SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE ON
REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED
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<S> <C> <C>
The United Illuminating Company Common Stock, no par value New York Stock Exchange
United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange
Securities, Series A (Liquidation
Preference $25 per Security)
</TABLE>
(1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3,
1995 by United Capital Funding Partnership L.P., a special purpose limited
partnership in which The United Illuminating Company owns all of the
general partner interests, and are guaranteed by The United Illuminating
Company.
SECURITIES REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE,
OF THE UNITED ILLUMINATING COMPANY
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 2000 was $716,746,100, computed on the basis of
the average of the high and low sale prices of said stock reported in the
listing of composite transactions for New York Stock Exchange listed securities,
published in The Wall Street Journal on February 1, 2000.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 2000, was 14,334,922.
DOCUMENTS INCORPORATED BY REFERENCE
None
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THE UNITED ILLUMINATING COMPANY
FORM 10-K
DECEMBER 31, 1999
TABLE OF CONTENTS
PAGE
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GLOSSARY 4
PART I
Item 1. Business. 5
- General 5
- Franchises, Regulation and Rates 5
- Franchises 5
- Regulation 5
- Rates 6
- Financing 6
- Fuel Supply 6
- Fossil Fuel 6
- Nuclear Fuel 7
- Power Supply Arrangements 7
- Arrangements with Other Utilities 8
- New England Power Pool 8
- New England Transmission Grid 8
- Hydro-Quebec 8
- Environmental Regulation 9
- Employees 10
Item 2. Properties. 11
- Generating Facilities 11
- Transmission and Distribution Plant 11
- Capital Expenditure Program 12
- Nuclear Generation 12
- General Considerations 14
- Insurance Requirements 14
- Waste Disposal and Decommissioning 15
Item 3. Legal Proceedings. 15
<PAGE>
TABLE OF CONTENTS (CONTINUED)
PAGE
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Item 4. Submission of Matters to a Vote of Security Holders. 15
Executive Officers of the Company 16
PART II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters. 17
Item 6. Selected Financial Data. 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 22
- Major Influences on Financial Condition 22
- Liquidity and Capital Resources 25
- Subsidiary Operations 27
- New Accounting Standards 28
- Results of Operations 28
- Looking Forward 37
Item 8. Financial Statements and Supplementary Data. 39
- Consolidated Financial Statements 39
- Statement of Income for the Years 1999, 1998 and 1997 39
- Statement of Cash Flows for the Years 1999, 1998 and 1997 40
- Balance Sheet as of December 31, 1999 and 1998 41
- Statement of Changes in Shareholders' Equity for the Years
1999, 1998 and 1997 43
- Notes to Consolidated Financial Statements 44
- Statement of Accounting Policies 44
- Capitalization 49
- Rate-Related Regulatory Proceedings 53
- Accounting for Phase-in Plan 57
- Short-Term Credit Arrangements 57
- Income Taxes 58
- Supplementary Information 60
- Pension and Other Benefits 61
- Jointly Owned Plant 64
- Unamortized Cancelled Nuclear Project 64
- Fuel Financing Obligations and Other Lease Obligations 64
- Commitments and Contingencies 66
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TABLE OF CONTENTS (CONTINUED)
PAGE
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PART II (CONTINUED)
- Capital Expenditure Program 66
- Nuclear Insurance Contingencies 66
- Other Commitments and Contingencies 67
- Connecticut Yankee 67
- Hydro-Quebec 67
- Environmental Concerns 68
- Site Decontamination, Demolition and Remediation Costs 68
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 68
- Fair Value of Financial Instruments 70
- Quarterly Financial Data (Unaudited) 71
- Segment Information 71
- Restatement of Financial Results 72
Report of Independent Accountants 75
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures. 77
PART III
Item 10. Directors and Executive Officers of the Company 77
Item 11. Executive Compensation. 80
Item 12. Security Ownership of Certain Beneficial Owners
and Management. 91
Item 13. Certain Relationships and Related Transactions. 94
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K. 95
Consent of Independent Accountants 102
Signatures 103
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<PAGE>
GLOSSARY
Certain capitalized terms used in this Annual Report have the following
meanings, and such meanings shall apply to terms both singular and plural unless
the context clearly requires otherwise:
"APS" means American Payment Systems, Inc., a wholly-owned subsidiary of
URI.
"the Company" means The United Illuminating Company.
"CSC" means the Connecticut Siting Council.
"Connecticut Yankee" means the Connecticut Yankee Atomic Power Company.
"Connecticut Yankee Unit" means the nuclear electric generating unit owned
by Connecticut Yankee and located in Haddam Neck, Connecticut.
"DEP" means the Connecticut Department of Environmental Protection.
"DOE" means the United States Department of Energy.
"DPUC" means the Connecticut Department of Public Utility Control.
"EPA" means the United States Environmental Protection Agency.
"FERC" means the United States Federal Energy Regulatory Commission.
"LLW" means low-level radioactive wastes.
"Millstone Unit 3" means the nuclear electric generating unit located in
Waterford, Connecticut, which is jointly owned by the Company and twelve
other New England electric utility entities.
"NEPOOL" means the New England Power Pool.
"NRC" means the United States Nuclear Regulatory Commission.
"NU" means Northeast Utilities.
"PCBs" means polychlorinated biphenyls.
"Preferred Stock" means capital stock of the Company having preferential
dividend and liquidation rights over shares of the Company's other classes
of capital stock.
"RCRA" means the federal Resource Conservation and Recovery Act.
"Restructuring Act" means Connecticut Public Act 98-28, enacted in 1998 and
designed to restructure the State's regulated electric utility industry.
"Seabrook Unit 1" means nuclear generating unit No. 1 located in Seabrook,
New Hampshire, which is jointly owned by the Company and ten other New
England electric utility entities.
"TSCA" means the federal Toxic Substances Control Act.
"URI" means United Resources, Inc., a wholly-owned subsidiary of the
Company.
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<PAGE>
PART I
Item 1. Business.
GENERAL
The United Illuminating Company (the Company) is an operating electric
public utility company, incorporated under the laws of the State of Connecticut
in 1899. It is engaged principally in the purchase, transmission, distribution
and sale of electricity for residential, commercial and industrial purposes in a
service area of about 335 square miles in the southwestern part of the State of
Connecticut. The population of this area is approximately 704,000 or 21% of the
population of the State. The service area, largely urban and suburban in
character, includes the principal cities of Bridgeport (population approximately
137,000) and New Haven (population approximately 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals. Of the Company's 1999 retail electric revenues,
approximately 42% was derived from residential sales, 40% from commercial sales,
16% from industrial sales and 2% from other sales. For a description of the
changes in the Company's electric public utility company business resulting from
the 1998 Connecticut legislation designed to restructure the State's electric
utility industry, see PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition."
The Company 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 the Company's regulated electric utility business and provide
long-term rewards to the Company's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
FRANCHISES, REGULATION AND RATES
FRANCHISES
Subject to the power of alteration, amendment or repeal by the Connecticut
legislature, and subject to certain approvals, permits and consents of public
authorities and others prescribed by statute, the Company has valid franchises
to engage in the purchase, transmission, distribution and sale of electricity in
the area served by it, the right to erect and maintain certain facilities on
public highways and grounds, and the power of eminent domain.
REGULATION
The Company is subject to regulation by the Connecticut Department of
Public Utility Control (DPUC), which has jurisdiction with respect to, among
other things, retail electric service rates, accounting procedures, certain
dispositions of property and plant, mergers and consolidations, the issuance of
securities, certain standards of service, management efficiency, operation and
construction, and the location and construction of certain electric facilities.
The DPUC consists of five Commissioners, appointed by the Governor of
Connecticut with the advice and consent of both houses of the Connecticut
legislature. See PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition," regarding the restructuring of Connecticut's regulated electric
utility industry.
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<PAGE>
The location and construction of certain electric facilities is also
subject to regulation by the Connecticut Siting Council (CSC) with respect to
environmental compatibility and public need. See "Environmental Regulation."
The Company is a "public utility" within the meaning of Part II of the
Federal Power Act and is subject to regulation by the Federal Energy Regulatory
Commission (FERC), which has jurisdiction with respect to interconnection and
coordination of facilities, wholesale electric service rates and accounting
procedures, among other things. See "Arrangements with Other Utilities."
In connection with ownership and leasehold interests in Seabrook Unit 1 and
Millstone Unit 3, the Company is a holder of licenses under the Atomic Energy
Act of 1954, as amended, and, as such, is subject to the jurisdiction of the
United States Nuclear Regulatory Commission (NRC), which has broad regulatory
and supervisory jurisdiction with respect to the construction and operation of
nuclear reactors, including matters of public health and safety, financial
qualifications, antitrust considerations and environmental impact. Connecticut
Yankee Atomic Power Company (Connecticut Yankee), in which the Company has a
9.5% common stock ownership share, is also subject to this NRC regulatory and
supervisory jurisdiction. See Item 2," Properties - Nuclear Generation."
The Company is subject to the jurisdiction of the New Hampshire Public
Utilities Commission for limited purposes in connection with its 17.5% ownership
and leasehold interests in Seabrook Unit 1.
RATES
The Company's retail electric service rates are subject to regulation by
the DPUC.
The Company's present general retail rate structure consists of various
rate and service classifications covering residential, commercial, industrial
and street lighting services.
Utilities are entitled by Connecticut law to charge rates that are
sufficient to allow them an opportunity to cover their reasonable operating and
capital costs, to attract needed capital and maintain their financial integrity,
while also protecting relevant public interests.
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Major Influences on Financial Condition"
regarding the five-year incentive rate regulation plan, for the years 1997
through 2001, that is currently in effect for the Company and the standard offer
rates established by the DPUC pursuant to Public Act 98-28, which was enacted in
1998 and designed to restructure Connecticut's regulated electric utility
industry.
FINANCING
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources,"
regarding the Company's capital requirements and resources and its financings
and financial commitments.
FUEL SUPPLY
FOSSIL FUEL
On April 16, 1999, the Company sold both of its operating fossil-fueled
generating stations, Bridgeport Harbor Station and New Haven Harbor Station, to
Wisvest-Connecticut, LLC, (Wisvest) a single-purpose subsidiary of Wisvest
Corporation, which is a non-utility subsidiary of Wisconsin Energy Corporation,
Milwaukee, Wisconsin. See PART II, Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Major Influences on Financial
Condition." All of the Company's fossil fuel supply contracts were assigned to
Wisvest-Connecticut, LLC on the closing date of the transaction.
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<PAGE>
NUCLEAR FUEL
The Company holds an ownership and leasehold interest in Seabrook Unit 1
and an ownership interest in Millstone Unit 3, both of which are nuclear-fueled
generating units. Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to uranium concentrates, the
conversion of uranium concentrates to uranium hexafluoride, enrichment of that
gas and fabrication of the enriched hexafluoride into usable fuel assemblies.
After a region (approximately 1/3 to 1/2 of the nuclear fuel assemblies in
the reactor at any time) of spent fuel is removed from a nuclear reactor, it is
placed in temporary storage in a spent fuel pool at the nuclear station for
cooling and ultimately is expected to be transported to a permanent storage
site, which has yet to be determined. See Item 2, "Properties - Nuclear
Generation."
Based on information furnished by the utility responsible for the operation
of the units in which the Company is participating, there are outstanding
contracts that cover uranium concentrate purchases for Millstone Unit 3 through
2003 and for Seabrook Unit 1 through 2002. In addition, there are outstanding
contracts, to the extent indicated below, for conversion, enrichment and
fabrication services for these units extending through the following years:
CONVERSION TO
HEXAFLUORIDE ENRICHMENT FABRICATION
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Millstone Unit 3 2003 2002 2010
Seabrook Unit 1 2002 2002 2008
POWER SUPPLY ARRANGEMENTS
In 1998, Connecticut enacted Public Act 98-28 (the Restructuring Act)
designed to restructure the State's electric utility industry. For a description
of the changes in the Company's electric public utility company business
resulting from the Restructuring Act, see PART II, Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Major
Influences on Financial Condition."
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. On and after
January 1, 2000 and until January 1, 2004, the Company is required to offer full
retail service to its customers under a regulated "standard offer" rate and is
also required to be 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. The Company is also
required under the Restructuring Act to provide back-up power supply service to
customers whose alternate power supply provider fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
In conjunction with the sale of its operating non-nuclear generating
stations to Wisvest on April 16, 1999, the Company entered into a wholesale
power supply contract with the purchaser for the sale of power to the Company,
through June 30, 2000, to replace the power that had been generated by the
Company at these generating stations. On December 28, 1999, the Company entered
into a series of agreements with Enron Power Marketing, Inc. (EPMI), a
subsidiary of Enron Corp., Houston, Texas, for the supply of all of the power
needed by the Company to meet its standard offer obligations until the end of
the four-year standard offer period and the power needed to serve the Company's
special contract customers for the remaining contract terms. From January 1,
2000 through June 30, 2000, EPMI will sell to the Company energy beyond that
supplied by Wisvest as described above. The agreements also provide for the sale
to EPMI of the Company's entitlements under all of its wholesale purchased power
agreements (PPAs). However, unless or until a PPA is terminated or formally
assigned to EPMI, the Company remains legally liable to pay the applicable power
supplier all amounts due under the PPA. The agreements with EPMI also include a
financially settled contract for differences related to certain call rights of
EPMI and put rights of the Company with respect to the Company's entitlements in
Seabrook Unit 1 and in Millstone Unit 3, and the Company's provision to EPMI of
certain ancillary products and services associated with those nuclear
entitlements, which provisions terminate at the earlier of December 31, 2003 or
the date that the Company sells its nuclear interests. The agreements do not
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<PAGE>
restrict the Company's right to sell to third parties the Company's ownership
interests in those nuclear generation units or the generated energy actually
attributable to its ownership interests.
If the generation resources available to the Company's wholesale suppliers
become inadequate to meet its customer service obligations, the Company expects
to be able to reduce the load on its system by the implementation of demand-side
management programs, to acquire other demand-side and supply-side resources,
and/or to purchase capacity from other utilities or from the installed
capability spot market, as necessary. However, because the generation and
transmission systems of the major New England utilities, including the Company,
are operated as if they were a single system, the ability of the Company to meet
its customer service obligations is and will be dependent on the ability of the
region's generation and transmission systems to meet the region's load. See Item
1, "Business - Arrangements with Other Utilities."
ARRANGEMENTS WITH OTHER UTILITIES
NEW ENGLAND POWER POOL
The Company, in cooperation with other privately and publicly owned New
England electric utilities, established the New England Power Pool (NEPOOL) in
1971. NEPOOL was formed to assure reliable operation of the bulk power system in
the most economic manner for the region. It has achieved these objectives
through central dispatching of all generation facilities owned by its members
and through coordination of the activities of the members that can have
significant inter-utility impacts. NEPOOL is governed by an agreement (NEPOOL
Agreement) that is filed with the Federal Energy Regulatory Commission (FERC);
and its provisions are subject to continuing FERC jurisdiction.
Because of evolving industry-wide changes, NEPOOL has been restructured.
Its membership has been broadened to cover all entities engaged in the
electricity business in New England, including power marketers and brokers,
independent power producers and load aggregators. An independent entity, ISO New
England, Inc., has the responsibility for the operation of the regional bulk
power system, so that the regional bulk power system will continue to be
operated both in accordance with the NEPOOL objectives and free of any adverse
impact on competition in the wholesale power markets, where various energy and
capacity products are traded in open competition among all participants.
Amendments to the NEPOOL Agreement establishing the markets were filed with and
have been approved by the FERC, and the markets became operational on May 1,
1999. Further significant amendments to the NEPOOL Agreement, to implement a
transmission congestion management and multi-settlement system, are expected to
be filed with the FERC prior to March 31, 2000.
NEW ENGLAND TRANSMISSION GRID
Under other agreements related to the Company's participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to
the financial support of certain 345 kilovolt transmission facilities that are a
part of the New England transmission grid.
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. The
Company is obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. As of December 31, 1999, the Company's
guarantee liability for this debt was approximately $6.2 million.
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<PAGE>
ENVIRONMENTAL REGULATION
The National Environmental Policy Act requires that detailed statements of
the environmental effect of the Company's facilities be prepared in connection
with the issuance of various federal permits and licenses, some of which are
described below. Federal agencies are required by that Act to make an
independent environmental evaluation of the facilities as part of their actions
during proceedings with respect to these permits and licenses.
Under the federal Toxic Substances Control Act (TSCA), the EPA has issued
regulations that control the use and disposal of polychlorinated biphenyls
(PCBs). PCBs had been widely used as insulating fluids in many electric utility
transformers and capacitors manufactured before TSCA prohibited any further
manufacture of such PCB equipment. Fluids with a concentration of PCBs higher
than 500 parts per million and materials (such as electrical capacitors) that
contain such fluids must be disposed of through burning in high temperature
incinerators approved by the EPA. Solid wastes containing PCBs must be disposed
of in either secure chemical waste landfills or in high-efficiency incinerators.
In response to EPA regulations, the Company has phased out the use of certain
PCB capacitors and has tested all Company-owned transformers located inside
customer-owned buildings and replaced all transformers found to have fluids with
detectable levels of PCBs (higher than 1 part per million) with transformers
that have no detectable PCBs. Presently, no transformers having fluids with
levels of PCBs higher than 500 parts per million are known by the Company to
remain in service in its system, except at one generating station. Compliance
with TSCA regulations has necessitated substantial capital and operational
expenditures by the Company, and such expenditures may continue to be required
in the future, although their magnitude cannot now be estimated. The Company
agreed to participate financially in the remediation of a source of PCB
contamination attributed to the Company-owned electrical equipment on property
in New Haven. In 1999, the Company made a $100,000 payment toward that
remediation activity and was released from any and all future claims.
Under the federal Resource Conservation and Recovery Act (RCRA), the
generation, transportation, treatment, storage and disposal of hazardous wastes
are subject to regulations adopted by the EPA. Connecticut has adopted state
regulations that parallel RCRA regulations but are more stringent in some
respects. The Company has complied with the notification and application
requirements of present regulations, and the procedures by which the Company
handles, stores, treats and disposes of hazardous waste products have been
revised, where necessary, to comply with these regulations.
As described in PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition," 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 indicated 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 undertook liability for payment of any remediation
required with respect to the purchased assets. However, the Company will be
responsible for remediation of the portions of the plant sites that it has
retained, and no estimate of the potential costs is available.
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 $8.4 million had been incurred as of December 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. In
addition, the Company is currently replacing the bulkhead that surrounds this
site, at an estimated cost of $13.5 million. Of this amount, $4.2 million
represents the portion of the costs to protect the Company's transmission
facilities and will be capitalized as plant in service. The remaining estimated
cost of $9.3 million was expensed in 1999.
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RCRA also regulates underground tanks storing petroleum products or
hazardous substances, and Connecticut has adopted state regulations governing
underground tanks storing petroleum and petroleum products that, in some
respects, are more stringent than the federal requirements. The Company
currently owns 8 underground storage tanks, which are used primarily for
gasoline and fuel oil, that are subject to these regulations. A testing program
has been installed to detect leakage from any of these tanks, and substantial
costs may be incurred for future actions taken to prevent tanks from leaking, to
remedy any contamination of groundwater, and to modify, remove and/or replace
older tanks in compliance with federal and state regulations.
In the past, the Company has disposed of residues from operations at
landfills, as most other industries have done. In recent years it has been
determined that such disposal practices, under certain circumstances, can cause
groundwater contamination. Although the Company has no knowledge of the
existence of any such contamination, if the Company or regulatory agencies
determine that remedial actions must be taken in relation to past disposal
practices, the Company may experience substantial costs.
Connecticut statutes prohibit the commencement of construction or
reconstruction of electric generation or transmission facilities, or
modification of such facilities, unless the Connecticut Siting Council has
issued a certificate of environmental compatibility and public need or a
declaratory ruling that no certificate is required because the facility or
modification will not have a substantial adverse environmental effect.
In complying with existing environmental statutes and regulations and
further developments in these and other areas of environmental concern,
including legislation and studies in the fields of water and air quality,
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.
See also "Franchises, Regulation and Rates" and Item 2, "Properties - Nuclear
Generation."
EMPLOYEES
As of December 31, 1999, the Company had 827 employees; and its
wholly-owned subsidiaries employed 412 persons in their non-regulated
businesses. Of the Company's employees, approximately 89.4% had been with the
Company for 10 or more years.
Approximately 389 of the Company's operating, maintenance and clerical
employees are represented by Local 470-1, Utility Workers Union of America,
AFL-CIO, for collective bargaining purposes. On June 30, 1997, the unionized
employees accepted a five-year agreement. The agreement provides for, among
other things, 2% annual wage increases beginning in May 1998, and annual lump
sum bonuses of 2.5% of base annual straight time wages (not cumulative). The
agreement also provides for job security for longer-term bargaining unit
employees. There has been no work stoppage due to labor disagreements since
1966, other than a strike of three days duration in May 1985; and employee
relations are considered satisfactory.
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<PAGE>
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1999,
based on summer ratings of the generating units, was as follows:
YEAR OF MAX CLAIMED COMPANY
COMPANY OPERATED: FUEL INSTALLATION CAPABILITY, MW ENTITLEMENT
- ---------------- ---- ------------ -------------- -----------
% Mw
English Station 7 #6 Oil 1948 34.06 100.00 34.06(1)
English Station 8 #6 Oil 1953 38.49 100.00 38.49(1)
OPERATED BY OTHER
UTILITIES:
- -----------------
Millstone Unit 3, Nuclear 1986 1154.56 3.685 42.55(2)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1161.00 17.50 203.18(3)
Seabrook, New Hampshire
(1) English Station 7 and 8 were placed in deactivated reserve status,
effective January 1, 1992.
(2) Represents the Company's 3.685% ownership share of total net capability.
(3) Represents the Company's 17.5% ownership and leasehold share of total net
capability. In August 1990, the Company sold to and leased back from an
owner trust established for the benefit of an institutional investor a
portion of the Company's 17.5% ownership interest in this unit. This
portion of the unit is subject to the lien of a first mortgage granted by
the owner trustee.
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Major Influences on Financial Condition,"
regarding the Company's sale of both of its operating non-nuclear generating
stations, on April 16, 1999, and its plan to divest its nuclear generation, in
compliance with Connecticut's electric utility industry Restructuring Act.
English Station is the Company's only remaining non-nuclear generating
station. Since June of 1998, the Company has been attempting to sell this
deactivated station, which is situated on a site bordering the Mill River in New
Haven, in order to avoid incurring the expense, estimated at $20 million, of
decommissioning and demolishing the generating units and buildings on the site.
On March 2, 2000, the Company agreed to sell the station to Quinnipiac Energy,
LLC, (QE) a privately-owned independent power producer. QE intends to reactivate
the generating units at the station. Under the terms of the purchase and sale
agreement for the transaction, the consummation of which is subject to a number
of conditions, including obtaining state and federal regulatory approvals, the
Company will retain a permanent right of occupancy on and over the station
property for the Company's existing New Haven harbor transmission line towers
and cables. QE will complete the bulkhead replacement project that the Company
has commenced to preserve and protect the station property; and QE will assume
responsibility for any and all environmental liability associated with the
Company's prior ownership and operation of the station. The Company has agreed
to pay for the cost of completing the bulkhead replacement project, the
estimated cost of which the Company recognized in 1999, to pay for 61% of the
environmental remediation costs (estimated at $750,000) that will be incurred by
QE under Connecticut's Transfer Act as a result of QE's acquisition of the
station, and to pay QE $4.25 million for QE's assumption of the remaining
Transfer Act remediation costs and any and all environmental liability
associated with the Company's prior ownership and operation of the station.
TRANSMISSION AND DISTRIBUTION PLANT
The transmission lines of the Company consist of approximately 102 circuit
miles of overhead lines and approximately 17 circuit miles of underground lines,
all operated at 345 KV or 115 KV and located within or
- 11 -
<PAGE>
immediately adjacent to the territory served by the Company. These transmission
lines interconnect the Bridgeport Harbor and New Haven Harbor generating
stations and are part of the New England transmission grid through connections
with the transmission lines of The Connecticut Light and Power Company. A major
portion of the Company's transmission lines is constructed on railroad
right-of-way pursuant to two Transmission Line Agreements. One of the Agreements
expires in May 2000 and the Company expects to extend this Agreement. The other
Agreement has been extended to May 2040.
The Company owns and operates 25 bulk electric supply substations with a
capacity of 1,756,300 KVA and 32 distribution substations with a capacity of
153,520 KVA. The Company has 3,170 pole-line miles of overhead distribution
lines and 130 conduit-bank miles of underground distribution lines.
See "Capital Expenditure Program" concerning the estimated cost of
additions to the Company's transmission and distribution facilities.
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program for 2000 through 2004
is presently estimated at $187.5 million, excluding allowance for funds used
during construction. See PART II, Item 8, "Financial Statements and
Supplementary Data - Notes to Consolidated Financial Statements - Note (L),
Commitments and Contingencies."
NUCLEAR GENERATION
The Company holds ownership and leasehold interests totalling 17.5% (203.18
megawatts) in Seabrook Unit 1, and a 3.685% (42.55 megawatts) ownership interest
in Millstone Unit 3. The Company also owns 9.5% of the common stock of
Connecticut Yankee, and was entitled to an equivalent percentage (53.21
megawatts) of the generating capability of the Connecticut Yankee Unit prior to
its retirement from commercial operation on December 4, 1996.
Seabrook Unit 1 commenced commercial operation in June of 1990, pursuant to
an operating license issued by the NRC, which will expire in 2026. It is jointly
owned by eleven New England electric utility entities, including the Company,
and is operated by a service company subsidiary of Northeast Utilities (NU).
Through December 31, 1999, Seabrook Unit 1 has operated at a lifetime capacity
factor of 80.5%.
Millstone Unit 3 commenced commercial operation in April of 1986, pursuant
to a 40-year operating license issued by the NRC. It is jointly owned by
thirteen New England electric utility entities, including the Company, and is
operated by another service company subsidiary of NU. Through March 30, 1996,
when Millstone Unit 3 was taken out of service following an engineering
evaluation that determined that four safety-related valves would not be able to
perform their design function during certain postulated events, Millstone Unit 3
had operated at a lifetime capacity factor of 71.9%. A comprehensive Nuclear
Regulatory Commission (NRC) inquiry into the conformity of the unit and its
operations with all applicable NRC regulations and standards was completed and
the unit was allowed to resume operation beginning on July 4, 1998. It achieved
full power production on July 14, 1998. Through December 31, 1999, Millstone
Unit 3 has operated at a lifetime capacity factor of 60.6%.
During the twenty-seven months that Millstone Unit 3 was out of service,
the Company incurred incremental replacement power costs estimated at
approximately $500,000 per month, and experienced an adverse impact on net
earnings per share of approximately $.02 per month. In addition to these costs
of replacement power, substantial incremental direct costs were incurred to
address the above-described problems with respect to Millstone Unit 3. The
Company and the other nine non-NU owners of Millstone Unit 3, who together own
about 19.5% of the unit, paid their monthly shares of the costs of the unit, but
reserved their rights to contest whether the NU service company subsidiary that
is the operator of Millstone Unit 3 and/or one or both of the two operating NU
subsidiary electric utility companies that are the majority joint owners of
Millstone Unit 3 are responsible for the additional costs that the other joint
owners experienced as a result of the shutdown of Millstone Unit 3. On August 7,
1997, the Company and the other nine minority, non-NU joint owners of Millstone
Unit 3 filed lawsuits against NU and its trustees, as well as a demand for
arbitration against The Connecticut Light and Power Company and Western
Massachusetts Electric Company
- 12 -
<PAGE>
the operating electric utility subsidiaries of NU that are the majority joint
owners of the unit and have contracted with the minority joint owners to operate
it. In the arbitration proceeding and lawsuits, which NU and its subsidiaries
are contesting vigorously, the non-NU joint owners claim that NU and its
subsidiaries failed to comply with NRC regulations, failed to operate Millstone
Station in accordance with good utility operating practice and concealed their
failures from the non-operating joint owners and the NRC, and seek to recover
costs of purchasing replacement power and increased operation and maintenance
costs resulting from the shutdown of Millstone Unit 3. Three of the non-NU joint
owners, who together own about 11.5% of the unit, have settled their claims
against NU and its subsidiaries and have withdrawn from the prosecution of the
arbitration proceeding and lawsuits.
The DPUC is currently considering the Company's plan for divesting its
ownership interest in Millstone Unit 3 through an auction process to be
conducted by a consultant to be selected by the DPUC.
The Connecticut Yankee Unit commenced commercial operation in January of
1968, pursuant to a 40-year operating license issued by the NRC. It is owned,
through ownership of Connecticut Yankee's common stock, by ten New England
electric utilities, including the Company, and is operated by another service
company subsidiary of NU. Prior to July 23, 1996, when the Connecticut Yankee
Unit was taken out of service following an engineering evaluation that
determined that safety-related air cooling system pipes could crack if the plant
should lose its outside source of electric power, the Connecticut Yankee Unit
had operated at a lifetime capacity factor of 75.6%. Prior to and following its
removal from service in July of 1996, NRC inspections of the Connecticut Yankee
Unit revealed issues that were similar to those previously identified at
Millstone Station and identified a number of significant deficiencies in the
engineering calculations and analyses that were relied upon to ensure the
adequacy of the design of key safety systems at the unit. Pending a resolution
of these issues, an economic study by the owners, comparing the costs of
continuing to operate the Connecticut Yankee Unit over the remaining period of
its operating license, which expires in 2007, to the costs of shutting down the
unit permanently and incurring replacement power costs for the same period,
resulted in a decision, on December 4, 1996, by the Board of Directors of
Connecticut Yankee to retire the Connecticut Yankee Unit from commercial
operation.
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 the Company. 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 sought
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 or timing 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 $10.0
million) and return on investment (approximately $3.8 million) at December 31,
1999, is approximately $27.1 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.
- 13 -
<PAGE>
GENERAL CONSIDERATIONS
Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee Unit are each
subject to the licensing requirements and jurisdiction of the NRC under the
Atomic Energy Act of 1954, as amended, and to a variety of other state and
federal requirements.
The NRC regularly conducts generic reviews of numerous technical issues,
ranging from seismic design to education and fitness for duty requirements for
licensed plant operators. The outcome of reviews that are currently pending, and
the ways in which the nuclear generating units in which the Company has
interests may be affected by these reviews, cannot be determined; and the cost
of complying with any new requirements that might result from the reviews cannot
be estimated. However, such costs could be substantial.
Additional capital expenditures and increased operating costs for nuclear
generating units may result from modifications of these facilities or their
operating procedures required by the NRC, or from actions taken by other joint
owners or companies having entitlements in the units. Some equipment
modifications have required and may in the future require shutdowns or deratings
of generating units that would not otherwise be necessary and that result in
additional costs. The amounts of additional capital expenditures and increased
costs cannot now be predicted, but they have been and may in the future be
substantial.
Public controversy concerning nuclear power could also adversely affect
Seabrook Unit 1 and Millstone Unit 3. Proposals to force the premature shutdown
of nuclear plants in other New England states have in the past received serious
attention, and the licensing of Seabrook Unit 1 was a regional issue. A renewal
of the controversy could be expected to increase the costs of operating the
nuclear generating units in which the Company has interests; and it is possible
that one or the other of the units could be shut down prematurely, resulting in
earlier funding of costs associated with decommissioning the unit and
acceleration of depreciation expense, which could have an adverse impact on the
Company's financial condition and/or results of operations.
INSURANCE REQUIREMENTS
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 two operating 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 two
operating 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
- 14 -
<PAGE>
assessments against the Company with respect to losses occurring during current
policy years are approximately $3.0 million.
WASTE DISPOSAL AND DECOMMISSIONING
See PART II, Item 8, "Financial Statements and Supplementary Data - Notes
to Consolidated Financial Statements - Note (M), Nuclear Fuel Disposal and
Nuclear Plant Decommissioning" regarding the disposal of spent nuclear fuel and
high-level and low-level radioactive wastes in connection with the operation and
decommissioning of Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee
Unit.
Item 3. Legal Proceedings.
See Item 2, "Properties - Nuclear Generation" regarding the Company's
participation in an arbitration proceeding and lawsuits against Northeast
Utilities and its subsidiaries with respect to their operation of Millstone Unit
3.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders, through the
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year ended December 31, 1999.
- 15 -
<PAGE>
EXECUTIVE OFFICERS OF THE COMPANY
The names and ages of all executive officers of the Company and all such
persons chosen to become executive officers, all positions and offices with the
Company held by each such person, and the period during which he or she has
served as an officer in the office indicated, are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION EFFECTIVE DATE
- ---- --- -------- --------------
<S> <C> <C> <C>
Nathaniel D. Woodson 58 Chairman of the Board of Directors, President
and Chief Executive Officer December 31, 1998
Robert L. Fiscus 62 Vice Chairman of the Board of Directors, Chief
Financial Officer, Treasurer and Secretary October 25, 1999
James F. Crowe 57 Group Vice President Power Supply Services October 1, 1996
Albert N. Henricksen 58 Group Vice President Support Services October 1, 1996
Anthony J. Vallillo 51 Group Vice President Client Services October 1, 1996
Rita L. Bowlby 61 Vice President Corporate Affairs February 1, 1993
Stephen F. Goldschmidt 54 Vice President Planning May 1, 1999
James L. Benjamin 58 Controller January 1, 1981
Charles J. Pepe 51 Assistant Treasurer and Assistant Secretary January 1, 1994
</TABLE>
There is no family relationship between any director, executive officer, or
person nominated or chosen to become a director or executive officer of the
Company. All executive officers of the Company hold office during the pleasure
of the Company's Board of Directors. All of the above executive officers have
entered into employment agreements with the Company. There is no arrangement or
understanding between any executive officer of the Company and any other person
pursuant to which such officer was selected as an officer.
A brief account of the business experience during the past five years of
each executive officer of the Company is as follows:
NATHANIEL D. WOODSON. Mr. Woodson served as Vice President and General
Manager of the Energy Systems Business Unit of Westinghouse Electric Corporation
during the period January 1, 1995 to April 30, 1996. He served as President of
the Company during the period February 23, 1998 to May 20, 1998 and President
and Chief Executive Officer during the period May 20, 1998 to December 31, 1998.
He has served as Chairman of the Board of Directors, President and Chief
Executive Officer since December 31, 1998.
ROBERT L. FISCUS. Mr. Fiscus served as President and Chief Financial
Officer during the period January 1, 1995 to February 23, 1998, and as Vice
Chairman of the Board of Directors and Chief Financial Officer from February 23,
1998 to October 25, 1999. He has served as Vice Chairman of the Board of
Directors, Chief Financial Officer, Treasurer and Secretary since October 25,
1999.
JAMES F. CROWE. Mr. Crowe served as Executive Vice President and Chief
Customer Officer during the period January 1, 1995 to October 1, 1996. He has
served as Group Vice President Power Supply Services since October 1, 1996.
ALBERT N. HENRICKSEN. Mr. Henricksen served as Vice
President-Administration during the period January 1, 1995 to October 1, 1996.
He has served as Group Vice President Support Services since October 1, 1996.
ANTHONY J. VALLILLO. Mr. Vallillo served as Vice President-Marketing during
the period January 1, 1995 to October 1, 1996. He has served as Group Vice
President Client Services since October 1, 1996.
RITA L. BOWLBY. Ms. Bowlby has served as Vice President-Corporate Affairs
of the Company during the five-year period.
- 16 -
<PAGE>
STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served as Vice
President-Information Resources during the period January 1, 1995 to October 1,
1996, and as Vice President Planning and Information Resources from October 1,
1996 to May 1, 1999. He has served as Vice President Planning since May 1, 1999.
JAMES L. BENJAMIN. Mr. Benjamin has served as Controller of the Company
during the five-year period.
CHARLES J. PEPE. Mr. Pepe has served as Assistant Treasurer and Assistant
Secretary of the Company during the five-year period.
PART II
Item 5. Market for the Company's Common Equity and Related Stockholder Matters.
The Company 's Common Stock is traded on the New York Stock Exchange, where
the high and low sale prices during 1999 and 1998 were as follows:
1999 SALE PRICE 1998 SALE PRICE
--------------- ---------------
HIGH LOW HIGH LOW
---- --- ---- ---
First Quarter 52 11/16 41 7/8 48 9/16 42 5/8
Second Quarter 44 11/16 39 5/16 51 15/16 46 15/16
Third Quarter 50 11/16 43 1/8 53 9/16 49
Fourth Quarter 53 3/16 47 15/16 53 3/4 48 1/16
The Company has paid quarterly dividends on its Common Stock since 1900.
The quarterly dividends declared in 1998 and 1999 were at a rate of 72 cents per
share.
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
$117.3 million were free from such limitations at December 31, 1999.
As of December 31, 1999, there were 13,664 Common Stock shareowners of
record.
- 17 -
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997
=====================================================================================================================
<S> <C> <C> <C>
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $271,605 $262,974 $259,325
Commercial 256,246 254,765 248,490
Industrial 100,437 102,201 102,763
Other 11,308 11,667 11,755
------------- ------------- -------------
Total Retail 639,596 631,607 622,333
Wholesale (1) 24,334 44,948 82,871
Other operating revenues 16,045 9,636 3,825
------------- ------------- -------------
Total operating revenues 679,975 686,191 709,029
------------- ------------- -------------
Fuel and interchange energy -net
Retail -own load 134,851 116,769 109,542
Wholesale 24,552 34,775 73,124
Capacity purchased-net 33,873 34,515 39,976
Depreciation 57,351 82,809 (3) 74,618 (3)
Other amortization, principally deferred return, cancelled plant
and regulatory tax assets 36,393 13,758 13,758
Other operating expenses, excluding tax expense 185,696 188,946 200,803
Gross earnings tax 24,518 24,039 23,571
Other non-income taxes 22,622 40,635 (4) 28,922
------------- ------------- -------------
Total operating expenses, excluding income taxes 519,856 536,246 564,314
------------- ------------- -------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 2,235 468 1,575
Other non-operating income(loss) (838) 1,097 (5) 1,361
Interest expense
Long-term debt - net 35,260 42,836 56,158
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other 7,319 9,018 6,068
------------- ------------- -------------
Total 47,392 56,667 67,039
------------- ------------- -------------
Income tax expense
Operating income tax 66,564 53,619 40,833 (6)
Non-operating income tax (4,664) (3,848) (3,678)
------------- ------------- -------------
Total 61,900 49,771 37,155
------------- ------------- -------------
Income before cumulative effect of accounting change 52,224 45,072 43,457
Cumulative effect of change in accounting - net of tax 0 0 0
------------- ------------- -------------
Net income 52,224 45,072 43,457
Premium (Discount) on preferred stock redemption 53 (21) (48)
Preferred and preference stock dividends 66 201 205
------------- ------------- -------------
Income applicable to common stock $52,105 $44,892 $43,300
- ---------------------------------------------------------------------------------------------------------------------
Operating income $93,555 $96,326 $103,882
=====================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $474,656 (12) $1,172,555 $1,222,174
Construction work in progress 25,708 33,695 25,448
Other property and investments 152,948 (13) 58,047 58,441
Current assets 220,126 305,189 204,474
Deferred charges and regulatory assets 924,772 (12) 371,674 408,993
------------- ------------- -------------
Total Assets $1,798,210 $1,941,160 $1,919,530
- ---------------------------------------------------------------------------------------------------------------------
Common stock equity $458,298 $445,507 $436,081
Preferred, preference stock and company-obligated mandatorily
redeemable securities of subsidiaries holding solel
parent debentures 50,000 54,299 54,351
Long-term debt excluding current portion 518,228 664,510 644,670
Noncurrent liabilities (9) 245,268 109,981 119,868
Current portion of long-term debt 25,000 66,202 100,000
Notes payable 17,131 86,892 37,751
Other current liabilities (9) 166,213 172,830 175,340
Deferred income tax liabilities and other 318,072 340,939 351,469
------------- ------------- -------------
Total Capitalization and Liabilities $1,798,210 $1,941,160 $1,919,530
=====================================================================================================================
</TABLE>
(1) Operating Revenues, for years prior to 1992, include wholesale power
exchange contract sales that were reclassified from Fuel and Capacity
expenses in accordance with Federal Energy Regulatory Commission
requirements.
(2) Includes reclassification of certain Commercial and Industrial customers.
(3) Includes the before-tax effect of charges for additional amortization of
conservation & load management costs: $13.1 million in 1998 and $6.6
million in 1997.
(4) Includes the effect of charges of $14.0 million, before-tax, associated
with property tax settlement.
(5) Includes the before-tax effect of charges for losses associated with
unregulated subsidiaries: $2.8 million in 1997 and $5.8 million in 1996.
(6) Includes the effect of credits of $6.7 million to provide tax provision for
fossil generation decommissioning.
- 18 -
<PAGE>
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992 1991 1990
==========================================================================================================
<S> <C> <C> <C> <C> <C> <C>
$266,068 $260,694 $252,386 $238,185 $226,455 $226,751 $211,891
264,111 259,715 250,771 (2) 256,559 253,456 (2) 255,782 234,704
109,032 106,963 104,242 (2) 97,466 97,010 (2) 91,895 94,526
11,903 11,736 11,469 11,349 11,065 10,886 10,536
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
651,114 639,108 618,868 603,559 587,986 585,314 551,657
72,844 48,232 34,927 45,931 75,484 84,236 85,657
3,300 3,109 2,953 3,533 3,855 3,821 3,332
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
727,258 690,449 656,748 653,023 667,325 673,371 640,646
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
95,359 96,538 99,589 98,694 108,084 123,010 119,285
65,158 41,631 27,765 39,356 55,169 61,858 69,117
46,830 47,420 44,769 47,424 43,560 44,668 42,827
65,921 61,426 58,165 56,287 50,706 48,181 36,526
13,758 13,758 1,172 1,780 10,415 10,415 4,173
219,630 (7) 183,749 193,098 203,427 (10) 183,426 178,912 176,419
26,804 27,379 27,403 27,955 27,362 27,223 25,595
30,382 31,564 32,458 29,977 31,869 28,673 24,648
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
563,842 503,465 484,419 504,900 510,591 522,940 498,590
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
0 0 0 7,497 15,959 17,970 21,503
2,375 2,762 3,463 4,067 3,232 5,190 3,443
(8,445) (5) (5,068) (1,907) 71 18,545 2,697 22,654
65,046 63,431 73,772 80,030 88,666 90,296 94,056
4,813 3,583 0 0 0 0 0
4,721 12,841 10,301 12,260 12,882 9,847 15,468
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
74,580 79,855 84,073 92,290 101,548 100,143 109,524
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
53,590 59,828 44,937 33,309 48,712 47,231 43,493
(9,869) (4,901) (3,214) (6,322) (12,558) (19,299) (17,409)
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
43,721 54,927 41,723 26,987 36,154 27,932 26,084
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
39,045 49,896 48,089 40,481 56,768 48,213 54,048
0 0 (1,294) 0 0 7,337 0
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
39,045 (8) 49,896 46,795 40,481 (11) 56,768 55,550 54,048
(1,840) (2,183) 0 0 0 0 0
330 1,329 3,323 4,318 4,338 4,530 4,751
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
$40,555 $50,750 $43,472 $36,163 $52,430 $51,020 $49,297
- ----------------------------------------------------------------------------------------------------------
$109,826 $127,156 $127,392 $114,814 $108,022 $103,200 $98,563
==========================================================================================================
$1,258,306 $1,277,910 $1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173
40,998 41,817 57,669 77,395 59,809 54,771 50,257
49,091 53,355 53,267 58,096 65,320 79,009 90,006
199,097 136,481 157,309 187,981 247,954 164,839 161,066
449,150 475,258 538,601 567,394 556,493 554,365 553,986
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
$1,996,642 $1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488
- ----------------------------------------------------------------------------------------------------------
$439,468 $439,484 $428,028 $423,324 $422,746 $401,771 $379,812
54,461 60,539 44,700 60,945 60,945 62,640 69,700
759,680 845,684 708,340 875,268 893,457 909,998 899,993
138,816 65,747 59,458 62,666 44,567 110,217 110,850
69,900 40,800 193,133 143,333 92,833 37,500 41,667
10,965 0 67,000 0 84,099 13,000 15,000
166,138 102,336 122,084 117,343 114,757 114,280 138,173
357,214 430,231 452,248 451,413 440,230 423,449 409,293
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
$1,996,642 $1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488
==========================================================================================================
</TABLE>
(7) Includes the effect of charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(8) Includes the effect of charges of $13.4 million, after-tax, associated with
voluntary early retirement programs.
(9) Amounts for years prior to 1996 were reclassified in 1996.
(10) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(11) Includes the effect of a reorganization charge of $7.8 million, after-tax.
(12) Reflects reclassification of $518.3 million of nuclear assets from plant in
service to regulatory asset.
(13) Includes $83.5 million investment in a generation facility as of December
31, 1999.
- 19 -
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1999 1998 1997
=================================================================================================================
<S> <C> <C> <C>
COMMON STOCK DATA
Average number of shares outstanding 14,052,091 14,017,644 13,975,802
Number of shares outstanding at year-end 14,062,502 14,034,562 13,907,824
Earnings per share (average) - basic $3.71 $3.20 $3.10
Earnings per share (average) - diluted $3.71 $3.20 $3.09
Book value per share $32.59 $31.74 $31.35
Average return on equity
Total 11.45% 9.44% 10.45%
Utility 14.00% 11.43% 11.54%
Dividends declared per share $2.88 $2.88 $2.88
Market Price:
High $53.188 $53.750 $45.938
Low $39.313 $42.625 $24.500
Year-end $51.375 $51.500 $45.938
=================================================================================================================
Net cash provided by operating activities, less dividends ($000's) $57,907 $71,566 $132,189
Capital expenditures, excluding AFUDC $34,772 $38,040 $33,436
=================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 2,053,927 1,924,724 1,899,284
Commercial 2,388,240 2,324,507 2,248,974
Industrial 1,161,856 1,154,935 1,168,470
Other 48,027 48,166 48,619
------------- ------------- -------------
Total 5,652,050 5,452,332 5,365,347
------------- ------------- -------------
Number of retail customers by class (average)
Residential 282,986 281,591 280,283
Commercial 29,757 29,468 29,228
Industrial 1,746 1,752 1,697
Other 1,185 1,172 1,163
------------- ------------- -------------
Total 315,674 313,983 312,371
------------- ------------- -------------
Revenue per kilowatt hour by class (cents)
Residential 13.22 13.66 13.65
Commercial 10.73 10.96 11.05
Industrial 8.64 8.85 8.79
Average large industrial customers time of use rate (cents) 8.21 8.16 8.12
- -----------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $655,327 $629,446 $620,636
Base rate adjustments (15,731) 2,161 1,697
Sales provision adjustment 0 0 0
------------- ------------- -------------
Total $639,596 $631,607 $622,333
------------- ------------- -------------
Revenues - retail sales per kWh (cents)
Base 11.59 11.54 11.57
Base rate adjustments (0.28) 0.04 0.03
Sales provision adjustment 0.00 0.00 0.00
------------- ------------- -------------
Total 11.31 11.58 11.60
------------- ------------- -------------
Fuel and energy cost per kWh (cents) 2.27 2.04 1.95
Fossil 3.02 2.60 2.39
Nuclear 0.58 0.58 0.61
- -----------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,239 1,193 1,175
Total utility employees payroll($000 'S) $66,155 $65,294 $68,640
=================================================================================================================
</TABLE>
(1) Includes reclassification of certain Commercial and Industrial customers.
- 20 -
<PAGE>
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992 1991 1990
==========================================================================================================
<S> <C> <C> <C> <C> <C> <C>
14,100,806 14,089,835 14,085,452 14,063,854 13,941,150 13,899,906 13,887,748
14,101,291 14,100,091 14,086,691 14,083,291 14,033,148 13,932,348 13,887,748
$2.88 $3.60 $3.09 $2.57 $3.76 $3.67 $3.55
$2.87 $3.59 $3.08 $2.56 $3.74 $3.66 $3.55
$31.16 $31.16 $30.39 $30.06 $30.12 $28.84 $27.35
9.20% 11.84% 10.19% 8.45% 12.67% 13.01% 13.39%
11.51% 13.04% 12.50% 10.97% 14.46% 13.39% 13.97%
$2.88 $2.82 $2.76 $2.66 $2.56 $2.44 $2.32
$39.750 $38.500 $39.500 $45.875 $42.000 $39.125 $34.125
$31.375 $29.500 $29.000 $38.500 $34.125 $30.000 $26.875
$31.375 $37.375 $29.500 $40.250 $41.500 $39.000 $31.125
==========================================================================================================
$120,624 $120,033 $94,807 $104,547 $109,020 $73,865 $39,189
$47,174 $59,363 $63,044 $94,743 $66,390 $63,157 $64,018
==========================================================================================================
1,895,804 1,890,575 1,892,955 1,844,041 1,799,456 1,851,447 1,826,700
2,263,056 2,273,965 2,285,942 (1) 2,359,023 2,303,216 (1) 2,347,757 2,259,340
1,143,410 1,126,458 1,135,831 (1) 1,036,547 997,168 (1) 980,071 1,060,751
48,388 48,435 48,718 50,715 52,984 55,118 58,013
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
5,350,658 5,339,433 5,363,446 5,290,326 5,152,824 5,234,393 5,204,804
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
279,024 278,326 275,441 273,752 273,936 274,064 275,637
28,666 28,550 28,394 (1) 28,968 28,848 (1) 29,768 29,808
1,652 1,599 1,538 (1) 959 1,017 (1) 268 319
1,141 1,122 1,127 1,175 1,358 1,361 1,352
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
310,483 309,597 306,500 304,854 305,159 305,461 307,116
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
14.03 13.79 13.33 12.92 12.58 12.25 11.60
11.67 11.42 10.97 10.88 11.00 10.89 10.39
9.54 9.50 9.18 9.40 9.73 9.38 8.91
8.26 8.53 8.69 8.89 8.84 8.64 8.06
- ----------------------------------------------------------------------------------------------------------
$643,344 $637,219 $619,097 $605,887 $608,176 $607,997 $589,346
7,770 1,889 (229) (2,328) (41,221) (37,497) (45,900)
0 0 0 0 21,031 14,814 8,211
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
$651,114 $639,108 $618,868 $603,559 $587,986 $585,314 $551,657
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
12.02 11.93 11.54 11.45 11.80 11.62 11.32
0.15 0.04 0.00 (0.04) (0.80) (0.72) (0.88)
0.00 0.00 0.00 0.00 0.41 0.28 0.16
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
12.17 11.97 11.54 11.41 11.41 11.18 10.60
- ---------------- ----------- ----------- ------------ ----------- ----------- ------------
1.69 1.71 1.76 1.75 2.43 2.67 2.63
2.41 2.22 2.14 2.08 2.98 3.11 2.89
0.46 0.85 0.94 1.23 1.42 1.62 1.55
- ----------------------------------------------------------------------------------------------------------
1,287 1,358 1,377 1,490 1,554 1,571 1,587
$69,276 $72,984 $75,441 $75,305 $74,052 $71,888 $69,237
==========================================================================================================
</TABLE>
- 21 -
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its utility retail sales and the Company's ability to control expenses,
as well as on the performance of the non-regulated businesses of the Company's
subsidiaries. The two primary factors that affect utility sales volume are
economic conditions and weather. Total utility operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, declined
by 1.6%, on average, during the five years 1995-1999.
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.
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 retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, 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 Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of assets, and one-third retained as earnings. As a result of the
Rate Plan, customer prices were required to be reduced, on average, by 3% in
1997 compared to 1996. Also as a result of the Rate Plan, customer prices were
required to be reduced by an additional 1% in 2000, and another 1% in 2001,
compared to 1996. Retail revenues decreased by approximately 7.0% through 1999
compared to 1996 due to customer price reductions. The Rate Plan was reopened in
1998, in accordance with its terms, to determine the assets to be subjected to
accelerated recovery in 1999. The DPUC decided on February 10, 1999 to subject
$12.1 million of the Company's regulatory tax assets to accelerated recovery in
1999.
The Rate Plan includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999, the DPUC issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates, as directed by the Restructuring Act described in detail below.
These standard offer customer rates are in effect for the period 2000-2001 and
supercede the rate reductions for this period that were included in the Rate
Plan. The decision also reduced the required amount of accelerated amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect through 2001. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.
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. As a result of the Act, the business of
generating and selling electricity directly to consumers is opened to
competition. These business activities are separated from the business of
delivering electricity to consumers, also known as the transmission and
distribution business. The business of delivering electricity remains with the
incumbent franchised utility companies (including the Company), which continues
to be regulated by the DPUC as Distribution Companies. Since mid-1999,
Distribution Companies have been required to separate on consumers' bills the
electricity generation services component from the charge for delivering the
electricity and all other charges.
- 22 -
<PAGE>
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.
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 interests in its nuclear-fueled power plants prior to 2004.
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 April 16, 1999, the
transaction closed and the Company received approximately $277.9 million from
this sale. The Company realized a before-tax book gain of $86.5 million from the
sale of these plant investments. However, under the Restructuring Act, this gain
was offset by a writedown of the stranded costs eligible for collection by the
Company under the Restructuring Act's competitive transition assessment, such
that there was 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, and in other regulatory dockets, the Company stated that
it plans to divest its nuclear generation ownership interests (17.5% of Seabrook
Unit 1 in New Hampshire and 3.685% of Millstone Station Unit 3 in Connecticut)
by the end of 2003, in accordance with the Restructuring Act. The DPUC is
currently considering the Company's plan for divesting its ownership interest in
Millstone Unit 3 through an auction process to be conducted by a consultant to
be selected by the DPUC. The divestiture process for Seabrook Unit 1 has not yet
been determined. In anticipation of ultimate divestiture, the Company has
satisfied the Restructuring Act's requirement that nuclear generating assets be
separated from its transmission and distribution assets. This was 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 decision dated May 19, 1999, the DPUC 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 and, in a decision dated May 19, 1999, the DPUC approved the
proposed corporate restructuring. The Company has filed applications with the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission
seeking approval of the proposed corporate restructuring, and a special meeting
of the Company's shareowners will be held on March 17, 2000 to vote on approval
of the restructuring.
- 23 -
<PAGE>
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the market value of the
Company's generating assets in an appeal taken to the Superior Court from the
DPUC's decision.
Under the Restructuring Act, retail customers representing a total of up
to 35% of the Company's retail customer load became able to choose their power
supply providers on and after January 1, 2000, and all of the Company's
customers will be able to choose their power supply providers as of July 1,
2000. On and after January 1, 2000 and through December 31, 2003, the Company is
required to offer fully-bundled "standard offer" electric service, under
regulated rates, to all customers who do not choose an alternate power supply
provider. The standard offer rates must include the fully-bundled price of
generation, transmission and distribution services, the competitive transition
assessment, the systems benefits charge and the conservation and renewable
energy charges. The fully-bundled standard offer rates must also be at least 10%
below the average fully-bundled prices in 1996.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be under the above requirements of the
Restructuring Act. In April, May and June of 1999, the Company filed descriptive
material, data and supporting testimony with the DPUC setting forth the
Company's overall approach for determining the components of its standard offer
rates, and for continuation of the five-year Rate Plan ordered by the DPUC in
its 1996 financial and operational review of the Company (see above) through the
four-year standard offer period. On July 27, 1999, the Company and Enron Capital
& Trade Resources Corp. (ECTR), an affiliate of Enron Corp., Houston, Texas
(Enron) filed with the DPUC a joint stipulation and settlement proposal to
resolve simultaneously all of the issues in the Company's standard offer rate
proceeding. The proposal included an arrangement between the Company and ECTR
whereby ECTR will supply all of the generation services needed by the Company to
meet its standard offer obligations for the four-year standard offer period, and
an assumption by ECTR of all of the Company's long-term purchased power
agreement (PPA) obligations. The stipulation and settlement proposal also
provided for the Company's standard offer rates at a fully-bundled level that
complies with the 10% reduction required by the Restructuring Act, including the
generation services component of these rates, the Company's stranded costs for
purposes of future recovery, the competitive transition assessment, systems
benefits charge, delivery (transmission and distribution) charges, and
conservation, load management and renewable energy charges. The Company also
requested that a purchased power adjustment clause authorized by the
Restructuring Act be put in place to adjust standard offer rates for limited
purposes, and that the Company's five-year Rate Plan, as modified and
supplemented by the stipulation and settlement proposal, be continued during the
four-year standard offer period. In its decision, dated October 1, 1999, on the
Company's standard offer rates, the DPUC approved elements of the stipulation
and settlement proposal, including the arrangements with ECTR, subject to
specified changes, including changes in the level of the generation services
component of customers' rates. On October 15, 1999, the Company filed its
standard offer generation services component of rates in compliance with the
DPUC's decision, and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal. These filings were approved by the DPUC on
December 9, 1999 and, on December 28, 1999, the Company and Enron Power
Marketing, Inc. (EPMI), another affiliate of Enron, entered into a Wholesale
Power Supply Agreement, a PPA Entitlements Transfer Agreement and related
agreements documenting the approved four-year standard offer power supply
arrangement and the assumption of all of the Company's PPAs, effective January
1, 2000. From January 1, 2000 through June 30, 2000, EPMI will sell to the
Company energy beyond that supplied by Wisvest as described above. The
agreements also provide for the sale to EPMI of the Company's entitlements under
all of its wholesale purchased power agreements (PPAs). However, unless or until
a PPA is terminated or formally assigned to EPMI, the Company remains legally
liable to pay the applicable power supplier all
- 24 -
<PAGE>
amounts due under the PPA. The agreements with EPMI also include a financially
settled contract for differences related to certain call rights of EPMI and put
rights of the Company with respect to the Company's entitlements in Seabrook
Unit 1 and in Millstone Unit 3, and the Company's provision to EPMI of certain
ancillary products and services associated with those nuclear entitlements,
which provisions terminate at the earlier of December 31, 2003 or the date that
the Company sells its nuclear interests. The agreements do not restrict the
Company's right to sell to third parties the Company's ownership interests in
those nuclear generation units or the generated energy actually attributable to
its ownership interests.
Based on the decisions in the regulatory proceedings described above, the
sale of the Company's fossil-generation assets in the second quarter of 1999,
the planned divestiture of its nuclear generation ownership interests by the end
of 2003, and in anticipation of the Restructuring Act becoming effective on
January 1, 2000, the Company ceased applying SFAS No. 71 to the generation
portion of its assets and operations as of December 31, 1999. Based on the
favorable DPUC decisions that allow full recovery, through the Company's rates,
of all historically incurred stranded costs, the Company did not record any
write-offs in connection with this event.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year (1) $39.1 $ - $ - $ - $ -
Internally Generated Funds less Dividends (2) 76.5 87.8 88.8 98.9 76.7
----- ---- ---- ---- ----
Subtotal 115.6 87.8 88.8 98.9 76.7
Less:
Utility Capital Expenditures (2) 58.1 36.1 18.9 21.8 30.8
Non-Regulated Business Capital Expenditures 4.3 5.4 3.9 4.0 4.2
---- ---- ---- ---- ----
Cash Available to pay Debt Maturities and Redemptions 53.2 46.3 66.0 73.1 41.7
Less:
Maturities and Mandatory Redemptions - - 100.0 100.0 -
Optional Redemptions 75.0 - - - -
Repayment of Short-Term Borrowings 17.0 - - - -
---- ---- ----- ----- ----
External Financing Requirements (Surplus) (2) $38.8 $(46.3) $34.0 $26.9 $(41.7)
==== ===== ==== ==== =====
</TABLE>
(1) Excludes $2.3 million Seabrook Unit 1 operating deposit and restricted cash
of American Payment Systems, Inc. of $26.9 million.
(2) Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections. All of these estimates are subject to change due to
future events and conditions that may be substantially different from those
used in developing the projections.
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 $60
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.
On January 16, 1999, the Company repaid $66.2 million principal amount of
6.20% Notes at maturity.
- 25 -
<PAGE>
On February 1, 1999, the Company converted $7.5 million principal amount of
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 is payable semi-annually on
August 1 and February 1. 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 is
payable semi-annually on August 1 and February 1.
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.
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.
On December 16, 1999, the Company borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $25 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2029, and
their interest rate is fixed at 5.4% for the three-year period ending December
1, 2002. At December 31, 1999, these proceeds were held by a trustee and were
recognized as cash and long-term debt on the Consolidated Balance Sheet. The
Company has used the proceeds of this $25 million borrowing to cause the
redemption and repayment of $25 million of 8.0%, 1989 Series A, Pollution
Control Revenue Bonds, an outstanding series of tax-exempt bonds on which the
Company also had a payment obligation to a trustee for the bondholders. Expenses
associated with this transaction, including redemption premiums totaling
$750,000 and other expenses of approximately $417,000, were paid by the Company.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 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 the Eurodollar interbank market in
London. 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 December 31, 1999, the Company had $17 million in
short-term borrowings outstanding under this facility.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1999, this coverage ratio was 4.7:1.0.
The provisions of the financing documents under which the Company leases a
portion of its entitlement in Seabrook Unit 1 from an owner trust established
for the benefit of an institutional investor presently require the Company to
maintain its consolidated annual after-tax cash earnings available for the
payment of interest at a level that is at least one and one-half times the
aggregate interest charges paid on all indebtedness outstanding during the year.
- 26 -
<PAGE>
On the basis of the formula contained in the Seabrook Unit 1 lease financing
documents, the coverage for the year ended December 31, 1999 was 4.7.
The Company is obligated to furnish a guarantee for its participating share
of the debt financing for the Hydro-Quebec Phase II transmission intertie
facility linking New England and Quebec, Canada. As of December 31, 1999, the
Company's guarantee liability for this debt was approximately $6.2 million.
At December 31, 1999, the Company had $68.3 million of cash and temporary
cash investments, a decrease of $56.2 million from the corresponding 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 $124.5
-----
Net cash provided by operating activities 98.5
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (266.9)
- Dividend payments (40.6)
Investment in debt securities 5.5
Net cash provided from sale of generation assets 270.6
Cash invested in unregulated businesses (88.5)
Cash invested in plant, including nuclear fuel (34.8)
-----
Net Change in Cash (56.2)
-----
Balance, December 31, 1999 $68.3
=====
SUBSIDIARY OPERATIONS
The Company 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 the Company's regulated electric utility business and provide
long-term rewards to the Company 's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
- 27 -
<PAGE>
The after-tax impact of the subsidiaries on the consolidated financial
statements of the Company is as follows:
ASSETS
NET LOSS LOSS AT DEC. 31
(000'S) PER SHARE (000'S)
-------- --------- ----------
(Basic & Diluted)
1999 $2,256 $0.16 $194,642
1998 1,111 0.08 83,306
1997 2,185 0.16 69,338
In 1997, the Company made provisions for losses of $1.6 million (after-tax)
associated with collection agent errors and defaults and miscellaneous other
items at its American Payment Systems, Inc. subsidiary.
NEW ACCOUNTING STANDARDS
See the discussion included in PART II, Item 8, "Financial Statements and
Supplementary Data - Notes to Consolidated Financial Statements - Note (A),
Statement of Accounting Policies."
RESULTS OF OPERATIONS
1999 VS. 1998
- -------------
Earnings for the twelve months of 1999 were $52.1 million, or $3.71 per
share (on both a basic and diluted basis), up $7.2 million, or $.51 per share,
from the twelve months of 1998. Excluding one-time items recorded during both
periods, earnings from operations for 1999 were $51.5 million, or $3.67 per
share (on both a basic and diluted basis), up $3.7 million, or $.26 per share,
from the twelve months of 1998.
Earnings from operations for 1999 before earnings "sharing" were $5.09 per
share, $1.44 per share or 39% higher than 1998. "Sharing" reduced the 1999
earnings from operations to $3.67 per share.
The one-time items recorded in 1999 and 1998 were:
EPS
- -------------- --------------------------------------------------------- -------
1999 Quarter 1 Purchased power expense refund $ .12
Sharing due to refund $(.08)
- -------------- --------------------------------------------------------- -------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .14
Sharing due to one time items recorded through
3rd quarter $(.05)
- -------------- --------------------------------------------------------- -------
1998 Quarter 4 Property tax settlement with the City of New Haven $(.59)
Reversal of sharing imputed to property tax settlement $ .29
- -------------- --------------------------------------------------------- -------
Utility Earnings from Operations
- --------------------------------
Overall, retail sales margin decreased by $13.2 million in 1999 compared to
1998, and retail sales margin from operations decreased by $9.4 million. Retail
revenues from operations increased by $11.9 million as electric revenues
increased for the reasons detailed below. Retail revenues decreased by $3.9
million because of "sharing" required under the current regulatory structure as
applied to the one-time items recorded in both periods. Retail fuel and energy
expense from operations increased by $20.7 million, primarily from higher
purchased power prices as a result of the Company's transition from a producer
to a purchaser of its customers' energy requirements, and the need to purchase
additional energy to replace power lost from nuclear plant refueling outages.
The principal components of the retail sales margin change for 1999, compared to
1998, include:
- 28 -
<PAGE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------- ----------- ---------- ----------
From From
Retail Sales Margin: $ millions Operations One-time Total
- ---------------------------------------------------------------- ----------- ---------- ----------
<S> <C> <C> <C>
Revenue from:
- ---------------------------------------------------------------- ----------- ---------- ----------
Sharing: for 1999 (see Note A) (14.4) (3.9) (18.3)
- ---------------------------------------------------------------- ----------- ---------- ----------
Estimate of "real" retail sales growth, up 3.2% 20.2 0 20.2
- ---------------------------------------------------------------- ----------- ---------- ----------
Estimate of weather effect on retail sales, up 1.1% 7.1 0 7.1
- ---------------------------------------------------------------- ----------- ---------- ----------
Sales decrease from Yale University cogeneration, (0.6)% (3.6) 0 (3.6)
- ---------------------------------------------------------------- ----------- ---------- ----------
Price mix of sales and other 2.6 0 2.6
- ---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL REVENUE 11.9 (3.9) 8.0
- ---------------------------------------------------------------- ----------- ---------- ----------
REVENUE BASED TAXES (0.6) 0.1 (0.5)
- ---------------------------------------------------------------- ----------- ---------- ----------
Fuel and energy, margin effect:
- ---------------------------------------------------------------- ----------- ---------- ----------
Sales increase (4.7) 0 (4.7)
- ---------------------------------------------------------------- ----------- ---------- ----------
Nuclear fuel prices and outage replacement power costs (0.5) 0 (0.5)
- ---------------------------------------------------------------- ----------- ---------- ----------
Purchased energy prices (see Note B) (15.5) 0 (15.5)
- ---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL FUEL AND ENERGY (20.7) 0 (20.7)
- ---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL SALES MARGIN (9.4) (3.8) (13.2)
- ---------------------------------------------------------------- ----------- ---------- ----------
</TABLE>
A. The Company's preliminary return on regulated utility common stock
equity for the twelve months of 1999 exceeded the 11.5% "sharing"
trigger by a total amount of about $53 million of pre-tax income. As a
result, and excluding "sharing" associated with one-time items, a book
revenue "sharing" reduction from operations of $17.4 million,
including a gross earnings tax component, was recorded in 1999,
approximately $14.4 million more than the $3.0 million book revenue
"sharing" reduction imputed from operations in 1998. All 1998 sharing
from operations was offset by the impact of sharing associated with a
one-time item recorded in December of 1998.
B. On April 16, 1999, the Company completed the sale of its operating
fossil-fueled generating plants and existing wholesale sales contracts
that was required by Connecticut's electric utility industry
restructuring legislation. As a result, the "geography" of the
Company's costs on the income statement and, hence, the year-over-year
variances, changed significantly beginning in the second quarter. This
particularly relates to wholesale revenue, retail purchased energy and
fossil fuel expenses, operation and maintenance expense, depreciation,
interest charges and property taxes. For example, the increased
purchased energy costs included in the table above are more than
offset by some of the decline in miscellaneous operation and
maintenance expense, due principally to the sale of generating plants,
shown in the table below, and to decreases in depreciation and
property taxes.
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $10.4 million in 1999 compared to 1998 from lower wholesale sales. Other
operating revenues, which include NEPOOL related transmission revenues,
increased by $6.4 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.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $5.7 million in 1999 compared to 1998. The principal
components of these expense changes include:
- 29 -
<PAGE>
$millions
- --------------------------------------------------------------------- ----------
Capacity expense:
- --------------------------------------------------------------------- ----------
Connecticut Yankee (2.4)
- --------------------------------------------------------------------- ----------
Cogeneration and other purchases (see Note A) 1.8
- --------------------------------------------------------------------- ----------
TOTAL CAPACITY EXPENSE (0.6)
- --------------------------------------------------------------------- ----------
Other O&M expense:
- --------------------------------------------------------------------- ----------
Seabrook Unit 1 (refueling outage costs and accruals) 4.1
- --------------------------------------------------------------------- ----------
Millstone Unit 3 (refueling outage costs and accruals) 1.1
- --------------------------------------------------------------------- ----------
Other expenses at nuclear units (0.8)
- --------------------------------------------------------------------- ----------
Fossil generation unit operating and maintenance costs (23.1)
- --------------------------------------------------------------------- ----------
NEPOOL transmission expense 3.4
- --------------------------------------------------------------------- ----------
Site remediation costs (see Note B) 7.8
- --------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale 2.4
- --------------------------------------------------------------------- ----------
TOTAL O&M EXPENSE (5.1)
- --------------------------------------------------------------------- ----------
Note A: A cogeneration facility was out of service for about a
month in the first quarter of 1998 but has operated normally in
1999.
Note B: These costs were incurred to repair a bulkhead at English
Station and for remediation of environmental conditions at
another site. No further material expenses are currently
anticipated for remediation of these sites.
Depreciation expense decreased by $12.4 million in 1999 compared to 1998,
due primarily to the generation asset sale.
On December 31, 1996, the Connecticut Department of Public Utility Control
issued an 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 scheduled accelerated
amortization for 1998, amounting to $13.1 million before-tax ($8.5 million
after-tax), was recorded against earnings from operations in 1998. The Company
recorded all of the scheduled accelerated amortization for 1999 by amortizing
regulatory income tax assets, totaling $12.1 million after-tax ($20 million
pre-tax equivalent).
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%, which the Company did achieve
during the third quarter of 1999. One-time items recorded against the return on
utility common stock equity, before the Company achieves the 11.5%, are recorded
with an appropriate "sharing" effect if the Company projects, at that time, that
there will be total "sharing" for the year adequate to cover the "sharing" for
the one-time item. Such "sharing" amortization was recorded in the first quarter
of 1999, in the amount of $1.0 million before-tax ($0.6 million after-tax), as a
result of the one-time gain recorded in that quarter. "Sharing" amortization
from operations of $10.0 million after-tax ($16.7 million before-tax) was
recorded in 1999. "Sharing" amortizations recorded and imputed in the first nine
months of 1998 were: $0.5 million before-tax ($0.3 million after-tax) as a
result of a one-time item, and $2.1 million before-tax ($1.2 million after-tax)
from operations. "Sharing" amortization recorded against earnings from
operations in the fourth quarter of 1998 was imputed to be $0.6 million
before-tax ($0.3 million after-tax). All of those 1998 "sharing" amortizations
were reversed in the fourth quarter of 1998 as a result of the impact of a
one-time charge recorded in that quarter.
Interest charges continued on a downward trend, decreasing by $12.8 million
for the regulated business in 1999 compared to 1998, partly offset by an
increase of $3.5 million in interest charges for non-regulated subsidiaries.
Most of the reduction in utility interest charges occurred after the generation
asset sale, which was completed on
- 30 -
<PAGE>
April 16, 1999. On that date, the Company used proceeds received from the sale
of plant to pay off $205 million of debt.
Non-regulated Business Earnings from Operations
- -----------------------------------------------
Overall, non-regulated businesses, after parent-allocated interest but
before income taxes, lost approximately $3.8 million in 1999 compared to losses
of about $1.8 million in 1998. American Payment Systems, Inc. (APS) earned
approximately $2.6 million (before-tax) in 1999, reflecting an increase of $1.0
million over 1998. Precision Power, Inc. (PPI) lost approximately $5.1 million
(before-tax) in 1999, compared to a loss of approximately $2.4 million in 1998,
reflecting increased infrastructure costs and lower than anticipated contract
margins.
On May 11, 1999, the Company's non-regulated subsidiary, United Bridgeport
Energy, Inc. (UBE), increased its 4% passive investment in Bridgeport Energy LLC
(BE) to 33 1/3%. The second phase of BE's merchant wholesale electric generating
project went into commercial operation in July 1999, adding 180 megawatts of
generation capacity for a total of 520 megawatts. UBE lost approximately $0.1
million (before-tax) in 1999, as a result of the second quarter shutdown of the
first phase generator to allow for construction of the second phase, and
additional unscheduled outages and higher gas prices in the fourth quarter of
1999. Other non-regulated subsidiary operations lost approximately $1.2 million
in 1999, compared to a similar loss in 1998.
Non-regulated business before-tax income is reported as part of "Other net"
income; parent interest charges allocated to the non-regulated businesses are
reported as part of "Interest charges"; and related income tax expense is
reported as part of "Non-operating income taxes."
<TABLE>
<CAPTION>
- ------------------------------------------------------------------ -------- ---------
12 mos.
ended 12 mos.
Summary of Non-regulated Business Unit Pre-tax Income: $millions Dec. 99 99 vs. 98
- ------------------------------------------------------------------ -------- ---------
<S> <C> <C>
American Payment Systems, Inc. 2.6 1.0
- ------------------------------------------------------------------ -------- ---------
Precision Power, Inc. (5.1) (2.7)
- ------------------------------------------------------------------ -------- ---------
United Bridgeport Energy, Inc. (0.1) (0.1)
- ------------------------------------------------------------------ -------- ---------
United Resources, Inc. Capital Projects (1.2) -
- ------------------------------------------------------------------ -------- ---------
TOTAL NON-REGULATED BUSINESSES (3.8) (1.8)
- ------------------------------------------------------------------ -------- ---------
</TABLE>
1998 VS. 1997
- -------------
Earnings for the twelve months of 1998 were $44.9 million, or $3.20 per
share (both basic and diluted), up $1.6 million, or $.11 per share, from the
twelve months of 1997, diluted. Excluding one-time items, accelerated
amortization due to one-time items and associated regulated "sharing" effects,
1998 earnings from operations were $47.8 million, or $3.41 per share, up $.48
per share from 1997. The one-time items and their earnings per share impacts
recorded in these periods are shown at "One-time items recorded in 1997 and
1998" below.
Retail operating revenues increased by about $9.3 million in the twelve
months of 1998 compared to 1997. Retail fuel and energy expense increased by
$7.2 million and there was an increase of $0.4 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $1.7 million. The principal components of the
retail sales margin change, year over year, include:
- 31 -
<PAGE>
$ millions
- ------------------------------------------------------------------ ---------
Revenue from:
- ------------------------------------------------------------------ ---------
DPUC rate order, excluding "sharing" (1.3)
- ------------------------------------------------------------------ ---------
Other price changes (0.3)
- ------------------------------------------------------------------ ---------
Estimate of "real" retail sales growth, up 1.3% 12.1
- ------------------------------------------------------------------ ---------
Estimate of weather effect on retail sales, up 0.2 % 1.8
- ------------------------------------------------------------------ ---------
Sales decrease from Yale University cogeneration, (0.9) % (3.0)
- ------------------------------------------------------------------ ---------
TOTAL REVENUE IMPACT 9.3
- ------------------------------------------------------------------ ---------
Fuel and energy, margin effect:
- ------------------------------------------------------------------ ---------
Sales increase (2.7)
- ------------------------------------------------------------------ ---------
Increased nuclear availability 0.4
- ------------------------------------------------------------------ ---------
Unscheduled outage at Bridgeport Unit 3 (see Note A) (2.5)
- ------------------------------------------------------------------ ---------
Fossil price and other (2.4)
- ------------------------------------------------------------------ ---------
TOTAL FUEL AND ENERGY IMPACT (7.2)
- ------------------------------------------------------------------ ---------
Note A: Saltwater contamination caused a shutdown of the Bridgeport
Harbor Unit 3 generating unit on May 22, 1998. The unit
returned to full service on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale energy expense)
increased slightly in the twelve months of 1998 compared to the twelve months of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $5.8 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $15.0 million in the twelve months of 1998 compared to the
twelve months of 1997. The principal components of these expense changes, year
over year, include:
$ millions
- ------------------------------------------------------------------ ---------
Capacity expense:
- ------------------------------------------------------------------ ---------
Connecticut Yankee preparing for decommissioning (4.2)
- ------------------------------------------------------------------ ---------
Cogeneration and other purchases (1.3)
- ------------------------------------------------------------------ ---------
Other O&M expense:
- ------------------------------------------------------------------ ---------
Seabrook (4.6)
- ------------------------------------------------------------------ ---------
Millstone Unit 3 (4.0)
- ------------------------------------------------------------------ ---------
Fossil generation unit overhauls and outages 7.5
- ------------------------------------------------------------------ ---------
Pension investment performance and assumptions (3.0)
- ------------------------------------------------------------------ ---------
Personnel reductions (6.0)
- ------------------------------------------------------------------ ---------
NEPOOL transmission expense 3.1
- ------------------------------------------------------------------ ---------
Other (2.5)
- ------------------------------------------------------------------ ---------
Depreciation expense, excluding accelerated amortization, increased by $1.5
million in the twelve months of 1998 compared to 1997. According to the
Company's current regulatory Rate Plan, "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 in 1997 was recorded ratably
throughout the year as a charge to depreciation expense. All of the accelerated
amortization for 1998, $13.1 million, was recorded against earnings from
operations. In addition, as part of the "sharing" mechanism, the Company would
have accrued an additional amortization of about $2.6 million ($1.7 million
after-tax) in 1998 against utility earnings from operations. Because of the
one-time items in 1998, no "sharing" was actually recorded. The one-time charge
for property tax expense incurred in the fourth quarter was a utility expense
and negated the "sharing" that would have occurred from operations.
- 32 -
<PAGE>
Other net income from operations decreased by about $1.9 million in the
twelve months of 1998 compared to 1997. The Company's largest unregulated
subsidiary, American Payment Systems, Inc. (APS), earned about $1.6 million
(before-tax) in 1998 compared to a $2.7 million loss in 1997. This was more than
offset by greater losses, compared to 1997, in the Company's other unregulated
subsidiaries: $1.2 million (before-tax) at Precision Power, Inc. from the
write-off of previously deferred costs and a review of reserves, and $1.2
million (before-tax) from start-up costs in other unregulated activities. By
DPUC order, since consolidation at the unregulated subsidiary level produced no
net taxable income in either year, the tax benefits associated with the losses,
about $0.8 million in 1998 and $0.4 million in 1997, were treated as benefits to
utility income for the purposes of calculating return on utility common equity
and "sharing." Other net income also decreased due to the absence of other
non-utility income accruals of about $1 million made in 1997 that reversed a
provision for 1997 Millstone 3 expense made in 1996 and charged to operating
expenses in 1997, cancelled project costs of about $0.8 million for merger and
acquisition advisor fees and analysis and lower income from non-operating
utility investments.
Interest charges, excluding allowance for borrowed funds used during
construction, continued on their downward trend, decreasing by $10.4 million in
the twelve months of 1998 compared to 1997, as a result of the Company's
refinancing program and strong cash flow.
OVERVIEW OF "SHARING" AND THE IMPACT ON EARNINGS
- ------------------------------------------------
As previously indicated, the Company's regulatory Rate Plan requires a
"sharing" of regulated utility income that produces a return on utility equity
exceeding 11.5%. The measurement of this utility income and resulting return
calculation includes the effects of any utility one-time items. Under the Rate
Plan, one-third of the income above the 11.5% return would be applied to
customer bill reductions, one-third would be applied to additional amortization
of regulatory assets, and one-third would be retained by shareowners.
Earnings from operations, which excludes the impact of one-time items,
should reflect an appropriate imputed amount of "sharing" to reflect accurately
what the earnings would have been had neither the one-time items, nor their
impact on "sharing," occurred. The Company estimates that the "sharing" that
would have occurred had there been no one-time items in 1998 would have been: a
revenue reduction of about $3.0 million or $.12 per share, increased
amortization of about $1.7 million (after-tax) or $.12 per share, and retention
by the Company of $1.7 million of income (after-tax) or $.12 per share. To
summarize for 1998:
1998 Earnings per share (EPS) From One-time
Operations Items
and and "Sharing"
"Sharing" Reversals Total
--------- ------------- -----
Utility earnings before "sharing" $3.73 $(.45) $3.28
Less: Utility earnings to be "shared" (.36) .36 -
---- --- ----
Utility EPS at 11.5% utility return $3.37 $(.09) $3.28
Plus: 1/3 Retained "Sharing" benefit .12 (.12) -
---- ---- ----
Net Utility EPS 3.49 (.21) 3.28
Unregulated Subsidiaries (.08) - (.08)
---- ---- ----
Total 1998 EPS $3.41 $(.21) $3.20
Earnings reported through 3rd quarter 3.02 (.12) 2.90
---- ----- ----
Imputed 4th quarter earnings $ .39 $(.09) $ .30
==== ===== ====
- 33 -
<PAGE>
ONE-TIME ITEMS RECORDED IN 1997 AND 1998
- ----------------------------------------
One-time Items EPS
- --------------------------------------------------------------------------------
1997 Cumulative deferred operating income tax benefits associated $ .48
with future decommissioning of fossil fuel generating plants
(see explanation below)
- --------------------------------------------------------------------------------
1997 Accelerated amortization associated with one-time item $(.30)
- --------------------------------------------------------------------------------
1997 Gain from subleasing office space $ .05
- --------------------------------------------------------------------------------
1997 Pension benefit adjustments associated with 1996 VERP and VSP $ .11
- --------------------------------------------------------------------------------
1997 Contract termination charge $(.18)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1998 Refund of prior period transmission charges, with interest $ .14
"Sharing" due to one-time items recorded through third quarter $(.05)
- --------------------------------------------------------------------------------
1998 Property tax settlement with the City of New Haven, CT $(.59)
Reversal of "sharing" imputed to property tax settlement $ .29
- --------------------------------------------------------------------------------
In accordance with a DPUC decision issued December 31, 1996 and effective
for years 1997-2001, related to a financial and operational review of the
Company (the Rate Plan), the Company was directed to explore and implement ways
to reduce its potentially stranded costs. In addition, the decision required the
Company to record a specified amount of accelerated amortization of conservation
and load management costs during 1997 ($6.4 million before-tax, $4.1 million
after-tax) as a stranded costs mitigation effort if the Company's return on its
utility common stock equity exceeded 10.5% for that year. Based on these
requirements, the Company recorded an operating income tax expense reduction of
$6.7 million, or $.48 per share, in the first quarter of 1997, which made
provision for the cumulative deferred tax benefit associated with the estimated
future decommissioning costs of fossil fuel generating plants for which the
Company had made provision in prior years without accruing the tax benefit. This
tax benefit, originally recorded in the second quarter of 1997, has been
restated to the first quarter of 1997 following consultations with the staff of
the Securities and Exchange Commission and the Company's independent accountants
to coincide with the effective date of the Rate Plan. As a result of recording
the tax benefit, the Company exceeded the 10.5% utility common stock equity
return and therefore was able to record the specified amount of accelerated
amortization required in the Rate Plan for 1997. The accelerated amortization,
which was originally recorded in the second quarter of 1997, has been restated
and is now recorded ratably throughout 1997 as a charge to depreciation expense
on the consolidated income statement. The after-tax amount of accelerated
amortization was less than the cumulative deferred tax benefit because the
after-tax amount of additional amortization was specified in the Rate Plan while
the deferred tax benefit was calculated based upon the cumulative amount of
estimated future decommissioning costs that had been recovered through rates at
that time.
During prior years, the Company had recognized, on a net basis, the
deferred tax assets and offsetting regulatory tax liability related to these tax
benefits associated with the future decommissioning of its fossil generating
plants on its consolidated balance sheet in accordance with Statement of
Financial Accounting Standards No. 109. The Company had recognized this
regulatory tax liability through the systematic recovery of before-tax future
decommissioning costs for its fossil generating units in its rates over the
useful lives of these units.
Additional 1997 one-time items included: a $.05 per share gain related to
subleasing office space; a "curtailment" gain of $2.5 million ($1.5 million
after-tax), or $.11 per share, related to forgone pension benefits associated
with the approximate 230 employees who left the Company as a result of 1996
voluntary retirement and separation programs; and a charge of $4.3 million ($2.5
million after-tax), or $.18 per share, for early termination of a contract with
consultants that assisted the Company with its restructuring efforts, after the
Company determined that the early termination option was more economic than the
multi-year performance-based payout option. All of these one-time items were
recorded as "Operating Expense - Operations - other."
As reported in its Quarterly Report on Form 10-Q for the period ending
March 31, 1998, filed with the Securities and Exchange Commission, the Company
had been investigating potential errors in the accounting
- 34 -
<PAGE>
procedure of APS. As a result of the investigation, the Company determined that
APS should create additional reserves for shortfalls in agent collections and
other potentially uncollectible receivables of $4.9 million. Of the total of
$4.9 million, $2.8 million and $2.1 million were restated to 1997 and 1996,
respectively, to provide for the reserves in the relevant periods. See PART II,
Item 8, "Financial Statements and Supplementary Data - Notes to Consolidated
Financial Statements - Note (Q), Restatement of Financial Results."
The principal business of APS is to operate a network of field agents for
the purpose of accepting cash and check payments of clients' bills and
forwarding those payments, through APS accounts, to the client. APS experienced
rapid growth in 1996 and 1997. The number of agents in the APS network increased
from 2,537 in 1995 to 4,904 in 1997; and the dollar volume of payment
transactions increased from $2.3 billion on 17.2 million transactions in 1995 to
$7.5 billion on 73.2 million transactions in 1997.
At year-end 1996, APS created a reserve to provide for losses associated
with agent collections and uncollectible check deposits totaling $4.4 million
before-tax. The Company has restated its 1996 earnings to move $0.7 million of
this loss to 1995. See PART II, Item 8, "Financial Statements and Supplementary
Data - Notes to Consolidated Financial Statements - Note (Q), Restatement of
Financial Results." These losses stemmed from inadequate "back-office" banking
systems and controls that failed to detect a significant amount of deposit
shortfalls from agents and failed to identify a substantial number of
uncollectible check deposits that were reimbursable from the clients serviced.
Specifically, APS agent bank accounts were not fully reconciled at the time the
APS balance sheet items were prepared to allow for the identification,
measurement and enforcement of material claims for recovery from APS agents for
defalcated amounts or from APS customers for checks returned by banks due to
insufficient funds.
In 1997, under new management with added banking expertise, APS began
implementing new systems and controls to manage the agent collection/deposit
process. These changes included the increased use of daily cash reporting and
account reconciliation on high volume agents, extensive reconciliation
procedures, and agent monitors that interact daily with agents to investigate
discrepancies in deposits. These new procedures were fully implemented by the
4th quarter of 1997.
In March of 1998, APS contracted for an insurance policy with an A+ rated
carrier to protect against future losses from robberies, missing deposits, and
agent fraud. The effect of the policy is to "cap" the cost of such losses at
$200,000 per event per agent. The level of detected agent fraud in 1998 was well
below that level, averaging $23,000 per month in total, or .004% of the monthly
transaction dollar volume.
Also in 1998, APS implemented new procedures to correct difficulties in
tracking agent deposits in bank merger or acquisition situations. During this
process, it was discovered that certain large agent depository bank accounts
were not reconciled appropriately and that the amount of APS working capital
invested in the agent depository accounts to cover timing delays for cash
transfers was over-estimated and the amount due to utilities underestimated.
These cash flow discrepancies were masked by the rapid growth of cash deposits
from the expansion in the agent network and the failure to properly take into
account the cash effects of uncleared bank transfers from agent depository
accounts to utilities. APS accounting procedures, which failed to detect the
cash flow discrepancies, have been rectified.
At December 31, 1998, the consolidated balance sheet reflected $54.5
million of accounts payable owed to APS customers. This payable was relieved by
$23.1 million of APS restricted cash, representing collections by APS agents
prior to transmittal to the respective APS customers and $31.4 million of
accounts receivable representing collections by APS agents that had not yet been
deposited into APS bank accounts. Of the accounts payable and accounts
receivable amounts, $4.7 million had originally been recorded on the
consolidated balance sheet as of December 31, 1998.
The following table summarizes the effect of the restatements described
above to the provision for APS losses, restricted cash, other accounts
receivable, and accounts payable - APS customers:
- 35 -
<PAGE>
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
1998 1997 1996 1995
---- ---- ---- ----
(In Thousands)
<S> <C> <C> <C> <C>
Provision for APS losses (before-tax), as originally reported $4,900 $ - $4,471 $ -
Effect of restatement, described above (4,900) 2,825 1,279 796
----- ----- ----- ---
Provision for APS losses (before-tax), as restated $ - $2,825 $5,750 $796
===== ===== ===== ===
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
1998 1997 1996
---- ---- ----
(In Thousands)
<S> <C> <C> <C>
Restricted cash, as originally reported $ - $ - $ -
Effect of restatement, described above 23,056 21,063 16,681
------ ------ ------
Restricted cash, as restated $23,056 $21,063 $16,681
====== ====== ======
Other accounts receivable, as originally reported (1) $37,472 $27,914 $38,367
Effect of restatement, described above
Additional accounts receivable for APS agents 26,768 23,284 19,903
Additional APS agent collection reserves - (4,900) (2,075)
------ ------ ------
Other accounts receivable, as restated $64,240 $46,298 $56,195
====== ====== ======
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
1998 1997 1996
---- ---- ----
(In Thousands)
<S> <C> <C> <C>
Accounts payable-APS customers, as originally reported $ - $ - $ -
Accounts payable-APS customers reclassed
from accounts payable 4,691 6,147 7,588
Effect of restatement, described above
Restricted cash 23,056 21,063 16,681
Additional amounts owed to APS customers 26,768 23,284 19,903
------ ------ ------
Accounts payable-APS customers, as restated $54,515 $50,494 $44,172
====== ====== ======
</TABLE>
(1) Includes accounts receivable from APS agents originally included in other
accounts receivable of $4,691,000, $6,147,000 and $7,588,000 as of December
31, 1998, 1997 and 1996, respectively.
The one-time gain recorded in the third quarter of 1998 was to record a
refund of prior period transmission charges. It amounted to $3.4 million or $.14
per share, but was recorded as two separate items; $1.8 million, or a gain of
$.07 per share, as a credit to operation expense and $1.6 million, or $.07 per
share, of interest income recorded as Other Income and (Deductions), Other-net.
At the time this one-time item was recorded, in the third quarter of 1998, the
Company estimated that it would be in the Rate Plan "sharing" range of earnings
for the year of 1998 in total, and recorded, therefore, a "sharing" revenue
reduction and increased amortization expense to reflect that estimate. The
"sharing" related to the utility portion of this one-time item, the operation
expense credit, was a charge of $.05 per share. The net result of the one-time
gain for the period was, therefore, $.09 per share. The one-time charge recorded
in the fourth quarter of 1998 as property tax expense of $14 million, or $.59
per share, reflected the DPUC's rejection of the Company's proposed accounting
treatment of a property tax settlement between the Company and the City of New
Haven. Upon that rejection, the Company was required to write-off immediately
the full effect of that settlement. As a result of this one-time charge, the
Company's final 1998 earnings results eliminated the requirement to record any
Rate Plan "sharing" in 1998. The one-time charge eliminated "sharing" revenue
reductions and increased amortization expense amounting to $.29 per share. The
net result of the one-time charge for the period was, therefore, $.30 per share.
- 36 -
<PAGE>
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year Rate Plan
- -------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework to reduce the Company's retail prices and accelerate the recovery of
certain "regulatory assets," beginning with deferred conservation costs. The
Company has operated under the terms of this Order since January 1, 1997. The
Order's schedule of price reductions and accelerated amortizations was based on
a DPUC pro-forma financial analysis that anticipated the Company would be able
to implement such changes and earn an allowed annual return on common stock
equity invested in utility assets of 11.5% over the period 1997 through 2001.
The Order established a set formula to share (see "Sharing Implementation"
below) any utility income that would produce a return above the 11.5% level:
one-third to be applied to customer price reductions, one-third to be applied to
additional amortization of regulatory assets, and one-third to be retained by
shareowners. Utility income is inclusive of earnings from operations and
one-time items. See "Major Influences on Financial Condition" for a more
extensive description of the five-year Rate Plan.
Sharing Implementation
- ----------------------
Based on the traditional quarterly earnings pattern, the Company realizes
about one-half of its pre-sharing utility earnings in the third quarter of each
year. The Company will not likely ever exceed the sharing level of utility
earnings before the third quarter of any year that "sharing" is in effect.
Assuming the sharing level of utility earnings is exceeded in the third quarter
of a particular year, then all positive utility earnings recorded in the fourth
quarter of that year will be subject to "sharing."
A look at 2000; continued growth of non-regulated business value
- ----------------------------------------------------------------
On January 1, 2000, the Company completed the restructuring process
required by the Connecticut electric utility industry restructuring legislation
in 1998 and its regulated business became an electricity delivery business. All
--------
customers are now seeing at least a 10% reduction in their electric rates from
1996 levels.
The framework of the current Rate Plan, including the "sharing" mechanism,
is expected to continue through 2001. Regulatory decisions during 1999 did not
alter the Company's allowed return of 11.5% on utility equity, and did not
impinge upon the Company's ability to achieve that return.
If the Company were to earn 11.5% on equity in the regulated business, that
level of earnings should generate $3.25 - $3.35 per share. In addition,
operation of the Company's nuclear entitlements should contribute to earnings
until such time as the units are sold. The Company expects that utility income
for common stock above 11.5% return will be greatly reduced from 1999 levels,
due to mandates in the restructuring legislation; and the Company expects that
the shareowners' portion of shared utility income will contribute no more than
$.10 - $.15 per share. Under these assumptions, customers also will see reduced
benefits.
Non-regulated businesses are expected to make significant contributions to
earnings in 2000. Both American Payment Systems and United Bridgeport Energy
should each contribute $.10 - $.15 per share in 2000. Precision Power and the
balance of United Resources, Inc. are expected to lose up to $.05 per share. As
a result of management's continued confidence in the potential of the
non-regulated businesses, the Company is evaluating further investments in this
area. However, additional losses could be incurred due to new growth initiatives
if the potential for future benefits warrant such losses.
- 37 -
<PAGE>
Total earnings for 2000, including the regulated business with sharing and
the non-regulated business units, are now estimated to be in the range of $3.60
to $3.80 per share. This estimate is contingent upon normal weather and normal
operation of the nuclear units.
- 38 -
<PAGE>
<TABLE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
OPERATING REVENUES (NOTE G) $679,975 $686,191 $709,029
------------ ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 159,403 151,544 182,666
Capacity purchased 33,873 34,515 39,976
Other (Note G) 147,709 146,058 158,600
Maintenance 37,987 42,888 42,203
Depreciation (Note G) 57,351 82,809 74,618
Amortization of cancelled nuclear project, 36,393 13,758 13,758
deferred return and regulatory tax asset (Note D and J)
Income taxes (Note A and F) 66,564 53,619 40,833
Other taxes (Note G) 47,140 64,674 52,493
------------ ------------ ------------
Total 586,420 589,865 605,147
------------ ------------ ------------
OPERATING INCOME 93,555 96,326 103,882
------------ ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 575 13 336
Other-net (Note G) (838) 1,097 1,361
Non-operating income taxes 4,664 3,848 3,678
------------ ------------ ------------
Total 4,401 4,958 5,375
------------ ------------ ------------
INCOME BEFORE INTEREST CHARGES 97,956 101,284 109,257
------------ ------------ ------------
INTEREST CHARGES
Interest on long-term debt 42,104 50,129 63,063
Interest on Seabrook obligation bonds owned by the company (6,844) (7,293) (6,905)
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other interest (Note G) 4,927 6,507 3,280
Allowance for borrowed funds used during construction (1,660) (455) (1,239)
------------ ------------ ------------
43,340 53,701 63,012
Amortization of debt expense and redemption premiums 2,392 2,511 2,788
------------ ------------ ------------
Net Interest Charges 45,732 56,212 65,800
------------ ------------ ------------
NET INCOME 52,224 45,072 43,457
Premium (Discount) on preferred stock redemptions 53 (21) (48)
Dividends on preferred stock 66 201 205
------------ ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $52,105 $44,892 $43,300
============ ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,052 14,018 13,976
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,055 14,023 13,992
EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.71 $3.20 $3.10
============ ============ ============
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.71 $3.20 $3.09
============ ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.88
</TABLE>
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 39 -
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(THOUSANDS OF DOLLARS)
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $52,224 $45,072 $43,457
------------ ------------ ------------
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 83,374 88,099 79,487
Deferred income taxes 17,451 3,074 6,804
Deferred income taxes-generation asset sale (70,222) - -
Deferred investment tax credits - net (468) (762) (762)
Amortization of nuclear fuel 8,425 6,892 5,799
Allowance for funds used during construction (2,235) (468) (1,575)
Amortization of deferred return 12,586 12,586 12,586
Changes in:
Accounts receivable - net 8,749 (14,889) 17,626
Fuel, materials and supplies (1,202) (14,466) 2,863
Prepayments 4,368 (4,027) 211
Accounts payable 2,025 (9,782) 8,404
Interest accrued (1,770) (63) (3,569)
Taxes accrued (6,446) 4,849 3,116
Other assets and liabilities (8,386) (4,062) (1,644)
------------ ------------ ------------
Total Adjustments 46,249 66,981 129,346
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 98,473 112,053 172,803
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 1,157 4,923 (6,432)
Long-term debt 25,000 199,636 98,500
Notes payable (69,761) 49,141 26,786
Securities redeemed and retired:
Preferred stock (4,299) (52) (110)
Long-term debt (218,008) (222,348) (151,199)
(Premium) Discount on preferred stock redemption (53) 21 48
Expenses of issues (550) (1,600) (1,500)
Lease obligations (348) (339) (315)
Dividends
Preferred stock (116) (202) (206)
Common stock (40,450) (40,285) (40,408)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (307,428) (11,105) (74,836)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in unregulated businesses (88,489) - -
Net cash received from sale of generation assets 270,590 - -
Plant expenditures, including nuclear fuel (34,772) (38,040) (33,436)
Investment in debt securities 5,447 8,528 (34,541)
------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 152,776 (29,512) (67,977)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (56,179) 71,436 29,990
BALANCE AT BEGINNING OF PERIOD 124,501 53,065 23,075
------------ ------------ ------------
BALANCE AT END OF PERIOD 68,322 124,501 53,065
LESS: RESTRICTED CASH 29,223 26,812 23,392
------------ ------------ ------------
BALANCE: UNRESTRICTED CASH AND TEMPORARY CASH INVESTMENTS $39,099 $97,689 $29,673
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $40,020 $51,481 $59,441
============ ============ ============
Income taxes $121,450 $42,450 $26,773
============ ============ ============
</TABLE>
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 40 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 AND 1998
ASSETS
(Thousands of Dollars)
1999 1998
----- ----
Utility Plant at Original Cost
In service $1,007,065 $1,886,930
Less, accumulated provision for depreciation 532,409 714,375
-------------- ------------
474,656 1,172,555
Construction work in progress 25,708 33,695
Nuclear fuel 21,101 20,174
-------------- ------------
Net Utility Plant 521,465 1,226,424
-------------- ------------
Other Property and Investments
Investment in generation facility 83,494 -
Nuclear decommissioning trust fund assets 28,255 23,045
Other 20,098 14,828
-------------- ------------
131,847 37,873
-------------- ------------
Current Assets
Unrestricted cash and temporary cash investments 39,099 97,689
Restricted cash 29,223 26,812
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 56,057 54,178
Other, less allowance for doubtful accounts of
$508 and $631 53,612 64,240
Accrued utility revenues 25,019 21,079
Fuel, materials and supplies, at average cost 9,259 33,613
Prepayments 3,056 7,424
Other 4,801 154
-------------- ------------
Total 220,126 305,189
-------------- ------------
Deferred Charges
Unamortized debt issuance expenses 8,688 9,421
Other 6,099 1,664
-------------- ------------
Total 14,787 11,085
-------------- ------------
Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Nuclear plant investments-above market 518,268 -
Income taxes due principally to book-tax
differences (Note A) 166,965 264,811
Long-term purchase power contracts-above market 144,406 -
Connecticut Yankee 37,013 42,633
Unamortized redemption costs 22,314 23,468
Unamortized cancelled nuclear project 8,780 10,952
Displaced worker protection costs 5,746 -
Uranium enrichment decommissioning costs 1,040 1,177
Deferred return - Seabrook Unit 1 - 12,586
Other 5,453 4,962
-------------- ------------
Total 909,985 360,589
-------------- ------------
$1,798,210 $1,941,160
============== ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 41 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 AND 1998
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1999 1998
----- ----
Capitalization (Note B)
Common stock equity
Common stock (no par value, 14,062,502 and $292,006 $292,006
14,034,562 shares outstanding in 1999
and 1998)
Paid-in capital 2,253 2,046
Capital stock expense (2,170) (2,182)
Unearned employee stock ownership plan equity (9,261) (10,210)
Retained earnings 175,470 163,847
-------------- ------------
458,298 445,507
Preferred stock - 4,299
Company-obligated mandatorily redeemable
securities of subsidiary holding solely
parent debentures 50,000 50,000
Long-term debt
Long-term debt 605,641 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
-------------- ------------
Net long-term debt 518,228 664,510
Total 1,026,526 1,164,316
-------------- ------------
Noncurrent Liabilities
Purchase power contract obligation 144,406 -
Nuclear decommissioning obligation 28,255 23,045
Connecticut Yankee contract obligation 27,056 32,711
Pensions accrued (Note H) 19,026 31,097
Obligations under capital leases 16,131 16,506
Other 10,394 6,622
-------------- ------------
Total 245,268 109,981
-------------- ------------
Current Liabilities
Current portion of long-term debt 25,000 66,202
Notes payable 17,131 86,892
Accounts payable 49,069 48,749
Accounts payable - APS customers 56,220 54,515
Dividends payable 10,125 10,155
Taxes accrued 2,570 9,015
Interest accrued 8,433 10,203
Obligations under capital leases 375 348
Other accrued liabilities 39,421 39,845
-------------- ------------
Total 208,344 325,924
-------------- ------------
Customers' Advances for Construction 1,867 1,867
-------------- ------------
Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Accumulated deferred investment tax credits 15,157 15,623
Deferred gains on sale of property 15,901 4
Customer refund 18,381 -
Other 2,543 2,061
-------------- ------------
Total 51,982 17,688
-------------- ------------
Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
TO TAXING AUTHORITIES) 264,223 321,384
Commitments and Contingencies (Note L)
-------------- ------------
$1,798,210 $1,941,160
============== ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 42 -
<PAGE>
<TABLE>
<CAPTION>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
DECEMBER 31, 1999, 1998 AND 1997
(DOLLAR AMOUNTS IN THOUSANDS)
CAPITAL UNEARNED
COMMON STOCK PREFERRED STOCK PAID-IN STOCK ESOP RETAINED
SHARES(A) AMOUNT SHARES(B) AMOUNT CAPITAL EXPENSE EQUITY EARNINGS TOTAL
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1996 14,101,291 284,579 44,612 4,461 772 (2,182) - $156,299 $443,929
- ------------------------------------------------------------------------------------------------------------------------------------
Net income for 1997 43,457 43,457
Cash dividends on common stock
- $2.88 per share (40,255) (40,255)
Cash dividends on preferred stock (205) (205)
Issuance of 134,844 shares common stock
- no par value 134,833 4,151 577 4,728
ESOP purchase of 328,300 common shares (328,300) (11,160) (11,160)
Repurchase and cancellation of
preferred stock (1,103) (110) (110)
Discount on preferred stock repurchase 48 48
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1997 13,907,824 288,730 43,509 4,351 1,349 (2,182) (11,160) $159,344 $440,432
- ------------------------------------------------------------------------------------------------------------------------------------
Net income for 1998 45,072 45,072
Cash dividends on common stock
- $2.88 per share (40,389) (40,389)
Cash dividends on preferred stock (201) (201)
Issuance of 98,798 shares common stock
- no par value 98,798 3,276 459 3,735
Allocation of benefits - ESOP 27,940 238 950 1,188
Repurchase and cancellation of
preferred stock (524) (52) (52)
Discount on preferred stock repurchase 21 21
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1998 14,034,562 292,006 42,985 4,299 2,046 (2,182) (10,210) 163,847 449,806
- ------------------------------------------------------------------------------------------------------------------------------------
Net income for 1999 52,224 52,224
Cash dividends on common stock
- $2.88 per share (40,470) (40,470)
Cash dividends on preferred stock (66) (66)
Allocation of benefits - ESOP 27,940 207 949 1,156
Repurchase and cancellation of
preferred stock (42,985) (4,299) 12 (12) (4,299)
Premium on preferred stock repurchase (53) (53)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1999 14,062,502 $292,006 $0 $0 $2,253 ($2,170) ($9,261) $175,470 $458,298
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) There were 30,000,000 shares authorized in 1999, 1998 and 1997
(b) There were 1,119,612 shares authorized in 1999, 1998 and 1997
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 43 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The United Illuminating Company (the Company) is an operating electric
public utility company, engaged principally in the purchase, transmission,
distribution and sale of electricity for residential, commercial and industrial
purposes in a service area of about 335 square miles in the southwestern part of
the State of Connecticut. The service area, largely urban and suburban in
character, includes the principal cities of Bridgeport (population approximately
137,000) and New Haven (population approximately 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals.
In addition, the Company has created, and owns, unregulated subsidiaries.
The Company 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 the Company's regulated electric utility business and provide
long-term rewards to the Company's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
(A) STATEMENT OF ACCOUNTING POLICIES
ACCOUNTING RECORDS
The accounting records are maintained in accordance with the uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC) and the Connecticut Department of Public Utility Control (DPUC).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to use estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, United Resources, Inc. Intercompany accounts
and transactions have been eliminated in consolidation.
REGULATORY ACCOUNTING
Generally accepted accounting principles for regulated entities in the
United States allow the Company to give accounting recognition to the actions of
regulatory authorities in accordance with the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." In accordance with SFAS No. 71, the Company has
deferred recognition of costs (a regulatory asset) or has recognized obligations
(a regulatory liability) if it is probable that such costs will be recovered or
obligations relieved in the
- 44 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
future through the ratemaking process. In addition to the Regulatory Assets and
Liabilities separately identified on the Consolidated Balance Sheet, there are
other regulatory assets and liabilities such as conservation and load management
costs and certain deferred tax liabilities. The Company also has obligations
under long-term power contracts, the recovery of which is subject to regulation.
If the Company, or a portion of its assets or operations, were to cease meeting
the criteria for application of these accounting rules, 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 the portion of the business that continues to meet the criteria
for application of SFAS No. 71.
The Restructuring Act enacted in Connecticut in 1998 provides for the
Company to recover previously deferred costs through ongoing assessments to be
included in future regulated service rates. See Note (C), "Rate-Related
Regulatory Proceedings" for a discussion of the nature, amount and timing of
recovery of the Company's stranded costs associated with the generation portion
of its assets and operations, as well as a discussion of the regulatory
decisions that provide for such recovery. Based on these regulatory decisions,
the sale of the Company's fossil-generation assets in the second quarter of
1999, the planned divestiture of its nuclear generation ownership interests by
the end of 2003, and, in anticipation of the Restructuring Act becoming
effective on January 1, 2000, on December 31, 1999 the Company discontinued
applying SFAS No. 71 to the generation portion of its assets and operations.
However, based on the recovery mechanism that allows recovery of all of its
stranded costs through its standard offer rates, the Company was not required to
take any write-offs in connection with this event. The Company expects to
continue to meet the criteria for application of SFAS No. 71 for the remaining
portion of its assets and operations for the foreseeable future. If a change in
accounting were to occur to the non-generation portion of the Company's
operations, 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.
UTILITY PLANT
The cost of additions to utility plant and the cost of renewals and
betterments are capitalized. Cost consists of labor, materials, services and
certain indirect construction costs, including an allowance for funds used
during construction (AFUDC). The cost of current repairs and minor replacements
is charged to appropriate operating expense accounts. The original cost of
utility plant retired or otherwise disposed of and the cost of removal, less
salvage, are charged to the accumulated provision for depreciation.
The Company's utility plant in service as of December 31, 1999 and 1998 was
comprised as follows:
1999 1998
---- ----
(000's)
Production (1) $271,012 $1,133,984
Transmission (1) 148,419 161,643
Distribution 415,892 408,845
General (1) 46,578 56,264
Future use plant 30,167 30,505
Other (1) 94,997 95,689
------- -------
$1,007,065 $1,886,930
========== ==========
(1) As of December 31, 1999, the Company had reclassified $496.9 million of
production plant, $7.4 million of transmission plant, $7.5 million of
general plant and $0.6 million of other plant associated with its nuclear
entitlements from utility plant in service to a regulatory asset.
- 45 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
See Note (C), "Rate-related Regulatory Proceedings" for a discussion of the
sale by the Company of its two operating fossil-fueled generating stations and
the regulatory decisions allowing for recovery of stranded costs, including the
above-market investment in nuclear generating units.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
In accordance with the uniform systems of accounts, the Company capitalizes
AFUDC, which represents the approximate cost of debt and equity capital devoted
to plant under construction. The portion of the allowance applicable to borrowed
funds is presented in the Consolidated Statement of Income as a reduction of
interest charges, while the portion of the allowance applicable to equity funds
is presented as other income. Although the allowance does not represent current
cash income, it has historically been recoverable under the ratemaking process
over the service lives of the related properties. The Company compounds the
allowance applicable to major construction projects semi-annually. Weighted
average AFUDC rates in effect for 1999, 1998 and 1997 were 7.75%, 7.0% and 7.5%,
respectively.
DEPRECIATION
Provisions for depreciation on utility plant for book purposes are computed
on a straight-line basis, using estimated service lives determined by
independent engineers. One-half year's depreciation is taken in the year of
addition and disposition of utility plant, except in the case of major operating
units on which depreciation commences in the month they are placed in service
and ceases in the month they are removed from service. The aggregate annual
provisions for depreciation for the years 1999, 1998 and 1997 were equivalent to
approximately 3.10%, 3.26% and 3.15%, respectively, of the original cost of
depreciable property.
INCOME TAXES
In accordance with Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes," the Company has provided deferred taxes for
all temporary book-tax differences using the liability method. The liability
method requires that deferred tax balances be adjusted to reflect enacted future
tax rates that are anticipated to be in effect when the temporary differences
reverse. In accordance with generally accepted accounting principles for
regulated industries, the Company has established a regulatory asset for the net
revenue requirements to be recovered from customers for the related future tax
expense associated with certain of these temporary differences.
For ratemaking purposes, the Company normalizes all investment tax credits
(ITC) related to recoverable plant investments except for the ITC related to
Seabrook Unit 1, which was taken into income in accordance with provisions of a
1990 DPUC retail rate decision.
ACCRUED UTILITY REVENUES
The estimated amount of utility revenues (less related expenses and
applicable taxes) for service rendered but not billed is accrued at the end of
each accounting period.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments.
The Company is required to maintain an operating deposit with the project
disbursing agent related to its 17.5% ownership interest in Seabrook Unit 1.
This operating deposit, which is the equivalent to one and one half months of
- 46 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the funding requirement for operating expenses, is restricted for use and
amounted to $2.3 million and $3.8 million at December 31, 1999 and 1998,
respectively.
The Company's wholly-owned subsidiary, American Payment Systems, Inc.,
maintains separate bank accounts for holding cash received from clients'
customers before the amounts are transferred to clients. The amount of this
restricted cash at December 31, 1999 and 1998 was $26.9 million and $23.1
million, respectively.
At December 31, 1999, the Company included in the cash balance $25 million
of proceeds from the issuance by the Business Finance Authority of the State of
New Hampshire of $25 million principal amount of tax-exempt Pollution Control
Refunding Revenue Bonds that were held by a trustee.
INVESTMENTS
The Company's investment in the Connecticut Yankee Atomic Power Company, a
nuclear generating company in which the Company has a 9 1/2% stock interest, is
accounted for on an equity basis. This investment amounted to $10.0 million and
$9.9 million at December 31, 1999 and 1998, respectively, and is included on the
Consolidated Balance Sheet as a regulatory asset. See Note (L), "Commitments and
Contingencies - Other Commitments and Contingencies - Connecticut Yankee."
RESEARCH AND DEVELOPMENT COSTS
Research and development costs, including environmental studies, are
charged to expense as incurred.
PENSION AND OTHER POSTEMPLOYMENT BENEFITS
The Company accounts for normal pension plan costs in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No. 87,
"Employers' Accounting for Pensions," and for supplemental retirement plan costs
and supplemental early retirement plan costs in accordance with the provisions
of SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and for Termination Benefits."
The Company accounts for other postemployment benefits, consisting
principally of health and life insurance, under the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions," which
requires, among other things, that the liability for such benefits be accrued
over the employment period that encompasses eligibility to receive such
benefits. The annual incremental cost of this accrual has been allowed in retail
rates in accordance with a 1992 rate decision of the DPUC.
URANIUM ENRICHMENT OBLIGATION
Under the Energy Policy Act of 1992 (Energy Act), the Company will be
assessed for its proportionate share of the costs of the decontamination and
decommissioning of uranium enrichment facilities operated by the Department of
Energy. The Energy Act imposes an overall cap of $2.25 billion on the obligation
assessed to the nuclear utility industry and limits the annual assessment to
$150 million each year over a 15-year period. The Company has recovered these
assessments in rates as a component of fuel expense. Accordingly, the Company
has recognized the unrecovered costs as a regulatory asset on its Consolidated
Balance Sheet. At December 31, 1999, the Company's remaining share of the
obligation, based on its ownership and leasehold interests in Seabrook Unit 1
and Millstone Unit 3, was approximately $1.0 million.
- 47 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $4.0 million, $2.6 million and $2.6 million
during 1999, 1998 and 1997 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1999, the Company's shares of the
trust fund balances, which included accumulated earnings on the funds, were
$20.5 million and $7.8 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.
IMPAIRMENT OF LONG-LIVED ASSETS
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets to Be Disposed Of" requires the recognition
of impairment losses on long-lived assets when the book value of an asset
exceeds the sum of the expected future undiscounted cash flows that result from
the use of the asset and its eventual disposition. This standard also requires
that rate-regulated companies recognize an impairment loss when a regulator
excludes all or part of a cost from rates, even if the regulator allows the
company to earn a return on the remaining allowable costs. Under this standard,
the probability of recovery and the recognition of regulatory assets under the
criteria of SFAS No. 71 must be assessed on an ongoing basis. The Company does
not have any assets that are impaired under this standard.
EARNINGS PER SHARE
The following table presents a reconciliation of the numerators and
denominators of the basic and diluted earnings per share calculations for the
years 1999, 1998 and 1997:
<TABLE>
<CAPTION>
INCOME APPLICABLE TO AVERAGE NUMBER OF
COMMON STOCK SHARES OUTSTANDING EARNINGS
(NUMERATOR) (DENOMINATOR) PER SHARE
----------- ------------- ---------
(000's, except per share amounts)
1999
- ----
<S> <C> <C> <C>
Basic earnings per share $52,105 14,052 $3.71
Effect of dilutive stock options - 3 (.00)
------- ------ -----
Diluted earnings per share $52,105 14,055 $3.71
======= ====== =====
1998
- ----
Basic earnings per share $44,892 14,018 $3.20
Effect of dilutive stock options - 5 (.00)
------- ------ ------
Diluted earnings per share $44,892 14,023 $3.20
======= ====== =====
1997
- ----
Basic earnings per share $43,300 13,976 $3.10
Effect of dilutive stock options - 16 (.01)
------- ------ -----
Diluted earnings per share $43,300 13,992 $3.09
======= ====== =====
</TABLE>
- 48 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation." This statement establishes financial accounting and
reporting standards for stock-based employee compensation plans, such as stock
purchase plans, stock options, restricted stock, and stock appreciation rights.
The statement defines the methods of determining the fair value of stock-based
compensation and requires the recognition of compensation expense for book
purposes. However, the statement allows entities to continue to measure
compensation expense in accordance with the prior authoritative literature, APB
No. 25, "Accounting for Stock Issued to Employees," but requires that pro forma
net income and earnings per share be disclosed for each year for which an income
statement is presented as if SFAS No. 123 had been applied. The accounting
requirements of this statement are effective for transactions entered into after
1995. However, pro forma disclosures must include the effects of all awards
granted after January 1, 1995. As of December 31, 1999, there were no options to
which this statement would apply. Options granted in 1999 are not yet
exercisable.
NEW ACCOUNTING STANDARDS
On January 1, 1998, the Company adopted Statement of Financial Standards
(SFAS) No. 130, "Reporting Comprehensive Income," which provides authoritative
guidance on the reporting and display of comprehensive income and its
components. For the years ended December 31, 1999, 1998 and 1997 comprehensive
income was equal to net income as reported.
On January 1, 1998, the Company adopted SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information," which provides guidance
about segment reporting. As described in Note (P), "Segment Information," the
Company has only one reportable segment, that of regulated generation,
distribution and sale of electricity.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement,
which is effective for fiscal quarters of fiscal years beginning after June 15,
2000, establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires entities to recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The accounting for the changes in the fair
value of a derivative (gains and losses) would depend on the intended use and
designation of the derivative. The Company cannot reasonably assess what effect
applying SFAS No. 133 will have on its financial condition and results of
operations in the future.
(B) CAPITALIZATION
COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at December 31, 1999 and 1998, of which 272,420 shares and 300,360
shares were unallocated shares held by the Company's Employee Stock Ownership
Plan (ESOP) and not recognized as outstanding for accounting purposes as of
December 31, 1999 and 1998, respectively.
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
- 49 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 December 31, 1999.
No options were exercised during 1999.
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ ----- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Balance - Beginning of Year 16,300 $38.37 115,098 $33.90 252,331 $32.20
Granted - - - - - -
Forfeited - - - - (2,400) $30.75
Exercised - - (98,798) $33.16 (134,833) $30.79
Balance - End of Year 16,300 $38.37 16,300 $38.37 115,098 $33.90
------ ------- -------
Exercisable at End of Year 16,300 $38.37 16,300 $38.37 96,698 $34.51
====== ======= =======
</TABLE>
On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the awarding of options to purchase up to 650,000 shares of the Company's
common stock over periods of from one to ten years following the dates when the
options are granted. The exercise price of each option cannot be less than the
market value of the stock on the date of the grant. On June 28, 1999, the
Company's shareowners approved the plan. Options to purchase 137,000 shares of
stock at an exercise price of $43 7/32 per share have been granted by the Board
of Directors and remained outstanding at December 31, 1999. No options to
purchase shares of the Company's common stock can be exercised without the
approval of the DPUC; and, as December 31, 1999, the Company had not requested
approval by the DPUC.
On February 23, 1998, the Board of Directors granted 80,000 "phantom" stock
options to Nathaniel D. Woodson upon his appointment as President of the
Company. On each of the first five anniversaries of the grant date, 16,000
phantom stock options become exercisable and can be exercised at any time within
Mr. Woodson's period of employment with the Company by means of the Company
paying him the difference between the prevailing market price for each share and
the phantom stock option price of $45.16 per share. At ten years after the grant
date any unexercised phantom stock options will expire. At December 31, 1999,
16,000 phantom stock options were exercisable. Due to the immaterial effect on
results of operations, no expense was recognized with regard to the phantom
stock options.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company Employee Stock Ownership Plan (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's contributions and dividends paid on
the unallocated shares of the stock held by the ESOP. As of December 31, 1999,
272,420 shares, with a fair market value of $14.0 million, had been purchased by
the ESOP and had not been committed to be released or allocated to ESOP
participants.
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
$117.3 million were free from such limitations at December 31, 1999.
- 50 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
PREFERRED AND PREFERENCE STOCK
The par value of each of these issues was credited to the appropriate stock
account and expenses related to these issues were charged to capital stock
expense.
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.
Shares of preferred stock have preferential dividend and liquidation rights
over shares of common stock. Preferred shareholders are not entitled to general
voting rights. However, if any preferred dividends are in arrears for six or
more quarters, or if certain other events of default occur, preferred
shareholders are entitled to elect a majority of the Board of Directors until
all preferred dividend arrearages are paid and any event of default is remedied.
There were no shares of preferred stock outstanding at December 31, 1999.
Preference stock is a form of stock that is junior to preferred stock but
senior to common stock. It is not subject to the earnings coverage requirements
or minimum capital and surplus requirements governing the issuance of preferred
stock. There were no shares of preference stock outstanding at December 31,
1999.
COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITIES OF SUBSIDIARY HOLDING SOLELY
PARENT DEBENTURES
United Capital Funding Partnership L.P. (United Capital) is a special
purpose limited partnership in which the Company owns all of the general partner
interests. United Capital has issued $50 million of 9 5/8% Preferred Capital
Securities, Series A, (Preferred Securities), the dividends on which are accrued
and paid monthly.
The sole holding of United Capital is the $50 million of 9 5/8% Junior
Subordinated Deferrable Interest Debentures, Series A, due April 30, 2025, (the
Series A Debentures) issued by United Illuminating in 1995.
Holders of the Preferred Securities will be entitled to receive, to the
extent of funds held by United Capital, cumulative preferential dividends, at an
annual rate 9 5/8% of the liquidation preference of $25 per security, payable
monthly in arrears on the last day of each calendar month. The payment of
dividends and payments on redemption with respect to the Preferred Securities to
the extent of funds held by United Capital, will be guaranteed under a Payment
and Guarantee Agreement (the Guarantee) of United Illuminating. The Guarantee
does not cover payment of amounts in respect of the Preferred Securities to the
extent that United Capital does not have available funds for the payment thereof
and cash on hand sufficient to make such payment. Such funds and cash on hand
will be limited to payments by United Illuminating on the Series A Debentures.
If United Illuminating fails to make interest payments on the Series A
Debentures, United Capital will have insufficient funds to pay dividends on the
Preferred Securities and the Guarantee will not cover payment of dividends.
The Preferred Securities are subject to mandatory redemption when the
Series A Debentures mature or are redeemed.
- 51 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
LONG-TERM DEBT
<TABLE>
<CAPTION>
DECEMBER 31,
1999 1998
---- ----
(000's)
<S> <C> <C>
Other Long-Term Debt
Pollution Control Revenue Bonds:
4.35%, 1996 Series, due June 26, 2026 (1) $ 7,500 $ 7,500
8%, 1989 Series A, due December 1, 2014 25,000 25,000
5 7/8%, 1993 Series, due October 1, 2033 64,460 64,460
Pollution Control Refunding Revenue Bonds:
4.35%, 1997 Series, due July 30, 2027 (2) 27,500 27,500
4.55%, 1997 Series, due July 30, 2027 (1) 71,000 71,000
5.40%, 1999 Series, due December 1, 2029 (3) 25,000 -
Notes:
6.20%, 1993 Series H, due January 15, 1999 - 66,202
6.25%, 1998 Series I, due December 15, 2002 100,000 100,000
6.00%, 1998 Series J, due December 15, 2003 100,000 100,000
Term Loans:
6.95%, due August 29, 2000 (4) - 50,000
6.4375%, due September 6, 2000 (4) - 20,000
6.675%, due October 25, 2001 (4) - 25,000
7.005%, due October 25, 2001 (4) - 50,000
Obligation under the Seabrook Unit 1 sale/leaseback agreement 210,424 217,230
------- -------
630,884 823,892
Unamortized debt discount less premium (243) (320)
------- -------
630,641 823,572
Less:
Current portion included in Current Liabilities 25,000 66,202
Investment-Seabrook Lease Obligation Bonds 87,413 92,860
------- -------
Total Long-Term Debt $518,228 $664,510
======= =======
</TABLE>
(1) The interest rate for these Bonds was fixed on February 1, 1999 for the
five-year period ending January 30, 2004. Prior to February 1, 1999, the
interest rate was variable.
(2) The interest rate for these Bonds was fixed on February 1, 1999 for the
three-year period ending January 30, 2002. Prior to February 1, 1999, the
interest rate was variable.
(3) The interest rate for these Bonds was fixed on December 16, 1999 for the
three-year period ending December 1, 2002.
(4) The fixed interest rate for these variable interest rate term loans
reflected the effect of the associated interest rate swaps.
- 52 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On January 16, 1999, the Company repaid $66.2 million principal amount of
6.20% Notes at maturity.
On February 1, 1999, the Company converted $7.5 million principal amount of
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 is payable semi-annually on
August 1 and February 1. 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 is
payable semi-annually on August 1 and February 1.
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.
On December 16, 1999, the Company borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $25 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2029, and
their interest rate is fixed at 5.4% for the three-year period ending December
1, 2002. At December 31, 1999, these proceeds were held by a trustee and were
recognized as cash and long-term debt on the Consolidated Balance Sheet. The
Company has used the proceeds of this $25 million borrowing to cause the
redemption and repayment of $25 million of 8.0%, 1989 Series A, Pollution
Control Revenue Bonds, an outstanding series of tax-exempt bonds on which the
Company also had a payment obligation to a trustee for the bondholders. Expenses
associated with this transaction, including redemption premiums totaling
$750,000 and other expenses of approximately $417,000, were paid by the Company.
The expenses to issue long-term debt are deferred and amortized over the
life of the respective debt issue.
Maturities and mandatory redemptions/repayments are set forth below:
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(000's)
Maturities $ - $ - $100,000 $100,000 $ -
(C) RATE-RELATED REGULATORY PROCEEDINGS
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 retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, 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 Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized
- 53 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
one-third for customer price reductions, one-third to increase amortization of
assets, and one-third retained as earnings. As a result of the Rate Plan,
customer prices were required to be reduced, on average, by 3% in 1997 compared
to 1996. Also as a result of the Rate Plan, customer prices were required to be
reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996.
Retail revenues decreased by approximately 7.0% through 1999 compared to 1996
due to customer price reductions. The Rate Plan was reopened in 1998, in
accordance with its terms, to determine the assets to be subjected to
accelerated recovery in 1999. The DPUC decided on February 10, 1999 to subject
$12.1 million of the Company's regulatory tax assets to accelerated recovery in
1999.
The Rate Plan includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999, the DPUC issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates, as directed by the Restructuring Act described in detail below.
These standard offer customer rates are in effect for the period 2000-2001 and
supercede the rate reductions for this period that were included in the Rate
Plan. The decision also reduced the required amount of accelerated amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect through 2001. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.
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. As a result of the Act, the business of
generating and selling electricity directly to consumers is opened to
competition. These business activities are separated from the business of
delivering electricity to consumers, also known as the transmission and
distribution business. The business of delivering electricity remains with the
incumbent franchised utility companies (including the Company), which continues
to be regulated by the DPUC as Distribution Companies. Since mid-1999,
Distribution Companies have been required to separate on consumers' bills the
electricity generation services component from the charge for delivering the
electricity and all other charges.
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.
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 interests in its nuclear-fueled power plants prior to 2004.
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 April 16, 1999, the
transaction closed and the Company received
- 54 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
approximately $277.9 million from this sale. The Company realized a before-tax
book gain of $86.5 million from the sale of these plant investments. However,
under the Restructuring Act, this gain was offset by a writedown of the stranded
costs eligible for collection by the Company under the Restructuring Act's
competitive transition assessment, such that there was 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, and in other regulatory dockets, the Company stated that
it plans to divest its nuclear generation ownership interests (17.5% of Seabrook
Unit 1 in New Hampshire and 3.685% of Millstone Station Unit 3 in Connecticut)
by the end of 2003, in accordance with the Restructuring Act. The DPUC is
currently considering the Company's plan for divesting its ownership interest in
Millstone Unit 3 through an auction process to be conducted by a consultant to
be selected by the DPUC. The divestiture process for Seabrook Unit 1 has not yet
been determined. In anticipation of ultimate divestiture, the Company has
satisfied the Restructuring Act's requirement that nuclear generating assets be
separated from its transmission and distribution assets. This was 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 decision dated May 19, 1999, the DPUC 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 and, in a decision dated May 19, 1999, the DPUC approved the
proposed corporate restructuring. The Company has filed applications with the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission
seeking approval of the proposed corporate restructuring, and a special meeting
of the Company's shareowners will be held on March 17, 2000 to vote on approval
of the restructuring.
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the market value of the
Company's generating assets in an appeal taken to the Superior Court from the
DPUC's decision.
Under the Restructuring Act, retail customers representing a total of up
to 35% of the Company's retail customer load became able to choose their power
supply providers on and after January 1, 2000, and all of the Company's
customers will be able to choose their power supply providers as of July 1,
2000. On and after January 1, 2000 and through December 31, 2003, the Company is
required to offer fully-bundled "standard offer" electric service, under
regulated rates, to all customers who do not choose an alternate power supply
provider. The
- 55 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
standard offer rates must include the fully-bundled price of generation,
transmission and distribution services, the competitive transition assessment,
the systems benefits charge and the conservation and renewable energy charges.
The fully-bundled standard offer rates must also be at least 10% below the
average fully-bundled prices in 1996.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be under the above requirements of the
Restructuring Act. In April, May and June of 1999, the Company filed descriptive
material, data and supporting testimony with the DPUC setting forth the
Company's overall approach for determining the components of its standard offer
rates, and for continuation of the five-year Rate Plan ordered by the DPUC in
its 1996 financial and operational review of the Company (see above) through the
four-year standard offer period. On July 27, 1999, the Company and Enron Capital
& Trade Resources Corp. (ECTR), an affiliate of Enron Corp., Houston, Texas
(Enron) filed with the DPUC a joint stipulation and settlement proposal to
resolve simultaneously all of the issues in the Company's standard offer rate
proceeding. The proposal included an arrangement between the Company and ECTR
whereby ECTR will supply all of the generation services needed by the Company to
meet its standard offer obligations for the four-year standard offer period, and
an assumption by ECTR of all of the Company's long-term purchased power
agreement (PPA) obligations. The stipulation and settlement proposal also
provided for the Company's standard offer rates at a fully-bundled level that
complies with the 10% reduction required by the Restructuring Act, including the
generation services component of these rates, the Company's stranded costs for
purposes of future recovery, the competitive transition assessment, systems
benefits charge, delivery (transmission and distribution) charges, and
conservation, load management and renewable energy charges. The Company also
requested that a purchased power adjustment clause authorized by the
Restructuring Act be put in place to adjust standard offer rates for limited
purposes, and that the Company's five-year Rate Plan, as modified and
supplemented by the stipulation and settlement proposal, be continued during the
four-year standard offer period. In its decision, dated October 1, 1999, on the
Company's standard offer rates, the DPUC approved elements of the stipulation
and settlement proposal, including the arrangements with ECTR, subject to
specified changes, including changes in the level of the generation services
component of customers' rates. On October 15, 1999, the Company filed its
standard offer generation services component of rates in compliance with the
DPUC's decision, and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal. These filings were approved by the DPUC on
December 9, 1999 and, on December 28, 1999, the Company and Enron Power
Marketing, Inc., another affiliate of Enron, entered into a Wholesale Power
Supply Agreement, a PPA Entitlements Transfer Agreement and related agreements
documenting the approved four-year standard offer power supply arrangement and
the assumption of all of the Company's PPAs, effective January 1, 2000. From
January 1, 2000 through June 30, 2000, EPMI will sell to the Company energy
beyond that supplied by Wisvest as described above. The agreements also provide
for the sale to EPMI of the Company's entitlements under all of its wholesale
purchased power agreements (PPAs). However, unless or until a PPA is terminated
or formally assigned to EPMI, the Company remains legally liable to pay the
applicable power supplier all amounts due under the PPA. The agreements with
EPMI also include a financially settled contract for differences related to
certain call rights of EPMI and put rights of the Company with respect to the
Company's entitlements in Seabrook Unit 1 and in Millstone Unit 3, and the
Company's provision to EPMI of certain ancillary products and services
associated with those nuclear entitlements, which provisions terminate at the
earlier of December 31, 2003 or the date that the Company sells its nuclear
interests. The agreements do not restrict the Company's right to sell to third
parties the Company's ownership interests in those nuclear generation units or
the generated energy actually attributable to its ownership interests.
Based on the decisions in the regulatory proceedings described above, the
sale of the Company's fossil-generation assets in the second quarter of 1999,
the planned divestiture of its nuclear generation ownership interests by the end
of 2003, and in anticipation of the Restructuring Act becoming effective on
January 1, 2000, the Company ceased applying SFAS No. 71 to the generation
portion of its assets and operations as of December 31, 1999. Based on the
favorable DPUC decisions that allow full recovery, through the Company's rates,
of all historically incurred stranded costs, the Company did not record any
write-offs in connection with this event.
- 56 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(D) ACCOUNTING FOR PHASE-IN PLAN
The Company phased into rate base its allowable investment in Seabrook Unit
1, amounting to $640 million, during the period January 1, 1990 to January 1,
1994. In conjunction with this phase-in plan, the Company was allowed to record
a deferred return on the portion of allowable investment excluded from rate base
during the phase-in period. The Company amortized the net-of-tax accumulated
deferred return of $62.9 million over the five-year period that ended on
December 31, 1999.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 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 the Eurodollar interbank market in
London. 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 December 31, 1999, the Company had $17 million in
short-term borrowings outstanding under this facility.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1999, this coverage ratio was 4.7:1.0.
Information with respect to short-term borrowings under the Company's
revolving credit agreements is as follows:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(000's)
<S> <C> <C> <C>
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $80,000 $130,000 $50,000
Average aggregate short-term borrowings outstanding during the year* $45,300 $115,753 $41,441
Weighted average interest rate* 5.5% 6.1% 5.9%
Principal amounts outstanding at year-end $17,000 $80,000 $30,000
Annualized interest rate on principal amounts outstanding at year-end 7.0% 5.7% 6.2%
</TABLE>
*Average short-term borrowings represent the sum of daily borrowings
outstanding, weighted for the number of days outstanding and divided by the
number of days in the period. The weighted average interest rate is determined
by dividing interest expense by the amount of average borrowings. Commitment
fees of approximately $291,000 and $381,000 paid during 1999 and 1998,
respectively, are excluded from the calculation of the weighted average interest
rate.
- 57 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
<TABLE>
<CAPTION>
1999 1998 1997
--- ---- ----
<S> <C> <C> <C>
Income tax expense consists of: (In thousands)
Income tax provisions:
Current
Federal $91,247 $36,774 $23,568
State 23,891 10,685 7,545
------------ ----------- -----------
Total current 115,138 47,459 31,113
------------ ----------- -----------
Deferred
Federal (39,767) 2,964 6,123
State (13,004) 110 681
------------ ----------- -----------
Total deferred (52,771) 3,074 6,804
------------ ----------- -----------
Investment tax credits (467) (762) (762)
------------ ----------- -----------
Total income tax expense $61,900 $49,771 $37,155
============ =========== ===========
Income tax components charged as follows:
Operating expenses $66,564 $53,619 $40,833
Other income and deductions - net (4,664) (3,848) (3,678)
------------ ----------- -----------
Total income tax expense $61,900 $49,771 $37,155
============ =========== ===========
The following table details the components
of the deferred income taxes:
Gain on sale of utility property ($70,573) ($697) ($272)
Tax depreciation on unrecoverable plant investment 5,902 6,291 8,089
Fossil plants decommissioning reserve (116) (329) (7,286)(1)
Conservation & load management (2,181) (8,026) (5,768)
Accelerated depreciation 4,996 5,449 5,681
Pension benefits 4,192 3,463 4,911
Seabrook sale/leaseback transaction (69) 304 2,664
Cancelled nuclear project (467) (467) (467)
Unit overhaul and replacement power costs 1,523 (1,157) 212
Displaced worker protection costs 2,329 - -
Deferred fossil fuel costs - - (686)
Bond redemption costs (1,014) (1,039) 172
Property tax settlement 834 (834) -
Other 1,873 116 (446)
------------ ----------- -----------
Deferred income taxes - net ($52,771) $3,074 $6,804
============ =========== ===========
</TABLE>
(1) $6,719 of this amount is for deferred income tax benefits from prior years.
- 58 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
PRE-TAX TAX PRE-TAX TAX PRE-TAX TAX
------- ------- ------- ------- ------- -------
(000's) (000's) (000's)
<S> <C> <C> <C> <C> <C> <C>
Computed tax at federal statutory rate $39,943 $33,195 $28,214
Increases (reductions) resulting from:
Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 12,586 4,405
ITC taken into income (468) (468) (762) (762) (762) (762)
Allowance for equity funds used during
construction (575) (201) (13) (5) (336) (118)
Fossil plant decommissioning reserve (262) (92) (723) (253) (15,591) (5,457)
Amortization of regulatory asset 22,635 7,922 - - - -
Book depreciation in excess of
non-normalized tax depreciation 16,155 5,654 22,789 7,976 23,926 8,374
State income taxes, net of federal
income tax benefits 10,887 7,076 10,795 7,017 8,226 5,345
Other items - net (6,683) (2,339) (5,149) (1,802) (8,134) (2,846)
------- ------- -------
Total income tax expense $61,900 $49,771 $37,155
======= ======= =======
Book income before income taxes $114,124 $94,843 $80,612
======== ======= =======
Effective income tax rates 54.2% 52.5% 46.1%
===== ===== =====
</TABLE>
At December 31, 1999 the Company had deferred tax liabilities for taxable
temporary differences of $352 million and deferred tax assets for deductible
temporary differences of $88 million, resulting in a net deferred tax liability
of $264 million. Significant components of deferred tax liabilities and assets
were as follows: tax liabilities on book/tax plant basis differences and on the
cumulative amount of income taxes on temporary differences previously flowed
through to ratepayers, $215 million; tax liabilities on normalization of
book/tax depreciation timing differences, $125 million and tax assets on the
disallowance of plant costs, $35 million.
- 59 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
<TABLE>
<CAPTION>
1999 1998 1997
----- ----- ----
(000'S)
<S> <C> <C> <C>
OPERATING REVENUES
- ------------------
Retail $639,596 $631,607 $622,333
Wholesale - capacity 2,235 11,524 9,747
- energy 22,099 33,424 73,124
Other 16,045 9,636 3,825
----------- ----------- -----------
Total Operating Revenues $679,975 $686,191 $709,029
=========== =========== ===========
SALES BY CLASS(MWH'S) - UNAUDITED
- ---------------------------------
Retail
Residential 2,053,927 1,924,724 1,899,284
Commercial 2,388,240 2,324,507 2,248,974
Industrial 1,161,856 1,154,935 1,168,470
Other 48,027 48,166 48,619
----------- ----------- -----------
5,652,050 5,452,332 5,365,347
Wholesale 1,009,866 1,551,109 2,700,393
----------- ----------- -----------
Total Sales 6,661,916 7,003,441 8,065,740
=========== =========== ===========
OTHER OPERATION EXPENSES
- ------------------------
Production $20,850 $28,427 $26,203
Transmission & Distribution 42,336 35,681 36,926
Customer Service 26,923 26,582 28,957
Administrative & General 57,600 55,368 66,514
----------- ----------- -----------
Total $147,709 $146,058 $158,600
=========== =========== ===========
DEPRECIATION
- ------------
Plant in service $53,347 $67,143 $65,585
Accelerated conservation and load management 0 13,086 6,636
Nuclear decommissioning 4,004 2,580 2,397
----------- ----------- -----------
$57,351 $82,809 $74,618
=========== =========== ===========
OTHER TAXES
- -----------
Charged to:
Operating:
State gross earnings $24,518 $24,039 $23,571
Local real estate and personal property (1) 17,745 35,088 22,974
Payroll taxes 4,877 5,547 5,948
----------- ----------- -----------
47,140 64,674 52,493
Nonoperating and other accounts 598 510 459
----------- ----------- -----------
Total Other Taxes $47,738 $65,184 $52,952
=========== =========== ===========
OTHER INCOME AND (DEDUCTIONS) - NET
- -----------------------------------
Interest income $1,801 $3,181 $2,317
Equity earnings from Connecticut Yankee 36 854 1,343
Loss from subsidiary companies (2) (590) (1,748) (3,639)
Miscellaneous other income and (deductions) - net (2,085) (1,190) 1,340
----------- ----------- -----------
Total Other Income and (Deductions) - net ($838) $1,097 $1,361
=========== =========== ===========
OTHER INTEREST CHARGES
- ----------------------
Notes Payable $2,662 $5,050 $2,462
Other 2,265 1,457 818
----------- ----------- -----------
Total Other Interest Charges $4,927 $6,507 $3,280
=========== =========== ===========
</TABLE>
(1) 1998 includes $14,025 charge for property tax settlement.
(2) Includes before-tax non-recurring charges in 1997 of $2,825 resulting from
losses at American Payment Systems, Inc.
- 60 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(H) PENSION AND OTHER BENEFITS
The Company's qualified pension plan, which is based on the highest three
years of pay, covers substantially all of its employees, and its entire cost is
borne by the Company. The Company also has a non-qualified supplemental plan for
certain executives and a non-qualified retiree only plan for certain early
retirement benefits. The net pension costs for these plans for 1999, 1998 and
1997 were ($7,960,000), ($5,138,000), and ($4,626,000), respectively.
The Company's funding policy for the qualified plan is to make annual
contributions that satisfy the minimum funding requirements of ERISA but that do
not exceed the maximum deductible limits of the Internal Revenue Code. These
amounts are determined each year as a result of an actuarial valuation of the
plan. In 1997, the Company contributed $2.7 million for 1996 funding
requirements and $2.5 million for 1997 funding requirements. In 1998, the
Company contributed $2.6 million for 1998 funding requirements. The Company did
not make a contribution in 1999. The Company has established a supplemental
retirement benefit trust and through this trust purchased life insurance
policies on the officers of the Company to fund the future liability under the
supplemental plan. The cash surrender value of these policies is shown as an
investment on the Company's Consolidated Balance Sheet.
In addition to providing pension benefits, the Company also provides other
postretirement benefits (OPEB), consisting principally of health care and life
insurance benefits, for retired employees and their dependents. Employees whose
sum of age and years of service at time of retirement is equal to or greater
than 85 (or who are 62 with at least 20 years of service) are eligible for
benefits partially subsidized by the Company. The amount of benefits subsidized
by the Company is determined by age and years of service at retirement.
For funding purposes, the Company established a Voluntary Employees'
Benefit Association Trust (VEBA) to fund OPEB for the Company's union employees.
Approximately 47% of the Company's employees are represented by Local 470-1,
Utility Workers Union of America, AFL-CIO, for collective bargaining purposes.
The Company established a 401(h) account in connection with the qualified
pension plan to fund OPEB for the Company's non-union employees who retire on or
after January 1, 1994. The funding policy assumes contributions to these trust
funds to be the total OPEB expense calculated under SFAS No. 106, adjusted to
reflect a share of amounts expensed as a result of voluntary early retirement
programs minus pay-as-you-go benefit payments for pre-January 1, 1994 non-union
retirees, allocated in a manner that minimizes current income tax liability,
without exceeding maximum tax deductible limits. In accordance with this policy,
the Company did not make contributions to the union VEBA in 1999, 1998 and 1997.
The Company did not make a contribution to the 401(h) account in 1999 and
contributed $0.9 million and $1.7 million to the 401(h) account in 1998 and
1997, respectively. Plan assets for both the union VEBA and 401(h) account
consist primarily of equity and fixed-income securities.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning fair
value of plan assets balance reconciled to the ending fair value of plan assets
balance and the respective funded status reconciled to the Consolidated Balance
Sheet.
- 61 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<TABLE>
<CAPTION>
AT DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
(000's)
CHANGE IN BENEFIT OBLIGATION
<S> <C> <C> <C> <C>
Benefit obligation at beginning of year $280,746 $259,545 $40,229 $35,112
Service Cost 5,334 4,389 549 1,078
Interest cost 17,470 17,828 2,276 2,576
Amendments 994 - 1,364 -
Actuarial (gain) loss (34,672) 14,064 (9,322) 4,002
Benefits paid (including expenses) (18,979) (15,080) (1,935) (2,539)
Acquisition/(Divestiture) (18,500) - (1,570) -
------- ------- ------ ------
Benefit obligation at end of year $232,393 $280,746 $31,591 $40,229
======= ======= ====== ======
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning
of year $268,684 $243,739 $23,203 $21,168
Actual return on plan assets 39,757 38,224 555 2,491
Employer contributions 2,525 2,914 208 910
Benefits paid (including expenses) (18,979) (16,193) (1,935) (1,366)
Acquisition/(Divestiture) (14,000) - (1,350) -
------- ------- ------ ------
Fair value of plan assets at end of year $277,987 $268,684 $20,681 $23,203
======= ======= ====== ======
Funded Status at December 31:
Projected benefits (less than) greater
than plan assets $(45,594) $12,062 $10,910 $17,026
Unrecognized prior service cost (3,731) (3,878) (291) 946
Unrecognized transition asset 5,552 7,274 (13,435) (16,368)
Unrecognized net gain (loss) from
past experience 62,799 15,639 7,674 1,241
------- ------ ------ ------
Accrued benefit obligation $ 19,026 $31,097 $ 4,858 $ 2,845
======= ====== ====== ======
</TABLE>
<TABLE>
<CAPTION>
AT DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
The following actuarial assumptions were used
in calculating the benefit obligations at
December 31:
Discount rate 7.50% 6.75% 7.50% 6.75%
Average wage increase 4.50% 4.50% 4.50% 4.50%
Health care cost trend rate N/A N/A 5.50% 5.50%
</TABLE>
- 62 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The components of net periodic benefit cost are:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
(000's)
Components of net periodic benefit cost:
<S> <C> <C> <C> <C>
Service cost $ 5,334 $ 4,389 $ 549 $ 1,078
Interest cost 17,470 17,828 2,276 2,576
Expected return on plan assets (28,677) (25,934) (2,463) (2,249)
Amortization of:
Prior service costs 537 406 11 (71)
Transition obligation (asset) (1,097) (1,095) 1,169 1,169
Actuarial (gain) loss (1,527) (1,132) (801) (361)
Settlements (curtailments) - 400 - -
------ ------ ----- ------
Net periodic benefit cost $(7,960) $(5,138) $ 741 $ 2,142
======= ======= ==== ======
</TABLE>
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
The following actuarial assumptions were used
in calculating net periodic benefit cost:
<S> <C> <C> <C> <C>
Discount rate 6.75% 7.25% 6.75% 7.25%
Average wage increase 4.50% 4.50% 4.50% 4.50%
Return on plan assets 11.00% 11.00% 11.00% 11.00%
Health care cost trend rate N/A N/A 5.50% 5.50%
</TABLE>
A one percentage point change in the assumed health care cost trend rate would
have the following effects:
1% INCREASE 1% DECREASE
----------- -----------
(000's)
Aggregate service and interest cost components $346 $(344)
Accumulated postretirement benefit obligation $3,316 $(3,608)
The Company has an Employee Savings Plan (401(k) Plan) in which
substantially all employees are eligible to participate. The 401(k) Plan enables
employees to defer receipt of up to 15% of their compensation and to invest such
funds in a number of investment alternatives. The Company also has an Employee
Stock Ownership Plan (ESOP) for substantially all its employees. The Company
makes matching contributions to the ESOP, in the form of Company common stock,
based on each employee's salary deferrals in the 401(k) Plan. The matching
contribution currently equals fifty cents for each dollar of the employee's
compensation deferred, but is not more than three and three-eighths percent of
the employee's annual salary. The Company's matching contributions to the ESOP
during 1999, 1998 and 1997 were $1.5 million, $1.7 million and $1.7 million,
respectively.
The Company pays dividends on the shares of stock in the ESOP to the
participant and the Company receives a tax deduction for the dividends paid. The
Company also makes contributions to the ESOP equal to 25% of the dividends paid
to each participant. The Company's annual contributions during 1999, 1998 and
1997 were $319,000, $270,000 and $417,000, respectively.
- 63 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(I) JOINTLY OWNED PLANT
At December 31, 1999, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT ACCUMULATED
SHARE INVESTMENT (1) DEPRECIATION
--------- ---------- ------------
(Millions)
Seabrook Unit 1 17.5 % $658 $164
Millstone Unit 3 3.685 136 66
(1) Of the plant investment amounts, $456 million for Seabrook Unit 1 and $62
million for Millstone Unit 3 are reflected on the consolidated balance
sheet as regulatory assets.
The Company's share of the operating costs of jointly owned plants is
included in the appropriate expense captions in the Consolidated Statement of
Income.
(J) UNAMORTIZED CANCELLED NUCLEAR PROJECT
From December 1984 through December 1992, the Company had been recovering
its investment in Seabrook Unit 2, a partially constructed nuclear generating
unit that was cancelled in 1984, over a regulatory approved ten-year period
without a return on its unamortized investment. In the Company's 1992 rate
decision, the DPUC adopted a proposal by the Company to write off its remaining
investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period,
corresponding with the flowback of certain Connecticut Corporation Business Tax
(CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit
2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not
deducted from rate base during the 24-year period of amortization in recognition
of a longer period of time for amortization of the Seabrook Unit 2 balance. As a
result of reducing its remaining unamortized investment in Seabrook Unit 2 with
proceeds from the sale of certain Seabrook Unit 2 equipment, the Company expects
to completely amortize its unamortized investment in the year 2007.
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company had a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases. 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 no longer has a need to acquire fossil
fuel. The Company and the financial institution agreed to terminate this
agreement as of May 31,1999 at no cost to the Company.
The Company also has lease arrangements for data processing equipment,
office equipment, vehicles and office space, including the lease of a
distribution service facility, which is recognized as a capital lease. The gross
amount of assets recorded under capital leases and the related obligations of
those leases as of December 31, 1999 are recorded on the balance sheet.
Future minimum lease payments under capital leases, excluding the Seabrook
sale/leaseback transaction, which is being treated as a long-term financing, are
estimated to be as follows:
- 64 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(000's)
2000 $ 1,696
2001 1,696
2002 1,696
2003 1,696
2004 16,000
After 2004 -
------
Total minimum capital lease payments 22,784
Less: Amount representing interest 6,278
------
Present value of minimum capital lease payments $16,506
=======
Capitalization of leases has no impact on income, since the sum of the
amortization of a leased asset and the interest on the lease obligation equals
the rental expense allowed for ratemaking purposes.
Operating leases, which are charged to operating expense, consist
principally of a large number of small, relatively short-term, renewable
agreements for a wide variety of equipment. In addition, the Company has an
operating lease for its corporate headquarters. Future minimum lease payments
under this lease are estimated to be as follows:
(000's)
2000 $ 6,524
2001 6,837
2002 8,168
2003 9,125
2004 9,242
2005-2012 81,966
-------
Total $121,862
========
Rental payments charged to operating expenses in 1999, 1998 and 1997,
including rental payments for its corporate headquarters, were $11.0 million,
$11.7 million and $12.2 million, respectively.
- 65 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM (UNAUDITED)
The Company's 2000-2004 estimated capital expenditure program, excluding
allowance for funds used during construction, is presently budgeted as follows:
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004 TOTAL
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Nuclear Generation (1) $ 3,113 $ 3,591 $ - $ - $ - $ 6,704
Distribution and Transmission 46,652 25,393 16,068 13,450 30,850 132,413
------ ------ ------ ------ ------ -------
Subtotal 49,765 28,984 16,068 13,450 30,850 139,117
Nuclear Fuel 8,317 7,090 2,880 8,394 - 26,681
------ ------ ------ ------ ------ -------
Total Utility Expenditures 58,082 36,074 18,948 21,844 30,850 165,798
Total Non-Regulated Business
Expenditures 4,294 5,364 3,864 4,038 4,167 21,727
------ ------ ------ ------ ------ -------
Total $62,376 $41,438 $22,812 $25,882 $35,017 $187,525
======= ======= ======= ======= ======= ========
</TABLE>
(1) The Connecticut Restructuring Act and decisions of the Connecticut DPUC do
not allow for the capitalization of nuclear generation costs, other than
for nuclear fuel, beyond 2001.
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 $88.1 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 $88.1 million, or $4.4
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the two operating 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 $18.6 million per incident. However, any
assessment would be limited to $2.1 million per incident per year.
The NRC requires each operating 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 two operating 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
- 66 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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 the Company. 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 $10.0
million) and return on investment (approximately $3.8 million) at December 31,
1999, is approximately $27.1 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. The
Company is obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. As of December 31, 1999, the Company's
guarantee liability for this debt was approximately $6.2 million.
- 67 -
<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 quality, 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 $8.4 million had been incurred as of December 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. In
addition, the Company is currently replacing the bulkhead that surrounds this
site, at an estimated cost of $13.5 million. Of this amount, $4.2 million
represents the portion of the costs to protect the Company's transmission
facilities and will be capitalized as plant in service. The remaining estimated
cost of $9.3 million was expensed in 1999.
As described at Note (C), "Rate-Related Regulatory Proceedings," 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
Costs associated with nuclear plant operations include amounts for disposal
of nuclear wastes, including spent fuel, and for the ultimate decommissioning of
the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department
of Energy (DOE) is required to design, license, construct and operate a
permanent repository for high level radioactive wastes and spent nuclear fuel.
The Act requires the DOE to provide for the disposal of spent nuclear fuel and
high level radioactive waste from commercial nuclear plants through contracts
with the owners and generators of such waste; and the DOE has established
disposal fees that are being paid to the federal government by electric
utilities owning or operating nuclear generating units. In return for payment of
the prescribed fees, the federal government was required to take title to and
dispose of the utilities' high level wastes and spent nuclear fuel beginning no
later than January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010, and possibly
not earlier than 2013, and that, absent a repository, the DOE has no statutory
obligation to begin taking high level wastes and spent nuclear fuel for disposal
by January 1998. However, numerous utilities and states have obtained a judicial
declaration that the DOE has a statutory responsibility to take title to and
dispose of high level wastes and spent nuclear fuel beginning in January 1998,
and that the contracts between the DOE and the plant
- 68 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
owners and generators of such waste will provide a potentially adequate remedy
to owners and generators in monetary damages for breach of the contracts. The
DOE is contesting these judicial declarations; and it is unclear at this time
whether the United States Congress will enact legislation to address spent
fuel/high level waste disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
operation or decommissioning of nuclear generating units decreased in 1999, as a
result of negotiations between the generators of such wastes and the owners of
licensed disposal facilities. Currently, the Chem Nuclear LLW facility at
Barnwell, South Carolina, is open to the Connecticut Yankee Unit, Millstone Unit
3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW facility at
Clive, Utah, is also open to these generating units for portions of their LLW.
All three units have contracts in place for LLW disposal at these disposal
facilities.
Because access to a LLW disposal facility may be lost at any time,
Millstone Unit 3 and Seabrook Unit 1 have storage plans that will allow on-site
retention of LLW for at least five years in the event that disposal is
interrupted. The Connecticut Yankee Unit, which has been retired from commercial
operation, has a similar storage program, although disposal of its LLW will take
place in connection with its decommissioning.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
Connecticut and New Jersey, who have formed the Northeast Interstate LLW
Compact, are negotiating terms for South Carolina to join them, which would
increase the likelihood that the Connecticut Yankee Unit and Millstone Unit 3
will have access to the Chem Nuclear LLW facility at Barnwell, South Carolina,
through the end of their decommissioning.
NRC licensing requirements and restrictions are also applicable to the
decommissioning of nuclear generating units at the end of their service lives,
and the NRC has adopted comprehensive regulations concerning decommissioning
planning, timing, funding and environmental reviews. The Company and the other
owners of the nuclear generating units in which the Company has interests
estimate decommissioning costs for the units and attempt to recover sufficient
amounts through their allowed electric rates, together with earnings on the
investment of funds so recovered, to cover expected decommissioning costs.
Changes in NRC requirements or technology, as well as inflation, can increase
estimated decommissioning costs.
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 $565 million (in 2000 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $99 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. The Company's share of the decommissioning payments
made during 1999 was $3.3 million. The Company's share of the fund at December
31, 1999 was approximately $20.5 million.
- 69 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $619 million (in 2000 dollars), of which the
Company's share would be approximately $23 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). The Company's share of the Millstone Unit 3 decommissioning
payments made during 1999 was $0.7 million. The Company's share of the fund at
December 31, 1999 was approximately $7.8 million. The current decommissioning
cost estimate for the Connecticut Yankee Unit, assuming the prompt removal and
dismantling of the unit, is $498 million, of which the Company's share would be
$47 million. Through December 31, 1999, $169 million has been expended for
decommissioning. The projected remaining decommissioning cost is $329 million,
of which the Company's share would be $31 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 $2.4
million were funded by the Company during 1999, and the Company's share of the
fund at December 31, 1999 was $17.7 million.
The Financial Accounting Standards Board (FASB) expects to issue a revised
exposure draft related to the accounting for the closure and removal costs of
long-lived assets, including nuclear plant decommissioning. If the proposed
accounting standard were adopted, it may result in higher annual provisions for
decommissioning to be recognized earlier in the operating life of nuclear units
and an accelerated recognition of the decommissioning obligation. The FASB will
be deliberating this issue, and the resulting final pronouncement is not
expected to be effective prior to 2002.
(N) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments are as
follows:
<TABLE>
<CAPTION>
1999 1998
---- ----
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(000's) (000's)
<S> <C> <C> <C> <C>
Unrestricted cash and temporary cash investments $39,099 $39,099 $97,689 $97,689
Long-term debt (1)(2)(3) $420,217 $399,767 $606,342 $611,524
</TABLE>
(1) Excludes the obligation under the Seabrook Unit 1 sale/leaseback agreement.
(2) The fair market value of the Company's long-term debt is estimated by
brokers based on market conditions at December 31, 1999 and 1998,
respectively.
(3) See Note (B), "Capitalization - Long-Term Debt."
- 70 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(O) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1999 and 1998 are set forth below:
<TABLE>
<CAPTION>
OPERATING OPERATING NET EARNINGS PER SHARE OF
QUARTER REVENUES INCOME INCOME COMMON STOCK(1)
- ------- --------- ------ ------ ---------------
(000's) (000's) (000's) Basic Diluted
----- -------
1999
- ----
<S> <C> <C> <C> <C> <C>
First Quarter $168,667 $23,207 $ 9,901 $ .70 $ .70
Second Quarter 164,533 25,193 13,986 .99 .99
Third Quarter 199,071 34,183 24,997 1.78 1.78
Fourth Quarter 147,704 10,972 3,340 .24 .24
1998
- ----
First Quarter $162,474 $22,677 $8,962 $0.64 $0.64
Second-Originally Reported $159,792 $21,174 $5,497 $0.39 $0.39
Provision - APS accounts receivable - - 2,882 0.21 0.21
------- ------ ------ ----- -----
Second-As Restated $159,792 $21,174 $8,379 $0.60 $0.60
======== ======= ====== ===== =====
Third Quarter $198,601 $37,462 $26,236 $1.87 $1.87
Fourth Quarter (2) $165,324 $15,013 $1,495 $0.10 $0.10
</TABLE>
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Operating income, net income and earnings per share for the fourth quarter
of 1998 included an after-tax charge of $8.3 million, associated with a
property tax settlement.
(P) SEGMENT INFORMATION
The Company has one reportable operating segment, that of regulated
generation, distribution and sale of electricity. The accounting policies used
for that segment do not differ from those used for nonreportable operating
segments. Revenues from inter-segment transactions are not material and all of
the Company's revenues are derived in the United States.
The revenues from external customers, interest income, interest expense and
depreciation charges of the one reportable segment are identical to the amounts
shown on the Consolidated Statement of Income for each year presented. Income
before taxes of the reportable segment is not materially different from that of
the Company as a whole.
The following table reconciles the total assets of the reportable segment
with the total assets shown on the Consolidated Balance Sheet at December 31:
- 71 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1999 1998
---- ----
(000's)
Total Assets - Regulated Utility $1,809,451 $1,943,328
Total Assets - Unregulated Subsidiaries 194,642 83,306
Total Assets - Elimination (205,883) (85,474)
--------- ---------
Total Consolidated Assets $1,798,210 $1,941,160
========= =========
(Q) RESTATEMENT OF FINANCIAL RESULTS
AMERICAN PAYMENT SYSTEMS, INC. (APS) RESTATEMENTS
- -------------------------------------------------
During the third quarter of 1999, the Company has restated its financial
statements for 1998, 1997 and 1996 for matters related to the timing of American
Payment Systems ("APS") agency collection reserves, for certain line loss
factors that affect the calculation of unbilled revenues and for cash, accounts
receivable and accounts payable amounts related to APS's collection agent
network. The Company had consultations with the staff of the Securities and
Exchange Commission and its independent accountants in determining these
restated amounts.
During 1997 and 1996, APS agent bank accounts were not fully reconciled at
the time APS balance sheet items were prepared to allow for the identification,
measurement and enforcement of material claims for recovery from APS agents for
defalcated amounts or from APS customers for checks returned by banks due to
insufficient funds. As a result, losses associated with collection agent errors
and defaults went undetected for extended periods of time. In the second quarter
of 1998, the Company performed a review of the accounting records at APS and
identified significantly past due agent collections of $4.9 million ($2.8
million, after-tax) that represented agent deposit shortfalls and uncollectible
agent check deposits. Pursuant to the result of this review, APS increased its
provision against their receivable balance by $4.9 million ($2.8 million,
after-tax) in the second quarter of 1998. The Company applied similar procedures
during 1996 and, based on the results, recorded a $4.5 million ($2.6 million,
after-tax) increase in its provision in the fourth quarter of 1996. Due to the
fact that these adjustments related to losses incurred in both current and prior
periods, the Company has restated the effects of these adjustments back to the
periods in which the losses occurred as shown below. The impact of the
adjustments described above was to reduce retained earnings as of January 1,
1998 by $2.8 million.
The restatement of cash, accounts receivable and accounts payable amounts
related to APS's collection agent network was recorded so as to include on the
Company's consolidated balance sheet amounts that had previously been recorded
on a net basis.
UNBILLED REVENUE RESTATEMENT
- ----------------------------
During the third quarter of 1999, the Company reviewed an adjustment of
$2.7 million ($1.6 million, after-tax) made to retail operating revenues in the
fourth quarter of 1997 related to the reversal of prior period overestimates of
transmission line losses. The Company uses an estimated line loss factor, based
upon a 24 month-moving historical line loss factor, to calculate the amount of
revenue from electricity sales that is unbilled during the period and therefore
should be accrued. This loss factor is applied to the known amount of
electricity delivered to the Company's transmission grid from internal and
external sources. Historically, this methodology provided a reasonable estimate
of the amount of unbilled revenue.
Beginning in the first quarter of 1996, the outages of four nuclear
generating units resulted in the Company purchasing power from other sources.
The electricity from other sources followed different transmission paths and
exhibited different line loss characteristics than the electricity generated by
the nuclear generating units. During this
- 72 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
period of time, the Company continued to utilize the 24 month-moving average
loss factor in order to smooth the impact of changes in the line loss factors in
the calculation of unbilled revenue amounts.
Based upon a review of the actual New England Power Pool line loss factors
during this period and the pattern of when they occurred, the Company has
restated the $1.2 million ($0.7 million, after-tax) of the adjustment made to
retail operating revenues, originally recorded in the fourth quarter of 1997, to
1996.
The following tables summarize the restatements that the Company has made
on net income, earnings per share and retained earnings.
Increase (decrease) in net income:
FOR THE YEAR ENDED DECEMBER 31,
1998 1997
---- ----
DESCRIPTION (000's)
-----------
1998 APS charge $ 2,882 $(1,643)
1997 unbilled revenues - (691)
------ -----
Net increase (decrease) to net income 2,882 (2,334)
Net income applicable to common shareholders,
as originally reported 42,010 45,634
------ ------
Net income applicable to common shareholders,
as restated $44,892 $43,300
====== ======
FOR THE YEAR ENDED DECEMBER 31,
DESCRIPTION 1998 1997
----------- ---- ----
Earnings per share, as originally reported
- Basic $3.00 $3.27
- Diluted $3.00 $3.26
Earnings per share, as restated
- Basic $3.20 $3.10
- Diluted $3.20 $3.09
AS OF DECEMBER 31,
1998 1997
---- ----
DESCRIPTION (000's)
-----------
Retained earnings, as originally reported $163,847 $162,226
Net effect of restatements, described above - (2,882)
------- --------
Retained earnings, as restated $163,847 $159,344
======== ========
Included in restricted cash at December 31, 1998 is $23,056, representing
collections by APS agents that are held in APS agent accounts prior to
transmittal to the respective APS customers. In addition, included in other
accounts receivable at December 31, 1998 is $26,768, representing collections by
APS agents not yet deposited into APS bank accounts. A corresponding accounts
payable has been recorded to reflect the portions of these collections owed to
APS customers, as well as the amount of restricted cash presented above. The
Company had previously presented its consolidated balance sheet net of these
accounts receivable and accounts payable amounts.
The following table summarizes the effect of the restatements described
above to restricted cash, other accounts receivable, and accounts payable - APS
customers:
- 73 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
AS OF DECEMBER 31,
1998
----
(000's)
Restricted cash, as originally reported $ -
Effect of restatement, described above 23,056
------
Restricted cash, as restated $23,056
======
Other accounts receivable, as originally reported (1) $37,472
Effect of restatement, described above
Additional accounts receivable for APS agents 26,768
Additional APS agent collection reserves -
------
Other accounts receivable, as restated $64,240
======
Accounts payable-APS customers, as originally reported $ -
Accounts payable-APS customers reclassed
from accounts payable 4,691
Effect of restatement, described above
Restricted cash 23,056
Additional amounts owed to APS customers 26,768
------
Accounts payable-APS customers, as restated $54,515
======
(1) Includes accounts receivable from APS agents originally included in other
accounts receivable of $4,691,000 as of December 31, 1998.
In addition, the Company has revised Schedule II on page S1 to reflect the
restatement of additional reserves for uncollectible accounts related to APS
agent collections.
- 74 -
<PAGE>
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders
of The United Illuminating Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, and of changes in shareholders' equity and of
cash flows present fairly, in all material respects, the financial position of
The United Illuminating Company and its subsidiaries (the "Company") at December
31, 1999 and 1998, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 75 -
<PAGE>
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and the Shareholders
of The United Illuminating Company:
Our audits of the consolidated financial statements referred to in our report
dated January 24, 2000 appearing in the 1999 Annual Report on Form 10-K also
included an audit of the financial statement schedule on page S-1 of this Form
10-K. In our opinion, this Financial Statement Schedule presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 76 -
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures.
Not Applicable
PART III
Item 10. Directors and Executive Officers of the Company.
DIRECTORS OF THE COMPANY
The following table provides information regarding all persons who were
directors at any time during the fiscal year ended December 31, 1999 and all
persons who will be nominated to become directors at the Company's 2000 Annual
Meeting of the Shareowners. All of the persons named below will be nominated to
become directors at the 2000 Annual Meeting of the Shareowners except Frank R.
O'Keefe, Jr., who will retire on the date of the Annual Meeting.
<TABLE>
<CAPTION>
NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
<S> <C> <C>
Thelma R. Albright 53 1995
President, Carter Products Division, Carter-Wallace, Inc., Cranbury, New Jersey.
During 1995, Ms. Albright was General Manager and Executive Vice President of
Revlon Beauty Care Division. Also, Director, Cosmetics, Toiletry and Fragrance
Association and Consumer Healthcare Products Association.
Marc C. Breslawsky 57 1995
President and Chief Operating Officer, Pitney Bowes, Inc., Stamford,
Connecticut. Also, Director, Pitney Bowes, Inc., Pitney Bowes Credit Corp., C.R.
Bard, Inc., Pittston Corp., The Family Foundation of North America, Connecticut
Business and Industry Association and United Way of Eastern Fairfield County;
Vice Chairman of the Governor's Council of Economic Competitiveness and
Technology; Member, Board of Governors, the State of Connecticut/Red Cross
Disaster Relief Cabinet and the Landmark Club; and Trustee, Norwalk Hospital.
David E. A. Carson 65 1993
Director, People's Bank, Bridgeport, Connecticut, and Trustee, People's Mutual
Holdings, Bridgeport, Connecticut. From 1985-1999 Mr. Carson was Chief Executive
Officer of People's Bank and People's Mutual Holdings. Also, Chairman,
Bridgeport Public Education Fund, Business Advisory Committee of Connecticut
Commission on Children and Bridgeport Area Foundation; and Director, Mass Mutual
Institutional Funds, MML Series Investment Funds, American Skandia Trust, Old
State House, Hartford, Connecticut, The Bushnell, Hartford, Connecticut, and
Hartford Stage Company.
</TABLE>
- 77 -
<PAGE>
<TABLE>
<CAPTION>
NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
<S> <C> <C>
Arnold L. Chase 48 1999
President, Gemini Networks, Inc., and Executive Vice President, Chase
Enterprises, Hartford, Connecticut. Also, Director, First International Bank,
Juvenile Diabetes Foundation International, Old State House Association,
Connecticut Historic Society and Science Center of Connecticut.
John F. Croweak 63 1987
Chairman of the Board of Directors, Anthem Blue Cross & Blue Shield of
Connecticut, Inc., North Haven, Connecticut. Prior to his retirement in 1997,
Mr. Croweak served as Chairman of the Board of Directors and Chief Executive
Officer of Anthem Blue Cross & Blue Shield of Connecticut and its predecessor,
Blue Cross & Blue Shield of Connecticut, Inc. Also Chairman of the Board of
Directors, Connecticut American Insurance Company, ProMed Systems, Inc., OPTIMED
Medical Systems and Signal Medical Services, Inc.; and Director, BCS Financial,
The New Haven Savings Bank, Quinnipiac College, Opticare and Anthem, Inc.
Robert L. Fiscus 62 1992
Vice Chairman of the Board of Directors, Chief Financial Officer, Treasurer and
Secretary, The United Illuminating Company. Mr. Fiscus served as President and
Chief Financial Officer of the Company during the period January 1995 to
February 1998 and as Vice Chairman of the Board of Directors and Chief Financial
Officer from February 1998 to October 1999. He has served as Vice Chairman of
the Board of Directors, Chief Financial Officer, Treasurer and Secretary since
October 1999. Also, Director, Bridgeport Regional Business Council, Griffin
Health Services Corporation, The Aristotle Corporation, Bridgeport Area
Foundation and Susquehanna University; Governor, University of New Haven; and
Trustee, Central Connecticut Coast Young Men's Christian Association, Inc.
Betsy Henley-Cohn 47 1989
Chairman of the Board of Directors, Joseph Cohn & Son, Inc., New Haven,
Connecticut. Also, Chairwoman of Birmingham Utilities, Inc.; and Director, The
Aristotle Corporation and Citizens Bank of Connecticut.
John L. Lahey 53 1994
President, Quinnipiac College, Hamden, Connecticut. Also, Director, Yale-New
Haven Hospital and The Aristotle Corporation; Vice Chairman and Director,
Regional Plan Association Board, New York, New York; and Member, Greater New
Haven Regional Leadership Council and Accreditation Committee of the American
Bar Association.
</TABLE>
- 78 -
<PAGE>
<TABLE>
<CAPTION>
NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
<S> <C> <C>
F. Patrick McFadden, Jr. 62 1987
Retired Chairman, Citizen's Bank of Connecticut, New Haven, Connecticut. During
the period 1995 through 1997, Mr. McFadden was President, Chief Executive
Officer and Director, The Bank of New Haven and BNH Bancshares, Inc. Also,
Chairman of the Board of Directors, Yale-New Haven Health Services Corporation;
and Member, Representative Policy Board of the South Central Connecticut
Regional Water District.
Daniel J. Miglio 59 1999
Formerly Chairman, President and Chief Executive Officer of Southern New England
Telecommunications Corporation during the period 1995 through 1998. Director,
The Aristotle Corporation, Yale-New Haven Health Services Corporation and
Connecticut Public Television and Radio; and Chairman, International Festival of
Arts and Ideas.
Frank R. O'Keefe, Jr. 70 1989
Retired; former President, Long Wharf Capital Partners, Inc. 1988-1990; retired
Chairman, President and Chief Executive Officer, Armtek Corporation 1986-1988;
President and Chief Operating Officer, Armstrong Rubber Company 1980-1986; and
Director, Aetna Inc.
James A. Thomas 60 1992
Associate Dean, Yale Law School. Also, Trustee, Yale-New Haven Hospital and
People's Mutual Holdings; and Director, People's Bank and Sea Research
Foundation.
Nathaniel D. Woodson 58 1998
Chairman of the Board of Directors, President and Chief Executive Officer, The
United Illuminating Company. Mr. Woodson served as President of the Energy
Systems Business Unit of Westinghouse Electric Corporation during the period
January 1995 to April 1996. He has served as President of the Company since
February 1998, Chief Executive Officer since May 1998 and Chairman of the Board
of Directors since January 1999.
</TABLE>
There is no arrangement or understanding between any of the persons listed
above and any other person pursuant to which the person listed above was or is
selected as a director or director-nominee. There is no family relationship
between any of the persons listed above, or between any person listed above and
any executive officer, or person chosen to be an executive officer, of the
Company.
EXECUTIVE OFFICERS OF THE COMPANY
See "EXECUTIVE OFFICERS OF THE COMPANY" in PART I of this Annual Report on
Form 10-K for information regarding the Company's Executive Officers.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's
directors and officers, and persons who own more than ten percent of the
Company's Common Stock, to file with the Securities and Exchange Commission
(SEC) and The New York Stock Exchange initial reports of ownership and reports
of changes in ownership of Common Stock and other equity securities of the
Company. Directors, officers and certain greater-than-ten-percent shareowners
are required by SEC regulations to furnish the Company with copies of all
Section 16(a) forms they file.
- 79 -
<PAGE>
To the Company's knowledge, based solely on review of reports furnished to
the Company and written representations that no other reports were required,
during the fiscal year ended December 31, 1999 all Section 16(a) filing
requirements applicable to its directors, officers and greater-than-ten-percent
shareowners were complied with.
Item 11. Executive Compensation.
EXECUTIVE COMPENSATION
The following table shows the annual and long-term compensation, for
services in all capacities to the Company for the years 1999, 1998 and 1997, of
the person who served as the chief executive officer during 1999 and of the four
other most highly compensated persons during 1999 who were serving as executive
officers at December 31, 1999:
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
----------------------
NAME AND ANNUAL COMPENSATION SECURITIES UNDERLYING LTIP ALL OTHER
-------------------
PRINCIPAL POSITION(1) YEAR SALARY($) BONUS($)(2) OPTIONS/SARS(#) PAYOUTS($) COMPENSATION(6)
------------------ ---- --------- -------- --------------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
Nathaniel D. Woodson 1999 $412,000 $220,000 21,000(7) $169,338
Chairman of the Board of 1998 341,668 105,000 80,000(8) 38,756
Directors, President and Chief
Executive Officer
Robert L. Fiscus 1999 $233,200 $110,000 15,500(7) $334,141(3) $8,471
Vice Chairman of the Board of 1998 224,900 55,000 260,691(4) 7,745
Directors, Chief Financial 1997 220,400 70,000 59,850(5) 7,360
Officer, Treasurer and Secretary
James F. Crowe 1999 $187,900 $70,000 8,000(7) $257,031(3) $7,750
Group Vice President 1998 181,200 37,000 200,531(4) 7,235
1997 177,600 55,000 42,750(5) 6,830
Anthony J. Vallillo 1999 $185,900 $68,000 8,000(7) $257,031(3) $7,105
Group Vice President 1998 175,700 46,000 72,191(4) 6,679
1997 170,000 55,000 6,840(5) 6,144
Albert N. Henricksen 1999 $162,700 $60,000 8,000(7) $154,219(3) $7,304
Group Vice President 1998 147,650 36,000 96,255(4) 6,876
1997 140,600 38,000 13,680(5) 6,401
</TABLE>
- -----------------------
(1) None of the persons named received any cash compensation in any of the
years shown other than the amounts appearing in the columns captioned
"Salary," "Bonus," "LTIP Payouts" and "All Other Compensation." None of
these persons received, in any of the years shown, any cash-equivalent form
of compensation, other than through participation in the Company's group
life, health and hospitalization plans, which are available on a uniform
basis to all salaried employees of the Company and the dollar value of
which, together with the dollar value of all other non-cash perquisites and
other personal benefits received by such person, did not exceed the lesser
of $50,000 or 10% of the total salary and bonus compensation received by
him for such year.
(2) The amounts appearing in this column are awards earned in the years 1997,
1998 and 1999 pursuant to the Executive Incentive Compensation Program
described below.
(3) This is the amount earned for the 1997-1999 performance period under the
1996 Long-Term Incentive Program as described below. The cash payouts were
made in February 2000.
(4) This is the amount earned for the 1996-1998 performance period under the
1996 Long-Term Incentive Program. The cash payouts were made in March 1999.
- 80 -
<PAGE>
(5) This is the amount earned for the 1995-1997 performance period under the
1993 Dividend Equivalent Program. Under this program, which was terminated
when the Long-Term Incentive Program described below was established in
1996, each officer of the Company was awarded a number of Dividend
Equivalent Units (Units) prior to the commencement of the 1995 performance
period and, due to the ranking of the Company's total shareowner return
during the performance period relative to the total shareowner returns of a
preselected peer group of companies, the officer earned a number of Units
that resulted in a cash payment equal to that number of Units multiplied by
the sum of all dividends paid per share on the Company's Common Stock
during the performance period. The cash payments were made in February,
1998.
(6) The amounts appearing in this column, except the amounts shown for Mr.
Woodson, are cash contributions by the Company to its Employee Stock
Ownership Plan (ESOP) on behalf of each of the persons named for (i) a
match of pre-tax elective deferral contributions by him to the Company's
401(k) Plan from his salary and bonus compensation (included in the columns
captioned "Salary" and "Bonus"), and (ii) an additional contribution by the
Company equal to 25% of the dividends paid on his shares in the ESOP. Cash
contributions of $5,403 and $5,521 were made on behalf of Mr. Woodson for
these purposes during 1998 and 1999 respectively, and are included in the
amount appearing in this column. In addition, during 1998, Mr. Woodson
received a reimbursement of his relocation expenses, in the amount of
$33,355, when he moved from Pennsylvania to Connecticut at the commencement
of his employment by the Company. In 1999, Mr. Woodson received $163,817 as
reimbursement for the costs associated with the selling of his residence in
Pennsylvania.
(7) These are stock options on shares of the Company's Common Stock granted on
March 22, 1999. The options are exercisable at the rate of one-third of the
options on each of the first three anniversaries of the grant date pursuant
to the terms of the 1999 Stock Option Plan as described below.
(8) These are phantom stock options on shares of the Company's Common Stock
granted to Mr. Woodson in February of 1998 at the time of his employment by
the Company as its President. The options are exercisable at the rate of
16,000 options on each of the first five anniversaries of the grant date
during the term of Mr. Woodson's employment agreement with the Company,
which is described below.
The Company's Executive Incentive Compensation Program was established in
1985 for the purposes of (i) helping to attract and retain executives and key
managers of high ability, (ii) heightening the motivation of those executives
and key managers to attain goals that are in the interests of shareowners and
customers, and (iii) encouraging effective management teamwork among the
executives and key managers of the Company. Under this program, cash awards may
be made each year to officers and key employees based on their achievement of
pre-established performance levels with respect to specific shareowner goals,
customer goals and individual goals for the preceding year, and upon an
assessment of the officers' performance as a group with respect to strategic
opportunities during that year, and based on such other factors as the Committee
deems relevant. Eligible officers, performance levels and specific goals are
determined each year by directors who are not employees of the Company, and
incentive awards are paid following action by the Board of Directors after the
close of the year. Incentive awards for the achievement of performance levels
and specific goals are made from individual target incentive award amounts,
which are prescribed percentages of the individual participants' salaries,
ranging from 20% to 35% depending on each participant's payroll salary grade. A
participant may, by achieving his or her pre-established performance levels with
respect to specific shareowner goals, customer goals and individual goals for a
year, become eligible for an incentive award for this achievement of up to 150%
of his or her target incentive award amount for that year.
The Company's 1996 Long-Term Incentive Program was established for the
purposes of (i) promoting the long-term success of the Company by attracting,
retaining and providing financial incentives to key employees who are in a
position to make significant contributions toward that success, (ii) linking the
interests of these key employees to the interests of the shareowners, and (iii)
encouraging these key employees to maintain proprietary interests in the Company
and achieve extraordinary job performance levels. Under the program, an initial
three-year Performance Period commenced on January 1, 1996, three-year
Performance Periods commenced on January 1, 1997 and January 1, 1998, and a
series of three-year Performance Periods was to commence on January 1, 1999 and
on each January 1 thereafter to and including January 1, 2005. In 1999, the
Board of Directors determined to substitute stock options, under the 1999 Stock
Option Plan described below, for the 1996 Long-Term
- 81 -
<PAGE>
Incentive Program. Under this Program, the Board of Directors has designated the
officer-participants in the program for each Performance Period, the number of
Contingent Performance Shares awarded each officer-participant for that
Performance Period, and a peer group of companies comparable to the Company for
that Performance Period. Each Contingent Performance Share is a share unit,
equivalent to one share of the Company's Common Stock, credited to an
officer-participant's performance share account in the program on a conditional
basis at the beginning of a Performance Period. At the end of each Performance
Period, the number of Performance Shares earned for the Performance Period is
calculated on the basis of the Company's total shareowner return during the
Performance Period relative to the peer group of companies preselected by the
Board of Directors for that Performance Period. Total shareowner return for the
Company, and for each member of the peer group, for a Performance Period is
measured by the formula:
Change in Market Price from + Dividends Declared During the Period
Beginning to End of Period
------------------------------------------------------------------------
Market Price at Beginning of Period
If the Company's total shareowner return for the Performance Period ranks at the
ninetieth percentile among the total shareowner returns of the peer group
companies, the number of Performance Shares earned by the officer-participant is
equal to the number of Contingent Performance Shares awarded to that
officer-participant at the commencement of the Performance Period. If the
Company's total shareowner return ranks below the thirtieth percentile among
those of the peer group companies, no Performance Shares are earned for the
Performance Period. If the Company's total shareowner return ranks between the
thirtieth and the ninetieth percentiles, the number of Performance Shares earned
is calculated from a scale rising from 15% to 100%. On each dividend payment
date with respect to the Company's Common Stock, the earned Performance Shares
in an officer-participant's Performance Share account are credited with an
additional number of Performance Shares in an amount equal to the dividend
payable on the earned Performance Shares in the account divided by the market
price of the Company's Common Stock on the dividend payment date. Upon the
termination of an officer-participant's employment by the Company, the
officer-participant is paid, in cash, an amount equal to the number of earned
Performance Shares in his or her Performance Share account multiplied by the
market price of the Company's Common Stock on the employment termination date.
An officer-participant is also entitled to payment at any time, in cash, of the
value of the earned Performance Shares in his or her Performance Share account,
provided that the officer-participant is in compliance with the minimum stock
ownership requirement for such officer prescribed by the Board of Directors at
that time.
The Company's 1999 Stock Option Plan is intended to promote the
profitability of the Company and its subsidiaries by providing directors,
officers and key full-time employees with incentives to contribute to the
Company's success, and enable the Company to attract, retain and reward the best
available directors and managerial employees. A maximum of 650,000 shares of
Common Stock may be purchased under the 1999 Stock Option Plan, and the maximum
number of shares that may be purchased through options granted in any one year
to any optionee may not exceed 50,000. Options under the 1999 Stock Option Plan
may be granted as incentive stock options, intended to qualify for favorable tax
treatment under federal tax law, or as nonqualified stock options. When
incentive stock options or nonqualified stock options become exercisable and are
exercised by the optionee to whom they have been granted, the optionee pays the
Company the exercise price per share fixed on the date of the option grant and
receives shares of Common Stock equal to the number of incentive stock options
or nonqualified stock options exercised. Directors who are not employees of the
Company select the optionees, determine the number of stock options to be
granted to each optionee, whether the stock options will be nonqualified stock
options or incentive stock options, and whether any stock option will include a
right to purchase an additional share of Common Stock contingent upon the option
holder's having exercised the stock option and having paid its exercise price in
full in shares of Common Stock (a "Reload Right"). The non-employee directors
also determine the period within which each stock option granted will be
exercisable, and may provide that the stock options will become exercisable in
installments.
- 82 -
<PAGE>
The following rules must be observed under the 1999 Stock Option Plan:
o the exercise price for each option must be equal to or greater than the
fair market value of the Common Stock on the date of the creation of the
option, determined by averaging the high and low sales prices of the Common
Stock on the New York Stock Exchange on that date,
o no option may be repriced after the date of its creation,
o no stock option may be exercisable less than one year, or more than ten
years, from the date it is granted,
o no more than 1/3 of the number of stock options granted to any optionee
on any date may first become exercisable in any twelve-month period,
o in the case of the grant of an incentive stock option to an optionee who,
at the time of the grant, owns more than 10% of the total combined voting
power of all classes of the stock of the Company or any of its
subsidiaries, in no event may the stock option be exercisable more than
five years from the date it is granted,
o in the case of incentive stock options, the number of stock options granted
to an optionee on any date that may first become exercisable in any
calendar year must be limited to $100,000 divided by the exercise price per
share,
o an option arising from the exercise of a Reload Right cannot be exercised
before the six-month anniversary of the date when the Reload Right was
exercised, and it will expire on the same date on which the option from
which it arose would have expired if it had not been exercised,
o except as otherwise provided in the 1999 Stock Option Plan, an employee
optionee may exercise a stock option only if he or she is, and has
continuously been since the date of the stock option was granted, a
full-time employee of the Company or one of its subsidiaries.
The Company has entered into an employment agreement with Mr. Woodson,
which will continue in effect until terminated by the Company at any time or by
the officer on six months' notice. This agreement provides that the annual
salary rate of Mr. Woodson will be $400,000, subject to upward revision by the
Board of Directors at such times as the salary rates for other officers of the
Company are reviewed by the Directors, and subject to downward revision by the
Board of Directors contemporaneously with any general reduction of the salary
rates of other officers of the Company, except in the event of a change in
control of the Company. The salary paid to Mr. Woodson in 1998 and 1999, shown
on the above table, was paid pursuant to this agreement. This agreement also
provides that when the officer's employment by the Company terminates after he
has served in accordance with its terms, the Company will pay him an annual
supplemental retirement benefit in an amount equal to the excess, if any, of (A)
over (B), where (A) is 2.0% of his highest three-year average total salary and
bonus compensation from the Company times the number of years (not to exceed 30)
of his deemed service as an employee of the Company, and (B) is the annual
benefit payable to him under the Company's pension plan. If the Company
terminates the officer's employment on less than three years' notice and without
cause, he will be paid the actuarial present value of this supplemental
retirement benefit and either a severance payment of up to two years'
compensation at his then-current salary and bonus rate, or an increase of a
total of six years of age and/or service in the calculation of his supplemental
retirement benefit and/or the benefits payable to him under the Company's
retiree medical benefit plans. Under the Company's Change in Control Severance
Plan, if Mr. Woodson's employment is terminated without cause within two years
following a change in control of the Company, he will be entitled to receive, in
lieu of his employment agreement termination benefits, a severance payment of
three years' compensation at his then-current salary and bonus rate, an increase
of three years of service in the calculation of his supplemental retirement
benefit and the benefits payable under the Company's retiree medical benefit
plans, and three years of continued participation in the Company's employee
benefit plans and programs.
The Company has also entered into employment agreements with Messrs. Fiscus
and Crowe, each of which will continue in effect until terminated by the Company
on three years' notice or by the officer on six months' notice. These agreements
provide that the annual salary rates of Messrs. Fiscus and Crowe will be
$218,400 and $176,600, respectively, subject to upward revision by the Board of
Directors at such times as the salary rates of other officers of the Company are
reviewed by the Directors, and subject to downward revision by the Board of
Directors contemporaneously with any general reduction of the salary rates of
other officers of the Company, except in the event of a change in control of the
Company. The salaries paid to Messrs. Fiscus and Crowe in 1997, 1998
- 83 -
<PAGE>
and 1999, shown on the above table, were paid pursuant to these agreements. Each
of these agreements also provides that when the officer's employment by the
Company terminates after he has served in accordance with its terms, the Company
will pay him an annual supplemental retirement benefit in an amount equal to the
excess, if any, of (A) over (B), where (A) is 2.2% of his highest three-year
average total salary and bonus compensation from the Company times the number of
years (not to exceed 30) of his service deemed as an employee of the Company,
and (B) is the annual benefit payable to him under the Company's pension plan.
If the Company terminates the officer's employment on less than three years'
notice and without cause, he will be paid the actuarial present value of this
supplemental retirement benefit and, if the termination occurs in connection
with a change in control of the Company, the officer will be entitled to either
a severance payment of two years' compensation at his then-current salary and
bonus rate, or an increase of a total of six years of age and/or service in the
calculation of his supplemental retirement benefit and/or the benefits payable
to him under the Company's retiree medical benefit plans. Under the Company's
Change in Control Severance Plan, if the officer's employment is terminated
without cause within two years following a change in control of the Company, he
will be entitled to receive, in lieu of his employment agreement termination
benefits, a severance payment of two years' compensation at his then-current
salary and bonus rate, an increase of two years of service in the calculation of
his supplemental retirement benefit and the benefits payable under the Company's
retiree medical benefit plans, and two years of continued participation in the
Company's employee benefit plans and programs.
The Company has also entered into employment agreements with Messrs.
Vallillo and Henricksen, each of which will continue in effect until terminated
by the Company at any time or by the officer on six months' notice. These
agreements provide that the annual salary rates of Messrs. Vallillo and
Henricksen will be $140,000 and $136,900, respectively, subject to upward
revision by the Board of Directors at such times as the salary rates for other
officers of the Company are reviewed by the Directors, and subject to downward
revision by the Board of Directors contemporaneously with any general reduction
of the salary rates of other officers of the Company, except in the event of a
change in control of the Company. The salaries paid to Messrs. Vallillo and
Henricksen in 1997, 1998 and 1999, shown on the above table, were paid pursuant
to these agreements. Each of these agreements also provides that when the
officer's employment by the Company terminates after he has served in accordance
with its terms, the Company will pay him an annual supplemental retirement
benefit in an amount equal to the excess, if any, of (A) over (B), where (A) is
2.0% of his highest three-year average total salary and bonus compensation from
the Company times the number of years (not to exceed 30) of his service as an
employee of the Company, and (B) is the annual benefit payable to him under the
Company's pension plan. If the Company terminates the officer's employment
without cause, he will be paid the actuarial present value of this supplemental
retirement benefit and either a severance payment of two years' compensation at
his then-current salary and bonus rate, or an increase of a total of six years
of age and/or service in the calculation of his supplemental retirement benefit
and/or the benefits payable to him under the Company's retiree medical benefit
plans. Under the Company's Change in Control Severance Plan, if the officer's
employment is terminated without cause within two years following a change in
control of the Company, he will be entitled to receive, in lieu of his
employment agreement termination benefits, a severance payment of two years'
compensation at his then-current salary and bonus rate, an increase of two years
of service in the calculation of his supplemental retirement benefit and the
benefits payable under the Company's retiree medical benefit plans, and two
years of continued participation in the Company's employee benefit plans and
programs
A trust fund has been established by the Company for the funding of the
supplemental retirement benefits accruing under the employment agreements with
Messrs. Woodson, Fiscus, Crowe, Vallillo and Henricksen, and to ensure the
performance of the Company's other payment obligations under each of these
employment agreements in the event of a change in control of the Company.
- 84 -
<PAGE>
OPTION/SAR GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
NUMBER OF % OF TOTAL POTENTIAL REALIZABLE VALUE
SECURITIES OPTIONS/SARS AT ASSUMED ANNUAL RATES
UNDERLYING GRANTED TO EXERCISE OR OF STOCK PRICE APPRECIATION
OPTIONS/SARS EMPLOYEES IN BASE PRICE EXPIRATION FOR OPTION TERM
----------------------------
NAME GRANTED (#) FISCAL YEAR ($/SHARE) DATE 5%($) 10%($)
- ---- ----------- ----------- --------- ---- ----- ------
<S> <C> <C> <C> <C> <C> <C>
Nathaniel D. Woodson 21,000 15.3% $43.2188 03/22/09 $453,797 $907,594
Robert L. Fiscus 15,500 11.3% 43.2188 03/22/09 334,945 669,891
James F. Crowe 8,000 5.8% 43.2188 03/22/09 172,875 345,750
Anthony J. Vallillo 8,000 5.8% 43.2188 03/22/09 172,875 345,750
Albert N. Henricksen 8,000 5.8% 43.2188 03/22/09 172,875 345,750
</TABLE>
- -------------------
These are stock options on shares of the Company's Common Stock granted on
March 22, 1999. The options are exercisable at the rate of one-third of the
options on each of the first three anniversaries of the grant date.
STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES
The following table shows aggregated Common Stock option exercises during
1999 by the chief executive officers and each of the other four most highly
compensated executive officers of the Company, including the aggregate value of
gains realized on the dates of exercise. In addition, this table shows the
number of shares covered by both exercisable and non-exercisable options as of
December 31, 1999. Also reported are the values as of December 31, 1999 for
"in-the-money" options, calculated as the positive spread between the exercise
price of existing options and the year-end fair market value of the Company's
Common Stock.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS/SARS
ACQUIRED ON VALUE OPTIONS/SARS AT FY-END(#) AT FY-END ($)(2)
------------------------- -------------
NAME EXERCISE(#) REALIZED($)(1) EXERCISABLE NOT EXERCISABLE EXERCISABLE NOT EXERCISABLE
---- ----------- ----------- --------------------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Nathaniel D. Woodson 0 $0 16,000 85,000 $ 99,499 $569,278
Robert L. Fiscus 0 0 10,500 15,500 157,500 126,422
James F. Crowe 0 0 0 8,000 0 65,250
Anthony J. Vallillo 0 0 0 8,000 0 65,250
Albert N. Henricksen 0 0 0 8,000 0 65,250
</TABLE>
- -------------------------
(1) Fair market value at exercise date less exercise price.
(2) Fair market value of shares at December 31, 1999 ($51.375) less exercise
price.
RETIREMENT PLANS
The following table shows the estimated annual benefits payable as a single
life annuity under the Company's qualified defined benefit pension plan on
retirement at age 65 to persons in the earnings classifications and with the
years of service shown. Retirement benefits under the plan are determined by a
fixed formula, based on years of service and the person's average annual
earnings from the Company during the three years during which the person's
earnings from the Company were the highest, applied uniformly to all persons.
- 85 -
<PAGE>
<TABLE>
<CAPTION>
AVERAGE
ANNUAL EARNINGS DURING
THE HIGHEST 3 ESTIMATED ANNUAL BENEFITS PAYABLE AT AGE 65(3)
-------------------------------------------
YEARS OF SERVICE(1)(2) 20 YEARS(4) 25 YEARS(4) 30 YEARS(4) 35 YEARS(4) 40 YEARS(4)
---------------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
$100,000 $32,000 $40,000 $48,000 $48,000 $48,000
$150,000 $48,000 $60,000 $72,000 $72,000 $72,000
$200,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$250,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$300,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$350,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$400,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$450,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
</TABLE>
- -------------------------
(1) Earnings include annual salary and cash bonus awards paid pursuant to the
Company's Executive Incentive Compensation Program. See "Executive
Compensation" above.
(2) Internal Revenue Code Section 401(a)(17) limits earnings used to calculate
qualified plan benefits to $160,000 for 1999. This limit was used in the
preparation of this table. (In addition, qualified plan benefits cannot
exceed an Internal Revenue Code Section 415(b) limit of $130,000 for 1999).
The Board of Directors has adopted a supplemental executive retirement plan
that will pay supplemental retirement benefits to Messrs. Woodson, Fiscus,
Crowe, Vallillo and Henricksen and other officers of the Company in amounts
sufficient to prevent these Internal Revenue Code limitations from
adversely affecting their retirement benefits determined by the pension
plan's fixed formula.
(3) The amounts shown in the table are not subject to any deduction for Social
Security or other offset amounts.
(4) As of their last employment anniversary dates, Messrs. Woodson, Fiscus,
Crowe, Vallillo and Henricksen had accrued 2, 27, 35, 31, and 36 years of
service, respectively.
BOARD OF DIRECTORS
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
All of the members of the Compensation and Executive Development Committee
of the Board of Directors (the Committee) are non-employee Directors.
The Committee, with the assistance of an outside compensation consulting
firm, formulates all of the objectives and policies relative to the compensation
of the officers of the Company, subject to approval by the entire Board of
Directors; and the Committee recommends to the Board of Directors all of the
elements of the officers' compensation arrangements, including the design and
adoption of compensation programs, the identity of program participants, salary
grades and structure, annual payments of salaries, and any awards under the
annual incentive compensation program and the long-term incentive program.
The Company's basic executive compensation program consists of three
components: annual salaries, bonuses under an annual incentive compensation
program, and long-term incentive program awards. The overall objective of this
program is to attract and retain qualified executives and to produce strong
financial performance for the benefit of the Company's shareowners, while
providing a high level of customer service and value for its customers.
Accordingly, all of the Committee's decisions, in 1999 and in prior years, have
ultimately been based on the Committee's assessment of the Company's performance
in these regards. As benchmarks, the Committee compares the Company's overall
performance relative to other electric utilities of comparable size, the
compensation practices and programs of other companies that are most likely to
compete with the Company for services of executive officers, the Company's
strategic objectives, and the challenges it faces.
The Committee formulates annual salary ranges for officers by periodic
comparisons to rates of pay for comparable positions in other electric
utilities, as reported in the Edison Electric Institute's Executive Compensation
- 86 -
<PAGE>
Survey (the EEI Survey). Within the applicable range, each individual officer's
annual salary is then set at a level that will compensate the officer for
day-to-day performance, in the light of the officer's level of responsibility,
past performance, prior year's salary and bonus, and potential future
contributions to the Company's strategic objectives.
As described in detail above at "Executive Compensation," the Company's
annual incentive compensation program and its long-term incentive program have
somewhat different purposes. Under the annual Executive Incentive Compensation
Program, cash awards may be made each year to officers based on their
achievement of performance levels formulated by the Committee with respect to
(1) specific shareowner financial goals, (2) specific business unit goals, (3)
specific team/individual goals, and (4) a qualitative assessment of the
officers' performance as a group with respect to strategic opportunities of the
Company during that year, and based on such other factors as the Committee deems
relevant. The Company's Long-Term Incentive Program rewards officers for
achieving a return to shareowners over three-year periods of time. Under the
Long-Term Incentive Program that was replaced by the 1999 Stock Option Plan
approved by the shareowners last year, long-term incentive awards have been
linked to the total return to the shareholders compared to a peer group of
electric utilities. This program continues to provide strong incentives for
superior future performance under the three-year contingent performance share
awards granted in 1998; and it also encourages officers to continue serving UI,
because the earning of each incentive award is conditioned upon the officer's
continued service for the award's three-year performance period. Continued
service is also a key feature of the Company's 1999 Stock Option Plan. As
described above at "Executive Compensation," this plan provides officers with
incentives to contribute to the Company's success as measured by the market
value of its Common Stock. Except as otherwise provided in the plan, an officer
optionee may exercise a stock option only if he or she is, and has continuously
been since the date that the stock option was granted, a full-time employee of
the Company or one of its affiliates.
For 1999, the bonus opportunities of the Company's officers were targeted
by the Committee such that the combination of each officer's 1999 salary and
annual Executive Incentive Compensation Program award, assuming that
pre-established performance goals were met, would approximate, on average, the
50th percentile of compensation for comparable positions as reported in the 1998
EEI Survey. Goals were established to focus the officers' attention at the
corporate level on shareowner financial measures and at the business unit level
on a "balanced scorecard," covering business unit financial, operational,
customer and human resource measures. A prerequisite threshold level of
recurring earnings per share was specified in order for any bonus to be earned.
For 1999 the pre-established shareowner financial goals, accounting for 70% of
both the Chairman, President and Chief Executive Officer and the Vice Chairman
and Chief Financial Officer bonus awards and 40% of the business unit leaders'
bonus awards, included two measures: recurring earnings per share from
operations and recurring cash from operations available to pay down debt. For
each of the business unit leaders, 40% of the bonus award for 1999 was based on
the achievement of business unit "balanced scorecard" goals. The remaining 30%
of the Chairman, President and Chief Executive Officer and the Vice Chairman and
Chief Financial Officer bonus awards and 20% of the business unit leaders' bonus
awards for 1999 were based on the Committee's qualitative assessment of the
performance of the Company's officers as a group with respect to 1999 strategic
opportunities. For 1999, this assessment focused on the officers' achievements
in the implementation of the Company's vision, which is to position the Company
to be the premier regulated distribution utility to the regional community and
the leading value-added energy services supplier to the Company's specific
customers. The implementation plan was to include items such as: addressing the
issues of (i) sale of the non-nuclear generating assets, (ii) successful
commencement of retail access on January 1, 2000, (iii) Year-2000 rollover
without interruption of services or any major business system, (iv) formation of
a holding company, and (v) an investment in non-regulated businesses.
The officers' achievements with respect to 1999 pre-established shareowner
financial goals were especially strong: 150% of the recurring earnings per share
from operations goal and 150% of the recurring cash available to pay down debt
goal. Business unit leader achievements of business unit goals were likewise
strong, and ranged between 116% and 125% of the several business unit goals.
- 87 -
<PAGE>
Overall, the Committee's bonus awards for 1999 under the Executive
Incentive Compensation Program ranged between 133% and 163% of the
pre-established targeted awards, depending on the individual officer's
achievements, reflecting a strong performance by the Company's officers.
Long-term incentives, in recognition of the increasingly competitive
business environment for utilities, are based on a competitive blend of utility
and general industry award levels. It is the intention of the Committee to
transition, over a period of several years, to a 50%/50% blend of median utility
and general industry long-term incentive awards. The partial use of general
industry data recognizes the more competitive environment for utilities, and was
deemed by the Committee to be an important step toward ensuring the Company's
ability to continue attracting, retaining and motivating experienced executive
talent, given similar changes in the compensation programs at other utilities.
Under the Company's Long-Term Incentive Program, which is now the 1999
Stock Option Plan, a total of 132,000 Nonqualified Stock Options were awarded in
1999 to a total of 29 directors, officers and key employees of the Company. The
number of options granted to each officer in 1999 was based on a weighted blend
of 70% median utility and 30% general industry long-term award levels for
comparably-sized companies. Grants made in 2000 will be based on a weighted
blend of 60% median utility and 40% general industry competitive long-term
incentive data.
It is not expected that any compensation paid to an executive officer
during 2000 will become non-deductible under Internal Revenue Code Section
162(m) (the "million dollar pay cap").
CHIEF EXECUTIVE OFFICER COMPENSATION FOR 1999
In March of 1999, the Committee recommended, and the Board of Directors
approved, a 1999 annual salary of $412,000 for Mr. Woodson, as Chairman,
President and Chief Executive Officer of the Company. This annual salary was
between the median and the 75th percentile salary for this officership position
at other electric utilities of comparable size, as reported in the 1998 EEI
Survey, and below the 25th percentile of general industry sample for companies
of similar size. It was the Committee's judgment that the salary was appropriate
for an executive with the skills and abilities of Mr. Woodson to lead the
Company forward in the competitive business environment for utilities. Mr.
Woodson's bonus performance target for 1999 under the annual Executive Incentive
Compensation Program was set at $144,200, consisting of a prerequisite threshold
level of recurring earnings per share from operations goal and pre-established
goals with respect to recurring cash from operations available to pay down debt
and strategic opportunities, as detailed above. At the conclusion of 1999, the
Committee recommended, and the Board of Directors approved, a 1999 bonus award
of $220,000 to Mr. Woodson, representing 143% of his prorated targeted annual
performance bonus based on the achievements as described above and an additional
sum of $14,515 based on the Committee's judgment that Mr. Woodson's performance
during 1999 had been extraordinary.
The Committee's qualitative assessment of the performance of the officers
as a group with respect to strategic opportunities during 1999 was very positive
and, in the judgment of the Committee, reflected favorably on Mr. Woodson's
leadership.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
Thelma R. Albright, Chair
Marc C. Breslawsky
David E. A. Carson
F. Patrick McFadden, Jr.
Daniel J. Miglio
James A. Thomas
- 88 -
<PAGE>
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No director of the Company who served as a member of the Compensation and
Executive Development Committee during 1999 was, during 1999 or at any time
prior thereto, an officer or employee of the Company. During 1999, no director
of the Company was an executive officer of any other entity on whose Board of
Directors an executive officer of the Company served.
DIRECTOR COMPENSATION
Directors who are employees of the Company receive no compensation for
their service as directors of the Company.
The remuneration of non-employee directors of the Company includes an
annual retainer fee of $21,000, payable $9,000 for service during the first
quarter of the year and $4,000 each for service during the second, third and
fourth quarters of the year (the $9,000 retainer fee payable for service during
the first quarter of the year is payable in shares of the Company's Common Stock
or by credit to a stock account under the Non-Employee Directors' Common Stock
and Deferred Compensation Plan described below), plus a fee of $1,000 for each
meeting of the Board of Directors or committee of the Board of Directors
attended. Committee chairpersons receive an additional fee of $750 per quarter
year. Non-employee directors are also provided travel/accident insurance
coverage in the amount of $200,000.
The Company's Non-Employee Directors' Common Stock and Deferred
Compensation Plan (the Plan) has two features: a mandatory Common Stock feature;
and an optional Deferred Compensation feature. Each non-employee director has
two accounts in the Plan: a stock account for the accumulation of units that are
equivalent to shares of Common Stock (Stock Units), and on which amounts equal
to cash dividends on the shares of the Company's Common Stock represented by
Stock Units in the account accrue as additional Stock Units; and a cash account
for accumulation of the director's fees payable in cash that the director elects
to defer, and on which interest accrues at the prime rate in effect at the
beginning of each month at Citibank, N.A.
Under the Common Stock feature of the Plan, a credit of Stock Units to each
non-employee director's stock account in the Plan is made on or about the first
day of March in each year, unless the director elects to receive shares of
Common Stock in lieu of having an equivalent number of Stock Units credited to
his or her stock account. Each annual credit consists of a number of whole and
fractional Stock Units equal to the sum of 200 plus the quotient resulting from
dividing the retainer fee for the first quarter of the year by the market value
of Common Stock on the date of the credit.
Under the Deferred Compensation feature of the Plan, a non-employee
director may elect to defer receipt of all or part of (i) his or her retainer
fee for service during the second, third and fourth quarters of each year, (ii)
his or her committee chairperson fees, and/or (iii) his or her meeting fees,
which are payable in cash. All amounts deferred are credited when payable, at
the director's election, to either the director's cash account or to the
director's stock account (in a number of whole and fractional Stock Units based
on the market value of the Company's Common Stock on the date the fee is
payable) in the Plan.
All amounts credited to a non-employee director's cash account or stock
account in the Plan are at all times fully vested and nonforfeitable, and are
payable only upon termination of the director's service on the Board of
Directors. At that time, the cash account is payable in cash and the stock
account is payable in an equivalent number of shares of Common Stock or, at the
director's election, in cash based on the market value of an equivalent number
of shares of Common Stock.
Under the Company's 1999 Stock Option Plan described above, each
non-employee director was granted 4,500 stock options, with Reload Rights, on
March 22, 1999. These options are exercisable at the rate of one-third of the
- 89 -
<PAGE>
options on each of the first three anniversaries of the grant date, at an
exercise price per share of $43 7/32, which was the fair market value of the
Common Stock on March 22, 1999.
SHAREOWNER RETURN PRESENTATION
Set forth below is a line graph comparing the yearly change in the
Company's cumulative total shareowner return on its Common Stock with the
cumulative total return on the S&P Composite-500 Stock Index, the S&P Public
Utility Index and the S&P Electric Power Companies Index for the period of five
fiscal years commencing 1995 and ending 1999.
[GRAPH]
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
UIL $100 $134 $124 $190 $224 $236
S&P 500 100 138 169 226 290 351
S&P PUB. UTY. 100 142 147 183 210 191
S&P EL. CO. 100 131 131 165 191 154
* ASSUMES THAT THE VALUE OF THE INVESTMENT IN THE COMPANY'S COMMON STOCK AND
EACH INDEX WAS $100 ON DECEMBER 31, 1994 AND THAT ALL DIVIDENDS WERE
REINVESTED. FOR PURPOSES OF THIS GRAPH, THE YEARLY CHANGE IN CUMULATIVE
SHAREOWNER RETURN IS MEASURED BY DIVIDING (I) THE SUM OF (A) THE CUMULATIVE
AMOUNT OF DIVIDENDS FOR THE YEAR, ASSUMING DIVIDEND REINVESTMENT, AND (B) THE
DIFFERENCE IN THE FAIR MARKET VALUE AT THE END AND THE BEGINNING OF THE YEAR,
BY (II) THE FAIR MARKET VALUE AT THE BEGINNING OF THE YEAR. THE CHANGES
DISPLAYED ARE NOT NECESSARILY INDICATIVE OF FUTURE RETURNS MEASURED BY THIS
OR ANY METHOD.
- 90 -
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management.
PRINCIPAL SHAREOWNERS
In statements filed with the Securities and Exchange Commission, the
persons identified in the table below have disclosed beneficial ownership of
shares of common stock as shown in the table. The percentages shown in the
right-hand column are calculated based on the 14,334,922 shares of common stock
outstanding as of the close of business on January 18, 2000. In the statements
filed with the Securities and Exchange Commission, none of the persons
identified in the table, except David T. Chase, has admitted beneficial
ownership of any shares not held in their individual names. All of the persons
identified in the table, including David T. Chase, have denied that they have
acted, or are acting, as a partnership, limited partnership or syndicate, or as
a group of any kind for the purpose of acquiring, holding or disposing of common
stock.
AMOUNT AND NATURE
NAME AND ADDRESS OF BENEFICIAL
TITLE OF CLASS OF BENEFICIAL OWNER OWNERSHIP PERCENT OF CLASS
- -------------- ------------------- --------- ----------------
Common Stock Rhoda L. Chase 560,000 shares, 3.91%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock Cheryl A. Chase 79,200 shares, 0.55%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock Arnold L. Chase 230,300 shares, 1.61%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock The Darland Trust 146,000 shares, 1.02%
St. Peter's House, owned directly
Le Bordage
St. Peter Port
Guernsey GY16AX
Channel Islands(1)
Common Stock David T. Chase 1,010,000 shares 7.05%
One Commercial Plaza owned indirectly(2)
Hartford, CT 06103
Common Stock DTC Holdings Corporation(3) 210,000 shares 1.46%
One Commercial Plaza owned directly
Hartford, CT 06103
- ---------------------------
(1) The Darland Trust is a trust for the benefit of Cheryl A.. Chase and her
children. The trustee of this trust is Rothschild Trust Cayman Limited.
(2) All of the shares listed for David T. Chase are included in the shares
listed for Rhoda L. Chase, his wife, Cheryl A. Chase, his daughter, Arnold
L. Chase, his son, and The Darland Trust.
- 91 -
<PAGE>
(3) DTC Holdings Corporation was formerly known as American Ranger, Inc. It is
a wholly-owned subsidiary of D.T. Chase Enterprises, Inc. and is indirectly
owned and controlled by David T. Chase, Rhoda L. Chase, Cheryl A. Chase,
Arnold L. Chase, trusts for the benefit of Arnold L. Chase and his
children, and trusts for the benefit of Cheryl A. Chase and her children.
D.T. Chase Enterprises, Inc. has its address at One Commercial Plaza,
Hartford, CT 06103.
STOCK OWNERSHIP OF DIRECTORS AND OFFICERS
The following table indicates the number of shares of common stock
beneficially owned, directly or indirectly, as of January 31, 2000, by each
Company director, by the person who served as the Chief Executive Officer of the
Company during 1999, and by each of the four other most highly compensated
officers of the Company during 1999, and by all directors and officers of the
Company as a group.
SHARES
NAME OF INDIVIDUAL OR BENEFICIALLY
NUMBER OF PERSONS IN OWNED DIRECTLY
GROUP OR INDIRECTLY
----------------------------------------------------------
Thelma R. Albright 4,095
Marc C. Breslawsky 5,648
David E.A. Carson 9,833
Arnold L. Chase 230,300
John F. Croweak 3,834
Robert L. Fiscus 34,257
Betsy Henley-Cohn 3,993
John L. Lahey 2,477
F. Patrick McFadden, Jr. 4,149
Daniel J. Miglio 3,000
Frank R. O'Keefe, Jr. 5,327
James A. Thomas 2,363
Nathaniel D. Woodson 12,216
James F. Crowe 7,027
Albert N. Henricksen 3,147
Anthony J. Vallillo 2,430
20 Directors and Officers as a
group, including those named above 349,318
The number of shares listed in the table above includes those held for the
benefit of officers that are participating in the Company's Employee Stock
Ownership Plan and, in the cases of Robert L. Fiscus, 10,500 shares, and, in the
case of all directors and officers as a group, 16,300 shares, that may be
acquired currently through the exercise of stock options under the Company's
1990 Stock Option Plan.
The numbers in the above table are based on reports furnished by the
directors and officers. The shares reported for Mr. Chase do not include shares
held by other members of his family and entities owned by them, which are
described at "Principal Shareowners" above. Mr. Chase does not admit beneficial
ownership of any shares other than those shown in the foregoing table, and he
has denied that he has acted, or is acting, as a member of a partnership,
limited partnership or syndicate, or group of any kind for the purpose of
acquiring, holding or disposing of the Company's Common Stock. With respect to
other directors and officers, the shares reported in the foregoing table
include, in some instances, shares held by the immediate families of directors
and officers or entities controlled by directors and officers, the reporting of
which is not to be construed as an admission of beneficial ownership.
- 92 -
<PAGE>
Each of the persons included in the above table has sole voting and
investment power as to the shares of Common Stock beneficially owned, directly
or indirectly, by him or her, except as described below:
o each person listed below shares investment and voting power for the
number of shares listed opposite his or her name below with his or her
spouse:
NAME NUMBER OF SHARES
---- ----------------
James F. Crowe 751
Albert N. Henricksen 449
All directors and officers
as a group 1,392
o voting and investment power is held by the other people or entities
described below on behalf of the persons included in the above table
with respect to the number of shares listed opposite their respective
names below:
NAME OF OTHER PERSON OR
ENTITY HOLDING VOTING
NAME NUMBER OF SHARES AND INVESTMENT POWER
---- ---------------- ---------------------
David E.A. Carson 159 Spouse
Robert L. Fiscus 700 Trust
Betsy Henley-Cohn 2,035 Trust
Frank R. O'Keefe, Jr. 669 Trust
Nathaniel D. Woodson 12,000 Trust
James F. Crowe 10 Child
All directors and officers
as a group 15,806 Spouse, Trust or Child
The number of shares listed in the stock ownership table above also
includes the number of stock units listed opposite each person's name below, for
which neither investment nor voting power is held:
NAME NUMBER OF SHARES
---- ----------------
Thelma R. Albright 3,857
Marc C. Breslawsky 5,548
David E.A. Carson 8,853
John F. Croweak 2,917
Betsy Henley-Cohn 425
John L. Lahey 239
F. Patrick McFadden, Jr. 2,215
Frank R. O'Keefe, Jr. 4,418
James A. Thomas 825
These stock units are in stock accounts under the Company's Non-Employee
Directors' Common Stock and Deferred Compensation Plan, described at "Director
Compensation." Stock units in this plan are payable, in an equivalent number of
shares of the Company's Common Stock, upon termination of service on the Board
of Directors.
The number of shares of Common Stock beneficially owned by Mr. Chase, as
listed in the above stock ownership table, is approximately 1.6% of the
14,334,922 shares of common stock outstanding as of January 18, 2000. The number
of shares of Common Stock beneficially owned by each of the other persons
included in th
- 93 -
<PAGE>
foregoing table is less than 1% of the outstanding shares of common stock as of
January 31, 2000; and the number of shares of Common Stock beneficially owned by
all of the directors, and officers as a group represents approximately 2.4% of
the outstanding shares of Common Stock as of January 31, 2000.
Item 13. Certain Relationships and Related Transactions.
Under a lease agreement dated May 7, 1991, the Company leased its
corporate headquarters offices in New Haven from Connecticut Financial Center
Associates Limited Partnership (CFCALP). CFCALP is a limited partnership
controlled by the David T. Chase family, including Arnold L. Chase, a Director
of the Company since June 28, 1999, and members of his immediate family. During
1999, the Company's lease payments to CFCALP totaled $6,162,000.
A subsidiary of the Company, United Capital Investments, Inc. (UCI),
intends to purchase, for $3,750,000, a minority ownership interest in a
newly-formed corporation, Gemini-United, Inc. (GUI), that proposes to develop,
build and operate an open-access, hybrid fiber coaxial communications network
serving business and residential customers located in the Company's franchised
service area. UCI also intends to provide marketing, management of system
customer base, and network deployment and maintenance consulting services to
GUI, for an annual fee of $70,000, for a period of five years, subject to early
termination in certain limited circumstances. The majority owner of GUI is
Gemini Networks, Inc., a corporation controlled by the David T. Chase family;
and Arnold L. Chase is the Chairman of the Board of Directors of GUI and the
President and a Director of Gemini Networks, Inc.
Since January 1, 1999, there has been no other transaction, relationship or
indebtedness of the kinds described in Item 404 of Regulation S-K.
- 94 -
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
Financial Statements (see Item 8):
Consolidated statement of income for the years ended December 31, 1999,
1998 and 1997
Consolidated statement of cash flows for the years ended December 31,
1999, 1998 and 1997
Consolidated balance sheet, December 31, 1999 and 1998
Consolidated statement of changes in shareholders' equity for the years
ended December 31, 1999, 1998 and 1997
Notes to consolidated financial statements
Report of independent accountants
Financial Statement Schedule (see S-1)
Schedule II - Valuation and qualifying accounts for the years ended
December 31, 1999, 1998 and 1997.
- 95 -
<PAGE>
Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain
of the following listed exhibits, which are annexed as exhibits to previous
statements and reports filed by the Company, are hereby incorporated by
reference as exhibits to this report. Such statements and reports are identified
by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1996.
(4) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1997.
(5) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1998.
(6) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1999.
(7) Filed with Registration Statement No. 33-40169, effective August 12, 1991.
(8) Filed with Registration Statement No. 33-35465, effective August 1, 1990.
(9) Filed with Amendment No. 1 to Registration Statement No. 33-55461,
effective October 31, 1994.
(10) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1995.
(11) Filed with Registration Statement No. 2-57275, effective October 19, 1976.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(13) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1996.
(14) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(15) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991.
(16) Filed with Registration Statement No. 2-54876, effective November 19, 1975.
(17) Filed with Registration Statement No. 2-66518, effective February 25, 1980.
(18) Filed with Registration Statement No. 2-52657, effective February 6, 1975.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1997.
(20) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1997.
(21) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1998.
(22) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1997.
(23) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1998.
(24) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1999.
(25) Filed March 29, 1996, with proxy material for the Annual Meeting of the
Shareowners.
- 96 -
<PAGE>
The exhibit number in the statement or report referenced is set forth in
the parenthesis following the description of the exhibit. Those of the following
exhibits not so identified are filed herewith.
<TABLE>
<CAPTION>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- ------- ------- --------- -----------
<S> <C> <C> <C>
(3) 3.1a (1) Copy of Restated Certificate of Incorporation of The United Illuminating Company, dated January
23, 1995. (Exhibit 3.1)
(3) 3.1b (2) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
August 4, 1995. (Exhibit 3.1b)
(3) 3.1c (3) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
July 16, 1996. (Exhibit 3.1c)
(3) 3.1d (4) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
December 11, 1996. (Exhibit 3.1d)
(3) 3.1e (5) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors and
Shareholders, dated May 28, 1998. (Exhibit 3.1d)
(3) 3.2 (6) Copy of Bylaws of The United Illuminating Company. (Exhibit 3.2c)
(4) 4.1 (7) Copy of Indenture, dated as of August 1, 1991, from The United Illuminating Company to The Bank
of New York, Trustee. (Exhibit 4)
(4),(10) 4.2 (8) Copy of Participation Agreement, dated as of August 1, 1990, among Financial Leasing
Corporation, Meridian Trust Company, The Bank of New York and The United Illuminating
Company. (Exhibits 4(a) through 4(h), inclusive, Amendment Nos. 1 and 2).
(4) 4.3a (9) Copy of form of Amended and Restated Agreement of Limited Partnership of United Capital Funding
Partnership L.P. (Exhibit 4(c))
(4) 4.3b (10) Copy of Action of The United Illuminating Company, as General Partner of United Capital Funding
Partnership L.P., relating to the 9 5/8% Preferred Capital Securities, Series A, of United
Capital Funding Partnership L.P. (Exhibit 4(b))
(4) 4.3c (9) Copy of form of Indenture, dated as of April 1, 1995, from The United Illuminating Company to
The Bank of New York, as Trustee. (Exhibit 4(e))
(4) 4.3d (10) Copy of First Supplemental Indenture, dated as of April 1, 1995, between The United Illuminating
Company and The Bank of New York, Trustee, supplementing Exhibit 4.3c. (Exhibit 4(d))
(4) 4.3e (9) Copy of form of Payment and Guarantee Agreement of The United Illuminating Company, dated as of
April 1, 1995. (Exhibit 4(j))
(10) 10.1 (11) Copy of Stockholder Agreement, dated as of July 1, 1964, among the various stockholders of
Connecticut Yankee Atomic Power Company, including The United Illuminating Company. (Exhibit
5.1-1)
(10) 10.2a (11) Copy of Power Contract, dated as of July 1, 1964, between Connecticut Yankee Atomic Power
Company and The United Illuminating Company. (Exhibit 5.1-2)
(10) 10.2b (12) Copy of Additional Power Contract, dated as of April 30, 1984, between Connecticut Yankee Atomic
Power Company and The United Illuminating Company.
(10) 10.2c (13) Copy of 1987 Supplementary Power Contract, dated as of April 1, 1987, supplementing Exhibits
10.2a and 10.2b. (Exhibit 10.2c)
(10) 10.2d (13) Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending Exhibits 10.2b and
10.2c. (Exhibit 10.2d)
(10) 10.2e (13) Copy of First Supplement to 1996 Amendatory Agreement, dated as of February 10, 1997,
supplementing Exhibit 10.2d. (Exhibit 10.2e)
</TABLE>
- 97 -
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- ------- ------- --------- -----------
<S> <C> <C> <C>
(10) 10.3 (11) Copy of Capital Funds Agreement, dated as of September 1, 1964, between Connecticut Yankee
Atomic Power Company and The United Illuminating Company. (Exhibit 5.1-3)
(10) 10.4 (14) Copy of Capital Contributions Agreement, dated October 16, 1967, between The United Illuminating
Company and Connecticut Yankee Atomic Power Company. (Exhibit 5.1-5)
(10) 10.5 Copy of Restated New England Power Pool Agreement, as amended to March 1, 2000.
(10) 10.6a (15) Copy of Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear
Units, dated May 1, 1973, as amended to February 1, 1990. (Exhibit 10.7a)
(10) 10.6b (16) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the Seabrook Companies.
(Exhibit 5.9-2)
(10) 10.6c (13) Copy of Twenty-third Amendment to Agreement for Joint Ownership, Construction and Operation of
New Hampshire Nuclear Units, dated as of November 1, 1990, amending Exhibit 10.6a. (Exhibit
10.7c)
(10) 10.7a (17) Copy of Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of September 1, 1973, among
The Connecticut Light and Power Company, The Hartford Electric Light Company, Western
Massachusetts Electric Company, New England Power Company, The United Illuminating Company,
Public Service Company of New Hampshire, Central Vermont Public Service Company, Montaup
Electric Company and Fitchburg Gas and Electric Light Company, relating to a nuclear fueled
generating unit in Connecticut. (Exhibit 5.8-1)
(10) 10.7b (18) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of August 1,
1974, amending Exhibit 10.7a. (Exhibit 5.9-2)
(10) 10.7c (11) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of December 15,
1975, amending Exhibit 10.7a. (Exhibit 5.8-4, Post-effective Amendment No. 2)
(10) 10.8a (14) Copy of Transmission Line Agreement, dated January 13, 1966, between the Trustees of the
Property of The New York, New Haven and Hartford Railroad Company and The United Illuminating
Company. (Exhibit 5.4)
(10) 10.8b (15) Notice, dated April 24, 1978, of The United Illuminating Company's intention to extend term of
Transmission Line Agreement dated January 13, 1966, Exhibit 10.8a. (Exhibit 10.9b)
(10) 10.8c (15) Copy of Letter Agreement, dated March 28, 1985, between The United Illuminating Company and
National Railroad Passenger Corporation, supplementing and modifying Exhibit 10.8a. (Exhibit
10.9c)
(10) 10.8d (19) Copy of Notice, dated April 22, 1997, of The United Illuminating Company's intention to extend
term of Transmission Line Agreement, Exhibit 10.9a, as supplemented and modified by Exhibit
10.8c. (Exhibit 10.9d)
(10) 10.9a (20) Copy of Agreement, effective May 16, 1997, between The United Illuminating Company and Local
470-1, Utility Workers Union of America, AFL-CIO. (Exhibit 10.10)
(10) 10.9b (21) Copy of Memorandum of Agreement, dated January 27, 1999, between The United Illuminating Company
and Local 470-1, Utility Workers Union of America, AFL-CIO.
</TABLE>
- 98 -
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- ------- ------- --------- -----------
<S> <C> <C> <C>
(10) 10.9c Copy of Memorandum of Agreement, dated March 5, 1999, between The United Illuminating Company
and Local 470-1, Utility Workers Union of America, AFL-CIO.
(10) 10.12a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The
United Illuminating Company and Robert L. Fiscus. (Exhibit 10.23)
(10) 10.12b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Robert L. Fiscus, dated as of February 1, 1998, amending Exhibit
10.12a. (Exhibit 10.14a)
(10) 10.13a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The
United Illuminating Company and James F. Crowe. (Exhibit 10.24)
(10) 10.13b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and James F. Crowe, dated as of February 1, 1998, amending Exhibit
10.13a. (Exhibit 10.15a)
(10) 10.14a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Albert N. Henricksen. (Exhibit 10.25)
(10) 10.14b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Albert N. Henricksen, dated as of February 1, 1998, amending Exhibit
10.14a. (Exhibit 10.16a)
(10) 10.15a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Anthony J. Vallillo. (Exhibit 10.26)
(10) 10.15b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Anthony J. Vallillo, dated as of February 1, 1998, amending Exhibit
10.15a. (Exhibit 10.17a)
(10) 10.16a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Rita L. Bowlby. (Exhibit 10.27)
(10) 10.16b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Rita L. Bowlby, dated as of December 13, 1999.
(10) 10.17a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Stephen F. Goldschmidt. (Exhibit 10.28)
(10) 10.17b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Stephen F. Goldschmidt, dated as of May 5, 1999.
(10) 10.18* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and James L. Benjamin. (Exhibit 10.29)
(10) 10.19a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Charles J. Pepe. (Exhibit 10.31)
(10) 10.19b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Charles J. Pepe, dated as of December 13, 1999.
(10) 10.20a* (23) Copy of Employment Agreement, dated as of February 23, 1998, between The United Illuminating
Company and Nathaniel D. Woodson. (Exhibit 10.28)
(10) 10.20b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Nathaniel D. Woodson, dated as of December 13, 1999.
(10) 10.21* (23) Copy of The United Illuminating Company Phantom Stock Option Agreement, dated as of February 23,
1998, between The United Illuminating Company and Nathaniel D. Woodson. (Exhibit 10.29)
(10) 10.22* (15) Copy of Executive Incentive Compensation Program of The United Illuminating Company. (Exhibit
10.24)
</TABLE>
- 99 -
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- ------- ------- --------- -----------
<S> <C> <C> <C>
(10) 10.23* (13) Copy of The United Illuminating Company 1990 Stock Option Plan, as amended on December 20, 1993,
January 24, 1994 and August 22, 1994.
(10) 10.24* (24) Copy of The United Illuminating Company 1999 Stock Option Plan. (Exhibit 10.29)
(10) 10.25a* (25) Copy of Non-Employee Directors' Common Stock and Deferred Compensation Plan of The United
Illuminating Company.
(10) 10.25b* Copy of Resolution adopted by the Board of Directors of The United Illuminating Company on
December 13, 1999, amending Subsection 6.01(b) of the Non-Employee Directors' Common Stock and
Deferred Compensation Plan.
(10) 10.27* (3) Copy of The United Illuminating Company 1996 Long-Term Incentive Program. (Exhibit 10.21)
(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 December 31, 1999, 1998,
1997, 1996 and 1995).
(21) 21 List of subsidiaries of The United Illuminating Company.
(27) 27 Financial Data Schedule
(28) 28.1 Copies of significant rate schedules of The United Illuminating Company.
</TABLE>
- ---------------------------
*Management contract or compensatory plan or arrangement.
- 100 -
<PAGE>
The foregoing list of exhibits does not include instruments defining the
rights of the holders of certain long-term debt of the Company and its
subsidiaries where the total amount of securities authorized to be issued under
the instrument does not exceed ten (10%) of the total assets of the Company and
its subsidiaries on a consolidated basis; and the Company hereby agrees to
furnish a copy of each such instrument to the Securities and Exchange Commission
on request.
(b) Reports on Form 8-K.
None
- 101 -
<PAGE>
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 33-50221 and
No. 33-64003) of our report dated January 24, 2000 relating to the financial
statements and financial statement schedule appearing in The United Illuminating
Company's Annual Report on Form 10-K for the year ended December 31, 1999.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 102 -
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the Company has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson
------------------------------
Nathaniel D. Woodson
Chairman of the Board of Directors,
President and Chief Executive Officer
DATE: MARCH 10, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
Director, Chairman of the
Board of Directors and
/s/ Nathaniel D. Woodson Chief Executive Officer March 10, 2000
- -------------------------------------
(Nathaniel D. Woodson)
(Principal Executive Officer)
Director, Vice Chairman of the
Board of Directors, Chief Financial
/s/ Robert L. Fiscus Officer, Treasurer and Secretary March 10, 2000
- -------------------------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
/s/ John F. Croweak Director March 10, 2000
- -------------------------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director March 10, 2000
- -------------------------------------
(F. Patrick McFadden, Jr.)
/s/ Betsy Henley-Cohn Director March 10, 2000
- -------------------------------------
(Betsy Henley-Cohn)
/s/Frank R. O'Keefe, Jr. Director March 10, 2000
- -------------------------------------
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director March 10, 2000
- -------------------------------------
(James A. Thomas)
/s/ David E.A. Carson Director March 10, 2000
- -------------------------------------
(David E.A. Carson)
/s/ John L. Lahey Director March 10, 2000
- -------------------------------------
(John L. Lahey)
/s/ Marc C. Breslawsky Director March 10, 2000
- -------------------------------------
(Marc C. Breslawsky)
/s/ Thelma R. Albright Director March 10, 2000
- -------------------------------------
(Thelma R. Albright)
/s/ Arnold L. Chase Director March 10, 2000
- -------------------------------------
(Arnold L. Chase)
/s/ Daniel J. Miglio Director March 10, 2000
- -------------------------------------
(Daniel J. Miglio)
</TABLE>
- 103 -
<PAGE>
<TABLE>
SCHEDULE II
VALUATION AND
QUALIFYING ACCOUNTS
THE UNITED ILLUMINATING COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999 AND 1998
(Thousands of Dollars)
<CAPTION>
COL. A COL. B COL. C COL. D COL. E
------ ------ ------ ------ ------
ADDITIONS
-------------------------------
BALANCE AT CHARGED TO CHARGED BALANCE AT
BEGINNING COSTS AND TO OTHER END OF
CLASSIFICATION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
-------------- ---------- ---------- -------- ---------- ------
<S> <C> <C> <C> <C> <C> <C>
RESERVE DEDUCTION FROM
ASSET TO WHICH IT APPLIES:
Reserve for uncollectible
accounts (consolidated):
1999 $2,431 $4,772 - $4,895 (A) $2,308
1998 $7,197 $5,745 - $10,511 (A) $2,431
Reserve for uncollectible
accounts (American
Payment Systems,
agent collections (B))
1999 $545 ($498) - ($123)(A) $170
1998 $5,392 $361 - $5,208 (A) $545
</TABLE>
- ------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
(B) Included in consolidated amounts above.
S-1
EXHIBIT 10.5
ATTACHMENT 2
SECOND COMPOSITE
RESTATED
NEW ENGLAND
POWER POOL AGREEMENT
(As amended through the Fifty-First Agreement
Amending New England Power Pool Agreement)
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 1
TABLE OF CONTENTS
PART ONE
INTRODUCTION........................................................12
SECTION 1
DEFINITIONS.........................................................12
1.1 Adjusted Load..............................................13
1.2 Adjusted Monthly Peak......................................13
1.3 Adjusted Net Interchange...................................13
1.3A Administrative Procedures..................................14
1.4 AGC Capability.............................................14
1.5 AGC Entitlement............................................14
1.6 Agreement..................................................15
1.7 Annual Transmission Revenue Requirements...................15
1.8 Automatic Generation Control or AGC........................15
1.8A Balloting Agent............................................16
1.9 Bid Price..................................................16
1.10 Commission.................................................16
1.11 Control Area...............................................17
1.12 Curtailment................................................18
1.13 Direct Assignment Facilities...............................18
1.14 Dispatch Price.............................................18
1.15 EHV PTF....................................................19
1.16 Electrical Load............................................19
1.17 Eligible Customer..........................................20
1.17A End User Participant.......................................21
1.18 Energy.....................................................21
1.19 Energy Entitlement.........................................21
1.20 Entitlement................................................22
1.21 Entity.....................................................22
1.22 Excepted Transaction.......................................23
1.23 [Deleted.].................................................23
1.24 Facilities Study...........................................23
1.25 Firm Contract..............................................24
1.26 First Effective Date.......................................24
1.27 Good Utility Practice......................................24
1.28 HQ Contracts...............................................25
1.29 HQ Energy Banking Agreement................................25
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 2
1.30 HQ Interconnection.........................................25
1.31 HQ Interconnection Agreement...............................26
1.32 HQ Interconnection Capability Credit.......................26
1.33 HQ Interconnection Transfer Capability.....................27
1.34 HQ Net Interconnection Capability Credit...................28
1.35 HQ Phase I Energy Contract.................................28
1.36 HQ Phase I Percentage......................................28
1.37 HQ Phase I Transfer Credit.................................28
1.38 HQ Phase II Firm Energy Contract...........................29
1.39 HQ Phase II Gross Transfer Responsibility..................29
1.40 HQ Phase II Net Transfer Responsibility....................29
1.41 HQ Phase II Percentage.....................................30
1.42 HQ Phase II Transfer Credit................................30
1.43 HQ Use Agreement...........................................30
1.44 Installed Capability.......................................30
1.45 Installed Capability Entitlement...........................31
1.46 Installed Capability Responsibility........ ..............31
1.47 Installed System Capability................................31
1.48 Interchange Transactions...................................32
1.49 Internal Point-to-Point Service............................32
1.50 Interruption...............................................32
1.51 ISO........................................................32
1.52 Kilowatt...................................................33
1.52A Liaison Committee..........................................33
1.53 Load.......................................................33
1.54 Local Network..............................................35
1.55 Local Network Service......................................35
1.56 Lower Voltage PTF..........................................35
1.57 Market Products............................................35
1.57A Market Rules...............................................36
1.58 [Deleted.].................................................36
1.58A Markets Committee..........................................36
1.59 Monthly Peak...............................................36
1.60 NEPOOL.....................................................36
1.61 NEPOOL Control Area........................................37
1.62 NEPOOL Installed Capability................................38
1.63 NEPOOL Installed Capability Responsibility.................38
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 3
1.64 NEPOOL Objective Capability................................38
1.64A NEPOOL Market..............................................38
1.64B NEPOOL System Rules........................................39
1.64C NERC.......................................................39
1.65 New Unit...................................................39
1.66 Non-Participant............................................39
1.66A NPCC.......................................................39
1.66B OASIS......................................................39
1.67 Operable Capability........................................40
1.68 [Deleted]..................................................40
1.69 [Deleted]. ................................................40
1.70 [Deleted]. ................................................40
1.71 Operating Reserve..........................................40
1.72 Operating Reserve Entitlement..............................40
1.73 Other HQ Energy............................................41
1.74 Participant................................................41
1.74A Participants Committee.....................................42
1.75 Pool-Planned Facility......................................42
1.76 Pool-Planned Unit..........................................42
1.77 Power Year.................................................42
1.78 Prior NEPOOL Agreement.....................................43
1.79 Proxy Unit.................................................43
1.80 PTF........................................................43
1.80A Publicly Owned Entity......................................43
1.81 [Deleted.].................................................44
1.82 Regional Network Service...................................44
1.83 [Deleted.].................................................44
1.84 [Deleted.].................................................44
1.85 Related Person.............................................44
1.85A Reliability Committee......................................45
1.85B Reliability Standards......................................45
1.85C Review Board...............................................45
1.86 Scheduled Dispatch Period..................................46
1.87 Second Effective Date......................................46
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 4
1.87A Sector.....................................................46
1.88 Service Agreement..........................................46
1.89 Summer Capability..........................................46
1.90 Summer Period..............................................47
1.91 System Contract............................................47
1.92 System Impact Study........................................47
1.93 System Operator............................................48
1.94 Target Availability Rate...................................48
1.95 Tariff.....................................................48
1.95A Tariff Committee...........................................48
1.95B Technical Committees.......................................49
1.96 Third Effective Date.......................................49
1.97 Through or Out Service.....................................49
1.98 Transition Period..........................................49
1.99 Transmission Customer......................................50
1.99A Transmission Owner.........................................50
1.99B Transmission Owners Committee..............................51
1.100 Transmission Provider......................................51
1.101 Unit Contract..............................................51
1.102 [Deleted.].................................................52
1.103 Winter Capability..........................................52
1.104 Winter Period..............................................52
1.105 10-Minute Spinning Reserve.................................52
1.106 10-Minute Non-Spinning Reserve.............................53
1.107 30-Minute Operating Reserve................................54
1.108 [Deleted.].................................................55
1.109 Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another
Participant Pursuant to Firm Contract......................55
SECTION 2 - PURPOSE; EFFECTIVE DATES.........................................58
2.1 Purpose....................................................58
2.2 Effective Dates; Transitional Provisions...................59
SECTION 3 - MEMBERSHIP.......................................................60
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 5
3.1 Membership.................................................60
3.2 Operations Outside the Control Area........................61
3.3 Lack of Place of Business in New England...................62
3.4 Obligation for Deferred Expenses...........................63
3.5 Financial Security.........................................63
SECTION 4 - STATUS OF PARTICIPANTS...........................................64
4.1 Treatment of Certain Entities as Single Participant........64
4.2 Participants to Retain Separate Identities.................65
SECTION 5 - NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS................65
5.1 NEPOOL Objectives..........................................65
5.2 Cooperation by Participants................................67
PART TWO - GOVERNANCE........................................................68
SECTION 6 - COMMITTEE ORGANIZATION AND VOTING................................68
6.1 Principal Committees.......................................68
6.2 Sector Representation......................................69
6.3 Appointment of Members and Alternates......................77
6.4 Term of Members............................................78
6.5 Regular and Special Meetings...............................78
6.6 Notice of Meetings.........................................79
6.7 Attendance.................................................79
6.8 Quorum.....................................................80
6.9 Voting Definitions.........................................80
6.10 Voting On Proposed Actions.................................84
6.11 Voting On Amendments.......................................84
6.12 Designated Representatives and Proxies.....................88
6.13 Limits on Representatives..................................89
6.14 Adoption of Bylaws.........................................89
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 6
6.15 Joint Meetings of Technical Committees.....................90
SECTION 7 - PARTICIPANTS COMMITTEE...........................................91
7.1 Officers...................................................91
7.2 Adoption of Budgets........................................91
7.3 Establishing Reliability Standards.........................91
7.4 Appointment and Compensation of NEPOOL Personnel...........92
7.5 Duties and Authority.......................................92
7.6 Attendance of Participants at Committee Meeting............99
7.7 Appeal of Actions to Review Board..........................99
SECTION 8 - RELIABILITY COMMITTEE...........................................101
8.1 Officers..................................................101
8.2 Notice to Members and Alternates of Participants
Committee.................................................102
8.3 Voting; Appeal of Actions.................................102
8.4 Responsibilities..........................................103
8.5 Establishment of Subcommittees and Task Forces............108
8.6 Further Powers and Duties.................................109
SECTION 9 - TARIFF COMMITTEE................................................109
9.1 Officers..................................................109
9.2 Notice to Members and Alternates of Participants
Committee.................................................110
9.3 Voting; Appeal of Actions.................................110
9.4 Responsibilities..........................................111
9.5 Establishment of Subcommittees and Task Forces............112
9.6 Further Powers and Duties.................................113
SECTION 10 - MARKETS COMMITTEE..............................................113
10.1 Officers..................................................113
10.2 Notice to Members and Alternates of Participants
Committee.................................................114
10.3 Voting; Appeal of Actions.................................114
10.4 Responsibilities..........................................115
10.5 Establishment of Subcommittees and Task Forces............118
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 7
10.6 Further Powers and Duties.................................118
10.7 Development of Rules Relating to Non-Participant
Supply and Demand-side Resources..........................118
SECTION 11 - FURTHER RESTRUCTURING..........................................119
SECTION 11A - REVIEW BOARD..................................................120
11A.1 Organization..............................................120
11A.2 Composition...............................................121
11A.3 Qualifications............................................122
11A.4 Term......................................................123
11A.5 Meetings..................................................123
11A.6 Bylaws....................................................123
11A.7 Procedure on Appeal of Participant Committee Action
or Failure to Take Action.................................124
11A.8 Effect of a Review Board Decision.........................127
SECTION 11B - TRANSMISSION OWNERS COMMITTEE.................................129
11B.1 Organization..............................................129
11B.2 Membership................................................130
11B.3 Appointment of Members and Alternates.....................130
11B.4 Term of Members...........................................130
11B.5 Regular and Special Meetings..............................131
11B.6 Notice of Meetings........................................131
11B.7 Attendance................................................131
11B.8 Votes.....................................................132
11B.9 Appointment of Task Forces or Working Groups..............133
11B.10 Officers....................................................133
11B.11 Adoption of Bylaws..........................................133
11B.12 Review of Committee Actions.................................134
SECTION 11C - LIAISON COMMITTEE.............................................135
11C.1 Organization; Duties......................................135
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 8
11C.2 Membership................................................135
11C.3 Regular and Special Meetings..............................136
11C.4 Notice of Meetings........................................136
11C.5 Attendance................................................136
11C.6 Officers..................................................137
PART THREE - MARKET PROVISIONS..............................................138
SECTION 12 - INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS..................138
12.1 Obligations to Provide Installed Capability...............138
12.2 Computation of Installed Capability Responsibilities......138
12.3 [Deleted].................................................159
12.4 Bids to Furnish Installed Capability......................159
12.5 Consequences of Deficiencies in Installed Capability
Responsibility............................................160
12.6 [Deleted].................................................162
12.7 Payments to Participants Furnishing Installed Capability..162
SECTION 13 - OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE
CONTRACTS......................................................164
13.1 Maintenance and Operation in Accordance with Good
Utility Practice..........................................164
13.2 Central Dispatch..........................................164
13.3 Maintenance and Repair....................................165
13.4 Objectives of Day-to-Day System Operation.................165
13.5 Satellite Membership......................................166
SECTION 14 - INTERCHANGE TRANSACTIONS.......................................167
14.1 Obligation for Energy, Operating Reserve and Automatic
Generation Control........................................167
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 9
14.2 Obligation to Bid or Schedule, and Right to Receive
Energy, Operating Reserve and Automatic Generation
Control...................................................170
14.3 Amount of Energy, Operating Reserve and Automatic
Generation Control Received or Furnished..................176
14.4 Payments by Participants Receiving Energy Service,
Operating Reserve and Automatic Generation Control........179
14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control.......181
14.6 Energy Transactions with Non-Participants.................184
14.7 Participant Purchases Pursuant to Firm Contracts and
System Contracts..........................................187
14.8 Determination of Energy Clearing Price....................188
14.9 Determination of Operating Reserve Clearing Price.........189
14.10 Determination of AGC Clearing Price.......................192
14.11 Funds to or from which Payments are to be Made............193
14.12 Development of Rules Relating to Nuclear and
Hydroelectric Generating Facilities, Limited-Fuel
Generating Facilities, and Interruptible Loads............201
14.13 Dispatch and Billing Rules During Energy Shortages........202
14.14 Congestion Uplift.........................................203
14.15 Additional Uplift Charges. ..............................207
PART FOUR - TRANSMISSION PROVISIONS.........................................208
SECTION 15 - OPERATION OF TRANSMISSION FACILITIES...........................208
15.1 Definition of PTF.........................................208
15.2 Maintenance and Operation in Accordance with Good
Utility Practice..........................................213
15.3 Central Dispatch..........................................213
15.4 Maintenance and Repair....................................214
15.5 Additions to or Upgrades of PTF...........................214
SECTION 16 - SERVICE UNDER TARIFF...........................................217
16.1 Effect of Tariff..........................................217
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 10
16.2 Obligation to Provide Regional Service....................217
16.3 Obligation to Provide Local Network Service...............218
16.4 Transmission Service Availability.........................221
16.5 Transmission Information..................................222
16.6 Distribution of Transmission Revenues.....................222
SECTION 17 - POOL-PLANNED UNIT SERVICE......................................226
17.1 Effective Period..........................................226
17.2 Obligation to Provide Service.............................226
17.3 Rules for Determination of Facilities Covered by
Particular Transactions...................................227
17.4 Payments for Uses of EHV PTF During the Transition Period.229
17.5 Payments for Uses of Lower Voltage PTF....................233
17.6 Use of Other Transmission Facilities by Participants......234
17.7 Limits on Individual Transmission Charges.................235
SECTION 17A - TRANSMISSION OWNERS RESERVED RIGHTS...........................235
17A.1 ..........................................................236
17A.2 ..........................................................236
17A.3 ..........................................................237
17A.4 ..........................................................237
17A.5 ..........................................................238
17A.6 ..........................................................238
17A.7 ..........................................................238
17A.8 ..........................................................239
PART FIVE - GENERAL.........................................................241
SECTION 18 - GENERATION AND TRANSMISSION FACILITIES.........................241
18.1 Designation of Pool-Planned Facilities....................241
18.2 Construction of Facilities................................241
18.3 Protective Devices for Transmission Facilities and
Automatic Generation Control Equipment....................242
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 11
18.4 Review of Participant's Proposed Plans....................243
18.5 Participant to Avoid Adverse Effect..............244
SECTION 19 - EXPENSES.......................................................245
19.1 Annual Fee................................................245
19.2 NEPOOL Expenses...........................................247
19.3 Restructuring Costs.......................................249
SECTION 20 - INDEPENDENT SYSTEM OPERATOR....................................255
SECTION 21 - MISCELLANEOUS PROVISIONS.......................................263
21.1 Alternative Dispute Resolution............................263
21.2 Payment of Pool Charges; Termination of Status as
Participant...............................................276
21.3 Assignment................................................280
21.4 Force Majeure.............................................281
21.5 Waiver of Defaults........................................282
21.6 Other Contracts...........................................282
21.7 Liability and Insurance...................................283
21.8 Records and Information...................................284
21.9 Consistency with NPCC and NERC Standards..................285
21.10 Construction..............................................285
21.11 Amendment.................................................285
21.12 Termination...............................................286
21.13 Notices to Participants, Committees, Committee Members,
or the System Operator....................................287
21.14 Severability and Renegotiation............................291
21.15 No Third-Party Beneficiaries..............................292
21.16 Counterparts..............................................292
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 12
COMPOSITE RESTATED NEW ENGLAND 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 May
7, 1999.
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):
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 13
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 Markets Committee to take account of associated
electrical losses, as appropriate, minus (b) the sum of (i) the
-----
Electrical Load of the Participant for the hour, and (ii) the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 14
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.
1.3A Administrative Procedures are procedures adopted by the System Operator
-------------------------
in order to fulfill its responsibilities to apply and implement NEPOOL
System Rules.
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 Markets 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 15
reduced or increased, as appropriate, to recognize rights to receive or
--------------------
obligations to supply AGC pursuant to Firm Contracts or System
Contracts in accordance with Section 14.7(a). An AGC Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 16
level of output in order to control frequency and to maintain currently
proper power flows into and out of the NEPOOL Control Area.
1.8A Balloting Agent is the Secretary of the Participants Committee.
---------------
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 Markets
Committee, as compensation for (i) furnishing Installed 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, 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.
----------
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 17
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:
(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 NERC; and
(4) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 18
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.
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 Markets Committee to incorporate the
Bid Price for such Energy and any loss adjustments, if and as
appropriate under such market operation rules.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 19
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
----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 20
(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 directly interconnected
offer the unbundled transmission service, or pursuant to a
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 21
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.
1.17A End User Participant is a Participant which is a consumer of
----------------------
electricity in the NEPOOL Control Area that generates or purchases
electricity primarily for its own consumption or a non-profit group
representing such consumers.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 22
pursuant to a Unit Contract, reduced by (iii) any portion thereof which
----------
such Entity is selling pursuant to a Unit Contract. An Energy
Entitlement in a generating unit or units may, but need not, be
combined with any other Entitlements relating to such generating unit
or units and may be transferred separately from the related Installed
Capability Entitlement, Operating Reserve Entitlements, or AGC
Entitlement.
1.20 Entitlement is an Installed 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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 23
(a) engaged in the electric power business (the generation and/or
transmission and/or distribution of electricity for
consumption by the public or the purchase, as a principal or
broker, of Installed Capability, Energy, Operating Reserve,
and/or AGC for resale); or
(b) a consumer of electricity in the NEPOOL Control Area that
generates or purchases electricity primarily for its own
consumption or a non-profit group representing such consumers.
1.22 Excepted Transaction is a transaction specified in Section 25 of the
---------------------
Tariff for the applicable period specified in that Section, or in
Sections 25A and 25B of the Tariff.
1.23 [Deleted.]
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,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 24
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, Energy, Operating Reserves, and/or
AGC, pursuant to which the purchaser's right to receive such Installed
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 25
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 26
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 Transfer
Capability, times (b) the HQ Phase II Transfer Credit. The Participants
-----
Committee shall establish appropriate HQ Interconnection Capability
Credits to apply for a Participant which has such a percentage share
(i) during an
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 27
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 Markets Committee in
accordance with a schedule consistent with that followed by it in its
determination of the Winter Capability and Summer Capability of
generating units.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 28
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.
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 Participants Committee may establish.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 29
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 Participants Committee shall establish an appropriate HQ Phase II
Gross Transfer Responsibility that shall remain in effect concurrently
with the HQ Interconnection Capability Credit.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 30
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 Participants 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.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 31
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 Energy Entitlement, Operating Reserve Entitlements, or AGC
Entitlement.
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.
----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 32
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 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 33
1.52 Kilowatt is a kilowatthour per hour.
--------
1.52A Liaison Committee is the committee whose responsibilities are specified
-----------------
in Section 11C.
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 Markets Committee), plus
----
(b) kilowatthours delivered by such Participant pursuant to Firm
Contracts to its wholesale customers for resale, plus
----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 34
(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 Markets Committee shall make, or supervise the making
of, appropriate adjustments in the computation of Load for the purposes
of calculating any Participant's Annual Peak, Adjusted Monthly Peak,
Adjusted Annual Peak and Monthly Peak to eliminate any distortions
resulting from emergency load curtailments which would significantly
affect the Load of any Participant.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 35
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 Participants Committee may designate or approve from
time to time. The Participants 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.
-----------------
1.57 Market Products are Installed Capability, Operable Capability, Energy,
---------------
each category of Operating Reserve and AGC.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 36
1.57A Market Rules are the system rules and operating procedures adopted
-------------
pursuant to the System Operator Agreement in connection with the
administration of the NEPOOL Market.
1.58 [Deleted.]
1.58A Markets Committee is the committee whose responsibilities are specified
-----------------
in Section 10 and which may have additional responsibilities under a
proper delegation of authority by the Participants Committee. To the
extent practicable, references in the Agreement to the Markets
Committee shall include the prior Regional Market Operations Committee
as the predecessor of the Markets Committee.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 37
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:
(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 NPCC and
NERC; and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 38
(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.
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 Participants Committee, required to be provided by the Participants
in aggregate for the period to meet the reliability standards
established by the Participants Committee pursuant to Section 7.5(e).
1.64A NEPOOL Market is the market for electric energy, capacity and certain
-------------
ancillary services within the NEPOOL Control Area.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 39
1.64B NEPOOL System Rules are the Market Rules, the NEPOOL Information Policy
-------------------
and any other system rules for the operation of the System and
administration of the NEPOOL Market, the NEPOOL Agreement and the
NEPOOL Tariff.
1.64C NERC is the North American Electric Reliability Council.
----
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.
---------------
1.66A NPCC is the Northeast Power Coordinating Council.
----
1.66B OASIS is the Open Access Same-Time Information System of the System
-----
Operator.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 40
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 Markets 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 Markets
Committee.
1.68 [Deleted].
1.69 [Deleted].
1.70 [Deleted].
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 41
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 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, 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 42
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.
1.74A Participants Committee is the committee whose responsibilities are
-----------------------
specified in Section 7. To the extent applicable, references in the
Agreement to the Participants Committee shall include the prior
Management Committee or Executive Committee as the predecessor of the
Participants Committee.
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).
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 43
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 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 Reliability Committee
determines, in accordance with criteria approved by the Participants
Committee and subject to review by the System Operator, should be
included in PTF.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 44
1.80A Publicly Owned Entity is an Entity which is either a municipality or an
---------------------
agency thereof, or a body politic and public corporation created under
the authority of one of the New England states, authorized to own,
lease and operate electric generation, transmission or distribution
facilities, or an electric cooperative, or an organization of any such
entities.
1.81 [Deleted.]
1.82 Regional Network Service is the transmission service by that name
--------------------------
provided pursuant to Section 14 of the Tariff.
1.83 [Deleted.]
1.84 [Deleted.]
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 45
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.
1.85A Reliability Committee is the committee whose responsibilities are
----------------------
specified in Section 8 and which may have additional responsibilities
under a proper delegation of authority by the Participants Committee.
To the extent practicable, references in the Agreement to the
Reliability Committee shall include the prior Market Reliability
Planning Committee or the prior Regional Transmission Planning
Committee as the predecessor of the Reliability Committee.
1.85B Reliability Standards are those rules, standards, procedures and
----------------------
protocols approved by the Participants Committee pursuant to Section
7.3, or its predecessors, that set forth specifics concerning how the
System Operator shall
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 46
exercise its authority over matters pertaining to the reliability of
the bulk power system.
1.85C Review Board is the board whose responsibilities are specified in
------------
Section 11A.
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).
1.87 Second Effective Date is May 1, 1999.
---------------------
1.87A Sector has the meaning specified in Section 6.2.
------
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 47
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 Markets Committee in
accordance with Section 10.4(d).
1.90 Summer Period in each Power Year is the four-month period from June
-------------
through September.
1.91 System Contract is any contract for the purchase of Installed
-----------------
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, 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 48
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 ISO New England Inc., unless
replaced by a substitute independent system operator, a regional
transmission organization or an entity that forms a part of a regional
transmission organization that has, in each case, been approved by the
Commission.
1.94 Target Availability Rate is the assumed availability of a type of
--------------------------
generating unit utilized by the Participants Committee in its
determination pursuant to Section 7.5(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 49
1.95A Tariff Committee is the committee whose responsibilities are specified
----------------
in Section 9 and which may have additional responsibilities under a
proper delegation of authority by the Participants Committee. To the
extent practicable, references in the Agreement to the Tariff Committee
shall include the prior Regional Transmission Operations Committee as
the predecessor of the Tariff Committee.
1.95B Technical Committees are the Reliability Committee, the Tariff
--------------------
Committee and the Markets Committee.
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 Participants 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
Participants Committee.
1.97 Through or Out Service is the transmission service by that name
------------------------
provided pursuant to Section 18 of the Tariff.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 50
1.98 Transition Period is the six-year period commencing on March 1, 1997.
-----------------
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.
1.99A Transmission Owner is a Transmission Provider which makes its
-------------------
PTF available under the Tariff and owns a Local Network listed in
Attachment E to the Tariff which is not a Publicly Owned Entity,
including any affiliate of a Transmission Provider that owns
transmission facilities that are made available as part of the
Transmission Provider's Local Network; provided that if a Transmission
Provider is not listed in Attachment E to the Tariff on May 10, 1999,
the Transmission Provider must also (1) own, or lease with rights
equivalent to ownership, PTF with an original capital investment in
its PTF as of the end of the most recent year for which figures are
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 51
available from annual reports submitted to the Commission in Form 1
or any similar form containing comparable annualized data of at
least $30,000,000, and (2) provide transmission service to
non-affiliated customers pursuant to an open access transmission tariff
on file with the Commission.
1.99B Transmission Owners Committee is the committee whose responsibilities
------------------------------
are specified in Section 11B.
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) to a specifically determined or
determinable amount of Energy, Operating
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 52
Reserves and/or AGC if, or to the extent that, a specific electric
generating unit or units is or can be operated.
1.102 [Deleted.]
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 Markets Committee in
accordance with Section 10.4(d).
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.
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,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 53
as approved by the Markets 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 Markets 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
Markets Committee is necessary.
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 Markets Committee, to be available
to provide contingency protection for the system: (1) the Kilowatts of
Operable Capability of an electric
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 54
generating unit or units that are not synchronized to the system,
during all or part of the hour, and any portion of a Participant's
Electrical Load that the System Operator is able to verify as 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 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 Markets 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
Markets 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.
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,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 55
as approved by the Markets 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 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
Markets 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 Markets 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.
1.108 [Deleted.]
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 56
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
(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 57
(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
(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 58
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 wherein:
-
Y
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 59
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 60
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
became effective on the Second Effective Date and replaced on the
Second Effective Date the remaining provisions of the Prior NEPOOL
Agreement, which continued in effect until the Second Effective Date.
As provided in Section 14, certain portions of Section 14 which became
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999
67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 61
Any other Entity may, upon compliance with such reasonable conditions
as the Participants 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 Participants 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 Participants 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 for an applicant which qualifies for membership
only as an End User
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 62
Participant, and $5,000 for all other applicants, or such other amount
as may be fixed by the Participants Committee.
3.2 Operations Outside the Control Area. Subject to the reciprocity
---------------------------------------
requirements of the Tariff, if a Participant serves a Load, or has
rights in supply or demand-side resources or owns transmission and/or
distribution facilities, located outside of the NEPOOL Control Area,
such Load and resources shall not be included for purposes of
determining the Participant's rights, responsibilities and obligations
under this Agreement, except that the Participant's Entitlements in
facilities or its rights in demand side-resources outside the NEPOOL
Control Area shall be included in such determinations if, to the
extent, and while such Entitlements are used for retail or wholesale
sales within the NEPOOL Control Area or such Entitlements or rights are
designated by a Participant for purposes of meeting its obligations
under Section 12 of this Agreement.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 63
state whose laws govern this Agreement) over any action or proceeding
arising out of or relating to this Agreement that is not subject to the
exclusive jurisdiction of the Commission, (2) agree that all claims
with respect to such action or proceeding may be heard and determined
in such Connecticut state court or Federal court, (3) waive any
objection to venue or any action or proceeding in Connecticut on the
basis of FORUM NON CONVENIENS, and (4) agree that service of process
may be made on the Participant outside Connecticut by certified mail,
postage prepaid, mailed to the Participant at the address of its member
on the Participants 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 64
3.5 Financial Security. For an Entity applying to become a Participant or
-------------------
any continuing Participant that the Participants Committee reasonably
determines may fail to meet its financial obligations under the
Agreement, the Participants Committee may require reasonable credit
review procedures which shall be made in accordance with standard
commercial practices. In addition, the Participants 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 Participants 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,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 65
each of them shall be collectively treated as a single Participant for
purposes of this Agreement, if they each elect such treatment. They are
encouraged to do so. Such an election shall be made in writing and
shall continue in effect until revoked in writing.
In view of the long-standing arrangements in Vermont, Vermont Electric
Power Company, Inc. and any other Vermont electric utilities which
elect in writing to be grouped with it shall be collectively treated as
a single Participant for purposes of this Agreement; provided, however,
that any Vermont electric utility which is a Publicly Owned Entity may
elect to join the Publicly Owned Entity Sector and be treated as a
member of that Sector for purposes of governance, annual fees and
NEPOOL expense allocation, without losing the benefits of single
Participant status for any other purpose under 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 66
signatory to anyone not a party to this Agreement. Each signatory shall
retain its separate identity and, to the extent not limited hereby, its
individual freedom in rendering service to its customers.
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
-------------------------------------------------
5.1 NEPOOL Objectives. The objectives of NEPOOL are, through joint
------------------
planning, central dispatching, cooperation in environmental matters and
coordinated construction, central dispatch by the System Operator of
the operation and coordinated maintenance of electric supply and
demand-side resources and transmission facilities, the provision of an
open access regional transmission tariff and the provision of a means
for effective coordination with other power pools and utilities
situated in the United States and Canada,
(a) to assure that the bulk power supply of the NEPOOL Control Area
conforms to proper standards of reliability;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 67
(b) to create and maintain open, non-discriminatory, competitive,
unbundled markets for Energy, capacity, and ancillary services
that function efficiently in a changing electric power
industry and have access to regional transmission at rates
that do not vary with distance;
(c) to attain maximum practicable economy, consistent with proper
standards of reliability and the maintenance of competitive
markets, in such bulk power supply; and
(d) to provide access to competitive markets within the NEPOOL
Control Area and to neighboring regions;
and to provide for equitable sharing of the resulting responsibilities,
benefits and costs.
5.2 Cooperation by Participants. In order to attain the objectives of
-----------------------------
NEPOOL set forth in Section 5.1, each Participant shall observe the
provisions of this Agreement in good faith, shall cooperate with all
other Participants and shall not either alone or in conjunction with
one or more other Entities take
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 68
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 69
PART TWO
GOVERNANCE
SECTION 6
COMMITTEE ORGANIZATION AND VOTING
---------------------------------
6.1 Principal Committees. There shall be four principal NEPOOL Committees
--------------------
(the "Principal Committees"), as follows:
(a) the Participants Committee which shall have the responsibilities
specified in Section 7;
(b) the Reliability Committee which shall have the responsibilities
specified in Section 8;
(c) the Tariff Committee which shall have the responsibilities
specified in Section 9; and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 70
(d) the Markets Committee which shall have the responsibilities
specified in Section 10.
In addition, there shall be a Transmission Owners Committee and a
Liaison Committee, which shall have the responsibilities specified in
Sections 11B and 11C, respectively, and such other committees as may be
established from time to time by the Participants Committee.
6.2 Sector Representation. The members of each Principal Committee shall
----------------------
each belong to a single sector for voting purposes ("Sector"). Each
Participant shall be obligated to designate in a notice to the
Secretary of the Participants Committee a Sector that it or its Related
Persons is eligible to join and that it elects to join for purposes of
all of the Principal Committees. A Participant and its Related Persons
shall together be entitled to join only one Sector and shall have no
more than one vote on each Principal Committee.
The Sectors for each Principal Committee, the criteria for eligibility
for membership in each Sector and the minimum requirement which a
Participant
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999
67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 71
must meet as a member of a Sector in order to appoint a voting member
of the Sector and Committee are as follows:
(a) a Generation Sector, which a Participant shall be eligible to
join if (i) it (A) owns or leases with rights equivalent to
ownership facilities for the generation of electric energy
that are located within the NEPOOL Control Area which are
currently in operation, or (B) has proposed generation for
operation within the NEPOOL Control Area either which has
received approvals under Sections 18.4 and/or 18.5 within the
past two years or for which completed environmental air or
environmental siting applications have been filed or permits
exist, and (ii) it is not a Publicly Owned Entity. Purchasing
all or a portion of the output of a generation facility shall
not be sufficient to qualify a Participant to join the
Generation Sector.
A Participant which joins the Generation Sector shall be
entitled but not required to designate an individual voting
member of each Principal Committee, and an alternate to the
member, if its operating or proposed generation facilities in
the NEPOOL Control Area have or will have,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 72
when placed in operation, an aggregate Winter Capability of at
least 15 MW.
A Participant which joins the Generation Sector but elects not
to or is not eligible to designate an individual voting
member, shall be represented by a group voting member and an
alternate to that member for each Principal Committee
(collectively, the "Generation Group Member"). The Generation
Group Member shall be appointed by a majority of the
Participants in the Generation Sector electing or required to
be represented by that member. The Generation Group Member
shall have the same percentage of the Sector vote as the
individual voting members designated by other Participants in
the Generation Sector which meet the 15 MW threshold and
designate an individual voting member. The Generation Group
Member shall be entitled to split his or her vote.
(b) a Transmission Sector, which a Participant shall be eligible
to join if it is a Transmission Provider and is not a Publicly
Owned Entity. Taking transmission service shall not be
sufficient to qualify a Participant to join the Transmission
Sector.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 73
A Participant which joins the Transmission Sector shall be
entitled to designate an individual voting member of each
Principal Committee, and an alternate to the member, if it
owns or leases with rights equivalent to ownership PTF with an
original capital investment in its PTF as of the end of the
most recent year for which figures are available from annual
reports submitted to the Commission in Form 1 or any similar
form containing comparable annualized data of at least
$30,000,000. A Transmission Provider with facilities which
were included as PTF prior to December 31, 1998 only pursuant
to clause (3) of the definition of PTF pursuant to Section
15.1 shall be entitled to designate an individual voting
member of each Principal Committee, and an alternate to the
member, whether or not PTF which it owns or leases with rights
equivalent to ownership which has an original capital
investment of at least $30,000,000, so long as such
Transmission Provider continues to own PTF.
A Participant which joins the Transmission Sector but which is
not entitled to designate an individual voting member of each
Principal
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 74
Committee because (i) it, together with all of its Related
Persons, does not meet the $30,000,000 threshold or (ii) it no
longer owns PTF and it does not have a Related Person that is
entitled to designate an individual voting member for each
Principal Committee in another Sector, together with the other
Participants in the Transmission Sector which for the same
reasons are unable to designate an individual voting member,
shall be represented by a group voting member of each
Principal Committee (the "Transmission Group Member"), and an
alternate to that member. The Transmission Group Member and
alternate shall be appointed by a majority vote of all
Participants in the Transmission Sector required to be
represented by that Member. The Transmission Group Member
shall have the same percentage of the Sector vote as the
individual voting members designated by other Participants in
the Transmission Sector which meet the $30,000,000 threshold
unless and until the original capital investment in PTF of the
Participants represented by the Transmission Group Member
equals or exceeds twice the $30,000,000 threshold amount. If
the aggregate original capital investment in PTF equals or
exceeds twice the $30,000,000 threshold amount, the percentage
of the Sector votes assigned to the Transmission Group
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 75
Member shall equal the number of full multiples of the
$30,000,000 threshold, provided that the Transmission Group
Member shall in no event be entitled to more than twenty-five
percent (25%) of the Sector vote. For example, if Participants
represented by the Transmission Group Member have an aggregate
original capital investment in PTF in the NEPOOL Control Area
totaling $70,000,000, the Transmission Group Member will have
the same percentage of such votes as two
($70,000,000/$30,000,000 Threshold = 2.33) individual voting
members designated by individual Participants, provided that
there are at least six other members in the Sector so the
Transmission Group Member does not have more than twenty-five
percent (25%) of the Transmission Sector vote. The
Transmission Group Member shall be entitled to split his or
her vote.
(c) a Supplier Sector, which a Participant shall be eligible to
join if (i) it engages in, or is licensed or otherwise
authorized by a state or federal agency with jurisdiction to
engage in, power marketing, power brokering or load
aggregation within the NEPOOL Control Area or it had been
engaged on and before December 31, 1998 solely in the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 76
distribution of electricity in the NEPOOL Control Area, and
(ii) it is not a Publicly Owned Entity. A Participant which
joins the Supplier Sector shall be entitled to designate a
voting member of each Principal Committee, and an alternate to
the member.
(d) a Publicly Owned Entity Sector, which all Participants which
are Publicly Owned Entities are eligible to join and shall
join, and which End User Participants are eligible to join if
there is not an activated End User Sector. A Participant which
joins the Publicly Owned Entity Sector shall be entitled to
designate a voting member of each Principal Committee, and an
alternate to the member, except for End User Participants
whose voting interests while they are in the Publicly Owned
Entity Sector are defined in Section 6.2(e) below.
(e) an End User Sector, which an End User Participant is eligible
to join. Participants which join the End User Sector shall be
entitled to designate a voting member of each Principal
Committee and an alternate to the member. Until there are at
least ten End User Participants, all End User Participants
shall be members of the Publicly Owned Entity Sector. So
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 77
long as there are less than three End User Participants, the
End User Participants in the Publicly Owned Entity Sector
shall be represented on each Principal Committee by a single
voting member. At such time as there are at least three, but
less than ten, End User Participants, End User Participants
shall become a sub-sector of the Publicly Owned Entity Sector.
Such sub-sector shall have twenty percent (20%) of the
Publicly Owned Entity Sector's vote, and each End User
Participant shall be entitled to designate a voting member of
each Principal Committee, and an alternate to that member, and
each voting member shall be allocated a per capita share of
the sub-sector's vote. The End User Sector shall become fully
operational automatically as soon, and shall remain
operational so long as, there are at least ten End User
Participants.
The System Operator shall have the right to designate, by written
notice delivered to the Secretary of the appropriate Principal
Committee, a non-voting member and an alternate to each Principal
Committee. All Participants have the right to join and be a member of a
Sector. If a Participant ceases to be eligible to be a member of the
Sector which it previously joined and is not eligible to
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 78
join another existing Sector other than the End User Sector, it shall
have the right to remain and vote in the Sector in which the
Participant is currently a member for up to one year. By the end of
such year, the NEPOOL Participants Committee shall make a filing with
the Commission pursuant to which the Participant can join another
Sector that either exists or is created pursuant to the NEPOOL
Participants Committee filing. Separate Sectors may be created, and the
membership of existing Sectors may be modified, by amendment of the
Agreement.
6.3 Appointment of Members and Alternates. A Participant or group of
-------------------------------------
Participants shall designate, by a written notice delivered to the
Secretary of the appropriate Committee, the voting member appointed by
it for the Committee and an alternate of the member. In the absence of
the member, the alternate shall have all the powers of the member,
including the power to vote. A Participant may change the Sector of
which it is a member. Other than for Sector changes required by
Section 6.4(c), a change in the Sector in which a Participant is a
member shall become effective beginning on the first annual meeting
of the Participants Committee following notice of such change.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 79
6.4 Term of Members. Each voting member of a Principal Committee shall hold
---------------
office until either (a) such member is replaced by the Participant or
group of Participants which appointed the member, or (b) the appointing
Participant ceases to be a Participant, or (c) the appointing
Participant (or its Related Person) is no longer eligible to be in the
Sector to which it belongs, but is eligible to join a different Sector.
Replacement of a member shall be effected by delivery by a Participant
or group of Participants of written notice of such replacement to the
Secretary of the appropriate Committee.
6.5 Regular and Special Meetings. Each Principal 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. Five
or more voting members of a Principal Committee may call subject to the
notice provisions of Section 6.6 a special meeting of the Committee in
the event that the Chair fails to schedule 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 80
6.6 Notice of Meetings. Written or electronic notice of each meeting of a
------------------
Principal Committee shall be given to each Participant, whether or not
such Participant is entitled to appoint an individual voting member of
the Committee, not less than three business days prior to the date of
the meeting in the case of the Technical Committees and five business
days prior to the date of the meeting for the Participants Committee.
A notice of meeting shall specify the principal subject matters
expected to be acted upon at the meeting. In addition, such notice
shall include, or specify internet location of, all draft resolutions
to be voted at the meeting (which draft resolutions may be subject to
amendment of intent but not subject matter during the meeting), and all
background materials deemed by the Chair or Secretary to be necessary
to the Committee to have an informed opinion on such matters. Motions
raised for which no draft resolutions or background materials have been
provided may not be acted upon at a meeting and shall be deferred to a
subsequent meeting which is properly noticed.
6.7 Attendance. Regular and special meetings may be conducted in person, by
----------
telephone, or other electronic means by means of which all persons
participating
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 81
in the meeting can communicate in real time with each other. In order
to vote during the course of a meeting, attendance is required in
person or by telephone or other real time electronic means by a voting
member or its alternate or a duly designated agent who has been given,
in writing, the authority to vote for the member on all matters or on
specific matters in accordance with Section 6.12.
6.8 Quorum. All actions by a Principal Committee, other than a vote by the
------
Participants Committee by written ballot to amend the NEPOOL Agreement
or Tariff, shall be taken at a meeting at which the members in
attendance pursuant to Section 6.7 constitute a Quorum. A Quorum
requires the attendance by members which satisfy the Sector Quorum
requirements (as defined in Section 6.9) for a majority of the
activated Sectors. No action may be taken by a Principal Committee
unless a Quorum is present; provided, however, that if a Quorum is not
present, the voting members then present shall have the power to
adjourn the meeting from time to time until a quorum shall be present.
6.9 Voting Definitions. For purposes of this Section 6.9 and Sections 6.10,
------------------
6.11 and 6.13, the following terms shall have the following respective
meanings:
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 82
(a) Sector Voting Share: for each active Sector, is the quotient
-------------------
obtained by dividing one hundred percent (100%) by the number
of active Sectors. For example, if there are five active
Sectors, the Sector Voting Share of each of the Sectors is
twenty percent (20%). The aggregate Sector Voting Shares shall
equal one hundred percent 100%.
(b) Sector Quorum: for a Sector shall be the lesser of (i) fifty
--------------
percent (50%) or more (rounded to the next higher whole
number) of the voting members of the Sector, or (ii) five (5)
or more voting members of the Sector for the Participants
Committee or three (3) or more voting members of the Sector
for the Technical Committees.
(c) Member Fixed Voting Share: for a Committee voting member,
---------------------------
whether or not the member is in attendance, is the quotient
obtained by dividing (i) the Sector Voting Share of the Sector
to which the Participant or group of Participants which
appointed the Committee voting member belongs by (ii) the
total number of Committee voting members appointed by members
of that Sector, adjusted, if necessary, to take into account
(A) the manner in which the voting shares of End User
Participants are
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 83
to be determined while they are members of the Publicly Owned
Entity Sector, and (B) any required change in the voting share
of a Group Member, in each case as determined in accordance
with Section 6.2.
(d) Member Adjusted Voting Share: for a Committee voting member
----------------------------
which casts an affirmative or negative vote on a proposed
action or amendment and which has been appointed by a
Participant or group of Participants which are members of a
Sector satisfying its Sector Quorum requirement for the
proposed action or amendment, is the quotient obtained by
dividing (i) the Sector Voting Share of that Sector by (ii)
the number of voting members appointed by members of that
Sector which cast affirmative or negative votes on the matter,
adjusted, if necessary, for End User Participants and group
voting members as provided in the definition of "Member Fixed
Voting Share".
(e) NEPOOL Vote: with respect to a proposed action or amendment is
-----------
the sum of (i) the Member Adjusted Voting Shares of the voting
members of the Committee which cast an affirmative vote on the
proposed action or amendment and which have been appointed by
a Participant or group of
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 84
Participants which are members of a Sector satisfying its
Sector Quorum requirements and (ii) the Member Fixed Voting
Shares of the voting members of the Committee which cast an
affirmative vote on the proposed action or amendment and which
have been appointed by a Participant or group of Participants
which are members of a Sector which fails to satisfy its
Sector Quorum requirements.
(f) Minimum Response Requirement: with respect to a proposed
------------------------------
amendment to this Agreement or Tariff means that the ballots
received by the Balloting Agent from Participants relating to
the proposed amendment before the end of the appropriate time
specified in Section 6.11(c) must satisfy the following
thresholds:
(i) the sum of the Member Fixed Voting Shares of the
Participant voting members whose ballots are received
must equal at least fifty percent (50%); and
(ii) the Participants whose voting members timely return
ballots for or against the amendment must include
Participants that are
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 85
represented by voting members having at least fifty
percent (50%) of the Member Fixed Voting Shares in
each of a majority of the activated Sectors.
6.10 Voting On Proposed Actions. All matters to be acted upon by a Principal
--------------------------
Committee shall be stated in the form of a motion by a voting member,
which must be seconded. Only one motion and any one amendment to that
motion may be pending at one time. Passage of a motion requires a
NEPOOL Vote as determined pursuant to Section 6.9 equal to or greater
than two thirds of the aggregate Sector Voting Shares. Voting members
not in attendance or represented at a meeting as specified in Section
6.7 or abstaining shall not be counted as affirmative or negative
votes.
6.11 Voting On Amendments. Subject to Section 21.11 and Section 17A,
--------------------
amendments to the NEPOOL Agreement or Tariff shall be accomplished as
follows:
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 86
(a) Amendments shall be drafted by a standing or ad hoc NEPOOL
committee or a Participant and sent to the Participants
Committee for its consideration.
(b) The Participants Committee shall take action pursuant to
Section 6.10 to direct the Balloting Agent to circulate
ballots for approval of the draft Amendment to each
Participant for execution by its voting member or alternate on
the Participants Committee or such Participant's duly
authorized officer.
(c) In order to be counted, ballots must be executed and returned
to the Balloting Agent for NEPOOL in accordance with the
following schedule:
(i) If the ballots are delivered to each Participant by
regular mail, properly executed ballots must be
returned to and received by the Balloting Agent
within ten (10) business days after deposit of such
ballots in the mail by the Balloting Agent, and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 87
(ii) If the ballots are delivered to each Participant by
overnight delivery, facsimile, electronic mail or
hand delivery, then properly executed ballots must be
returned to and received by the Balloting Agent
within five (5) business days after (A) deposit of
such ballots with an overnight delivery courier if
delivered by overnight delivery, or (B) transmission
of such ballots by the Balloting Agent if delivered
by facsimile or electronic mail, or (C) receipt by
the Participant if delivered by hand delivery.
(iii) If the Minimum Response Requirement for an amendment
has not been received by the Balloting Agent within
the schedule identified in subsection (i) or (ii)
above, the Balloting Agent shall send notice by
overnight delivery, facsimile, electronic mail or
hand delivery to all non-responding Participants and
shall count any additional properly executed ballots
which it receives within five (5) business days after
such notice. The date by which properly executed
ballots must be returned and received by the
Balloting Agent shall be specified by the Balloting
Agent in the notice accompanying such ballots.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 88
(d) A Participant may appeal to the Review Board or submit for
resolution pursuant to the alternative dispute resolution
provisions of Section 21.1 a proposed amendment for which
ballots have been circulated, provided that such appeal is
taken or submission is presented before the end of the
tenth (10th) business day after the Participants Committee has
taken action to direct the Balloting Agent to circulate
ballots for approval of the draft amendment, by giving to the
Secretary of the Participants Committee a signed and written
notice of appeal or submission. The appeal shall be moot, or
submission shall be deemed withdrawn, if the amendment is not
approved in balloting by the Participants Committee. If the
amendment is approved, a valid appeal or submission shall stay
the filing with the Commission of any amendment to the NEPOOL
Agreement or Tariff until either (i) a decision on the appeal
by the Review Board, or (ii) the earlier of resolution
pursuant to Section 21.1 or termination pursuant to Section
21.1.B(2) of the suspension effects of the submission.
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 89
(e) In order for a proposed amendment to the NEPOOL Agreement or
Tariff to be approved by the Participants Committee, the
following criteria must be satisfied:
(i) The Minimum Response Requirement must be satisfied
with respect to the proposed amendment.
(ii) The affirmative ballot votes with respect to the
proposed amendment must equal or exceed two thirds of
the aggregate Sector Voting Shares.
6.12 Designated Representatives and Proxies. The vote of any member of a
-----------------------------------------
Principal Committee or the member's alternate, other than a ballot on
an amendment, may be cast by another person pursuant to a written,
standing designation or proxy. A designation or proxy shall be dated
not more than one year previous to the meeting and shall be delivered
by the member or alternate to the Secretary of the Committee at or
prior to any votes being taken at the meeting at which the vote is cast
pursuant to such designation or proxy. A single individual may be the
designated representative of or be given the proxy
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 90
of the voting members representing any number of Participants of any
one Sector or Participants from multiple Sectors.
6.13 Limits on Representatives. In the Generation Sector, no one person may
-------------------------
exercise more than twenty-five percent (25%) of that Sector's total
Member Fixed Voting Shares without the unanimous written agreement of
all members of the Generation Sector. Other Sectors may by unanimous
written agreement elect to impose limits on the voting power any one
individual may have in that Sector through being the designated
representative of multiple voting members or carrying multiple proxies
from voting members of that Sector. Notice of any such limits on voting
power must be posted on the System Operator home page and be capable of
being accessed by all Participants.
6.14 Adoption of Bylaws. The Participants Committee shall adopt bylaws,
------------------
consistent with this Agreement, governing procedural matters including
the conduct of its meetings and those of the other Principal
Committees. If there is any conflict between such bylaws and the
Agreement, the Agreement shall control. A Principal Committee may vote
to waive its bylaws for a particular meeting,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 91
provided the motion to effect the waiver is approved in accordance with
Section 6.10.
6.15 Joint Meetings of Technical Committees. It is recognized that
-------------------------------------------
responsibilities of the Technical Committees may overlap in certain
areas. In areas of overlap, the Reliability Committee is responsible
for addressing reliability matters, the Markets Committee is
responsible for addressing market implications of actions or
recommendations, and the Tariff Committee is responsible for addressing
issues relating to transmission and ancillary services. The Chairs of
the Technical Committees, with input from the Liaison Committee
Co-Chairs or entire Liaison Committee, as appropriate, shall prioritize
and sequence Technical Committee activities to ensure full and proper
input by Participants while maximizing the efficiency of the decision
making process. To the extent appropriate and desirable, the Technical
Committees are authorized and encouraged to hold meetings, and to
conduct studies and exercise responsibilities, jointly with other
Technical Committees.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 92
SECTION 7
PARTICIPANTS COMMITTEE
----------------------
7.1 Officers. At its annual meeting, the Participants Committee shall elect
--------
from among its members a Chair and Vice-Chair; it shall also elect a
Secretary who shall not be a member. These officers shall have the
powers and duties usually incident to such offices and as set forth in
the Committee bylaws.
7.2 Adoption of Budgets. At each annual meeting, the Participants Committee
-------------------
shall adopt a NEPOOL budget for the ensuing calendar year. In adopting
budgets the Participants Committee shall give due consideration to the
budgetary requests of each committee. The Participants Committee may
modify any NEPOOL budget from time to time after its adoption.
7.3 Establishing Reliability Standards. It shall be the duty of the
----------------------------------
Participants Committee, after review of reports, recommendations and
actions of the System Operator and the Reliability Committee and such
other matters as the Participants Committee deems pertinent, to
establish or approve Reliability Standards for the bulk power supply of
NEPOOL. Such Reliability Standards
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 93
shall be consistent with the directives of NERC and the NPCC and shall
be reviewed periodically by the Participants Committee and revised as
the Participants Committee deems appropriate.
7.4 Appointment and Compensation of NEPOOL Personnel. The Participants
---------------------------------------------------
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. In addition,
the Participants Committee shall determine what resources are desirable
for the effective operation of the Technical Committees and shall, on
its own or pursuant to the recommendation of a Technical Committee,
authorize the incurrence of such expenses as may be required to enable
the Technical Committee, or its subgroups, to properly perform their
duties, including, but not limited to, the retention of a consultant or
the procurement of computer time.
7.5 Duties and Authority.
--------------------
(a) The Participants Committee shall have the duty and requisite
authority to administer, enforce and interpret the provisions
of this Agreement and
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 94
any other agreement or document approved by the Participants
Committee or its predecessor in order to accomplish the
objectives of NEPOOL including the making of any decision or
determination necessary under any provision of this Agreement
or any other agreement or document approved by the
Participants Committee or its predecessor and not expressly
specified to be decided or determined by any other body.
(b) The Participants Committee shall have the authority to provide
for such facilities, materials and supplies as the
Participants Committee may determine are necessary or
desirable to carry out the provisions of this Agreement.
(c) The Participants Committee shall have, in addition to the
authority provided in Section 7.3, 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 95
affect the reliability of NEPOOL, and to review such
arrangements to determine compliance with such standards.
(d) The Participants 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 Participants Committee, or its designee, shall have the
authority on behalf of all Participants to execute any
contract, lease or other instrument which has been properly
authorized pursuant to this Agreement including, but not
limited to, one or more contracts with the System Operator,
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 System Operator, and
(iii) related tariffs, rate schedules and certificates of
concurrence. The Participants Committee shall, in addition,
have the authority to represent NEPOOL in proceedings before
the Commission.
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 96
(e) The Participants 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 Participants Committee may determine on the basis of
such review. Since changes in the circumstances which must be
assumed by the Participants Committee in fixing NEPOOL
Objective Capability for a future period can significantly
affect the required level of NEPOOL Objective Capability for
that period, the Participants 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 Participants Committee shall have the duty and requisite
authority to establish or approve schedules fixing the amounts
to be paid by
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 97
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 Participants Committee shall have the duty and requisite
authority to provide for the sharing by Participants, on such
basis as the Participants Committee may deem appropriate, of
payments and costs which are not otherwise reimbursed under
this Agreement and which are incurred by Participants or under
arrangements with Non-Participants and approved or authorized
by the Committee as necessary in order to meet or avoid
short-term deficiencies in the amount of resources available
to meet the Pool's reliability objectives.
(h) The Participants 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
Participants Committee determines that such compliance would
be unnecessary or inappropriate for such Entity and
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 98
the waiver for such Entity will not impose an additional
burden on other Participants.
(i) The Participants Committee shall have the authority to
establish standard conditions and waivers with respect to
applications by Entities for membership in NEPOOL and to
modify such standard conditions and waivers as appropriate in
connection with changed circumstances with respect to such
applicants, provided that the Participants Committee
determines that the standard conditions and waivers for such
Entities will not impose an additional burden on other
Participants.
(j) The Participants Committee shall have the duty and requisite
authority to act on appeals to it from the actions of other
Principal Committees if delegated to such Committees by the
Participants Committee pursuant to Section 7.5(k), to appoint
the Review Board, 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.
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 99
(k) The Participants Committee shall have the authority to
delegate its powers and duties to one or more of the Technical
Committees, the System Operator, or other entity as it sees
fit provided that (i) such delegation is clearly stated and
approved by a Participant Committee action, (ii) such
delegation does not violate any other provision set forth
herein, and (iii) the action of such entity on any matter
delegated to it may be appealed by any Participant to the
Participants Committee provided such an appeal is taken prior
to the end of the tenth business day following the action of
the Technical Committee, the System Operator, or such entity
by giving to the Secretary of the Participants Committee a
signed and written notice of appeal, a copy of which the
Secretary shall provide to the System Operator and each member
and alternate of the Participants Committee. Pending action
on the appeal by the Participants Committee, the giving of a
notice of appeal as aforesaid shall suspend the action
appealed from.
(l) The Participants Committee shall have the duty and requisite
authority to establish the NEPOOL Information Policy.
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 100
(m) The Participants Committee shall have the duty and requisite
authority to adopt and approve, amend and approve or resubmit
to one or more Technical Committees for additional comment,
any matter submitted to the Participants Committee by a
Technical Committee.
(n) The Participants Committee shall have such further powers and
duties as are conferred or imposed upon it by other sections
of this Agreement.
7.6 Attendance of Participants at Committee Meeting. Each Participant which
-----------------------------------------------
does not have the right to designate an individual voting member of the
Participants Committee shall, with the exception of meetings held
pursuant to Section 11B.9 and meetings in executive session pursuant to
Section 11B.10, be entitled to attend any meeting of the Committee or
any other NEPOOL committee, and shall have a reasonable opportunity to
express views on any matter to be acted upon at the meeting.
7.7 Appeal of Actions to Review Board. Any Participant which otherwise has
---------------------------------
the ability to submit a matter for resolution under Section 21.1 may,
in lieu of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 101
submitting a dispute as to a Participants Committee action or failure
to take action for resolution pursuant to Section 21.1, appeal such
matter to the Review Board. Except as otherwise provided in Section
6.11, such an appeal shall be taken prior to the end of the tenth
business day following the meeting of the Participants Committee to
which the appeal relates by giving to the Secretary of the Participants
Committee by hand delivery, facsimile, electronic mail or regular mail
a signed and written notice of appeal, a copy of which the Secretary
shall provide to each Participant. If no appeal of a Participants
Committee action or failure to take action is taken, and the action or
failure to take action is not submitted for resolution pursuant to
Section 21.1, within such time period, that Participants Committee
action or failure to take action shall be final and effective. If an
appeal is taken, pending action on the appeal by the Review Board, the
giving of a notice of appeal as aforesaid shall suspend the action
appealed from. To the extent any action taken relates to the approval
of a rule or procedure which must be filed with the Commission, the
rule or procedure shall not be filed until the time for appeal or
submission for dispute resolution has elapsed and, if an appeal has
been filed or submission for dispute resolution has been made, either
(i) a decision on the appeal has been issued by the Review Board, or
(ii) the earlier of resolution pursuant to Section 21.1 of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 102
the matter submitted for dispute resolution or the termination pursuant
to Section 21.1.B(2) of the suspension effect of such submission.
SECTION 8
RELIABILITY COMMITTEE
---------------------
8.1 Officers. The Reliability Committee shall have a Chair, Vice-Chair and
--------
Secretary. The Chair and Secretary of the Reliability Committee shall
be appointed by the System Operator from time to time in accordance
with Section 20(j). The Chair will be responsible for presiding at
meetings of the Committee and establishing agendas for its meetings in
conjunction with the Vice-Chair and shall have the powers and duties as
set forth in the Committee bylaws. The Secretary shall have the powers
and duties usually incident to such office and as set forth in the
Committee bylaws. The Chair and Secretary shall have no voting rights.
The Vice-Chair shall be elected by the Reliability Committee from among
its voting members from time to time. The Vice-Chair shall have the
powers and duties usually incident to such office and such powers and
duties as set forth in the Committee bylaws, including, without
limitation, the
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 103
responsibility to develop in conjunction with the Chair, Committee
meeting agendas.
8.2 Notice to Members and Alternates of Participants Committee. Prior to
------------------------------------------------------------
the end of the fifth business day following a meeting of the
Reliability Committee, the Secretary of the Reliability Committee shall
give written notice to the System Operator and each member and
alternate of the Participants Committee of any action taken by the
Reliability Committee at such meeting.
8.3 Voting; Appeal of Actions. Votes taken by the Reliability Committee
--------------------------
shall be binding on the Participants only for those matters in which
the Committee has specifically designated authority under this
Agreement or has been properly delegated authority by the Participants
Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding
action taken by the Reliability Committee. Such an appeal shall be
taken prior to the end of the tenth business day following the meeting
of the Reliability Committee to which the appeal relates by giving to
the Secretary of the Participants Committee a signed and written notice
of appeal, a copy of which the Secretary
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 104
shall provide to the System Operator and each member and alternate of
the Participants Committee. Pending action on the appeal by the
Participants Committee, the giving of a notice of appeal as aforesaid
shall suspend the action appealed from.
8.4 Responsibilities. The Reliability Committee shall perform the following
----------------
functions, in conjunction with the System Operator as appropriate, and
shall recommend action to the System Operator, Participants Committee
or Transmission Owners, as appropriate, with respect thereto:
(a) provide input to the Participants Committee, Transmission
Owners, and System Operator, as appropriate, on transmission
facilities and the development of a regional transmission plan
in order to achieve the objectives of NEPOOL;
(b) following appropriate study, recommend NEPOOL Objective
Capability for each Power Year;
Issued by: David T. Doot Effective: March 1, 2000
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<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 105
(c) periodically review the procedures used to calculate NEPOOL
Installed Capability, NEPOOL Objective Capability and NEPOOL
Capability Responsibility;
(d) periodically prepare short and long term load forecasts for
use in NEPOOL studies and operations and to meet requirements
of regulatory agencies;
(e) review communications and liaison arrangements between NEPOOL
and governmental authorities on power supply, environmental,
load forecasting, and transmission issues;
(f) coordinate the collection and exchange of necessary system
data and future plans related to reliability for use in NEPOOL
planning and to meet requirements of regulatory agencies;
(g) coordination of studies of, and provide information to
Participants on, maintenance schedules for the supply and
demand-side resources and transmission facilities of the
Participants;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 106
(h) based on appropriate studies, recommend for Participants
Committee approval Reliability Standards to assure the
reliable operation and facilitate the efficient operation of
the NEPOOL Control Area bulk power system and those operating
rules which guide the implementation of the Reliability
Standards. Such Reliability Standards and operating rules
shall include, without limitation, the following:
(i) standards to determine the current Annual Peak,
Adjusted Annual Peak, Monthly Peak, Adjusted Monthly
Peak, and aggregate obligations of the Participants
in each of the NEPOOL Markets;
(ii) standards to establish short and long term load
forecasts for use in NEPOOL operations and to meet
requirements of regulatory agencies;
(iii) standards with respect to the administration and
enforcement of, and reporting pursuant to, NERC and
NPCC policies and requirements;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 107
(iv) standards for use in planning and design of the
NEPOOL interconnected bulk power system;
(v) standards to ensure the continuous reliability of the
bulk power transmission system, such standards to
include, without limitation, criteria and rules
relating to protective equipment, transfer limits,
voltage schedules, voltage guides, operating guides,
sub-area reserves, switching, voltage control, load
shedding, emergency and restoration procedures, and
the coordination of scheduling of the operation and
maintenance of supply and demand-side resources and
transmission facilities of the Participants;
(vi) standards for determining the 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; and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 108
(vii) as appropriate, reliability standards for interpool
coordination transactions.
(i) review proposed supply and demand-side resource plans and the
proposed transmission and interconnection plans of
Participants pursuant to Section 18.4 and, based on such
review, recommend action regarding such proposed plans.
(j) make recommendations regarding procedures for dispatch
infrastructure (i.e. voice and data communications protocols,
AGC pulsing arrangements, Energy Management System and System
Control and Data Acquisition interfaces, Satellite relations,
etc.);
(k) provide input and make recommendations with respect to the
reliability considerations of general system operations (i.e.
commitment/decommitment, real time dispatch, review and
approval of distribution of reserves, etc.);
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 109
(l) recommend to the Participants Committee the retention of a
consultant, procurement of computer time, or the incurrence of
consultant expenses or such other expenses as may be required
to enable the Reliability Committee, its subcommittees, and
task forces properly to perform their duties;
(m) make recommendations to the Participants Committee,
Transmission Owners, and System Operator, as appropriate, with
respect to development and amendment of interconnection
procedures and documents related to such procedures;
(n) to the extent appropriate, develop criteria, guidelines and
methodologies to assure consistency in monitoring and
assessing conformance of Participant and regional transmission
plans to accepted reliability criteria.
8.5 Establishment of Subcommittees and Task Forces. The Reliability
----------------------------------------------
Committee shall have the authority to establish subcommittees and task
forces for particular studies.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 110
8.6 Further Powers and Duties. The Reliability Committee shall have such
-------------------------
further powers and duties as are consistent with the duties and
responsibilities set forth herein or as may be properly delegated to it
by the Participants Committee.
SECTION 9
TARIFF COMMITTEE
----------------
9.1 Officers. The Tariff Committee shall have a Chair, Vice-Chair and
--------
Secretary. The Chair and Secretary of the Tariff Committee shall be
appointed by the System Operator from time to time in accordance with
Section 20(j). The Chair will be responsible for presiding at meetings
of the Committee and establishing agendas for its meetings in
conjunction with the Vice-Chair and shall have the powers and duties as
set forth in the Committee bylaws. The Secretary shall have the powers
and duties usually incident to such office and as set forth in the
Committee bylaws. The Chair and Secretary shall have no voting rights.
The Vice-Chair shall be elected by the Tariff Committee from among its
voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties
as set forth in the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 111
Committee bylaws, including, without limitation, the responsibility to
develop in conjunction with the Chair, Committee meeting agendas.
9.2 Notice to Members and Alternates of Participants Committee. Prior to
------------------------------------------------------------
the end of the fifth business day following a meeting of the Tariff
Committee, the Secretary of the Tariff Committee shall give written
notice to the System Operator and each member and alternate of the
Participants Committee of any action taken by the Tariff Committee at
such meeting.
9.3 Voting; Appeal of Actions. Votes taken by the Tariff Committee shall be
-------------------------
binding on the Participants only for those matters in which the
Committee has specifically designated authority under this Agreement or
has been properly delegated authority by the Participants Committee
pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding
action taken by the Tariff Committee. Such an appeal shall be taken
prior to the end of the tenth business day following the meeting of the
Tariff Committee to which the appeal relates by giving to the Secretary
of the Participants Committee a signed and written notice of appeal, a
copy of which the Secretary
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 112
shall provide to the System Operator and each member and alternate of
the Participants Committee. Pending action on the appeal by the
Participants Committee, the giving of a notice of appeal as aforesaid
shall suspend the action appealed from.
9.4 Responsibilities. The Tariff Committee shall perform the following
----------------
functions, in conjunction with the System Operator as appropriate, and
shall recommend action to the System Operator, Participants Committee
or Transmission Owners, as appropriate, with respect thereto:
(a) develop appropriate billing procedures for transmission and
ancillary services pursuant to this Agreement and the Tariff;
(b) develop and recommend to the Participants Committee and the
Transmission Owners Committee, as appropriate, (i) amendments,
additions and other changes to the Tariff and (ii) related
Tariff rules;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 113
(c) providing input to the System Operator on the development of
Administrative Procedures with respect to the administration
of the Tariff and the OASIS;
(d) to the extent appropriate, conduct and/or review such studies
and make such determinations as are assigned to the Committee
pursuant to this Agreement and the Tariff with respect to
financial treatment of additions to or upgrades of PTF;
(e) recommend to the Participants Committee the retention of a
consultant, procurement of computer time, or the incurrence of
consultant expenses or such other expenses as may be required
to enable the Tariff Committee, its subcommittees, and task
forces properly to perform their duties.
9.5 Establishment of Subcommittees and Task Forces. The Tariff Committee
----------------------------------------------
shall have the authority to establish subcommittees and task forces for
particular studies.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 114
9.6 Further Powers and Duties. The Tariff Committee shall have such further
-------------------------
powers and duties as are consistent with the duties and
responsibilities set forth herein or as may be properly delegated to it
by the Participants Committee.
SECTION 10
MARKETS COMMITTEE
-----------------
10.1 Officers. The Markets Committee shall have a Chair, Vice-Chair and
--------
Secretary. The Chair and Secretary of the Markets Committee shall be
appointed by the System Operator from time to time in accordance with
Section 20(j). The Chair will be responsible for presiding at meetings
of the Committee and establishing agendas for its meetings in
conjunction with the Vice-Chair and shall have the powers and duties as
set forth in the Committee bylaws. The Secretary shall have the powers
and duties usually incident to such office and as set forth in the
Committee bylaws. The Chair and Secretary shall have no voting rights.
The Vice-Chair shall be elected by the Markets Committee from among its
voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties
as set forth in the Committee bylaws, including, without limitation,
the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 115
responsibility to develop in conjunction with the Chair, Committee
meeting agendas.
10.2 Notice to Members and Alternates of Participants Committee. Prior to
------------------------------------------------------------
the end of the fifth business day following a meeting of the Markets
Committee, the Secretary of the Markets Committee shall give written
notice to the System Operator and each member and alternate of the
Participants Committee of any action taken by the Markets Committee at
such meeting.
10.3 Voting; Appeal of Actions. Votes taken by the Markets Committee shall
--------------------------
be binding on the Participants only for those matters in which the
Committee has specifically designated authority under this Agreement or
has been properly delegated authority by the Participants Committee
pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding
action taken by the Markets Committee. Such an appeal shall be taken
prior to the end of the tenth business day following the meeting of the
Markets Committee to which the appeal relates by giving to the
Secretary of the Participants Committee a signed and written notice of
appeal, a copy of which the Secretary
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 116
shall provide to the System Operator and each member and alternate of
the Participants Committee. Pending action on the appeal by the
Participants Committee, the giving of a notice of appeal as aforesaid
shall suspend the action appealed from.
10.4 Responsibilities. The Markets Committee shall perform the following
----------------
functions, in conjunction with the System Operator as appropriate, and
shall recommend action to the System Operator, Participants Committee
or Transmission Owners, as appropriate, with respect thereto:
(a) based on appropriate studies, develop market procedures to
assure the reliable operation and facilitate the efficient
operation of the NEPOOL Control Area bulk power supply;
(b) (i) evaluate studies of the market implications of maintenance
schedules for the supply and demand-side resources and
transmission facilities of the Participants and operable
capacity margins, and (ii) develop market procedures for
scheduling maintenance for supply and demand resources and
transmission resources.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 117
(c) to the extent appropriate to assure the efficient operation of
the NEPOOL Markets, develop 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) develop procedures for determining the market implications of
the seasonal capabilities of each electric generating unit or
combination of units in which a Participant has an
Entitlement;
(e) develop procedures for determining as appropriate from time to
time the current Annual Peak, Adjusted Annual Peak, Monthly
Peak, Adjusted Monthly Peak, Installed Capability
Responsibility, and obligations for Energy, Operating Reserve
and AGC of each Participant;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 118
(f) develop Market Rules and periodically review and recommend
changes thereto as appropriate. Such Market Rules shall
include, without limitation, the following:
(i) submission of Bid Prices and the determination of
prices for each of the NEPOOL Markets;
(ii) determination for each Participants of its
obligations under each of the NEPOOL Markets;
(iii) establishment or approval of appropriate billing
procedures for market transactions pursuant to this
Agreement;
(iv) calculation and equitable apportionment of losses
incurred in connection with Interchange Transactions;
and
(v) interpool market contract coordination as appropriate.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 119
(g) develop operating procedures relating to the administration of
the NEPOOL Markets and periodically review and recommend
changes thereto as appropriate;
(h) recommend the retention of a consultant, procurement of
computer time, or the incurrence of consultant expenses or
such other expenses as may be required to enable the Markets
Committee, its subcommittees, and task forces properly to
perform their duties.
10.5 Establishment of Subcommittees and Task Forces. The Markets Committee
----------------------------------------------
shall have the authority to establish subcommittees and task forces for
particular studies.
10.6 Further Powers and Duties. The Markets Committee shall have such
----------------------------
further powers and duties as are consistent with the duties and
responsibilities set forth herein or as may be properly delegated to it
by the Participants Committee.
10.7 Development of Rules Relating to Non-Participant Supply and Demand-side
-----------------------------------------------------------------------
Resources. It is recognized that arrangements between Participants and
---------
Non-
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 120
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 Markets Committee shall analyze
such special problems and recommend to the Participants Committee
appropriate rules for reflecting such resources in the Installed 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 Participants 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 upon acceptance by the Commission.
SECTION 11
FURTHER RESTRUCTURING
---------------------
The NEPOOL Participants undertake to finalize by March 31, 2000 the negotiation
of more comprehensive arrangements for the reassignment of appropriate
administrative responsibilities to the System Operator in the Interim ISO
Agreement.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 121
SECTION 11A
REVIEW BOARD
------------
11A.1 Organization. There shall be a Review Board which, in addition to
------------
appeals responsibility under Section 11B.12, shall be responsible for
ruling on taken from actions of the Participants Committee and for
advising theParticipants Committee as to the issues raised on any
appeals before it provided that appeals from actions of the System
Operator shall not be taken to the Review Board. In ruling on appeals,
the Review Board shall consider, among other things, whether the actio
is consistent with Commission policies. In addition, if the appeal
relates to an amendment to the Agreement or market rule, the Review
Board shall consider the extent to which such amendment imposes a
burden on the Participants which do not vote in favor of the amendment
that is materially greater in degree than that imposed on the
Participants which have voted in favor of the amendment. The Review
Board shall not have the right to review or otherwise participate in
actions of the System Operator or to take any action with respect to
any matter involving a dispute between the System Operator and either
NEPOOL or any Participant. The Participants agree that the process of
selecting the Review Board shall commence upon the initial
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 122
formation of the Participants Committee. Until the initial organization
of the Review Board is completed, the Board of Directors of the System
Operator or a committee thereof consisting of not less than three
System Operator Directors designated by the System Operator Board of
Directors shall perform the functions of the Review Board, provided
that the provisions of Sections 11A.2 through 11A.6 shall not be
applicable to the Board of Directors of the System Operator acting as a
Review Board. All expenses incurred by the System Operator as a result
of the Board of Directors in acting as the Review Board shall be NEPOOL
expenses.
11A.2 Composition. The Review Board shall be composed of five members. The
-----------
Review Board Members shall initially be selected by the Participants
retained by the Committee from a slate of candidates. An independent
consultant, Participants Committee, shall prepare a list of persons
qualified and willing to serve on the Review Board. A subcommittee
appointed by the Participants Committee shall review the list and
distribute to the members of the Participants Committee a slate from
among the list proposed by the independent consultant, along with
information on the background and experience of the persons on the
slate appropriate to evaluating their fitness for service on the Review
Board. If
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 123
the Participants Committee fails to select a full Review Board from the
slate proposed by the subcommittee, the Committee shall direct the
independent consultant to propose a further list of nominees for
consideration at the next regular meeting of the Participants
Committee. Thereafter, prior to the expiration of a Review Board
Member's term, and upon the occurrence of any vacancy on the Board, the
Participants Committee shall select a successor Member.
11A.3 Qualifications. The Review Board Members shall be independent experts
--------------
knowledgeable about issues typically faced by entities engaged in energy
production, transmission, distribution and sale under Federal or State
regulation. A Review Board Member shall not be, and shall not have
been at any time within five years of election to the Review Board, a
director, officer or employee of a Participant or of a Related Person
of a Participant. While serving on the Review Board, a Review Board
Member shall have no direct business relationship or other affiliation
with any Participant or its Related Persons and shall otherwise be
subject to the same independence requirements imposed on Directors of
the System Operator Board of Directors.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 124
11A.4 Term. A Review Board Member shall serve for a term of three years;
----
provided, however, that two of the Review Board Members selected
initially shall be chosen by lot to serve a term of two years, two of
the Review Board Members selected initially shall be chosen by lot to
serve a term of three years and the other Review Board Member selected
initially shall serve a term of four years.
11A.5 Meetings. Meetings of the Review Board may be conducted in person or by
--------
telephone or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each
other.
11A.6 Bylaws. To the extent not inconsistent with any provision of this
------
Agreement, the Participants Committee shall adopt bylaws establishing
procedures for the Review Board's activities as it may deem
appropriate, including but not limited to bylaws governing the
scheduling, noticing and conduct of meetings of the Review Board, a
code of conduct, selection of a Chair and Vice-Chair of the Review
Board, and action by the Review Board without a meeting. Such bylaws
shall not modify or be inconsistent with any of the rights or
obligations established by this Agreement.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 125
11A.7 Procedure on Appeal of Participant Committee Action or Failure to Take
----------------------------------------------------------------------
Action.
------
(a) Submission of an Appeal: A Participant seeking review
("Appealing Party") by the Review Board of action of the
Participants Committee shall give written notice of the appeal
in accordance with Section 7.7, and the appeal shall have the
suspension effect specified in Section 7.7.
(b) Intervenors and Time Limits: Any other Participant that wishes
to participate in the appeal proceeding hereunder shall give
signed written notice to the Secretary of the Participants
Committee no later than ten (10) business days after the
Appealing Party has given notice of appeal and shall upon the
approval of the Review Board be permitted to participate in
the appeal.
(c) Procedural Rules: The procedural rules (if any), for the
----------------
conduct of the appeal shall be determined by the Review Board
in consultation with the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 126
Participants Committee and each Appealing Party on a
case-by-case basis.
(d) Pre-hearing Submissions: Each Appealing Party shall provide the
-----------------------
Review Board, within 15 days of the giving of its notice of
appeal or such other time as permitted by the Review Board, 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 Review Board to
review. The Participants Committee and, as appropriate, any other
Participant participating in the appeal will provide the Review
Board, within 10 days of the Appealing Party's submission or such
other time as permitted by the Review Board, copies of the
minutes of all NEPOOL committee meetings at which the matter was
discussed and if deemed appropriate by the Participants Committee
or otherwise requested by the Review Board a brief description of
the action (or failure to act) being appealed and a brief
statement explaining why the Participants Committee believes its
action (or failure to act) should be upheld by the Review Board,
together with copies of documents or other materials referenced
in such submission for the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 127
Review Board to review and materials, if any, which interested
Participants provide to the Secretary of the Participants
Committee and reasonably request be submitted to the Review
Board.
In addition, each party shall designate one or more
individuals to be available to answer questions the Review
Board may have on the documents or other materials submitted.
The answers to all such questions shall be reduced to writing
by the party providing the answer and a copy shall be made
available to any requesting Participant.
(e) Hearing: A hearing (if any) will be held as soon as is
-------
reasonably practicable.
(f) Decision: The Review Board's decision, to the extent
--------
practicable, shall be due, within ninety (90) days of the
giving of notice of the appeal.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 128
11A.8 Effect of a Review Board Decision.
---------------------------------
(a) Each Review Board Member shall have one vote and a decision of
the Review Board, either to grant or deny an appeal, shall
require affirmative votes by a majority of the Review Board
Members but not less than three (3) such Members.
(b) (i) Appeal denied. If the Review Board denies the appeal,
-------------
the action of the Participants Committee will be
final and effective, subject to Commission acceptance
if and as required.
(ii) Appeal granted. If the Review Board grants the
---------------
appeal, the Review Board's determination (granting
the appeal) will be final and the action of the
Participants Committee shall not take effect.
(c) If the Review Board grants an appeal, the Review Board may
submit a proposed resolution of the matter that was the
subject of the appeal to the Participants Committee. The
Participants Committee may, but is not required to, take
further action with regard to the matter. If the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 129
Participants Committee votes on an action regarding the matter
(including a vote not to act on the matter), the action or
non-action of the Participants Committee shall be subject to
further appeal by any Participant to the Review Board in
accordance with Section 7.7. Any proposed resolution that the
Review Board submits to the Participants Committee is advisory
only.
11A.9 An action or failure to act once appealed by a Participant to the Review
Board may not be subject to the alternative dispute resolution provisions
of Section 21.1, regardless of the outcome of the appeal. Conversely, an
action or failure to act submitted for resolution by a Participant pursuant
to Section 21.1 may not be brought before the Review Board. If more than
one Participant appeals and/or submits for alternative dispute resolution
under Section 21.1 the same issue, the Participant that first takes such
action shall determine whether the issue is to be heard by the Review Board
or considered under Section 21.1; provided that each Participant
-------- ----
challenging an action or failure to take action shall have the same
opportunity to present its case and may not be excluded from participating
under Section 11A.7(b).
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 130
11A.10 Any action taken or failure to take action by the Review Board does not
restrict or limit in any way the rights of a Participant to seek review
by the Commission, or a review in any other forum available to the
Participant and there shall be no requirement to submit an appeal to
the Review Board concerning any amendment, action or inaction by the
Participants Committee prior to a Participant exercising any such
rights to seek review by the Commission or any other forum with
jurisdiction.
11A.11 The Review Board may not take action that is inconsistent with or
infringes upon any of the rights set forth in Section 17A.
SECTION 11B
TRANSMISSION OWNERS COMMITTEE
-----------------------------
11B.1 Organization. There shall be a Transmission Owners Committee
------------
established pursuant to this Section 11B which shall implement the
rights reserved to Transmission Owners by Section 17A.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 131
11B.2 Membership. Membership on the Transmission Owners Committee shall be
----------
open to all Transmission Owners, regardless of their individual choices
in Sector membership under Section 6.2.
11B.3 Appointment of Members and Alternates. A Transmission Owner shall join
-------------------------------------
the Transmission Owners Committee by written notice delivered to the
Secretary of the Transmission Owners Committee, and shall designate in
the notice the initial member appointed by it for the Committee and an
alternate of the member. In the absence of the member, the alternate
shall have all the powers of the member, including the power to vote.
11B.4 Term of Members. A member of the Transmission Owners Committee
-----------------
appointed by a Transmission Owner shall serve until replaced by the
Transmission Owner which appointed it or until such Transmission Owner
ceases to be a Participant or otherwise lose its right to appoint the
member. Appointment or replacement of a member shall be effected by a
Transmission Owner by giving written notice of such appointment or
replacement to the Secretary of the Transmission Owners Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 132
11B.5 Regular and Special Meetings. The Transmission Owners 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. Thirty percent (30%) or more of the voting members of the
Transmission Owners Committee may call a special meeting of the
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.
11B.6 Notice of Meetings. Written notice of each meeting of the Transmission
------------------
Owners Committee shall be given to each Transmission Owner and to other
Participants not less than five (5) business days prior to the date of
the meeting.
11B.7 Attendance. Regular and special meetings may be conducted in person, by
----------
telephone, or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each
other. In order to vote during the course of a meeting, attendance is
required in person or by telephone or other real time electronic means
by a voting member or its alternate or a duly
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 133
designated agent who has been given, in writing, the authority to vote
for the member on all matters or the proxy to vote for the member on
specific matters.
11B.8 Votes. Any action taken by the Transmission Owners Committee shall
-----
require the concurrence of:
(i) representatives of at least two-thirds of the Transmission
Owners provided that Transmission Owners that are Related
Persons to one another shall together have a single vote; and
(ii) representatives of Transmission Owners having at least
two-thirds of the Weighted Votes of all Transmission Owners,
where each Transmission Owner's Weighted Vote is equal to its
original capital investment in its PTF as of the end of the
most recent year for which figures are available.
Notwithstanding the foregoing, if a vote is taken and paragraph (i)
above is satisfied but paragraph (ii) above is not, the action being
voted on by the Transmission Owners Committee shall pass if (1) there
are seven or more
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 134
Transmission Owners on the Committee and fewer than three Transmission
Owners oppose the action or (2) there are less than seven Transmission
Owners on the Committee and only one Transmission Owner opposes the
action.
11B.9 Appointment of Task Forces or Working Groups. The Transmission Owners
--------------------------------------------
Committee shall have the authority to appoint task forces or working
groups to address matters for which the Committee is responsible.
Notwithstanding Section 7.6, such tasks force or working groups may be
limited to Transmission Owners only.
11B.10 Officers. At its annual meeting, the Transmission Owners Committee
--------
shall elect from its 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, including the right to convene an executive session of the
Transmission Owners Committee to consider and vote upon submittals to
the Commission or litigation strategy.
11B.11 Adoption of Bylaws. The Transmission Owners Committee may adopt bylaws,
------------------
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 135
consistent with this Agreement, governing procedural matters including
the conduct of its meetings.
11B.12 Review of Committee Actions. To the extent the Commission determines,
---------------------------
pursuant to Section 17A.7, that Transmission Owners have the exclusive
right to make unilateral filings under Section 205 of the Federal Power
Act, a Transmission Owner may either submit a dispute for resolution
pursuant to Section 21.1 or appeal to the Review Board any action taken
by the Transmission Owners Committee with respect to such a Section 205
filing. Such a submission or appeal shall be taken prior to the end of
the tenth business day following the meeting of the Transmission Owners
Committee to which the submission or appeal relates by giving to the
Secretary of the Transmission Owners Committee a signed and written
notice of submission or appeal. Pending action on an appeal by the
Review Board, the giving of a notice of appeal as aforesaid shall
suspend the action appealed from. For purposes of the application of
the dispute resolution process of Section 21.1 and the suspension
effect of a submission to alternative dispute resolution, Section 21.1
shall be applied as if the Transmission Owners Committee were the
Participants Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 136
SECTION 11C
LIAISON COMMITTEE
-----------------
11C.1 Organization; Duties. There shall be a Liaison Committee which shall
--------------------
be an advisory committee only responsible to act as a steering
committee formanaging NEPOOL business through the committee process and
facilitating communications between NEPOOL and the System Operator and
among Participants. The Liaison Committee's duties as a steering
committee include, without limitation, recommending that matters be
assigned to particular committees for action where the subject matter
of a proposed rule or other action potentially falls in the purview of
more than one committee and assuring appropriate input from other
committees as needed.
11C.2 Membership. The Liaison Committee shall have the following members: the
----------
Chair and Vice-Chair of each of the Principal Committees; the Chair of
the Transmission Owners Committee; a Participant representative of each
Sector that is not otherwise represented on the Liaison Committee; the
chief executive
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 137
officer of the System Operator; and two members of the System
Operator's Board of Directors.
11C.3 Regular and Special Meetings. The Liaison Committee shall hold meetings
----------------------------
in accordance with a schedule adopted by the Committee or at the call
of the Co- Chairs.
11C.4 Notice of Meetings. Written notice of each meeting of the Liaison
-------------------
Committee shall be given to each member of the Committee and all
members of the Participants Committee not less than five business days
prior to the date of the meeting.
11C.5 Attendance. Regular and special meetings may be conducted in person, by
----------
telephone, or other electronic means by means of which all persons
participating in the meeting can communicate in real time with each
other. Participants Committee members and alternates may attend
meetings of the Liaison Committee. Any individual that is not a member
of the Liaison Committee may participate at a meeting at the invitation
of a Co-Chair.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 138
11C.6 Officers. The Co-Chairs of the Liaison Committee shall be the chief
--------
executive officer of the System Operator and the Chair of the
Participants Committee. The Liaison Committee shall 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 139
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS
---------------------------------------------
12.1 Obligations to Provide Installed Capability.
-------------------------------------------
(a) Each Participant shall have Installed System Capability during
each hour of each month at least sufficient to satisfy its
Installed Capability Responsibility for the month.
(b) [Deleted].
12.2 Computation of Installed Capability Responsibilities.
----------------------------------------------------
(a) (1) At the conclusion of each month, the System Operator
under the direction of the Participants Committee
shall determine each
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 140
Participant's tentative Installed Capability
Responsibility in Kilowatts for such month in
accordance with the following formula:
X = (P(A-N)+Np)(1+T) - C(Dp)
As used in this Section 12.2(a)(1), the symbols used
in the formula and the additional symbols defined
below have the following meanings:
X is the Participant's tentative Installed
Capability Responsibility for the month.
P is the value of the Participant's fraction
for the month as determined in accordance
with the following formula:
P = (Fp + Dp) / (F + D), wherein:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 141
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.
Dp is the Participant's actual or
potential load reduction resulting
from its NEPOOL Interruptible and
Dispatchable Loads for the month.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 142
does not constitute a Firm Contract
as defined in this Agreement.
D is the aggregate for the month of
the actual or potential load
reduction resulting from all
Participants' NEPOOL Interruptible
and Dispatchable Loads.
C is the factor, which when multiplied by D in
megawatts, results in the reduction to
NEPOOL Objective Capability that would
result from including D in the determination
of NEPOOL Objective Capability. The value
for C shall be adopted by the Participants
Committee each time it fixes NEPOOL
Objective Capability pursuant to Section
7.6(e).
A is the NEPOOL Objective Capability in
megawatts for the month as fixed by the
Participants Committee pursuant to Section
7.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 143
N is the aggregate of the New Unit Adjustments
for all Participants for the month as
determined by the Participants 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 Participants Committee,
and is equal to the aggregate of the
--------
Participant's adjustments for each New Unit
included in its Installed System Capabilit
during the hour of the coincident peak load
of the Participants for the month. The
Participant's adjustment for each New Unit
may be positive or negative and shall be the
product of (i) the Participant's Installed
Capability Entitlement in the New Unit
during the hour of the coincident peak load
of the Participants for the month, times
-----
(ii) the New Unit Adjustment Factor
applicable to the New Unit as determined in
accordance with Section 12.2(a)(2).
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 144
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 weighte
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 145
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 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 Participants Committee
in its most recent determination of NEPOOL
Objective Capability pursuant to Section 7.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 146
H for the Participant for the month is the
percentage which represents the weighted
average (using the Installed Capability of
each Installed Capability Entitlement for
such month for the weighting) of the Four
Year Actual Availability Rates of the
Installed Capability Entitlements which are
included in the Participant's Installed
System Capability during the hour of the
coincident peak load of the Participants for
the month. The Four Year Actual Availability
Rate for an Installed Capability Entitlement
for any month is the percentage which
represents the average of the amounts
determined for H1 for the four applicable
Twelve-Month Measurement Periods within the
forty-eight months which comprise the period
of four consecutive calendar years ending
within the Power Year which includes such
month; 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 147
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 148
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
(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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 149
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 Participants
Committee in its most recent
determination of NEPOOL Objective
Capability pursuant to Section 7.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 150
Capability Entitlements. The value for J
shall be adopted by the Participants
Committee each time it fixes NEPOOL
Objective Capability pursuant to Section 7.
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.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 151
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 System Operator under the direction
of the Participants Committee in accordance with the
following formula:
n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f-F)c2)
As used in this Section 12.2(a)(2), the symbols used
in the formula have the following meanings:
R is the phase out factor as defined in
Section 12.2(a)(1) above.
n is the New Unit Adjustment Factor, expressed
as a fraction, for the month for a New Unit.
c is the Winter Capability of the New Unit.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 152
C is the Winter Capability of the Proxy Unit,
which shall be the number of Kilowatts, as
determined by the Participants 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
Participants Committee of NEPOOL Objective
Capability for the month.
F is the equivalent forced outage rate of the
Proxy Unit. F, a fraction, shall be the
weighted average equivalent forced outage
rate (using the Winter Capability of each
generating unit for such weighting) of the
generating units in which the Participants
have Installed Capability Entitlements,
adjusted to compensate for the rounding of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 153
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
Participants Committee of NEPOOL Objective
Capability pursuant to Section 7.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 154
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 155
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 Participants Committee and reviewed
every five years (or more frequently if the
Participants 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 Participants 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,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 156
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 5 MW, 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)
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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 157
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;
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 Markets Committee prior to the
activation of the Participants Committee or the
Participants Committee thereafter.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 158
(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
System Operator under the direction of the Participants
Committee shall determine each Participant's tentative
Installed Capability Responsibility for the month with and
without the application of said paragraph (ii) The difference
between the sum of all Participants' tentative Installed
Capability Responsibilities, with and without the application
of said paragraph (ii) for the month, shall be added to the
tentative Installed Capability Responsibilities of the
Participants, as determined in accordance with Section
12.2(a), in proportion to said tentative Installed Capability
Responsibilities, thereby establishing each Participant's
adjusted tentative Installed Capability Responsibility for the
month.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 159
(c) For each month, the System Operator under the direction of the
Participants Committee shall determine the sum of all
Participants' adjusted tentative Installed Capability
Responsibilities, as initially determined in accordance with
Section 12.2(a) and as adjusted in accordance with Section
12.2(b), if Section 12.2(b) is applicable for such month. If
the sum is less than, or equal to, the minimum NEPOOL
Installed Capability during the month, then the adjusted
tentative Installed Capability Responsibility as determined
pursuant to Section 12.2(a) or 12.2(b), whichever is
applicable, for each Participant is the final Installed
Capability Responsibility for each Participant. If the sum
is greater than such minimum NEPOOL Installed Capability, then
each Participant's final Installed Capability Responsibility
shall be its adjusted tentative Installed Capability
Responsibility as determined pursuant to Section 12.2(a) or
12.2(b), whichever is applicable, multiplied by the ratio of
the minimum NEPOOL Installed Capability during the month to
the sum of the adjusted tentative Installed Capability
Responsibilities for the month.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 160
(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 Markets Committee shall analyze such special
problems and recommend to the Participants Committee for
approval 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 [Deleted].
12.4 Bids to Furnish Installed Capability. Each Participant shall submit to
------------------------------------
or have on file with the System Operator, in accordance with the market
operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter, one or more bids specifying the Bid Price and Kilowatt
amount at which it will furnish any and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 161
all surplus Installed System Capability for a month through NEPOOL to
other Participants. If no bid is submitted for a month for any surplus
Installed System Capability, the Bid Price for any such surplus for
which there is no bid 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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 162
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.
(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 163
(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.
12.6 [Deleted].
12.7 Payments to Participants Furnishing Installed Capability.
--------------------------------------------------------
(a) Participants that are deemed pursuant to Section 12.5 to
furnish any surplus in their Installed System Capability to
other Participants shall
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 164
receive therefor their pro rata shares on a Kilowatt basis of
all payments made by Participants for the month under Section
12.5, excluding any applicable fees for services assessed
pursuant to Section 19.2. If two or more Participants with
excess Installed System Capability have bid Kilowatts at the
Installed Capability Clearing Price, but not all the excess
Installed System Capability bid at such price is required to
meet shortages of Installed System Capability, then the excess
Installed System Capability bid at the Installed Capability
Clearing Price that each such Participant shall be deemed to
have furnished shall be the Kilowatts of excess Installed
System Capability bid by the Participant at that price
multiplied by the ratio of (i) the total Kilowatts of excess
----------
Installed System Capability bid at the 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) [Deleted].
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 165
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS
13.1 Maintenance and Operation in Accordance with Good Utility Practice.
-----------------------------------------------------------------------
Each Participant shall, to the fullest extent practicable, cause all
generating facilities and other resources owned or controlled by it to
be designed, constructed, maintained and operated in accordance with
Good Utility Practice.
13.2 Central Dispatch. Subject to the following sentence, each Participant
----------------
shall, to the fullest extent practicable, subject all generating
facilities and other resources owned or controlled by it to central
dispatch by the System Operator; provided, however, that each
Participant shall at all times be the sole judge as to whether or not
and to what extent safety requires that at any time any of such
facilities will be operated at less than full capacity or not at all.
Each Participant may remove from central dispatch a 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
Participants Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 166
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 Markets Committee prior to
the activation of the Participants Committee or the Participants
Committee thereafter, (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 Markets
Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter.
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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 167
(a) satisfy the NEPOOL Control Area's Operating Reserve
requirements, including the proper distribution of those
Operating Reserves;
(b) satisfy the Automatic Generation Control requirements of the
NEPOOL Control Area; and
(c) satisfy the Energy requirements of all Electrical Loads of the
Participants,
all at the lowest practicable aggregate dispatch cost to the NEPOOL
Control Area in light of available Bid Prices and Participant-directed
schedules.
13.5 Satellite Membership. Each Participant which is responsible for 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 168
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.
(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 169
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 Participants Committee determines
should be assigned specifically to such
Participant and not be shared by all
Participants.
OR is the aggregate number of Kilowatts of that
category of Operating Reserve determined by
the System Operator in accordance with the
directions of the Participants Committee to
be required for the NEPOOL Control Area for
the hour that is not assigned to
Non-Participants.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 170
SA is the aggregate number of Kilowatts of that
category of Operating Reserve for the hour
that the Participants Committee determines
should not be shared by all Participants,
but not including Operating Reserve assigned
to Non-Participants.
ELp is the Participant's Electrical Load for the
hour.
EL is the sum of ELp for all Participants.
(c) Each Participant shall have for each hour an AGC obligation
equal to its share of AGC required for the NEPOOL Control Area
in the hour. Subject to adjustment pursuant to Section 14.6, a
Participant's share of AGC required for any hour shall be
determined in accordance with the following formula:
AGCp=AGC (ELp/EL), wherein
AGCp is the Participant's share of AGC for the
hour.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 171
AGC is the total amount of AGC determined by the
System Operator in accordance with market
operation rules approved by the Markets
Committee prior to the activation of the
Participants Committee or the Participants
Committee thereafter to be required for the
NEPOOL Control Area for the hour that is not
assigned to Non-Participants.
ELp and EL are as defined in Section 14.1(b).
14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating
---------------------------------------------------------------------
Reserve and Automatic Generation Control.
----------------------------------------
(a) A Participant which has Energy Entitlements shall submit to or
have on file with the System Operator, in accordance with the
market operation rules approved by the Markets Committee prior
to the activation of the Participants Committee or the
Participants Committee thereafter, 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 Markets Committee prior to the activation of
the Participants Committee or the Participants Committee
thereafter, one or more bids for each such Entitlement for
which the Participant is permitted to bid specifying the Bid
Prices at which it will furnish 10-Minute Spinning Reserve,
10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve
and/or AGC through NEPOOL to other Participants under this
Agreement or to Non-Participants for ancillary services under
the Tariff, except to the extent such Entitlements are
scheduled by the Participant consistent with Section 14.2(d).
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 172
(c) Except as emergency circumstances may result in the System
Operator requiring load curtailments by Participants, each
Participant shall be entitled to receive from the other
Participants (or from the service made available from
Non-Participants pursuant to arrangements entered into
under Section 14.6) such amounts, if any, of Energy, Operating
Reserve, and AGC as it requires and Non-Participants shall be
entitled to receive from Participants the amount of ancillary
services to which they are entitled pursuant to the Tariff.
If, for any hour, load curtailments are required, the amount
that Participants and Non-Participants with shortages are
entitled to receive shall be proportionally reduced by the
System Operator in a fair and non-discriminatory manner in
light of the circumstances.
(d) All Bid Prices for Entitlements shall be submitted in
accordance with market operation rules approved by the Markets
Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter. 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 173
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 174
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 Markets
Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter. On and
after the Third Effective Date, such Bid Prices shall be
submitted for each hour of the day and the notice period for
such Bid Prices shall be reduced to one hour or such shorter
time as the System Operator determines from time to time is
practical while maintaining reliability and meeting its other
obligations to the Participants, except that such notice
period shall be longer than one hour if and to the extent that
the System Operator reasonably determines that such notice is
the shortest notice that is technically feasible at that time
to maintain reliability and meet its other obligations to the
Participants. The System Operator shall notify the
Participants following its receipt of all Bid Prices of the
expected dispatch schedule for the next Scheduled Dispatch
Period. The System Operator shall reduce the notice required
for Bid Prices and the applicable Scheduled Dispatch Period to
the minimum time technically and practically feasible while
maintaining reliability and meeting its other obligations to
the Participants.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 175
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 Markets Committee
prior to the activation of the Participants Committee or the
Participants Committee thereafter consistent herewith. Subject
to the right of the System Operator to direct changes to
schedules in order to ensure reliability in the NEPOOL Control
Area or any neighboring control area, a Participant permitted
to bid its Energy, Operating Reserve, and/or AGC Entitlements
in a generating unit or units, or required to make Energy
deliveries, may submit an hour-to-hour schedule for the
operation or dispatch of such Entitlements during a Scheduled
Dispatch Period at or before the time that Bid Prices are
required to be submitted for such period. In addition, prior
to the Third Effective Date, a Participant permitted to bid a
unit or units may submit a short-notice schedule for the
operation or dispatch of any or all of the Energy available
from such unit or units during the current or a subsequent
Scheduled Dispatch Period following the time that the System
Operator notifies the appropriate Participants of their
expected
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 176
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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 177
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.
(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 assigne
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
Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter 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
-----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 178
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 between the Kilowatts of such Operating
Reserve assigned to the Participant for the hour under Section
14.1(b) and the Kilowatts of such Operating Reserve designated
by the System Operator to be provided in the hour by the
Participant's applicable Operating Reserve Entitlements.
(c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the
Third Effective Date, the amount of AGC which a Participant is
deemed to have received in an hour is the AGC assigned to the
Participant for the hour under Section 14.1(c), and the amount
a Participant is deemed to have furnished in the hour is the
AGC designated by the System Operator to be provided in the
hour by the Participant's AGC Entitlements. For purposes of
Sections 14.4, 14.5, and 14.10, on and
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 179
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.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 180
(b) For every hour in which a Participant is deemed to receive
Operating Reserve of any category in accordance with Section
14.3(b), the number of Kilowatts it is deemed to receive for
the hour in each category shall be computed. The Participant
shall pay therefor for the hour any applicable uplift charge
assessed under Section 14.15 and any applicable fees for
services assessed pursuant to Section 19.2 plus the product of
----
(i) the aggregate amount paid to Participants for that
category of Operating Reserve for the hour pursuant to Section
14.5(b) and (ii) a fraction of which the numerator is the
Kilowatts of that category of 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 181
amount paid to Participants for AGC for the hour pursuant to
Section 14.5(c) and (ii) a fraction of which the numerator is
the AGC the Participant is deemed under Section 14.3(c) to
have received for the hour and the denominator is the
aggregate amount of AGC all Participants are deemed under
Section 14.3(c) to have received for the hour.
14.5 Payments to Participants Furnishing Energy Service, Operating Reserve,
----------------------------------------------------------------------
and Automatic Generation Control.
--------------------------------
(a) Subject to the provisions of Section 14.12, a Participant that
is deemed in an hour to furnish Energy service to other
Participants pursuant to Section 14.3, or 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 Markets
Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter. 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 Markets Committee prior to the activation of the
Participants Committee or the Participants Committee
thereafter.
(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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 182
(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 Markets Committee prior to the
activation of the Participants Committee or the
Participants Committee thereafter; plus
----
(ii) an AGC reservation payment for each AGC Entitlement
that the System Operator designated for AGC in the
hour calculated as (A) the AGC Clearing Price in
effect for the hour, times (B) the level of AGC the
-----
System Operator determines to be available in the
hour from the Entitlement, times (C) the portion of
-----
the hour during which the System Operator had
designated the Entitlement for AGC; plus
----
(iii) a payment that compensates the Participant for its
lost opportunity cost, if any, for the operation of
the generating unit
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 183
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 Markets Committee
prior to the activation of the Participants Committee
or the Participants Committee thereafter.
14.6 Energy Transactions with Non-Participants.
-----------------------------------------
(a) The Participants Committee is authorized to enter into
contracts on behalf of and in the names of all Participants
(i) with power pools or other entities in one or more other
control areas to purchase or furnish emergency Energy (and
related services) that is available for the System Operator to
schedule in order to ensure reliability in the NEPOOL Control
Area or neighboring control areas, and (ii) with Non-
Participants pursuant to which ancillary services will be
provided by the Participants pursuant to the Tariff. The
terms of any such contractual arrangement shall not require
the furnishing of emergency service to any other control area
until the service needs of all Participants have been
provided for with the least expensive resources practicable.
Energy
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 184
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 Participants Committee is authorized to provide for the
day-to-day scheduling through the System Operator of the HQ
Phase II Firm Energy Contract, in accordance with the HQ Use
Agreement, as if the Contract were a contract covering Energy
transactions with a Non-Participant entered into pursuant to
Section 14.6(a). The HQ Phase II Firm Energy Contract shall
not be deemed a Firm Contract for purposes of this Agreement.
Energy received in an hour from Hydro-Quebec pursuant to the
HQ Energy Banking Agreement, and Energy purchased in any hour
from Hydro-Quebec pursuant to the HQ Phase II Firm Energy
Contract or any other HQ Contract shall be deemed to be Energy
furnished to each Participant entitled to such Energy for the
hour in the amount reflected for the Participant in the System
Operator's scheduling of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 185
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 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).
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 186
14.7 Participant Purchases Pursuant to Firm Contracts and System Contracts.
---------------------------------------------------------------------
(a) For Firm Contracts and System Contracts, the treatment of
Installed 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
Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter. If and to
the extent necessary to implement the agreement between the
parties, such market operation rules, upon approval by the
Participants Committee, shall supersede the provisions of th
Agreement that otherwise apply for determination of the
respective responsibilities and Entitlements of the parties.
(b) In the event a Participant has the right to receive 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 Energy Entitlement, Operating Reserve
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 187
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 Markets Committee prior to the activation of
the Participants Committee or the Participants Committee
thereafter.
14.8 Determination of Energy Clearing Price. For each hour, the System
--------------------------------------
Operator shall determine the Energy Clearing Price as follows:
(a) The System Operator shall rank in the order of lowest to
highest (i) the Dispatch Prices derived from the Bid Prices to
furnish Energy in the hour and (ii) the cost to NEPOOL of any
Energy received from Non-Participants in the hour pursuant to
contracts referenced in Section 14.6.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 188
(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 Markets Committee
prior to the activation of the Participants Committee or the
Participants Committee thereafter 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 Markets
Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.
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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 189
(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 Markets Committee
prior to the activation of the Participants Committee
or the Participants Committee thereafter) of that
category of Operating Reserve that are designated by
the System Operator for use in the hour.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 190
(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 Markets Committee prior to the
activation of the Participants Committee or the
Participants Committee thereafter) 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 Opportunity Price for a
Participant's resource shall be the amount by which the Energy
Clearing Price for the hour exceeds the resource's
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 191
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 Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter to
reflect those AGC resources with the highest Bid Prices that were
designated by the System Operator to provide AGC in the hour and were
deemed pursuant to Section 14.3(c) to have been received by
Participants for the hour.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 192
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).
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 193
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
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 194
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:
(i) (A) amounts owed to Non-Participants (other than
Hydro-Quebec) for the month under contracts entered
into with them pursuant to Section 14.6(a) shall be
paid, and (B) amounts owed to Hydro-Quebec for the
month for Energy deemed to be furnished pursuant to
Section 14.6(b) to Participants which are not
participants in the Phase I or Phase II arrangements
with
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 195
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.
(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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 196
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 HQEnergy 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.
(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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 197
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 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
-----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 198
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.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 199
aggregate amount paid by Participants for the excess
Energy pursuant to Section 14.6(b) shall be paid to
the Energy Banking Fund. The Escrow Agent under the
HQ Use Agreement shall hold and invest these funds.
On the return of the excess Energy to Hydro-Quebec,
the amount so held by the Escrow Agent shall be
repaid to Hydro-Quebec and Participants in accordance
with the Energy Banking Agreement.
(c) Phase I HQ Savings Fund.The aggregate amount allocated to each
-----------------------
Participant's share of the Phase I HQ Savings Fund for each
month shall 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 200
(d) Phase II HQ Savings Fund. The aggregate amount allocated to
------------------------
the Phase II HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the
month for Energy deemed to be furnished to the Participant
under the Phase II HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for Energy
deemed to be furnished to the Participant under the HQ
Interconnection Agreement. The balance of the amount
allocated to the Fund for the month shall be paid to the
Escrow Agent under the HQ Use Agreement to be held and
disbursed by it through the 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 201
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
Markets Committee shall analyze such special problems and recommend to
the Participants Committee for approval appropriate rules for
dispatching such facilities (including, but not limited to, bids for
dispatchable pumping load at pumped storage facilities), for handling
such interruptible loads and for paying for 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
Participants 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 Markets Committee shall analyze such special problems and recommend
to the Participants Committee for approval appropriate dispatch and
billing rules to be applied during periods when the Participants
Committee determines that there is, or is anticipated to
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 202
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 Participants Committee, such rules shall supersede
the economic dispatch and billing provisions of this Agreement to the
extent of any conflict therewith for the duration of such Energy
shortage period.
14.14 Congestion Uplift.
-----------------
(a) It shall be the responsibility of the Participants 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 March 1, 2000 and after the preparation of
necessary implementing rules and computer software or
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 203
on an earlier or later effective date. If the Participants
Committee determines that such a provision should be made
effective, it shall recommend to the Participants any required
amendment to the Agreement and/or the Tariff and a schedule
for implementation which will permit sufficient time for the
development of necessary rules and computer software. If the
Participants 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 the earlier of June 1, 2000 or the beginning of
the first calendar month sixty (60) days after the filing of
an amendment to the Agreement and/or the Tariff by the
Participants Committee, any Participant or group of
Participants, 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 204
Participants 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 operation rules approved by the
Regional Market Operations Committee and the Regional
Transmission Operations Committee prior to the activation of
the Participants Committee or the Participants Committee
thereafter, 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 prior to
the activation of the Participants Committee or the
Participants Committee thereafter, the System
Operator shall identify for each Participant and Non-
Participant the difference in megawatt hours, if any,
between (A) Electrical Load served by the Participant
or Non-Participant in the constrained area and
transactions by the Participant or Non-Participant
occurring in the hour which utilized the constrained
interface to move Energy through the constrained area
and (B) the Participant's or Non-Participant's
in-merit Energy Entitlements located in the
constrained area that were used in the hour to serve
such Electrical Load, taking into account Firm
Contracts and System Contracts between Participants
and electrical losses, if and as appropriate.
(ii) The System Operator shall identify for each
Participant and Non-Participant the megawatt hours,
if any, of the rights of that Participant or
Non-Participant to use the then effective transfer
capability across the constrained interface.
(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 exceeds
the clause (ii) amount, the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 205
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 Tariff. Accordingly, if and to the extent
appropriate, feasible and practical,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 206
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 prior to the activation of the
Participants Committee or the Participants Committee thereafter.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 207
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 208
(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:
(a) The connection is rated 69 kV or above.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 209
(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 Reliability 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.
(ii) Lines which loop, from two geographically
separate points on the NEPOOL Transmission
System, the supply
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 210
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 Person files with the Secretary of
the Participants Committee its consent to such treatment; and
(ii) the Participants Committee determines that
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 211
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 extent safety requires that at any time
any of such facilities will be operated at less than their full
capability or not at all.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 212
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 Tariff 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 Tariff 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 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 Reliability
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 213
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 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 Reliability Committee, subject to review by the System Operator,
one or more Transmission Providers shall be designated by
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 214
the Reliability 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.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 215
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 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 216
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.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 217
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;
(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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 218
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 Years
-------- -------- ---------- --------- -----
Five and
--------
Six
---
% of
charge to 100% 80% 60% 40% 20%
be paid
(iv) that if the Transmission Provider receives a distribution
pursuant to Section 16.6 from NEPOOL out of revenues paid for
Through or Out 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 219
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, except that any reductions to the
amount due from Eligible Customers for Excepted Transactions
identified in Section 25(1) and (2) of the Tariff shall be
made only for service rendered through February 28, 1999, and
such reductions shall cease and shall be replaced thereafter
in their entirety with the credits under the NEPOOL Tariff,
provided in accordance with Sections 25A and 25B of the
Tariff.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 220
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 those Participants
owning PTF
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 221
or those load-serving Participants supporting PTF which are
obligated to take and pay for Regional Network Service and/or
Internal Point-to- Point Service in accordance with the
Tariff, 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 such owners and supporters, in accordance with the
following Schedule:
Year One Year Two Year Three Year Four Year Five Year Six
Allocated 25% 20% 15% 10% 5% 2.5%
Flows:
Annual 75% 80% 85% 90% 95% 97.5%
Transmission
Revenue
Requirements:
Revenues received by NEPOOL for providing Regional Network
Service each month after the Transition Period shall be
distributed to the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 222
Participants owning or supporting PTF in proportion to their
respective Annual Transmission Revenue Requirements for PTF.
B. Through or Out Service Revenues. The revenues received by
-------------------------------
NEPOOL each month for providing Through or Out Service shall
be distributed among the Participants owning PTF on the basis
of allocated flows for the transaction determined in
accordance with the methodology specified in Attachment A to
this Agreement; provided that for service provided during the
Transition Period but not thereafter, for an "Out" transaction
which originates on the system of a Participant which owns the
PTF interconnection facilities on the New England side of the
interface with the other Control Area over which the
transaction is 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 shall be distributed among those
load-serving Participants owning or supporting PTF which are
obligated to take and pay for Regional
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 223
Network Service and/or Internal Point-to-Point Service in
accordance with the Tariff, 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 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 224
any hour shall be applied in accordance with Section 14.5(a)
in payment for Energy service.
SECTION 17
POOL-PLANNED UNIT SERVICE
17.1 Effective Period. The provisions contained in this Section 17 shall
----------------
continue in effect for the period to and including February 28, 2001,
and shall be of no effect after that date.
17.2 Obligation to Provide Service. Until February 28, 2001, 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;
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 225
(b) the transfer to a Participant's system of its Entitlement in a
purchase under a contract entered into by it before November
1, 1996 (including a purchase under the HQ Phase II Firm
Energy Contract) from Hydro-Quebec where the line over which
the transfer is made into New England is the HQ
Interconnection; and
(c) the transfer to a Non-Participant of its Entitlement in a
Pool-Planned Unit pursuant to an arrangement which has been
approved prior to November 1, 1996 by the Participants
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:
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 226
(a) To the extent that EHV PTF is available to effect the
transaction, over all or part of the distance to be covered,
the use shall be deemed to be effected on such EHV PTF over
such portion of the distance to be covered.
(b) To the extent that EHV PTF is not available for the entire
distance to be covered by the use, but Lower Voltage PTF is
available to cover all or part of the distance not covered by
EHV PTF, the transaction shall be deemed to be effected on
such Lower Voltage PTF.
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
Participants Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 227
17.4 Payments for Uses of EHV PTF During the Transition Period.
---------------------------------------------------------
(a) Each Participant shall pay each month for its uses of EHV PTF
for transfers of Entitlements pursuant to subsections (a) or
(b) of Section 17.2, one-twelfth of the NEPOOL EHV PTF
Participant Summer or Winter Wheeling Rate in effect for the
calendar year ending December 31, 1996, as determined in
accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its current Entitlements which qualify for transfer
pursuant to subsections (a) or (b) of Section 17.2, except as
otherwise provided in Section 17.3; provided that such 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 228
month for the use of EHV PTF for deliveries under the Phase II
Firm Energy Contract during the Base Term of the HQ Phase II
Firm Energy Contract, one-twelfth of the NEPOOL EHV PTF
Participant Summer or Winter Wheeling Rate in effect for the
calendar year ending December 31, 1996, as determined in
accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its HQ Phase II Net Transfer Responsibility for the month.
If, and to the extent that, such Responsibility continues for
any period by which the term of said Contract extends beyond
the Base Term, each such Participant shall continue to pay the
above rate during the extension period with respect to its
continuing Responsibility. A Participant shall not be deemed
to be directly interconnected to the HQ Interconnection for
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 229
counsel describing and authenticating such rights, shall be
filed with the Secretary of the Participants Committee.
The NEPOOL EHV PTF Participant Summer Wheeling Rate for any
calendar year shall be applicable to the months in the Summer
Period.
The NEPOOL EHV PTF Participant Winter Wheeling Rate for any
calendar year shall be applicable to the months in the Winter
Period.
A NEPOOL Exchange Arrangement is one entered into by two
Participants each of which has an ownership interest in a
Pool-Planned Unit on its own system pursuant to which each
sells out of its ownership interest, a Unit Contract
Entitlement to the other for a period of time which is, in
whole or part, the 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 230
the same, the portion of the larger Entitlement which exceeds
the amount of the smaller Entitlement shall not be deemed to
be covered by such NEPOOL Exchange Arrangement for purposes of
this Section 17.4.
(b) Each Participant shall pay each month for its use of EHV PTF
for a transfer of an Entitlement in a Pool-Planned Unit to a
Non-Participant pursuant to Section 17.2(c) such charge as is
fixed by the Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 231
17.2 shall be paid to, and retained by, the Participant on
whose system the transfer originates, or in the event the EHV
PTF system of such Participant is supported in part by other
Participants, then to the Participant on whose system the
transfer originates and such other Participants in proportion
to the respective shares of the costs of such EHV PTF system
borne by each of them or in such other manner as the
Participants involved may jointly direct; provided that the
Participant on whose system the transfer originates shall have
the right to waive such 50% payment in whole or part as to a
particular transfer except that no such waiver may adversely
affect the payments to any other Participant which is
supporting in part the originating system's EHV PTF system.
17.5 Payments for Uses of Lower Voltage PTF. Each Participant which uses
---------------------------------------
another Participant's Lower Voltage PTF pursuant to this Section 17
shall pay each month to the owner of such Lower Voltage PTF (1) for
each Kilowatt of its use of such Lower 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 232
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; except that the requirements for such payments shall
terminate on March 1, 1999 for Participants receiving network service
under both the Tariff and applicable Local Network Service Tariff.
17.6 Use of Other Transmission Facilities by Participants. For the period to
----------------------------------------------------
and including February 28, 1999, 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 233
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.
SECTION 17A
TRANSMISSION OWNERS RESERVED RIGHTS
-----------------------------------
Notwithstanding any other provision of this Agreement, or any other
agreement or amendment made in connection with the restructuring of NEPOOL, each
Transmission Owner shall retain all of the rights set forth in this Section 17A;
provided, however, that such rights shall be exercised in a manner consistent
with the Transmission Owner's rights and obligations under the Federal Power Act
and the Commission's rules and regulations thereunder.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 234
17A.1 Each Transmission Owner shall have the right at any time unilaterally
to file pursuant to Section 205 of the Federal Power Act to change the
revenue requirements underlying its component of the rates for service
under the NEPOOL Tariff and the transmission-related provisions of this
Agreement.
17A.2 Nothing in this Agreement shall restrict any rights, to the extent such
rights exist: (a) of Transmission Owners that are parties to a merger,
acquisition or other restructuring transaction to make a filing under
Section 205 of the Federal Power Act with respect to the reallocation
or redistribution of revenues among such Transmission Owners; or (b) of
any Transmission Owner to terminate its participation in NEPOOL
pursuant to Section 21.2 of this Agreement, notwithstanding any effect
its withdrawal from NEPOOL may have on the distribution of transmission
revenues among other Transmission Owners. Further, nothing in this
Agreement shall be interpreted to permit the adoption of a rate design
change that is inconsistent with any settlement under the Tariff
accepted by the Commission without the consent of all signatories to
the settlement.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 235
17A.3 Each Transmission Owner retains all rights that it otherwise has
incident to its ownership of its assets, including, without limitation,
its PTF and non-PTF, including the right to build, acquire, sell,
merge, dispose of, retire, use as security, or otherwise transfer or
convey all or any part of its assets, including, without limitation,
the right, individually or collectively, to amend or terminate the
Transmission Owner's relationship with the ISO in connection with the
creation of an alternative arrangement for the ownership and/or
operation of its transmission facilities on an unbundled basis (e.g., a
transmission company), subject to necessary regulatory approvals and to
any approvals required under applicable provisions of this Agreement.
This section is not intended to reduce or limit any other rights of a
Transmission Owner as a signatory to this Agreement.
17A.4 The obligation of any Transmission Owner to expand or modify its
transmission facilities in accordance with the Tariff shall be subject
to the Transmission Owners' right to recover, pursuant to appropriate
financial arrangements contained in Commission-accepted tariffs or
agreements, all reasonably incurred costs, plus a reasonable return on
investment, associated with constructing and owning or financing such
expansions or modifications to its facilities.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 236
17A.5 Each Transmission Owner shall have the right to adopt and implement
procedures it deems necessary to protect its electric facilities from
physical damage or to prevent injury or damage to persons or property.
17A.6 Each Transmission Owner retains the right to take whatever actions it
deems necessary to fulfill its obligations under local, state or
federal law.
17A.7 In addition to having the rights reserved under other provisions of
this Section 17A, all Participants retain the right to take any
position before the Commission, and any appellate court with
jurisdiction to review a Commission determination, or to seek a
determination by the Commission, regarding whether, and the extent to
which, the Transmission Owners may retain the exclusive right to make
unilateral filings under Section 205 of the Federal Power Act to amend
the Tariff and the transmission related provisions of this Agreement.
If and to the extent the Commission rules that the Transmission Owners
do not retain such rights, then any such amendment that is not subject
to any of Section 17A.1 through 17A.6 may be filed with the Commission
only upon the approval by the Participants Committee of the amendment
under Section 6.11, including Section 6.11(d). If and to the extent
the Commission
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 237
rules that the Transmission Owners do retain such rights, then the
Transmission Owners, acting through the Transmission Owners Committee,
shall have the exclusive right to make unilateral filings under Section
205 of the Federal Power Act to amend the Tariff and the
transmission-related provisions of this Agreement, other than filings
subject to Sections 17A.1 or 17A.2.
17A.8(a) Notwithstanding anything to the contrary in this Agreement, the
rights of each Participant under the Federal Power Act shall be
preserved.
(b) Any dispute over whether a matter falls within the scope of any of
the rights reserved under this Section 17A will be subject to
resolution pursuant to Section 11.A.
(c) No amendment to any provision of this Section 17A or Section 11B
may be adopted without the agreement of the Transmission Owners
specified in Section 11B.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 238
(d) Any agreement entered into between NEPOOL and a System Operator
shall require the System Operator to respect the rights reserved under
this Section 17A.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 239
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
--------------------------------------
18.1 Designation of Pool-Planned Facilities. At the request of a
--------------------------------------------
Participant, the Participants Committee shall designate as
"pool-planned" a generating or transmission facility to be constructed
by the Participant or its Related Person if the Participants Committee
determines that the facility is consistent with NEPOOL planning. The
Participants 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.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 240
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 Participants 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 Participants 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
Participants Committee may determine to be required in order to
maintain proper frequency for the interconnected bulk power system of
the Participants and to maintain proper power flows into and out of the
NEPOOL Control Area.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 241
18.4 Review of Participant's Proposed Plans. Each Participant shall submit
---------------------------------------
to the System Operator, Participants Committee, the Reliability
Committee, and the Markets Committee or the Tariff Committee, as
appropriate, for review by them, in such form, manner and detail as the
Participants Committee may reasonably prescribe, (i) any new or
materially changed plan for additions to, retirements of, or changes in
the capacity of any supply and demand-side resources or transmission
facilities rated 69 kV or above subject to control of such Participant,
and (ii) any new or materially changed plan for any other action to be
taken by the Participant which may have a significant effect on the
stability, reliability or operating characteristics of its system or
the system of any other Participant. No significant action (other than
preliminary engineering action) leading toward implementation of any
such new or changed plan shall be taken earlier than sixty days (or
ninety days, if the System Operator or the Participants 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
Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 242
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 Participants Committee and the
Participant required to submit the plan.
18.5 Participant to Avoid Adverse Effect. If the Participants Committee
-------------------------------------
notifies a Participant pursuant to Section 18.4 that implementation of
the Participant's plan has been determined to have a significant
adverse effect upon the reliability or operating characteristics of its
system or the systems of one or more other Participants, the
Participant shall not proceed to implement such plan unless the
Participant 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 Participants 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 Participants Committee to
address the adverse effects on reliability or operating
characteristics, the negotiations either address the adverse effects to
the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 243
satisfaction of the Participants Committee, or no satisfactory
resolution can be achieved on terms acceptable to the parties within 90
days of the Participant's receipt of the Participants Committee's
notice. Any agreement resulting from such negotiations shall be in
writing and shall be filed in accordance with the Commission's filing
requirements if it requires any payment.
SECTION 19
EXPENSES
--------
19.1 Annual Fee. Each Participant shall pay to NEPOOL in January of each
----------
year an annual fee, which shall be applied toward NEPOOL expenses, as
follows:
(a) Each End User Participant which is a non-profit residential or
small business consumer, or non-profit group representing such
entities, shall pay an annual fee of $500.
(b) Each End User Participant, other than non-profit residential
or small business consumers or non-profit groups representing
such entities, shall pay an annual fee of $500; plus an
----
additional fee of $500 per megawatt
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 244
hour of its highest Energy use during any hour in the
preceding year (net of any use of on-site generation) up to a
maximum of $5,000; plus an additional fee of $200 per megawatt
hour for each megawatt hour by which its highest Energy use
during any hour in the preceding year (net of any use of
on-site generation during such hour) exceeded 20 megawatt
hours.
(c) Each Participant which is a Publicly Owned Entity and a member
of the Publicly Owned Entity Sector shall pay an annual fee of
$5,000, except that any such Participant which is engaged in
electricity distribution and had annual Energy sales of less
than 30,000 megawatt hours in the preceding year shall pay an
annual fee of $500, and the difference between $5,000 and $500
for each such Participant shall be paid, as an additional
fee, by the remaining Participants which are Publicly Owned
Entities and members of the Publicly Owned Entity Sector.
(d) Each Participant other than an End User Participant or a
Publicly Owned Entity shall pay an annual fee of $5,000.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 245
19.2 NEPOOL Expenses. Commencing on January 1, 1999, most expenses of the
----------------
System Operator are recovered by it directly from Participants and Non-
Participants under the ISO's Tariff for Transmission Dispatch and Power
Administration (the "ISO Tariff") or through direct charges for
services rendered by the ISO, and have ceased to be NEPOOL expenses. At
that time, the payment of a portion of NEPEX expenses from the Savings
Fund in accordance with the Prior NEPOOL Agreement also terminated.
Further, commencing on January 1, 1999 through June 30, 1999, the
balance of NEPOOL expenses remaining to be paid after the application
of (i) the annual fee to be paid pursuant to Section 19.1 and (ii) any
fees or other charges for services or other revenues received by
NEPOOL, or collected on its behalf by the System Operator, shall,
except as otherwise provided in Section 19.3, be allocated among and
paid monthly by the Participants in accordance with their respective
voting shares, as determined in accordance with the Agreement
provisions in effect during such period.
Commencing as of July 1, 1999, such balance of NEPOOL expenses for July
and subsequent months shall be divided equally into as many shares as
there are active
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 246
Sectors pursuant to Sector 6.2 (other than an End User Sector) and each
Sector's share shall be paid monthly by the Participants in each such
Sector (other than an End User Sector) in such manner as the
Participants in each Sector may determine by unanimous vote and advise
the ISO, provided that if the Participants in a Sector fail to agree
unanimously on the allocation of their Sector's share, the Participants
in the Sector shall pay for such Sector share in the same proportion as
the vote they are entitled to in the Sector. Participants in the Sector
that are represented by a group voting member shall subdivide their
portion of the Sector's share of expenses in such a manner as they may
determine by unanimous agreement; provided that if there is not
unanimous agreement among the Participants represented by a group
member as to how to allocate their portion of the Sector's share of
expenses, such portion shall be allocated among the Participants
represented by that group member as follows: (i) for each Participant
in the Generation Sector represented by a group voting member, the
portion will be allocated in the same proportion that the Megawatts of
generation owned by the Participants represents of the total Megawatts
owned by Participants represented by the group voting member; and (ii)
for Participants in the Transmission Sector, the portion will be
allocated equally among the Participants represented by the group
member. Notwithstanding the foregoing, no portion of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 247
such balance shall be paid by End User Participants and, until such
time as an End User Sector is activated, the monthly share allocated to
the Publicly Owned Entity Sector shall be reduced by one-twelfth of the
aggregate annual fees paid by End Users for the year pursuant to
Section 19.1 and one-third of the amount of such reduction shall be
allocated to each of the other three Sectors.
19.3 Restructuring Costs.
-------------------
(a) 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, (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, and (iv) capital expenditures and
capitalized project costs of the Independent System Operator,
shall be funded (to the extent not already funded) and
amortized according to this Section 19.3.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 248
(b) The Restructuring Expense incurred (other than certain capital
expenditures and capitalized project costs funded separately
by the ISO) before the Second Effective Date (the "Early
Restructuring Expense") has been funded during the period
prior to such date by those entities which have been the
Participants during such period. Commencing at the Second
Effective Date, the Early Restructuring Expense shall be
amortized in equal monthly amounts and repaid 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 Early Restructuring
Expense, plus accumulated interest, and each Participant or
other Entity which previously paid an unreimbursed portion of
the aggregate Early 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 i
accordance with the following formulas:
A
X = -- in which
A1
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 249
X is the percentage to be paid for a month by
a Participant of the aggregate amount
payable pursuant to this subsection (b) by
all Participants for the month.
A is the amount payable by the Participant for
the month under Schedule 2 (Energy
Administration Services) of the ISO Tariff
(as defined in Section 19.2) as amended or
revised from time to time.
A1 is the aggregate amount payable by all
Participants for the month under Schedule 2
(Energy Administration Services) of the ISO
Tariff as amended or revised from time to
time.
Y = B
-- 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 subsection (b) by all Participants or
other Entities for the month.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 250
B is the amount of Early Restructuring Expense
paid by the Participant or other Entity
which has not previously been reimbursed.
B1 is the aggregate amount of Early
Restructuring Expense paid by all
Participants and other Entities which has
not previously been reimbursed.
(c) The Restructuring Expense incurred on the Second Effective
Date and to but not including January 1, 2000 or thereafter
shall be funded each month by the Participants in proportion
to the Member Fixed Voting Shares (as defined in Section
6.9(c)) of each Participant as in effect at the beginning of
the month provided, however, that in calculating the
allocation of this portion of the Restructuring Expense, the
Member Fixed Voting Shares of End User Participants tha
participate in NEPOOL for governance purposes only in
accordance with NEPOOL's Standard Membership Conditions,
Waivers and Reminders ("Governance Only End User
Participants") shall not be included in such calculations and
the amounts that would otherwise have been
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 251
payable by such Governance Only End User Participants will be
allocated to all of the other Participants on the basis of
their Member Fixed Voting Shares.
(d) The Restructuring Expense incurred on or after January 1, 2000
(the"Late Restructuring Expense") shall initially be funded
for each month, on an as incurred basis, by the Participants
in proportion to their charges under the ISO Tariff for the
prior month. The aggregate Late Restructuring Expense funded
in any calendar year shall be amortized in equal monthly
amounts and repaid over the next 60 months, commencing
in January of the immediately succeeding calendar year, with
interest thereon from the date of payment at the rate equal to
the average Weighted Costs of Capital of all Transmission
Providers in effect on October 20, 1999 (without subsequent
adjustment) determined pursuant to Section II(A)(2)(a) of the
Implementation Rule for Calculating Annual Transmission
Revenue Requirements filed as a supplement to the Tariff.
Thus, for example, the Late Restructuring Expense incurred in
2000 will be amortized and repaid over a 60-month period
commencing in January 2001. Each month during the applicable
amortization period each
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 252
Participant shall pay its share of the portion of the Late
Restructuring Expense being amortized during such period, plus
accumulated interest, and each Participant or other Entity
which previously paid an unreimbursed portion of the aggregate
Late Restructuring Expense being amortized during such period
shall be entitled to receive its share of the aggregate amount
paid for such month, including accumulated interest, according
to an allocation methodology that is based on the appropriate
schedules of the ISO Tariff, which allocation methodology will
be established under subsection (e) below.
(e) The Participants agree to amend the Agreement within twelve
months after the Second Effective Date to specify how the
balance of the Early Restructuring Expense is to be paid. The
Participants agree to amend the Agreement by November 1, 2000
to provide for the amortization and repayment of the Late
Restructuring Expense, according to an allocation methodology
that is based on the appropriate schedules of the ISO Tariff
as approved by the Commission.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 253
(f) The funding methodology set forth in subsection (d) shall
terminate automatically upon the implementation of a permanent
restructuring funding methodology acceptable to the
Participants Committee and the ISO, to the extent superseded
by such permanent restructuring funding methodology.
SECTION 20
INDEPENDENT SYSTEM OPERATOR
---------------------------
(a) The Participants 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 and the
administration of the Tariff. In addition, the ISO shall be
responsible for the furnishing of billing and other services
required by NEPOOL.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 254
(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 expenditures and capitalized
project 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
Participants Committee. All such land, structures, fixtures,
equipment
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 255
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 Participants Committee. For those Participants
subject to the Public Utility Holding Company Act of 1935
("PUHCA"), any such acquisition by those Participants is
subject to PUHCA approval to the extent such acquisition
requires approval under PUHCA. Unless otherwise agreed by the
Participants, the funding of the acquisition, or lease, of
land, structures, fixtures, equipment and facilities, and
other capital and/or capitalized project related expenditures,
or the acquisition of other assets, and the ownership thereof,
or the obligations of Participants as lessees, shall be in
accordance with Section 19.3 of this Agreement. 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 256
maintain and care for, insure as appropriate, and pay any
property taxes relating to, assets made available for its use.
(e) The ISO Agreement shall require the ISO to refrain from any
action that would create any lien, security interest or
encumbrance of any kind upon the facilities, equipment or
other assets of any Participant, or upon anything that becomes
affixed to such facilities, equipment or other assets. The
Participants and the ISO shall include in the ISO Agreement
a provision that, upon the request of any Participant, the ISO
shall (i) provide a written statement that it has taken no
action that would create any such lien, security interest or
encumbrance, and (ii) take all actions within the control of
the ISO, at the direction and expense of the requesting
Participant, required for compliance by such Participant with
the provisions of its mortgage relating to such facilities,
equipment or other assets.
(f) The ISO shall have the right to appoint a non-voting member
and an alternate to each NEPOOL committee other than the
Participants
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 257
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 Participants Committee any action taken by any other
NEPOOL committee, and shall be entitled to appear before the
Participants Committee on any such appeal. Further, the ISO
shall be entitled to submit any dispute with respect to a vote
of the Participants 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 Participants Committee which denies an appeal
to the Participants 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 Participants
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 Participants Committee within ten days of the action of
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 258
the Participants Committee and shall mail a copy of such
notice to each member of the Participants 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 Participants Committee's action. Unless the Board
of Directors of the ISO acts within 60 days of the ISO's
notice to the Participants Committee, the Participants
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 259
and 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.
(j) Appointment of Technical Committee Officers. The System
-------------------------------------------
Operator shall, after its chief executive officer has
conferred with the Participant members of the Liaison
Committee regarding such appointment(s), appoint the Chair and
Secretary of each of the Technical Committees. Each individual
appointed by the System Operator shall be an independent
person not affiliated with any Participant. Before appointing
an individual to the position of Chair or Secretary, the
System Operator shall notify the Committee to which such
officer is being appointed of the proposed assignment and,
consistent with its personnel practices, provide any other
information about the individual reasonably requested by the
Committee. In the event that a Technical
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 260
Committee determines that the performance of the Chair or
Secretary of the Committee is not satisfactory, the Committee
shall provide notice to the System Operator that such
performance deficiencies must be corrected within 60 days. If
the Committee determines that the performance deficiencies
have not been corrected within the 60-day period, the
Committee may vote to remove the officer, subject to appeal to
the Participants Committee. A vote of the Technical Committee
to remove its officer shall be immediately effective and
binding on the System Operator and shall cause the System
Operator to appoint a replacement officer in accordance with
the provisions of this Section 20(j) unless an appeal to the
Participants Committee has been taken prior to the end of the
tenth business day following the vote to remove the officer in
which case the vote for removal shall be subject to the
outcome of such appeal. A vote of the Participants Committee
with respect to any such appeal shall be immediately effective
and binding on the System Operator and not subject to any
further appeals.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 261
SECTION 21
MISCELLANEOUS PROVISIONS
------------------------
21.1 Alternative Dispute Resolution.
------------------------------
A. General:
-------
If the ISO is aggrieved by a vote of the Participants
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 Participants Committee is
aggrieved by an action of the ISO Board of Directors ("ISO
Board") under this Agreement, including the Tariff or the ISO
Agreement (as defined in Section 20(a)), the Participants
Committee may submit the matter for resolution hereunder;
provided, however, that if the action of the ISO relates to
rulemaking, the Participants 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 Participants Committee to approve, modify or
reject a proposed action under this Agreement, including the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 262
Tariff, may, as provided below, submit the matter for
resolution hereunder if the vote:
(1) requires such Participant to make a payment or to
take any action pursuant to this Agreement; or
(2) reduces the amount of any receipt or forbids,
pursuant to this Agreement, the taking of any action
by the Participant; or
(3) fails to afford it any right to which it is entitled
under the provisions of this Agreement or imposes on
it a burden to which it is not subject under the
provisions of this Agreement; or
(4) results in the termination of the Participant's
status as a Participant or imposes any penalty on the
Participant; or
(5) results in an allocation of transmission or other
facilities support obligations; or
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 263
(6) fails to grant in full an application for
transmission service pursuant to the Tariff.
No legal or regulatory proceeding (except those reasonably
necessary to toll statutes of limitations, claims for laches
or other bars to later legal or regulatory action) shall be
initiated by any Participant with respect to any such matter
while proceedings are pending under this Section with respect
to the matter.
B. Procedure:
---------
(1) Submission of a Dispute: The ISO or a Participant
-------------------------
seeking review of a vote of the Participants
Committee shall give written notice to the Secretary
of the Participants Committee within ten business
days of the vote, and shall mail or telecopy a copy
of its notice to each member of the Participants
Committee. Where the Participants Committee is
seeking review of an action of the ISO Board, the
Participants Committee shall give written notice to
the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 264
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 Participants Committee pursuant to this
Section, the vote to be reviewed shall be suspended
pending resolution of such review by the arbitrator
or the Commission if raised in regulatory
proceedings. If a Participant seeks such a review,
the vote to be reviewed shall be suspended for up to
90 days following the giving of the Participant's
notice pending resolution of any arbitration
proceeding unless the Participants 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 Participants Committee, the
Aggrieved Party's notice to the Participants
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
Participants
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 265
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 Participants
Committee and the Aggrieved Party. Notwithstanding
the initiation of mediation, the arbitration
proceeding shall proceed concurrently with the
selection of the arbitrator pursuant to paragraph
C(1) of this Section 21.1.
(ii) If the notice is to seek review of an ISO action, the
Participants 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 Participants Committee's
right to proceed with the arbitration if mediation
does not resolve the matter within 20 days of the
giving of the Participants Committee's notice or such
longer period as may be fixed by mutual agreement of
the ISO Board
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 266
and the Participants 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.
(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 Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 267
agreements by the ISO or the aggrieved Participant
and the Participants 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 Participants
Committee shall attempt to choose by mutual
agreement a single neutral arbitrator to
hear the dispute. If the ISO or the
Participant and the Participants Committee
fail to agree upon a single arbitrator
within ten calendar days of the giving of
notice of arbitration to the Secretary of
the Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 268
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 Participants 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 Participants
Committee. If a proceeding is initiated by
an aggrieved Participant, each party shall
be responsible for the following costs, if
applicable:
(i) its own costs incurred during the
arbitration process (except that
this does not preclude billing the
aggrieved Participant for its share
of NEPOOL Expenses that may include
the Participants Committee's
arbitration costs); plus
----
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 269
(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.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 270
(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 Participants
Committee will provide the arbitrator with a
copy of this Agreement and all relevant
implementing documents, a brief description
of the action being arbitrated, copies of
the minutes of all NEPOOL committee meetings
at which the matter was discussed, a brief
statement explaining why the Participants
Committee believes its decision should be
upheld by the arbitrator, and copies of any
documents or other materials the
Participants Committee wishes the arbitrator
to review. If the Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 271
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.
(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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 272
(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 Participants Committee,
within sixty days of the initial hearing or
within ninety days of the Aggrieved Party's
initiation of arbitration, whichever occurs
first. The arbitrator shall be authorized
only to interpret and apply the provisions
of this Agreement and the arbitrator shall
have no power to modify or change the
Agreement in any manner.
(5) Effect of Arbitration Decision: The decision
------------------------------
of the arbitrator will be conclusive in a
subsequent regulatory or legal proceeding as
to the facts determined by the arbitrator
but will not be conclusive as to the law or
constitute precedent on issues of law in any
subsequent regulatory or legal proceedings.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 273
An aggrieved party may initiate a proceeding with a
court or with the Commission with respect to the
arbitration or arbitrator's decision only:
o if the arbitration process does not
result in a decision within the time
period specified and the proceeding
is initiated within thirty days
after the expiration of such time
period; or
o on the grounds specified in Sections
10 and 11 of Title 9 of the United
States Code for judicial vacation or
modification of an arbitration award
and the proceeding is initiated
within thirty days of the issuance
of the arbitrator's decision.
(6) Other Disputes: In the event a dispute
--------------
arises with a Non-Participant which receives
or is eligible to receive service under this
Agreement or the Tariff with respect to such
service, the Non-Participant shall have the
right to have
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 274
the dispute considered by the Participants
Committee. In the event the Non-Participant
is aggrieved by the Participants 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 Participants 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 275
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 Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 276
of creditors, the Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 277
by NEPOOL, or by the ISO on behalf of NEPOOL, or the
Participant fails to perform any other obligation under the
Agreement or the Tariff, and such failure continues for at
least ten days, NEPOOL may notify the Participant that it is
in default and may initiate a proceeding before the Commission
to terminate such Participant's 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 278
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
incurred 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 Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 279
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 Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 280
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 Participants
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 Participants Committee. Any such waiver
by the Participants 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 obligation
under this Agreement.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 281
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 282
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 Participants 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 283
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 NPCC and NERC 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. Subject to Section 17A and the provisions of this Section,
---------
this Agreement, including the Tariff, and any attachment or exhibit
hereto may be amended from time to time by vote of the Participants in
accordance with Section 6.11.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 284
Any amendment to this Agreement approved in accordance with Section
6.11 and/or Section 17A shall be in writing and shall become effective,
and shall bind all Participants regardless of whether they have
executed a ballot in favor of such amendment, on the date specified in
the amendment, subject to acceptance or approval by the Commission.
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 Agreement.
21.12 Termination. This Agreement shall continue in effect until terminated,
-----------
in accordance with the Commission's regulations, by Participants
represented by members of the Participants Committee having Member
Fixed Voting Shares equal to at least 70% of the Member Fixed Voting
Shares of all Participants. No such termination shall relieve any party
of any obligation arising prior to the effective time of such
termination.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 285
21.13 Notices to Participants, Committees, Committee Members, or the System
---------------------------------------------------------------------
Operator.
--------
(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 Participants Committee member or alternate representing
that Participant; (2) mailed, postage prepaid, to the
Participant at the address of its member on the Participants
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 Participants 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 Participants 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
Participants Committee, who shall cause such change to be
reflected in the NEPOOL roster.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 286
(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 notice, demand, request or other communication required or
authorized by this Agreement to be given to a member or
alternate to that member of a Principal Committee (for the
purposes of this Section 21.13, individually or collectively
the "Committee Member") shall be (1) personally delivered to
the Committee Member; (2) mailed, postage prepaid, to the
Committee Member at the address of the Committee Member set
out in the NEPOOL roster; (3) sent by facsimile ("faxed")
to the Committee Member at the fax number of the Committee
Member set out in the NEPOOL roster; or (4) delivered
electronically to the
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 287
Committee Member at the electronic mail address of the
Committee Member set out in the NEPOOL roster. The designation
of any such address may be changed at any time by written
notice delivered to the Secretary of the Principal Committee
on which the Committee Member serves, who shall cause such
change to be reflected in the NEPOOL roster.
(d) Any notice, demand, request or other communication required or
authorized by this Agreement to be given to the System
Operator shall be in writing, and shall be (1) personally
delivered to the Participants Committee member or alternate
appointed by the System Operator; (2) mailed, postage prepaid,
to the System Operator at the address of its member on the
Participants Committee as set out in the NEPOOL roster;
(3) sent by facsimile ("faxed") to the System Operator at the
fax number of its member on the Participants Committee as set
out in the NEPOOL roster; or (4) delivered electronically to
the System Operator at the electronic mail address of its
member on the Participants 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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 288
Secretary of the Participants Committee, who shall cause such
change to be reflected in the NEPOOL roster.
(e) To the extent that the Participants Committee is required to
serve upon any Participant a copy of any document or
correspondence filed with the Commission under the Federal
Power Act or the Commission's rules and regulations
thereunder, by or on behalf of any Principal Committee,
such service may be accomplished by electronic delivery to the
Participant at the electronic mail address of its Participants
Committee member and alternate. The designation of any such
address may be changed at any time by written notice delivered
to the Secretary of the Participants Committee.
(f) 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, Committee Member,
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 289
System Operator, or Secretary of the NEPOOL committee,
whichever is applicable.
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 290
21.15 No Third-Party Beneficiaries. Except for the provisions of this
------------------------------
Agreement and the Tariff which provide for service to Non-Participants,
this Agreement is intended to be solely for the benefit of the
Participants and their respective successors and permitted assigns and,
unless expressly stated herein, is not intended to and shall not confer
any 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 identica
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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 291
ATTACHMENT A
TO RESTATED
NEPOOL AGREEMENT
METHODOLOGY FOR
DETERMINATION OF
TRANSMISSION FLOWS
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 292
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 Reliability Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 293
B. Periodic Review
---------------
Calculations of MW-Mile allocations shall be performed whenever
significant changes to the transmission system load flows, as determined by the
Reliability Committee, 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 294
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 Reliability
Committee.
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
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 295
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 Reliability Committee.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 296
These areas shall be based on the system
boundaries of each Local Network.
b. Calculation of MW-Miles
The change in real power flow (MW) over each
transmission line and transformer shall be
determined for each combination of supply
and receipt areas by determining the
absolute value of the 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.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
<PAGE>
New England Power Pool
FERC Electric Rate Schedule No. 5, Original Revised Sheet No. 297
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 and for which there are no
arrangements in effect by which other Participants
support the facility. For facilities that are jointly
owned and/or supported, each Participant shall be
assigned MW-miles in proportion to the percentage of
its ownership of jointly-owned facilities and/or the
percentage of its support for facilities that are
jointly supported to the extent such support payments
are included in the determination of Annual
Transmission Revenue Requirements.
Issued by: David T. Doot Effective: March 1, 2000
Issued on: December 30, 1999 67269.43
EXHIBIT 10.9C
MEMORANDUM OF AGREEMENT
Pension Plan & Post-Retirement Health and Life Insurance Plans
MEMORANDUM OF AGREEMENT, made as of March 5, 1999, by and between THE
UNITED ILLUMINATING COMPANY ("the Company") and LOCAL 470-1, UTILITY WORKERS
UNION OF AMERICA, AFL-CIO ("the Union").
WHEREAS, the Company and the Union are parties to a collective
bargaining agreement dated May 16, 1997 (the "1997 Labor Contract"); and
WHEREAS, the 1997 Labor Contract contains certain provisions concerning
The United Illuminating Company Pension Plan (the "Pension Plan"), as well as
certain letter agreements concerning post-retirement health insurance and
post-retirement life insurance benefits; and
WHEREAS, the parties have in good faith negotiated certain changes to
the Pension Plan and to the post-retirement health insurance and life insurance
benefits applicable to existing employees, which changes have been ratified by
the bargaining unit; and
WHEREAS, the Company and the Union now desire to reduce to writing
their agreement concerning the negotiated changes to the Pension Plan and to the
post-retirement health insurance and life insurance benefits applicable to
current employees.
NOW THEREFORE, the parties have agreed, and do hereby agree, as
follows:
1. THE PENSION PLAN. The Company will take such action as may be
----------------
appropriate to amend the Pension Plan and obtain the approval of the U.S.
Treasury Department, for the purpose of effecting the following changes to the
Pension Plan:
(a) BENEFIT FORMULA. The pension benefit formula shall, as of
a participant's normal retirement date, be equal to one and six tenths percent
(1.6%) of the participant's final average compensation multiplied by
participant's total years of benefit service up to and including thirty (30)
years of benefit service; PROVIDED THAT such pension benefit shall not be less
than the participant's accrued benefit determined as of March 31, 1999 (or the
day prior to the Closing Date of the sale of UI's Generation assets to Wisvest
of Connecticut, LLC, if later) and frozen as of said date under the pension
benefit formula in effect immediately prior to the effective date of the current
changes to the Pension Plan.
(b) EARLY RETIREMENT BENEFITS.
(i) UNREDUCED EARLY RETIREMENT BENEFIT - RULE OF 88. Any
participant who is at least fifty-eight (58) years of age at the time
of retirement from active service, and whose combined age and years of
vesting service then equals at least eighty-eight (88), shall be
entitled to a monthly pension benefit following the participant's
actual
<PAGE>
retirement equal to the pension the participant would have been
entitled to at normal retirement date, based upon the participant's
accrued benefit at the date of actual retirement, and such benefit
shall not be reduced for early commencement.
(ii) MODIFIED EARLY RETIREMENT BENEFIT - RULE OF 88. Any
participant who retires from active employment on or after age
fifty-five (55) and before age fifty-eight (58), whose combined age and
years of vesting service then equals at least eighty-eight (88), shall
be entitled to a monthly pension before the participant's normal
retirement date, and the amount thereof shall be reduced by
four-twelfths (4/12) of one percent (1%) (i.e., 4% per year) for each
month by which the benefit commencement date precedes the participant's
fifty-eighth (58th) birthday.
(iii) ALL OTHER EARLY RETIREMENTS. Each other participant
retiring from service prior to the participant's normal retirement
date, who is at least fifty-five (55) years of age and who has at least
ten (10) years of vesting service, but who has not satisfied the Rule
of 88 under (i) or (ii) above, may commence monthly pension benefits
any time before the participant's normal retirement date and the amount
thereof shall be reduced by four-twelfths (4/12) of one percent (1%)
(i.e., 4% per year) for each month by which the benefit commencement
date precedes the participant's fifty-eighth (58th) birthday, and by an
additional three-twelfths (3/12) of one percent (1%) (i.e., 3% per
year) for each succeeding month by which the benefit commencement date
precedes the participant's sixty-fifth (65th) birthday.
(c) LUMP-SUM DISTRIBUTION. As soon as administratively practical
following termination of employment, a participant may elect, subject to
applicable spousal consent requirements, to receive the participant's accrued
benefit, otherwise payable upon the participant's normal retirement date, in the
form of an actuarially equivalent lump-sum payment. In order to be eligible for
a lump-sum distribution, a participant who has been laid off by the Company must
no longer have any recall rights.
(d) FINAL AVERAGE COMPENSATION. A participant's "Final Average
Compensation" shall be the average of the participant's annual compensation over
the three (3) highest paid calendar years of employment with the Company,
wherever occurring or, if greater, the average of the participant's monthly
compensation during the final thirty-six (36) months of employment with the
Company.
(e) GRANDFATHER PROVISIONS. The pension benefit for any participant
who, as of December 31, 1999, is (i) at least age fifty-five (55) and is
credited with at least ten (10) years of vesting service, or (ii) has a combined
number of years of vesting service and age equaling at least eighty-eight (88),
shall be the greater of:
(i) the accrued benefit calculated in accordance with the
formula set forth in paragraph 1(a) above, or;
2
<PAGE>
(ii) the participant's accrued benefit calculated in
accordance with the formula in effect as of December 31, 1998, based upon the
participant's total years of benefit service and average annual compensation as
of the date the participant retires.
(f) SURVIVOR DEATH BENEFITS. Pre-retirement death benefits under the
Pension Plan shall be payable to the participant's spouse, if the participant is
married, unless such spouse has waived his or her right to this survivor annuity
in favor of another beneficiary. If the participant is not married, the
participant may designate another beneficiary.
(g) EFFECTIVE DATE. The effective date of the foregoing changes shall
be January 1, 1999, it being understood that the accrued benefits of
participants other than those grandfathered under paragraph 1(e) shall be
determined as of March 31, 1999, and frozen as of March 31, 1999, in accordance
with the formula in effect as of December 31, 1998.
2. POST-RETIREMENT HEALTH INSURANCE.
------------------------------------
(a) The letter agreement on page 94 of the 1997 Labor Contract,
dated May 16, 1995, from Mr. Albert N. Henricksen to Mr. Gary J. Brooks, shall
be limited to those employees who retired between May 16, 1995 and May 16, 1998,
inclusive.
(b) The letter agreement on page 99 of the 1997 Labor Contract, dated
May 16, 1997, from Mr. Albert N. Henricksen to Mr. Gary J. Brooks, shall be
limited to (i) employees who retired between May 17, 1998 and December 31, 1998,
inclusive; (ii) current employees who had attained age 62 and who had ten years
of service as of December 31, 1999; and (iii) current employees whose combined
age and years of service were equal to at least eighty-eight (88) as of December
31, 1999.
(c) Except as provided in paragraph 2(b) above, the Company will make
available to current employees retiring on or after January 1, 1999 medical and
dental insurance coverage as set forth in the letter agreement attached hereto
as Appendix I.
3. POST-RETIREMENT LIFE INSURANCE.
----------------------------------
(a) Paragraph (b) of the letter agreement on page 92 of the 1997
Labor Contract, dated May 16, 1997, from Mr. Albert N. Henricksen to Mr. Gary J.
Brooks, shall be limited to those employees who retired between May 16, 1997 and
December 31, 1998, inclusive.
(b) The Company will provide fully paid life insurance in the amount of
$14,000 for current full time employees who retire on or after January 1, 1999,
who at the time of retirement are eligible for a subsidized medical benefit in
accordance with the UI Retiree Medical Cost Share Table, attached hereto as
Appendix II, and who at the time of retirement are members of the Group Life
Insurance Plan.
IN WITNESS WHEREOF, the parties have executed this agreement on the
date set forth below:
3
<PAGE>
LOCAL 470-1, UTILITY WORKERS UNION OF AMERICA, AFL-CIO
By /s/ Diane M. Diedrich Date: 04/01/1999
---------------------------- -----------
Diane M. Diedrich, President, Local 470-1, UWUA, AFL-CIO
THE UNITED ILLUMINATING COMPANY
By /s/ Albert N. Henricksen Date: 04/01/1999
---------------------------- -----------
Albert N. Henricksen, Group Vice President, Support Services
4
<PAGE>
Appendix I
April 1, 1999
Ms. Diane M. Diedrich
President
Local 470-1 U.W.U.A., AFL-CIO
P.O. Box 1497
New Haven, CT 06506
Dear Ms. Diedrich:
This will replace our prior agreement concerning post-retirement health
insurance benefits, as set forth in my letter dated May 16, 1997, with respect
to retirements occurring on or after January 1, 1999. This letter is written
pursuant to Paragraph 3(c) of our Memorandum of Agreement of even date herewith.
As we have agreed, during the term of our 1997-2002 collective
bargaining agreement, the Company will make available or furnish to retirees who
retire pursuant to the terms of the Company's Pension Plan on or after January
1, 1999, medical and dental coverage under the following conditions:
1. Retirements After Age 55 With 10 Years of Service
-------------------------------------------------
(a) For retirees who at the time of retirement are at least age 55 with at least
ten years of service, but who do not qualify for a subsidized medical benefit
per item 2 below, the Company will make available until age 65 coverage under
plans providing benefits equivalent to the Blue Cross & Blue Shield of
Connecticut BlueCare Plus POS Plan and the Blue Cross & Blue Shield of
Connecticut Dental Plan, Option B applicable to bargaining unit employees, all
at no cost to the Company.
(b) For retirees who at the time of retirement are at least age 55 with at least
ten years of service, but who do not qualify for a subsidized medical benefit
per item 2 below, the Company will make available commencing at age 65 coverage
under a Medicare supplemental plan that will provide with Medicare, if
available, benefits equivalent to the Blue Cross 65 High Option Health Insurance
Plan and Blue Shield 65-Plan 83 Health Insurance Plan at no cost to the Company.
2. Retirements After Age 55 With 30 Years of Service
-------------------------------------------------
(a) For retirees who at the time of retirement are at least age 55 with at least
30 years of service, the Company will make available until age 65 coverage under
a plan providing benefits equivalent to the Blue Cross & Blue Shield of
Connecticut BlueCare Plus POS Plan.
5
The retiree's share of the cost of such coverage, on a percentage basis, shall
be based on the retiree's years of service at the time of retirement and the
retiree's age at the time benefits commence, in accordance with the UI Retiree
Medical Cost Share Table. The Company shall pay the remaining cost of the
premiums.
(b) For retirees who at the time of retirement are at least age 55 with at least
30 years of service, the Company will furnish or make available commencing at
age 65 coverage under a Medicare supplemental plan that will provide with
Medicare, if available, benefits equivalent to the Blue Cross 65 High Option
Health Insurance Plan and Blue Shield 65-Plan 83 Health Insurance Plan. The
retiree's share of the cost of such coverage, on a percentage basis, shall be
based on the retiree's years of service at the time of retirement and the
retiree's age at the time benefits commence, in accordance with the UI Retiree
Medical Cost Share Table. The Company shall pay the remaining cost of the
premiums.
(c) For retirees who at the time of retirement are at least age 55 with at least
30 years of service, the Company will make available to such retirees until age
65 coverage under a plan providing benefits equivalent to the Blue Cross & Blue
Shield of Connecticut Dental Plan, Option B applicable to bargaining unit
employees, at no cost to the Company.
3. Retirements After Age 62 With 20 Years of Service
-------------------------------------------------
For retirees who at the time of retirement are at least age 62 with at least 20
years of service, the Company will make available the same health and dental
insurance benefits described in paragraphs 2(a) through 2(c) above on the same
terms and conditions as set forth in paragraphs 2(a) through 2(c) above.
4. Medicare Part B
---------------
(a) For employees employed by the Company as of May 16, 1992, who retire on or
after age 62 with at least 20 years of service, or after attaining age 55 with
30 or more years of service, the Company will provide, commencing with the date
of enrollment and continuing for the lifetime of the retiree, reimbursement on a
monthly basis of a portion of the monthly premium for coverage under Medicare
Part B for the retiree and any enrolled, eligible, dependents based on the
retiree's years of service at the time of retirement and the retiree's age at
the time benefits commence, in accordance with the UI Retiree Medical Cost Share
Table. The additional cost of Medicare Part B coverage, if any, shall be borne
by the retiree and the retiree's dependents, if any, in accordance with the UI
Retiree Medical Cost Share Table.
(b) Employees hired on or after May 16, 1992, shall not be entitled, upon
retirement, to any contribution by the Company for Medicare part B coverage for
themselves or their dependents.
Once a cost share for a retiree is established on a percentage basis
for a retiree under Sections 2 or 3 above, the cost share shall not change.
6
<PAGE>
The equivalent benefits described in this letter will be made available
or furnished, as the case may be, without regard to a specific carrier or
provider.
The coverages described in this letter shall be made available or
furnished only to a retiree who has the appropriate coverage in effect at the
time of retirement and who is eligible for such coverage under the terms of the
plans or policies. Further, the coverage described above requiring payment by
the retiree will be made available only to a retiree who provides for the
prepayment of the monthly premiums by authorized deduction from the retiree's
pension.
Very truly yours,
/s/ Albert N. Henricksen
------------------------
Albert N. Henricksen
Group Vice President
Support Services
7
<PAGE>
<TABLE>
<CAPTION>
RETIREE COST SHARE PERCENTAGES
S E R V I C E
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
----------------------------------------------------------------------------------------------------------------------------
55 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
56 100 100 100 100 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
57 100 100 100 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
58 100 100 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
59 100 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
A 60 100 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
G 61 100 100 100 100 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
E 62 100 100 100 100 100 50.0 47.5 45.0 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
63 100 100 100 100 100 47.5 45.0 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
64 100 100 100 100 100 45.0 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
65 100 100 100 100 100 42.5 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
66 100 100 100 100 100 40.0 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
67 100 100 100 100 100 37.5 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
68 100 100 100 100 100 35.0 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
69 100 100 100 100 100 32.5 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
70 100 100 100 100 100 30.0 27.5 25.0 22.5 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0
----------------------------------------------------------------------------------------------------------------------------
</TABLE>
EXHIBIT 10.16B
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 13th day of December, 1999, to the
Employment Agreement, made as of the 1st day of March, 1997, (the "Agreement")
between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation (the
"Company") and RITA L. BOWLBY, an individual (the "Officer").
WITNESSETH THAT:
(1) The Company and the Officer hereby agree to amend the Agreement as set
forth in sections (2), (3) and (4) below:
(2) By adding, after Section (4)(e), the following Section (4)(f):
(4)(f) Supplemental Retirement. Upon termination of the Officer's
employment, a supplemental retirement benefit shall be payable to
him or his beneficiary in accordance with the provisions of this
Section (4)(f). The annual supplemental retirement benefit,
expressed in the form of a single life annuity beginning at the
Officer's Normal Retirement Date (as defined in the Company's
Pension Plan), shall be the excess, if any, of (A) less (B),
where (A) is 1.9% (.019) of the Officer's highest three-year
average Total Compensation times the number of years at
termination (not to exceed twenty-five) of the Officer's service
as an employee of the Company plus 0.1% (.001) of the Officer's
highest three-year average Total Compensation times the number of
years at termination in excess of twenty-five (not to exceed
five) of the Officer's service as an employee of the Company, and
(B) is the benefit payable under the Company's Pension Plan.
Payment of the supplemental retirement benefit shall begin at the
same time as the Officer's Pension Plan benefit payments and
shall be subject to the same reductions for early commencement.
The supplemental retirement benefit may be paid in any form
available under the Pension Plan, as elected by the Officer prior
to benefit payment commencement. The conversion factors between
forms of benefits used for purposes of the Pension Plan shall be
used for purposes of the supplemental retirement benefit. The
form of payment of the supplemental retirement benefit may be the
same or different from the form of payment of the Officer's
benefits under the Pension Plan. If the form of payment provides
for a death benefit, such benefit shall be payable to the
Officer's estate, unless another beneficiary has been designated
by the Officer. If the Officer dies prior to the commencement of
benefit payments, the death benefit provisions of the Pension
Plan shall apply, mutatis mutandis, to the supplemental
retirement benefit payable pursuant to this Section (4)(f). The
supplemental retirement benefit shall be paid from the The United
Illuminating Company Supplemental Retirement Trust established
pursuant to the Agreement, made as of the 1st day of June, 1995
and as amended effective December 31,1995, between the Company
and State Street Bank and Trust Company, as Trustee.
(3) By substituting, in each of Sections (6)(a), (6)(b) and (6)(d)(i), for
the phrase "Sections (4)(c) and (4)(d) hereof", the phrase "Sections
(4)(c), (4)(d) and (4)(f) hereof".
<PAGE>
(4) By substituting, for Section (B) of Schedule (A), the following:
(B) The Officer's choice of the addition of six years of age, or
six years of service deemed as an employee of the Company, or any
combination (not to exceed 6) of whole and partial years of age
and whole or partial years of service deemed as an employee of
the Company, in the calculation of the benefits payable to the
Officer under the Company's retiree medical benefit plan(s) and
in the calculation of the benefits payable to the Officer as a
supplemental retirement benefit under the Officer's Employment
Agreement. The Officer may elect to commence receipt of payments
under this option at the termination of the Officer's employment
or at any time thereafter, but not prior to age 55 or later than
age 65.
(5) All the terms and conditions of the Agreement, as amended hereby, are
and shall remain in full force and effect
(6) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of
which together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of the
day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Nathaniel D. Woodson
---------------------------------------
Its Chairman of the Board of Directors,
President and Chief Executive Officer
/s/ Kurt Mohlman
----------------------------
Treasurer and Secretary
/s/ Rita L. Bowlby
---------------------------------------
Rita L. Bowlby
EXHIBIT 10.17B
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 5th day of May, 1999, to the Employment
Agreement, made as of the 1st day of March, 1997, (the "Agreement") between THE
UNITED ILLUMINATING COMPANY, a Connecticut corporation (the "Company") and
STEPHEN F. GOLDSCHMIDT, an individual (the "Executive").
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2), (3) and (4) below:
(2) By adding after the final sentence of Section (2) the following
sentence: "For purposes of this agreement, any such change in
officership position will be consistent with the Executive's abilities
and consist of duties and responsibilities comparable to those of the
officership position on the 1st day of April, 1999".
(3) By, in SCHEDULE A Section (B), deleting the first sentence and adding
in its place the following sentence: The Officer's choice of the
addition of six years of age or six years of service deemed as an
employee of the Company, or any combination (not to exceed 6) of whole
and partial years of age and whole and partial years of service as an
employee of the Company, in the calculation of a supplemental
retirement benefit payable by the Company to the Officer in an amount
equal to the excess of (A) over (B), where (A) is a retirement benefit
calculated in accordance with the Company's Pension Plan, but with the
aforesaid addition of whole and partial years of age and/or service,
and (B) is the benefit payable to the Officer under the Company's
Pension Plan, plus the Officer's choice of the addition of seven years
of age or seven years of service deemed as an employee of the Company,
or any combination (not to exceed 7) of whole and partial years of age
and whole and partial years of service as an employee of the Company,
in the calculation of the benefits payable to the Officer under the
Company's retiree medical benefit plan(s).
(4) By additionally in SCHEDULE A Section (B) adding after the final
sentence: " The supplemental retirement benefit shall be paid from the
Supplemental Retirement Benefit Trust of the Company that was
established by an agreement between the Company and State Street Bank
and Trust Company, dated as of June 1, 1995 and amended effective
December 31, 1995".
(5) All the terms and conditions of the Agreement, as amended hereby, are
and shall remain in full force and effect
<PAGE>
(6) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of
which together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as
of the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Nathaniel D. Woodson
---------------------------------------
Its Chairman of the Board of Directors,
President and Chief Executive Officer
/s/ Kurt Mohlman
-----------------------------
Treasurer and Secretary
/s/ Stephen J. Goldschmidt
---------------------------------------
Stephen J. Goldschmidt
EXHIBIT 10.19B
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 13th day of December, 1999, to the
Employment Agreement, made as of the 1st day of March, 1997, (the "Agreement")
between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation (the
"Company") and CHARLES J. PEPE, an individual (the "Officer").
WITNESSETH THAT:
(1) The Company and the Officer hereby agree to amend the Agreement as set
forth in sections (2), (3) and (4) below:
(2) By adding, after Section (4)(e), the following Section (4)(f):
(4)(f) Supplemental Retirement. Upon termination of the Officer's
employment, a supplemental retirement benefit shall be payable to
him or his beneficiary in accordance with the provisions of this
Section (4)(f). The annual supplemental retirement benefit,
expressed in the form of a single life annuity beginning at the
Officer's Normal Retirement Date (as defined in the Company's
Pension Plan), shall be the excess, if any, of (A) less (B),
where (A) is 1.9% (.019) of the Officer's highest three-year
average Total Compensation times the number of years at
termination (not to exceed twenty-five) of the Officer's service
as an employee of the Company plus 0.1% (.001) of the Officer's
highest three-year average Total Compensation times the number of
years at termination in excess of twenty-five (not to exceed
five) of the Officer's service as an employee of the Company, and
(B) is the benefit payable under the Company's Pension Plan.
Payment of the supplemental retirement benefit shall begin at the
same time as the Officer's Pension Plan benefit payments and
shall be subject to the same reductions for early commencement.
The supplemental retirement benefit may be paid in any form
available under the Pension Plan, as elected by the Officer prior
to benefit payment commencement. The conversion factors between
forms of benefits used for purposes of the Pension Plan shall be
used for purposes of the supplemental retirement benefit. The
form of payment of the supplemental retirement benefit may be the
same or different from the form of payment of the Officer's
benefits under the Pension Plan. If the form of payment provides
for a death benefit, such benefit shall be payable to the
Officer's estate, unless another beneficiary has been designated
by the Officer. If the Officer dies prior to the commencement of
benefit payments, the death benefit provisions of the Pension
Plan shall apply, mutatis mutandis, to the supplemental
retirement benefit payable pursuant to this Section (4)(f). The
supplemental retirement benefit shall be paid from the The United
Illuminating Company Supplemental Retirement Trust established
pursuant to the Agreement, made as of the 1st day of June, 1995
and as amended effective December 31,1995, between the Company
and State Street Bank and Trust Company, as Trustee.
(3) By substituting, in each of Sections (6)(a), (6)(b) and (6)(d)(i), for
the phrase "Sections (4)(c) and (4)(d) hereof", the phrase "Sections
(4)(c), (4)(d) and (4)(f) hereof".
<PAGE>
(4) By substituting, for Section (B) of Schedule (A), the following:
(B) The Officer's choice of the addition of six years of age, or
six years of service deemed as an employee of the Company, or any
combination (not to exceed 6) of whole and partial years of age
and whole or partial years of service deemed as an employee of
the Company, in the calculation of the benefits payable to the
Officer under the Company's retiree medical benefit plan(s) and
in the calculation of the benefits payable to the Officer as a
supplemental retirement benefit under the Officer's Employment
Agreement. The Officer may elect to commence receipt of payments
under this option at the termination of the Officer's employment
or at any time thereafter, but not prior to age 55 or later than
age 65.
(5) All the terms and conditions of the Agreement, as amended hereby, are
and shall remain in full force and effect
(6) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of
which together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of the
day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Nathaniel D. Woodson
---------------------------------------
Its Chairman of the Board of Directors,
President and Chief Executive Officer
/s/ Kurt Mohlman
-----------------------------------
Treasurer and Secretary
/s/ Charles J. Pepe
---------------------------------------
Charles J. Pepe
EXHIBIT 10.20B
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 13th day of December, 1999, to the
Employment Agreement, made as of the 23rd day of February, 1998,(the
"Agreement") between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation
(the "Company") and NATHANIEL D. WOODSON, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in section (2) below:
(2) Section (11) is amended by adding thereto subsections (c) and (d), as
follows:
(c) If for purposes of the excise tax imposed by Section 4999
of the Internal Revenue Code, the payments that the Executive is entitled to
receive under this Agreement, together with any other payment or distribution by
the Company to or for the benefit of the Executive (whether paid or payable or
distributed or distributable) pursuant to this Agreement or otherwise, would be
less than or equal to 3.2 times the "base amount" of the Executive's
compensation (as defined in Section 280G of the Internal Revenue Code, and not
governed by any term defined in this Agreement), any portion of such payments
that would constitute "excess parachute payments" (as defined in said Section
280G) subject to such excise tax shall be reduced to the largest amount that
will result in no portion of such excess parachute payments being subject to
such excise tax.
(d) If for purposes of the excise tax imposed by Section 4999
of the Internal Revenue Code, the payments that the Executive is entitled to
receive under this Agreement, together with any other payment or distribution by
the Company to of for the benefit of the Executive (whether paid or payable or
distributed or distributable) pursuant to this Agreement or otherwise, would be
more than 3.2 times the "base amount" of the Executive's compensation (as
defined in Section 280G of the Internal Revenue Code, and not governed by any
term defined in this Agreement), but not more than 4.0 times such "base amount,"
the Executive shall be entitled to receive an additional payment (the "Gross-Up
Payment") in an amount equal to (i) the amount of the excise tax imposed on the
Executive in respect of the payments he is entitled to receive (the "Excise
Tax"), plus (ii) all federal, state and local income, employment and excise
taxes (including any interest or penalties imposed with respect to such taxes)
imposed on the Executive in respect of the Gross-Up
<PAGE>
Payment, such that after payment of all such taxes (including any applicable
interest or penalties) on the Gross-Up Payment, the Executive retains a portion
of the Gross-Up Payment equal to the Excise Tax.
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as
of the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Albert N. Henricksen
----------------------------
Albert N. Henricksen
Its Group Vice President
Support Services
/s/ Robert L. Fiscus
---------------------------
Robert L. Fiscus
Its Treasurer and Secretary
/s/ Nathaniel D. Woodson
----------------------------
Nathaniel D. Woodson
2
EXHIBIT 10.25B
RESOLUTION ADOPTED BY THE BOARD OF DIRECTORS
OF THE UNITED ILLUMINATING COMPANY
ON DECEMBER 13, 1999
AMENDING SUBSECTION 6.01(b) OF THE
NON-EMPLOYEE DIRECTORS' COMMON STOCK
AND DEFERRED COMPENSATION PLAN
RESOLVED: That effective December 13, 1999, the first sentence of
Subsection 6.01(b) of The United Illuminating Company Non-Employee
Directors Common Stock and Deferred Compensation Plan be amended to
read as follows: (b) The number of Phantom Stock Units in a
Participant's Phantom Stock Account, including Phantom Stock Units
credited as a result of reinvested dividends, shall be calculated and,
as elected by the Participant in accordance with Subsection 6.01(c) of
the Plan: (1) Stock shall be distributed to the Participant, either in
a single distribution promptly after the date of such termination of
Service or in five or ten substantially equal annual installment
distributions (together with additional Phantom Stock Units credited as
a result of reinvested dividends) promptly after such termination date
and on each of the several anniversaries thereof; or (2) cash shall be
distributed to the Participant, either in a single distribution
promptly after the date of such termination of Service or in five or
ten substantially equal annual installment distributions (together with
interest on the undistributed amount, credited in accordance with
Subsection 5.02(a) of the Plan and payable annually, in arrears, with
each annual installment) promptly after such termination date and on
the several anniversaries thereof, in an amount equal to the value of
all of the Phantom Stock Units in the Participant's Phantom Stock
Account on such termination date, calculated by reference to the Fair
Market Value of a share of Stock on such date; or (3) cash shall be
distributed to the Participant in five or ten annual installment
distributions promptly after the date of such termination of Service
and promptly after the several anniversaries thereof in amounts equal
to the number of Phantom Stock Units in the Participant's Phantom Stock
Account on such termination date divided by the elected number of
installments (together with additional Phantom Stock Units credited as
a result of reinvested dividends following such termination date)
multiplied by the Fair Market Value of a share of Stock on such
termination date and each of the several anniversaries thereof.
<TABLE>
EXHIBIT 12
PAGE 1 OF 2
THE UNITED ILLUMINATING COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS)
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- ------
<S> <C> <C> <C> <C> <C>
EARNINGS
Net income $ 49,896 $ 39,045 $ 43,457 $ 45,072 $ 52,224
Federal income taxes 41,721 35,224 28,929 38,976 51,013
State income taxes 12,907 8,497 8,226 10,795 10,887
Fixed charges 83,994 80,097 78,016 67,871 57,915
------- ------- ------- ------- -------
Earnings available for fixed charges $188,518 $162,863 $158,628 $162,714 $172,039
======== ======== ======== ======== ========
FIXED CHARGES
Interest on long-term debt $ 63,431 $ 66,305 $ 63,063 $ 50,129 $ 42,104
Other interest 16,723 9,534 10,881 13,831 12,132
One third of rental charges 3,840 4,258 4,072 3,911 3,679
-------- -------- -------- -------- --------
$ 83,994 $ 80,097 $ 78,016 $ 67,871 $ 57,915
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED
CHARGES 2.24 2.03 2.03 2.40 2.97
======== ======== ======== ======== ========
</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>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- ------
<S> <C> <C> <C> <C> <C>
EARNINGS
Net income $ 49,896 $ 39,045 $ 43,457 $ 45,072 $52,224
Federal income taxes 41,721 35,224 28,929 38,976 51,013
State income taxes 12,907 8,497 8,226 10,795 10,887
Fixed charges 83,994 80,097 78,016 67,871 57,915
------- ------- ------- ------- -------
Earnings available for combined fixed
charges and preferred stock
dividend requirements $188,518 $162,863 $158,628 $162,714 $172,039
======== ======== ======== ======== ========
FIXED CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS
Interest on long-term debt $ 63,431 $ 66,305 $ 63,063 $ 50,129 $42,104
Other interest 16,723 9,534 10,881 13,831 12,132
One third of rental charges 3,840 4,258 4,072 3,911 3,679
Preferred stock dividend requirements (1) 2,778 699 379 428 144
-------- -------- -------- -------- --------
$ 86,772 $ 80,796 $ 78,395 $ 68,299 $ 58,059
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED
CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS 2.17 2.02 2.02 2.38 2.96
======== ======== ======== ======== ========
</TABLE>
- ------------
(1) Preferred Stock Dividends increased to reflect the pre-tax earnings required
to cover such dividend requirements.
EXHIBIT NO. 21
LIST OF SUBSIDIARIES OF
THE UNITED ILLUMINATING COMPANY
<TABLE>
<CAPTION>
STATE OR JURISDICTION
OF INCORPORATION OR NAME UNDER WHICH
NAME OF SUBSIDIARY ORGANIZATION SUBSIDIARY DOES BUSINESS
------------------ --------------------- ------------------------
<S> <C> <C>
United Funding Capital Delaware United Funding Capital
Partnership L.P. Partnership L.P.
United Resources, Inc. Connecticut United Resources, Inc.
Precision Power, Inc.* Connecticut Precision Power, Inc.
American Payment Systems, Inc.* Connecticut American Payment Systems, Inc.
United Bridgeport Energy, Inc.* Connecticut United Bridgeport Energy, Inc.
United Capital Investments, Inc.* Connecticut United Capital Investments, Inc.
Thermal Energies, Inc.** Connecticut Thermal Energies, Inc.
Precision Constructors, Inc.** Connecticut Precision Constructors, Inc.
Allan Electric Co., Inc.** New Jersey Allan Electric Co., Inc.
</TABLE>
- ----------------------
* Subsidiary of United Resources, Inc.
** Subsidiary of Precision Power, Inc.
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 521,465
<OTHER-PROPERTY-AND-INVEST> 131,847
<TOTAL-CURRENT-ASSETS> 220,126
<TOTAL-DEFERRED-CHARGES> 924,772
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,798,210
<COMMON> 282,745
<CAPITAL-SURPLUS-PAID-IN> 83
<RETAINED-EARNINGS> 175,470
<TOTAL-COMMON-STOCKHOLDERS-EQ> 458,298
0
0
<LONG-TERM-DEBT-NET> 518,228
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 17,131
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 25,000
0
<CAPITAL-LEASE-OBLIGATIONS> 16,131
<LEASES-CURRENT> 375
<OTHER-ITEMS-CAPITAL-AND-LIAB> 763,047
<TOT-CAPITALIZATION-AND-LIAB> 1,798,210
<GROSS-OPERATING-REVENUE> 679,975
<INCOME-TAX-EXPENSE> 66,564
<OTHER-OPERATING-EXPENSES> 519,856
<TOTAL-OPERATING-EXPENSES> 586,420
<OPERATING-INCOME-LOSS> 93,555
<OTHER-INCOME-NET> 4,401
<INCOME-BEFORE-INTEREST-EXPEN> 97,956
<TOTAL-INTEREST-EXPENSE> 45,732
<NET-INCOME> 52,224
66
<EARNINGS-AVAILABLE-FOR-COMM> 52,105
<COMMON-STOCK-DIVIDENDS> 40,470
<TOTAL-INTEREST-ON-BONDS> 33,204
<CASH-FLOW-OPERATIONS> 98,473
<EPS-BASIC> 3.71
<EPS-DILUTED> 3.71
</TABLE>
EXHIBIT 28.1
TABLE OF CONTENTS
CURRENT
GENERAL CPUCA NO.
Terms and Conditions 297
Purchased Power Adjustment Clause 303
RESIDENTIAL
Rate R 304
Rate A 305
Rate RT 306
Rate RHP 307
COMMERCIAL AND INDUSTRIAL
Rate GS 308
Rate GS - Special Contract 308
Rate GST 309
Rate GST - Special Contract 309
Rate TE 310
Rate TE - Special Contract 310
Rate LPT 311
Rate LPT - Special Contract 311
T & C for Non-Utility Generators 294
Rate NUS 312
Rate SG1 320
Rate SG2 321
Rider NE 159
Rider MFG 322
Rider CIHP 313
STREET LIGHTING
Rate M 314
Rate MC 315
Rate U 316
Rate MH 317
INTERRUPTIBLES
Rider LC 318
ECONOMIC DEVELOPMENT
Rider ED 319
<PAGE>
C.P.U.C.A. NO. 297
CANCELLING: C.P.U.C.A. NO. 221
THE UNITED ILLUMINATING COMPANY
TERMS AND CONDITIONS
The following Terms and Conditions are a part of all rates, where not
inconsistent with such rates, and observance of them by the Customer is a
condition necessary for initial and continuing supply of electricity by the
Company. It is not intended that these Terms and Conditions include all
necessary requirements for service.
1. "Customer" means any person, partnership, firm, company,
corporation, municipality, cooperative, organization, governmental agency or
similar organization furnished electric service by The United Illuminating
Company.
2. Wherever reference is made to electricity delivered or a payment
to be made "each month" or "per month," it shall mean the electricity delivered
in the period between two successive regular monthly meter readings or the
payment to be made for such period, or, in the case of an estimated bill, it
shall mean the electricity estimated to have been delivered in the monthly
period, based upon previous average use, or the payment to be made for such
period.
3. A Customer's Premises shall be deemed to include only those
facilities operated as a single enterprise under a single name, at a single
location capable of accepting delivery at a single point. A Customer's Premises
may include properties separated by a public street only where such Customer has
legally extended his electric service across such street, with the Company's
consent, and in conformance with the Company's construction specifications,
regulations adopted by the Connecticut Department of Public Utility Control
("DPUC") (Sections 16-11-100 through 16-11-152 of Regulations of Connecticut
State Agencies, as such may be amended from time to time), the National
Electrical Code, the National Electrical Safety Code, and the regulations of any
state or local agency with jurisdiction with respect to such facilities. Where
it is feasible for the Company to deliver separate service to a non-residential
building, or any separately wired section of a non-residential building, the
Company may, at the option of the Customer, deliver service at more than one
point, and each such building or separately wired section will be treated as an
additional "Customer's Premises."
4. Where two or more individual apartments are metered through a
single meter, the applicable Residential rate will be applied by multiplying the
Basic Service Charge by the number of such individual apartments; provided,
however, that in the case of a new apartment building, the number of individual
apartments may be reduced, during an initial six month period, by the number of
apartments, as of the end of each billing period, that have never been occupied.
For this purpose, areas with separate permanent cooking facilities in regular
use will be considered as individual apartments.
PAGE 1 OF 7
<PAGE>
5. Seasonal Residential Customers are those using electricity between
June 1st and October 31st only, or those using electricity principally between
June 1st and October 31st and incidentally or intermittently during the rest of
the year.
6. Under ordinary load conditions demand will be based upon the
Customer's fifteen minute peak, which is the average rate of delivery of
electricity during the fifteen minute period of greatest use during the month.
In the case of extremely fluctuating loads or other special condition where the
fifteen minute peak would not equitably compensate the Company, the demand will
be based upon the peak for a shorter period than fifteen minutes.
7. In the event that a Customer, due to the installation of load
management equipment or energy efficiency improvements or permanent changes in
operations or usage patterns which support conservation and load management,
does not experience full applicable rate savings because of a higher demand
registered during the time period prior to the installation of the equipment or
improvements, such Customer will receive a billing demand adjustment.
In the event that a Customer, due to the use of load management
equipment or energy efficiency improvements or permanent changes in operations
or usage patterns which support conservation and load management, experiences an
extraordinary load condition resulting in a new billing demand, but having no
significant impact on the Company's peak demand, such Customer will receive a
billing demand adjustment as set forth below. Examples of the types of operating
conditions or situations which may create an extraordinary load condition
qualifying for such adjustment include:
(a) A Customer registers a new billing demand during the initial
start-up of a system as a result, for example, of equipment or
installation problems, or testing.
(b) A Customer and UI mutually agree to a prearranged scheduled time
period, which does not coincide with a period in which UI requests
load reductions, for the Customer to perform maintenance which
results in the system operating in such a manner as to cause a new
billing demand;
(c) A Customer, despite maintaining its system in good operating
condition, experiences a new billing demand due to an unexpected
failure of a system component.
In the event that such operating conditions are repeated or are due
to a Customer's mismanagement or improper equipment maintenance, the Customer
will not qualify for a billing demand adjustment.
A Customer's request for a billing demand adjustment and the
reason(s) therefore shall be submitted to the Company, and the Company must
approve a Customer's request for the billing demand adjustment to be effective.
Any approved billing demand adjustment shall be made to the Customer's bill
within sixty (60) days of such approval.
PAGE 2 OF 7
<PAGE>
8. All requirements for a single class of service on a Customer's
Premises will be delivered at a single point except in accordance with Section 3
of these Terms and Conditions. Each point of delivery will be billed as a
separate Customer. Bills will be computed on the basis of readings of the
Company's single metering installation. Where separate delivery and metering of
single- and three-phase service to a Customer's Premises exists before April 1,
1983, and all such service is capable of delivery through a single meter if the
Customer combined his service entrance equipment, the demand and energy readings
of one single-phase meter and of one three-phase meter will continue to be
combined.
9. a) All bills shall be due and payable upon presentation. The
Company will charge $15.00 for each returned check.
b) Bills for non-residential Customers not fully paid within 28
days after mailing shall be subject to interest on the unpaid
balance at the rate of 1 1/4% per month from the mailing date
of the bill to the date payment is received at the Company's
offices or at authorized collection agencies. Bills for the
state and any political subdivision thereof shall not be
subject to this charge for the first 60 days following the
due date of such bill. The United States Postal Service is
not an authorized agent for the purposes of receiving payment
of Customers' bills.
c) Bills for residential Customers not fully paid within 28 days
after mailing shall be subject to interest on the unpaid
balance at the rate of 1 1/4% per month from the mailing date
of the bill to the date payment is received at the Company's
offices or at authorized collection agencies. The United
States Postal Service is not an authorized agent for the
purposes of receiving payment of Customers' bills.
10. Where in the Company's opinion the use of service is uniform, by
mutual agreement bills may be computed on the basis of estimated consumption,
pursuant to a tariff for unmetered service.
11. a) The Company shall have the right, in accordance with
applicable statutes and regulations of the DPUC, to
discontinue its service on due notice and to remove its
property from the Customer's Premises in the event the
Customer fails to pay any bill due the Company for such
service, or fails to perform any of his obligations to the
Company. For restoration of service after such
discontinuance a reconnection charge of $25.00 will be made
if reconnected during regular business hours. A charge of
$33.00 will be made for reconnection after 5 P.M., or on
weekends or holidays.
b) For restoration of service after discontinuation for any
reason other than failure to pay any bill due the Company, a
reconnection charge of $25.00 will be made if reconnection
is made during regular business hours, and $33.00 if
reconnection is made after 5 P.M., or on weekends or
holidays.
PAGE 3 OF 7
<PAGE>
c) Application for service in a new location, by a person who
is or has been a Customer at another location, will be
accepted only when all bills for the same class of service
to such Customer at any location have been paid or, in the
case of Residential Customers, arrangements satisfactory to
the Company for payment of such bills have been made.
12. The Company may, in accordance with applicable statutes and
regulations of the DPUC, require a cash deposit as security for prompt payment
of the Customer's indebtedness to the Company, provided that such deposit shall
be returned after twelve consecutive months of prompt payment. The Company will
pay interest upon any such cash deposit at a rate calculated in accordance with
Section 16-262j of the Connecticut General Statutes.
13. The selection of a Customer's rate is the responsibility of the
Customer. The Company makes no guarantee that the rate under which the Customer
purchases electric service is the most economic or most appropriate rate for the
Customer. The Customer may, upon request to the Company, change from the rate
under which he is purchasing electric service to any other rate for which the
Customer is eligible; provided that such change shall not be retroactive and
shall not reduce, eliminate or modify the amount due the Company from the
Customer for service received prior to the change of rate. Nor shall any such
change reduce, eliminate, or modify any contract period, provision, or guarantee
made in respect of any line extension or other special condition, nor, without
the Company's consent, cause electric service to be billed on any rate for a
period less than that specified in such rate; and provided further that a
Customer having changed from one rate to another may not again change within
twelve months without the Company's consent.
14. The Company shall make, or cause to be made, application for any
necessary street permits, and shall not be required to supply service until a
reasonable time after such permits are granted. The Customer shall obtain or
cause to be obtained all permits or certificates necessary to give the Company
or its agents access to the Customer's equipment and to enable its conductors to
be connected.
15. One span of overhead wires will be installed at the Company's
expense between the overhead wires in the street and the Customer's service
entrance wires. Additional poles and wires on private property will be furnished
and installed in conformance with Company specifications, subject to Company
approval, and paid for by the Customer. The Company will assume ownership and
maintenance of such additional poles and service wires on private property if
given written permission by the owner of the property.
16. A Customer's Premises may be connected to the Company's aerial
distribution wires through an underground connection upon payment by the
Customer of its total cost including the necessary standpipe, and such
underground connection and standpipe shall be and remain the property of the
Customer.
PAGE 4 OF 7
<PAGE>
17. The metering equipment will be furnished by the Company and
installed at a location designated by the Company. The Company will retain
ownership of the metering equipment and at any time may change its meter or may
change the location of its meter or may change from an indoor to an outdoor
metering installation.
18. a) In accordance with regulations of the DPUC, upon written
request of a Customer, the Company shall make a test of the
accuracy of the meter in use at the Customer's Premises,
provided the meter has not been verified by the Company or by
the DPUC within a period of one year previous to such request,
and provided the Customer agrees to abide by the results of
such test.
b) If a Customer requests that the meter on its Premises be
tested notwithstanding the fact that its meter had been tested
within a period of one year previous to such request, a charge
of $43.00 will be made if the meter is tested and found to be
accurate.
19. The Company shall have the right of access, subject to any
reasonable regulations of the Customer, to the Customer's Premises at all
reasonable times for the purpose of determining the quantity of electricity
consumed or delivered, or to examine or remove the Company's meters, wires,
devices and other facilities for supplying, controlling, or regulating the
supply of electricity.
20. The Customer shall not permit access for any purpose whatsoever,
except by authorized employees of the Company, to the meter or other appliances
and equipment of the Company, or interfere with the same, and shall provide for
their safe keeping. In case of loss of or damage to any property of the Company
in the custody of the Customer, the Customer shall reimburse the Company for
such loss or damage.
21. When the Company furnishes transformers:
a) Such transformers will be limited to its standard
distribution types and sizes.
b) The Company's transformers must, at all times, be at an
accessible location.
c) The Company reserves the right to designate the appropriate
size and number of transformers at a given location.
22. The Customer shall furnish and install upon its Premises such
service and meter switch or circuit breaker and appropriate protective relaying
as shall conform with specifications issued from time to time by the Company,
and the Company may seal such service and meter switch, and adjust, set and seal
such circuit breaker and relays. These seals shall not be broken and such
adjustments or settings shall not be changed or in any way interfered with by
the Customer.
PAGE 5 OF 7
<PAGE>
23. The Customer shall furnish, free of cost to the Company, upon its
Premises the necessary space and provide, in conformity with the Company's
specifications and subject to its approval, suitable foundations, supports,
housing, equipment replacement access, equipment ventilation, grounding, wiring,
conduit, and fittings for any transformers, switching arrangements, meters, and
other apparatus required in connection with the supply of electricity.
24. The Customer's wiring, conduit, apparatus and equipment shall, at
all times, conform to the requirements of all constituted authorities and to
those of the Company, and the Customer shall keep such wiring, conduit,
apparatus and equipment in proper repair.
25. Equipment having inherently low power factor or intermittent or
fluctuating demands shall not be operated by the Customer unless appropriate
facilities shall have been installed by the Customer to correct any adverse
effect from the operation of such equipment upon the Company's service to other
Customers.
26. The Company may require a Customer to guarantee a minimum annual
payment for a term of years whenever the estimated expenditures for the
equipment necessary to supply electricity to the Customer's Premises shall be of
such an amount that the income to be derived from service at the applicable
rates will, in the opinion of the Company, be insufficient to warrant such
expenditures.
27. Temporary service is service which will not continue for a
sufficient period to yield the Company adequate revenue at its regular rates to
justify the expenditures necessary to provide such service. Temporary service
will be supplied only if the Customer agrees to make such specific payment or
payments, in addition to the payments for electricity at the regular rates, as
may be reasonable and just in each case.
28. The Company shall not be required to supply service to an
establishment which obtains part or all of its electrical energy requirements
from a source other than the Company except under a rate specifically available
for such service or subject to a reasonable guarantee in respect to payment for
such service.
29. The Company will not supply service to a Customer whose wiring is
designed for resale of electricity through sub-metering, unless such
sub-metering is in compliance with regulations of the DPUC.
30. Assisted living facilities classified as "institutional" rather
than "residential" under the State Building Code that provide housing and
services and regularly provide centralized food services can be provided with a
common electric meter for each building instead of separate metering for each
living unit. These facilities must comply with the requirements stated in
Section III C.2. of the DPUC's decision in Docket No. 97-11-14.
PAGE 6 OF 7
<PAGE>
31. The Company shall not in any way be liable with respect to any
interruptions, discontinuances or reversal of its service due to causes beyond
its control, whether accident, labor difficulties, condition of fuel supply, the
action of any public authority or inability for any other reason beyond the
Company's control to maintain uninterrupted and continuous service.
32. The Company shall not be liable for injury or damage resulting
from the use of electricity or from the presence of the Company's appliances or
equipment on the Customer's Premises, except in the case of the Company's
negligence.
33. The Company shall not be liable in any respect for interruption,
discontinuance, variance or reduction of its service when the Company considers
such interruption, discontinuance, variance or reduction necessary to prevent
injury to persons or damage to property, to permit the Company to repair, change
or improve its facilities, or to maintain the electrical integrity of the
interconnected generation - transmission system of which the Company's
facilities are a part.
34. These Terms and Conditions, and each of the Company's rates and
service contracts, are subject to the jurisdiction of the DPUC and may, with its
approval, be revised, amended or supplemented from time to time pursuant to
Title 16, Chapter 277, of the General Statutes of Connecticut, revision of 1958,
as amended. Each such revision, amendment, or supplement shall, on its effective
date, become applicable to all Customers receiving service under such rate or
service contract, as the case may be.
EFFECTIVE: OCTOBER 1, 1998
PAGE 7 OF 7
<PAGE>
C.P.U.C.A. NO. 303
CANCELLING: C.P.U.C.A. NO. 287
THE UNITED ILLUMINATING COMPANY
PURCHASED POWER ADJUSTMENT CLAUSE
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA TO ALL STANDARD OFFER CUSTOMERS.
The rate per kWh shall be increased or decreased, as appropriate, in accordance
with the following formula for UI's standard offer customers. The Purchased
Power Adjustment Clause (PPAC) rate for any billing period should result from
the following calculation:
[(Current Period GSC Costs-Current Period GSC Revenues)+Prior Period Adjustment]
- --------------------------------------------------------------------------------
Projected Standard Offer GSC kWh Sales
DEFINITIONS:
Current Period = Actual costs of the power supply purchased for standard
GSC Costs offer service customers for an historical six-month
period.
Current Period = Base rate revenue component of the GSC rate times
GSC Revenues standard offer sales for the six-month period used in
the calculation of Current Period GSC Costs. The base
rate revenue component of the GSC consists of the
charge attributable to recover the cost of the initial
or wholesale standard offer power supply cost embedded
in the GSC rate. This value does not include that
portion of the GSC designed to recover CTA revenues.
Prior Period = Difference between projected and actual revenue recovery
Adjustment from the previous PPAC billing period.
Projected = Projected standard offer sales for the upcoming
Standard Offer six-month period.
GSC kWh Sales
The purchased power adjustment clause operates only if the result of the PPAC
charge or credit equals or exceeds $.00001 per kilowatt-hour.
If the cost of Standard Offer Service supply increases, the PPAC may change,
subject to the approval of the Department of Public Utility Control.
EFFECTIVE: JANUARY 1, 2000
PAGE 1 OF 1
<PAGE>
C.P.U.C.A. NO. 304
CANCELLING: C.P.U.C.A. NO. 298
THE UNITED ILLUMINATING COMPANY
RESIDENTIAL RATE R
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is for all normal residential requirements,
qualifying veterans organizations usage, and qualifying agricultural usage.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase where secondaries of the proper character exist at the
service location.
RATE PER MONTH:
Standard Offer Generation 5.0000 cents/kWhr
Competitive Transition Assessment (CTA) 1.0798 cents/kWhr
Systems Benefits Charge (SBC) 0.2446 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7443 cents/kWhr
DISTRIBUTION CHARGES:
BASIC SERVICE CHARGE: $8.55
CHARGE PER KILOWATT-HOUR:
SUMMER:
JUNE - SEPT.
0-500 3.5835 cents
Excess 500 6.6204 cents
WINTER:
OCT. - MAY
0-500 3.5835 cents
Excess 500 3.5835 cents
PAGE 1 OF 2
<PAGE>
BULK METERING FOR APARTMENTS:
Where two or more individual apartments are metered through a single
meter in accordance with Section 4 of the Company's Terms and Conditions, a
discount of:
$5.40 per month for each of the second through the tenth individual
apartments
plus
$6.08 per month for each additional individual apartment
will be applied to the Customer's Basic Service Charge.
The energy charge per month designated above as "0-500" will be
applied to all kilowatt-hours up to the product of 500 times the number of
individual apartments.
The energy charge per month designated above as "Excess 500" will be
applied solely to those kilowatt-hours in excess of the product of 500 times the
number of individual apartments.
MINIMUM BILL:
$8.55 per month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM TERM OF SERVICE:
One year.
SEASONAL SERVICE:
Seasonal Residential Customers will be supplied under this rate
provided that the Minimum Bill will be $57.60 per year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 305
CANCELLING C.P.U.C.A. NO. 299
THE UNITED ILLUMINATING COMPANY
RESIDENTIAL HEATING AND OFF-PEAK RATE A
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is for all normal residential requirements ,
qualifying veterans organizations usage, and qualifying agricultural usage (1)
where electric service is used for all space heating requirements on a
Customer's Premises, or (2) where the Customer has an electric Off-Peak storage
water heater in regular operation throughout the year as his sole source of hot
water supply, or (3) where the Customer's requirements for electric service
include loads of at least 3 kW which operate primarily during Off-Peak Hours,
and require consumption comparable to that normally resulting from space heating
or water heating qualifying under (1) or (2) for service under this rate, or (4)
where the Customer has an electric Off-Peak storage water heater in regular
operation throughout the year with supplemental water heating supplied by a
renewable energy source which shall not include coal, gas, or oil.
To qualify for service under this rate, equipment must be of a size
and design approved by the Company and must be installed in accordance with the
Company's specifications.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase where secondaries of the proper character exist at the
service location.
RATE PER MONTH:
Standard Offer Generation 4.3000 cents/kWhr
Competitive Transition Assessment (CTA) 0.3937 cents/kWhr
Systems Benefits Charge (SBC) 0.2446 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7443 cents/kWhr
PAGE 1 OF 3
<PAGE>
DISTRIBUTION CHARGES:
BASIC SERVICE CHARGE: $12.60
CHARGE PER KILOWATT-HOUR:
SUMMER
JUNE - SEPT.
On-Peak 7.2888 cents
Off-Peak 1.0765 cents
WINTER
OCT. - MAY
On-Peak 6.1606 cents
Off-Peak 1.0765 cents
BULK METERING FOR APARTMENTS:
Where two or more individual apartments are metered through a single
meter in accordance with Section 4 of the Company's Terms and Conditions, a
discount of:
$8.10 per month for each of the second through the tenth individual
apartments
plus
$9.18 per month for each additional individual apartment
will be applied to the Customer's Basic Service Charge.
OFF-PEAK HOURS:
The hours after 11 P.M. and before 7 A.M. Eastern Standard Time
(12 A.M. to 8 A.M. Daylight Savings Time) or such other eight hour period as the
Company may designate.
MINIMUM BILL:
$12.60 per month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 3
<PAGE>
MINIMUM TERM OF SERVICE:
One year.
SEASONAL SERVICE:
Seasonal Residential Customers will be supplied under this rate
provided that the Minimum Bill will be $89.10 per year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 306
CANCELLING C.P.U.C.A. NO. 300
THE UNITED ILLUMINATING COMPANY
RESIDENTIAL TIME-OF-USE RATE RT
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is optional for all individually metered
residential requirements, qualifying veterans organizations usage, and
qualifying agricultural usage subject to the availability and installation of
appropriate metering equipment.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase where secondaries of the proper character exist at the
service location.
RATE PER MONTH:
Standard Offer Generation 4.3000 cents/kWhr
Competitive Transition Assessment (CTA) 0.3983 cents/kWhr
Systems Benefits Charge (SBC) 0.2446 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7443 cents/kWhr
DISTRIBUTION CHARGES:
BASIC SERVICE CHARGE: $8.55
CHARGE PER KILOWATT-HOUR:
SUMMER JUNE - SEPT.
On-Peak 12.4119 cents
Off-Peak 2.9223 cents
PAGE 1 OF 2
<PAGE>
WINTER OCT. - MAY
On-Peak 8.6319 cents
Off-Peak 1.2519 cents
OFF-PEAK HOURS:
The hours after 8 P.M. and before 9 A.M. on weekdays, local time, and
all weekend hours.
MINIMUM BILL:
$8.55 per month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 307
CANCELLING C.P.U.C.A. NO. 301
THE UNITED ILLUMINATING COMPANY
RESIDENTIAL HEAT PUMP RATE RHP
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is available for residential customers,
qualifying veterans organizations usage, and qualifying agricultural usage whose
primary source of space heating is an electric heat pump with energy efficiency
standards at least 10 percent greater than those set by the State of Connecticut
or the highest efficiency in an equipment class at the time of installation.
This rate is closed to new customers effective July 1, 2000 and will be
terminated to existing customers effective January 1, 2004.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase where secondaries of the proper character exist at the
service location.
RATE PER MONTH:
Basic Service Charge: $9.50
ENERGY CHARGE PER KILOWATT-HOUR
SUMMER:
JUNE - SEPT.
On-Peak 14.3000 cents
Off-Peak 7.4000 cents
WINTER:
OCT - MAY
On-Peak 10.3000 cents
Off-Peak 4.9000 cents
OFF-PEAK HOURS:
The hours after 8 P.M. and before 9 A.M. weekdays, local time, and all weekend
hours.
PAGE 1 OF 2
<PAGE>
MINIMUM BILL:
$9.50 per month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above rate per month will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM TERM OF SERVICE:
One Year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 308
CANCELLING C.P.U.C.A. NO. 254
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE RATE GS
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is for all requirements on a Customer's
Premises, provided the Customer's demand does not exceed 500 Kw in two
consecutive months.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase at one standard secondary voltage as determined in
accordance with the Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter except
as may be provided in Section 7 of the Company's Terms and Conditions. When the
Company elects to meter service at primary voltage, the kilowatt-hours metered
will be reduced by 3% for billing purposes.
RATE PER MONTH:
Standard Offer Generation 4.5000 cents/kWhr
Systems Benefits Charge 0.1492 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7581 cents/kWhr
COMPETITIVE TRANSITION ASSESSMENT (CTA):
Non-Demand and Unmetered
Rate Charge Per kWhr 2.8856 cents/kWhr
Demand Rate (kW) $4.00/kW
Demand Rate Charge Per kWhr .9811 cents/kWhr
PAGE 1 OF 3
<PAGE>
DISTRIBUTION CHARGES:
Where Demand is not billed:
BASIC SERVICE CHARGE:
Unmetered $8.33
Non-Demand $9.00
CHARGE PER KILOWATT-HOUR:
SUMMER JUNE - SEPT.
Unmetered 4.8022 cents
Non-Demand 5.6662 cents
WINTER OCT. - MAY
Unmetered 4.8022 cents
Non Demand 4.2200 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $25.20
SUMMER:
Demand Charge JUNE - SEPT.
$5.00 per kilowatt
of Demand
Charge per JUNE - SEPT.
Kilowatt-hour 2.9345 cents
WINTER:
Demand Charge OCT. - MAY
$3.20 per kilowatt
of Demand
Charge per OCT. - MAY
Kilowatt-hour: 1.7300 cents
MINIMUM BILL:
The applicable Basic Service Charge but not less than $7.20 per
kilowatt of Demand.
PAGE 2 OF 3
<PAGE>
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 8 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 308 SPECIAL CONTRACT
CANCELLING C.P.U.C.A. NO. 254
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE RATE GS - SPECIAL CONTRACT
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is for all requirements on a Customer's
Premises, provided the Customer's demand does not exceed 500 Kw in two
consecutive months.
To be served under this rate a customer must have been under special
contract with this rate as the special contract base prior to 1-1-2000.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase at one standard secondary voltage as determined in
accordance with the Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter except
as may be provided in Section 7 of the Company's Terms and Conditions. When the
Company elects to meter service at primary voltage, the kilowatt-hours metered
will be reduced by 3% for billing purposes.
Where Demand is not billed:
BASIC SERVICE CHARGE:
Unmetered $ 9.25
Non Demand $10.00
PAGE 1 OF 3
<PAGE>
ENERGY CHARGE PER KILOWATT-HOUR:
SUMMER JUNE - SEPT.
Unmetered 14.4400 cents
Non Demand 15.4000 cents
WINTER OCT. - MAY
Unmetered 14.4400 cents
Non Demand 13.7100 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $28.00
SUMMER:
Demand Charge JUNE - SEPT.
$10.00 per kilowatt
of Demand
Energy Charge per JUNE - SEPT.
Kilowatt-hour 10.1353 cents
WINTER:
Demand Charge OCT. - MAY
$8.00 per kilowatt
of Demand
Energy Charge per OCT. - MAY
Kilowatt-hour: 9.0000 cents
MINIMUM BILL:
The applicable Basic Service Charge but not less than $8.00 per
kilowatt of Demand.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 3
<PAGE>
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 8 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 309
CANCELLING C.P.U.C.A. NO. 255
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE TIME-OF-USE RATE GST
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is optional for all requirements on a
Customer's Premises, subject to the availability and installation of metering
equipment.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single or three
phase at one standard secondary voltage as determined in accordance with the
Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter. When
the Company elects to meter the service at primary voltage the kilowatt-hours
metered will be reduced by 3% for billing purposes.
RATE PER MONTH:
Standard Offer Generation 4.2000 cents/kWhr
Systems Benefits Charge (SBC) 0.1172 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7581 cents/kWhr
COMPETITIVE TRANSITION ASSESSMENT (CTA):
Non-Demand Rate Charge Per kWhr 2.8464 cents/Kwhr
Demand Rate (kW) (On-Peak) $6.00
Demand Rate Charge Per kWhr 1.0153 cents
PAGE 1 OF 3
<PAGE>
DISTRIBUTION CHARGES:
Where Demand is not billed:
BASIC SERVICE CHARGE: $20.70
CHARGE PER KILOWATT-HOUR:
SUMMER JUNE - SEPT.
On-Peak Hours 7.9274 cents
Off-Peak Hours 0.8174 cents
WINTER OCT. - MAY
On-Peak Hours 2.2395 cents
Off-Peak Hours 0.500 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $35.10
SUMMER:
Demand Charge:
JUNE - SEPT.
On-peak hours $3.00 per kilowatt
Off-peak hours $1.50 per kilowatt
of Excess kW
Charge per Kilowatt-hour:
JUNE - SEPT.
On-peak hours 5.0000 cents
Off-peak hours 0.800 cents
WINTER:
Demand Charge:
OCT. - MAY
On-peak hours $1.65 per kilowatt
Off-peak hours $1.50 per kilowatt
of Excess kW
Charge per Kilowatt-hour:
OCT. - MAY
On-peak hours 3.0600 cents
Off-peak hours 0.500 cents
PAGE 2 OF 3
<PAGE>
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 8 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
The On-peak Demand will be the greatest demand registered during the
on-peak hours of the month. The Off-peak Demand will be the greatest demand
registered during the off-peak hours of the month.
DETERMINATION OF EXCESS DEMAND:
The Excess kW is the amount of kW by which the Off-peak Demand
exceeds the On-peak Demand.
OFF-PEAK HOURS:
The hours after 6 P.M. and before 10 A.M. on weekdays local time, and
all weekend hours.
MINIMUM BILL:
The applicable Basic Service Charge but not less than:
$9.00 per kilowatt of Demand for the summer months.
$7.65 per kilowatt of Demand for the winter months.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 309 SPECIAL CONTRACT
CANCELLING C.P.U.C.A. NO. 255
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE TIME-OF-USE RATE GST - SPECIAL CONTRACT
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is optional for all requirements on a
Customer's Premises, subject to the availability and installation of metering
equipment.
To be served under this rate a customer must have been under special
contract with this rate as the special contract base prior to 1-1-2000.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single or three
phase at one standard secondary voltage as determined in accordance with the
Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter. When
the Company elects to meter the service at primary voltage the kilowatt-hours
metered will be reduced by 3% for billing purposes.
Where Demand is not billed:
BASIC SERVICE CHARGE: $23.00
PAGE 1 OF 3
<PAGE>
ENERGY CHARGE PER KILOWATT-HOUR:
SUMMER JUNE - SEPT.
On-Peak Hours 17.5000 cents
Off-Peak Hours 9.6000 cents
WINTER OCT. - MAY
On-Peak Hours 16.0000 cents
Off-Peak Hours 8.0200 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $39.00
SUMMER:
Demand Charge:
JUNE - SEPT.
On-peak hours $10.00 per kilowatt
Off-peak hours $ 3.00 per kilowatt
of Excess kW
Energy Charge per Kilowatt-hour:
JUNE - SEPT.
On-peak hours 13.9000 cents
Off-peak hours 7.0000 cents
WINTER:
Demand Charge:
OCT. - MAY
On-peak hours $8.50 per kilowatt
Off-peak hours $3.00 per kilowatt
of Excess kW
Energy Charge per Kilowatt-hour:
OCT. - MAY
On-peak hours 11.3000 cents
Off-peak hours 6.3980 cents
PAGE 2 OF 3
<PAGE>
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 8 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
The On-peak Demand will be the greatest demand registered during the
on-peak hours of the month. The Off-peak Demand will be the greatest demand
registered during the off-peak hours of the month.
DETERMINATION OF EXCESS DEMAND:
The Excess kW is the amount of kW by which the Off-peak Demand
exceeds the On-peak Demand.
OFF-PEAK HOURS:
The hours after 6 P.M. and before 10 A.M. on weekdays local time, and
all weekend hours.
MINIMUM BILL:
The applicable Basic Service Charge but not less than:
$10.00 per kilowatt of Demand for the summer months.
$ 8.50 per kilowatt of Demand for the winter months.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 310
CANCELLING C.P.U.C.A. NO. 256
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE HEATING RATE TE
APPLIES ONLY TO CUSTOMERS AT PRESENT LOCATIONS TAKING SERVICE UNDER RATE TE ON
OR BEFORE FEBRUARY 1, 1990.
AVAILABILITY:
Service under this rate is for all requirements on the Premises of a
Customer where electric service is used for all energy requirements for space
heating; where electric energy use for space heating, cooking, water heating and
air conditioning is not less than one half of Customer's annual electric energy
use for all purposes; and where electrical equipment for these purposes is of a
size and design approved by the Company.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase at one standard secondary voltage as determined in
accordance with the Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter except
as may be provided in Section 7 of the Company's Terms and Conditions. When the
Company elects to meter service hereunder at primary voltage the kilowatt-hours
metered will be reduced by 3% for billing purposes.
RATE PER MONTH:
Standard Offer Generation 4.2000 cents/kWhr
Competitive Transition Assessment (CTA) 2.3733 cents/kWhr
Systems Benefits Charge (SBC) 0.1492 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7581 cents/kWhr
DISTRIBUTION CHARGES:
Where Demand is not billed:
BASIC SERVICE CHARGE: $9.00
PAGE 1 OF 3
<PAGE>
SUMMER:
Charge per JUNE - SEPT.
Kilowatt-hour: 5.8485 cents
WINTER:
Charge per OCT. - MAY
Kilowatt-hour: 3.8685 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $32.40
SUMMER:
Demand Charge: JUNE - SEPT.
$10.80 per Kilowatt
of Demand
Charge per JUNE - SEPT.
Kilowatt-hour: 1.4349 cents
WINTER:
Demand Charge: OCT. - MAY
$7.65 per Kilowatt
of Demand
Charge per OCT. - MAY
Kilowatt-hour: 0.3585 cents
MINIMUM BILL:
The applicable Basic Service Charge but not less than:
$10.80 per kilowatt of Demand for the summer months
$7.65 per kilowatt of Demand for the winter months.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 3
<PAGE>
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 10 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE:JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 310 SPECIAL CONTRACT
CANCELLING C.P.U.C.A. NO. 256
THE UNITED ILLUMINATING COMPANY
GENERAL SERVICE HEATING RATE TE - SPECIAL CONTRACT
APPLIES ONLY TO CUSTOMERS AT PRESENT LOCATIONS TAKING SERVICE UNDER RATE TE ON
OR BEFORE FEBRUARY 1, 1990.
AVAILABILITY:
Service under this rate is for all requirements on the Premises of a
Customer where electric service is used for all energy requirements for space
heating; where electric energy use for space heating, cooking, water heating and
air conditioning is not less than one half of Customer's annual electric energy
use for all purposes; and where electrical equipment for these purposes is of a
size and design approved by the Company.
To be served under this rate a customer must have been under special
contract with this rate as the special contract base prior to 1-1-2000.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, single phase or
single and three phase at one standard secondary voltage as determined in
accordance with the Company's Requirements for Electric Service.
Service will be delivered at one point through a single meter except
as may be provided in Section 7 of the Company's Terms and Conditions. When the
Company elects to meter service hereunder at primary voltage the kilowatt-hours
metered will be reduced by 3% for billing purposes.
Where Demand is not billed:
BASIC SERVICE CHARGE: $10.00
PAGE 1 OF 3
<PAGE>
SUMMER:
Energy Charge per JUNE - SEPT.
Kilowatt-hour 14.7000 cents
WINTER:
Energy Charge per OCT. - MAY
Kilowatt-hour 12.5000 cents
Where Demand is billed:
BASIC SERVICE CHARGE: $36.00
SUMMER:
Demand Charge JUNE - SEPT.
$12.00 per Kilowatt
of Demand
Energy Charge per JUNE - SEPT.
Kilowatt-hour 9.7960 cents
WINTER:
Demand Charge OCT. - MAY
$8.50 per Kilowatt
of Demand
Energy Charge per OCT. - MAY
Kilowatt-hour 8.6000 cents
MINIMUM BILL:
The applicable Basic Service Charge but not less than:
$12.00 per kilowatt of Demand for the summer months
$ 8.50 per kilowatt of Demand for the winter months.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 3
<PAGE>
DEMAND:
Where consumption exceeds 1560 kilowatt-hours per month for two
consecutive months or when the Company determines that demand will likely exceed
approximately 10 kw for any month, a demand meter will be installed. Once a
demand meter has been installed, the customer will pay the demand rate for 12
consecutive months. Thereafter, the customer will pay the demand rate when
monthly energy consumption exceeds 1560 kWh, and the customer will pay the
non-demand rate when monthly energy consumption is below 1560 kWh.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1,2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 311
CANCELLING C.P.U.C.A. NO. 258
THE UNITED ILLUMINATING COMPANY
LARGE POWER TIME-OF-USE RATE LPT
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is optional for all requirements on a
Customer's Premises, subject to availability and installation of metering
equipment.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, three phase, in
accordance with the Company's Requirements for Electric Service.
Service will ordinarily be measured through a single meter at a
primary voltage. In cases where service is measured at secondary voltage, the
kilowatt-hours metered will be increased 3% for billing purposes.
TIME PERIODS: (LOCAL TIME)
ON-PEAK 10 AM - 6 PM Weekdays
SHOULDER 7 AM - 10 AM Weekdays
6 PM - 11 PM Weekdays
OFF-PEAK 11 PM - 7 AM Weekdays
All Weekend Hours
RATE PER MONTH:
Standard Offer Generation 4.0000 cents/kWhr
Systems Benefits Charge (SBC) 0.1172 cents/kWhr
Conservation Charge 0.3000 cents/kWhr
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7581 cents/kWhr
PAGE 1 OF 3
<PAGE>
COMPETITIVE TRANSITION ASSESSMENT (CTA)
Demand Charge (KW) On-Peak $10.06/kW
DISTRIBUTION CHARGES:
BASIC SERVICE CHARGE: $202.50
DEMAND CHARGE PER KILOWATT:
SUMMER WINTER
JUNE-SEPT. OCT.-MAY
On-Peak $5.75 $4.32
Shoulder Excess 2.00 2.00
Off-Peak Excess 1.50 1.50
CHARGE PER KILOWATT-HOUR:
SUMMER WINTER
JUNE-SEPT. OCT.-MAY
On-Peak 0.8000 cents 0.6000 cents
Shoulder 0.6000 cents 0.3897 cents
Off-Peak 0.2000 cents 0.2000 cents
MINIMUM MONTHLY BILL: $202.50
DETERMINATION OF DEMAND CHARGE:
The Demand Charge for each month will be the sum of the charges
computed by applying the applicable Demand Charge Per Kilowatt to the demands as
determined in accordance with the Company's Terms and Conditions and the
following:
ON-PEAK DEMAND:
The greatest demand registered during the On-Peak hours of the month,
but not less than 80% of the On-Peak Demand in the preceding months of June
through September.
PAGE 2 OF 3
<PAGE>
SHOULDER EXCESS DEMAND:
The amount of demand by which the Shoulder Demand exceeds the On-Peak
Demand, where the Shoulder Demand is the greatest demand registered during the
Shoulder hours.
OFF-PEAK EXCESS DEMAND:
The lesser of the amount of demand by which the Off-Peak Demand
exceeds either (a) the On-Peak Demand, or (b) the Shoulder Demand, where the
Off-Peak Demand is the greatest demand registered during the Off-Peak hours of
the month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
SPECIAL PROVISION:
Where Customer's capacity requirement is 3,000 or more KVA and the
Customer provides all transformers enabling service to be delivered and metered
at a voltage of 13,800 or higher, a credit of $0.204 per kilowatt of the
greatest demand will be applied to the above rate.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
In particular, in accordance with Term and Condition No. 7, a
Customer may apply to the Company for a billing demand adjustment when
undertaking conservation and load management measures.
EFFECTIVE:JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 311 SPECIAL CONTRACT
CANCELLING C.P.U.C.A. NO. 258
THE UNITED ILLUMINATING COMPANY
LARGE POWER TIME-OF-USE RATE LPT - SPECIAL CONTRACT
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is optional for all requirements on a
Customer's Premises, subject to availability and installation of metering
equipment.
To be served under this rate a customer must have been under special
contract with this rate as the special contract base prior to 1-1-2000.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycles, three phase, in
accordance with the Company's Requirements for Electric Service.
Service will ordinarily be measured through a single meter at a
primary voltage. In cases where service is measured at secondary voltage, the
kilowatt-hours metered will be increased 3% for billing purposes.
TIME PERIODS: (LOCAL TIME)
ON-PEAK 10 AM - 6 PM Weekdays
SHOULDER 7 AM - 10 AM Weekdays
6 PM - 11 PM Weekdays
OFF-PEAK 11 PM - 7 AM Weekdays
All Weekend Hours
Rate per Month:
BASIC SERVICE CHARGE: $225.00
DEMAND CHARGE PER KILOWATT:
SUMMER WINTER
JUNE-SEPT. OCT.-MAY
On-Peak $18.00 $14.00
Shoulder Excess 9.50 7.50
Off-Peak Excess 4.00 4.00
PAGE 1 OF 3
<PAGE>
ENERGY CHARGE PER KILOWATT-HOUR:
SUMMER WINTER
JUNE-SEPT. OCT.-MAY
On-Peak 8.9000 cents 7.5000 cents
Shoulder 7.1000 cents 5.9930 cents
Off-Peak 4.4600 cents 4.4600 cents
MINIMUM MONTHLY BILL: $225.00
DETERMINATION OF DEMAND CHARGE:
The Demand Charge for each month will be the sum of the charges
computed by applying the applicable Demand Charge Per Kilowatt to the demands as
determined in accordance with the Company's Terms and Conditions and the
following:
ON-PEAK DEMAND:
The greatest demand registered during the On-Peak hours of the month,
but not less than 80% of the On-Peak Demand in the preceding months of June
through September.
SHOULDER EXCESS DEMAND:
The amount of demand by which the Shoulder Demand exceeds the On-Peak
Demand, where the Shoulder Demand is the greatest demand registered during the
Shoulder hours.
OFF-PEAK EXCESS DEMAND:
The lesser of the amount of demand by which the Off-Peak Demand
exceeds either (a) the On-Peak Demand, or (b) the Shoulder Demand, where the
Off-Peak Demand is the greatest demand registered during the Off-Peak hours of
the month.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 3
<PAGE>
SPECIAL PROVISION:
Where Customer's capacity requirement is 3,000 or more KVA and the
Customer provides all transformers enabling service to be delivered and metered
at a voltage of 13,800 or higher, a credit of $0.227 per kilowatt of the
greatest demand will be applied to the above rate.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
In particular, in accordance with Term and Condition No. 6, a
Customer may apply to the Company for a billing demand adjustment when
undertaking conservation and load management measures.
EFFECTIVE: JANUARY 1, 2000
PAGE 3 OF 3
<PAGE>
C.P.U.C.A. NO. 294
CANCELLING C.P.U.C.A. NO. 231
THE UNITED ILLUMINATING COMPANY
TERMS AND CONDITIONS
APPLICABLE TO NON-UTILITY GENERATORS
In addition to the other Terms and Conditions of the Company that may
be in effect from time to time and not inconsistent with the following, these
provisions are applicable to the class of Customers who are directly
interconnected with and normally operate their Self-Generating Facilities in
parallel with the Company's electric system for the purpose of self-generation
and/or power sales to the Company or to any other lawful purchaser.
(A) DEFINITIONS:
(1) NON-UTILITY GENERATOR - A Customer who provides all or
part of his electric energy needs from a generator owned and operated by the
Customer, who does not have a licensed agreement to sell electricity to a
franchised service area.
(2) QUALIFYING FACILITY: A facility on a Customer's Premises
meeting the standards for a Qualifying Facility under the terms of Subpart B of
Part 292 of Chapter I, Title 18, Code of Federal Regulations, or the
corresponding provisions of any successor regulations established pursuant to
Section 201 and 210 of the Public Utility Regulatory Policies Act of 1978
(PURPA), as the same may be amended from time to time, and certified as a
Qualifying Facility.
(3) FULL REQUIREMENTS SERVICE: Electric service (demand and
energy) normally supplied by the Company to a Customer for meeting the total
electric needs of the Customer.
(4) PARTIAL REQUIREMENTS SERVICE: Electric service (demand and
energy) supplied by the Company to the Customer in addition to the
interconnected source of generation to meet the needs of the Customer. Partial
Requirements Service available to the interconnected Generating Facilities
includes:
(a) BACKUP SERVICE: Electric service supplied by the
Company to a Self-Generating Facility during periods of unscheduled outages of
the Customer's generating facilities to replace power ordinarily generated by
the Customer.
PAGE 1 OF 5
<PAGE>
(b) MAINTENANCE SERVICE: Electric service supplied by
the Company to a Self-Generating Facility to replace power ordinarily generated
by the Customer during Company approved periods of scheduled outages of the
Customer's generating facilities.
(c) SUPPLEMENTAL SERVICE: Electric service supplied by
the Company to a Self-Generating Facility on a regular basis in addition to the
power generated by the Customer's generating facilities.
(5) METERING EQUIPMENT: Company approved equipment associated
with metering such as single and three phase meter troughs, manual by-pass
including, as may be required, Company approved metering transformer enclosures
and switches for metering transformers.
(6) INTERCONNECTION COSTS: All costs resulting from and
attributable to the Customer's decision to interconnect and parallel its
self-generating facilities with the Company's electric system.
(7) RENEWABLE FUEL: Wind, water, biomass or other solar
resources.
(8) FOSSIL FUEL: A non-nuclear fuel other than a Renewable Fuel.
(B) TERMS:
(1) PARALLEL OPERATION:
(a) The Customer's Self-Generating Facilities may not
be operated in parallel with the Company unless:
(i) the Customer's generating facility is
in compliance with the Company's specifications and operating guidelines as set
forth in the "Technical Requirements for Parallel Operation of Customer
Generation" (EO-3-12).
(ii) the Customer provides, at its expense, an
approved generator disconnect switch or other Company approved disconnecting
device, accessible to the Company and equipped for the Company's lock. Such
switch or device will be locked open or closed and will be operated at the sole
discretion of the Company.
(iii) the Customer allows the Company to install
metering equipment whereby the Company can meter the output of the Customer's
generating facilities.
PAGE 2 OF 5
<PAGE>
(iv) the Customer provides, at its expense,
Company approved capacitors or any such other approved equipment for generator
excitation requirements, or with the Company's approval makes other arrangements
to compensate the Company for the excitation supply.
(v) the Customer provides, at its expense,
automatic protective equipment, approved by the Company, such as, but not
limited to, over-current protection, over- and under-voltage protection, over-
and under-frequency protection, and automatic synchronization.
(vi) the Customer submits to the Company and
obtains Company approval of complete detailed drawings and one-line diagrams of
the connection of the generating equipment to be interconnected in parallel with
the Company's electric system.
(vii) the Company has accepted a signed service
agreement from the Customer for Partial Requirements Service.
(viii) the Customer has received written
authorization from the Company to operate in parallel with the Company's
electric system.
(b) The Company reserves the right to suspend parallel
operation if, in the Company's opinion, continued operation would:
(i) contribute to a system emergency.
(ii) endanger the safety of any Company employee,
any employee of a subcontractor performing work for the Company, or any other
person.
(iii) endanger the operation or physical
integrity of any equipment, conductor, device, or apparatus forming a part of,
or connected to, the Company's electric system.
(iv) adversely affect the reliability of service
provided by the Company to any other Customer.
(c) The Company may periodically inspect and test the
Customer's generating facilities to ascertain Customer's compliance with the
Company's requirements for parallel operation with the Company's electric
system. The Customer's failure to maintain compliance may result in immediate
termination of parallel operation. If parallel operation has been terminated,
resumption of parallel operation will require new written authorization from the
Company.
PAGE 3 OF 5
<PAGE>
(d) The Company shall not be liable for or with respect
to any injury or damage, or interruption, discontinuance, variance or reduction
of its service due to or resulting from the interconnection of the Customer's
generating facilities with the Company's electric system.
(2) ELECTRIC SERVICE SUPPLIED BY UI: A Customer who operates its
Generating Facility in parallel with the Company's electric system will be a
Partial Requirements Service Customer. Prior to the Company's energizing the
interconnection with a Customer's Generating Facility, the Customer will have
made application for and obtained approval to receive service under Rate NUS.
Supplemental Power Service, as described in Rate NUS, must be selected with the
amount of service designated in writing. Backup and/or Maintenance Service may
be selected as options under Rate NUS.
Rate NUS Customers who elect to take Supplemental Service on or
after January 1, 1993, shall select one of the Company's applicable time-of-use
rates for such service.
(3) NON-FIRM OR NET ENERGY SALES TO UI: Parallel operation of a
Generating Facility for the purpose of power sales to the Company or to any
other lawful purchaser is conditioned upon Company acceptance of a signed
Self-Generating Facility Option Agreement.
(4) METERING: The Company will install, own, and maintain, at the
Customer's expense, the meter(s) necessary to measure the electricity purchased
by the Company from the Customer's generating facilities. These costs shall
include those related to the installation, maintenance and reading of meter(s)
and telemetering devices, including modifications to the Customer's Metering
Equipment. In certain cases, at the Company's discretion and expense, the
Company may install Metering Equipment and meter(s) to meter such
characteristics of the Customer's generating facilities as station service and
power factor.
Meters and metering transformers required exclusively for
measuring electric service supplied by the Company to the Customer will be
provided at the Company's expense.
(5) EXCEPTIONAL INTERCONNECTION COSTS: When the sole purpose of a
Customer's interconnection with the Company's electric system is to sell
electric capacity or energy to the Company or when the Company must incur
exceptional costs to interconnect a Customer, the Company will require payment
of the interconnection costs including all taxes, or so much as is exceptional,
subject to approval by the Department of Public Utility Control (DPUC) as may be
required. If the DPUC does not disapprove of the charge within 90 days of the
Customer's written application for interconnection, the interconnection shall be
made upon payment by the Customer of this charge; however, should the DPUC later
reduce the interconnection charge, the amount of the reduction plus interest at
the current cost of the Company's long-term debt shall be refunded to the
Customer.
PAGE 4 OF 5
<PAGE>
(6) TRANSFER TO FULL REQUIREMENTS SERVICe: A Customer who
abandons or retires its generating facility and desires to transfer to Full
Requirements Service must provide the Company with written notice of such intent
at least six months prior to such transfer. Customers who take partial
requirements service in conjunction with Qualifying Facility Net Energy Rider NE
or have not contracted for Backup or Maintenance Service in the last twelve
months are exempt from these notice provisions. During the notice period, if
economic capacity becomes available, the Customer will be transferred to full
requirements service. Otherwise, interruptible service under Contract
Interruptible Rider CI will be provided.
The Customer may request the Company to purchase capacity from
other sources to meet the Customer's needs. The Customer agrees to compensate
the Company for all incremental system capacity costs that may be required in
order for the Company to provide uninterruptible Full Requirements Service to
the Customer. The Customer's obligation to provide such compensation shall begin
as of the date the Company first incurs the additional costs, subject to DPUC
approval as may be required.
Upon completion of the notice period and transfer to Full
Requirements Service, there will be no additional Customer charges for transfer.
EFFECTIVE: OCTOBER 1, 1998
PAGE 5 OF 5
<PAGE>
C.P.U.C.A. NO. 312
CANCELLING C.P.U.C.A. NO. 295
THE UNITED ILLUMINATING COMPANY
NON-UTILITY GENERATING FACILITY STANDBY RATE NUS
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is for all purposes where partial or total
electric service requirements are obtained from a Self-Generation Facility (SG)
on the Customer's Premises and interconnected with the Company's electric power
system where the Customer may require the Company's electric service to replace
that source during periods of unscheduled outages (Backup Power), scheduled
outages (Maintenance Power) or where the Customer may require the Company's
electric service to supplement (Supplemental Power) the SG source.
Any Non-Utility Customer who operates a Self-Generation Facility
interconnected with the Company's electric power system is required to take
service under this rate schedule.
The Customer may elect Backup Service only, Maintenance Service only,
Supplemental Service only, or any combination of these services.
CHARACTER OF SERVICE:
Service is alternating current, nominally 60 cycle single-phase or
three-phase, at the Company's standard voltage available.
TERMS AND CONDITIONS:
The "Terms and Conditions Applicable to Self-Generators " and other
Company Terms and Conditions, where not inconsistent with any provisions hereof,
are part of this rate.
DEFINITIONS:
"Backup Service" means electric demand and energy supplied by the
Company during an unscheduled outage of the Customer's generation to replace
demand and energy ordinarily generated by a Customer's own generation equipment.
NOTE: Backup Service is available for all outages except for
outages scheduled as Maintenance Service.
PAGE 1 OF 7
<PAGE>
"Maintenance Service" means electric demand and energy supplied by
the Company to replace demand and energy ordinarily generated by a Customer's
own generation equipment during Company approved scheduled outages only.
NOTE: When Backup Service is chosen, Maintenance Service is also
provided up to the Backup Demand level.
"Supplemental Service" means electric demand and energy supplied by
the Company on a regular basis in addition to that which is normally provided by
the Customer's own generation equipment.
DETERMINATION OF CONTRACT BACKUP DEMAND:
1. Initially, the Customer and the Company shall mutually agree upon
a maximum amount of backup demand in kW to be supplied by the Company. This
shall be termed for billing purposes as the "Contract Backup Demand." Whenever
the Contract Backup Demand is exceeded by a higher amount of Actual Backup
Demand, such greater amount becomes the new Contract Backup Demand up to the
nameplate capacity of the generator(s) and for the subsequent eleven months.
2. The Contract Backup Demand for the current billing period shall be
the greater of: (1) the mutually agreed upon Contract Backup Demand, (2) the
Contract Backup Demand determined under the preceding paragraph, or (3) the
maximum 15-minute kW backup power requirement established in the current billing
month.
3. Where a bona fide change in the Customer's backup demand
requirement occurs, the Company and the Customer shall agree upon a new Contract
Backup Demand.
DETERMINATION OF CONTRACT MAINTENANCE DEMAND:
1. Initially, the Customer and the Company shall mutually agree upon
a maximum amount of maintenance demand in kW to be supplied by the Company. This
shall be termed for billing purposes as the "Contract Maintenance Demand."
Unless otherwise requested, the minimum Contract Maintenance Demand will equal
the Contract Backup Demand. Whenever the Contract Maintenance Demand is exceeded
by a higher amount of Actual Maintenance Demand, such greater amount becomes the
new Contract Maintenance Demand up to the nameplate capacity of the generator(s)
and for the subsequent eleven months.
2. The Contract Maintenance Demand for the current billing period
shall be the greater of (1) the mutually agreed upon Contract Maintenance
Demand, (2) the Contract Maintenance Demand determined under the preceding
paragraph, or (3) the maximum 15-minute kW maintenance power requirement
established in the current billing month.
PAGE 2 OF 7
<PAGE>
3. Where a bona fide change in the Customer's maintenance demand
requirement occurs, the Company and the Customer shall agree upon a new Contract
Maintenance Demand.
DETERMINATION OF BACKUP AND MAINTENANCE SERVICE REQUIREMENTS:
1. The Customer shall notify the Company of all outages of the
Customer's generation within three business days after the end of the billing
period and the amount of demand in kW ordinarily supplied by the Customer's
generation for each 15-minute time interval of such outages.
2. For each 15-minute time interval of occurrence of an unscheduled
outage of the Customer's generation, the backup power amount shall be determined
by the following formula:
Backup power in kW =
Amount of demand in kW ordinarily supplied by Customer's
generation
minus
Customer's generation output in kW during the Customer's
unscheduled outage.
NOTE: In no event shall the backup power amount be less than zero,
nor exceed the nameplate capacity of the Customer's
generating facilities.
3. For each 15-minute time interval of occurrence of a Company
approved scheduled outage of the Customer's generation, the maintenance power
amount shall be the smaller of (1) the total Company-supplied power or (2) the
Contract Maintenance Demand.
NOTE: In no event shall the maintenance power amount be less than
zero, nor exceed the nameplate capacity of the Customer's
generating facilities.
DETERMINATION OF SUPPLEMENTAL SERVICE REQUIREMENTS:
A determination of the Customer's supplemental power use shall be
made for each 15-minute time interval of the billing period in accordance with
the following formula:
Supplemental Power in kW =
Total Company-supplied power in kW
PAGE 3 OF 7
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minus
Actual backup and/or maintenance power in kW.
NOTE: In no event shall the supplemental power amount be less than
zero.
RATE PER MONTH:
Standard Offer Generation 3.5000 cents/kWhr
Systems Benefits Charge (SBC) 0.1172 cents/kWhr
Conservation Charge 0.3000 cents/KWHR
Renewable Energy Charge 0.0500 cents/kWhr
Transmission Charge 0.7581 cents/KWHR
COMPETITIVE TRANSITION ASSESSMENT (CTA)
$0.70/kW of either contract demand or if no
present contract demand then contract
demand prior to January 1, 2000.
DISTRIBUTION CHARGES
BASIC SERVICE CHARGE:
Basic Service Charge of Applicable Rate Schedule for Supplemental
Service plus $57.60 when the Customer contracts for Backup or Maintenance
Service.
Time Periods As Applied To Backup Service:
On-Peak Periods: 10 A.M. to 6 P.M. (Eastern Standard Time)
weekdays for Demand Charges and 10 A.M. to 6 P.M. (Eastern
Standard Time) June, July, August and September weekdays for
Distribution kWh Charges.
Off-Peak Periods: All periods other than the On-Peak
Periods.
PAGE 4 OF 7
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DISTRIBUTION DEMAND CHARGE:
PER KW OF
CONTRACT
BACKUP DEMAND
Service between 115KV & 2.4 KV $2.53
Service below 2.4 KV $3.39
CHARGE PER KILOWATT-HOUR:
ON-PEAK OFF-PEAK
Service between 115 KV & 2.4 KV 2.74 cents 2.38 cents
Service below 2.4 KV 2.82 cents 2.46 cents
PURCHASED POWER ADJUSTMENT CLAUSE:
The above RATE PER MONTH will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
MINIMUM MONTHLY BILL:
The minimum monthly bill shall be the Basic Service Charge plus the
Demand Charges for Supplemental Service, plus Backup Service and Maintenance
Service when contracted.
TERM OF SERVICE:
One year, subject to limitation of availability.
Customers taking backup or maintenance service under this rate
schedule who desire to transfer to full requirements service will be required to
give the Company written notice six months prior to such transfer. Such notice
shall be irrevocable unless the Company and the Customer shall mutually agree to
void revocation. Upon fulfillment of the notice period, if the Customer desires
to continue to receive Backup and Maintenance Service, the Company may, at its
sole option, include the nameplate capacity of the Customer's Generation
Facility in that Customer's supplemental billing demand in addition to the
actual supplemental demand for a period not to exceed six months.
PAGE 5 OF 7
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Transfer, before completion of the required written notice period, to
any full requirements rate for which the Customer qualifies will be permitted if
it can be shown by the Customer and the Company that such transfer is in the
best interest of the Customer, the Company and the Company's other ratepayers.
Customers who take partial requirements service in conjunction with
Qualifying Facility Net Energy Rider NE or have not contracted for Backup or
Maintenance Service in the last twelve months are exempt from these notice
provisions.
SPECIAL PROVISIONS:
1. The Company requires that the Customer enter into a Partial
Requirements Service Agreement contract. Whenever the Customer increases his
electrical load, which increase requires the Company to increase facilities
installed for the specific use of the Customer, a new Term of Service may be
required.
2. The Company will furnish service under this rate schedule at a
single voltage. Equipment to supply additional voltages or additional facilities
for the use of the Customer shall be furnished and maintained by the Customer.
3. The Customer shall allow the Company to install time recording
metering on the electrical output of all interconnected generation equipment.
The metering location(s) must be accessible to Company personnel for testing,
inspection, maintenance, and retrieval of recorded generation output data. The
Customer shall reimburse the Company for the installed cost of the metering and
be charged 1.54% per month (18.44% per year) of the installed cost of the
metering equipment for operation and maintenance of the equipment by the
Company, provided this metering is required for billing purposes.
4. Where the Company and the Customer agree that the Customer's
service requirements are wholly backup or wholly maintenance or wholly
supplemental, the Company shall bill the Customer accordingly and not require
metering of the Customer's generation output.
Rate NUS Customers who elect to take Supplemental Service on or after
January 1, 1993, shall select one of the Company's applicable time-of-use rates
for such service.
5. In the event a Customer taking Backup or Maintenance Service does
not provide outage information to the Company within three business days of the
end of the billing period, the Company shall render a bill based on all
Company-supplied demand and energy being supplemental service. If the Customer
provides outage information for the current billing period prior to the end of
the next billing period, the Company shall issue a revised bill and assess the
Customer an additional administrative charge of $18.97.
PAGE 6 OF 7
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6. For determination of backup and maintenance service requirements,
the Customer shall maintain accurate generation performance records available
for review by the Company for verifying outage information utilized in the
billing procedure.
7. Backup Service for any single unscheduled outage is limited to 24
consecutive months. After that time all service will be billed as Supplemental
Service. After the Generation Facility has been out of service for six
consecutive months following an unscheduled outage, the Customer will provide to
the Company a monthly status letter on the progress being made to render the
Facility operational.
8. To qualify for Maintenance Power, the Customer must provide the
Company by August 1 of each year a schedule of planned maintenance outages for
the period September 1 through August 31. If any subsequent changes are made,
the Customer must notify the Company, in writing, at least 30 days prior to the
time maintenance service will be required, stating the date the Customer's
generation equipment will be taken out of service and the expected duration of
the outage.
Maintenance Power is available, subject to this notification to the
Company, during all hours in the periods October 1 through May 31, and during
the off-peak and shoulder hours of the Customer's supplemental service rate in
the period June 1 to September 30.
EFFECTIVE: JANUARY 1, 2000
PAGE 7 OF 7
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C.P.U.C.A. NO. 320
CANCELLING C.P.U.C.A. NO. 292
THE UNITED ILLUMINATING COMPANY
SELF-GENERATOR RATE SG1
AVAILABILITY: ONLY FOR BRIDGEPORT RESCO.
PURCHASE OF QUALIFYING FACILITY GENERATION:
The Company will purchase electric energy supplied to the Company from
the Bridgeport RESCO generation equipment under the provisions of the Power
Purchase Agreements between the supplier and the Company. Rate SG1 shall be 95%
of the annual average of the NEPOOL market clearing price for energy for the
preceding year.
The Company will determine the energy payment as the sum of
delivered energy for each hour in the billing period times the NEPOOL market
clearing price for energy for such hour. The hourly market clearing prices will
be subject to revision per the ISO-NE audit procedures and retroactive billing
adjustments may occur.
There shall be no capacity payment. The voltage level at which
purchases are made shall be the level at which sales are made by the Company to
the Qualifying Facility, unless otherwise agreed by the Company.
TERM OF CONTRACT:
One Year.
EFFECTIVE: JANUARY 1, 2000
PAGE 1 OF 1
<PAGE>
C.P.U.C.A. NO. 321
CANCELLING C.P.U.C.A. NO. 293
THE UNITED ILLUMINATING COMPANY
SELF-GENERATOR RATE SG2
AVAILABLE TO BLOCK 2 SELF-GENERATORS
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is available to any Block 2 Qualifying
Generating Facility interconnected to the Company's facilities for the purpose
of selling to the Company.
BASIC SERVICE CHARGE PER MONTH:
$11.73 plus 4.5% of the initial invoice cost of the metering equipment
installed to measure purchases of electricity by the Company for the Customer.
PURCHASE OF QUALIFYING FACILITY GENERATION:
Rate SG2 shall be 95% of the monthly average of the NEPOOL market
clearing prices for energy for the preceding month.
The Company will determine the energy payment as the sum of delivered
energy for each hour in the billing period times the NEPOOL market clearing
price for energy for such hour. The hourly market clearing price for energy will
be subject to revision per the ISO-NE audit procedures and retroactive billing
adjustments may occur.
There shall be no capacity payment. The voltage level at which
purchases are made shall be the level at which sales are made by the Company to
the Qualifying Facility, unless otherwise agreed by the Company.
TERM OF CONTRACT:
One Year.
TERMS AND CONDITIONS:
The "Terms and Conditions Applicable to Interconnected Qualifying
Facilities" and other Company Terms and Conditions, where not inconsistent with
any provisions hereof, are part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 1 OF 1
<PAGE>
C.P.U.C.A. NO. 159
CANCELLING C.P.U.C.A. NO. 120
THE UNITED ILLUMINATING COMPANY
QUALIFYING FACILITY NET ENERGY RIDER NE
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
This rider is available for partial requirements service where any
part of the electric service requirements are normally obtained from a
Qualifying Facility on the Customer's Premises with installed nameplate capacity
of 100 kilowatts or less if fueled by a Renewable Resource, or 50 kilowatts or
less if a Fossil Fuel is used.
METERING:
Customers electing service under this rider in conjunction with a
demand-metered supplemental service rate shall be metered by two meters, one
meter to measure supplemental service sold to the Customer and one meter to
measure kilowatt hours purchased by the Company. Customers electing service
under this rider and a non-demand metered supplemental service rate may be
metered by one meter. The appropriate meter provision(s) will be provided by the
Customer. The Company may install, at its own cost, time-differentiated meters
for load research purposes.
If the installed nameplate capacity is greater than 100 kilowatts if
fueled by a renewable resource, or greater than 50 kilowatts if a fossil fuel is
used, a Customer may elect service under this rider upon the Customer's stated
intention to limit operation to the 100 kilowatt or 50 kilowatt level as
appropriate to the fuel used, provided that the Customer installs an approved
metering provision so as to allow the Company to meter generation output. The
Customer agrees to provide the Company access to this meter during normal
Company business hours.
RATE PER MONTH:
Net Sales to Customer:
The Customer may elect any of the Company's appropriate supplemental
service rates. Kilowatt-hours purchased by the Company shall be deducted from
sales to the Customer prior to applying the rate for supplemental service in
order to determine the bill for net sales.
PAGE 1 OF 2
<PAGE>
PURCHASES FROM CUSTOMERS:
Any net output from the Qualifying Facility which exceeds sales to the
Customer on a monthly basis will be purchased by the Company under Rate SG2.
The Company will credit all amounts it owes the Customer for
purchases under this Rider against any amounts the Customer owes the Company
with respect to electric energy. Any excess credit will be paid by the Company
to the Customer.
MINIMUM TERM OF SERVICE:
One year.
TERMS AND CONDITIONS:
The "Terms and Conditions Applicable to Interconnected Qualifying
Facilities" and other Company Terms and Conditions, where not inconsistent with
any provisions hereof, are part of this rider.
EFFECTIVE: FEBRUARY 1, 1990
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 322
CANCELLING C.P.U.C.A. NO. 270
THE UNITED ILLUMINATING COMPANY
MANUFACTURER GROSS EARNINGS TAX CREDIT
RIDER MFG
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
Section 65 of Public Act 93-74, as amended, provides that for a defined class of
manufacturing customers, the gross earnings tax on the sale of electricity is
reduced from 5 percent to lower percentages, and then eliminated completely,
over a period of years. The decreases are applicable only to companies that are
included in classifications 2000 through 3999 of the Standard Industrial
Classification Manual of the United States Office of Management and Budget, 1987
Edition ("SIC Codes").
Pursuant to the 1993 statutory change, the applicable gross earnings tax rates
for electricity used directly by customers with SIC Codes in the 2000 - 3999
range are as follows:
TIME PERIOD OF ELECTRICITY USE RATE
------------------------------ ----
January 1 - December 31, 1994 4%
January 1 - December 31, 1995 3%
January 1 - December 31, 1996 2%
January 1 - 1997 and Later 0%
Rider MFG applies a credit to the bills of customers with SIC Codes in the
2000-3999 range in accordance with this legislation. The credit will appear on
affected customers' bills as "manufacturer gross earnings tax credit." The
calculation of the credit is as follows:
Total Bill minus FCA and State Tax times the Manufacturers Gross
Earnings Tax Credit factor. The Gross Earnings Tax credit factors
authorized by Public Act 93-74 are as follows:
1994 1.0417%
1995 2.0619%
1996 3.0612%
1997 through 1999 5.0000% *
2000 and Later 8.50%
Based upon Public Act 98-28 the Gross Earnings Tax becomes 8.50% effective
1-1-2000. It is applied to all components of a customer's bill except the
generation service charge.
*Special contract customers will continue to receive a tax credit of 5.0% after
1-1-2000 on their bundled bills (Re. Sections 56 and 57 of Public Act 98-28).
PAGE 1 OF 2
<PAGE>
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where not
inconsistent with any specific provisions hereof are a part of this rider. This
rider may be modified or eliminated if applicable Connecticut legislation in the
future changes the gross earnings tax rates for customers with SIC codes in the
2000-3999 range.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 313
CANCELLING C.P.U.C.A. NO. 283
THE UNITED ILLUMINATING COMPANY
COMMERCIAL AND INDUSTRIAL HEAT PUMP RIDER CIHP
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
This Rider is available to any Customer receiving service under any of
the Company's demand-metered rate schedules whose source of space heating is an
electric heat pump with energy efficiency standards equivalent to those set by
the State of Connecticut Building Energy Code, subsequent to January 1, 1990.
This Rider will be closed to new customers effective July 1, 2000 and will be
terminated to existing customers effective January 1, 2004.
DEMAND CHARGE REDUCTION:
During the period from October 15 through April 15 any customer who
qualifies for this Rider will receive a credit of $8.50 per KW (but not higher
than the applicable demand charge) off of the Customer's monthly demand charge
(for TOU customers their On-Peak Demand Charge) for the difference in the
Customer's billing demand for that month and the Customer's billing demand in
the corresponding month of the Base Period. The Base Period is the preceding
period of October 15 through April 15. The maximum KW a customer may receive
credit for is the KW equivalent of the connected load of the installed heat pump
system. Also, if the Customer is being billed on a TOU rate, any excess demand
created in the shoulder or off-peak period by the heat pump system will be
waived. Credits will be pro-rated when necessary.
For new customers who have not established a Base Period, the first
year's Base Period demand will be determined by doing an on-site inspection of
the Customer's premises during the period of October 15 through April 15 and
securing what would have been the Customer's billing demand excluding heat pump
system equipment for the hours of 10 A.M. to 6 P.M. Monday through Friday and
also for all other hours. The Customer's credit will be based on the difference
between the monthly billing demand and the determined Base Period demand.
The Company will have the right to inspect the Customer's premises to
determine if the heat pump is in regular use, and to review and adjust base
demand as required.
This Rider cannot be applied in conjunction with any other Rider the
Company may offer for energy efficient installations.
PAGE 1 OF 2
<PAGE>
TERMS AND CONDITIONS:
A New Customer is defined as the owner or occupant of a premises who
has not been a Customer in the same premises during the previous months of
October through April as determined by the Company. An existing Customer is
defined as the owner or occupant of a premises who has received service at the
same premises under any of the Company's rate schedules during the previous
months of October through April.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO. 314
CANCELLING C.P.U.C.A. NO. 260
THE UNITED ILLUMINATING COMPANY
STREET AND SECURITY LIGHTING RATE M
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is available for any town, city or municipal
subdivision, or to any other Customer, except that no new installations of
mercury vapor lighting will be made for offstreet lighting.
INSTALLATION:
The Company will furnish and maintain its standard equipment
necessary for supplying this service.
Where one or more wood poles must be installed in order to effect
service, the Customer will make a one-time payment of $574.22 per pole and is
responsible thereafter for the cost of any subsequent replacement poles.
Alternatively, the Customer may pay a monthly charge of $13.17 per pole.
Where an overhead service pole is installed at a location more than
one span distant from the Company's overhead distribution facilities, or an
underground service ornamental pole is installed at a location more than 150
feet distant from the Company's underground distribution facilities, or an
underground service low post fixture is installed at a location more than 50
feet distant from the Company's underground distribution facilities, the
Customer will be required to reimburse the Company for the installation cost
attributable to such excess distance.
Where underground service to low post fixtures is not installed
concurrently with the installation of underground distribution facilities, the
Customer is responsible for reimbursing the Company for all trenching,
back-filling and resurfacing costs.
The Customer is responsible for reimbursing the Company for any other
excess installation costs created by unusual conditions.
PAGE 1 OF 4
<PAGE>
The following components are to be added to the proposed standard
offer rate for Street and Security Lighting Rate M:
UNBUNDLED COMPONENT PRICE
Standard Offer Generation 3.2000 cents/kwhr
Competitive Transition Assessment 0.8213 cents/kwhr
Systems Benefits Charge 0.0864 cents/kwhr
Conservation Charge 0.3000 cents/kwhr
Renewable Energy Charge 0.0500 cents/kwhr
Transmission Charge 0.7581 cents/kwhr
Payment: These unbundled components as well as any adjustments or charges based
on kWh will be based on monthly burn hours.
ANNUAL RATES PER LIGHT:
Overhead Service from Overhead Circuits to Standard Lights on
Standard Wooden Poles
LUMEN RATING SODIUM
4,000 $82.93
5,800 94.91
9,500 126.25
16,000 156.72
27,500 203.14
50,000 264.21
FLOODLIGHTING
27,500 198.28
50,000 257.62
Underground Service from Underground Circuits to Standard Lights on
Standard Wooden Poles will be charged an additional $61.52 (1) prior to August
29, 1983, and $116.69 for facilities installed on or after August 29, 1983.
Standard Ornamental Poles will be charged an additional $47.56 (1) per
year for facilities installed prior to August 29, 1983 and $541.98 for
facilities installed after August 29, 1983.
PAGE 2 OF 4
<PAGE>
Underground Service from Underground Circuits to Lights on Low Posts
MODERN OR
COLONIAL FIXTURES CONTEMPORARY FIXTURES
LUMEN RATING ON WOOD POLES ON NON-WOOD POSTS
High Pressure Sodium $186.66 $211.31
9,500
PAYMENT:
One twelfth of the above annual rates will be billed monthly.
HOURS OF OPERATION:
Lights supplied under this rate will be operated each night
approximately from one-half hour after sunset until one-half hour before
sunrise, approximately 4150 hours each year. The Customer shall be responsible
for notifying the Company of any outage, and lamp replacements will normally be
made on the first working day after notification.
If a timing device is placed into operation to effectively reduce the
annual burn hours of a fixture or fixtures, the customer's monthly billing will
be reduced accordingly to reflect the reduced kilowatt hours of consumption.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above ANNUAL RATES PER LIGHT will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 3 OF 4
<PAGE>
ESTIMATED KILOWATT-HOURS:
The amount of the Purchased Power Adjustment for each Light will be
determined each month by multiplying the Company's Purchased Power Adjustment by
the Estimated Monthly Kilowatt Hours (wattage divided by 1,000 times monthly
burn hours).
LUMEN RATING FIXTURE WATTAGE
4,000 64
5,800 81
9,500 116
16,000 173
27,500 307
50,000 471
The following are the burn hours of each month:
January 433 July 269
February* 365 August 301
March 364 September 334
April 310 October 388
May 280 November 413
June 251 December 442
-------- ---
Total 4150
* Leap Year 377
MINIMUM TERM OF SERVICE:
If Company owned lighting facilities are removed at the request of
the Customer, the Customer shall reimburse the Company for the original cost,
less accumulated provisions for depreciation and net salvage, of the facilities
removed.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 4 OF 4
<PAGE>
C.P.U.C.A. NO. 315
CANCELLING C.P.U.C.A. NO. 261
THE UNITED ILLUMINATING COMPANY
SODIUM VAPOR STREET LIGHTING CONVERSION RATE MC
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Street lighting service under this rate is available for any town,
city or municipal subdivision, for sodium vapor lights converted from existing
mercury vapor lights on ornamental poles only installed before August 29, 1983.
CONVERSION:
Conversion of existing mercury lights on ornamental poles will be
limited to the following sizes of sodium vapor lights:
MERCURY TO SODIUM
LUMEN RATING LUMEN RATING
8,150 9,500
11,500 9,500
21,500 16,000
21,500 27,500
60,000 50,000
The following components are to be added to the proposed standard
offer rate for Sodium Vapor Street Lighting Conversion Rate MC:
UNBUNDLED COMPONENT PRICE
Standard Offer Generation 3.2000 cents/kwhr
Competitive Transition Assessment 0.8213 cents/kwhr
Systems Benefits Charge 0.0864 cents/kwhr
Conservation Charge 0.3000 cents/kwhr
Renewable Energy Charge 0.0500 cents/kwhr
Transmission Charge 0.7581 cents/kwhr
PAGE 1 OF 4
<PAGE>
PAYMENT:
These unbundled components as well as any adjustments or charges
based on kWh will be based on monthly burn hours.
ANNUAL RATES PER LIGHT:
Service to Lights on Ornamental Poles
LUMEN OVERHEAD
RATING SERVICE
9,500 $183.52
16,000 235.53
27,500 304.94
50,000 533.40
Underground Service from Underground Circuits to Standard Lights on
Standard Wooden Poles will be charged an additional $61.52 (1) prior to August
29, 1983, and $116.69 for facilities installed on or after August 29, 1983.
Standard Ornamental Poles will be charged an additional $47.56 (1)
per year for facilities installed prior to August 29, 1983 and $541.98 for
facilities installed after August 29, 1983.
HOURS OF OPERATION:
Lights supplied under this rate will be operated each night
approximately from one-half hour after sunset until one-half hour before
sunrise, approximately 4,150 hours each year. The Customer shall be responsible
for notifying the Company of any outage, and lamp replacements will normally be
made on the first working day after notification.
If a timing device is placed into operation to effectively reduce the
annual burn-hours of a fixture or fixtures, the Customer's monthly billing will
be reduced accordingly to reflect the reduced kilowatt-hours of consumption.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above ANNUAL RATES PER LIGHT will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
PAGE 2 OF 4
<PAGE>
ESTIMATED KILOWATT-HOURS:
The amount of the Purchased Power Adjustment for each Light will be
determined each month by multiplying the Company's Purchased Power Adjustment by
the Estimated Kilowatt-hours (wattage divided by 1,000 times monthly burn
hours.)
LUMEN
RATING FIXTURE WATTAGE
9,500 116
16,000 173
27,500 307
50,000 471
The following are the burn hours of each month:
January 433
February* 365
March 364
April 310
May 280
June 251
July 269
August 301
September 334
October 388
November 413
December 442
-------- ----
Total 4150
*Leap Year 377
PAYMENT:
One twelfth of the above annual rates will be billed monthly.
PAGE 3 OF 4
<PAGE>
MINIMUM TERM OF SERVICE:
If Company owned street lighting facilities are converted to sodium
and subsequently removed at the request of the Customer, the Customer shall
reimburse the Company for the original cost, less accumulated provisions for
depreciation and net salvage, of the facilities removed.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 4 OF 4
<PAGE>
C.P.U.C.A. NO. 316
CANCELLING C.P.U.C.A. NO. 262
THE UNITED ILLUMINATING COMPANY
UNMETERED MUNICIPAL STREET LIGHTING RATE U
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Subject to the General Provisions of this rate, unmetered electric
service is available under this rate for any town, city, or municipal
subdivision for street lighting service on the streets and highways within a
specifically defined geographic area of any municipality to Street Lighting
Fixtures and/or Underground Utilization Facilities not owned by the Company. For
purposes hereof, such a specifically defined geographic area installation of a
municipality's street lighting equipment shall consist of not less than all
street lighting equipment on a public street lying between the intersections of
that public street and two other public streets, or one other public street and
a dead end or the municipal boundary.
Service under this rate may not be commenced or continued at any
location where the Customer has a suitable metered service available.
BILLING:
Kilowatt-hour consumption shall be calculated using lamp and fixture
characteristics plus an additional allowance representing the line losses for
service remote from the Company's secondary distribution system, and shall be
calculated for 4150 hours of operation per year for photocontrolled systems
which are designed for night operation from approximately one-half hour after
sunset until one-half hour before sunrise. Multiple fixtures supplied from a
single delivery point by Customer maintained distribution facilities shall be
considered a single delivery point for billing purposes under this rate. Point
of delivery shall be the Company's secondary distribution facilities.
If a timing device is placed into operation to effectively reduce the
annual burn-hours of a fixture or fixtures, the Customer's monthly billing will
be reduced accordingly to reflect the reduced kilowatt-hours of consumption. The
Customers credit for reduced kilowatt hours will be made in accordance with the
rate per month under Company Rate SG2 as approved by the DPUC.
PAGE 1 OF 4
<PAGE>
The following components are to be added to the proposed monthly
standard offer rate for Unmetered Municipal Street Lighting Rate U:
UNBUNDLED COMPONENT PRICE
Standard Offer Generation 3.2000 cents/kwhr
Competitive Transition Assessment 0.8213 cents/kwhr
Systems Benefits Charge 0.0864 cents/kwhr
Conservation Charge 0.3000 cents/kwhr
Renewable Energy Charge 0.0500 cents/kwhr
Transmission Charge 0.7581 cents/kwhr
PAYMENT:
These unbundled components as well as any adjustments or charges
based on kWh will be based on monthly burn hours.
RATE PER MONTH:
Facility Charge: $3.75 per delivery point
Energy Charge: 3.9942 cents per kilowatt-hour
ESTIMATED KILOWATT-HOURS:
The amount of the Purchased Power Adjustment for each Light will be
determined each month by multiplying the Company's Purchased Power Adjustment by
the Estimated Monthly Kilowatt Hours (wattage divided by 1,000 times monthly
burn hours).
The following are the burn hours of each month:
January 433
February* 365
March 364
April 310
May 280
June 251
July 269
August 301
September 334
October 388
November 413
December 442
-------- ---
Total 4150
*Leap Year 377
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<PAGE>
PURCHASED POWER ADJUSTMENT CLAUSE:
The above Energy Charge will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause.
GENERAL PROVISIONS:
The Customer shall be responsible for the cost of installation,
replacement, modification, maintenance, and removal, of (1) all brackets,
hangers, lamps, reflectors, refractors, ballasts, and controls, together with
conductors, insulators, and moldings used to connect such equipment to the
Company's secondary distribution system, and poles or other supports used solely
for the Customer's purposes (hereinafter collectively called "Street Lighting
Fixtures"), and (2) all foundations and supporting poles, masts, standards, and
posts used only to support Street Lighting Fixtures together with risers,
underground conduits, and conductors used to connect Street Lighting Fixtures to
the Company's secondary distribution system (hereinafter collectively called
"Underground Utilization Facilities").
The attachment of Street Lighting Fixtures to the Company's secondary
distribution system shall be done by the Company at the expense of the Customer.
All other work in connection with installation, replacement, or modification of
Street Lighting Fixtures or Underground Utilization Facilities shall be
performed at the expense of the Customer either by the Company, under a separate
agreement with the Customer, or by a contractor approved by the Company, and
shall be done in accordance with the Company's applicable Construction
Standards.
Street Lighting Fixtures and Underground Utilization Facilities shall
be supplied energy from standard secondary circuits and shall be of a type
approved by the Company. In order to assure safe and reliable operation of
Company and Customer facilities, the Company reserves the right to approve the
location of equipment.
Maintenance limited to cleaning or replacing lamps, photoelectric
controls, reflectors, and refractors may be performed by qualified employees of
the Customer, provided that such limited maintenance can be performed without
climbing any of the Company's poles. All other maintenance and tree-trimming
necessary for proper distribution of light shall be performed at the expense of
the Customer either by the Company under the terms of a separate maintenance
agreement with the Customer or by a contractor approved by the Company;
provided, however, that in cases in which the Company is not engaged to provide
maintenance, the Company reserves the right to make at the Customer's expense
any emergency repairs necessary to preserve the public safety or the integrity
of the Company's distribution system, and to repair at the Customer's expense
any particular Street Lighting Fixtures which remain lighted during daylight
hours for more than forty-eight hours after the Customer has been notified of
such malfunction.
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<PAGE>
No modification in size, type, or manufacturer of any Street Lighting
Fixtures, including but not limited to modifications which affect kilowatt hour
consumption or power factor, shall be made by the Customer without the prior
written approval of the Company.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 4 OF 4
<PAGE>
C.P.U.C.A. NO. 317
CANCELLING C.P.U.C.A. NO. 284
THE UNITED ILLUMINATING COMPANY
METAL HALIDE LIGHTING RATE MH
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Service under this rate is available to any Customer.
INSTALLATION:
The Company will furnish and maintain its standard equipment
necessary for supplying this service.
Where one or more wood poles must be installed in order to effect
service, the Customer will make a one-time payment of $574.22 per pole and is
responsible thereafter for the cost of any subsequent replacement poles.
Alternatively, the Customer may pay a monthly charge of $13.17 per pole. The
annual charge for standard ornamental poles will be $541.98, alternatively, the
Customer may pay a monthly charge of $45.16 per pole.
Where an overhead service pole is installed at a location more than
one span distant from the Company's overhead distribution facilities, or an
underground service ornamental pole is installed at a location more than 150
feet distant from the Company's underground distribution facilities, or an
underground service low post fixture is installed at a location more than 50
feet distant from the Company's underground distribution facilities, the
Customer will be required to reimburse the Company for the installation cost
attributable to such excess distance.
Where underground service to low post fixtures is not installed
concurrently with the installation of underground distribution facilities, the
Customer is responsible for reimbursing the Company for all trenching,
back-filling and resurfacing costs.
The Customer is responsible for reimbursing the Company for any other
excess installation costs created by unusual conditions.
PAGE 1 OF 4
<PAGE>
The following components are to be added to the proposed standard
offer rate for Metal Halide Lighting Rate MH:
UNBUNDLED COMPONENT PRICE
Standard Offer Generation 3.2000 cents/kwhr
Competitive Transition Assessment 0.8213 cents/kwhr
Systems Benefits Charge 0.0864 cents/kwhr
Conservation Charge 0.3000 cents/kwhr
Renewable Energy Charge 0.0500 cents/kwhr
Transmission Charge 0.7581 cents/kwhr
PAYMENT:
These unbundled components as well as any adjustments or charges
based on kWh will be based on monthly burn hours.
ANNUAL RATES PER LIGHT:
Overhead Service from Overhead Circuits to Standard Lights on
Standard Wooden Poles
LUMEN RATING WATTAGE COBRAHEAD
14,000 175 $176.77
20,500 250 230.14
36,000 400 295.71
110,000 1,000 474.52
LUMEN RATING WATTAGE FLOODLIGHT
14,000 175 $169.57
20,500 250 216.28
36,000 400 271.12
110,000 1,000 421.42
Underground Service from Underground Circuits to Lights on Low Posts
MODERN OR
COLONIAL FIXTURES CONTEMPORARY FIXTURES
LUMEN RATING WATTAGE ON WOOD POLES ON NON-WOOD POSTS
14,000 175 188.07 212.72
20,500 250 261.81
36,000 400 274.87
PAGE 2 OF 4
<PAGE>
PAYMENT:
One twelfth of the above annual rates will be billed monthly.
HOURS OF OPERATION:
Lights supplied under this rate will be operated each night
approximately from one-half hour after sunset until one-half hour before
sunrise, approximately 4150 hours each year. The Customer shall be responsible
for notifying the Company of any outage, and lamp replacements will normally be
made on the first working day after notification.
CHARGE FOR CONVERSION TO METAL HALIDE:
Replacement of other type lighting with a Metal Halide, or a high
lumen Metal Halide with a lower lumen Metal Halide, will require that the
Customer pay a one time charge of $81.00/per pole for the first pole and $22.50
for each additional pole, to be paid prior to replacement.
PURCHASED POWER ADJUSTMENT CLAUSE:
The above ANNUAL RATES PER LIGHT will be increased or decreased, as
appropriate, by an amount determined in accordance with the Company's Purchased
Power Adjustment Clause. The amount of the Purchased Power Adjustment for each
Light will be determined each month by multiplying the Company's Purchased Power
Adjustment by the Estimated Kilowatt Hours specified below opposite the Lumen
Rating of such Light.
ESTIMATED KILOWATT-HOURS:
The amount of the Purchased Power Adjustment for each Light will be
determined each month by multiplying the Company's Purchased Power Adjustment by
the Estimated Monthly Kilowatt Hours (wattage divided by 1,000 times monthly
burn hours).
LUMEN RATING FIXTURE WATTAGE
14,000 200
20,500 306
36,000 471
110,000 1,200
PAGE 3 OF 4
<PAGE>
The following are the burn hours of each month:
January 433
February* 365
March 364
April 310
May 280
June 251
July 269
August 301
September 334
October 388
November 413
December 442
-------- ---
Total 4150
*Leap Year 377
MINIMUM TERM OF SERVICE:
If Company owned lighting facilities are removed at the request of
the Customer, the Customer shall reimburse the Company for the original cost,
less accumulated provisions for depreciation and net salvage, of the facilities
removed, plus all labor and other expenses incurred.
TERMS AND CONDITIONS:
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
EFFECTIVE: JANUARY 1, 2000
PAGE 4 OF 4
<PAGE>
C.P.U.C.A. NO. 318
CANCELLING C.P.U.C.A. NO. 246
THE UNITED ILLUMINATING COMPANY
LOAD CONTROL RIDER LC
APPLIES THROUGHOUT THE COMPANY'S SERVICE AREA.
AVAILABILITY:
Availability to any demand-metered Customer who by contract agrees to
interrupt a minimum of 30 kilowatts subject to availability and installation of
the required metering equipment.
TERMS AND CONDITIONS:
The Customer may designate any amount of load equal to or greater than
30 kilowatts as Contracted Load Reduction. The primary requirements are:
Minimum Notice for Interruption: 1 hour
Maximum Daily Duration: 10 hours per interruption
RATE PER MONTH:
In any month when the Customer's load is reduced at the Company's
request, a credit calculated as follows will be applied to the Customer's bill:
NUMBER OF DAYS CREDIT PER KILOWAT
LOAD REDUCTION REQUESTED OF REDUCED LOAD
1 $ 2.00
2 2.50
3 3.00
4 or more 4.00
MONTHLY CREDIT CALCULATION:
For each billing month in which an interruption is requested, the
Customer will be credited the Performance Payment. The Performance Payment will
be calculated by multiplying a) the Actual Load Reduction, by b) the number of
interruptions in the billing month, by c) the Performance Credit.
PAGE 1 OF 2
<PAGE>
The Actual Load Reduction will be calculated for each billing month by
subtracting a) the average demand during periods of interruption, from b) the
average demand during the same hours of the billing month's other weekdays when
interruptions were not requested, excluding the Customer's holidays and
scheduled shutdowns.
The Company's Terms and Conditions in effect from time to time are a
part of this Rider where not inconsistent with any specific provisions hereof.
MINIMUM TERM OF SERVICE:
One year.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
<PAGE>
C.P.U.C.A. NO.319
CANCELLING C.P.U.C.A. NO. 247
THE UNITED ILLUMINATING COMPANY
ECONOMIC DEVELOPMENT RIDER ED
APPLIES ONLY TO CUSTOMERS ON THIS RIDER PRIOR TO JANUARY 1, 2000..
AVAILABILITY:
Service under this optional Rider is available to Existing Customers
and New Customers in conjunction with Rate LPT, Rate GST, or any other
demand-metered rate, provided, in the latter case, that at least 20% of any load
greater than 50 Kw is designated as interruptible under one of the Company's
Interruptible Riders.
This Rider is not available to any customer, new or existing, after
January 1, 2000.
QUALIFICATIONS:
The Company will render this Rider to a Customer whose Premises meets
one of the following conditions:
1. At least 75% of the Customer's electric requirements are for
manufacturing activities classified by SIC Major Group Numbers 20-39, or for
computer related activities in SIC Numbers 7371-7379, or for Research and
Development Labs in SIC Numbers 7391, 7397, and 8922, as determined by the
Company.
or
2. Service sector businesses, including supermarkets, as determined
by the Company, which are currently located in or plan to relocate into an
Enterprise zone identified by the Department of Economic Development.
or
3. Businesses which provide added value to UI's service territory,
as determined by the Company.
PAGE 1 OF 2
<PAGE>
TERMS AND CONDITIONS:
A New Customer is defined as the owner or occupant of a Customer's
Premises who has not been a Customer in the Company's Service Area in any of the
12 months preceding application for service under this Rider, as determined by
the Company. An Existing Customer is defined as the owner or tenant of a
Customer's Premises who has received service under any of the Company's
demand-metered rates for a period of 12 months or longer.
For an Existing Customer to qualify, the combined kilowatt-hour usage
for three consecutive billing months following application for service under
this Rider must exceed, by the lesser of 10 percent or 200 megawatt hours per
month, the usage in the comparable three months of the Base Period, where the
Base Period is the twelve month period immediately preceding the month in which
the Customer applies for service under this Rider or some appropriate Base
Period determined by the Company. Base Period usage may be adjusted for the
implementation of conservation measures as determined by the Company. Upon
meeting this requirement, such usage will be rebilled in accordance with this
Rider and the Customer's account credited accordingly. The Company may remove a
Customer from this Rider if, in three consecutive months, kilowatt-hour usage is
less than 10 percent greater than usage in the comparable months of the Base
Period.
The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof are a part of this rate.
TOTAL BILL REDUCTIOn: For New Customers, applies to the entire bill
determined in accordance with the applicable Rate. For Existing
Customers, it applies only to the amount by which the current month's
bill exceeds the bill which would have been rendered on the
consumption in the same month of the Base Period:
FOR BILLS RENDERED IN: TOTAL BILL
(YEAR) REDUCTION
1 40%
2 32%
3 24%
4 16%
5 8%
6 0%
EXCESS FACILITIES CHARGE:
In cases where distribution facilities are not in place or where an
extraordinary investment must be made to provide electric service, all revenue
requirements in excess of UI's normal facilities costs will be borne by the
customer.
EFFECTIVE: JANUARY 1, 2000
PAGE 2 OF 2
