<PAGE>
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________
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, 1993
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 ______
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 of (I.R.S. Employer Identification No.)
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
________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
------------------- ------------------------
Common Stock, no par value New York Stock Exchange
8.80% Preferred Stock ($25 par value per share) New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: Common Stock,
no par value
____________________________________________________
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
--- ---
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, 1994 was $524,639,840, 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, 1994.
The number of shares outstanding of the registrant's only class of common
stock, as of January 31, 1994, was 14,084,291.
DOCUMENTS INCORPORATED BY REFERENCE
Part of this Form 10-K into
Document which document is incorporated
-------- ------------------------------
Definitive Proxy Statement, dated
April 8, 1994, for Annual Meeting of the
Shareholders to be held on May 18, 1994. III
<PAGE>
THE UNITED ILLUMINATING COMPANY
FORM 10-K
December 31, 1993
TABLE OF CONTENTS
Page
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GLOSSARY 4
Part I
Item 1. Business. 6
- General 6
- Franchises, Regulation and Competition 6
- Franchises 6
- Regulation 7
- Competition 7
- Rates 8
- Financing 9
- Fuel Supply 11
- Fossil Fuel 11
- Nuclear Fuel 12
- Arrangements with Other Utilities 13
- Hydro-Quebec 13
- Environmental Regulation 13
- Employees 16
Item 2. Properties. 17
- Generating Facilities 17
- Tabulation of Peak Loads, Resources, and Margins 18
- Transmission and Distribution Plant 19
- Seabrook 20
- Capital Expenditure Program 21
- Nuclear Generation 22
- Insurance Requirements 22
- Waste Disposal and Decommissioning 23
Item 3. Legal Proceedings. 24
Item 4. Submission of Matters to a Vote of Security Holders. 25
Executive Officers of the Company 26
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TABLE OF CONTENTS (continued)
Page
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Part II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters. 29
Item 6. Selected Financial Data. 30
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 34
- Major Influences on Financial Condition 34
- Liquidity and Capital Resources 34
- Results of Operations 36
- Outlook 38
- Inflation 39
Item 8. Financial Statements and Supplementary Data. 40
- Consolidated Statements for the Years Ended
December 31, 1993, 1992 and 1991 40
- Income Statement 40
- Cash Flows 41
- Balance Sheet 42
- Retained Earnings 44
- Notes to Consolidated Financial Statements 45
- Statement of Accounting Policies 45
- Capitalization 48
- Rate-Related Regulatory Proceedings 53
- Accounting for Phase-in Plan 54
- Income Taxes 55
- Short-Term Credit Arrangements 56
- Supplementary Information 59
- Pension and Other Post-Employment Benefits 60
- Jointly Owned Plant 64
- Unamortized Cancelled Nuclear Project 64
- Fuel Financing Obligations and Other Lease Obligations 64
- Commitments and Contingencies 65
- Capital Expenditure Program 65
- Seabrook 65
- Nuclear Insurance Contingencies 66
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Page
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Part II (continued)
- Other Commitments and Contingencies 67
- Hydro-Quebec 67
- Reorganization Charge 67
- Site Remediation Costs 67
- Property Taxes 67
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 67
- Environmental Concerns 69
- Change in Method of Accounting for Property Taxes 69
- Fair Value of Financial Instruments 70
- Quarterly Financial Data (Unaudited) 71
Report of Independent Accountants 72
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures.
Part III
Item 10. Directors and Executive Officers of the Company 73
Item 11. Executive Compensation. 73
Item 12. Security Ownership of Certain Beneficial Owners and
Management. 73
Item 13. Certain Relationships and Related Transactions. 73
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K. 74
Consent of Independent Accountants 81
Signatures 82
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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:
"BEC" means Bridgeport Electric Company.
"CL&P" means The Connecticut Light and Power Company.
"CLM" means conservation and load management program.
"Company" or "UI" 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 and operated by Connecticut Yankee.
"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.
"EUA" means Eastern Utilities Associates.
"EUA Power" means EUA Power Corporation.
"FERC" means the United States Federal Energy Regulatory
Commission.
"FCA" means fossil fuel adjustment clause.
"Hydro-Quebec" means a transmission line facility intertie
linking New England and Quebec, Canada.
"LLW" means low-level radioactive wastes.
"Millstone Unit 3" means the nuclear electric generating unit
located in Waterford, Connecticut, which is jointly owned by UI and
thirteen other New England electric utilities.
"NDFC" means the Nuclear Decommissioning Finance Committee.
"NEPOOL" means the New England Power Pool.
"NRC" means the United States Nuclear Regulatory Commission.
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GLOSSARY (continued)
"NU" means Northeast Utilities.
"OPEB" means other postretirement benefits.
"PCBs" means polychlorinated biphenyls.
"Preferred Stock" means capital stock of the Company having
preferential dividend andliquidation rights over shares of the
Company's other classes of capital stock.
"PSNH" means Public Service Company of New Hampshire.
"RCI" means Research Center, Inc., a wholly-owned subsidiary of
UI.
"RCRA" means the federal Resource Conservation and Recovery Act.
"Seabrook Unit 1" means nuclear generating unit No. 1 located in
Seabrook, New Hampshire, which is jointly owned by UI and eleven other
New England electric utilities.
"Seabrook Unit 2" means nuclear generating unit No. 2 proposed
to be located in Seabrook, New Hampshire, on which all construction was
terminated in April 1984, and which was cancelled in 1984.
"SEC" means Securities and Exchange Commission.
"SFAS" means Statement of Financial Accounting Standards.
"TSCA" means the federal Toxic Substances Control Act.
"UEI" means United Energy International, Inc., a wholly-owned
subsidiary of UI.
"Unit 1" means Seabrook Unit 1.
"UI" or "Company" means The United Illuminating Company.
"URI" means United Resources, Inc., a wholly-owned subsidiary of
UI.
"VEBA" means Voluntary Employees' Benefit Association Trusts.
"Ventana" means Ventana Corporation, a subsidiary of UI.
"VERP" means the Voluntary Early Retirement Program.
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<PAGE>
PART I
Item 1. Business.
GENERAL
The United Illuminating 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 production,
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 698,000,
or 21% of the population of the State. The service area, largely
urban and suburban in character, includes the principal cities of
Bridgeport (population 135,250) and New Haven (population 123,470)
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 1993
retail electric revenues, approximately 39% was derived from
residential sales, 43% from commercial sales, 16% from industrial
sales and 2% from other sales.
UI has four wholly-owned subsidiaries. Bridgeport Electric
Company, a single-purpose corporation, owns and leases to UI a
generating unit at Bridgeport Harbor Station. Research Center,
Inc. (RCI) has been formed to participate in the development of one
or more regulated power production ventures, including possible
participation in arrangements for the future development of
independent power production and cogeneration facilities. United
Energy International, Inc. (UEI) has been formed to facilitate
participation in a proposed joint venture relating to power
production plants abroad. United Resources, Inc. (URI) serves as
the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business
ventures that will complement and enhance UI's electric utility
business and serve the interests of the Company and its
shareholders and customers.
Four wholly-owned subsidiaries of URI have been incorporated.
Souwestcon Properties, Inc. is participating as a 25% partner in
the ownership of a medical hotel building in New Haven. A second
wholly-owned subsidiary of URI is Thermal Energies, Inc., which is
participating in the development of district heating and cooling
water facilities in the downtown New Haven area, including the
energy center for an office tower and participation as a 37%
partner in the energy center for a new city hall and office tower
complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial
buildings and industrial facilities. A fourth URI subsidiary,
American Payment Systems, Inc., manages agents and equipment for
electronic data processing of bill payments made by customers of
utilities, including UI, at neighborhood businesses. In addition
to these subsidiaries, URI also has an 82% ownership interest in
Ventana Corporation, which offers energy conservation engineering
and project management services to governmental and private
institutions.
The Board of Directors of the Company has authorized the
investment of a maximum of $13.5 million, in the aggregate, of the
Company's assets in all of URI's ventures, UEI and RCI, and, at
December 31, 1993, approximately $10.6 million had been so
invested.
FRANCHISES, REGULATION AND COMPETITION
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
production, 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.
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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. See "Rates". The DPUC consists of five Commissioners,
appointed by the Governor of Connecticut with the advice and
consent of both houses of the Connecticut legislature.
The location and construction of certain electric facilities is
also subject to regulation by the Connecticut Siting Council with
respect to environmental compatibility and public need. See
"Environmental Regulation".
UI 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".
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 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 ownership interest in Seabrook Unit 1. See Item 2. Properties
- - "Seabrook".
Competition
The electric utility industry has become, and can be expected to
be, increasingly competitive, due to a variety of economic,
regulatory and technological developments; and UI is exposed to
competitive forces in varying degrees.
Although UI has not historically been a major wholesale supplier
of bulk electric power (power sold to other utilities), it has
marketed generating capacity and energy aggressively in recent
years, seeking to sell outside its service territory the power it
produces in excess of the present needs of its own customers that
became available when Seabrook Unit 1 commenced operating in 1990.
Due to a general oversupply of power in the New England region and
the region's slow economic growth, the Company's wholesale sales
efforts have faced increasing competition; and wholesale sales are
expected to remain relatively weak during the near term. Moreover,
competition in this market can be expected to increase by reason of
the federal Energy Policy Act of 1992, which was designed to foster
competition in the wholesale market by facilitating the ownership
and operation of independently-owned generating facilities and
authorizing the FERC to order electric utilities to furnish
transmission service to the owners of these generating facilities.
Competition can also be expected to increase in the wholesale power
market due to the entry of brokers and marketers, who buy and sell
generating capacity and energy without owning or operating any
generating or transmission facilities.
In UI's principal market, retail sales of electricity in the
Company's franchised service territory, competitive pressures are
rising from several sources. Industrial and large commercial
customers may have the ability to own and operate facilities that
generate their own electric energy requirements. If these
facilities satisfy certain statutory requirements, UI can be
required to purchase their output at UI's avoided cost. These
customers may also substitute natural gas or oil for electricity as
fuel for heating and cooling purposes, and industrial customers may
have the option of relocating their facilities to a lower-cost
environment. As a result of these pressures, and with the approval
of the DPUC, UI offers special rate and service agreements to
induce industrial and large commercial customers to remain on the
Company's system. However, to the extent that the Company loses
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revenues from customers leaving the system or paying for service
under special rate or service agreements, the Company's only
opportunity to replace such revenues will be through increased
wholesale sales and retail sales growth. The Company is not
capitalizing these "lost" revenues for future rate recovery and has
publicly stated that it does not plan to seek rate increases for
the foreseeable future.
The legislatures and regulatory commissions in several states
have considered or are considering "retail wheeling." This, in
general terms, means the transmission by an electric utility of
energy produced by another entity over the utility's transmission
and distribution system to a retail customer in the utility's own
service territory. A retail wheeling requirement would have the
effect of permitting retail customers to purchase electric capacity
and energy, at the election of such customers, from the electric
utility in whose service area they are located or from any other
electric utility or independent power producer anywhere. The DPUC
has commenced a proceeding to investigate the pros and cons of
retail wheeling.
RATES
The Company's retail electric service rates are subject to
regulation by the DPUC.
UI's present general retail rate structure consists of various
rate and service classifications covering residential, commercial,
industrial and street lighting services.
On December 16, 1992, the DPUC approved levelized rate increases
of 2.66% ($15.8 million) in 1993 and 2.66% (an additional $17.3
million) in 1994, including allowed conservation and load
management program (CLM) revenue increases. The rate increases
total $33.1 million, or 5.4%, over two years.
In order to achieve levelized 2.66% rate increases for each of
these two years, the DPUC determined that the recovery of $13.1
million of sales adjustment clause revenues would be deferred from
1993 to 1994.
Utilities are entitled by Connecticut law to revenues sufficient
to allow them to cover their operating and capital costs, to
attract needed capital and maintain their financial integrity,
while also protecting the public interest. Accordingly, the DPUC's
1992 rate decision authorized a return on equity of 12.4% for
ratemaking purposes. However, the Company may earn up to 1% above
this level before a mandatory review is required by the DPUC.
Since January 1971, UI has had a fossil fuel adjustment clause
(FCA) in virtually all of its retail rates. The DPUC is required
by law to convene an administrative proceeding prior to approving
FCA charges or credits for each month. The law permits automatic
implementation of the charges or credits if the DPUC fails to act
within five days of the administrative proceeding, although all
such charges and credits are also subject to further review and
appropriate adjustment by the DPUC at public hearings required to
be held at least every three months. The DPUC has made no material
changes in UI's FCA charges and credits as the result of any of
these proceedings or hearings.
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FINANCING
The Company's capital requirements are presently projected as
follows:
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Capital Expenditure Program $ 73,424 $ 84,876 $ 82,632 $ 51,324 $ 74,304
Long-term Debt Maturities 53,000 97,000 - 50,000 100,000
Mandatory Redemptions/
Repayments 60,333 66,134 12,770 15,171 15,562
------- ------- ------- ------- -------
Total Capital Requirements $186,757 $248,010 $ 95,402 $116,495 $189,866
======= ======= ======= ======= =======
</TABLE>
The Company presently estimates that its cash on hand and
temporary cash investments at the beginning of 1994, totaling $48.2
million, and its projected net cash provided by operations, less
dividends, of $102 million, less capital expenditures of $73.4
million, will be insufficient to fund the Company's 1994
requirements for long-term debt maturities and mandatory
redemptions and repayments, amounting to $113.3 million, by $36
million. The Company currently anticipates that its projected net
cash provided by operations, less dividends and capital
expenditures, for 1995 will be insufficient to fund the Company's
1995 requirements for long-term debt maturities and mandatory
redemptions and repayments, by approximately $138 million. The
Company currently anticipates that its projected net cash provided
by operations, less dividends and capital expenditures, for 1996
through 1998 will be insufficient to fund the Company's
requirements for long-term debt maturities and mandatory
redemptions and repayments in the years 1996 through 1998, in
amounts that cannot now be predicted accurately, but which may be
substantial in the aggregate, depending on the levels of the
Company's sales, wholesale and retail rates, operation and
maintenance costs and taxes. All of the Company's capital
requirements that exceed available net cash will have to be
provided by external financing; and the Company has no commitment
to provide such financing from any source of funds. The Company
expects to be able to satisfy its external financing needs by
issuing common stock and additional short-term and long-term debt,
although 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.
In January 1993, the net proceeds from the liquidation of an
investment in tax-exempt municipal debt instruments were used to
pay $60 million principal amount of maturing 10.32% First Mortgage
Bonds of the Company's wholly-owned subsidiary, Bridgeport Electric
Company; to repay a $7.5 million 13.1% term loan; to repay short-
term borrowings incurred for the August 1, 1992 redemption of the
Company's 12% Debentures, due August 1, 2017, and for repayment of
a $7.5 million 12.9% term loan on September 30, 1992; and to repay
short-term borrowings incurred for a $19.1 million rent payment on
December 31, 1992 under the Company's facility sale and leaseback
arrangement for a portion of its ownership interest in Seabrook
Unit 1.
On September 30, 1993, the Company repaid a $5 million 12.9%
term loan with funds obtained through short-term borrowings.
On September 17, 1993, the Company invited the owners of
$68,400,000 aggregate principal amount of 14 1/2% Pollution Control
Revenue Bonds, due October 1 and December 1, 2009, ("Bonds") to
sell to the Company, for cash, any and all of the Bonds. The Bonds
were issued in 1984 by The Industrial Development Authority of the
State of New Hampshire ("NHIDA"), which loaned the issue proceeds
to the Company to pay for the cost of installing pollution control
facilities at the Seabrook nuclear generating plant in New
Hampshire; and the Business Finance Authority of the State of New
Hampshire ("NHBFA"), successor to the NHIDA, agreed to issue
Pollution Control Refunding Revenue Bonds ("Refunding Bonds") in a
principal amount equal to the aggregate principal amount of Bonds
purchased by the Company and surrendered to the Bond trustee for
cancellation, and to loan the issue proceeds of the Refunding Bonds
to the Company to pay for part of the purchase price of the Bonds
being purchased and cancelled. On October 15, 1993, the Company
accepted offers from holders of $64,460,000 aggregate principal
amount of the Bonds to sell them for an aggregate purchase price of
$75,710,000. On October 26, 1993, the NHBFA issued and sold
$64,460,000 principal amount of 5 7/8%
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Refunding Bonds, due October 1, 2033, and loaned the issue proceeds
to the Company, which used them to pay a portion of the purchase
price of the Bonds. The remainder of the purchase price was funded
with the proceeds of short-term borrowings.
On December 7, 1993, the Company issued and sold $100 million
principal amount of five-year and one month Notes at a coupon rate
of 6.20%. The net proceeds were used to repay $60 million
principal amount of maturing 10.32% First Mortgage Bonds of the
Company's wholly-owned subsidiary, Bridgeport Electric Company in
January 1994; to repay a $5 million 13.1% term loan in January 1994
and for general corporate purposes, including repayment of
short-term borrowings.
The Company has a revolving credit agreement with a group of
banks, which currently extends to January 19, 1995. The borrowing
limit of this facility is $75 million. The facility permits the
Company to borrow funds at a fluctuating interest rate determined
by the prime lending market in New York, and also permits the
Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar
interbank market in London, by the certificate of deposit market in
New York, or by bidding, at the Company's option. If a material
adverse change in the business, operations, affairs, assets or
condition, financial or otherwise, or prospects of the Company and
its subsidiaries, on a consolidated basis, should occur, the banks
may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the
time of such an occurrence would not then become due and payable.
As of December 31, 1993, the Company had no 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 in the previous paragraph
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.
The Company had a $50 million term loan facility with a group of
banks during 1993. Under this agreement, the Company chose an
interest rate from among three alternatives: (i) a fluctuating
interest rate determined by the prime lending market in New York;
(ii) a fixed interest rate determined by the Eurodollar interbank
market in London; and (iii) a fixed interest rate determined by the
certificate of deposit market in New York. On February 1, 1993,
the Company borrowed $50 million from this group of banks, using
the proceeds to repay short-term borrowings and other current
obligations. On December 3, 1993, the Company repaid the $50
million borrowing and terminated the agreement.
The Company had a term loan agreement with PruLease, Inc.
(PruLease) that expired on December 1, 1993. This agreement was
executed on December 31, 1992, when the Company borrowed $49.1
million from PruLease and purchased all the nuclear fuel that was
owned by PruLease and leased to the Company on that date. This
loan, which was collateralized by a first lien on the Company's
ownership interest in the nuclear fuel for Seabrook Unit 1, was
repaid in full at maturity.
The Company has a Fossil Fuel Supply Agreement with a financial
institution providing for financing up to $37.5 million in fossil
fuel purchases. Under this agreement, the financing entity
acquires and stores natural gas, coal and fuel oil for sale to the
Company, and the Company purchases these fossil fuels from the
financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an
inventory of the fuel determined by reference to the fluctuating
interest rate on thirty-day, dealer-placed commercial paper in New
York. The Company is obligated to insure the fuel inventories and
to indemnify the financing entity against all liabilities, taxes
and other expenses incurred as a result of its ownership, storage
and sale of fossil fuel to the Company. This agreement currently
extends to February 1995. At December 31, 1993, approximately
$10.1 million of fossil fuel purchases were being financed under
this agreement.
The Company's Preferred Stock provisions prohibit the issuance
of additional Preferred Stock unless the Company's after-tax income
for a period of twelve consecutive months ending not more than 90
days prior to such issuance is at least one and one-half times the
aggregate of annual interest charges on all indebtedness and
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annual dividends on all Preferred Stock to be outstanding. The
Preferred Stock provisions also prohibit any increase in long-term
indebtedness unless the Company's after-tax income for a period of
twelve consecutive months ending not more than 90 days prior to
such increase is at least twice the annualized interest charges on
all long-term indebtedness to be outstanding.
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 UI 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.
On the basis of the formulas contained in the Preferred Stock
provisions and the Seabrook Unit 1 lease financing documents, the
coverages for each of the five years ended December 31, 1993 are
set forth below.
<TABLE>
<CAPTION>
Preferred Stock Seabrook Lease
Provisions Provisions
---------------------- -----------------
Preferred Long-term Earnings/Interest
Year Stock Indebtedness Ratio
---- --------- ------------ -----------------
<C> <C> <C> <C>
1989 3.11 3.54 Not applicable
1990 3.38 3.84 1.72
1991 3.38 3.77 2.20
1992 3.23 3.88 2.41
1993 3.33 3.67 2.59
</TABLE>
See Item 7. - "Management's Discussion and Analysis of Financial
Condition and Results of Operations" regarding the financing
outlook for 1994 and beyond.
The success of future financings by the Company will be
dependent on a number of factors, most importantly, conditions in
the securities markets, including the availability and cost of
capital, economic conditions and the level of the Company's income
and cash flow.
The Company has a 5.45% participating share in Phase II of the
Hydro-Quebec transmission intertie facility linking New England and
Quebec, Canada. See "Arrangements with Other Utilities -
Hydro-Quebec". As a participant, the Company is obligated to
furnish a guarantee for its participating share of the debt
financing for Phase II of the facility. Currently, the Company's
guarantee liability on this account amounts to approximately $9.8
million.
The Company has a 9.5% common stock ownership share in
Connecticut Yankee Atomic Power Company, which owns and operates a
nuclear electric generating station in Haddam Neck, Connecticut.
Connecticut Yankee plans and implements a construction program that
is essential to maintain its station as a dependable source of
low-cost electric power in New England. In this regard, the
Company is obligated to furnish 9.5% of Connecticut Yankee's
capital requirements within specified limits. As a condition of
the debt financing arrangements for Connecticut Yankee's
construction program, the lenders from time to time have required
guarantees from the shareowners of Connecticut Yankee, although no
such guaranteed debt is currently outstanding.
FUEL SUPPLY
Fossil Fuel
The Company burns coal, residual oil and natural gas at its
fossil fuel generating stations in Bridgeport and New Haven.
During 1993, approximately 745,000 tons of coal, 3.2 million
barrels of fuel oil and 266.0 million cubic feet of natural gas
were consumed in the generation of electricity. The Company leases
fuel oil storage
- 11 -<PAGE>
<PAGE>
tanks at its major generating stations in Bridgeport and New Haven
that have maximum capacities of approximately 680,000 and 650,000
barrels of oil, respectively. In addition, the Company maintains
approximately a 45-day coal supply of 150,000 tons at its
Bridgeport Harbor Station.
The Company has a fuel oil supply contract with the Tosco
Corporation for the Company's New Haven and Bridgeport generating
stations. The contract expires on September 30, 1995.
The Company burns coal at the largest generating unit at
Bridgeport Harbor Station, which is also capable of burning oil,
and has a coal supply contract with Pittston Coal Sales Company
that extends until July 1, 2007, subject to earlier termination
provisions.
The Company's New Haven Harbor Station has a dual-fuel
capability of burning natural gas and oil. Under an agreement with
Tenngasco, a division of Tenneco, the Company is obligated to burn
approximately 6 billion cubic feet of gas per year, if tendered,
during the non-heating months and when offered by Tenngasco at a
price that is competitive with oil. The natural gas burned by the
Company during 1993 was not purchased pursuant to this agreement.
Nuclear Fuel
In addition to its common stock ownership in Connecticut Yankee,
the Company holds ownership and leasehold interests in Seabrook
Unit 1 and 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 1/5 to 1/3 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 permanent storage sites.
Based on information furnished by the utilities responsible for
the operation of the units in which the Company is participating,
there are outstanding contracts that cover uranium concentrate
purchases for the Connecticut Yankee Unit and Millstone Unit 3
through 1995 and for Seabrook Unit 1 through 1999. 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:
<TABLE>
<CAPTION>
Conversion to
Hexafluoride Enrichment Fabrication
------------- ---------- -----------
<S> <C> <C> <C>
Connecticut Yankee Unit 1995 1994 (1) 1999 (2)
Millstone Unit 3 1995 1995 (1) 1997 (3)
Seabrook Unit 1 1999 2014 (4) 2000
<FN>
(1) Currently, 70% of the enrichment requirements through 1998 and
50% through 1999 are covered under an existing contract.
(2) The present contract extends fabrication services through 1999.
It is presently under negotiation that would extend it through
2007.
(3) The contract provides an option to extend fabrication services
through 1999.
(4) Enrichment requirements are 100% covered through 2014.
</TABLE>
UI expects that uranium concentrates and related services for
periods not covered by existing contracts will be available,
although there can be no assurance that such concentrates and
services will, in fact, be available when needed. Costs for
subsequent periods could be substantially higher than those under
existing contracts.
- 12 -<PAGE>
<PAGE>
ARRANGEMENTS WITH OTHER UTILITIES
The Company, in cooperation with other privately and publicly
owned New England electric utilities, established the New England
Power Pool (NEPOOL) in 1971. The objectives of NEPOOL are: (a) to
assure that the bulk power supply of New England and any adjoining
areas served conforms to proper standards of reliability, (b) to
attain maximum practicable economy, consistent with such proper
standards of reliability, in such bulk power supply, and (c) to
provide for equitable sharing of the resulting benefits and costs.
These objectives are achieved through joint planning, central
dispatching, cooperation in environmental matters, coordinated
construction, operation and maintenance scheduling of electric
generation and transmission facilities and through the provision
for more effective coordination with other power pools and
utilities situated in the United States and Canada. The agreement
establishing NEPOOL is filed with the Federal Energy Regulatory
Commission (FERC) and its provisions are subject to continuing FERC
jurisdiction.
Operation, dispatching and coordination of planning of electric
generating capacity for New England is done on a regular basis
under NEPOOL. A central dispatching agency of NEPOOL, designated
NEPEX, directs the operation and schedules the maintenance of the
generating and transmission facilities of participating utilities
and provides for coordination with other power pools and utilities.
The Company contributes to the financial support of certain 345
kilovolt transmission facilities that are a part of the New England
transmission grid in connection with its participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3.
Hydro-Quebec
The Company is a participant in the Hydro-Quebec transmission
intertie facility linking New England and Quebec, Canada. Phase II
of this facility, in which UI has a 5.45% participating share, has
increased the capacity of the intertie from 690 megawatts to a
maximum of 2,000 megawatts. A ten-year Firm Energy Contract, which
provides for the sale of 7 million megawatt-hours per year by
Hydro-Quebec to the New England participants in the Phase II
facility, became effective on July 1, 1991. See "Financing".
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.
The federal Clean Water Act requires permits for discharges of
effluents into navigable waters and requires that all discharges of
pollutants comply with federally approved state water quality
standards. The Connecticut Department of Environmental Protection
(DEP) has adopted, and the federal government has approved, water
quality standards for receiving waters in Connecticut. A joint
federal and state permit system, administered by the DEP, has been
established to assure that applicable effluent limitations and
water quality standards are met in connection with the construction
and operation of facilities that affect or discharge into these
waters. The current discharge permit for New Haven Harbor Station
was issued by the DEP on September 30, 1991. The discharge permits
for Bridgeport Harbor, English and Steel Point Stations expired on
February 25, 1992, May 15, 1992 and March 16, 1992, respectively.
Applications for renewal of these permits were filed on August 23,
1991, November 14, 1991 and September 13, 1991, respectively, and,
although new permits have not yet been issued, the Company has not
been advised by the DEP that any of these facilities has a
permitting problem. While the renewal applications are pending,
the terms of the expired permits continue in effect. The DEP has
determined that the thermal component of the discharges at each of
the Company's stations will not result in a violation of state
water quality standards and that the location, design, construction
and capacity of the cooling water intake structures reflect the
best technology available, as defined by the federal Environmental
Protection Agency (EPA). All discharge permits may be reopened and
amended to incorporate more stringent standards and effluent
limitations that may be adopted by federal and state authorities.
Compliance with this permit system
- 13 -<PAGE>
<PAGE>
has necessitated substantial capital and operational expenditures
by UI, and it is expected that such expenditures will continue to
be required in the future. Although the magnitude of future
expenditures cannot now be estimated accurately, the Company
presently anticipates spending several million dollars during the
next several years to consolidate and improve the wastewater
collection and treatment system at Bridgeport Harbor Station.
Under the federal Clean Air Act, the EPA has promulgated
national primary and secondary air quality standards for certain
air pollutants, including sulfur oxides, particulate matter and
nitrogen oxides. The DEP has adopted regulations for the
attainment, maintenance and enforcement of these standards. In
order to comply with these regulations, the Company is required to
burn fuel oil with a sulfur content not in excess of 1%, and
Bridgeport Harbor Unit 3 is required to burn a low-sulfur, low-ash
content coal, the sulfur dioxide (SO2) emissions from which are not
to exceed 1.1 pounds of SO2 per million BTU of heat input. Current
air pollution regulations also include other air quality standards,
emission performance standards and monitoring, testing and
reporting requirements that are applicable to the Company's
generating stations and further restrict the construction of new
sources of air pollution or the modification of existing sources by
requiring that both construction and operating permits be obtained
and that a new or modified source will not result in the violation
of the EPA's national air quality standards or its regulations for
the prevention of significant deterioration of air quality.
Amendments to the Clean Air Act in 1990 will require a
significant reduction in nationwide SO2 emissions by fossil
fuel-fired generating units to a permanent total emissions cap in
the year 2000. This reduction is to be achieved by the allotment
of allowances to emit SO2, measured in tons per year, to each owner
of a unit, and requiring the owner to hold sufficient allowances
each year to cover the emissions of SO2 from the unit during that
year. Allowances are transferable and able to be bought and sold.
The Company believes that, under the allowances allocation formula,
it will hold more than sufficient allowances to permit continued
operation of its existing generating units without incurring
substantial expenditures for additional SO2 controls. The Company
is marketing its surplus allowances, and has sold to a midwestern
utility company an option to purchase a quantity of the Company's
surplus allowances commencing in the year 2000. This sale has not
had a significant impact on the Company's earnings.
The same 1990 Clean Air Act amendments also contain major new
requirements for the control of nitrogen oxides that will be
applicable to generating units located in or near areas, such as
UI's service territory, where air quality standards for nitrogen
oxides and/or photochemical oxidants have not been attained. These
amendments will also require the installation and/or modification
of continuous emission monitoring systems, and require all existing
generating units to obtain operating permits. During 1993, the
Company expended approximately $12.3 million for nitrogen oxides
controls and monitoring systems during a major overhaul of the
largest generating unit at Bridgeport Harbor Station; and
approximately $1.7 million will be expended in 1994 to complete
this work. However, a federally-mandated 1994 revision to
Connecticut's plan for achieving compliance with air quality
standards for photochemical oxidants has not yet been promulgated,
and the Company is not yet able to assess accurately the
applicability and impact of implementing regulations to and on its
generating facilities. Compliance may require substantial
additional capital and operational expenditures in the future. In
addition, due to the 1990 amendments and other provisions of the
Clean Air Act, future construction or modification of fossil-fired
generating units and all other sources of air pollution in
southwestern Connecticut will be conditioned on installing state-
of-the-art nitrogen oxides controls and obtaining nitrogen oxide
emission offsets -- in the form of reductions in emissions from
other sources -- which may hinder or preclude such construction or
modification programs in UI's service area, depending on ambient
pollutant levels over which the Company has no control.
The Company's generating stations in Bridgeport and New Haven
comply with the air quality and emission performance standards
adopted by those cities.
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
- 14 -<PAGE>
<PAGE>
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, UI 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 UI to
remain in service in its system, except at one of UI's generating
stations. Compliance with TSCA regulations has necessitated
substantial capital and operational expenditures by UI, and such
expenditures may continue to be required in the future, although
their magnitude cannot now be estimated. The Company has agreed to
participate financially in the remediation of a source of PCB
contamination attributed to UI-owned electrical equipment on
property in New Haven. Although the scope of the remediation and
the extent of UI's participation have not yet been fully
determined, the owner of the property has estimated the total
remediation cost to be approximately $346,000.
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 UI handles,
stores, treats and disposes of hazardous waste products have been
revised, where necessary, to comply with these regulations.
The Company has estimated that the cost of environmental
remediation of its decommissioned Steel Point Station property in
Bridgeport, which the Company intends to sell for development, will
be approximately $10.3 million, and that the value of the property
following remediation will not exceed $6 million. In its
December 16, 1992 decision on UI's application for retail rate
increases, the DPUC provided for additional revenues to be
recovered from customers in the amount of the $4.3 million
difference during the period 1993-1996, subject to true-up in the
Company's next retail rate proceeding based on actual remediation
costs and actual gains on sale of the property.
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 has 19 underground storage
tanks, which are used primarily for gasoline and fuel oil, that are
subject to these regulations. The Company has a testing program to
detect leakage from any of its tanks, and it may incur substantial
costs for future actions taken to prevent tanks from leaking, to
remedy any contamination of groundwater, and to remove and 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.
A Connecticut statute authorizes the creation of a lien against
all real estate owned by a person causing a discharge of hazardous
waste, in favor of the DEP, for the costs incurred by the DEP to
contain and remove or mitigate the effects of the discharge.
Another Connecticut law requires a person intending to transfer
ownership of an establishment that generates more than 100
kilograms per month of hazardous waste to provide the purchaser and
the DEP with a declaration that no release of hazardous waste has
occurred on the site, or that any wastes on the site are under
control, or that the waste will be cleaned up in accordance with a
schedule approved by the DEP. Failure to comply with this law
entitles the transferee to recover damages from the transferor and
renders the transferor strictly liable for the cleanup costs. In
addition, the DEP can levy a civil penalty of up to $100,000 for
providing false information. UI does not believe that any material
claims against the Company will arise under these Connecticut laws.
- 15 -<PAGE>
<PAGE>
A Connecticut statute prohibits the commencement of construction
or reconstruction of electric generation or transmission facilities
without a certificate of environmental compatibility and public
need from the Connecticut Siting Council (CSC). In certification
proceedings, the CSC holds public hearings, evaluates the basis of
the public need for the facility, assesses its probable
environmental impact and may impose specific conditions for
protection of the environment in any certificate issued. During
1993, a citizens' group appealed to the Connecticut Superior Court
from a decision of the CSC declining to reopen the 1991
certification of a transmission line that has since been completed
by the Company and The Connecticut Light and Power Company in
Fairfield County. The Superior Court dismissed this appeal; but
the citizens' group has taken an appeal from the Superior Court's
decision, and the Company is unable to predict what impact, if any,
the group's actions will have on the operation of the transmission
facility.
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 (particularly "air toxics" and
"global warming"), hazardous waste handling and disposal, toxic
substances, and electric and magnetic fields, the Company may incur
substantial capital expenditures for equipment modifications and
additions, monitoring equipment and recording devices, and it may
incur additional operating expenses. Litigation expenditures may
also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful
health effects of electric and magnetic fields. The Company
believes any additional costs are recoverable through the
ratemaking process. The total amount of these expenditures is not
now determinable. See also Item 2. Properties - "Nuclear
Generation".
EMPLOYEES
As of December 31, 1993, the Company had 1,490 employees. Of
these, approximately 63% had been with the Company for 10 or more
years.
Approximately 762 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
May 21, 1992, the Company and the union agreed on a three-year
contract, effective May 16, 1992. There has been no work
stoppage due to labor disagreements during the past 27 years, other
than a strike of three days duration in May 1985; and employee
relations are considered satisfactory by the Company.
In the Spring of 1993, the Company commenced an organizational
study, parts of which were requested by the DPUC in its December
1992 rate order. The major objective of this organizational study
was to prepare UI to meet the needs of its customers in a highly
competitive environment. See "Competition." In November 1993, the
Company announced a reorganization at the officer level, which took
place on January 1, 1994. See "Executive Officers of the Company".
In January 1994, the Company announced a comprehensive
reorganization of its corporate structure, which calls for
approximately 650 management and non-union weekly/hourly positions
- -- a reduction of about 75 positions. Anticipating that this
reorganization would result in fewer positions, UI offered a
Voluntary Early Retirement Program (VERP) to 145 of its non-union
employees during the fourth quarter of 1993. On January 24, 1994,
the Company announced that 103 employees had elected early
retirement under this program and that, as a result of the
anticipated costs of the organizational study and the success of
the VERP, UI would record an after-tax charge of $7.8 million, or
56 cents per share, against its 1993 earnings. The Company expects to
recover this amount, through reduced operating expenses, during the
1994-1996 period. No decision has been made as to whether the
Company will offer a severance program to employees who may be
affected by the corporate reorganization when it is completed but
who were not eligible for, or did not accept, the VERP.
- 16 -<PAGE>
<PAGE>
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1993,
based on summer ratings of the generating units, was as follows:
<TABLE>
<CAPTION>
Year of Max Claimed UI
UI Operated: Fuel Installation Capability, Mw Entitlement
- --------------------------- ---- ------------ -------------- -----------
% Mw
<S> <C> <C> <C> <C> <C>
Bridgeport Harbor Station 1 #6 Oil 1957 82.00 100.00 82.00(1)
Bridgeport Harbor Station 2 #6 Oil 1961 170.00 100.00 170.00
Bridgeport Harbor Station 3 #6 Oil/
Coal 1968/1985 385.00 100.00 385.00(2)
Bridgeport Harbor Station 4 Jet Oil 1967 17.10 100.00 17.10
New Haven Harbor Station #6 Oil/
Gas 1975 447.00 93.71 418.86(3)
English Station 7 #6 Oil 1948 34.06 100.00 34.06(4)
English Station 8 #6 Oil 1953 38.49 100.00 38.49(4)
Operated by Other Utilities:
- ---------------------------
Connecticut Yankee Unit, Nuclear 1968 560.10 9.50 53.21(5)
Haddam, Connecticut
Millstone Unit 3, Nuclear 1986 1136.73 3.69 41.89(6)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1150.00 17.50 201.25(7)
Seabrook, New Hampshire
Power Purchases From
Cogeneration Facilities:
- -----------------------
Bridgeport RESCO, Refuse 1988 62.00 100.00 62.00
Bridgeport, Connecticut
Total 1503.86
=======
<FN>
(1) Effective January 1, 1994, Bridgeport Harbor Station 1 was removed from
operation and dispatching under NEPOOL and was placed in deactivated
reserve. See Item 1. Business - "Arrangements with Other Utilities."
(2) UI leases this unit from UI's wholly-owned subsidiary, Bridgeport Electric
Company (BEC), and it is subject to the lien of a first mortgage granted by
BEC. The unit has been burning coal since early January 1985.
(3) UI's 93.705% ownership share of total net capability, including 25 MW sold
to another utility for a 10-year period, commencing October 1, 1986 and 25
MW involved in a capacity exchange with another utility for a 6.5 year
period, commencing May 1, 1993. This unit is jointly owned by UI
(93.705%), Fitchburg Gas and Electric Light Company (4.5%) and the
electric departments of three Massachusetts municipalities (See Item 1.
Business - "Fuel Supply".
(4) English Station Units 7 and 8 were placed in deactivated reserve, effective
January 1, 1992.
(5) Represents UI's 9.5% entitlement in the unit. See Item 1. Business
- "Financing".
(6) Represents UI's 3.685% ownership share of total net capability.
(7) Represents UI's 17.5% ownership share of total net capability. In August
1990, UI sold to and leased back from an owner trust established for the
benefit of an institutional investor a portion of UI'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.
</TABLE>
- 17 -<PAGE>
<PAGE>
<TABLE>
<CAPTION>
TABULATION OF PEAK LOADS, RESOURCES, AND MARGINS
1993 ACTUAL, 1994 - 1998 FORECAST
(MEGAWATTS)
Actual Forecast
------ ---------------------------------------
1993 1994 1995 1996 1997 1998
<S> <C> <C> <C> <C> <C> <C>
At Time of Peak Load
on UI's System:
- -------------------
Capacity of generating
units operated by UI (1) 1072.96 990.96 990.96 990.96 990.96 990.96
- -------------------------
Entitlements in nuclear
units (1) (2)
- -----------------------
Connecticut Yankee Unit 53.21 53.21 53.21 53.21 53.21 53.21
Millstone Unit 3 41.89 41.89 41.89 41.89 41.89 41.89
Seabrook Unit 1 201.25 201.25 201.25 201.25 201.25 201.25
------- ------- ------- ------- ------- -------
296.35 296.35 296.35 296.35 296.35 296.35
------- ------- ------ ------- ------- -------
Equivalent capacity value
of the entitlement in
Hydro-Quebec (1) (2) 98.10 98.10 98.10 98.10 98.10 98.10
- -------------------------
Purchases from cogeneration
facilities
- ---------------------------
Bridgeport RESCO 62.00 62.00 62.00 62.00 62.00 62.00
Shelton Landfill (3) 1.88 1.74 1.61 1.50
Purchase from New York
Power Authority 1.03 1.18 1.18 1.18 1.18 1.18
- ----------------------
Purchases from (sales to)
other utilities
- -------------------------
Net power contracts - fossil (15.00) (10.00) 27.00 30.00 40.00 40.00
------- ------- ------- ------- ------- -------
Total generating resources 1515.44 1438.59 1477.47 1480.33 1490.20 1490.09
======= ======= ======= ======= ======= =======
Calculation of NEPOOL
capability responsibility (4)
- ------------------------------
Peak load 1115.00 1134.00 1143.00 1160.00 1176.00 1186.00
Required reserve margin 118.57 210.48 236.46 240.20 243.72 245.92
------- ------- ------- ------- ------- -------
Total capability
responsibility 1233.57 1344.48 1379.46 1400.20 1419.72 1431.92
======= ======= ======= ======= ======= =======
Available Margin (5) 281.87 94.11 98.01 80.13 70.48 58.17
<FN>
(1) Capacity shown reflects summer ratings of generating units.
(2) Winter ratings of UI nuclear and Hydro-Quebec interconnection's equivalent
capacity value entitlements (megawatts):
Connecticut Yankee Unit - 56.05
Millstone Unit 3 - 42.33
Seabrook Unit 1 - 201.25
Hydro-Quebec - 66.22
(3) Projected to begin commercial operation by September 1994.
(4) UI's required capacity as a NEPOOL participant.
(5) Total generating resources less capability responsibility. In addition, UI
maintains three units (Bridgeport Harbor Station 1 and English Station 7
and 8) in deactivated reserve. A total of 154 MW of capacity can be
generated by these units.
</TABLE>
- 18 -<PAGE>
During 1993, the peak load on the Company's system was
approximately 1,115 megawatts, which occurred in July. UI's total
generating capability at the time was 1,515 megawatts, including a
98 megawatt increase in capability provided by the equivalent
capacity value of UI's entitlements in the Hydro-Quebec facility
and reflecting the net effect of temporary arrangements with other
electric utilities and cogenerators. The Company is currently
forecasting a compound growth in peak load of 1.2% during the
period 1993 to 2003. Based on current forecasts of loads, UI's
generating capability will exceed its projected capability
responsibility to NEPOOL for generating capacity through at least
1999, and English Station Units 7 and 8 and Bridgeport Harbor
Station Unit 1 can be reactivated if higher than anticipated load
growth occurs. If, due to the permanent loss of a generating unit
or higher than expected load growth, UI's own generating capability
becomes inadequate to meet its capability responsibility to NEPOOL,
UI expects to be able to reduce the load on its system by the
implementation of additional demand-side management programs, to
acquire other demand-side and supply-side resources, and/or to
purchase capacity from other utilities as necessary. However,
because the generation and transmission systems of the major New
England utilities, including UI, are operated as if they were a
single system, the ability of UI to meet its load is and will be
dependent on the ability of these New England utilities to meet the
region's load. At the time of the NEPOOL summer peak in July 1993,
these New England utilities had 26,555 megawatts of generating
capacity, including 1,500 megawatts of interconnection credit of
the Hydro-Quebec facility, available to meet the New England peak
load of 19,570 megawatts. See "Seabrook", "Nuclear Generation" and
Item 1. Business - "Competition" and "Arrangements with Other
Utilities".
Shown below is a summary of the Company's sources and uses of
electricity for 1993.
<TABLE>
<CAPTION>
Megawatthours
-------------
(000's)
Sources Uses
- ------- ----
<S> <C> <S> <C>
Owned Retail Customers 5,290
Nuclear (Millstone Unit 3
and Seabrook Unit 1) 1,823
Coal 1,976 Wholesale
Oil 1,932 Delivered to NEPOOL 1,160
Gas & Gas Turbines 26 Contracts 1,031
-----
Total Owned 5,757
Company Use & Losses 340
-----
Purchased
Nuclear (Connecticut Yankee Unit) 356 Total Uses 7,821
Contracts 842 =====
NEPOOL 515
Hydro-Quebec 351
-----
Total Sources 7,821
=====
</TABLE>
TRANSMISSION AND DISTRIBUTION PLANT
The transmission lines of the Company consist of approximately
95 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 immediately adjacent to the territory served by
the Company. These transmission lines interconnect the Company's
English, 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 a railroad right-of-way pursuant to a
Transmission Line Agreement that expires in May 2000.
The Company owns and operates 23 bulk electric supply
substations with a capacity of 2,547,000 KVA and 50 distribution
substations with a capacity of 288,750 KVA. The Company has 3,113
pole-line miles of overhead distribution lines and 130 conduit-bank
miles of underground distribution lines.
- 19 -<PAGE>
<PAGE>
See "Capital Expenditure Program" concerning the estimated cost
of additions to the Company's transmission and distribution
facilities.
SEABROOK
The Company has a 17.5% share in Seabrook Unit 1, a 1,150
megawatt nuclear generating unit located in Seabrook, New
Hampshire. Eleven other New England electric utilities have
ownership shares in Unit 1.
After experiencing increasing financial stress beginning in May
1987, Public Service Company of New Hampshire (PSNH), which held
the largest ownership share (35.6%) in Seabrook, commenced a
proceeding under Chapter 11 of the Bankruptcy Code in January of
1988. Under this statute, PSNH continued its operations while
seeking a financial reorganization. A reorganization plan proposed
by Northeast Utilities (NU) was confirmed by the bankruptcy court
in April of 1990 and, on May 16, 1991, PSNH completed the financing
required for payment of its pre-bankruptcy secured and unsecured
debt under the first stage of the reorganization plan and emerged
from bankruptcy. On May 19, 1992, the NRC issued the final
regulatory approval necessary for the second stage of the NU
reorganization plan, under which PSNH would be acquired by NU; and
on June 5, 1992, this acquisition was completed. As part of the
transaction, PSNH's ownership share of Seabrook Unit 1 was
transferred to a wholly-owned subsidiary of NU. Two previous
regulatory approvals of the NU reorganization plan for PSNH, by the
Federal Energy Regulatory Commission (FERC) and the Securities and
Exchange Commission (SEC), continue to be challenged in court
proceedings, and the Company is unable to predict the outcome of
these proceedings.
On February 28, 1991, EUA Power Corporation (EUA Power), the
holder of a 12.1% ownership share in Seabrook, commenced a
proceeding under Chapter 11 of the Bankruptcy Code. EUA Power, a
wholly-owned subsidiary of Eastern Utilities Associates (EUA), was
organized solely for the purpose of acquiring an ownership share in
Seabrook and selling in the wholesale market its share of the
electric power produced by Seabrook. EUA Power commenced this
bankruptcy proceeding because the cash generated by its sales of
power at current market prices was insufficient to pay its
obligations on its outstanding debt. Subsequently, EUA Power's
name was changed to Great Bay Power Corporation (Great Bay). The
official committee of Great Bay's bondholders (Bondholders
Committee) has proposed, and the bankruptcy court has confirmed, a
reorganization plan for Great Bay, under which substantially all of
the equity ownership of Great Bay would pass to its bondholders.
On February 2, 1994, the Bondholders Committee accepted a financing
proposal that would inject $35 million of new ownership equity into
Great Bay. The bankruptcy court must approve this structure before
the Great Bay reorganization plan becomes effective. Further
approvals are also required from the NRC, FERC and the New
Hampshire Public Utilities Commission. The bankruptcy court has
approved an agreement among Great Bay, the Bondholders Committee,
UI and The Connecticut Light and Power Company (CL&P), under which
up to $20 million in advance payments against their respective
future monthly Seabrook payment obligations will be made available
between UI and CL&P as needed until the reorganization plan becomes
effective. UI's share of funding obligations under this agreement
totals $8 million. As of December 31, 1993, $5.5 million had been
advanced by UI under this agreement. At January 31, 1994, $602,000
of the Company's advances remained outstanding. This agreement can
be terminated by UI and CL&P upon thirty days notice or upon
failure of the reorganization process to achieve certain milestones
by specified dates. UI is unable to predict what impact, if any,
failure of the reorganization plan to become effective will have on
the operating license for Seabrook Unit 1, or what other actions UI
and the other joint owners of the unit may be required to take in
response to developments in this bankruptcy proceeding as it may
affect Seabrook.
Nuclear generating units are subject to the licensing
requirements of the Nuclear Regulatory Commission (NRC) under the
Atomic Energy Act of 1954, as amended, and a variety of other state
and federal requirements. Although Seabrook Unit 1 has been issued
a 40-year operating license, NRC proceedings and investigations
prompted by inquiries from Congressmen and by NRC licensing board
consideration of technical contentions may arise and continue for
an indefinite period of time in the future. See "Nuclear
Generation".
- 20 -<PAGE>
<PAGE>
CAPITAL EXPENDITURE PROGRAM
The Company's 1994-1998 capital expenditure program, excluding
allowance for funds used during construction (AFUDC) and its
effect on certain capital related items, is presently budgeted as
follows:
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998 Total
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Production $23,688 $19,428 $22,308 $ 4,824 $15,180 $ 85,428
Distribution 10,140 21,840 21,288 22,164 21,588 97,020
Transmission 12,096 16,980 10,800 6,336 11,376 57,588
Conservation and
Load Management 11,988 11,892 10,860 10,716 10,320 55,776
Nuclear Fuel 4,980 6,756 11,280 1,248 11,820 36,084
Other 10,532 7,981 6,096 6,036 4,020 34,665
------- -------- ------- ------- ------- --------
Total Expenditures $73,424 $ 84,877 $82,632 $51,324 $74,304 $366,561
======= ======== ======= ======= ======= ========
AFUDC (Pre-tax) $4,934 $3,431 $2,474 $1,940 $1,968
Capitalized Interest 4,151 2,890 2,084 1,638 1,669
Book Depreciation 57,053 62,438 66,425 69,382 72,288
Decommissioning 2,741 2,794 2,851 1,841 1,909
Normalized Tax
Depreciation 33,086 36,392 38,708 40,194 41,368
Accelerated Tax
Depreciation 74,722 69,548 60,738 62,214 61,424
Amortization of Deferred
Return on Seabrook
Unit 1 Phase-In (1) 0 (12,635) (12,635) (12,635) (12,635)
Estimated Rate Base
(end of period) $1,218,137 $1,239,962 $1,254,603 $1,227,959 $1,203,104
<FN>
(1) Deferred return will be amortized over the period 1995-1999.
</TABLE>
- 21 -<PAGE>
<PAGE>
NUCLEAR GENERATION
General
UI holds ownership and leasehold interests in Seabrook Unit 1
(17.5%) and Millstone Unit 3 (3.685%). UI also owns 9.5% of the
common stock of Connecticut Yankee and is entitled to 9.5% of the
generating capability of its nuclear generating unit. Each of
these nuclear generating units is 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 UI 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 the nuclear generating units in which UI has interests 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 the generating units that would not
otherwise be necessary and that result in additional costs for
replacement power. The amounts of additional capital expenditures,
increased operating costs and replacement power 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 the nuclear generating units in which UI has interests.
Proposals to force the premature shutdown of nuclear plants in
other New England states have received serious attention, and the
licensing of Seabrook Unit 1 was a regional issue. The continuing
controversy can be expected to increase the costs of operating the
nuclear generating units in which UI has interests; and it is
possible that one or more of the units could be shut down
prematurely.
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 $75.5 million per
incident, levied on each of the nuclear units licensed to operate
in the United States, subject to a maximum assessment of $10
million per incident per nuclear unit in any year. In addition, if
the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial
protection, each reactor operator can be assessed an additional 5%
of $75.5 million, or $3.775 million. The maximum assessment is
adjusted at least every five years to reflect the impact of
inflation. Based on its interests in nuclear generating units, the
Company estimates its maximum liability would be $20.3 million per
incident. However, assessment would be limited to $3.1 million per
incident, per year. With respect to each of the 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.
The NRC requires nuclear generating units 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 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.
- 22-<PAGE>
<PAGE>
Waste Disposal and 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, beginning in 1998, 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 is to
take title to and dispose of the utilities' high level wastes and
spent nuclear fuel beginning no later than 1998. However, the DOE
has announced that its first high level waste repository will not
be in operation earlier than 2010, notwithstanding the DOE's
statutory and contractual responsibility to begin disposal of
high-level radioactive waste and spent fuel beginning not later
than January 31, 1998.
Until the federal government begins receiving such materials in
accordance with the Nuclear Waste Policy Act, operating nuclear
generating units will need to retain high level wastes and spent
fuel on-site or make other provisions for their storage. Storage
facilities for Millstone Unit 3 are expected to be adequate for the
projected life of the unit. Storage facilities for the Connecticut
Yankee unit are expected to be adequate through the mid-1990s.
Storage facilities for Seabrook Unit 1 are expected to be adequate
until at least 2010. Fuel consolidation and compaction
technologies are being developed and are expected to provide
adequate storage capability for the projected lives of the latter
two units. In addition, other licensed technologies, such as dry
storage casks, can accommodate spent fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that
result from normal operation of nuclear generating units have
increased significantly in recent years and are expected to
continue to rise. The cost increases are functions of increased
packaging and transportation costs and higher fees and surcharges
charged by the disposal facilities. Pursuant to the Low-Level
Radioactive Waste Policy Act of 1980, each state was responsible
for providing disposal facilities for LLW generated within the
state and was authorized to join with other states into regional
compacts to jointly fulfill their responsibilities. Pursuant to
the Low-Level Radioactive Waste Policy Amendments Act of 1985, each
state in which a currently operating disposal facility is located
(South Carolina, Nevada and Washington) is allowed to impose volume
limits and a surcharge on shipments of LLW from states that are not
members of the compact in the region in which the facility is
located. On June 19, 1992, the United States Supreme Court issued
a decision upholding certain parts of the Low-Level Radioactive
Waste Policy Amendments Act of 1985, but invalidating a key
provision of that law requiring each state to take title to LLW
generated within that state if the state fails to meet federally-
mandated deadlines for siting LLW disposal facilities. The
decision has resulted in uncertainty about states' continuing roles
in siting LLW disposal facilities and may result in increased LLW
disposal costs and the need for longer interim LLW storage before
a permanent solution is developed.
The Connecticut Hazardous Waste Management Service (the
Service), a state quasi-public corporation, was charged with
coordinating the establishment of a facility for disposal of LLW
originating in Connecticut. In June 1991, the Service announced
that it had selected three potential sites in north-central
Connecticut for further study. The Service's announcement provoked
intense controversy in the affected municipalities and resulted in
legislative action to stop the selection process. On February 1,
1993, the Service presented the legislature with a new site
selection plan under which communities are urged to volunteer a
site for a facility in return for financial and other incentives.
The volunteer process is being continued in 1994. The Service's
activities in this regard are funded by assessments on
Connecticut's LLW generators. Due to a change in the volunteer
process, there was no assessment for the 1993-1994 fiscal year and
the state projects no assessment for the 1994-1995 and 1995-1996
fiscal years.
Additional LLW storage capacity has been or can be constructed
or acquired at the Millstone and Connecticut Yankee sites to
provide for temporary storage of LLW should that become necessary.
Connecticut
- 23 -<PAGE>
<PAGE>
LLW can be managed by volume reduction, storage or shipment at
least through 1999. The Company cannot predict whether and when a
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 Seabrook
Unit 1 has been denied access to existing disposal facilities.
Therefore, LLW generated by Seabrook Unit 1 is being stored on-
site. The Seabrook storage facility currently has capacity to
store approximately five years' accumulation of waste generated by
Seabrook, and the plant operator plans to expand its storage
capacity as necessary.
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. UI and the other owners of the nuclear
generating units in which UI has interests estimate decommissioning
costs for the units and attempt to recover sufficient amounts
through their allowed electric rates to cover expected
decommissioning costs. Changes in NRC requirements or technology
can increase estimated decommissioning costs, and UI's customers in
future years may experience higher electric rates to offset the
effects of any insufficient rate recovery in prior years.
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) established $345 million
(in 1993 dollars) as the decommissioning cost estimate for Seabrook
Unit 1. This estimate premises the prompt removal and dismantling
of the Unit at the end of its estimated 40-year energy producing
life. Monthly decommissioning payments are being made to the
state-managed decommissioning trust fund. UI's share of the
decommissioning payments made during 1993 was $1.3 million. UI's
share of the fund at December 31, 1993 was approximately $3.7
million.
Connecticut has enacted a law requiring the operators of nuclear
generating units to file periodically with the DPUC their plans for
financing the decommissioning of the units in that state. Current
decommissioning cost estimates for Millstone Unit 3 and Connecticut
Yankee are $421 million (in 1994 dollars) and $324 million (in 1994
dollars), respectively. These estimates premise the prompt removal
and dismantling of each unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on
these cost estimates, are being made to decommissioning trust funds
managed by Northeast Utilities. UI's share of the Millstone Unit
3 decommissioning payments made during 1993 was $328,000. UI's
share of the fund at December 31, 1993 was approximately $1.9
million. For the Company's 9.5% equity ownership in Connecticut
Yankee, decommissioning costs of $1.3 million were funded by UI
during 1993, and UI's share of the fund at December 31, 1993 was
$9.5 million.
Item 3. Legal Proceedings.
See Item 2. Properties - "Seabrook".
On October 27, 1992, the Company's wholly-owned subsidiary,
Bridgeport Electric Company (BEC) received personal property tax
bills from the City of Bridgeport (the City) for the then current
and two past tax years, aggregating $26.7 million, based on an
assertion that BEC did not list its only asset, Bridgeport Harbor
Station generating Unit No. 3, on the City's tax lists during the
three years. The Company listed and paid taxes on this generating
unit in each of the three years, based on values agreed upon in a
1988 court-approved settlement with the City of prior years' tax
litigation. BEC subsequently commenced an action in the Superior
Court against the City to enjoin the City from any effort to
collect the personal property tax bills it had sent to BEC. On
June 10, 1993, the Superior Court, in denying the City's motion to
strike BEC's complaint, decided that the City had not followed the
prescribed procedures in assessing and levying taxes on BEC. Since
the time period for assessing and levying taxes for the earliest of
the three years at issue has expired, the effect of this decision
was to remove $10 million of the City's $26.7 million claim from
the controversy and to require the City to reinstitute its
assessment and levying proceeding with respect to the other two
years, and the remaining $16.7 million, at issue. The City,
without prejudice to its taking such an appeal, has attempted to
remedy the assessment and levying procedures found deficient by the
Superior Court by holding hearings. On October 14, 1993, following
these
- 24 -<PAGE>
<PAGE>
hearings, the City issued "corrected" personal property tax bills
to Bridgeport Electric Company for the tax years 1986-1987 through
1992-1993 aggregating $81.6 million, with interest through June 30,
1993 in the aggregate amount of $61.5 million. BEC has stated that
it will not pay these tax bills, and it and the Company are
contesting the City's tax claim vigorously. BEC has commenced a
second action in the Superior Court to enjoin the City from any
effort to collect these tax bills. It is the present opinion of
the Company's Counsel that the City will not prevail in efforts to
collect these tax bills, and that BEC and the Company will be able
to defend against such efforts successfully.
On November 2, 1993, the Company received "updated" personal
property tax bills from the City of New Haven (the City) for the
tax year 1991-1992, aggregating $6.6 million, based on an audit by
the City's tax assessor. The Company anticipates receiving
additional bills of this sort for the tax years 1992-1993 and
1993-1994, the amounts of which cannot be predicted at this time.
The Company is contesting these tax bills vigorously and has
commenced an action in the Superior Court to enjoin the City from
any effort to collect these tax bills. Due to a lack of data, it
is not possible, at this time, to assess accurately the Company's
liability, if any.
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, 1993.
- 25 -<PAGE>
<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>
Richard J. Grossi 58 Chairman of the Board of May 1, 1991
Directors and Chief
Executive Officer
Robert L. Fiscus 56 President and Chief May 1, 1991
Financial Officer
James F. Crowe 51 Executive Vice President January 1, 1994
and Chief Customer Officer
Walter E. Barker 56 Vice President-Transmission
and Distribution
Rita L. Bowlby 55 Vice President-Corporate February 1, 1993
Affairs
Stephen F. Goldschmidt 48 Vice President-Information January 1, 1994
Resources
Albert N. Henricksen 52 Vice President-Administration January 1, 1994
David W. Hoskinson 58 Vice President-Generation January 1, 1994
Robert H. Hyde 53 Vice President-Customer January 1, 1986
Services
E. Jon Majkowski 51 Vice President May 1, 1992
Anthony J. Vallillo 45 Vice President-Marketing June 1, 1992
James L. Benjamin 52 Controller January 1, 1981
Kurt D. Mohlman 45 Treasurer and Secretary January 1, 1994
Charles J. Pepe 45 Assistant Treasurer and January 1, 1994
Assistant Secretary
</TABLE>
- 26 -<PAGE>
<PAGE>
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 and Messrs. Grossi, Fiscus and Crowe have each entered
into an employment agreement 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:
Richard J. Grossi. Mr. Grossi served as President and Chief
Operating Officer during the period January 1, 1989 to May 1, 1991.
He has served as Chairman of the Board of Directors and Chief
Executive Officer since May 1, 1991.
Robert L. Fiscus. Mr. Fiscus served as Executive Vice
President and Chief Financial Officer of the Company during the
period January 1, 1989 to May 1, 1991. He has served as President
and Chief Financial Officer since May 1, 1991.
James F. Crowe. Mr. Crowe served as Senior Vice
President-Marketing of the Company during the period January 1,
1989 to May 1, 1992, and as Executive Vice President from May 1,
1992 to January 1, 1994. He has served as Executive Vice President
and Chief Customer Officer since January 1, 1994.
Walter E. Barker. Mr. Barker served as Superintendent of
Transmission and Distribution of the Company during the period
January 1, 1989 to July 23, 1990, and as Vice President-Transmission
and Distribution Engineering and Operations from July 23, 1990 to
January 1, 1994. He has served as Vice President-Transmission and
Distribution since January 1, 1994.
Rita L. Bowlby. Ms. Bowlby has served as Vice President-
Corporate Affairs since February 1, 1993. Prior to joining the
Company, during the period from January 1, 1989 to February 1,
1993, she served as President of Bowlby & Associates, a business-
to-business communications agency in Farmington, Connecticut.
Stephen F. Goldschmidt. Mr. Goldschmidt served as Vice
President-Planning from January 1, 1989 to January 1, 1994. He has
served as Vice President-Information Resources since January 1,
1994.
Albert N. Henricksen. Mr. Henricksen served as Vice
President-Engineering of the Company during the period January 1,
1989 to July 23, 1990, and as Vice President-Human and
Environmental Resources from July 23, 1990 to January 1, 1994. He
has served as Vice President-Administration since January 1, 1994.
David W. Hoskinson. Mr. Hoskinson served as Senior Vice
President-Operations of the Company during the period January 1,
1989 to July 23, 1990, and as Senior Vice President-Generation
Engineering and Operations from July 23, 1990 to January 1, 1994.
He has served as Vice President-Generation since January 1, 1994.
Robert H. Hyde. Mr. Hyde has served as Vice President-Customer
Services of the Company since January 1, 1989.
E. Jon Majkowski. Mr. Majkowski served as Vice
President-Public Affairs of the Company during the period January
1, 1989 to May 1, 1992. He has served as Vice President since May
1, 1992.
Anthony J. Vallillo. Mr. Vallillo served as Director of Sales
and Market Development of the Company during the period January 1,
1989 to December 1, 1990, and as Director of Marketing from
December 1, 1990 to June 1, 1992. He has served as Vice
President-Marketing since June 1, 1992.
James L. Benjamin. Mr. Benjamin has served as Controller of
the Company since January 1, 1989.
- 27 -<PAGE>
<PAGE>
Kurt D. Mohlman. Mr. Mohlman served as Director of Financial
Planning during the period January 1, 1989 to September 1, 1990 and
as Director of Financial Planning and Investor Relations from
September 1, 1990 to January 1, 1994. He has served as Treasurer
and Secretary of the Company since January 1, 1994.
Charles J. Pepe. Mr. Pepe served as Director of Financing
during the period January 1, 1989 to January 1, 1994. He has
served as Assistant Treasurer and Assistant Secretary of the
Company since January 1, 1994.
- 28 -<PAGE>
<PAGE>
PART II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters.
UI's Common Stock is traded on the New York Stock Exchange,
where the high and low sale prices during 1993 and 1992 were as
follows:
<TABLE>
<CAPTION>
1993 Sale Price 1992 Sale Price
--------------- ---------------
High Low High Low
---- --- ---- ---
<S> <C> <C> <C> <C>
First Quarter 43 5/8 41 38 7/8 34 1/8
Second Quarter 44 41 3/4 37 3/8 35 7/8
Third Quarter 45 7/8 42 5/8 39 7/8 36 5/8
Fourth Quarter 45 1/4 38 1/2 42 38 1/2
</TABLE>
UI has paid quarterly dividends on its Common Stock since 1900.
The quarterly dividends declared in 1992
and 1993 were at a rate of 64 cents per share and 66 1/2 cents per
share, respectively.
The indenture under which the Company's Medium-Term Notes and
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 $82.6 million
were free from such limitations at December 31, 1993.
As of January 31, 1994, there were 21,919 Common Stock
shareowners of record.
- 29 -<PAGE>
<PAGE>
<TABLE>
Item 6. Selected Financial Data
<CAPTION>
1993 1992 1991
================================================================================
<S> <C> <C> <C>
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity:
Retail
Residential $238,185 $226,455 $226,751
Commercial 256,559 253,456 (2) 255,782
Industrial 97,466 97,010 (2) 91,895
Other 11,349 11,065 10,886
---------- ---------- ----------
Total Retail 603,559 587,986 585,314
Wholesale (1) 45,931 75,484 84,236
Other operating revenues 3,533 3,855 3,821
---------- ---------- ----------
Total operating revenues 653,023 667,325 673,371
---------- ---------- ----------
Fuel and interchange energy -net:
Retail -own load 98,694 108,084 123,010
Wholesale 39,356 55,169 61,858
Capacity purchased-net 47,424 43,560 44,668
Depreciation 56,287 50,706 48,181
Other operating expenses,
excluding tax expense 205,207 193,841 189,327
Gross earnings tax 27,955 27,362 27,223
Other non-income taxes 29,977 31,869 28,673
---------- ---------- ----------
Total operating expenses, excluding
income taxes 504,900 510,591 522,940
---------- ---------- ----------
Deferred return Seabrook Unit 1 7,497 15,959 17,970
AFUDC 4,067 3,232 5,190
Other non-operating income(loss) 71 18,545 2,697
Interest expense:
Long-term debt 80,030 88,666 90,296
Other 12,260 12,882 9,847
---------- ---------- ----------
Total 92,290 101,548 100,143
---------- ---------- ----------
Income tax expense:
Operating income tax 33,309 48,712 47,231
Non-operating income tax (6,322) (12,558) (19,299)
---------- ---------- ---------
Total 26,987 36,154 27,932
---------- ---------- ---------
Income(loss) before cumulative effect of
accounting change 40,481 56,768 48,213
Cumulative effect of change in accounting
for property taxes - net of tax 0 0 7,337
---------- ---------- ---------
Net income (loss) 40,481(3) 56,768 55,550
Preferred and preference stock dividends 4,318 4,338 4,530
---------- ---------- ---------
Income (loss) applicable to common stock $36,163 $52,430 $51,020
- -------------------------------------------------------------------------------
Operating income $114,814 $108,022 $103,200
===============================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $1,243,426 $1,224,058 $1,219,871
Construction work in progress 77,395 59,809 54,771
Plant-related regulatory asset 0 0 0
Other property and investments 58,096 65,320 79,009
Current assets 187,981 247,954 164,839
Regulatory assets 567,394 556,493 554,365
---------- ---------- ----------
Total Assets $2,134,292 $2,153,634 $2,072,855
- -------------------------------------------------------------------------------
Common stock equity $423,324 $422,746 $401,771
Preferred and preference stock
Not subject to mandatory redemption 60,945 60,945 62,640
Subject to mandatory redemption 0 0 0
Long-term debt excluding current portion 875,268 893,457 909,998
Noncurrent liabilities 29,119 25,853 96,973
Current portion of long-term debt 143,333 92,833 37,500
Notes payable 0 84,099 13,000
Other current liabilites 150,890 133,471 127,524
Regulatory liabilities and other 451,413 440,230 423,449
---------- ---------- ----------
Total Capitalization and Liabilities $2,134,292 $2,153,634 $2,072,855
===============================================================================
<FN>
(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 effect of a reorganization charge of $7.8 million.
</TABLE>
- 30 -<PAGE>
<PAGE>
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984
=============================================================================
<C> <C> <C> <C> <C> <C> <C>
$211,891 $205,183 $200,170 $188,740 $178,268 $190,880 $185,209
234,704 219,852 208,801 195,972 180,888 192,658 187,112
94,526 92,855 96,665 100,354 99,939 118,637 124,118
10,536 9,943 9,732 9,480 9,516 10,367 10,664
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
551,657 527,833 515,368 494,546 468,611 512,542 507,103
85,657 77,925 63,263 54,708 48,010 49,164 45,021
3,332 3,348 3,570 3,077 2,508 2,394 2,367
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
640,646 609,106 582,201 552,331 519,129 564,100 554,491
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
119,285 128,739 121,425 131,471 126,778 175,764 233,423
69,117 62,681 53,837 51,411 46,466 49,066 45,021
42,827 50,234 35,465 17,746 15,028 10,112 11,724
36,526 35,618 24,069 37,160 22,112 18,128 15,952
180,592 155,282 143,822 138,315 131,448 122,567 95,309
25,595 24,506 23,948 22,997 21,838 25,221 25,474
24,648 20,294 21,695 17,194 17,991 16,566 18,891
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
498,590 477,354 424,261 416,294 381,661 417,424 445,794
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
21,503 0 0 0 0 0 0
3,443 65,443 75,656 81,419 78,044 62,623 57,242
22,654 (219,742) (23,369) (97,686) (75,380) 29,838 (16,719)
94,056 91,126 90,022 88,700 88,610 72,068 45,417
15,468 22,849 12,069 9,228 2,223 5,334 6,934
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
109,524 113,975 102,091 97,928 90,833 77,402 52,351
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
43,493 37,963 44,045 50,633 51,419 62,047 44,371
(17,409) (101,135) (14,548) (37,440) (33,884) (3,317) (15,913)
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
26,084 (63,172) 29,497 13,193 17,535 58,730 28,458
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
54,048 (73,350) 78,639 8,649 31,764 103,005 68,411
0 0 0 0 0 0 0
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
54,048 (73,350) 78,639 8,649 31,764 103,005 68,411
4,751 8,233 11,348 11,953 18,969 20,339 16,883
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
$49,297 ($81,583) $67,291 ($3,304) $12,795 $82,666 $51,528
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
$98,563 $93,789 $113,895 $85,404 $86,049 $84,629 $64,326
=============================================================================
$1,209,173 $562,473 $560,930 $563,210 $571,549 $425,873 $360,054
50,257 675,831 812,246 737,169 742,585 845,112 749,566
0 81,768 88,339 68,603 55,497 0 0
90,006 91,648 83,860 76,032 70,927 60,127 61,166
161,066 170,823 166,270 122,075 107,399 214,057 198,532
553,986 605,696 653,418 610,913 607,294 93,350 97,386
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
$2,064,488 $2,188,239 $2,365,063 $2,178,002 $2,155,251 $1,638,519 $1,466,704
- -----------------------------------------------------------------------------
$379,812 $362,584 $473,674 $438,564 $476,108 $493,261 $434,030
69,700 70,000 70,000 70,000 70,000 70,000 70,000
0 0 34,000 40,000 63,000 96,000 99,000
899,993 868,884 862,287 767,559 661,548 664,648 567,736
99,933 107,781 111,971 95,070 81,263 59,814 51,242
41,667 18,667 3,667 28,667 18,667 3,667 3,667
15,000 45,000 0 0 25,675 0 34,000
149,090 142,878 122,237 117,009 100,666 131,803 121,632
409,293 572,445 687,227 621,133 658,324 119,326 85,397
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
$2,064,488 $2,188,239 $2,365,063 $2,178,002 $2,155,251 $1,638,519 $1,466,704
=============================================================================
</TABLE>
- 31 -<PAGE>
<PAGE>
<TABLE>
Item 6. Selected Financial Data (continued)
<CAPTION>
1993 1992 1991
================================================================================
<S> <C> <C> <C>
COMMON STOCK DATA
Average number of shares outstanding 14,063,854 13,941,150 13,899,906
Number of shares outstanding at year-end 14,083,291 14,033,148 13,932,348
Earnings (loss) per share (average) $2.57(3) $3.76 $3.67(1)
Book value per share $30.06 $30.12 $28.84
Average return on equity
Total 8.45% 12.67% 13.01%
Utility 10.97% 14.46% 13.39%
Dividends declared per share $2.66 $2.56 $2.44
Market Price:
High $45.875 $42.000 $39.125
Low $38.500 $34.125 $30.000
Year-end $40.250 $41.500 $39.000
================================================================================
Net cash provided by operating
activities, less dividends ($000's) $102,989 $109,020 $73,865
Capital expenditures,
excluding AFUDC $94,743 $66,390 $63,157
================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWH's)
Residential 1,844,041 1,799,456 1,851,447
Commercial 2,359,023 2,303,216(2) 2,347,757
Industrial 1,036,547 997,168(2) 980,071
Other 50,715 52,984 55,118
--------- --------- ---------
Total 5,290,326 5,152,824 5,234,393
--------- --------- ---------
Number of retail customers by class
(average)
Residential 273,752 273,936 274,064
Commercial 28,968 28,848(2) 29,768
Industrial 959 1,017(2) 268
Other 1,175 1,358 1,361
--------- --------- ---------
Total 304,854 305,159 305,461
--------- --------- ---------
System requirements (MWH) 5,630,581 5,475,664 5,541,477
Peak load - kilowatts 1,114,900 1,034,440 1,145,820
Generating capability- peak(kilowatts) 1,515,420 1,402,800 1,474,190
Fuel generation mix percentages
Coal 31 34 34
Oil 16 17 21
Nuclear 38 35 29
Cogeneration 8 8 9
Gas 1 1 4
Hydro 6 5 3
- --------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $605,887 $608,176 $607,997
Fuel Adjustment Clause (2,328) (41,221) (37,497)
Sales Provision Adjustment 0 21,031 14,814
--------- --------- ---------
Total $603,559 $587,986 $585,314
--------- --------- ---------
Revenue - retail sales per KWH (cents)
Base 11.45 11.80 11.62
Fuel Adjustment Clause (0.04) (0.80) (0.72)
Sales Provision Adjustment 0.00 0.41 0.28
--------- --------- ---------
Total 11.41 11.41 11.18
--------- --------- ---------
Fuel and energy cost per KWH (cents) 1.75 2.43 2.67
Fossil 2.08 2.98 3.11
Nuclear 1.23 1.42 1.62
- --------------------------------------------------------------------------------
Number of employees 1,490 1,554 1,571
Total payroll ($000's) $75,305 $74,052 $71,888
================================================================================
<FN>
(1) Includes the cumulative effect of accounting change for municipal property
taxes which increased earnings by $0.53 per share.
(2) Includes reclassification of certain Commercial and Industrial customers.
(3) Includes the effect of a reorganization charge which decreased earnings
by $.56 per share.
</TABLE>
- 32 -<PAGE>
<PAGE>
<TABLE>
<CAPTION>
1990 1989 1988 1987 1986 1985 1984
================================================================================
<C> <C> <C> <C> <C> <C> <C>
13,887,748 13,887,748 13,887,748 13,887,654 13,827,431 13,623,093 13,213,526
13,887,748 13,887,748 13,887,748 13,887,748 13,886,566 13,720,050 13,429,443
$3.55 ($5.87) $4.85 ($0.24) $0.93 $6.07 $3.90
$27.35 $26.11 $34.11 $31.58 $34.29 $35.95 $32.32
13.39% -18.88% 14.75% -0.72% 2.64% 17.83% 12.23%
13.97% 20.21% 32.91% 15.34% 16.81% 16.21% 15.82%
$2.32 $2.32 $2.32 $2.32 $2.32 $2.08 $2.30
$34.125 $34.25 $27.50 $34.00 $36.25 $27.125 $23.875
$26.875 $24.75 $19.125 $21.25 $26.625 $13.75 $9.00
$31.125 $34.25 $26.875 $26.875 $29.25 $27.00 $13.75
================================================================================
$39,189 $31,437 $40,607 $37,986 $16,796 $47,239 $32,402
$64,018 $77,041 $83,735 $73,253 $116,124 $116,480 $153,136
================================================================================
1,826,700 1,883,363 1,870,318 1,780,333 1,700,302 1,654,591 1,642,564
2,259,340 2,254,099 2,174,200 2,046,289 1,914,889 1,810,192 1,729,027
1,060,751 1,109,119 1,186,336 1,236,151 1,232,209 1,286,402 1,314,328
58,013 60,427 61,303 62,246 65,533 68,064 71,998
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
5,204,804 5,307,008 5,292,157 5,125,019 4,912,933 4,819,249 4,757,917
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
275,637 276,385 274,884 271,302 267,509 264,112 261,023
29,808 29,526 28,826 28,103 27,215 26,679 26,209
319 347 367 369 372 386 412
1,352 1,316 1,267 1,191 1,179 1,145 1,151
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
307,116 307,574 305,344 300,965 296,275 292,322 288,795
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
5,501,495 5,603,502 5,581,897 5,403,519 5,182,516 5,058,084 5,025,840
1,054,600 1,094,400 1,132,100 1,039,600 985,710 1,019,980 998,910
1,449,600 1,289,800 1,271,500 1,236,000 1,309,700 1,169,700 1,229,400
43 39 37 42 37 40 0
24 37 41 37 53 51 94
20 11 11 10 9 9 6
9 9 7 1 0 0 0
3 3 0 5 0 0 0
1 1 4 5 1 0 0
- --------------------------------------------------------------------------------
$589,346 $577,611 $574,422 $558,060 $537,147 $532,264 $495,669
(45,900) (49,778) (59,054) (63,514) (68,536) (19,722) 11,434
8,211 0 0 0 0 0 0
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
$551,657 $527,833 $515,368 $494,546 $468,611 $512,542 $507,103
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
11.32 10.88 10.85 10.89 10.93 11.04 10.42
(0.88) (0.93) (1.11) (1.24) (1.39) (0.40) 0.24
0.16 0 0 0 0 0 0
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
10.60 9.95 9.74 9.65 9.54 10.64 10.66
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
2.63 2.78 2.53 2.54 2.45 3.48 4.65
2.89 2.98 2.74 2.58 2.58 3.71 4.90
1.55 0.89 0.87 0.94 1.02 1.01 0.91
- ---------- ---------- ---------- ---------- ---------- ---------- ----------
1,587 1,627 1,620 1,604 1,576 1,501 1,559
$69,237 $65,175 $62,387 $57,207 $52,782 $49,150 $46,911
===============================================================================
</TABLE>
- 33 -<PAGE>
<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 should continue to improve as
a result of the December 16, 1992 rate decision by the DPUC. The
DPUC decision granted levelized rate increases of 2.66% ($15.8
million) in 1993 and 2.66% (an additional $17.3 million) in 1994.
However, the Company's financial condition will continue to be
dependent on the level of retail and wholesale sales. The two
primary factors that affect sales volume are economic conditions
and weather. The regional recession has restricted retail sales
growth and been largely responsible for a weak wholesale sales
market during the past two years. Sales increases due to economic
recovery would help to increase the Company's earnings.
Another major factor affecting the Company's financial condition
will be the Company's ability to control expenses. A significant
reduction in interest expense has been achieved since 1989, and
additional savings of $10 million are expected in 1994 due to debt
refinancing. Since 1990, annual growth in total operation and
maintenance expense, excluding one-time items and cogeneration
capacity purchases, has averaged approximately 2.7%, and the
Company hopes to restrict future increases to less than the rate of
inflation.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as
follows:
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(000's)
<S> <C> <C> <C> <C> <C>
Capital Expenditure Program $ 73,424 $ 84,876 $82,632 $ 51,324 $ 74,304
Long-term Debt Maturities 53,000 97,000 - 50,000 100,000
Mandatory Redemptions/
Repayments 60,333 66,134 12,770 15,171 15,562
-------- -------- ------- -------- --------
Total Capital Requirements $186,757 $248,010 $95,402 $116,495 $189,866
======== ======== ======= ======== ========
</TABLE>
The Company presently estimates that its cash on hand and
temporary cash investments at the beginning of 1994, totaling $48.2
million, and its projected net cash provided by operations, less
dividends, of $102 million, less capital expenditures of $73.4
million, will be insufficient to fund the Company's 1994
requirements for long-term debt maturities and mandatory
redemptions and repayments, amounting to $113.3 million, by $36
million. The Company currently anticipates that its projected net
cash provided by operations, less dividends and capital
expenditures, for 1995 will be insufficient to fund the Company's
1995 requirements for long-term debt maturities and mandatory
redemptions and repayments, by approximately $138 million. The
Company currently anticipates that its projected net cash provided
by operations, less dividends and capital expenditures, for 1996
through 1998 will be insufficient to fund the Company's
requirements for long-term debt maturities and mandatory
redemptions and repayments in the years 1996 through 1998, in
amounts that cannot now be predicted accurately, but which may be
substantial in the aggregate, depending on the levels of the
Company's sales, wholesale and retail rates, operation and
maintenance costs and taxes. All of the Company's capital
requirements that exceed available net cash will have to be
provided by external financing; and the Company has no commitment
to provide such financing from any source of funds. The Company
expects to be able to satisfy its external financing needs by
issuing common stock and additional short-term and long-term debt,
although 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.
- 34 -<PAGE>
<PAGE>
At December 31, 1993, the Company had $48.2 million of cash and
temporary cash investments, an increase of $37.1 million from the
balance at December 31, 1992. The components of this increase,
which are detailed in the Consolidated Statement of Cash Flows, are
summarized as follows:
<TABLE>
<CAPTION>
(Millions)
--------
<S> <C>
Balance, December 31, 1992 $ 11.1
Net cash provided by operating activities 145.9
Net cash provided by (used in) financing
activities:
- Financing activities, excluding dividend payments (67.3)
- Dividend payments (41.3)
Net cash provided by investing activities, excluding
investment in plant 94.5
Cash invested in plant, including nuclear
fuel (94.7)
-------
Net Increase 37.1
-------
Balance, December 31, 1993 $ 48.2
=======
</TABLE>
The Company has a revolving credit agreement with a group of
banks, which currently extends to January 19, 1995. The borrowing
limit of this facility is $75 million. The facility permits the
Company to borrow funds at a fluctuating interest rate determined
by the prime lending market in New York, and also permits the
Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar
interbank market in London, by the certificate of deposit market in
New York, or by bidding, at the Company's option. If a material
adverse change in the business, operations, affairs, assets or
condition, financial or otherwise, or prospects of the Company and
its subsidiaries, on a consolidated basis, should occur, the banks
may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the
time of such an occurrence would not then become due and payable.
As of December 31, 1993, the Company had no 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 in the previous paragraph
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.
The Company had a $50 million term loan facility with a group of
banks during 1993. Under this agreement, the Company chose an
interest rate from among three alternatives: (i) a fluctuating
interest rate determined by the prime lending market in New York;
(ii) a fixed interest rate determined by the Eurodollar interbank
market in London; and (iii) a fixed interest rate determined by the
certificate of deposit market in New York. On February 1, 1993,
the Company borrowed $50 million from this group of banks, using
the proceeds to repay short-term borrowings and other current
obligations. On December 3, 1993, the Company repaid the $50
million borrowing and terminated the agreement.
The Company had a term loan agreement with PruLease, Inc.
(PruLease) that expired on December 1, 1993. This agreement was
executed on December 31, 1992, when the Company borrowed $49.1
million from PruLease and purchased all the nuclear fuel that was
owned by PruLease and leased to the Company on that date. This
- 35 -<PAGE>
<PAGE>
loan, which was collateralized by a first lien on the Company's
ownership interest in the nuclear fuel for Seabrook Unit 1, was
repaid in full at maturity.
The Company has a Fossil Fuel Supply Agreement with a financial
institution providing for financing up to $37.5 million in fossil
fuel purchases. Under this agreement, the financing entity
acquires and stores natural gas, coal and fuel oil for sale to the
Company, and the Company purchases these fossil fuels from the
financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an
inventory of the fuel determined by reference to the fluctuating
interest rate on thirty-day, dealer-placed commercial paper in New
York. The Company is obligated to insure the fuel inventories and
to indemnify the financing entity against all liabilities, taxes
and other expenses incurred as a result of its ownership, storage
and sale of fossil fuel to the Company. This agreement currently
extends to February 1995. At December 31, 1993, approximately
$10.1 million of fossil fuel purchases were being financed under
this agreement.
UI has four wholly-owned subsidiaries. Bridgeport Electric
Company, a single-purpose corporation, owns and leases to UI a
generating unit at Bridgeport Harbor Station. Research Center,
Inc. (RCI) has been formed to participate in the development of one
or more regulated power production ventures, including possible
participation in arrangements for the future development of
independent power production and cogeneration facilities. United
Energy International, Inc. (UEI) has been formed to facilitate
participation in a proposed joint venture relating to power
production plants abroad. United Resources, Inc. (URI) serves as
the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business
ventures that will complement and enhance UI's electric utility
business and serve the interests of the Company and its
shareholders and customers.
Four wholly-owned subsidiaries of URI have been incorporated.
Souwestcon Properties, Inc. is participating as a 25% partner in
the ownership of a medical hotel building in New Haven. A second
wholly-owned subsidiary of URI is Thermal Energies, Inc., which is
participating in the development of district heating and cooling
water facilities in the downtown New Haven area, including the
energy center for an office tower and participation as a 37%
partner in the energy center for a new city hall and office tower
complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial
buildings and industrial facilities. A fourth URI subsidiary,
American Payment Systems, Inc., manages agents and equipment for
electronic data processing of bill payments made by customers of
utilities, including UI, at neighborhood businesses. In addition
to these subsidiaries, URI also has an 82% ownership interest in
Ventana Corporation (Ventana), which offers energy conservation
engineering and project management services to governmental and
private institutions. In September 1993, URI recorded a $1.2
million after-tax write off of outstanding debt owed to URI by
Ventana, which represented the difference between the amount owed
to URI by Ventana and the value of an additional equity interest in
Ventana received by URI in November 1993. This additional equity
interest in Ventana was received in exchange for the forgiveness of
debt owed to URI by Ventana.
The Board of Directors of the Company has authorized the
investment of a maximum of $13.5 million, in the aggregate, of the
Company's assets in all of URI's ventures, UEI and RCI, and, at
December 31, 1993, approximately $10.6 million had been so
invested.
RESULTS OF OPERATIONS
1993 vs. 1992
- -------------
Earnings for the year 1993 were $36.2 million, or $2.57 per
share, down $16.3 million, or $1.19 per share, from 1992. This
decrease reflects a one-time reorganizational charge of
approximately $7.8 million after-tax, or $.56 per share, and the
non-recurrence of one-time gains of $.59 per share in 1992.
Earnings per share for 1993, excluding one-time items and
accounting changes, decreased by $.04 per share, to $3.13 per share
from $3.17 per share for 1992.
- 36 -<PAGE>
<PAGE>
Sales margin increased by $10.3 million for the year. Retail
revenues increased $36.6 million; $20.7 million from a recent rate
decision ($12.1 million from rate changes and $13.2 million for the
fold-in to base rates of the 1992 sales adjustment revenues, partly
offset by the pass through to customers of expense credits of $4.6
million), and $15.9 million from increased retail sales. Retail
sales increased by 2.7%, mostly due to a return to more normal
summer weather.
The retail revenue increases were offset by anticipated
reductions of $21 million from the sales adjustment provision and
$13.7 million in wholesale capacity revenues. Other operating
revenues decreased by $0.3 million. Reductions in wholesale energy
revenues of $15.8 million were directly offset by reductions in
energy expense.
Other factors affecting sales margin were lower retail fuel
expense, increasing margin by $9.4 million, and higher revenue
related taxes, decreasing margin by $0.6 million.
Other operation and maintenance expenses, including purchased
capacity charges, increased by $10.2 million, or 4.5%, in 1993
relative to 1992. Major generating station overhauls and
unscheduled repairs accounted for $5.2 million of this increase.
Employment costs increased by $4.0 million, most of which resulted
from the adoption of a liability for postretirement benefits other
than pensions that the implementation of Statement of Financial
Accounting Standards (SFAS) No. 106 requires to be accrued over
employees' careers. Purchased capacity charges (cogeneration and
Connecticut Yankee power purchases) for 1993 increased by $4.0
million, transmission costs increased by $2.4 million; but other
nuclear operation and maintenance expenses decreased by $4.0
million.
Other operating expenses, including income taxes but excluding
a 1993 fourth quarter one-time reorganization charge, decreased by
$20.3 million in 1993 from 1992, as the effect of accounting
treatments ordered in recent rate decisions for recovery of
canceled plant, the flow-through to income of certain income tax
benefits and lower property taxes more than offset increases in
depreciation expense.
Other income declined by $23 million in 1993 from 1992, $9.4
million of which was attributable to the absence of net one-time
gains realized in 1992. The remainder was due primarily due to an
expected decline in deferred revenue and income tax benefits
associated with the DPUC's 1992 rate decision, offset, in part, by
lower interest charges of $9.3 million. "Net" interest margin
(interest income less interest expense) improved by $6.6 million in
1993 over 1992.
1992 vs. 1991
- -------------
Earnings for 1992 were $52.4 million, or $3.76 per share, up
$1.4 million, or $.09 per share, over 1991. Earnings per share for
1992, excluding one-time items and accounting changes, increased by
$.27, to $3.17 from $2.90 per share for 1991. Non-recurring
earnings declined to a level of $.59 per share in 1992 from $.77
per share in 1991.
Operating revenues in 1992, exclusive of retail and wholesale
fuel recovery revenue, were up $4.3 million over 1991 levels,
adding $.18 per share after taxes. Increased rates provided only
$11 million of an expected annual $15 million revenue increase,
because commercial and industrial customers shifted into lower
priced time-of-use rates. An additional $6 million of revenue was
accrued under the terms of the sales adjustment provisions of the
Company's 1990 rate decision by the Department of Public Utility
Control (DPUC). Retail sales volume declined 1.6% from the prior
year, reducing retail revenues by $10.6 million and sales margin
(revenue minus fuel expense and revenue-based taxes) by $7.4
million. Most of this decline reflected the cool, wet weather for
the summer of 1992. On a weather-adjusted basis, retail sales were
about even with 1991. Wholesale capacity sales declined by $2.1
million for the year, reflecting the end of a major contract in
October 1992.
Other sales margin improvements were derived from increased
nuclear generation, which added $10.5 million to margin in 1992
over 1991. An overall capacity factor of 76% for the nuclear units
was achieved in 1992, compared to 65% for 1991. Offsetting this
gain, the Company experienced unusually low and intermittent demand
by the New England Power Pool for the operation of the Company's
fossil generating units, thus
- 37 -<PAGE>
<PAGE>
degrading their efficiency, increasing fuel expense and decreasing
sales margin by $2.5 million from 1991. These amounts are not
recoverable through the fuel adjustment clause.
Operation, maintenance and capacity expense for 1992 nuclear
generation declined only $1.7 million from 1991 levels, compared to
a savings of $4-5 million the Company originally expected to
realize (principally from reduced Seabrook expenses). Other
operation and maintenance expenses, excluding fuel and energy
expenses, increased by $2.6 million for the year (excluding net
non-recurring charges for 1992).
Other taxes increased by $3.7 million (excluding a one-time
charge in 1991), reflecting primarily the increased property tax
placed on Seabrook by the State of New Hampshire. Depreciation
increased by $2.5 million in 1992 over 1991. Net changes in
interest income and expense added $2.9 million to pre-tax income in
1992, excluding one-time credits in 1991 and 1992. Reductions in
plant balances not in rate base (Seabrook and other) led to
reductions in deferred revenue of about $4 million after-tax.
Non-recurring items decreased by $.18 per share compared to 1991
levels, to a net earnings figure of $.59 per share. In 1992, a net
$2.7 million in income, or $.19 per share, was booked for
Seabrook Unit 1 adjustments; $3.6 million, or $.26 per share, in
non-operating income tax credits were realized; a net $3.0 million
in income, or $.21 per share, from a gain on the sale of property
was realized; and there were one-time charges to operating expenses
of a net $1.0 million, for a loss of $.07 per share.
OUTLOOK
The Company's financial condition should continue to improve as
a result of the December 16, 1992 retail rate decision by the DPUC.
The DPUC decision granted levelized rate increases of 2.66% ($15.8
million) in 1993 and 2.66% (an additional $17.3 million) in 1994.
However, the Company did not realize the full anticipated benefit
of the 1993 rate increase, realizing about $4 million less than
awarded due to differences between the sales realized in individual
rate classes and the sales projections used for rate case purposes.
The differences arose principally from rate class shifting by
customers and differential growth in sales among rate classes. A
similar shortfall may develop in 1994.
The Company's financial condition will continue to be dependent
on the level of retail and wholesale sales. The two primary
factors that affect sales volume are economic conditions and
weather. The regional recession has restricted retail sales growth
and been largely responsible for a weak wholesale sales market
during the past two years. Sales increases due to economic
recovery would help to increase the Company's earnings. A 1%
increase in sales would add about $6 million in revenue and about
$5 million in sales margin (revenue minus fuel expense and revenue-
based taxes). Wholesale capacity sales are expected to be
approximately $6 million in 1994.
Another major factor affecting the Company's financial condition
will be the Company's ability to control expenses. Fuel expense,
excluding wholesale fuel expense, is expected to decline by
approximately $2.3 million in 1994 from the 1993 level, reflecting
significantly lower nuclear fuel prices. Also, significant
reductions in interest expense have been achieved since 1989, and
additional savings of $10 million are expected in 1994 due to debt
refinancing. For 1994, operation and maintenance expenses are
expected to increase from normal inflationary pressures, but these
increases should be substantially offset by savings from the
phase-in of the Company's corporate structure reorganization.
Since 1990, annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity
purchases, has averaged approximately 2.7%, and the Company hopes
to restrict future increases to less than the rate of inflation.
The final portion of the cost of Seabrook Unit 1 has been added
to rate base (and retail revenues) for 1994. This will eliminate
deferred revenues and reduce net income by $7.4 million after-tax
in 1994 from 1993 levels.
Although the Company believes that its financing outlook and
plans are unlikely to be adversely affected by further developments
with respect to the licensing and operation of Seabrook Unit 1, the
Company's financial status and financing capability will continue
to be sensitive to any such developments and to many other factors,
including conditions in the securities markets, economic
conditions, the level of the Company's income and cash
- 38 -<PAGE>
<PAGE>
flow, and legislative and regulatory developments, including the
cost of compliance with increasingly stringent environmental
legislation and regulations and competition within the electric
utility industry.
INFLATION
As a result of inflation and increased environmental and
regulatory requirements, the estimated cost of replacing the
Company's productive capacity today would substantially exceed the
historical cost of such facilities reported in the financial
statements. Since the Company's rates for service to its customers
have been based in the past on the cost of providing such service
and have been revised from time to time to reflect increased costs
of service, the Company believes that any higher replacement costs
it may experience in the future will be recovered through the
normal regulatory process.
- 39 -<PAGE>
<PAGE>
<TABLE>
Item 8.Financial Statements and Supplementary Data
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
For the Years Ended December 31, 1993, 1992 and 1991
(Thousands except per share amounts)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Operating Revenues (Note G) $653,023 $667,325 $673,371
--------- --------- ---------
Operating Expenses
Operation
Fuel and energy 138,050 163,253 184,868
Capacity purchased 47,424 43,560 44,668
Reorganization charge 13,620 - -
Other 148,332 145,032 137,118
Maintenance 41,475 38,394 41,794
Depreciation 56,287 50,706 48,181
Amortization of cancelled
nuclear project (Note J) 1,172 10,415 10,415
Amortization of deferred
fossil fuel costs 608 - -
Income taxes (Notes A and E) 33,309 48,712 47,231
Other taxes (Note G) 57,932 59,231 55,896
--------- --------- ---------
Total 538,209 559,303 570,171
--------- --------- ---------
Operating Income 114,814 108,022 103,200
--------- --------- ---------
Other Income and (Deductions)
Allowance for equity funds
used during construction 999 1,003 1,259
Deferred return - Seabrook Unit 1 7,497 15,959 17,970
Other-net (Note G) 71 18,545 2,697
Non-operating income taxes 6,322 12,558 19,299
--------- --------- ---------
Total 14,889 48,065 41,225
--------- --------- ---------
Income Before Interest Charges 129,703 156,087 144,425
--------- --------- ---------
Interest Charges
Interest on long-term debt 80,030 88,666 90,296
Other interest (Note G) 12,260 12,882 9,847
Allowance for borrowed funds
used during construction (3,068) (2,229) (3,931)
--------- --------- ---------
Net Interest Charges 89,222 99,319 96,212
--------- --------- ---------
Income Before Cumulative Effect
of Accounting Change 40,481 56,768 48,213
--------- --------- ---------
Cumulative effect for years prior
to 1991 of accounting change for
property taxes (net of income
taxes of $5,559) (Note N) - - 7,337
--------- --------- ---------
Net Income 40,481 56,768 55,550
Dividends on Preferred Stock 4,318 4,338 4,530
--------- --------- ---------
Income Applicable to Common Stock $36,163 $52,430 $51,020
========= ========= =========
Average Number of Common
Shares Outstanding 14,064 13,941 13,900
Earnings per share of Common Stock
before cumulative effect of
accounting change $2.57 $3.76 $3.14
Cumulative effect for years prior
to 1991 of accounting change
for property taxes - - 0.53
--------- --------- ---------
Earnings per share of Common Stock $2.57 $3.76 $3.67
========= ========= =========
Cash Dividends Declared per share
of Common Stock $2.66 $2.56 $2.44
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 40 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 1993, 1992 and 1991
(Thousands of Dollars)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net Income $40,481 $56,768 $55,550
--------- --------- ---------
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 65,788 70,298 66,408
Deferred income taxes 9,422 31,093 19,977
Deferred investment tax credits - net (762) (762) (3,322)
Gain on sale of facility - (5,915) -
Amortization of nuclear fuel 21,922 23,440 21,671
Cumulative effect for years prior to 1991 of
accounting change for property taxes-net - - (7,337)
Allowance for funds used during
construction (4,067) (3,232) (5,190)
Deferred return - Seabrook Unit 1 (7,497) (15,959) (17,970)
Sales adjustment revenue 7,668 (6,217) (6,571)
Changes in:
Accounts receivable - net 3,344 (4,637) (9,022)
Fuel, materials and supplies (638) 1,481 17,747
Accounts payable (10,098) 7,672 (14,363)
Interest accrued (2,431) (6,918) 2,019
Taxes accrued 1,017 (1,829) (10,558)
Reorganization charge accrued 13,620 - -
Other assets and liabilities 8,087 3,354 2,783
--------- --------- ---------
Total Adjustments 105,375 91,869 56,272
--------- --------- ---------
Net Cash provided by Operating Activities 145,856 148,637 111,822
--------- --------- ---------
Cash Flows from Financing Activities
Common stock 1,834 3,442 1,518
Long-term debt 164,460 247,000 53,000
Notes payable (84,099) 71,099 (2,000)
Securities retired and redeemed,
including premiums:
Preferred stock - (1,695) (7,060)
Long-term debt (143,543) (214,811) (47,870)
Expenses of issues (1,742) (1,453) 3,165
Lease obligations (4,174) (71,866) (3,106)
Dividends
Preferred stock (4,318) (4,365) (4,612)
Common stock (36,991) (35,252) (33,345)
--------- --------- ---------
Net Cash used in Financing Activities (108,573) (7,901) (40,310)
--------- --------- ---------
Cash Flows from Investing Activities
Plant expenditures, including nuclear fuel (94,743) (66,390) (63,157)
Proceeds from the sale of facility - 6,012 -
Investment in debt securities 94,529 (94,529) -
--------- --------- ---------
Net Cash used in Investing Activities (214) (154,907) (63,157)
--------- --------- ---------
Cash and Temporary Cash Investments:
Net change for the period 37,069 (14,171) 8,355
Balance at beginning of period 11,102 25,273 16,918
--------- --------- ---------
Balance at end of period $48,171 $11,102 $25,273
========= ========= =========
Cash paid during the period for:
Interest (net of amount capitalized) $78,021 $82,829 $71,641
========= ========= =========
Income taxes $17,435 $12,634 $7,912
========= ========= =========
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 41 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
December 31, 1993, 1992 and 1991
ASSETS
(Thousands of Dollars)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Utility Plant at Original Cost
In service $1,690,142 $1,631,787 $1,591,415
Less, accumulated provision
for depreciation 446,716 407,729 371,544
----------- ---------- -----------
1,243,426 1,224,058 1,219,871
Construction work in progress 77,395 59,809 54,771
Nuclear fuel 40,285 52,144 65,450
----------- ----------- -----------
Net Utility Plant 1,361,106 1,336,011 1,340,092
----------- ----------- -----------
Other Property and Investments 17,811 13,176 13,559
----------- ----------- -----------
Current Assets
Cash and temporary cash investments 48,171 11,102 25,273
Short-term investment - 94,529 -
Accounts receivable
Customers, less allowance for
doubtful accounts of $4,700,
$3,900 and $3,200 62,703 56,796 58,258
Other 28,160 37,411 31,312
Accrued utility revenues 22,765 24,389 23,200
Fuel, materials and supplies, at
average cost 21,178 20,540 22,021
Prepayments 4,963 3,130 4,633
Other 41 57 142
----------- ----------- -----------
Total 187,981 247,954 164,839
----------- ----------- -----------
Regulatory Assets (future amounts
due from customers
through the ratemaking
process)
Income taxes due principally to book-tax
differences (Note A) 408,272 406,258 418,188
Deferred return - Seabrook Unit 1 62,929 55,432 39,473
Unamortized cancelled nuclear projects 26,964 28,136 37,700
Unamortized redemption costs 32,573 28,186 30,716
Sales adjustment revenues 13,113 20,781 14,814
Uranium enrichment decommissioning cost 1,600 - -
Deferred fossil fuel costs 198 1,109 -
Unamortized debt issuance expenses 6,631 6,474 5,391
Other 15,114 10,117 8,083
----------- ----------- -----------
Total 567,394 556,493 554,365
----------- ----------- -----------
$2,134,292 $2,153,634 $2,072,855
=========== =========== ===========
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 42 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
December 31, 1993, 1992 and 1991
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $284,028 $282,433 $279,340
Paid-in capital 734 495 146
Capital stock expense (3,163) (3,163) (3,163)
Retained earnings 141,725 142,981 125,448
----------- ----------- -----------
423,324 422,746 401,771
Preferred stock 60,945 60,945 62,640
Long-term debt 875,268 893,457 909,998
----------- ----------- -----------
Total 1,359,537 1,377,148 1,374,409
----------- ----------- -----------
Noncurrent Liabilities
Obligations under capital leases
Nuclear fuel - - 69,439
Other property 19,871 23,855 26,136
Uranium enrichment decommissioning
reserve 1,486 - -
Nuclear decommissioning obligation 5,606 - -
Other 2,156 1,998 1,398
----------- ----------- -----------
Total 29,119 25,853 96,973
----------- ----------- -----------
Current Liabilities
Current portion of long-term debt 143,333 92,833 37,500
Notes payable - 84,099 13,000
Accounts payable 49,424 59,522 51,850
Dividends payable 10,445 10,017 9,602
Taxes accrued 6,851 5,834 7,663
Pensions accrued (Note H) 33,547 18,714 13,244
Interest accrued 21,972 24,403 31,321
Obligations under capital leases 1,838 2,028 2,174
Other accrued liabilities 26,813 12,953 11,670
----------- ----------- -----------
Total 294,223 310,403 178,024
----------- ----------- -----------
Customers' Advances for
Construction 2,667 2,672 3,064
----------- ----------- -----------
Regulatory Liabilities (future amounts
owed to customers
through the
ratemaking process)
Accumulated deferred investment
tax credits 19,433 20,195 20,957
Deferred gain on sale of utility plant 2,070 3,391 4,574
Other 1,837 - 45
----------- ----------- -----------
Total 23,340 23,586 25,576
----------- ----------- -----------
Deferred Income Taxes (future tax
liabilities owed
to taxing
authorities) 425,406 413,972 394,809
Commitments and Contingencies - - -
----------- ----------- -----------
$2,134,292 $2,153,634 $2,072,855
=========== =========== ===========
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 43 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
For the Years Ended December 31, 1993, 1992 and 1991
(Thousands of Dollars)
<CAPTION>
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Balance, January 1 $142,981 $125,448 $105,046
Net Income 40,481 56,768 55,550
Discount applicable to repurchase
of preferred stock - 796 3,304
--------- --------- ---------
Total 183,462 183,012 163,900
--------- --------- ---------
Deduct Cash Dividends Declared
Preferred stock 4,318 4,338 4,530
Common stock 37,419 35,693 33,922
--------- --------- ---------
Total 41,737 40,031 38,452
--------- --------- ---------
Balance, December 31 $141,725 $142,981 $125,448
========= ========= =========
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
- 44 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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).
Principles of Consolidation
The consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries, Bridgeport Electric
Company (BEC), United Resources Inc., United Energy International,
Inc. and Research Center, Inc. Intercompany accounts and
transactions have been eliminated in consolidation.
Reclassification of Previously Reported Amounts
Certain amounts previously reported have been reclassified to
conform with current year presentations.
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.
Allowance for Funds Used During Construction
In accordance with the applicable regulatory systems of
accounts, the Company capitalizes AFUDC, which represents the
approximate cost of debt and equity capital devoted to plant under
construction. In accordance with FERC prescribed accounting, 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 semi-annually the
allowance applicable to major construction projects. AFUDC rates
in effect for 1993, 1992 and 1991 were 8.75%, 10.25% and 10.88%,
respectively.
Depreciation
Provisions for depreciation on utility plant for book purposes,
excluding costs associated with the 1984 reconversion of BEC's
plant to a dual-fired capability, 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. During the years 1985-1989, depreciation associated
with BEC's reconversion costs was computed on an annuity basis over
the original ten-year period that this plant was being leased to
the Company by BEC. Commencing January 1, 1990, the reconversion
costs are being depreciated on a straight-line basis over a period
ending July 2000. The aggregate annual provisions for depreciation
for the years 1993, 1992 and 1991 were equivalent to approximately
3.22%, 3.15% and 3.10%, respectively, of the original cost of
depreciable property.
- 45 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Income Taxes
Effective January 1, 1993, the Company adopted SFAS 109,
"Accounting for Income Taxes". In accordance with SFAS 109, 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 net regulatory asset that reflects
anticipated future recovery in rates of these deferred tax
provisions.
For ratemaking purposes, the Company practices full
normalization for 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 the 1989 Settlement Agreement.
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 Cash Equivalents
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 equivalents.
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 the funding requirement
for operating expenses, is restricted for use and amounted to $3.4
million, $2.9 million, and $1.8 million at December 31, 1993, 1992
and 1991, respectively.
Investments
The Company's investment in the Connecticut Yankee Atomic Power
Company joint venture, a nuclear generating company in which the
Company has a 9 1/2% stock interest, is accounted for on an equity
basis.
Fossil Fuel Costs
The amount of fossil fuel costs that cannot be reflected
currently in customers' bills pursuant to the FCA in the Company's
rates is deferred at the end of each accounting period. Since
adoption of the deferred accounting procedure in 1974, rate
decisions by the DPUC and its predecessors have consistently made
specific provision for amortization and rate-making treatment of
the Company's existing deferred fossil fuel cost balances.
Research and Development Costs
Research and development costs, including environmental studies,
are capitalized if related to specific construction projects and
depreciated over the lives of the related assets. Other research
and development costs are charged to expense as incurred.
Pension and Other Post-Employment 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
- 46 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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".
Prior to January 1, 1993, the Company accounted for other post-
employment benefits, consisting principally of health and life
insurance, on a pay-as-you-go basis. Effective January 1, 1993,
the Company commenced accounting for these costs under the
provisions of SFAS No. 106, "Employers' Accounting for Post-
Retirement 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 accounting change
has been allowed in retail rates in accordance with a 1992 rate
decision.
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. At December 31,
1993, the Company's unfunded share of the obligation, based on its
ownership interest in Seabrook Unit 1 and Millstone Unit 3, was
approximately $1.5 million. Effective January 1, 1993, the Company
was allowed to recover these assessments in rates as a component of
fuel expense. Accordingly, the Company has recognized these costs
as a regulatory asset on its Consolidated Balance Sheet.
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 $1,616,000, $1,334,000 and $1,011,000 during 1993,
1992 and 1991 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1993, the Company's
share of the trust fund balances, which include accumulated
earnings on the funds, were $3.7 million and $1.9 million for
Seabrook Unit 1 and Millstone Unit 3, respectively. These fund
balances are included in "Other Property and Investments" and the
accrued decommissioning obligation is included in "Noncurrent
Liabilities" on the Company's Consolidated Balance Sheet.
- 47 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<CAPTION>
(B) CAPITALIZATION December 31,
-----------------------------------------------------------------------------
1993 1992 1991
Shares Shares Shares
Outstanding $(000's) Outstanding $(000's) Outstanding $(000's)
------------- ----------- ------------- ---------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Common Stock Equity
Common stock, no par value,
at December 31(a) 14,083,291 $284,028 14,033,148 $282,433 13,932,348 $279,340
Shares authorized
1991 30,000,000
1992 30,000,000
1993 30,000,000
Paid-in capital 734 495 146
Capital stock expense (3,163) (3,163) (3,163)
Retained earnings (b) 141,725 142,981 125,448
----------- ----------- -----------
Total common stock equity 423,324 422,746 401,771
----------- ----------- -----------
Preferred and Preference Stock (c)
Preferred stock issues:
4.35% Series A 40,425 40,425 40,425
4.72% Series B 50,730 50,730 67,680
4.64% Series C 32,100 32,100 32,100
5 5/8% Series D 61,200 61,200 61,200
7.60% Series E 125,000 125,000 125,000
7.60% Series F 150,000 150,000 150,000
------------- ------------ ------------
459,455 45,945 459,455 45,945 476,405 47,640
Cumulative preferred stock, ------------- ----------- ------------ ----------- ------------ -----------
$25 par value, shares
authorized at December 31,
1991 2,400,000
1992 2,400,000
1993 2,400,000
Preferred stock issues:
8.80% 1976 Series 600,000 15,000 600,000 15,000 600,000 15,000
Cumulative preference stock,
$25 par value, shares
authorized at December 31,
1991 5,000,000
1992 5,000,000
1993 5,000,000
Preference stock issues - - - - - -
Total preferred stock not ----------- ----------- -----------
subject to mandatory redemption 60,945 60,945 62,640
----------- ----------- -----------
</TABLE>
- 48 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<CAPTION>
December 31,
----------------------------
1993 1992 1991
$(000's) $(000's) $(000's)
-------- -------- -------
<S> <C> <C> <C>
Long-term Debt (d)
Long-term debentures:
10 1/2%, 1995 Series, due October 1, 1995 - - $69,600
5 3/4%, 1996 Series, due August 15, 1996 - - 15,000
6%, 1997 Series, due June 15, 1997 - - 22,500
7%, 1999 Series, due January 15, 1999 - - 15,000
7 3/4%, 2002 Series, due October 1, 2002 - - 25,000
8 1/4%, 2003 Series, due December 15, 2003 - - 30,000
12%, 2017 Series, due August 1, 2017 - - 2,078
-------- -------- --------
- - 179,178
First Mortgage Bonds-Bridgeport Electric Company:
9.44%, Series B, maturing serially as
to $10,800 principal amount on February 15
in each of the years 1995 to 1999. 54,000 54,000 54,000
10.32%, Series C, maturing serially as
to $55,333 principal amount on January 15
in each of the years 1994 and 1995. 110,666 166,000 180,000
Other Long-term Debt
Pollution Control Revenue Bonds:
14 1/2%, 1984 Series, due October 1, 2009 110 40,000 40,000
14 1/2%, 1984 Series B, due December 1, 2009 3,830 28,400 28,400
9 1/2%, 1986 Series, due June 1, 2016 7,500 7,500 7,500
9 3/8%, 1987 Series, due July 1, 2012 25,000 25,000 25,000
10 3/4%, 1987 Series, due November 1, 2012 43,500 43,500 43,500
8%, 1989 Series A, due December 1, 2014 25,000 25,000 25,000
5 7/8%, 1993 Series, due October 1, 2033 64,460 - -
Solid Waste Disposal Revenue Bonds:
Adjustable rate 1990 Series A
due September 1, 2015 30,000 30,000 30,000
</TABLE>
- 49 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<CAPTION>
December 31,
----------------------------------
1993 1992 1991
$(000's) $(000's) $(000's)
---------- ---------- -----------
<S> <C> <C> <C>
Other Long-term Debt, continued
Medium-Term Notes:
7.62%,1991 Series A, due September 12,1994 $ 30,000 $ 30,000 $ 30,000
7.20%,1991 Series B, due November 1, 1994 13,000 13,000 13,000
6.82%,1991 Series C, due December 2, 1994 10,000 10,000 10,000
6.00%,1992 Series D, due January 15, 1994 50,000 50,000 -
7.00%,1992 Series E, due January 15, 1997 50,000 50,000 -
7.25%,1992 Series F, due October 2, 1995 47,000 47,000 -
7 3/8%,1992 Series G, due January 15, 1998 100,000 100,000 -
6.20%,1993 Series H, due January 15, 1999 100,000 - -
Long-term bank loans:
12.9%, maturing in 1994 5,000 17,500 32,500
Obligation under the Seabrook Unit 1
sale/leaseback agreement 250,000 250,000 250,000
----------- ----------- -----------
1,019,066 986,900 948,078
Unamortized debt discount less premium
at December 31, 1993, 1992 & 1991 (465) (610) (580)
----------- ----------- -----------
Total long-term debt 1,018,601 986,290 947,498
----------- ----------- -----------
Less current portion included in
Current Liabilities (d) 143,333 92,833 37,500
----------- ----------- -----------
Total long-term debt included
in Capitalization 875,268 893,457 909,998
----------- ----------- -----------
Total Capitalization $1,359,537 $1,377,148 $1,374,409
=========== =========== ===========
</TABLE>
- 50 -<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
<PAGE>
(a) Common Stock
The Company issued 46,000 shares of common stock in 1993,
100,800 shares of common stock in 1992 and 44,600 shares of common
stock in 1991 pursuant to a stock option plan. During 1993, the
Company also issued 4,143 shares of common stock pursuant to a
long-term incentive program.
Common stock, no par value, authorized at December 31, 1993,
included 400,000 shares reserved for the Company's Employee Stock
Ownership Plan (ESOP). There were no additions to ESOP in 1991,
1992 or 1993.
The Company purchased on the open market, on behalf of
shareholders participating in the common stock Dividend
Reinvestment Plan, 148,362 shares of stock in 1991, 136,679 shares
of stock in 1992 and 138,145 shares of stock in 1993.
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. On June 5, 1991, the DPUC approved the issuance of
500,000 shares of stock pursuant to this plan. The exercise price
of each option cannot be less than the market value of the stock on
the date of the grant. Options to purchase 214,000 shares of stock
at an exercise price of $30.75 per share, 2,800 shares of stock at
an exercise price of $28.3125 per share, 1,800 shares of stock at
an exercise price of $31.1875 per share, 4,000 shares of stock at
an exercise price of $35.625 per share, 36,200 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 remain outstanding at December 31, 1993.
Options to purchase 44,600 shares of stock at an exercise price of
$30.75 were exercised during 1991. Options to purchase 98,000
shares of stock at an exercise price of $30.75 and 2,800 shares of
stock at an exercise price of $28.3125 were exercised during 1992.
Options to purchase 42,400 shares of stock at an exercise price of
$30.75 per share, 1,400 shares of stock at an exercise price of
$28.3125 per share, 1,200 shares of stock at an exercise price of
$31.1875 per share and 1,000 shares of stock at an exercise price
of $35.625 per share were exercised during 1993.
In addition, certain executive officers were eligible to earn
shares of the Company's common stock, based upon the dividend and
market performance of the stock compared to a peer group of
electric utilities over a four-year period ending December 31,
1992, under the Company's long-term incentive program. The
issuance of shares of stock pursuant to this program received DPUC
approval on June 5, 1991. The total number of shares of common
stock that could have been earned under the long-term incentive
program was limited to 7,091. For the four-year period ending
December 31, 1992, 6,027 shares of the Company's common stock were
earned. Of this amount, a total of 4,143 shares were issued to the
participants in 1993, and the remainder was distributed in an
equivalent amount of cash based on the closing price of the
Company's Common Stock on March 1, 1993, pursuant to the terms of
the long-term incentive program. This program ended as of December
31, 1992.
(b) Retained Earnings Restriction
The indenture under which the Company's Medium-Term Notes and
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 $82.6 million
were free from such limitations at December 31, 1993.
(c) 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.
- 51 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
In 1991, the Company purchased and cancelled shares of its $100
par value Preferred Stock, at a discount, resulting in a
non-taxable addition to common equity of approximately $3,304,000.
The 1991 purchases consisted of:
9,575 shares of 4.35% Preferred Stock, Series A
7,320 shares of 4.72% Preferred Stock, Series B
39,900 shares of 4.64% Preferred Stock, Series C
13,800 shares of 5 5/8% Preferred Stock, Series D
In 1992, the Company purchased and cancelled 16,950 shares of
its $100 par value 4.72% Preferred Stock, Series B, at a discount,
resulting in a non-taxable addition to common equity of
approximately $796,650.
There was no redemption of preferred stock in 1993.
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 some other event of default occurs, preferred shareholders
are entitled to elect a majority of the Board of Directors until
all preferred dividend arrears are paid and any event of default is
terminated.
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, 1993.
(d) Long-Term Debt
In January 1993, the net proceeds from the liquidation of an
investment in tax-exempt municipal debt instruments were used to
pay $60 million principal amount of maturing 10.32% First Mortgage
Bonds of the Company's wholly-owned subsidiary, Bridgeport Electric
Company; to repay a $7.5 million 13.1% term loan; to repay short-
term borrowings incurred for the August 1, 1992 redemption of the
Company's 12% Debentures, due August 1, 2017, and for repayment of
a $7.5 million 12.9% term loan on September 30, 1992; and to repay
short-term borrowings incurred for a $19.1 million rent payment on
December 31, 1992 under the Company's facility sale and leaseback
arrangement for a portion of its ownership interest in Seabrook
Unit 1.
On September 30, 1993, the Company repaid a $5 million 12.9%
term loan with funds obtained through short-term borrowings.
On September 17, 1993, the Company invited the owners of
$68,400,000 aggregate principal amount of 14 1/2% Pollution Control
Revenue Bonds, due October 1 and December 1, 2009, ("Bonds") to
sell to the Company, for cash, any and all of the Bonds. The Bonds
were issued in 1984 by The Industrial Development Authority of the
State of New Hampshire ("NHIDA"), which loaned the issue proceeds
to the Company to pay for the cost of installing pollution control
facilities at the Seabrook nuclear generating plant in New
Hampshire; and the Business Finance Authority of the State of New
Hampshire ("NHBFA"), successor to the NHIDA, agreed to issue
Pollution Control Refunding Revenue Bonds ("Refunding Bonds") in a
principal amount equal to the aggregate principal amount of Bonds
purchased by the Company and surrendered to the Bond trustee for
cancellation, and to loan the issue proceeds of the Refunding Bonds
to the Company to pay for part of the purchase price of the Bonds
being purchased and cancelled. On October 15, 1993, the Company
accepted offers from holders of $64,460,000 aggregate principal
amount of the Bonds to sell them for an aggregate purchase price of
$75,710,000. On October 26, 1993, the NHBFA issued and sold
$64,460,000 principal amount of 5 7/8% Refunding Bonds, due
October 1, 2033, and loaned the issue proceeds to the Company,
which used them to pay
- 52 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
a portion of the purchase price of the Bonds. The remainder of the
purchase price was funded with the proceeds of short-term
borrowings.
On December 7, 1993, the Company issued and sold $100 million
principal amount of five-year and one month Notes at a coupon rate
of 6.20%. The net proceeds were used to repay $60 million
principal amount of maturing 10.32% First Mortgage Bonds of the
Company's wholly-owned subsidiary, Bridgeport Electric Company in
January 1994; to repay a $5 million 13.1% term loan in January 1994
and for general corporate purposes, including repayment of
short-term borrowings.
Maturities and mandatory redemptions/repayments and annual
interest expense on existing long-term debt are set forth below:
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(000's)
<S> <C> <C> <C> <C> <C>
Long-term debt (beginning of
period)(1) $989,067 $875,734 $712,600 $699,830 $634,659
Less:
Maturities 53,000 97,000 - 50,000 100,000
Mandatory redemptions/
repayments 60,333 66,134 12,770 15,171 15,562
-------- -------- -------- -------- --------
Long-term debt
(end of period)(1)(2) $875,734 $712,600 $699,830 $634,659 $519,097
======== ======== ======== ======== ========
Annual interest associated with
existing outstanding debt
(1)(2) $ 72,800 $ 59,637 $ 55,221 $ 50,838 $ 42,930
Annual amortization of issuance
expense and repurchase premiums
associated with existing debt $7,915 $5,451 $3,167 $2,893 $2,543
<FN>
(1) Does not include $30 million of tax-exempt adjustable rate Solid
Waste Disposal Revenue Bonds, 1990 Series A, due September 1,
2015, classified on the Company's books as a current
liability (interest rate for September 1993 to March 1994 is
2.90%).
(2) Does not include interest on any new financings that may be
required to fund maturities, redemptions or plant additions
in any given year. The Company expects some new financings to
occur.
</TABLE>
(C) RATE-RELATED REGULATORY PROCEEDINGS
On December 16, 1992, the DPUC approved levelized rate increases
of 2.66% ($15.8 million) for 1993 and 2.66% (an additional $17.3
million) for 1994, including allowed conservation and load
management revenue increases. The rate increases totaled $33.1
million, or 5.4%, over two years.
In order to achieve levelized 2.66% rate increases for each of
these two years, the DPUC determined that the recovery of $13.1
million of sales adjustment clause revenues would be deferred from
1993 to 1994.
Utilities are entitled by Connecticut law to revenues sufficient
to allow them to cover their operating and capital costs, to
attract needed capital and maintain their financial integrity,
while also protecting the public interest. Accordingly, the DPUC's
1992 rate decision authorized a return on equity of 12.4% for
ratemaking purposes. However, the Company may earn up to 1% above
this level before a mandatory review is required by the DPUC.
- 53 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Since January 1971, UI has had a fossil fuel adjustment clause
(FCA) in virtually all of its retail rates. The DPUC is required
by law to convene an administrative proceeding prior to approving
FCA charges or credits for each month. The law permits automatic
implementation of the charges or credits if the DPUC fails to act
within five days of the administrative proceeding, although all
such charges and credits are also subject to further review and
appropriate adjustment by the DPUC at public hearings required to
be held at least every three months. The DPUC has made no material
changes in UI's FCA charges and credits as the result of any of
these proceedings or hearings.
(D) ACCOUNTING FOR PHASE-IN PLAN
The Company has been phasing into rate base its allowable
investment in Seabrook Unit 1, amounting to $640 million, since
January 1, 1990. In conjunction with this phase-in plan, the
Company has been allowed to record a deferred return on the portion
of allowable investment excluded from rate base during the phase-in
period. The accumulated deferred return has been added to rate
base each year since January 1, 1991 in the same proportion as the
phase-in installment for that year has borne to the portion of the
$640 million remaining to be phased-in. On January 1, 1994, the
Company phased into rate base the remaining $74.5 million of
allowable investment, plus the remaining $28.2 million of
accumulated deferred return. The Company will be allowed to
recover the accumulated deferred return, amounting to $62.9
million, over a five-year period commencing January 1, 1995.
- 54 -<PAGE>
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(E) INCOME TAXES
<CAPTION>
1993 1992 1991
---- ---- ----
(000's)
<S> <C> <C> <C>
Income tax expense consists of:
Income tax provisions:
Current
Federal $13,484 $6,815 $10,869
State 4,843 2,645 407
-------- -------- --------
Total current 18,327 9,460 11,276
-------- -------- --------
Deferred
Federal 9,620 16,860 13,297
State (198) 14,233 12,240
-------- -------- --------
Total deferred 9,422 31,093 25,537
-------- -------- --------
Investment tax credits (762) (4,399) (3,322)
-------- -------- --------
Total income tax expense $26,987 $36,154 $33,491
======== ======== ========
Income tax components charged as follows:
Operating expenses $33,309 $48,712 $47,231
Other income and deductions - net (6,322) (12,558) (19,299)
Cumulative effect of change in accounting
for property taxes - - 5,559
-------- -------- --------
Total income tax expense $26,987 $36,154 $33,491
======== ======== ========
The following table details the components
of the deferred income taxes:
Accelerated depreciation $11,318 $15,452 $17,176
Tax depreciation on unrecoverable
plant investment 7,915 9,378 10,923
Conservation & load management 3,084 3,995 8,374
Property tax adjustment (1,991) (1,991) 5,974
Deferred fossil fuel costs (381) 490 (1,330)
Seabrook sale/leaseback transaction (2,016) 1,629 (1,963)
Premiums on BEC bond redemption (2,378) (3,209) (3,209)
Cancelled nuclear projects (467) (3,795) (3,795)
Alternative minimum tax (139) (1,344) (9,922)
Sales adjustment revenues (3,248) 2,415 2,846
Gains on sale of utility plant - 1,237 -
Pension & postretirement benefits (7,179) (2,489) (885)
Other - net 4,904 9,325 1,348
-------- -------- --------
Deferred income taxes - net $9,422 $31,093 $25,537
======== ======== ========
</TABLE>
- 55 -<PAGE>
<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>
1993 1992 1991
---- ---- ----
Pre-Tax Tax Pre-Tax Tax Pre-Tax Tax
------- --- ------- --- ------- ---
(000's)
<S> <C> <C> <C> <C> <C> <C>
Computed tax at federal
statutory rate $23,614 $31,593 $30,274
Increases (reductions)
resulting from:
Deferred return-Seabrook
Unit 1 ($7,497) (2,624) ($15,959) (5,426) ($17,970) (6,110)
ITC taken into income (762) (762) (4,399) (4,399) (3,322) (3,322)
Allowance for equity funds
used during construction (999) (349) (1,003) (341) (1,259) (428)
Tax exempt interest on
municipal bonds (283) (99) (3,664) (1,246) - -
Book depreciation in excess
of non-normalized tax
depreciation 21,711 7,599 20,182 6,862 19,894 6,764
State income taxes, net of
federal income tax
benefits 4,645 3,019 16,878 11,140 12,647 8,347
Other items - net (9,746) (3,411) (5,968) (2,029) (5,979) (2,034)
------- ------- -------
Total income tax expense $26,987 $36,154 $33,491
======== ======== ========
Book Income Before Federal
Income Taxes $67,467 $92,921 $89,041
======== ======== ========
Effective income tax rates 40.0% 38.9% 37.6%
</TABLE>
At December 31, 1993, the Company had deferred tax liabilities
for taxable temporary differences of $574 million and deferred tax
assets for deductible temporary differences of $149 million,
resulting in a net deferred tax liability of $425 million.
Significant components of deferred tax liabilities and assets were
as follows: tax liabilities on book/tax plant basis differences,
$229 million; tax liabilities on the cumulative amount of income
taxes on temporary differences previously flowed through to
ratepayers, $163 million; tax liabilities on normalization of
book/tax depreciation timing differences, $89 million and tax
assets on the disallowance of plant costs, $77 million.
The Tax Reform Act of 1986 provides for a more comprehensive
corporate alternative minimum tax (AMT) for years beginning after
1986. To the extent that the AMT exceeds the federal income tax
computed at statutory rates, the excess must be paid in addition to
the regular tax liability. For tax purposes, the excess paid in
any year can be carried forward indefinitely and offset against any
future year's regular tax liability in excess of that year's
tentative AMT. The AMT carryforward at December 31, 1993, 1992 and
1991 was $11.4 million, $11.3 million and $9.9 million,
respectively.
(F) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of
banks, which currently extends to January 19, 1995. The borrowing
limit of this facility is $75 million. The facility permits the
Company to borrow funds at a fluctuating interest rate determined
by the prime lending market in New York, and also permits the
Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar
interbank market in London, by the certificate of deposit market in
New York, or by bidding, at the
- 56 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Company's option. If a material adverse change in the business,
operations, affairs, assets or condition, financial or otherwise,
or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money
to the Company under this revolving credit agreement, although
borrowings outstanding at the time of such an occurrence would not
then become due and payable. As of December 31, 1993, the Company
had no 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 in the previous paragraph
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.
The Company had a $50 million term loan facility with a group of
banks during 1993. Under this agreement, the Company chose an
interest rate from among three alternatives: (i) a fluctuating
interest rate determined by the prime lending market in New York;
(ii) a fixed interest rate determined by the Eurodollar interbank
market in London; and (iii) a fixed interest rate determined by the
certificate of deposit market in New York. On February 1, 1993,
the Company borrowed $50 million from this group of banks, using
the proceeds to repay short-term borrowings and other current
obligations. On December 3, 1993, the Company repaid the $50
million borrowing and terminated the agreement.
The Company had a term loan agreement with PruLease, Inc.
(PruLease) that expired on December 1, 1993. This agreement was
executed on December 31, 1992, when the Company borrowed $49.1
million from PruLease and purchased all the nuclear fuel that was
owned by PruLease and leased to the Company on that date. This
loan, which was collateralized by a first lien on the Company's
ownership interest in the nuclear fuel for Seabrook Unit 1, was
repaid in full at maturity.
The Company has a Fossil Fuel Supply Agreement with a financial
institution providing for financing up to $37.5 million in fossil
fuel purchases. Under this agreement, the financing entity
acquires and stores natural gas, coal and fuel oil for sale to the
Company, and the Company purchases these fossil fuels from the
financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an
inventory of the fuel determined by reference to the fluctuating
interest rate on thirty-day, dealer-placed commercial paper in New
York. The Company is obligated to insure the fuel inventories and
to indemnify the financing entity against all liabilities, taxes
and other expenses incurred as a result of its ownership, storage
and sale of fossil fuel to the Company. This agreement currently
extends to February 1995. At December 31, 1993, approximately
$10.1 million of fossil fuel purchases were being financed under
this agreement.
- 57 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Information with respect to short-term borrowings is as follows:
<TABLE>
<CAPTION>
1993 1992 1991
---- ---- ----
(000's)
<S> <C> <C> <C>
Maximum aggregate principal amount of
short-term borrowings outstanding at
any month-end $94,635 $84,099 $59,000
Average aggregate short-term borrowings
outstanding during the year* $73,700 $43,055 $33,364
Weighted average interest rate* 4.1% 4.4% 6.9%
Principal amounts outstanding at year-end $0 $84,099 $13,000
Annualized interest rate on principal
amounts outstanding at year-end N/A 5.1% 5.7%
<FN>
*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
$259,600, $208,400 and $289,000 paid during 1993, 1992 and 1991,
respectively, are excluded from the calculation of the weighted
average interest rate.
</TABLE>
- 58 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(G) SUPPLEMENTARY INFORMATION
<TABLE>
<CAPTION>
1993 1992 1993
---- ---- ----
(000's)
<S> <C> <C> <C>
Operating Revenues
- ------------------
Retail - Base Rates $603,559 $566,955 $570,500
Sales provision adjustment - 21,031 14,814
Wholesale - capacity 6,575 20,315 22,379
- energy 39,356 55,169 61,857
Other 3,533 3,855 3,821
--------- --------- ---------
Total Operating Revenues $653,023 $667,325 $673,371
========= ========= =========
Other Income and (Deductions) - net
- -----------------------------------
Interest and dividend income $ 3,568 $ 6,681 $ 1,493
Seabrook funding adjustments - 7,506 -
Equity earnings from Connecticut
Yankee Unit 1,350 1,340 1,536
Amortization of loss on investment
in tax-exempt bonds - (1,752) -
Amortization of oil tank lease (1,322) (1,183) (1,059)
Gain on sale of property 2,032 7,104 1,058
Miscellaneous other income
and (deductions) - net (5,557) (1,151) (331)
--------- --------- ---------
Total Other Income
and (Deductions) - net $ 71 $ 18,545 $ 2,697
========= ========= =========
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $ 27,955 $ 27,362 $ 27,223
Local real estate
and personal property 24,449 26,339 22,919
Payroll taxes 5,525 5,527 5,252
Other 3 3 502
--------- --------- ---------
Total 57,932 59,231 55,896
Nonoperating and other accounts 335 837 766
--------- --------- ---------
$ 58,267 $ 60,068 $ 56,662
========= ========= =========
Other Interest Charges
- ----------------------
Notes payable $ 3,049 $ 2,120 $ 2,338
Amortization of debt expense
and repurchase premiums 7,818 8,898 7,370
Other 1,393 1,864 139
--------- --------- ---------
Total Other Interest Charges $ 12,260 $ 12,882 $ 9,847
========= ========= =========
</TABLE>
- 59 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(H) PENSION AND OTHER POST-EMPLOYMENT 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
1993, 1992 and 1991 were $14,966,000, $5,749,000 and $2,054,000,
respectively.
The Company's funding policy for the qualified plan is to make
annual contributions that satisfy the minimum funding requirements
of ERISA but which 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 accordance
with this policy, the Company will be contributing $3.3 million in
1994 for 1993 funding requirements. Previously, due to the
application of the full funding limitation under ERISA, the Company
had not been required to make a contribution since 1985. The
supplemental plan is unfunded.
The qualified plan's irrevocable trust fund consists principally
of equity and fixed-income securities and real estate investments
in approximately the following percentages:
<TABLE>
<CAPTION>
Percentage of
Asset Category Total Fund
-------------- ------------
<S> <C>
Equity Securities 63
Fixed-income Securities 32
Real Estate 5
</TABLE>
- 60 -<PAGE>
<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
<TABLE>
<CAPTION>
1993 1992
---- ----
(000's)
<S> <C> <C>
The components of net pension costs were as follows:
Service cost of benefits earned during the period $3,977 $ 3,846
Interest cost on projected benefit obligation 13,165 12,300
Actual return on plan assets (23,344) (7,676)
Net amortization and deferral 10,130 (5,559)
------ ------
Net pension cost $3,928* $2,911**
<FN>
*In addition, a cost of $11,038,000 was recognized under SFAS
No. 88 as a result of special termination benefits provided under
the Pension Plan.
**In addition, a loss of $108,000 was recognized in 1992 under SFAS
No. 88 as a result of a curtailment with regard to the supplemental
plans, and a cost of $2,730,000 was recognized under SFAS No. 88 as
a result of certain terminations.
Assumptions used to determine pension costs were:
Discount rate 8.25% 8.25%
Average wage increase 5.50% 5.50%
Return on plan assets 8.50% 8.50%
</TABLE>
<TABLE>
<CAPTION>
December 31, 1993 December 31, 1992
----------------- -----------------
Qualified Non-Qualified Qualified Non-Qualified
Plan Plans Plan Plans
---- ----- ---- -----
(000's)
<S> <C> <C> <C> <C>
The funded status and amounts
recognized in balance sheets
are as follows:
Actuarial present value of
benefit obligations:
Vested benefit obligation $130,582 $3,097 $106,417 $3,572
======== ====== ======== ======
Accumulated benefit
obligation $137,081 $3,097 $108,820 $3,572
======== ====== ======== ======
Reconciliation of accrued
pension liability:
Projected benefit
obligation $198,236 $4,262 $159,899 $4,166
Less fair value of plan
assets 167,732 - 152,401 -
-------- ------ -------- ------
Projected benefit
greater (less) than plan
assets 30,504 4,262 7,498 4,166
Unrecognized prior service
cost (6,516) (157) (6,955) (180)
Unrecognized net gain (loss)
from past experience (6,966) (327) 840 (478)
Unrecognized net asset
(obligation) at date of
initial application 12,878 (131) 13,986 (163)
------- ------ ------- ------
Accrued pension
liability $29,900 $3,647 $15,369 $3,345
======= ====== ======= ======
Assumptions used in estimating
benefit obligations:
Discount rate 7.50% 7.50% 8.25% 8.25%
Average wage increase 5.50% 5.50% 5.50% 5.50%
</TABLE>
- 61 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 with 25 years of service
are eligible for full benefits, while employees with less than 25
years of service but greater than 15 years of service are entitled
to partial benefits. Years of service prior to age 35 are not
included in determining the number of years of service.
Prior to January 1, 1993, the Company recognized the cost of
providing OPEB on a pay-as-you-go basis by expensing the annual
insurance premiums. These costs amounted to $1.3 million and $1.1
million for 1992 and 1991, respectively. Effective January 1,
1993, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 106, "Employers' Accounting for Postretirement
Benefits Other than Pensions", which requires, among other things,
that OPEB costs be recognized over the employment period that
encompasses eligibility to receive such benefits. In its December
16, 1992 decision on the Company's application for retail rate
relief, the DPUC recognized the Company's obligation to adopt SFAS
No. 106, effective January 1, 1993, and approved the Company's
request for revenues to recover OPEB expenses on a SFAS No. 106
basis. A portion of these expenses represents the transition
obligation, which will accrue over a 20-year period, representing
the future liability for medical and life insurance benefits based
on past service for retirees and active employees.
For funding purposes, the Company has established two Voluntary
Employees' Benefit Association Trusts (VEBA) to fund OPEB for
employees who retire on or after January 1, 1994; one VEBA for
union employees and one for non-union employees. Approximately 52%
of the Company's employees are represented by Local 470-1, Utility
Workers Union of America, AFL-CIO, for collective bargaining
purposes. The funding policy assumes contributions to these trust
funds to be the total OPEB expense under SFAS No. 106, excluding
the amount that resulted from the reorganization minus pay-as-you-
go benefit payments for pre-January 1, 1994 retirees, allocated in
a manner that minimizes current income tax liability, without
exceeding maximum tax deductible limits. In accordance with this
policy, the Company contributed approximately $3 million to the
union VEBA on December 30, 1993. The Company currently plans to
fund the portion of the OPEB expense that is related to the
reorganization during the years 1994-1996.
The 1993 cost for OPEB includes the following components:
<TABLE>
<CAPTION>
(000's)
<S> <C>
Service cost $1,182
Interest cost 1,959
Actual return on plan assets -
Amortizations and deferrals - net 1,215
------
Net Cost of Postretirement Benefit $4,356
======
Assumptions used to determine OPEB costs were:
Discount rate 8.25%
Health Care Cost Trend Rates
Pre-age 65 claims 8.3%*
Post-age 65 claims 9.0%*
<FN>
*Assumed rates gradually decline to 6.2% by the year 2020
</TABLE>
A one percentage point increase in the assumed health care cost
trend rate would have increased the service cost and interest cost
components of the 1993 net cost of periodic postretirement benefit
by approximately $445,000 and would increase the accumulated
postretirement benefit obligation for health care benefits by
approximately $2,421,000.
- 62 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table reconciles the funded status of the plan
with the amount recognized in the Consolidated Balance Sheet as of
December 31, 1993:
<TABLE>
<CAPTION>
(000's)
<S> <C>
Accumulated Postretirement Benefit Obligation:
Retirees $ 12,292
Fully eligible active plan participants 1,950
Other active plan participants 16,088
-------
Total Accumulated Postretirement Benefit Obligation 30,330
Plan assets at fair value 2,984
Accumulated Postretirement Benefit Obligation in
Excess of Plan Assets 27,346
Unrecognized net loss (2,990)
Unamortized transition obligation (23,089)
-------
Accrued Postretirement Benefit Obligation $ 1,267
=======
</TABLE>
The weighted average discount rate used to measure the
accumulated postretirement benefit obligation was 7.5%.
During 1993, in conjunction with a in-depth organizational
review, the Company offered a voluntary early retirement program to
non-union employees who were eligible to receive pension benefits.
This offer was accepted by 103 employees. The 1993 OPEB cost for
this program was $1.267 million. These costs are recognized as a
component of the reorganizational charge shown on the Company's
Consolidated Statement of Income.
In November 1992, the FASB issued SFAS No. 112, "Employers'
Accounting for Post-Employment Benefits". This statement, which
will be adopted during the first quarter of 1994, establishes
accounting standards for employers who provide benefits, such as
unemployment compensation, severance benefits and disability
benefits, to former or inactive employees after employment but
before retirement and requires recognition of the obligation for
these benefits. The adoption of this new standard will result in
a pre-tax charge against earnings amounting to approximately $2
million during the first quarter of 1994. Subsequent period costs
are not expected to be material.
- 63 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(I) JOINTLY OWNED PLANT
At December 31, 1993, the Company had the following interests in
jointly owned plants:
<TABLE>
<CAPTION>
Ownership/
Leasehold Plant In Accumulated
Share Service Depreciation
---------- -------- ------------
(Millions)
<S> <C> <C> <C>
Seabrook Unit 1 17.5 % $650 $63
Millstone Unit 3 3.685 134 48
New Haven Harbor Station 93.7 132 60
</TABLE>
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 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.
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial
institution providing for financing up to $37.5 million in fossil
fuel purchases. Under this agreement, the financing entity
acquires and stores natural gas, coal and fuel oil for sale to the
Company, and the Company purchases these fossil fuels from the
financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an
inventory of the fuel determined by reference to the fluctuating
interest rate on thirty-day, dealer-placed commercial paper in New
York. The Company is obligated to insure the fuel inventories and
to indemnify the financing entity against all liabilities, taxes
and other expenses incurred as a result of its ownership, storage
and sale of fossil fuel to the Company. This agreement currently
extends to February 1995. At December 31, 1993, approximately
$10.1 million of fossil fuel purchases were being financed under
this agreement.
The Company has leases (some of which are capital leases),
including arrangements for data processing and office equipment,
vehicles, office space and oil tanks. The gross amount of assets
recorded under capital leases and the related obligations of those
leases as of December 31, 1993 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>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
<TABLE>
<CAPTION>
Next five years: (000's)
<S> <C>
1994 $22,757
1995 950
1996 0
1997 0
1998 0
After 1998 0
-------
Total minimum capital lease payments 23,707
Less: Amount representing interest 1,998
-------
Present value of minimum capital lease payments $21,709
=======
</TABLE>
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.
Rental payments charged to operating expenses in 1993, 1992 and
1991 amounted to $14.1 million, $14.8 million and $14.9 million,
respectively.
Operating leases, which are charged to operating expense,
consist of a large number of small, relatively short-term,
renewable agreements for a wide variety of equipment.
(L) COMMITMENTS AND CONTINGENCIES
Capital Expenditure Program
The Company has entered into commitments in connection with its
continuing capital expenditure program, which is presently
estimated at approximately $366.5 million, excluding AFUDC, for
1994 through 1998.
Seabrook
After experiencing increasing financial stress beginning in May
1987, Public Service Company of New Hampshire (PSNH), which held
the largest ownership share (35.6%) in Seabrook, commenced a
proceeding under Chapter 11 of the Bankruptcy Code in January of
1988. Under this statute, PSNH continued its operations while
seeking a financial reorganization. A reorganization plan proposed
by Northeast Utilities (NU) was confirmed by the bankruptcy court
in April of 1990 and, on May 16, 1991, PSNH completed the financing
required for payment of its pre-bankruptcy secured and unsecured
debt under the first stage of the reorganization plan and emerged
from bankruptcy. On May 19, 1992, the NRC issued the final
regulatory approval necessary for the second stage of the NU
reorganization plan, under which PSNH would be acquired by NU; and
on June 5, 1992, this acquisition was completed. As part of the
transaction, PSNH's ownership share of Seabrook Unit 1 was
transferred to a wholly-owned subsidiary of NU. Two previous
regulatory approvals of the NU reorganization plan for PSNH, by the
Federal Energy Regulatory Commission (FERC) and the Securities and
Exchange Commission (SEC), continue to be challenged in court
proceedings, and the Company is unable to predict the outcome of
these proceedings.
On February 28, 1991, EUA Power Corporation (EUA Power), the
holder of a 12.1% ownership share in Seabrook, commenced a
proceeding under Chapter 11 of the Bankruptcy Code. EUA Power, a
wholly-owned subsidiary of Eastern Utilities Associates (EUA), was
organized solely for the purpose of acquiring an ownership share in
Seabrook and selling in the wholesale market its share of the
electric power produced by Seabrook. EUA Power commenced this
bankruptcy proceeding because the cash generated by its sales of
power at current market prices was insufficient to pay its
obligations on its outstanding debt. Subsequently, EUA Power's
name
- 65 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
was changed to Great Bay Power Corporation (Great Bay). The
official committee of Great Bay's bondholders (Bondholders
Committee) has proposed, and the bankruptcy court has confirmed, a
reorganization plan for Great Bay, under which substantially all of
the equity ownership of Great Bay would pass to its bondholders.
On February 2, 1994, the Bondholders Committee accepted a financing
proposal that would inject $35 million of new ownership equity into
Great Bay. The bankruptcy court must approve this structure before
the Great Bay reorganization plan becomes effective. Further
approvals are also required from the NRC, FERC and the New
Hampshire Public Utilities Commission. The bankruptcy court has
approved an agreement among Great Bay, the Bondholders Committee,
UI and The Connecticut Light and Power Company (CL&P), under which
up to $20 million in advance payments against their respective
future monthly Seabrook payment obligations will be made available
between UI and CL&P as needed until the reorganization plan becomes
effective. UI's share of funding obligations under this agreement
totals $8 million. As of December 31, 1993, $5.5 million had been
advanced by UI under this agreement. At January 31, 1994, $602,000
of the Company's advances remained outstanding. This agreement can
be terminated by UI and CL&P upon thirty days notice or upon
failure of the reorganization process to achieve certain milestones
by specified dates. UI is unable to predict what impact, if any,
failure of the reorganization plan to become effective will have on
the operating license for Seabrook Unit 1, or what other actions UI
and the other joint owners of the unit may be required to take in
response to developments in this bankruptcy proceeding as it may
affect Seabrook.
Nuclear generating units are subject to the licensing
requirements of the Nuclear Regulatory Commission (NRC) under the
Atomic Energy Act of 1954, as amended, and a variety of other state
and federal requirements. Although Seabrook Unit 1 has been issued
a 40-year operating license, NRC proceedings and investigations
prompted by inquiries from Congressmen and by NRC licensing board
consideration of technical contentions may arise and continue for
an indefinite period of time in the future.
Nuclear Insurance Contingencies
The Price-Anderson Act, currently extended through August 1,
2002, limits public liability resulting from a single incident at
a nuclear power plant. The first $200 million of liability
coverage is provided by purchasing the maximum amount of
commercially available insurance. Additional liability coverage
will be provided by an assessment of up to $75.5 million per
incident, levied on each of the nuclear units licensed to operate
in the United States, subject to a maximum assessment of $10
million per incident per nuclear unit in any year. In addition, if
the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial
protection, each reactor operator can be assessed an additional 5%
of $75.5 million, or $3.775 million. The maximum assessment is
adjusted at least every five years to reflect the impact of
inflation. Based on its interests in nuclear generating units, the
Company estimates its maximum liability would be $20.3 million per
incident. However, assessment would be limited to $3.1 million per
incident, per year. With respect to each of the 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.
The NRC requires nuclear generating units 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 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.
- 66 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Other Commitments and Contingencies
Hydro-Quebec
The Company is a participant in the Hydro-Quebec transmission
intertie facility linking New England and Quebec, Canada. Phase II
of this facility, in which UI has a 5.45% participating share, has
increased the capacity value of the intertie from 690 megawatts to
a maximum of 2000 megawatts. A ten-year Firm Energy Contract,
which provides for the sale of 7 million megawatt-hours per year by
Hydro-Quebec to the New England participants in the Phase II
facility, became effective on July 1, 1991. The Company is
obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. Currently, the Company's
guarantee liability for this debt amounts to approximately $9.8
million.
Reorganization Charge
During 1993, the Company undertook an in-depth organizational
review with the primary objective of improving customer service.
As a result of this review, the Company eliminated approximately 75
positions.
In conjunction with this review, the Company offered a voluntary
early retirement program to non-union employees who were eligible
to receive pension benefits. The early retirement offer was
accepted by 103 employees and the Company incurred a one-time
charge to 1993 earnings of approximately $13.6 million ($7.8
million, after-tax). No decision has been made as to whether to
offer a severance program to employees who may be affected by the
organizational review when it is completed, but who were not
eligible for, or did not accept, the early retirement offer.
Site Remediation Costs
The Company has estimated that the cost of environmental
remediation of its decommissioned Steel Point Station property in
Bridgeport will be approximately $10.3 million and has recorded a
liability for this cost. Following remediation, the Company
intends to sell the property for development for a value it
estimates will not exceed $6 million. In the Company's last rate
decision, the DPUC provided additional revenues to recover the $4.3
million difference during the period 1993-1996, subject to true-up
in the Company's next retail rate proceeding, based on actual
remediation costs and the actual gain on the sale of the property.
Property Taxes
In November 1993, the Company received "updated" personal
property tax bills from the City of New Haven (the City) for the
tax year 1991-1992, aggregating $6.6 million, based on an audit by
the City's tax assessor. The Company anticipates receiving
additional bills of this sort for the tax years 1992-1993 and
1993-1994, the amounts of which cannot be predicted at this time.
The Company is contesting these tax bills vigorously and has
commenced an action in the Superior Court to enjoin the City from
any effort to collect these tax bills. Due to a lack of data, it
is not possible, at this time, to assess accurately the Company's
liability, if any.
(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, beginning in 1998, 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
- 67 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 is to
take title to and dispose of the utilities' high level wastes and
spent nuclear fuel beginning no later than 1998. However, the DOE
has announced that its first high level waste repository will not
be in operation earlier than 2010, notwithstanding the DOE's
statutory and contractual responsibility to begin disposal of
high-level radioactive waste and spent fuel beginning not later
than January 31, 1998.
Until the federal government begins receiving such materials in
accordance with the Nuclear Waste Policy Act, operating nuclear
generating units will need to retain high level wastes and spent
fuel on-site or make other provisions for their storage. Storage
facilities for Millstone Unit 3 are expected to be adequate for the
projected life of the unit. Storage facilities for the Connecticut
Yankee unit are expected to be adequate through the mid-1990s.
Storage facilities for Seabrook Unit 1 are expected to be adequate
until at least 2010. Fuel consolidation and compaction
technologies are being developed and are expected to provide
adequate storage capability for the projected lives of the latter
two units. In addition, other licensed technologies, such as dry
storage casks, can accommodate spent fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that
result from normal operation of nuclear generating units have
increased significantly in recent years and are expected to
continue to increase. The cost increases are functions of
increased packaging and transportation costs and higher fees and
surcharges charged by the disposal facilities. Pursuant to the
Low-Level Radioactive Waste Policy Act of 1980, each state was
responsible for providing disposal facilities for LLW generated
within the state and was authorized to join with other states into
regional compacts to jointly fulfill their responsibilities.
Pursuant to the Low-Level Radioactive Waste Policy Amendments Act
of 1985, each state in which a currently operating disposal
facility is located (South Carolina, Nevada and Washington) is
allowed to impose volume limits and a surcharge on shipments of LLW
from states that are not members of the compact in the region in
which the facility is located. On June 19, 1992, the United States
Supreme Court issued a decision upholding certain parts of the
Low-Level Radioactive Waste Policy Amendments Act of 1985, but
invalidating a key provision of that law requiring each state to
take title to LLW generated within that state if the state fails to
meet federally-mandated deadlines for siting LLW disposal
facilities. The decision has resulted in uncertainty about states'
continuing roles in siting LLW disposal facilities and may result
in increased LLW disposal costs and the need for longer interim LLW
storage before a permanent solution is developed.
The Connecticut Hazardous Waste Management Service (the
Service), a state quasi-public corporation, was charged with
coordinating the establishment of a facility for disposal of LLW
originating in Connecticut. In June 1991, the Service announced
that it had selected three potential sites in north-central
Connecticut for further study. The Service's announcement provoked
intense controversy in the affected municipalities and resulted in
legislative action to stop the selection process. On February 1,
1993, the Service presented the legislature with a new site
selection plan under which communities are urged to volunteer a
site for a facility in return for financial and other incentives.
The volunteer process is being continued in 1994. The Service's
activities in this regard are funded by assessments on
Connecticut's LLW generators. Due to a change in the volunteer
process, there was no assessment for the 1993-1994 fiscal year and
the state projects no assessment for the 1994-1995 and 1995-1996
fiscal years.
Additional LLW storage capacity has been or can be constructed
or acquired at the Millstone and Connecticut Yankee sites to
provide for temporary storage of LLW should that become necessary.
Connecticut LLW can be managed by volume reduction, storage or
shipment at least through 1999. The Company cannot predict whether
and when a 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 Seabrook
Unit 1 has been denied access to existing disposal facilities.
Therefore, LLW generated
- 68 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
by Seabrook Unit 1 is being stored on-site. The Seabrook storage
facility currently has capacity to store approximately five years'
accumulation of waste generated by Seabrook, and the plant operator
plans to expand its storage capacity as necessary.
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. UI and the other owners of the nuclear
generating units in which UI has interests estimate decommissioning
costs for the units and attempt to recover sufficient amounts
through their allowed electric rates to cover expected
decommissioning costs. Changes in NRC requirements or technology
can increase estimated decommissioning costs, and UI's customers in
future years may experience higher electric rates to offset the
effects of any insufficient rate recovery in prior years.
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) established $345 million
(in 1993 dollars) as the decommissioning cost estimate for Seabrook
Unit 1. This estimate premises the prompt removal and dismantling
of the Unit at the end of its estimated 40-year energy producing
life. Monthly decommissioning payments are being made to the
state-managed decommissioning trust fund. UI's share of the
decommissioning payments made during 1993 was $1.3 million. UI's
share of the fund at December 31, 1993 was approximately $3.7
million.
Connecticut has enacted a law requiring the operators of nuclear
generating units to file periodically with the DPUC their plans for
financing the decommissioning of the units in that state. Current
decommissioning cost estimates for Millstone Unit 3 and Connecticut
Yankee are $421 million (in 1994 dollars) and $324 million (in 1994
dollars), respectively. These estimates premise the prompt removal
and dismantling of each unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on
these cost estimates, are being made to decommissioning trust funds
managed by Northeast Utilities. UI's share of the Millstone Unit
3 decommissioning payments made during 1993 was $328,000. UI's
share of the fund at December 31, 1993 was approximately $1.9
million. For the Company's 9.5% equity ownership in Connecticut
Yankee, decommissioning costs of $1.3 million were funded by UI
during 1993, and UI's share of the fund at December 31, 1993 was
$9.5 million.
Environmental Concerns
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 (particularly "air toxics", "ozone
non-attainment" and "global warming"), hazardous waste handling and
disposal, toxic substances, and electric and magnetic fields, the
Company may incur substantial capital expenditures for equipment
modifications and additions, monitoring equipment and recording
devices, and it may incur additional operating expenses.
Litigation expenditures may also increase as a result of scientific
investigations, and speculation and debate, concerning the
possibility of harmful health effects of electric and magnetic
fields. The Company believes that any additional costs incurred
for these purposes will be recoverable through the ratemaking
process. The total amount of these expenditures is not now
determinable.
(N) CHANGE IN METHOD OF ACCOUNTING FOR PROPERTY TAXES
Effective January 1, 1991, the Company changed its method of
accounting for property taxes from accrual over the twelve-month
period following assessment date to accrual over the fiscal period
of the applicable taxing authority. The effect of the change in
accounting was to increase 1991 earnings for common stock by $7.9
million, of which $7.3 million represented the cumulative effect of
the change at January 1, 1991, and $.6 million represented an
increase in earnings for 1991.
- 69 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(O) FAIR VALUE OF FINANCIAL INSTRUMENTS (1)
The estimated fair values of the Company's financial instruments
are as follows:
<TABLE>
<CAPTION>
1993 1992
---- ----
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(000's) (000's)
<S> <C> <C> <C> <C>
Cash and temporary cash investments $ 48,171 $ 48,171 $105,631 $105,631
Long-term debt (2)(3) $768,601 $810,329 $736,290 $786,496
<FN>
(1) Equity investments were not valued because they were not
considered to be material.
(2) Excludes the $250,000,000 Obligation under the Seabrook Unit
1 sale/leaseback agreement.
(3) The fair market value of the Company's long-term debt is
estimated by brokers based on market conditions at December
31, 1993 and 1992, respectively.
</TABLE>
- 70 -<PAGE>
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(P) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1993 and 1992 are set
forth below:
<TABLE>
<CAPTION>
Earnings (Loss)
Operating Operating Net Income Per Share of
Quarter Revenues Income (Loss) (2) Common Stock(1)(2)
- ------- --------- --------- ---------- ------------------
(000's) (000's) (000's)
<S> <C> <C> <C> <C>
1993
First $161,936 $31,164 $12,586 $ .82
Second 151,012 29,335 10,374 .66
Third 189,432 41,358 22,756 1.54
Fourth 150,643 12,957 (5,235) (.45)
1992
First $176,800 $30,177 $13,722 $ .91
Second 160,451 30,335 21,575 1.47
Third 175,877 29,889 16,014 1.07
Fourth 154,197 17,621 5,457 .31
------------------
<FN>
(1) Based on weighted average number of shares outstanding each quarter.
(2) Earnings per share for the fourth quarter of 1993 include an after-tax
charge of $7.8 million or $.56 per share associated with the
reorganization of the Company.
</TABLE>
- 71 -<PAGE>
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Shareowners and Directors of
The United Illuminating Company:
We have audited the accompanying consolidated balances sheets of
The United Illuminating Company as of December 31, 1993, 1992 and
1991, and related consolidated statements of income, retained
earnings and cash flows for the years then ended. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements and financial statement schedules based on
our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards 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. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of The United Illuminating Company as of
December 31, 1993, 1992, and 1991, and the consolidated results
of its operations and its cash flows for the years then ended in
conformity with generally accepted accounting principles.
/s/ COOPERS & LYBRAND
Hartford, Connecticut
January 24, 1994
- 72 -<PAGE>
<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.
The information appearing under the captions "NOMINEES FOR
ELECTION AS DIRECTORS" AND "COMPLIANCE WITH SECTION 16(a) OF THE
SECURITIES EXCHANGE ACT OF 1934" in the Company's definitive Proxy
Statement, dated April 8, 1994, for the Annual Meeting of the
Shareholders to be held on May 18, 1994, which Proxy Statement will
be filed with the Securities and Exchange Commission on or about
April 8, 1994, is incorporated by reference in partial answer to
this item. See also "EXECUTIVE OFFICERS OF THE COMPANY", following
Part I, Item 4 herein.
Item 11. Executive Compensation.
The information appearing under the captions "EXECUTIVE
COMPENSATION," "STOCK OPTION PLAN," "RETIREMENT PLANS,"
"STOCK OPTION EXERCISES IN 1993 AND YEAR-END OPTION VALUES,"
"COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION"
AND "DIRECTOR COMPENSATION" in the Company's definitive Proxy
Statement, dated April 8, 1994, for the Annual Meeting of the
Shareholders to be held on May 18, 1994, which Proxy Statement
will be filed with the Securities and Exchange Commission on or
about April 8, 1994, is incorporated by reference in answer to
this item.
Item 12. Security Ownership of Certain Beneficial Owners and
Management.
The information appearing under the captions "PRINCIPAL
SHAREHOLDERS" and "STOCK OWNERSHIP OF DIRECTORS AND OFFICERS" in
the Company's definitive Proxy Statement, dated April 8, 1994 for
the Annual Meeting of the Shareholders to be held on May 18, 1994,
which Proxy Statement will be filed with the Securities and
Exchange Commission on or about April 8, 1994, is incorporated by
reference in answer to this item.
Item 13. Certain Relationships and Related Transactions.
The information appearing under the caption "NOMINEES FOR
ELECTION AS DIRECTORS" in the Company's definitive Proxy Statement,
dated April 8, 1994, for the Annual Meeting of the Shareholders to
be held on May 18, 1994, which Proxy Statement will be filed with
the Securities and Exchange Commission on or about April 8, 1994,
is incorporated by reference in answer to this item.
- 73 -<PAGE>
<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,
1993, 1992 and 1991
Consolidated statement of cash flows for the years ended
December 31, 1993, 1992 and 1991
Consolidated balance sheet, December 31, 1993, 1992 and 1991
Consolidated statement of retained earnings for the years
ended December 31, 1993, 1992 and 1991
Statement of accounting policies
Notes to consolidated financial statements
Report of independent accountants
Financial Statement Schedules (see S-1 through S-5)
Schedule V - Property, plant and equipment for the years ended
December 31, 1993, 1992 and 1991.
Schedule VI - Accumulated depreciation, depletion and
amortization of property, plant and equipment for the years
ended December 31, 1993, 1992 and 1991.
Schedule VIII - Valuation and qualifying accounts for the
years ended December 31, 1993, 1992 and 1991.
- 74 -<PAGE>
<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, 1991.
(2) Filed with Registration Statement No. 2-45434, effective
September 25, 1972, and Registration Statement No. 2-45435,
effective September 26, 1972.
(3) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(4) Filed with Registration Statement No. 2-66518, effective
February 25, 1980.
(5) Filed with Registration Statement No. 2-57275, effective
October 19, 1976.
(6) Filed with Registration Statement No. 2-67998, effective June 19, 1980.
(7) Filed with Registration Statement No. 2-72907, effective July 16, 1981.
(8) Filed with Post-Effective Amendment No. 1 to Registration
Statement No. 2-78643, effective August 19, 1982.
(9) Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1990.
(10) Filed with Quarterly Report (Form 10-Q) for fiscal quarter
ended September 30, 1991.
(11) Filed with Quarterly Report (Form 10-Q) for fiscal quarter
ended March 31, 1991.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1992.
(13 Filed with Registration Statement No. 33-40169, effective
August 12, 1991.
(14) Filed with Registration Statement No. 33-35465, effective
August 1, 1990.
(15) Filed with Registration Statement No. 2-49669, effective
December 11, 1973.
(16) Filed with Registration Statement No. 2-54876, effective
November 19, 1975.
(17) Filed with Registration Statement No. 2-52657, effective
February 6, 1975.
(18) Filed with Quarterly Report (Form 10-Q) for fiscal quarter
ended June 30, 1992.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter
ended September 30, 1990.
- 75 -<PAGE>
<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.
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- -------- ------- --------- -----------
(3) 3.1 (1) Copy of Charter of The United Illuminating Company,
dated December 15, 1965. (Exhibit 3.1)
(3) 3.2 (2) Copy of a certificate concerning the creation of a
class of Preferred Stock of The United Illuminating
Company and the authority of the Board of Directors
to issue said Preferred Stock, dated July 13, 1956,
and filed with the Secretary of State of
Connecticut July 13, 1956. (Exhibit 3.12)
(3) 3.3 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated November 19, 1962, andfiled with the
Secretary of State of Connecticut November 29,
1962. (Exhibit 3.3)
(3) 3.4 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated October 25, 1965, and filed with the
Secretary of State of Connecticut November 22,
1965. (Exhibit 3.4)
(3) 3.5 (2) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated June 6, 1967, and filed
with the Secretary of State of Connecticut
June 6, 1967. (Exhibit 3.13)
(3) 3.6 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated December 1, 1967, and filed with the
Secretary of State of Connecticut December 7,
1967. (Exhibit 3.6)
(3) 3.7 (3) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated April 27, 1971, and
filed with the Secretary of State of Connecticut
April 29, 1971. (Exhibit 2.2-14)
(3) 3.8 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated March 29, 1972, and filed with the Secretary
of State of Connecticut March 30, 1972.
(Exhibit 3.8)
(3) 3.9 (4) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors and
Shareholders, dated May 4 1973, and filed with the
Secretary of State of Connecticut May 7, 1973.
(Exhibit 2.2-17)
(3) 3.10 Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated July 2, 1973, and filed with the Secretary
of State of Connecticut July 2, 1973.
(Exhibit 3.10)
(3) 3.11 (5) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated April 26, 1976, and filed
with the Secretary of State of Connecticut
April 27, 1976. (Exhibit 2.2-18)
(3) 3.12 (5) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated April 26, 1976, and filed
with the Secretary of State of Connecticut
April 27, 1976. (Exhibit 2.2-19)
(3) 3.13 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated October 20, 1976, and filed with the
Secretary of State of Connecticut October 21,
1976. (Exhibit 3.13)
(3) 3.14 (1) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated April 4, 1979, and filed with the Secretary
of State of Connecticut April 5, 1979.
(Exhibit 3.14)
(3) 3.15 Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated April 29, 1980, and filed with the Secretary
of State of Connecticut April 30, 1980.
(Exhibit 3.15)
- 76 -<PAGE>
<PAGE>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- -------- ------- --------- -----------
(3) 3.16 (6) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated May 20, 1980, and filed
with the Secretary of State of Connecticut May 23,
1980. (Exhibit 2.2-20)
(3) 3.17 (7) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated June 12, 1981, and filed
with the Secretary of State of Connecticut
June 16, 1981. (Exhibit 1.20)
(3) 3.18 (12) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated July 13, 1981, and filed with the Secretary
of State of Connecticut July 14, 1981.
(3) 3.19 (8) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors
and Shareholders, dated June 1, 1983, and filed
with the Secretary of State of Connecticut
June 3, 1983. (Exhibit 4.31)
(3) 3.20 (9) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated July 24, 1984, and filed with the Secretary
of State of Connecticut July 24, 1984.
(Exhibit 1)
(3) 3.21 (9) Copy of Certificate Amending Certificate of
Incorporation by Action of Board of Directors,
dated August 8, 1984, and filed with the Secretary
of State of Connecticut August 9, 1984.
(Exhibit 2)
(3) 3.22 (9) Copy of Certificate Amending or Restating
Certificate of Incorporation, filed with the
Secretary of State of Connecticut August 1, 1990.
(Exhibit 3.22)
(3) 3.23 (10) Copy of Certificate Amending or Restating
Certificate of Incorporation, dated May 9, 1991,
and filed with the Secretary of State of
Connecticut August 27, 1991. (Exhibit 3.22a)
(3) 3.24a (3) Copy of Bylaws of The United Illuminating
Company. (Exhibit 2.3)
(3) 3.24b (10) Copy of Article II, Section 2, of Bylaws of The
United Illuminating Company, as amended March 26,
1990, amending Exhibit 3.24a. (Exhibit 3.23b)
(3) 3.24c (11) Copy of Article V, Section 1, of Bylaws of The
United Illuminating Company, as amended April 22,
1991, amending Exhibit 3.24a. (Exhibit 3.23c)
(4) 4.1 (9) Copy of First Mortgage Indenture and Deed of Trust,
dated as of December 1, 1984, between Bridgeport
Electric Company and The First National Bank of
Boston, Trustee. (Exhibit 4.12)
(4) 4.2 (12) Copy of First Supplemental Mortgage Indenture,
dated as of February 15, 1987, between Bridgeport
Electric Company and The First National Bank of
Boston, Trustee, amending and supplementing
Exhibit 4.1. (Exhibit 4.2)
(4) 4.3 (12) Copy of Second Supplemental Mortgage Indenture,
dated as of January 14, 1988, between Bridgeport
Electric Company and The First National Bank of
Boston, Trustee, amending and supplementing Exhibit
4.1 and amending Exhibit 4.2. (Exhibit 4.3)
(4) 4.4 Copy of Third Supplemental Mortgage Indenture,
dated as of March 31, 1988 between Bridgeport
Electric Company and The First National Bank of
Boston, Trustee, amending Exhibit 4.1.
(4) 4.5 (13) Copy of Indenture, dated as of August 1, 1991,
from The United Illuminating Company to The Bank
of New York, Trustee. (Exhibit 4)
(4) 4.6 (14) Copy of Participation Agreement, dated as of
(10) 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).
- 77 -<PAGE>
<PAGE>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- -------- ------- --------- -----------
(10) 10.1 (5) 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 (5) 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 (3) Copy of Supplementary Power Contract, dated as
of March 1, 1978, between Connecticut Yankee
Atomic Power Company and The United Illuminating
Company, supplementing Exhibit 10.2a.
(Exhibit 5.1-6)
(10) 10.2c (1) Copy of Agreement Amending Supplementary Power
Contract, dated August 22, 1980, between
Connecticut Yankee Atomic Power Company and The
United Illuminating Company, amending
Exhibit 10.2b. (Exhibit 10.2b)
(10) 10.2d (12) Copy of Second Amendment of the Supplementary
Power Contract, dated as of October 15, 1982,
between Connecticut Yankee Atomic Power Company
and The United Illuminating Company, amending
Exhibit 10.2b. (Exhibit 10.2d)
(10) 10.2e (9) Copy of Second Supplementary Power Contract,
dated as of April 30, 1984, between Connecticut
Yankee Atomic Power Company and The United
Illuminating Company, supplementing
Exhibit 10.2a. (Exhibit 10.2e)
(10) 10.2f (9) Copy of Additional Power Contract, dated as of
April 30, 1984, between Connecticut Yankee Atomic
Power Company and The United Illuminating Company.
(Exhibit 10.2f)
(10) 10.3 (5) 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) 10.4a (5) Copy of Connecticut Yankee Transmission
Agreement, dated as of October 1, 1964, among the
various stockholders of Connecticut Yankee Atomic
Power Company, including The United Illuminating
Company. (Exhibit 5.1-4)
(10) 10.4b (4) Copy of Agreement Amending and Revising
Connecticut Yankee Transmission Agreement, dated
as of July 1, 1979, amending Exhibit 10.4a.
(Exhibit 5.1-7)
(10) 10.5 (3) 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) 10.6a (1) Copy of NEPOOL Power Pool Agreement, dated as
of September 1, 1971, as amended to November 1,
1988. (Exhibit 10.6a)
(10) 10.6b (15) Copy of Agreement Setting Out Supplemental
NEPOOL Understandings, dated as of April 2, 1973.
(Exhibit 5.7-10)
(10) 10.6c (1) Copy of Amendment to NEPOOL Power Pool Agreement,
dated as of March 15, 1989, amending
Exhibit 10.6a. (Exhibit 10.6c)
(10) 10.6d (1) Copy of Agreement Amending NEPOOL Power Pool
Agreement, dated as of October 1, 1990, amending
Exhibit 10.6a. (Exhibit 10.6d)
(10) 10.6e Copy of Agreement Amending NEPOOL Power Pool
Agreement, dated as of September 15, 1992,
amending Exhibit 10.6a.
(10) 10.6f Copy of Agreement Amending NEPOOL Power Pool
Agreement, dated as of June 1, 1993, amending
Exhibit 10.6a.
(10) 10.7a (1) 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) 10.7b (16) Copy of Transmission Support Agreement, dated
as of May 1, 1973, among the Seabrook Companies.
(Exhibit 5.9-2)
- 78 -<PAGE>
<PAGE>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- -------- ------- --------- -----------
(10) 10.7c (10) 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 10.7a.
(Exhibit 10.8ab)
(10) 10.8a (4) 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) 10.8b (17) Copy of Amendment to Sharing Agreement - 1979
Connecticut Nuclear Unit, dated as of August 1,
1974, amending Exhibit 10.8a. (Exhibit 5.9-2)
(10) 10.8c (5) Copy of Amendment to Sharing Agreement - 1979
Connecticut Nuclear Unit, dated as of December 15,
1975, amending Exhibit 10.8a.
(Exhibit 5.8-4, Post-effective Amendment No. 2)
(10) 10.9a (3) 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) 10.9b (1) Notice, dated April 24, 1978, of The United
Illuminating Company's intention to extend term
of Transmission Line Agreement dated January 13,
1966, Exhibit 10.9a. (Exhibit 10.9b)
(10) 10.9c (1) Copy of Letter Agreement, dated March 28, 1985,
between The United Illuminating Company and
National Railroad Passenger Corporation,
supplementing and modifying Exhibit 10.9a.
(Exhibit 10.9c)
(10) 10.10 (12) Copy of Agreement, effective May 16, 1992,
between The United Illuminating Company and Local
470-1, Utility Workers Union of America, AFL-CIO.
(Exhibit 10.10)
(10) 10.11 Copy of Fuel Oil Purchase and Sale Agreement,
dated as of October 1, 1993, among Tosco
Corporation, The United Illuminating Company and
The Connecticut Light and Power Company.
(Confidential treatment requested)
(10) 10.12 (12) Copy of Coal Sales Agreement, dated as of
August 1, 1992, between Pittston Coal Sales
Corp. and The United Illuminating Company.
(Confidential treatment requested)
(Exhibit 10.13)
(10) 10.13 (10) Copy of Fossil Fuel Supply Agreement between
BLC Corporation and The United Illuminating
Company, dated as of July 1, 1991.
(Exhibit 10.31)
(10) 10.14a (9) Copy of Lease, dated as of December 1, 1984,
between Bridgeport Electric Company as Lessor
and The United Illuminating Company as Lessee.
(Exhibit 10.22a)
(10) 10.14b (12) Copy of Amendment, dated as of February 15,
1987, to Lease between Bridgeport Electric
Company as Lessor and The United Illuminating
Company as Lessee, amending Exhibit 10.16a.
(Exhibit 10.16b)
(10) 10.14c (12) Copy of Second Amendment to Lease, dated as of
December 9, 1987, between Bridgeport Electric
Company as Lessor and The United Illuminating
Company as Lessee, amending Exhibit 10.16a.
(Exhibit 10.16c)
(10) 10.14d (12) Copy of Third Amendment to Lease, dated as of
January 14, 1988, between Bridgeport Electric
Company as Lessor and The United Illuminating
Company as Lessee, amending Exhibit 10.16a.
(Exhibit 10.16d)
- 79 -<PAGE>
<PAGE>
Exhibit
Table Exhibit Reference
Item No. No. No. Description
- -------- ------- --------- -----------
(10) 10.15a (12) Copy of Revolving Credit Agreement, dated as of
January 25, 1993, among The United Illuminating
Company, the Banks named therein, and Citibank,
N.A., as Agent for the Banks. (Exhibit 10.19)
(10) 10.15b Copy of letter, dated January 27, 1994, from
Citibank, N.A., extending the expiration date of
Exhibit 10.15a to January 19, 1995.
(10) 10.16a* (12) Copy of Employment Agreement, dated as of January 1,
1988, between The United Illuminating Company and
Richard J. Grossi. (Exhibit 10.22a)
(10) 10.16b* (19) Copy of Amendment to Employment Agreement, dated
as of July 23, 1990, between The United
Illuminating Company and Richard J. Grossi,
amending Exhibit 10.22a. (Exhibit 10.26a)
(10) 10.17a* (12) Copy of Employment Agreement, dated as of
January 1, 1988, between The United Illuminating
Company and Robert L. Fiscus. (Exhibit 10.23a)
(10) 10.17b* (19) Copy of Amendment to Employment Agreement, dated
as of July 23, 1990, between The United
Illuminating Company and Robert L. Fiscus,
amending Exhibit 10.23a. (Exhibit 10.27a)
(10) 10.18a* (12) Copy of Employment Agreement, dated as of
January 1, 1988, between The United Illuminating
Company and James F. Crowe. (Exhibit 10.24a)
(10) 10.18b* (19) Copy of Amendment to Employment Agreement, dated
as of July 23, 1990, between The United
Illuminating Company and James F. Crowe,
amending Exhibit 10.24a. (Exhibit 10.28a)
(10) 10.19* (1) Copy of Executive Incentive Compensation Program
of The United Illuminating Company.
(Exhibit 10.24)
(10) 10.21a* (19) Copy of The United Illuminating Company 1990
Stock Option Plan. (Exhibit 10.33)
(10) 10.21b Amendments to The United Illuminating Company 1990
Stock Option Plan, adopted November 22, 1993 and
January 24, 1994.
(21) 21 List of subsidiaries of The United Illuminating
Company.
(28) 28.1 (12) Copies of significant rate schedules of The
United Illuminating Company. (Exhibit 28.1)
- -----------------------
*Management contract or compensatory plan or arrangement.
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.
Items Financial Statements Date of
Reported Filed Report
- -------- -------------------- -------
5 None December 22, 1993
- 80 -<PAGE>
<PAGE>
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We consent to the incorporation by reference in the Registration
Statement of The United Illuminating Company on Form S-3 (File
No. 33-50221) and the Registration Statement on Form S-3 (File
No. 33-50445) of our report, dated January 24, 1994, on our
audits of the consolidated financial statements and financial
statement schedules of The United Illuminating Company as of
December 31, 1993, 1992 and 1991 and for the years then ended,
which report is included in this Annual Report on Form 10-K.
/s/ COOPERS & LYBRAND
Hartford, Connecticut
February 15, 1994
- 81 -<PAGE>
<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/ Richard J. Grossi
------------------------------
Richard J. Grossi
Chairman of the Board of Directors
and Chief Executive Officer
Date: February 18, 1994
-----------------
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.
Signature Title Date
--------- ----- ----
Director, Chairman of the
Board of Directors and
/s/ Richard J. Grossi Chief Executive Officer February 18, 1994
- ---------------------
(Richard J. Grossi)
(Principal Executive Officer)
Director, President and
/s/ Robert L. Fiscus Chief Financial Officer February 18, 1994
- ---------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
/s/ John D. Fassett Director February 18, 1994
- --------------------
(John D. Fassett)
/s/ Leland W. Miles Director February 18, 1994
- --------------------
(Leland W. Miles)
/s/ William S. Warner Director February 18, 1994
- ----------------------
(William S. Warner)
/s/ John F. Croweak Director February 18, 1994
- --------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director February 18, 1994
- -----------------------------
(F. Patrick McFadden, Jr.)
/s/ J. Hugh Devlin Director February 18, 1994
- -------------------
(J. Hugh Devlin)
/s/ Betsy Henley-Cohn Director February 18, 1994
- ----------------------
(Betsy Henley-Cohn)
Director February , 1994
- ------------------------
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director February 18, 1994
- ----------------------
(James A. Thomas)
/s/ David E.A. Carson Director February 18, 1994
- ----------------------
(David E.A. Carson)
- 82 -<PAGE>
<PAGE>
<TABLE>
Schedule V
Property, Plant
and Equipment
THE UNITED ILLUMINATING COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1993
(Thousands of Dollars)
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
---------- -------- -------- -------- -------- --------
Other
Balance at Changes Balance at
Beginning Additions Add End of
Classification of Period at Cost Retirements (Deduct) Period
---------------- ----------- --------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
UTILITY PLANT, at original cost:
ELECTRIC PLANT IN SERVICE:
Production Plant:
Steam $323,658 $12,517 $333 $33 $335,875
Nuclear 757,744 9,652 960 - 766,436
Jet Turbine 1,845 - - - 1,845
----------- ----------- ----------- ----------- -----------
Total Production Plant 1,083,247 22,169 1,293 33 1,104,156
Transmission Plant 126,211 8,791 660 (5,156) 129,186
Distribution Plant 319,409 17,664 8,011 5,189 334,251
General Plant 42,065 1,357 2,373 (40) 41,009
Intangible Plant 34,318 18,001 - - 52,319
----------- ----------- ----------- ----------- -----------
Total Electric Plant in Service 1,605,250 67,982 12,337 26 1,660,921
ELECTRIC PLANT HELD FOR
FUTURE USE 26,537 2,739 3 (52) 29,221
CONSTRUCTION WORK IN
PROGRESS 59,809 17,586 - - 77,395
NUCLEAR FUEL OWNED AND
LEASED 52,144 10,063 - (21,922)(1) 40,285
----------- ----------- ----------- ----------- -----------
TOTAL UTILITY PLANT,
at original cost $1,743,740 98,370 $12,340 ($21,948) $1,807,822
=========== =========== =========== ===========
NONUTILITY PROPERTY, at cost $20,337 440 $11,392 - $9,385
=========== ----------- =========== =========== ===========
GROSS PROPERTY ADDITIONS $98,810
===========
- --------------------
<FN>
NOTES:
(1) Represents nuclear fuel consumed at Millstone Unit 3 and Seabrook Unit 1.
</TABLE>
S-1<PAGE>
<PAGE>
<TABLE>
Schedule V
Property, Plant
and Equipment
THE UNITED ILLUMINATING COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1992
(Thousands of Dollars)
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
---------- -------- -------- -------- -------- --------
Other
Balance at Changes Balance at
Beginning Additions Add End of
Classification of Period at Cost Retirements (Deduct) Period
---------------- ----------- --------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
UTILITY PLANT, at original cost:
ELECTRIC PLANT IN SERVICE:
Production Plant:
Steam $344,710 $2,982 $806 ($23,228)(1) $323,658
Nuclear 757,311 433 - - 757,744
Jet Turbine 1,730 115 - - 1,845
----------- ----------- ----------- ----------- -----------
Total Production Plant 1,103,751 3,530 806 (23,228) 1,083,247
Transmission Plant 108,837 18,215 848 7 126,211
Distribution Plant 304,774 21,236 6,263 (338) 319,409
General Plant 49,767 1,221 8,365 (558) 42,065
Intangible Plant 22,078 12,240 - - 34,318
----------- ----------- ----------- ----------- -----------
Total Electric Plant in Service 1,589,207 56,442 16,282 (24,117) 1,605,250
ELECTRIC PLANT HELD FOR
FUTURE USE 2,208 1,090 - 23,239 (1) 26,537
CONSTRUCTION WORK IN
PROGRESS 54,771 5,038 - - 59,809
NUCLEAR FUEL OWNED AND
LEASED 65,450 6,921 - (20,227)(2) 52,144
----------- ----------- ----------- ----------- -----------
TOTAL UTILITY PLANT,
at original cost $1,711,636 69,491 $16,282 ($21,105) $1,743,740
=========== =========== =========== ===========
NONUTILITY PROPERTY, at cost $20,206 131 $ - $ - $20,337
=========== ----------- =========== =========== ===========
GROSS PROPERTY ADDITIONS $69,622
===========
- --------------------
<FN>
NOTES:
(1) Represents a transfer of English Station from Plant in Service to Electric Plant Held for Future Use.
(2) Represents nuclear fuel consumed at Millstone Unit 3 and Seabrook Unit 1.
</TABLE>
S-2<PAGE>
<PAGE>
<TABLE>
Schedule V
Property, Plant
and Equipment
THE UNITED ILLUMINATING COMPANY
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1991
(Thousands of Dollars)
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
---------- -------- -------- -------- -------- --------
Other
Balance at Changes Balance at
Beginning Additions Add End of
Classification of Period at Cost Retirements (Deduct) Period
---------------- ----------- --------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
UTILITY PLANT, at original cost:
ELECTRIC PLANT IN SERVICE:
Production Plant:
Steam $343,935 $1,356 $603 $22 $344,710
Nuclear 763,745 1,589 (41) (8,064) 757,311
Jet Turbine 1,730 - - - 1,730
----------- ----------- ----------- ----------- -----------
Total Production Plant 1,109,410 2,945 562 (8,042) 1,103,751
Transmission Plant 88,709 19,260 344 1,212 108,837
Distribution Plant 291,988 19,319 4,871 (1,662) 304,774
General Plant 43,731 (385) 1,058 7,479 49,767
Intangible Plant 7,046 14,146 - 886 22,078
----------- ----------- ----------- ----------- -----------
Total Electric Plant in Service 1,540,884 55,285 6,835 (127) 1,589,207
ELECTRIC PLANT HELD FOR
FUTURE USE - LAND 848 1,360 - - 2,208
CONSTRUCTION WORK IN
PROGRESS 50,257 4,514 - - 54,771
NUCLEAR FUEL OWNED AND
LEASED 77,850 6,972 - (19,372)(1) 65,450
----------- ----------- ----------- ----------- -----------
TOTAL UTILITY PLANT,
at original cost $1,669,839 68,131 $6,835 ($19,499) $1,711,636
=========== =========== =========== ===========
NONUTILITY PROPERTY, at cost $19,988 216 $ - $2 $20,206
=========== ----------- =========== =========== ===========
GROSS PROPERTY ADDITIONS $68,347
===========
- --------------------
<FN>
NOTES:
(1) Represents nuclear fuel consumed at Millstone Unit 3 and Seabrook Unit 1.
</TABLE>
S-3<PAGE>
<PAGE>
<TABLE>
Schedule VI
Accumulated
Depreciation
THE UNITED ILLUMINATING COMPANY
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31, 1993, 1992 and 1991
(Thousands of Dollars)
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
---------- -------- -------- -------- -------- --------
Additions Other
Balance at Charged to Changes Balance at
Beginning Costs and Add End of
Classification of Period Expenses Retirements (Deduct) Period
---------------- ----------- --------- ----------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Accumulated depreciation,
utility plant:
1993 $407,729 $52,077 (A) $12,340 ($750)(D) $446,716
1992 371,544 49,369 (B) 16,282 3,098 (D) 407,729
1991 332,559 47,167 (C) 6,866 (1,316)(D) 371,544
Accumulated depreciation,
nonutility plant:
1993 17,813 1 11,392 - 6,422
1992 17,813 - - - 17,813
1991 17,813 - - - 17,813
- --------------------
<FN>
NOTES:
(A) Excludes $1,075 of amortization of costs for Steel Point Station, $1,516 of amortization of
economic development costs, $1,616 of decommissioning costs applicable to Millstone Unit 3
and Seabrook Unit 1 and $3 depreciation expense billed by lead owners (Unit 3).
(B) Excludes decommissioning costs of $1,334 applicable to Millstone Unit 3 and Seabrook Unit 1
and $3 depreciation expense billed by lead owners (Unit 3).
(C) Excludes decommissioning costs of $1,011 applicable to Millstone Unit 3 and Seabrook Unit 1
and $3 depreciation expense billed by lead owners (Unit 3).
1993 1992 1991
(D) Represents: ------ ------ ------
Government reimbursements in connection
with relocation of plant in service $184 $395 ($13)
Net salvage (cost of removal) (934) 2,703 (1,303)
----------- ----------- -----------
($750) $3,098 ($1,316)
=========== =========== ===========
</TABLE>
S-4<PAGE>
<PAGE>
<TABLE>
Schedule VIII
Valuation and
Qualifying Accounts
THE UNITED ILLUMINATING COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1993, 1992 and 1991
(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:
1993 $3,900 $8,971 - $8,171 (A) $4,700
1992 3,200 8,741 - 8,041 (A) 3,900
1991 3,100 7,160 - 7,060 (A) 3,200
- --------------------
<FN>
NOTE:
(A) Accounts written off, less recoveries.
</TABLE>
S-5<PAGE>
<PAGE>
EXHIBIT INDEX
(a) Exhibits
Exhibit
Table Item Exhibit
Number Number Description Page No.
---------- ------- ----------- --------
(4) 4.4 Copy of Third Supplemental Mortgage
Indenture, dated as of March 31, 1988
between Bridgeport Electric Company and
The First National Bank of Boston,
Trustee, amending Exhibit 4.1.
(10) 10.6e Copy of Agreement Amending NEPOOL Power
Pool Agreement, dated as of September 15,
1992, amending Exhibit 10.6a.
(10) 10.6f Copy of Agreement Amending NEPOOL Power
Pool Agreement, dated as of June 1, 1993,
amending Exhibit 10.6a.
(10) 10.11 Copy of Fuel Oil Purchase and Sale
Agreement, dated as of October 1, 1993,
among Tosco Corporation, The United
Illuminating Company and The Connecticut
Light and Power Company. (Confidential
treatment requested)
(10) 10.15b Copy of letter, dated January 27, 1994,
from Citibank, N.A., extending the
expiration date of Exhibit 10.15a
to January 19, 1995.
(10) 10.21b Amendments to The United Illuminating
Company 1990 Stock Option Plan, adopted
November 22,1993 and January 24, 1994.
(21) 21 List of subsidiaries of The United
Illuminating Company.
<PAGE>
<PAGE>
<PAGE>
EXHIBIT NO. 4.4
BRIDGEPORT ELECTRIC COMPANY
TO
THE FIRST NATIONAL BANK OF BOSTON,
TRUSTEE
----------------------------
THIRD SUPPLEMENTAL MORTGAGE INDENTURE
Dated as of March 31, 1988
TO
FIRST MORTGAGE INDENTURE AND DEED OF TRUST
Dated as of December 1, 1984
<PAGE>
<PAGE>
THIS THIRD SUPPLEMENTAL MORTGAGE INDENTURE, dated as of
March 31, 1988, made and entered into by and between BRIDGEPORT
ELECTRIC COMPANY, a Delaware corporation, with its principal
office in New Haven, Connecticut (hereinafter with its successors
and assigns called the Company), and THE FIRST NATIONAL BANK OF
BOSTON, a national banking association, with its principal office
in Boston, Massachusetts (hereinafter with its successors called
the Trustee), witnesseth that:
WHEREAS, the Company heretofore duly executed and delivered
to the Trustee a certain First Mortgage Indenture and Deed of
Trust dated as of December 1, 1984, a First Supplemental Mortgage
Indenture dated as of February 15, 1987 and a Second Supplemental
Mortgage Indenture dated as of January 14, 1988 (said First
Mortgage Indenture and Deed of Trust being hereinafter referred
to as the Mortgage Indenture, and together with all indentures
expressly stated to be supplemental thereto, including said First
and Second Supplemental Mortgage Indentures and this Third
Supplemental Mortgage Indenture, being hereinafter generally
referred to as the Indenture, as provided in Section 1.20 of the
Mortgage Indenture) for the purpose of borrowing money for its
corporate purposes and issuing its bonds therefor from time to
time in one or more series and to secure the same, which Mortgage
Indenture and First and Second Supplemental Mortgage Indentures
are recorded, respectively, in the office of the Secretary of the
State of Connecticut in Volume 60, Page K, Volume 61, Page 186,
and Volume 61, Page 320, Railroad Mortgages, and in the Land
Records of the Towns of Bridgeport and New Haven, Connecticut,
and are also on file in the offices of the Trustee and the
Company and to which indentures reference is hereby expressly
made; and
WHEREAS, the Company has heretofore issued under the
Indenture $200,000,000 principal amount of the Company's 18%
First Mortgage Bonds, Series A, due November 30, 1994,
$54,000,000 principal amount of the Company's 9.44% First
Mortgage Bonds, Series B, due February 15, 1999 and $180,000,000
of 10.32% First Mortgage Bonds, Series C, due January 15, 1995,
of which only the $54,000,000 of Series B Bonds and the
$180,000,000 of Series C bonds are now outstanding; and
WHEREAS, the Company purposes to amend Article 4 of the
Mortgage Indenture, with the consent of the holders of not less
than 66 2/3% of the outstanding Bonds, to change the limits in
the issue of additional series of Bonds; and
WHEREAS the execution and delivery of this Third
Supplemental Mortgage Indenture is authorized by section 14.02 of
the Mortgage Indenture and has been duly authorized by the Board
of Directors of the Company; and
WHEREAS all acts and things necessary to constitute this
Third Supplemental Mortgage Indenture a valid, legal and binding
<PAGE>
<PAGE>
instrument enforceable in accordance with its terms have been in
all respects duly authorized and done.
NOW, THEREFORE, it is hereby covenanted, declared and
agreed, upon the trusts and for the purposes aforesaid, as set
forth in the following covenants, agreements, conditions and
provisions, viz.:
ARTICLE 1
AMENDMENT OF THE INDENTURE
1.01 Amendment of Section 4.02. Section 4.02 of the Mortgage
Indenture is hereby amended to read in its entirety as follows:
4.02. Additional Bonds. Bonds of one or more series
having a final maturity date not earlier than the final
maturity date of the Series A Bonds may be authenticated and
delivered from time to time pursuant to this section so long
as the aggregate principal amount of Bonds outstanding,
including the Bonds then being authenticated and delivered
pursuant to this section, but excluding (i) any Bonds
outstanding which have been authenticated and delivered
pursuant to section 4.03 and (ii) any Bonds which have been
authenticated and delivered pursuant to section 4.05 on the
basis of retired Bonds which were previously authenticated
and delivered pursuant to section 4.03, shall not exceed
$375,000,000, but only upon and in compliance with the
provisions of section 4.01 and the furnishing of the
following documents to the Trustee:
(a) a Lease Amendment which (i) amends the Lease
to increase the rental payments to a level sufficient
to assure that the payments will, after deducting all
other amounts required to be paid therefrom, at least
equal the scheduled payments of principal, premium, if
any, and interest on all outstanding Bonds and Junior
Debt, but (ii) does not amend or modify the Lease in
any other respect;
(b) a supplemental indenture or other instrument,
duly executed by the Company, subjecting the Company's
interest in the Lease Amendment to the lien of this
Indenture;
(c) an Opinion of Counsel, dated not earlier than
the date of the application for authentication and
delivery of the Bonds, setting forth:
(1) that he has examined the Lease Amendment
and that it is in compliance with the requirements
of section 4.02(a);
- 2 -<PAGE>
<PAGE>
(2) that the Lease Amendment has been duly
authorized, executed and delivered by the Company
and United and is the valid and legally binding
obligation of each;
(3) that the Lease Amendment has been duly
authorized or approved or exempted from any
requirements for such authorization or approval,
by any and all governmental authorities whose
authorization, approval or exemption is requisite
to the enforceability of the Lease Amendment, and
specifying by what, if any, officially
authenticated certificates or other documents such
authorization, approval or exemption is or may be
evidenced, or that no authorization, approval or
exemption of any governmental authority is
requisite to the enforceability of the Lease
Amendment;
(4) that the Company's interest in the Lease
Amendment has been subjected to the lien of this
Indenture and is subject to no lien ranking prior
to or on an equality with the lien of this
Indenture; and
(5) that the Lease, as amended by the Lease
Amendment, continues in full force and effect;
(d) the officially authenticated certificates or
other documents evidencing the action by governmental
authorities, if any, specified in such Opinion of
Counsel, or certified copies thereof, or other evidence
satisfactory to the Trustee that such authorization,
approval or exemption, if any, has been granted; and
(e) an Accountant's Certificate, dated not later
than the date of the application for authentication and
delivery of the Bonds, demonstrating that the rentals
provided by the Lease Amendment will be sufficient to
meet the requirements of section 4.02(a).
1.02. Deletion of Section 4.04. Section 4.04 of the Mortgage
Indenture is hereby deleted and shall be of no further force or
effect.
1.03. Amendment of Section 7.02(d). Subparagraph (d) of
Section 7.02 of the Mortgage Indenture, as heretofore amended, is
hereby further amended to read in its entirety as follows:
"(d) in the case of the series of 10.32% First
Mortgage Bonds, Series C, due January 15, 1995, the Trustee shall
apportion to each holder a percentage of the aggregate principal
- 3 -<PAGE>
<PAGE>
amount to be redeemed equal to its percentage of the outstanding
Bonds of such series, provided that after any of the Bonds of
such series have been sold in an offering with respect to which a
registration statement filed under the Securities Act of 1933 was
in effect, then the apportionment provided for in this paragraph
shall not be applicable (and the provisions of paragraph (b)
shall instead be applicable) to the Bonds of the series covered
by such registration statement and any Bonds issued in place of
such Bonds, but the apportionment provided for in this paragraph
(d) shall continue to be applicable to the balance of the Bonds
of the series whether or not held by original owners of the
series."
ARTICLE 2
MISCELLANEOUS PROVISIONS
2.01. Defined Terms. The usage in this Third Supplemental
Mortgage Indenture of terms which are defined in the Mortgage
Indenture is in accordance with the definitions thereof in the
Mortgage Indenture, except where the context clearly otherwise
requires.
2.02. Third Supplemental Mortgage Indenture for Benefit of
Parties and Bondholders Solely. All the covenants and provisions
of this Third Supplemental Mortgage Indenture are and shall be
held to be for the sole and exclusive benefit of the parties
hereto and the holders of the Bonds outstanding under the
Indenture and no others shall have any legal, equitable or other
right, remedy or claim under or by reason of this Third
Supplemental Mortgage Indenture or any covenant, condition or
provision contained herein.
2.03. Rights and Duties under Indenture Not Waived or
Limited By Supplement. Nothing in this Third Supplemental
Mortgage Indenture, expressed or implied, is intended or shall be
construed to waive any right the Trustee might otherwise have
under the Indenture; and nothing herein shall affect or limit the
obligation of the Company to execute and deliver to the Trustee
any instrument of further assurance, or other instrument, which
elsewhere in the Indenture is required to be made to or with the
Trustee.
2.04. Trust Indenture Act to Control. If any provision of
this Third Supplemental Mortgage Indenture limits, qualifies or
conflicts with another provision included in the Indenture which
is required to be included in the Indenture by any of Sections
310-317, inclusive, of the Trust Indenture Act of 1939, as
amended, such required provision shall control.
2.05. Effect of Supplemental Indenture. This Third
Supplemental Mortgage Indenture is executed, shall be construed
- 4 -<PAGE>
<PAGE>
as and is expressly stated to be an indenture supplemental to the
Mortgage Indenture, and shall form a part of the Indenture, and
the Mortgage Indenture, as supplemented and amended by this Third
Supplemental Mortgage Indenture, is hereby confirmed and adopted
by the Company as its obligation.
2.06. Counterparts. This Third Supplemental Mortgage
Indenture may be executed in any number of counterparts, each of
which shall be deemed an original; and such counterparts shall
constitute but one and the same instrument, which shall for all
purposes be sufficiently evidenced by any such original
counterpart.
2.07. Cover, Headings, etc. The cover of this Third
Supplemental Mortgage Indenture and all article and descriptive
headings, and the table of contents and marginal headings and
notes, if any, are inserted for convenience only, and shall not
affect any construction or interpretation hereof.
2.08. Governing Law. This Third Supplemental Mortgage
Indenture shall be deemed to be a contract made under the law of
the State of Connecticut, and for all purposes shall be governed
and construed in accordance with the law of said State.
IN WITNESS WHEREOF, Bridgeport Electric Company has caused
this Third Supplemental Mortgage Indenture to be executed on its
behalf by its President or one of its Vice Presidents and by its
Treasurer or its Assistant Treasurer and its corporate seal to be
hereto affixed and attested by its Secretary or an Assistant
Secretary; and The First National Bank of Boston has caused this
Third Supplemental Mortgage Indenture to be executed on its
behalf and its corporate seal to be affixed by one of its Senior
Account Managers; all as of the date and year above written, but
actually on July 21, 1988.
BRIDGEPORT ELECTRIC COMPANY
(Corporate Seal) By /s/ Robert L. Fiscus
-----------------------
Vice President
and by
/s/ Leon A. Morgan
-----------------------
Secretary-Treasurer
- 5 -<PAGE>
<PAGE>
Attest: /s/ William A. Elder
----------------------
Assistant Secretary
Signed, sealed and delivered on
behalf of BRIDGEPORT ELECTRIC
COMPANY in the presence of:
/s/ Camille C. Costelli
-----------------------
/s/ Susan E. Allen
-----------------------
As Witnesses
THE FIRST NATIONAL BANK OF
BOSTON, TRUSTEE
(Corporate Seal) By /s/ Robert J. Dunn
-----------------------
Senior Account Manager
Signed, sealed and delivered on
behalf of THE FIRST NATIONAL BANK
OF BOSTON in the presence of:
/s/ Thomas F. Tresselt
----------------------
/s/ Donald K. Canby
----------------------
As Witnesses
- 6 -<PAGE>
<PAGE>
<PAGE>
EXHIBIT NO. 10.6e
TWENTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS AGREEMENT, dated as of the 15th day of September, 1992
is entered into by the signatories hereto for the amendment by
them of the New England Power Pool Agreement dated as of
September 1, 1971 (the "NEPOOL Agreement"), as previously amended
or proposed to be amended by twenty-seven (27) amendments, the
most recent of which was dated as of October 1, 1990.
WHEREAS, in response to the factors specified in Section
5.10 of the NEPOOL Agreement regarding election of members of the
Management Committee to serve as an Executive Committee, the
member of the Management Committee representing Public Service
Company of New Hampshire has been elected to serve as a member of
the Executive Committee since the formation of NEPOOL; and
WHEREAS, Northeast Utilities has recently acquired Public Service
Company of New Hampshire, Public Service Company of New Hampshire
has elected to be treated as a single Participant with the other
Entities controlled by Northeast Utilities, and Public Service
Company of New Hampshire is no longer entitled to be separately
represented by a member of the Management Committee; and
WHEREAS, the signatory Participants have determined to amend
the NEPOOL Agreement in the manner specified below in order to
<PAGE>
<PAGE>
reflect the fact that the considerations specified in Section
5.10 for membership on the Executive Committee can now be
satisfied by election of only ten members.
NOW THEREFORE, the signatories hereby agree as follows:
SECTION I
TEXT OF AMENDMENT
-----------------
Section 5.10 of the NEPOOL Agreement is amended to read as
follows:
Election of Executive Committee Members
---------------------------------------
Unless there are less than eleven members of the
Management Committee, the Management Committee, at each
annual meeting, shall elect ten of its members to serve
as an Executive Committee. In electing the Executive
Committee, the Management Committee shall give such
consideration as it shall deem advisable to
qualifications for the office, geographic distribution,
the relative sizes of Participants and the public and
- 2 -<PAGE>
<PAGE>
private sectors of the electric utility industry. Each
member so selected may designate an alternate who is
acceptable to the Management Committee.
SECTION II
EFFECTIVENESS OF AGREEMENT
--------------------------
Following its execution by the requisite number of
Participants, this Agreement, and the amendment provided for
above, shall become effective on December 1, 1992, or on such
later date as the Federal Energy Regulatory Commission shall
provide that such amendment shall become effective.
SECTION III
USAGE OF DEFINED TERMS
----------------------
The usage in this Agreement of terms which are defined in
the NEPOOL Agreement shall be deemed to be in accordance with
the definitions thereof in the NEPOOL Agreement.
- 3 -<PAGE>
<PAGE>
SECTION IV
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
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 thereof, and may be attached to another counterpart of
this Agreement identical in form hereto but having attached to it
one or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a
counterpart signature page to be executed by its duly authorized
representative, as of the 15th day of September, 1992.
- 4 -<PAGE>
<PAGE>
CONFORMED COPY
COUNTERPART SIGNATURE PAGE
TO TWENTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF SEPTEMBER 15, 1992
The NEPOOL Agreement, being dated as of September 1, 1971,
and being previously amended by twenty-seven (27) amendments, the
most recent prior amendment being an amendment dated as of
October 1, 1990.
Asburnham Municipal Light Department
By: /s/ Robert W. Gould
-------------------------
Manager
86 Central Street
Ashburnham, MA 01430
Bangor Hydro-Electric Company
By: /s/ Robert S. Briggs
-------------------------
President and CEO
33 State Street
Bangor, ME 04402-0932
Belmont Municipal Light Department
By: /s/ Timothy L. McCarthy
-------------------------
Acting Manager
450 Concord Avenue
Belmont, MA 02178
Boston Edison Company
By: /s/ Cameron H. Daley
-------------------------
Senior Vice President
800 Boylston Street
Boston, MA 02199
- 5 -<PAGE>
<PAGE>
Boylston Municipal Light Department
By: /s/ H. Bradford White, Jr.
--------------------------
Manager
P.O. Box 560
Boylston, MA 01505
Central Maine Power Company
By: /s/ Donald F. Kelly
-------------------------
Senior Vice President
Edison Drive
Augusta, ME 04336
City of Chicopee Municipal Lighting
Plant
By: /s/ Barry W. Soden
-------------------------
General Manager
725 Front Street
Chicopee, MA 01021-0405
Commonwealth Energy System Companies
Commonwealth Electric Company
Cambridge Electric Light Company
Canal Electric Company
By: /s/ Harold N. Scherer, Jr.
--------------------------
President and CEO
2421 Cranberry Highway
Wareham, MA 02571
Concord Municipal Light Plant
By: /s/ Daniel J. Sack
-------------------------
Superintendent
135 Keyes Road
Concord, MA 01742
Connecticut Mutual Electric Energy
Cooperative
By: /s/ Maurice R. Scully
-------------------------
Executive Director
30 Slott Avenue
Norwich, CT 06360-1526
- 6 -<PAGE>
<PAGE>
Eastern Utilities
By: /s/ Donald G. Pardus
-------------------------
Chairman/CEO
One Liberty Square
Boston, MA 02109
Groton Electric Light Department
By: /s/ Roger H. Beeltje
--------------------------
Manager
P.O. Box 679
Groton, MA 01450
Hingham Municipal Lighting Plant
By: /s/ Joseph R. Spadea, Jr.
--------------------------
General Manager
19 Elm Street
Hingham, MA 02043
Holden Municipal Light Department
By: /s/ Edla Ann Bloom
---------------------------
Director of Electric Services
94 Reservoir Street
Holden, MA 01520
Holyoke Gas & Electric Department
By: /s/ George E. Leary
---------------------------
Manager
70 Suffolk Street
Holyoke, MA 01040
Ipswich Municipal Light Department
By: /s/ Donald R. Stone
----------------------------
Director of Utilities
P.O. Box 151
Ispwich, MA 01938
- 7 -<PAGE>
<PAGE>
Mansfield Municipal Electric Department
By: /s/ John Larch
----------------------------
Manager
50 West Street
Mansfield, MA 02048
Marblehead Municipal Light Department
By: /s/ Richard L. Bailey
----------------------------
General Manager
80 Commercial Street
Marblehead, MA 01945
Merrimac Municipal Light Department
By: /s/ David Vance
----------------------------
Commissioner
2 School Street
Merrimac, MA 01860
Middleton Municipal Electric Department
By: /s/ William E. Kelley
----------------------------
Manager
197 North Main Street
Middleton, MA 01949
The Narragansett Electric Company
By: /s/ Robert L. McCabe
----------------------------
President
280 Melrose Street
Providence, RI 02901
New England Power Company
By: /s/ Jeffrey D. Tranen
----------------------------
Vice President
25 Research Drive
Westborough, MA 01582
- 8 -<PAGE>
<PAGE>
Massachusetts Electric Company
By: /s/ John H. Dickson
----------------------------
President
25 Research Drive
Westborough, MA 01582
Granite State Electric Company
By: /s/ Lydia M. Pastuszek
----------------------------
President
33 West Lebanon Road
Lebanon, New Hampshire
The Connecticut Light and Power Company
By: /s/ Bernard M. Fox
----------------------------
President
P.O. Box 270
Hartford, CT 06141-0270
Western Massachusetts Electric Company
By: /s/ Bernard M. Fox
----------------------------
President
P.O. Box 270
Hartford, CT 06141-0270
Holyoke Water Power Company
By: /s/ Bernard M. Fox
----------------------------
President
P.O. Box 270
Hartford, CT 06141-0270
Holyoke Power and Electric Company
By: /s/ Bernard M. Fox
----------------------------
President
P.O. Box 270
Hartford, CT 06141-0270
- 9 -<PAGE>
<PAGE>
Public Service Company of New Hampshire
By: /s/ Bernard M. Fox
----------------------------
President
P.O. Box 270
Hartford, CT 06141-0270
Pascoag Fire District - Electric
Department
By: /s/ James E. Daniels
---------------------------
Chairman, Operating Committee
55 South Main Street
Pascoag, RI 02859
Princeton Municipal Light Department
By: /s/ Sharon A. Staz
---------------------------
Manager
P.O. Box 247
Princeton, MA 01541-0247
Rowley Municipal Lighting Plant
By: /s/ G. Robert Merry
---------------------------
Manager
47 Summer Street
Rowley, MA 01969
Taunton Municipal Lighting Plant
By: /s/ Joseph M. Blain
----------------------------
General Manager
55 Weir Street
Taunton, MA 02780
The United Illuminating Company
By: /s/ Richard J. Grossi
-----------------------------
Chairman and CEO
157 Church Street
New Haven, CT 06506-0901
- 10 -<PAGE>
<PAGE>
Vermont Electric Power Company, Inc.
By: /s/ Richard W. Mallary
-----------------------------
President
P.O. Box 548
Rutland, VT 05702-0548
Central Vermont Public Service
Corporation
By: /s/ Robert de R. Stein
------------------------------
Vice President
77 Grove Street
Rutland, VT 05701
Citizens Utilities Company
By: /s/ James P. Avery
------------------------------
Vice President
High Ridge Park
Stamford, CT 06905
City of Burlington Electric Dept.
By: /s/ Dale L. Pohlman
-----------------------------
General Manager
585 Pine Street
Burlington, VT 05401
Franklin Electric Light Co.
By: /s/ Hugh H. Gates
-----------------------------
President
P.O. Box 96
Franklin, VT 05457-0096
Green Mountain Power Corporation
By: /s/ John V. Cleary
-----------------------------
President and CEO
P.O. Box 850
S. Burlington, VT 06402
- 11 -<PAGE>
<PAGE>
Rochester Electric Light & Power Company
By: /s/ Thomas Pierce
-----------------------------
President
P.O. Box 6
Rochester, VT 05767
Vermont Marble Company
By: /s/ John M. Mitchell
-----------------------------
President
61 Main Street
Proctor, VT 05765
Vermont Public Power Supply Authority
By: /s/ William J. Gallagher
-----------------------------
General Manager
512 St. George Road
Williston, VT 05495
Village of Hardwick Electric Department
By: /s/ Jack E. Young
-----------------------------
General Manager
Box 516
Hardwick, VT 05843
Village of Ludlow Electric Light
Department
By: /s/ Donald Ellison
-----------------------------
Commissioner, Chairman
P.O. Box 289
Ludlow, VT 05149
Village of Morrisville Water and Light
Department
By: /s/ James C. Fox
------------------------------
Superintendent
18 Portland Street
Morrisville, VT 05661
- 12 -<PAGE>
<PAGE>
Village of Northfield Electric
Department
By: /s/ Kevin O'Donnell
------------------------------
Municipal Manager
26 South Main Street
Northfield, VT 05663
Village of Orleans Electric Department
By: /s/ Slayton R. Marsh
------------------------------
Superintendent
Memorial Square
Orleans, VT 05860
Village of Readsboro Electric Light
Department
By: /s/ Annette Caruso
-------------------------------
Utility Clerk
P.O. Box 247
Readsboro, VT 05350
Wakefield Municipal Light Department
By: /s/ William J. Wallace
-------------------------------
Manager
11 Albion Street
Wakefield, MA 01880
- 13 -<PAGE>
<PAGE>
<PAGE>
EXHIBIT NO. 10.6f
THIRTIETH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS AGREEMENT, dated as of the 1st day of June, 1993 is
entered into by the signatories hereto for the amendment by them
of the New England Power Pool Agreement dated as of September 1,
1971 (the "NEPOOL Agreement"), as previously amended by twenty -
eight (28) amendments, the most recent of which was dated as of
September 15, 1992, and as proposed to be amended by a pending
twenty-ninth amendment dated as of May 1, 1993.
WHEREAS, the signatory Participants propose to amend the
provisions on NEPOOL planning in the NEPOOL Agreement, and to
provide for new categories of Pool-Planned Facilities and Pool-
Planned Purchases and to couple this with a change in the
definition of Pool-Planned Unit to reference only existing Units;
and
WHEREAS, the proposed amendments are intended, among other
things, to facilitate the use of revenue bond financing by
Participants which are Massachusetts municipal utilities, and to
avoid in the future controversies over criteria for the
designation of Pool-Planned Units.
NOW THEREFORE, the signatories hereby agree as follows:
<PAGE>
<PAGE>
SECTION I
AMENDMENTS
----------
Section 1. Amendment of Section 7.12
-------------------------
Section 7.12(j) is amended to read as follows:
(j) coordinating the review of proposed plans of
Participants pursuant to Sections 10.1, 10.4 and
11.1 and coordinating the submission of
recommendations to the Management Committee
regarding such proposed plans;
Section 7.12 is further amended by deleting the "and" at the
end of Subsection (i) and by adding the following new Subsections
at the end of the Section:
(k) to the extent appropriate, enabling the planning
and installation of reliable and economical bulk
power supply and related facilities of NEPOOL by
establishing reasonable criteria, guidelines and
methods relating to the appropriate provisions for
integrated bulk power supply planning and related
facilities on behalf of all the NEPOOL
Participants;
(l) preparing forecasts of the aggregate coincidental
Adjusted Load of the Participants and of the
Annual and Monthly Peaks and the Adjusted Annual
and Monthly Peaks of each of the Participants for
use by the Management Committee in estimating "C"
and "E" for purposes of Section 9.2(a); and
(m) coordinating with neighboring pools, non-
Participants and the regional reliability council
on matters of regional planning and regional
reliability.
- 2 -<PAGE>
<PAGE>
Section 2. Amendment of Section 9.4(a)
---------------------------
Section 9.4(a) is amended to read as follows:
(a) At the conclusion of each Capability Period, the
Operations Committee shall determine whether each
Participant has satisfied its Capability
Responsibility obligation for each month during
such Capability Period. If the minimum monthly
System Capability of a Participant during a month
was less than its Capability Responsibility, the
number of Kilowatts of its deficiency shall be
computed and the Participant shall pay a
Capability Responsibility adjustment charge for
the month computed at the rate prescribed by
Section 9.4(b). For purposes of Sections 9.4(a)
and 9.4(d), the minimum monthly System Capability
of a Participant for a month during a Capability
Period is equal to the sum of (i) the
Participant's lowest System Capability (as
determined without taking into account any
Entitlements in Pool-Planned Facilities initially
placed in commercial operation during the
Capability Period) for any day during the month,
plus (ii) for each Pool-Planned Facility initially
placed in commercial operation during the Period
on or prior to the first day of the third month of
the Period, one-sixth of (A) the amount of the
Participant's Entitlement, if any, in such
Facility times (B) the number of full months
during such period that such Facility was in
commercial operation, subject to the right of the
Participant to elect, by written notice received
by the chairman of the Operations Committee prior
to the end of the Period, not to receive credit
under this clause (ii), plus (iii) for each Pool-
Planned Facility initially placed in commercial
operation during the period on or prior to the
first day of the month and for which no credit was
given under clause (ii), the amount of the
Participant's Entitlement, if any, in such
Facility. Retirements made on the last day of any
month shall not be deducted from System Capability
for that month.
- 3 -<PAGE>
<PAGE>
Section 3. Amendment of Section 10.1
-------------------------
Section 10.1 is amended to.read as follows:
10.1 Recommendation of Additional Facilities
---------------------------------------
The Management Committee shall periodically review
the need for, and shall recommend, additions to
and changes in generating and transmission
facilities of the Participants, or sales to or
purchases of power from Non-Participants, to meet
the reliability standards established by it
pursuant to Section 5.13 and the other objectives
of NEPOOL. In making its review and
recommendations, the Management Committee shall
give due consideration to (i) reports of the
Policy Planning Committee as to any alternatives
proposed by the Policy Planning Committee, and
(ii) such other matters as the Management
Committee deems pertinent.
The Management Committee shall specify the type,
range of capacity, target date for initial
commercial operation and other appropriate
characteristics of recommended facilities.
At least once every three years the Management
Committee shall adopt a ten-year NEPOOL expansion
plan specifying the type and timing of additional
generating units, PTF facilities and other
resources recommended for commercial operation
during the period of the expansion plan.
The Management Committee shall also periodically
review the need for, and shall recommend,
arrangements to meet the reliability standards
established by it pursuant to Section 5.13 and the
other objectives of NEPOOL, under which
Participants, affiliates of Participants or other
persons may effect additions to and changes in
generating and transmission facilities for use by
Participants. Any such facilities shall be
eligible for designation as Pool-Planned
Facilities under Section 11.1.
- 4 -<PAGE>
<PAGE>
Section 4. Amendment of Section 10.6
-------------------------
Section 10.6 is amended to read as follows:
10.6 Increase in Reserves Because of Non-NEPOOL Planned
--------------------------------------------------
Unit or Facility
----------------
If a Participant has at any time an Entitlement in
a generating unit placed in commercial operation
after October 31, 1975, which is not a Pool-
Planned Unit or a Pool-Planned Facility and with
respect to which no significant firm commitments
to manufacturers or constructors were made on or
before November 1, 1971, and as a result of the
character, size or operation of such unit NEPOOL
reserves are required to be increased, such
Participant shall be responsible for providing (at
its expense and, if more than one Participant has
an Entitlement in the unit, in proportion to its
Entitlement in such unit) the required additional
NEPOOL reserves for so long as, and to the extent
that, such increase is required by reason of such
unit, or until such unit is accepted by the
Management Committee as a Pool-Planned Unit or a
Pool-Planned Facility; provided that such
Entitlement shall be included in the Participant's
System Capability for Capability Responsibility
purposes.
Section 5. Amendment of Section 11.1
-------------------------
Section 11.1 is amended to read as follows:
11.1 Pool Access Objectives; Designation of Pool-Planned
---------------------------------------------------
Facilities or Purchases
-----------------------
It is an objective of NEPOOL that each Participant
shall have an appropriate opportunity to meet its
Capability Responsibility from Pool-Planned
Facilities.
It is recognized that in the past Participants
have satisfied their generating needs in various
ways, as sole or joint owners of generating units,
as joint owners of interests in generating
companies, as purchasers from other Participants
- 5 -<PAGE>
<PAGE>
or Non-Participants under Unit Contracts or as
wholesale customers, although some smaller
Participants have indicated a desire to change
their mode of participation in the future by
ceasing to be wholesale customers in whole or
part. It is anticipated that such smaller
Participants and their suppliers will work out
individual arrangements covering the phase-out of
present contracts and that in many cases this may
best be accomplished over a five-to-ten year
period. Furthermore, Participants have
participated in transmission facilities as sole
owners, as joint owners of interests in
transmission companies, or by entering into joint
long-term support arrangements, and it is expected
that this diversity will continue in the future
because of the varying situations of the
Participants. Many of the joint arrangements have
been arranged or facilitated by NEPOOL action, and
it is a continuing objective of NEPOOL to
facilitate, in appropriate circumstances, joint
generation and transmission arrangements through
the designation of Pool-Planned Facilities and
Pool-Planned Purchases.
A Participant which proposes, or whose affiliate
proposes, a joint arrangement for the installation
with other Participants of an additional
generating unit rated 25 MW (gross) or above or a
transmission facility rated 69 kV or above, or for
a purchase jointly with other Participants of a
Unit Contract Entitlement from a Non-Participant
may submit, in such form, manner and detail as the
Management Committee or the Policy Planning
Committee may reasonably prescribe, a request to
the Management Committee to designate the
generating unit or the transmission facility as a
Pool-Planned Facility or the purchase as a Pool-
Planned Purchase, as the case may be. If the
request relates to an additional generating unit
or transmission facility to be installed by the
Participant or its affiliate, the request shall be
submitted at or before the time the Participant's
plan for the facility is submitted pursuant to
Section 10.4. It shall be a condition to the
granting of the requested Pool-Planned status for
a generating unit or purchase that the share of
the unit or purchase which the Participant
proposes to make available for joint participation
- 6 -<PAGE>
<PAGE>
be at least a 25% share and that it be offered
first to all other Participants on a fair and
nondiscriminatory basis, before any offering is
made to Non-Participants.
The Policy Planning Committee shall review the
Participant's proposal to determine its
consistency with NEPOOL objectives and shall
report the results of its review to the Management
Committee. If the Management Committee determines,
on the basis of the Policy Planning Committee's
report and such other information as the
Management Committee deems appropriate, that the
proposal is consistent with NEPOOL objectives and
that the Participant has made the offer of joint
participation contemplated by this Section, if
required, (whether or not such offer has been
accepted by one or more other Participants), it
shall designate the proposed generating unit or
transmission facility as a Pool-Planned Facility,
or shall designate the purchase as a Pool-Planned
Purchase, as the case may be.
Provided the Participant has offered at least 25%
of the capacity to other Participants through
joint ownership or unit contract participation,
the Management Committee may not unreasonably
withhold designation as a Pool-Planned Facility of
a generating unit proposed to be constructed by
one or more Participants in order to satisfy their
anticipated Capability Responsibilities and/or to
provide an appropriate mix of their generating
capabilities if the needs of such Participants in
these regards have not been satisfied from other
units or facilities designated as Pool-Planned on
a basis consistent with the following objectives:
(a) Each Participant should have a reasonable
opportunity to satisfy its load over some
reasonable time period with a mix of
generation reasonably comparable as to
economics and types to that being developed
for New England.
(b) No Participant should be required to subject
itself to an excessively disproportionate
exposure to backup power costs or reserve
obligations as a result of having to take any
Entitlement which is excessively
- 7 -<PAGE>
<PAGE>
disproportionately large as compared to the
Participant's size, or as the result, during
any sustained period, of having to take a
disproportionate portion of its capacity from
immature units.
(c) No Participant which has maintained an
integrated system in the past should be
required to impair the attractiveness of its
securities in the capital markets by making
unreasonably large capital investments in new
generation or by becoming dependent upon
other participants for a substantially
disproportionate amount of its System
Capability.
Section 6. Amendment of Section 15.33
--------------------------
Section 15.33 is amended to read as follows:
15.33 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).
Section 7. Addition of New Section 15.33A
------------------------------
The Agreement is amended by adding new Section 15.33A, as
follows:
15.33A Pool-Planned Facility and Pool-Planned
Purchase are, respectively, (a)(i) a
generating unit or transmission facility
designated as a "Pool-Planned Facility"
pursuant to Section 11.1 or (ii) which was
designated as a "Pool-Planned facility"
pursuant to Section 10.1 prior to January 1,
1993, and (b) a purchase from a Non-
Participant designated by the Management
Committee as a "Pool-Planned Purchase"
pursuant to Section 11.1; provided that a
- 8 -<PAGE>
<PAGE>
"Pool-Planned Purchase" will not be entitled
to transfer rights under Section 13.2(c), but
Section 13.2(c) shall continue to be
effective as to existing and new purchases
from Hydro-Quebec utilizing the HQ
Interconnection.
SECTION II
EFFECTIVENESS OF AGREEMENT
--------------------------
Following its execution by the requisite number of
Participants, this Agreement, and the amendments provided for
above, shall become effective on September 30, 1993, or on such
later date as Federal Energy Regulatory Commission shall provide
that such amendment shall become effective.
SECTION III
USAGE OF DEFINED TERMS
----------------------
The usage in this Agreement of terms which are defined in
the NEPOOL Agreement shall be deemed to be in accordance with the
definitions thereof in the NEPOOL Agreement.
SECTION IV
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
- 9 -<PAGE>
<PAGE>
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 thereof, and may be attached to another counterpart of
this Agreement identical in form one or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a
counterpart signature page to be executed by its duly authorized
representative, as of the 1st day of June, 1993.
- 10 -<PAGE>
<PAGE>
COUNTERPART SIGNATURE PAGE
TO THIRTIETH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF JUNE 1, 1993
The NEPOOL Agreement, being dated as of September 1, 1971,
and being previously amended by twenty-eight (28) amendments
(with a pending twenty-ninth (29) amendment dated as of May 1,
1993), the most recent prior amendment which has become effective
an amendment dated as of September 15, 1992.
Boston Edison Company
By: /s/ Cameron H. Daley
--------------------
Senior Vice President
800 Boylston Street
Boston, MA 02199
Central Maine Power Company
By: /s/ Donald F. Kelly
-------------------
Senior Vice President
Edison Drive
Augusta, Maine 04336
Commonwealth Electric Company for
Cambridge Electric Light
Company
Canal Electric Company
Commonwealth Electric Company
By: /s/ James J. Keane
------------------
Vice President
2421 Cranberry Highway
Wareham, MA 02571
Eastern Utilities Associates Companies
Blackstone Valley Electric Company
Eastern Edison Company,
Montaup Electric Company,
Newport Electric Corporation
By: /s/ Arthur A. Hatch
------------------
Executive Vice President
One Liberty Square
Boston, MA 02109
- 11 -<PAGE>
<PAGE>
The Narragansett Electric Company
By: /s/ Robert L. McCabe
--------------------
President
280 Melrose Street
Providence, RI 02901
New England Electric System Operating
Companies
Granite State Electric Company
By: /s/ Lydia M. Pastuszek
----------------------
President
4 Park Street
Concord, NH 03301-6313
Massachusetts Electric Company
By: /s/ John H. Dickson
-------------------
President
25 Research Drive
Westborough, MA 01582
New England Power Company
By: /s/ Jeffrey D. Tranen
---------------------
President
25 Research Drive
Westborough, MA 01582
Northeast Utilities Companies
The Connecticut Light and
Power Company
Western Massachusetts Electric
Company
Holyoke Water Power Company
Holyoke Power and Electric
Company
By: /s/ Frank P. Sabatino
---------------------
Vice President - Marketing
P.O. Box 270
Hartford, CT 06141-0270
- 12 -<PAGE>
<PAGE>
Public Service Company of New
Hampshire
By: /s/ Frank R. Locke
------------------
President
1000 Elm Street
Manchester, NH 03105
Vermont Electric Power Company,
Inc.
By: /s/ Richard W. Mallary
----------------------
P.O. Box 548
Rutland, VT 05702
Central Vermont Public Service
Corp.
By: /s/ Robert de R. Stein
----------------------
77 Grove Street
Rutland, VT 05701
Vermont Marble Company
By: /s/ John M. Mitchell
--------------------
Executive Vice President
61 Main Street
Proctor, VT 05765
Village of Enosburg Falls Water &
Light Department
By: /s/ Edward Gill de Rubio
------------------------
Manager
Route 4
Enosburg Falls, VT 05450
Village of Hardwick Electric
Department
By: /s/ Jack E. Young
-----------------
General Manager
P.O. Box 516
Hardwick, VT 05843
- 13 -<PAGE>
<PAGE>
Village of Jacksonville
By: /s/ Earle S. Holland
--------------------
President
Box 73
Jacksonville, VT 05342
Village of Morrisville Water &
Light Department
By: /s/ James C. Fox
----------------
Manager/Superintendent
P.O. Box 325
Morrisville, VT 05661
Village of Northfield Electric
Department
By: /s/ Kevin O'Donnell
-------------------
Municipal Manager
26 South Main Street
Northfield, VT 05663
Village of Readsboro Electric
Light Department
By: /s/ Annette Caruso
------------------
P.O. Box 247
Readsboro, VT 05350
Vermont Public Power Supply
Authority
By: /s/ William J. Gallagher
------------------------
General Manager
512 St. George Road
Williston, VT 05495
The United Illuminating Company
By: /s/ Richard J. Grossi
---------------------
Chairman and CEO
157 Church Street
New Haven, CT 06506-0901
- 14 -<PAGE>
<PAGE>
<PAGE>
EXHIBIT NO. 10.11
Fuel Oil Purchase and Sale Agreement
This Agreement is made as of October l, 1993 among Tosco
Corporation ("Tosco"), a Nevada corporation with its principal
place of business at 72 Cummings Point Road, Stamford,
Connecticut (the "Seller"); and, The United Illuminating Company
("UI"), a Connecticut corporation with its principal place of
business at 157 Church Street New Haven, Connecticut, and The
Connecticut Light & Power Company ("CL&P"), a Connecticut
corporation with its principal office at 107 Selden Street,
Berlin, Connecticut. UI and CL&P are hereinafter referred to
collectively as "Buyers", and separately as "Buyer".
WHEREAS, Buyers and Seller intend that this Agreement shall
apply to Seller's supply of No. 6 fuel oil to Buyers, and each
Buyer's separate purchase of No. 6 fuel oil from Seller, during
the Term hereof as hereinafter defined;
NOW THEREFORE, in consideration of the premises and other
valuable consideration, the receipt of which is hereby
acknowledged by the respective parties hereto, the Buyers and
Seller hereby agree as follows:
Article 1 - Term
The term of this Agreement shall be for two (2) years (the
"Term") commencing on October 1, 1993 and expiring on September
30, 1995 and shall automatically renew for one additional
twelve-month period from October 1, 1995 to September 30, 1996
unless any party gives each of the other parties notice of its
desire to terminate the Agreement on or before June 30, 1995
effective at the close of business on September 30, 1995. Each
twelve month period, commencing on October 1 and expiring on
September 30, shall be referred to as a "Contract Year". Each
successive three month period within a Contract Year shall be
referred to as a "Contract Quarter".
Article 2 - Purchase and Sale
a. Seller shall sell and agrees to deliver to Buyers, and each
Buyer agrees to purchase from Seller and pay for an amount of No.
6 fuel oil (the "Product"). This amount shall be 100% of each
Buyer's purchase requirements of No. 6 fuel oil during each
Contract Year, as limited by Article 2.b. However, each Buyer
reserves the right to make "Spot Purchases" of Product. Such
Spot Purchases shall not exceed xx% of Buyers aggregate purchase
requirements in any Contract Year. For purposes of this
Agreement, UI's annual purchase requirements are estimated to be
6,500,000 barrels of Product (1.0% Sulfur maximum by weight);
and, CL&P's annual purchase requirements are estimated to be
6,500,000 barrels of Product (4,000,000 barrels of 1.0% Sulfur
maximum by weight and 2,500,000 barrels of 0.5% Sulfur maximum by
<PAGE>
<PAGE>
weight). Buyers shall provide Seller with a report of purchase
requirements and Spot Purchases each Contract Quarter.
b. If during a Contract Year, Buyers aggregate purchases exceed
14,300,000 barrels, Seller shall be under no obligation to sell
such excess to any Buyer and any Buyer shall be under no
obligation to purchase such excess from Seller.
c. Seller agrees that the ordering notice required of Buyers
under Article 3.d(1) is for Seller's convenience and may, from
time to time, not allow Buyers the necessary coverage because
actual demand often differs from estimated demand. Each Buyer
reserves the right to revise the volumes scheduled under Article
3.d(1), and shall provide Seller the option to meet the revised
schedule. Seller shall respond to Buyer's request for a revised
schedule within 24 hours from receiving notice. If Seller
declines the option to supply Buyer's revised schedule, Buyer
remains obligated, at a minimum, to purchase Product from Seller
at the original schedule. However, if Buyer's revised schedule
was for an increase in volumes, Seller shall allow that Buyer to
procure such Product in the open market. Such purchases will not
be included in that Buyer's Spot Purchases.
d. Notwithstanding Article 2.c, in the event that a Buyer
requires an emergency supply of Product to meet unanticipated
fuel needs at its electric generating stations, Seller agrees
that it will supply such Product within four days of notice, on a
delivered or a FOB point of shipment basis (at Buyers option).
The amount of such Product supplied to Buyers shall not exceed
100,000 barrels during each Contract Quarter. The price of such
additional supply shall be determined as described in Article 4
herein, plus other such documented costs incurred by Seller to
respond to Buyers emergency demand.
e. While the parties intend that the principal purpose of this
agreement is to supply Buyers needs for fuel for their electric
generating stations, Buyers and Seller recognize that there may
be occasions when Buyers will sell fuel hereunder. Buyers and
Seller agree that such sales by Buyers will not exceed x% of
aggregate purchases from Seller. Buyers shall provide Seller
with a report each Contract Quarter.
Article 3 - Quality and Quantity
a. Product Grades
--------------
Grade 0.5/10 - 0.5% Sulfur maximum by weight, 10.0 minimum
API Gravity.
Grade 1.0/10 - 1.0% Sulfur maximum by weight, 10.0 minimum
API Gravity.
Grade 1.0/8 - 1.0% Sulfur maximum by weight, 8.0 minimum API
Gravity.
- 2 -<PAGE>
<PAGE>
b. Quality Specifications
----------------------
Product delivered by Seller to Buyers hereunder shall be
commercially acceptable, not contain any hazardous materials, and
comply with the following quality specifications (subject to the
Product availability provision of Article 3.f):
<TABLE>
Specification Table:
<CAPTION>
ASTM/IP Specification Requirement
------- ------------- -----------
<C> <C> <C>
D-287 API Gravity ("API") 8.0 minimum, or
10.0 minimum
D-4294 Sulfur 0.5% maximum by weight, or
1.0% maximum by weight
D-445(1) Viscosity SSF at
122 Degrees F. 15 minimum - 300 maximum
D-482 Ash - 8.0 API Grade 0.15% maximum
Ash - 10.0 API Grades 0.10% maximum
D-97 Pour point - Degrees F. 15 maximum
D-93 Flash point - Degrees F. 150 minimum
D-95 Water by Distillation 0.5 maximum
D-473 Sediment by Extraction 0.25 maximum
D-1548 Vanadium 200 ppm maximum
IP-377 Aluminum - 8.0 API Grade 175 ppm maximum
Aluminum - 10.0 API Grades 175 ppm maximum per shipment
125 ppm maximum per calendar
month
IP-377 Silicon - 8.0 API Grade 175 ppm maximum
Silicon - 10.0 API Grades 175 ppm maximum per shipment
125 ppm maximum per calendar
month
Oil loading or discharge temperature shall be the greater of
110 Degrees Fahrenheit or 30 Degrees Fahrenheit above Pour
Point. Minimum discharge temperature into UI's Bridgeport
Harbor Terminal shall be 70 Degrees Fahrenheit.
<FN>
Note 1: ASTM D-2161 shall be used to convert kinematic
viscosity test results (ASTM D-445) to Saybolt Furol
Viscosity.
</TABLE>
- 3 -<PAGE>
<PAGE>
c. In-Tank Specifications & Barge Blending
---------------------------------------
Seller will provide a Buyer, upon Buyer's request, any and
all available specifications of in-tank Product quality at the
loadport, and/or on-board Product quality as the case may be for
delivered transactions. In the event Seller anticipates loading
from multiple (two or more) shore tanks, the official Product
quality analysis shall be determined by a barge composite
performed by a mutually agreed upon independent inspector.
d. Deliveries & Delivery Locations
-------------------------------
(1) Delivery Notice
---------------
No later than the first business day of the month preceding
the delivery month, each Buyer shall notify Seller of: (1 ) a
firm volume of purchases, by specific Product grade, for the
following month; (2) for each separate loading, a three day
loading range and volume per load; and, (3) estimated total
purchase volume, by specific Product grade, for the following two
months. Within three business days of such notice, Seller shall
advise each Buyer of points of loading for such volumes. In the
event Seller cannot accommodate a Buyer's request, it should so
state its documentable operational reason for such and the
parties will endeavor to provide a mutually acceptable
alternative. It is the intent of this provision that Seller
shall exercise best efforts to accommodate a Buyer's proposed
schedule because sufficient notice is being given.
(2) Terminals
---------
Except as otherwise provided herein, Product shall be sold
on a FOB point of shipment basis at either one of the following
four terminals: IMTT Terminal, Bayonne, New Jersey ("IMTT");
Bayway Refinery, Bayway, New Jersey ("Bayway"); Tosco's Riverhead
Terminal, Riverhead, Long Island ("Riverhead"); or Seller's
facility, leased from UI, at Bridgeport, Connecticut
("Bridgeport"). Terminal choice is the Seller's option.
Provided that Buyers have nominated a minimum volume of xxxxxxx
barrels per Contract Quarter, then beginning with the first full
Contract Quarter after the completion of the installation of
sparging equipment in tank C or D of UI's Bridgeport terminal
leased to Seller, if the volume of Product delivered to Buyers
from Bridgeport does not reach a minimum volume of xxxxxxx
barrels per Contract Quarter, Buyers, at their option, may
request an increase in the Spot Purchase option and/or a decrease
in the prices for Product under this agreement and, if such
negotiation does not successfully conclude in an increase in the
Spot Purchase option and/or a decrease in the prices for Product
that is acceptable to Buyers, Buyers may elect to terminate this
agreement ninety days after written notification to Seller of
Buyers election to terminate.
- 4 -<PAGE>
<PAGE>
(3) Buyers may load in varying lot sizes and Seller shall
not require Buyers to shift berths, or load at multiple locations
unless Seller agrees to fully compensate the affected Buyer for
its increased freight and inspection charges to accommodate such
a request.
(4) Subject to specific agreement between a Buyer and
Seller, delivery may occur via tank transfer at Bridgeport at the
FOB Bridgeport price.
e. Quantity and Quality Determination
----------------------------------
(1) The quantity and quality of a specific loading or
delivery shall be determined by a mutually agreed to,
independently licensed and certified Petroleum inspector (the
"Inspector"). FOB point of shipment loadings shall be determined
at the loadport. Delivered barges shall be determined at the
discharge port. The costs of the independent inspection and any
laboratory fees shall be shared by Buyers and Seller.
The determination of compliance of each loading or delivery
shall be made after taking a representative composite sample of
the applicable shore tank(s) and loading line(s); or, if
delivered via barge or tank transfer, by a representative
composite sample of the barge and/or transfer tank(s) and loading
lines (if applicable). The Inspector shall be required by the
parties to deliver a certificate setting forth the quality
analysis and quantity of the Product for each shipment of
Product. Buyers and Seller reserve the right to request
supplemental tests from the Inspector at the expense of the party
making such request. If such supplemental tests indicate that
the results fail to meet any of the quality characteristics
specified in Article 3.b, then the provisions of Article 3.e(2)
apply.
The quantity of the Product delivered for FOB point of
shipment loadings shall be ascertained at the loadport by
measurement of a static shore tank(s) from which delivery is made
immediately before and after delivery. For delivered barges,
quantity shall be ascertained at the discharge port by
measurement of Buyer's shore tanks immediately before and after
delivery. In the event the Inspector suspects the shore tank
quantity is in error he/she will notify the Buyer and Seller that
an alternative method based on barge quantity (after adjustment
for bottoms and the barge's vessel experience factor ("VEF"))
will be used. All quantities shall be adjusted to 60 Degrees
Fahrenheit in accordance with Table 6B of ASTM D-1250 Petroleum
Measurement Tables.
(2) If the Inspector certifies that the results fail to
meet any of the quality characteristics specified in Article 3.b,
the Buyer will use its reasonable efforts to accept the shipment
if its receipt is legal under Federal and Connecticut Laws or
- 5 -<PAGE>
<PAGE>
regulations, and its use of such Product will not damage that
Buyer's facilities, equipment or operations. Seller shall
provide a discount to the price for Buyer's role in accepting
such nonconforming fuel oil. The amount of such discount shall
be negotiated by the Buyer and Seller.
If, in the reasonable judgement of the Buyer, after good
faith consultation with the Seller, the non-conforming fuel oil
cannot be corrected in a timely manner or the discount proposed
by Buyer is not agreed to by Seller, Seller at its sole cost and
risk shall promptly remove the non-conforming fuel oil from that
Buyer's barge and/or tank(s) and reimburse that Buyer for its
reasonably incurred costs for the delivery of the nonconforming
fuel oil to that Buyer's facilities or, if in progress, back to
Seller's loading facility.
(3) Buyers and Seller shall have the right to have a
representative present to observe the loading, unloading, and
inspection.
(4) Buyers and Seller shall allow the Inspector reasonable
facility (but not equipment) necessary for sampling, taking
measurements, and temperatures before, during, and after pumping
Product.
f. Product Availability
--------------------
Seller and Buyers acknowledge Seller's primary source of
Grade 1.0/8 fuel oil is low API blend stocks from the Bayway
Refining Company of Tosco Corporation ("Tosco's Bayway
Refinery"), while Grades 1.0/10 and 0.5/10 are readily available
from other sources. Providing Tosco's Bayway Refinery is
operating at a capacity of at least xx% during the delivery
month, Buyers may elect to purchase, and Seller must deliver at
Buyer's option at least xx% of Buyers aggregate 1.0% Sulfur
maximum by weight purchase requirements as Grade 1.0/8. The
minimum volume of Grade 1.0/8 to be delivered, if Buyer so elects
to receive Grade 1.0/8, is xxxxxxx barrels.
In the event Tosco's Bayway Refinery is operating at a
capacity of at least xx% during the delivery month and cannot
make Grade 1.0/8 Product available to Buyers, Seller will supply
Grade 1.0/10, as a replacement, and such Grade 1.0/10 will be
deemed as Grade 1.0/8 for the pricing and Btu per gallon
guarantees contained herein.
In the event Tosco's Bayway Refinery operates at a capacity
lower than xx% during the delivery month, and Seller has no other
source of lower API gravity blend stocks, Seller shall notify
each Buyer forthwith. Any Buyer may then elect either to; (1)
purchase such quantities from other sources, which shall be
included in calculating Buyers xx% minimum purchase requirement
- 6 -<PAGE>
<PAGE>
obligation, or, (2) purchase Grade 1.0/10 from Seller under the
pricing and Btu/gallon guarantee for Grade 1.0/10.
In the event Seller has not declared a Force Majeure
condition, and will not supply a Buyer's requirement(s) of Grade
1.0/10 (including the amount of Grade 1.0/10 that replaces
unavailable Grade 1.0/8) or Grade 0.5/10, and such Buyer must
purchase Product from other sources, such purchases shall be
included when determining a Buyer's xx% minimum purchase
requirement obligation to Seller, and Seller will reimburse Buyer
within ten days of notice thereto for any increased costs of
those purchases versus the pricing herein contained.
g. BTU Guarantee & Credit Adjustment
---------------------------------
The weighted average of the Btu content of fuel delivered
hereunder during each Contract Year shall meet the Btu Guarantee
below.
<TABLE>
<CAPTION>
Fuel Specification BTU Guarantee
------------------ -------------
<C> <C>
Grade 0.5/10 151,500 Btu/gallon
Grade 1.0/10 152,625 Btu/gallon
Grade 1.0/8 154,000 Btu/gallon
</TABLE>
In the event that the weighted average of the BTU content
for a given fuel specification, for each Buyer, is not met during
an applicable Contract Year, the affected Buyer shall be entitled
to a credit determined in accordance with the following:
If the actual weighted average Btu/gallon content for the
most recent Contract Year (including any overages from the
preceding Contract Year) when divided by the guarantees listed in
3.g, is less than 1.0, the difference from 1.0 will be multiplied
times the weighted average purchase price of the specific fuel
type for the same Contract Year. This result will then be
multiplied by the purchase volume of such specific fuel type for
such period to determine the total credit due the affected
Buyer(s). Any and all credits due Buyer(s) will be issued within
thirty days after the end of the Contract Year.
Article 4 - Pricing
a. Purchase Price
--------------
Product prices, in dollars per barrel and rounded to three
decimal places, shall be determined as follows. The xxxxxxxxxx
xxxxxxxx shall mean the xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
- 7 -<PAGE>
<PAGE>
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx posted effective
price for New York Harbor for the applicable Sulfur percent by
weight (typically reported at 5:00 p.m. EST/EDT). xxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx. The loading
date referred to above is the calendar date of the commencement
of loading. Refer to Exhibit 1 for examples of xxxxxxxxxxxxxxx
effective prices used in the xxxxxxxxxxxxxxxxxx pricing formula.
(1) For Grade 0.5/10; the xxxxxxxxxxxxxxxxx of xxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx prices, will
determine the Product price. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx to determine the final
Product price.
(2) For Grade 1.0/10; the Three Day Average of the spot
cargo low 1.0% Sulfur posted effective price will be determine
the final Product price.
(3) For Grade 1.0/8; the Three Day Average of the spot
cargo low 1.0% Sulfur posted effective price will be determine
the Product price. A discount of $0.175 per barrel will be
subtracted from the Three Day Average to determine the final
Product price.
b. Subject to mutual agreement, each Buyer may request Seller
to deliver the Product to its generating stations, providing that
Buyer and Seller agree on a transportation price. Any and all
delivered oil (except for revised schedules under Article 2.c and
emergency supply under Article 2.d herein) shall be requested by
a Buyer at the time the initial volumes are pledged.
c. In the event that Buyer's barges are not presented to Seller
for loading within the agreed three-day window, Seller shall be
entitled to the higher of; the price determined pursuant to
Article 4 herein as if the Barge had commenced loading on the
last day of the three-day window, or, the price determined
pursuant to Article 4 herein on the basis of the day of the
actual commencement of loading.
d. In the event that Seller fails to load a barge nominated by
a Buyer or a Buyer's agent, and providing such Buyer's nomination
is within the agreed three-day window and notice of the
nomination is given two days in advance, Buyer shall be entitled
to be charged by Seller the lower of; the price as determined
pursuant to Article 4 herein as if the barge commenced loading on
the day it was nominated for, or, the price determined pursuant
to Article 4 herein on the day of actual commencement of loading.
For delivered barges, delivered by Seller prior to the three
day range, pricing will be determined under Article 4 herein as
the lower of; the first day of the three day range, or, the day
of commencement of discharge.
- 8 -<PAGE>
<PAGE>
For delivered barges, delivered by Seller after the three
day range, pricing will be determined under Article 4 herein as
the lower of; the last day of the three day range, or, the day of
commencement of discharge.
e. If xxxxxxxxxxxxxxxxxxxxxxxx, then the Buyers and Seller
agree to substitute the comparable effective price xxxxxxxxxxxx
xxxxx during the duration of the non-publication by xxxxxxxx.
f. In the event of a holiday or other calendar day for which
neither xxxxxxxxxxxxxxxxx are published, the prices are to be
selected in accordance with the schedule provide in Exhibit 1,
attached hereto. If xxxxxx does not report a price on any day
used to determine a xxxxxxxxxxxxxxxxxx and xxxxx does report a
price xxxxxxxxxxxxxxxxxxxxxx, the parties agree to substitute the
comparable effective price in xxxxxxxxxxxxxxx for those day(s).
g. Seller shall furnish and each Buyer shall complete and
provide Seller with export certificates or other legally
acceptable evidence that will exempt any sale hereunder from New
York or New Jersey gross receipts taxes payable by Seller, or the
prices hereunder shall be adjusted to account for such tax
liability. Seller shall be responsible for administering all
applicable federal, state taxes and the Connecticut Gross
Receipts Tax (on FOB Connecticut loadings, deliveries or
transfers) which shall be paid to Seller, if applicable, by a
Buyer via a separate line item invoice charge. Regarding FOB New
York or New Jersey loadings, Buyers or their agents, will
administer the Connecticut Gross Receipts Tax. The parties agree
that the pricing described in Article 4 herein include the
following taxes and fees currently in effect for domestic
Product; Import Duty, Superfund Tax, Customs Users Fee, Harbor
Maintenance Tax, Federal Oil Spill Tax, New York and New Jersey
Spill Tax, and OPA 1990 Pollution Spill Coverage of Seller or
Seller's Terminal(s).
Article 5 - Demurrage & Dead Freight
a. Seller shall pay Buyer (within fifteen calendar days of
receipt of documentation from Buyer or Buyer's agent) for
applicable demurrage on all FOB point of shipment loadings,
except those from the Bridgeport Terminal. Demurrage shall be
for tug and barge at Riverhead, and for barge only at IMTT and
Bayonne. Laytime will commence from Notice Of Readiness (NOR)
given by Buyer or Buyer's agent, and end xx hours after,
providing such barge arrives at its scheduled time (or
re-scheduled time as the case may be) as agreed between Seller
and Buyer or Buyer's agent. If barge arrives outside of its
scheduled, or rescheduled, time or if such time(s) are in
dispute, Laytime shall commence when barge is all fast in berth.
b. Buyer shall pay Seller (within xxxxxxx calendar days of
receipt of documentation from Seller) for applicable demurrage on
all delivered loadings.
- 9 -<PAGE>
<PAGE>
c. In the event that, due to the fault of the Seller or its
designated terminal controlling such loading, xx% of the
nominated net barrel volume is not loaded onto Buyers' barge,
Seller shall also be liable for applicable dead-freight (payable
within xxxxxxx calendar days of receipt of documentation from
Buyer or Buyer's agent).
Article 6 - Title
Title to, responsibility for, and risk of loss of the
Product, including but not limited to responsibility for any
Product spills, shall, for FOB point of shipment loadings, pass
from Seller to the respective Buyer when and as the Product
passes that Buyer's outboard flange which is connected to
Seller's outboard fixed flange. For delivered shipments, title
to, responsibility for, and risk of loss of the Product,
including but not limited to responsibility for any Product
spills, shall pass at the first connecting flange connection of
Seller's outboard flange and the respective Buyer's outboard
fixed flange. Responsibility for leakage at the flange
connections mentioned above shall be with the Party making up the
flange.
Article 7 - Payment
Each Buyer shall pay the Seller an amount due calculated by
multiplying the Purchase Price determined in accordance with
Article 4 herein (including any quality credits due the
respective Buyer and/or any transportation costs for delivered
Product) and the Inspector's certified quantity in accordance
with 3.e(1) herein, by telegraphic transfer to a U.S. account
designated by Seller in writing in immediately available U.S.
funds on or before the xxxxx calendar day after delivery of an
invoice to the applicable Buyer.
No Buyer shall act as surety or guarantor for the other
Buyer. Each Buyer is solely responsible for payment of its
obligation to Seller.
Article 8 - Oil Spills & Pollution
Buyers and Seller shall comply with the requirements of the
Oil Pollution Act of 1990 ("OPA-90") for all vessels and/or
facilities, as defined in OPA-90, which pertain to this
Agreement. In the event that Product is spilled, Buyers and
Seller will implement their OPA-90 spill response plan in
accordance with applicable guidelines.
- 10 -<PAGE>
<PAGE>
Article 9 - Force Majeure
"Force Majeure" as used herein shall mean a cause beyond the
control of, and without the fault or negligence of Buyers or
Seller, as the case may be, which wholly or partially prevents
either party from carrying out its obligations under this
Agreement. Examples of "Force Majeure", include but are not
limited to, wars, hostilities, public enemy's actions, sabotage,
blockade, revolution, insurrections, riots, commotions, acts of
God, fire, frost, earthquake, storm, lightening, tidal waves,
tsunamis, perils of the sea, navigational accidents, vessel
damage, accidents, closing of ports, docks, dams, channels,
riverbeds or other marine or navigational aids, epidemics and
quarantines, strikes or agreements among workers, lockouts or
other labor disturbances, explosions or accidents, expropriation,
requisition, confiscation, nationalization, embargo, export or
import restrictions, rationing, declaration of Force Majeure by
or other failure of Seller's suppliers, severe shortage or
unavailability of crude oil or Product of the type to be
delivered hereunder from Seller's existing source of supply, acts
of civil or military governments including such acts as would
prevent storage, blending and burning of Product at Buyers
facilities and any other event of a similar nature or effect.
Economic reasons, such as the price of Product, are not
considered to be valid Force Majeure claims.
A party suffering from a condition of Force Majeure shall
give prompt notice thereof, including the nature of the event,
its anticipated length, the actions taken to relieve the event
and another such other information as is reasonably requested by
the other party. Such notice shall be supplemented from time to
time upon request of the other party.
If because of Force Majeure either Buyers or Seller are
unable to carry out their obligations under this Agreement, the
obligations and liabilities of the party giving such notice and
the corresponding obligations of the other party arising or
occurring after such notice shall be suspended to the extent made
necessary by and during the continuance of such Force Majeure;
provided, however, that the disabling effects of such Force
Majeure shall be eliminated as soon as and to the extent possible
or reasonable, and further provided, however, no party shall be
required to accede to the demands of the labor unions, suppliers
or other third parties that such party, in its discretion, deems
unacceptable.
Any deficiencies in the sale of Product hereunder caused by
Force Majeure shall not be made up except by mutual consent nor
shall the term of this Agreement be extended by Force Majeure.
Buyers shall have the option to purchase Product in the open
market in an amount equal to that which the Seller failed to
supply for reasons of Force Majeure provided such open market
- 11 -<PAGE>
<PAGE>
purchases are made only during the period of such Force Majeure
or to remedy the effects of Force Majeure.
In the event of restricted supply conditions of Product
resulting from Force Majeure affecting Seller, Seller agrees not
to enter new contracts for the supply of Product to electric
generating utilities which it is not then supplying or to make
spot sales of Product to such electric generating utilities
unless it will also be able to supply Buyers contract
requirements hereunder. The provision shall not prevent Seller
from renewing or extending any existing such contract between
Seller and any other electric generating utility at existing
quantity levels.
Article 10 - Notices
Any notice, demand or other communication required to be
sent hereunder shall not be effective unless in writing and hand
delivered, faxed, telexed or mailed certified mail/return receipt
requested, postage pre-paid, to the address, telex or fax number
noted below:
If to Seller, to: Tosco Corporation
72 Cummings Point Road
Stamford, Connecticut 06902
Attn: Wilkes McClave, III
Telephone: (203) 977-1005
Fax (203) 964-3187
and,
Bayway Refining Company
1400 Park Avenue
Linden, New Jersey 07036
Attn: Andrew J. Kelleher
Telephone: (908) 523-5145
Fax (908) 523-5045
If to Buyers, to: The United Illuminating Company
P.O. Box 1564
157 Church Street
New Haven, Connecticut 06506-0901
Attn: Robert W. Lancio
Telephone: (203) 499-2719
Fax (203) 499-3617
- 12 -<PAGE>
<PAGE>
and,
Northeast Utilities Service Company
agent for The Connecticut Light & Power
Company
P.O. Box 270
Hartford, Connecticut 06141
Attn: Mark K. Coulson
Telephone: (203) 665-2503
Fax (203) 665-2383
Notices sent by certified mail shall be deemed to have been
given at the earlier of seven (7) days after the mailing thereof
or date of receipt noted on the return receipt. All other
notices shall be deemed to have been given on the date of receipt
thereof at the designated address, telex or fax number. Any
party may change its address by giving notice of such change in
the manner provided above.
Article 11 - Miscellaneous
a. Assignment
----------
This Agreement shall not be assigned or transferred by
either party hereto without the written consent of the other
parties, which shall not be unreasonably withheld, except that,
1. Seller may assign or transfer to an affiliate (as that term is
defined in the Internal Revenue Code of 1954, as amended and
specifically includes any wholly-owned subsidiaries of TOSCO
Corporation) or to a successor or transferee of all of its
assets, providing such assignee is of equal stature as Seller,
without release of liability hereunder of the party making the
assignment, and 2. Buyers may assign this Agreement to a banking
institution, insurance company or other institutional lender
("Institution") which shall have agreed to maintain Buyers
Product reserves and to supply Product from such reserves to
Buyers. Any such assignment shall contain a provision entitling
Buyers to a reassignment to it of this Contract at any time; and
Buyers covenants and agrees to exercise said right if any of the
Product sold is proposed to be resold by the "Institution" to any
entity other than Buyers. Such assignment shall not relieve the
assignor of its obligations hereunder. Any assignment in
violation hereof shall be void.
b. Separation
----------
In the event Buyers decide that separate agreements with
Seller are desired, Buyers will propose draft language to Seller
for such a separation and Seller will be obligated to meet its
same obligations herein when aggregating the separate Agreements
with the Buyers.
- 13 -<PAGE>
<PAGE>
c. Waiver
------
No waiver by either party of any breach of any of the
covenants or conditions herein contained to be performed by the
other party shall be construed as a waiver of any succeeding
breach of the same or any covenant or condition.d
d. Governing Law
-------------
This Agreement shall be governed by the laws of the State of
Connecticut applicable to agreements made and to be performed in
the State of Connecticut.
e. Binding Effect
--------------
This Agreement shall inure to the benefit of and shall be
binding upon the parties hereto and their respective permitted
successors and assigns.
f. Severability
------------
If any article, phrase, provision or portion of this
Agreement shall, for any reason, be held or adjudged to be
invalid or illegal or unenforceable by any court of competent
jurisdiction, such article, phrase, provision or portion so
adjudged shall be deemed separate distinct and independent and
the remainder of this Agreement shall be and remain in full force
and effect and shall not be invalidated or rendered illegal or
unenforceable or otherwise affected by such adjudication.
g. Counterparts
------------
With the written consent of all parties, this Agreement may
be executed in several counterparts, each of which shall be an
original and all of which shall constitute one and the same
instrument.
h. Confidentiality
---------------
Seller and Buyers agree that each of them will and will
cause their officers, agents and employees to maintain the
confidentiality of and not to disclose to third parties, the
terms and conditions of this agreement (including but not limited
to prices paid and purchase volumes estimated and ordered) unless
disclosure is required by court order. This provision does not
apply to the specifications listed in Article 3.b.
- 14 -<PAGE>
<PAGE>
i. Security
--------
Each Buyer reserves the right at any time during the Term of
this Agreement to require Seller to purchase a performance bond,
or similar security instrument, under Buyer's name which such
Buyer can and will draw down in the event of a material default
of this Agreement by Seller. The value of such performance bond,
or similar security instrument, shall in no event exceed
$4,000,000. Such Buyer will reimburse Seller for the costs of
such security instrument providing such is within acceptable
industry quotations for such instruments.
j. Entire Agreement
----------------
This Agreement constitutes the entire agreement between the
parties hereto relating to the subject matter hereof and shall
completely and fully supersede all other prior understandings or
agreements, both written and oral, between the parties. This
Agreement may be amended, changed, modified or altered only by a
written instrument executed by both parties.
IN WITNESS WHEREOF, the parties hereto have made and executed
this Agreement, signed by their duly authorized officers or
individuals, as of the day and the year first above written.
THE UNITED ILLUMINATING COMPANY, Buyer
By /s/ David W. Hoskinson
----------------------
Title Senior Vice President, Generation-
---------------------------------
Engineering and Operations
--------------------------
Witness: /s/ R.W. Lancio
---------------
NORTHEAST UTILITIES SERVICE COMPANY,
as agent for The Connecticut Light and Power
Company, Buyer
By /s/ Keith R. Marvin
-------------------
Title Vice President, Purchasing and General
--------------------------------------
Services
--------
Witness: /s/ Mary Ann Beatty
-------------------
- 15 -<PAGE>
<PAGE>
TOSCO CORPORATION, Seller
By /s/ Tom O'Malley
----------------
Title President and Chief Executive Officer
-------------------------------------
Witness: /s/ D.F. Lucey
--------------
- 16 -<PAGE>
<PAGE>
<TABLE>
EXHIBIT 1
Three Day Average Purchase Price Examples
<CAPTION>
xxxxxxxxxxxxxxxxxxxxxxxx Product Pricing based on
Loading Date (calendar days) xxxxxxxxxxxxxxxxxxxxxx
Prices Effective for:
Non-Holiday Calendar Day Loadings:
<C> <C> <C>
Monday xxxxxxxxxxx xxxxxxxxxxx
Tuesday xxxxxxxxxxx xxxxxxxxxxx
Wednesday xxxxxxxxxxx xxxxxxxxxxx
Thursday xxxxxxxxxxx xxxxxxxxxxx
Friday xxxxxxxxxxx xxxxxxxxxxx
Saturday xxxxxxxxxxx xxxxxxxxxxx
Sunday xxxxxxxxxxx xxxxxxxxxxx
Holiday Calendar Day Loadings:
Monday-Holiday xxxxxxxxxxx xxxxxxxxxxx
Tuesday-Holiday xxxxxxxxxxx xxxxxxxxxxx
Wednesday-Holiday xxxxxxxxxxx xxxxxxxxxxx
Thursday-Holiday xxxxxxxxxxx xxxxxxxxxxx
Friday-Holiday xxxxxxxxxxx xxxxxxxxxxx
Calendar Day Loading prior to a Holiday:
Thursday before a
Friday Holiday xxxxxxxxxxx xxxxxxxxxxx
Sunday before a
Monday Holiday xxxxxxxxxxx xxxxxxxxxxx
Calendar Day Loading after a Holiday:
Tuesday after a
Monday Holiday xxxxxxxxxxx xxxxxxxxxxx
Saturday after a
Friday Holiday xxxxxxxxxxx xxxxxxxxxxx
</TABLE>
- 17 -<PAGE>
<PAGE>
<PAGE>
EXHIBIT 10.15b
Citibank, N.A. 399 Park Avenue
New York, NY
10043
CITIBANK
January 27, 1994
Ms. Susan Allen
Manager, Finance Administration
United Illuminating Company
157 Church Street
P. O. Box 1564
New Haven, CT 06506-0901
Dear Sue:
Re: United Illuminating $75 Million Revolving Credit Agreement
dated as of January 25, 1993
Citibank has received written notice from all Lenders
participating in the aforementioned Agreement that they are
consenting, pursuant to Section 2.17, to extend their
commitments. The new expiration date of the Agreement will
therefore be January 19, 1995.
Please feel free to call me at (212) 559-1670 with any additional
information you may require.
Sincerely,
/s/ Scott DeGhetto
Scott DeGhetto
<PAGE>
<PAGE>
<PAGE>
EXHIBIT 10.21b
THE UNITED ILLUMINATING COMPANY
1990 STOCK OPTION PLAN
Amendments adopted December 20, 1993
and January 24, 1994
------------------------------------
(1) The second paragraph of Subsection (c) of Section 5 is
amended to provide as follows:
Except as otherwise provided in subsection (d) of
this Section 5, an Optionee may exercise a Stock Option
only (i) if he or she is, and has continuously been
since the date the Stock Option was granted, a full-
time employee of the Company or one of its
Subsidiaries, and (ii) if such Stock Option was granted
in tandem with a dividend equivalent unit under the
Company's 1993 Stock Option Dividend Equivalent
Program, the Company's Board of Directors has confirmed
the dividend equivalent performance results for the
related dividend equivalent Performance Period.
(adopted December 20, 1993)
(2) Subsection (d)(iii) of Section 5 is amended to provide
as follows:
(iii) Upon Voluntary or Involuntary Termination of
Service. Upon a voluntary or involuntary termination
of full-time employment due to any cause other than
death, retirement, disability or termination in
connection with an Optionee's acceptance of full-time
employment by another business entity, such Optionee,
or his or her Successor in Interest, may exercise, in
<PAGE>
<PAGE>
whole or in part: (A) Nonqualified Stock Options exercisable
by such Optionee on the date of termination of his or her
full-time employment, from time to time within five months
after such date; and (B) Incentive Stock Options exercisable
by such Optionee on such date, from time to time within
three months after such date; provided, however, that if an
Optionee is terminated for cause (as determined by the
Administrator), or if an Optionee, at any time after his or
her voluntary or involuntary termination of full-time
employment, engages in any occupation or business that, in
the opinion of the Administrator, is a competitor of the
Company or any of its Subsidiaries, all of such Optionee's
unexercised Stock Options (and any tandem SARs) may be
cancelled by the Administrator.
(adopted January 24, 1994)
- 2 -<PAGE>
<PAGE>
<PAGE>
<TABLE>
EXHIBIT 21
List of Subsidiaries of
The United Illuminating Company
-------------------------------
<CAPTION>
State or Jurisdiction
Name of of incorporation Name under which
Subsidiary or organization Subsidiary does business
- ---------- --------------------- ------------------------
<C> <C> <C>
Bridgeport Electric
Company Delaware Bridgeport Electric Company
Research Center, Inc. Connecticut Research Center, Inc.
United Energy United Energy
International, Inc. Connecticut International, Inc.
United Resources, Inc. Connecticut United Resources, Inc.
Souwestcon Properties,
Inc.* Connecticut Souwestcon Properties, Inc.
Thermal Energies, Inc.* Connecticut Thermal Energies, Inc.
Precision Power, Inc.* Connecticut Precision Power, Inc.
American Payment
Systems, Inc.* Connecticut American Payment Systems, Inc.
Ventana Corporation* Connecticut Ventana Corporation
- ----------------------------
*Subsidiary of United Resources, Inc.
</TABLE>
