Document/Exhibit Description Pages Size
1: 10-K Annual Report Form 10-K 90 517K
2: EX-3.2B Bylaws, Article Ii, Section 2 1 5K
3: EX-3.2C Bylaws, Article V, Section 1 1 6K
8: EX-10.13 Fossil Fuel Supply Agrmt, Dated 7/1/91 35 135K
4: EX-10.2C 1987 Supplementary Power Contract 28 53K
5: EX-10.2D 1996 Amendatory Agreement 17 44K
6: EX-10.2E First Supplement to 1996 Amendatory Agreement 3 9K
7: EX-10.7C 23D Amnd-Jo Ownshp Const & Opr Nh Nuclr Unt 13 23K
9: EX-12 Statement Re: Computation of Ratios 2 13K
10: EX-21 Subsidiaries of United Illuminating 1 6K
11: EX-27 FDS -- 12 Mos. of 1996 1 8K
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, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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COMMISSION FILE NUMBER 1-6788
THE UNITED ILLUMINATING COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
CONNECTICUT 06-0571640
(State or other jurisdiction 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
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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NAME OF EACH EXCHANGE ON
REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED
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The United Illuminating Company Common Stock, no par value New York Stock Exchange
United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange
Securities, Series A (Liquidation
Preference $25 per Security)
(1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3,
1995 by United Capital Funding Partnership L.P., a special purpose limited
partnership in which The United Illuminating Company owns all of the
general partner interests, and are guaranteed by The United Illuminating
Company.
SECURITIES REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE, OF THE UNITED
ILLUMINATING COMPANY
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 1997 was $415,988,085, 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 3, 1997.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 1997, was 14,101,291.
DOCUMENTS INCORPORATED BY REFERENCE
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Document Part of this Form 10-K into which document is incorporated
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DEFINITIVE PROXY STATEMENT, DATED MARCH 27, 1997,
FOR ANNUAL MEETING OF THE SHAREHOLDERS TO BE HELD ON MAY 21, 1997. III
THE UNITED ILLUMINATING COMPANY
FORM 10-K
DECEMBER 31, 1996
TABLE OF CONTENTS
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PAGE
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GLOSSARY 4
PART I.
Item 1. Business. 6
- General 6
- Franchises, Regulation and Competition 6
- Franchises 6
- Regulation 6
- Competition 7
- Rates 8
- Financing 9
- Fuel Supply 11
- Fossil Fuel 11
- Nuclear Fuel 12
- Arrangements with Other Utilities 12
- New England Power Pool 12
- 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
- Capital Expenditure Program 20
- Nuclear Generation 21
- General Considerations 22
- Insurance Requirements 23
- Waste Disposal and Decommissioning 23
Item 3. Legal Proceedings. 25
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. 27
Item 6. Selected Financial Data. 28
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 32
- Major Influences on Financial Condition 32
- Liquidity and Capital Resources 33
- Subsidiary Operations 35
- Results of Operations 36
- Looking Forward for 1997 38
Item 8. Financial Statements and Supplementary Data. 42
- Consolidated Statements for the Years Ended December 31, 1996, 1995 and 1994 42
- Statement of Income 42
- Cash Flows 43
- Balance Sheet 44
- Retained Earnings 46
- Notes to Consolidated Financial Statements 47
- Statement of Accounting Policies 47
- Capitalization 52
- Rate-Related Regulatory Proceedings 57
- Accounting for Phase-in Plan 58
- Income Taxes 59
- Short-Term Credit Arrangements 60
- Supplementary Information 62
- Pension and Other Benefits 63
- Jointly Owned Plant 66
- Unamortized Cancelled Nuclear Project 67
- Fuel Financing Obligations and Other Lease Obligations 67
- Commitments and Contingencies 68
- Capital Expenditure Program 68
- Nuclear Insurance Contingencies 68
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TABLE OF CONTENTS (CONTINUED)
PAGE
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PART II (CONTINUED)
- Other Commitments and Contingencies 69
- Connecticut Yankee 69
- Hydro-Quebec 69
- Voluntary Early Retirement and Separation Programs 69
- Property Taxes 70
- Environmental Concerns 70
- Site Decontamination, Demolition and Remediation Costs 70
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 71
- Property Tax Settlement 72
- Fair Value of Financial Instruments 73
- Quarterly Financial Data (Unaudited) 74
Reports of Independent Accountants 75
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures. 77
PART III
Item 10. Directors and Executive Officers of the Company 77
Item 11. Executive Compensation. 77
Item 12. Security Ownership of Certain Beneficial Owners and Management. 77
Item 13. Certain Relationships and Related Transactions. 77
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 78
Consents of Independent Accountants 85
Signatures 87
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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:
"AFUDC" means allowance for funds used during construction.
"APS" means American Payment Systems, Inc., a wholly-owned subsidiary of
URI.
"the 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
by Connecticut Yankee and located in Haddam Neck, Connecticut.
"DEP" means the Connecticut Department of Environmental Protection.
"DOE" means the United States Department of Energy.
"DPUC" means the Connecticut Department of Public Utility Control.
"EPA" means the United States Environmental Protection Agency.
"FERC" means the United States Federal Energy Regulatory Commission.
"LLW" means low-level radioactive wastes.
"Millstone Unit 3" means the nuclear electric generating unit located in
Waterford, Connecticut, which is jointly owned by UI and twelve other New
England electric utility entities.
"NDFC" means the Nuclear Decommissioning Finance Committee.
"NEPOOL" means the New England Power Pool.
"NOx " means nitrogen oxides.
"NRC" means the United States Nuclear Regulatory Commission.
"NU" means Northeast Utilities.
"PCBs" means polychlorinated biphenyls.
"PPI" means Precision Power, Inc., a wholly-owned subsidiary of URI.
"Preferred Stock" means capital stock of the Company having preferential
dividend and liquidation rights over shares of the Company's other classes
of capital stock.
"RCRA" means the federal Resource Conservation and Recovery Act.
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GLOSSARY (CONTINUED)
"Seabrook Unit 1" means nuclear generating unit No. 1 located in Seabrook,
New Hampshire, which is jointly owned by UI and ten other New England
electric utility entities.
"SO2" means sulfur dioxide.
"SPI" means Souwestcon Properties, Inc., a wholly-owned subsidiary of URI
that has been dissolved.
"TEI" means Thermal Energies, Inc., a wholly-owned subsidiary of URI.
"TSCA" means the federal Toxic Substances Control Act.
"UI" or "the Company" means The United Illuminating Company.
"URI" means United Resources, Inc., a wholly-owned subsidiary of UI.
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PART I
Item 1. Business.
GENERAL
The United Illuminating Company (UI or the Company) is an operating
electric public utility company, incorporated under the laws of the State of
Connecticut in 1899. It is engaged principally in the 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 704,000 or 21% of the population of the State. The service area,
largely urban and suburban in character, includes the principal cities of
Bridgeport (population 137,000) and New Haven (population 124,000) and their
surrounding areas. Situated in the service area are retail trade and service
centers, as well as large and small industries producing a wide variety of
products, including helicopters and other transportation equipment, electrical
equipment, chemicals and pharmaceuticals. Of the Company's 1996 retail electric
revenues, approximately 41% was derived from residential sales, 40% from
commercial sales, 17% from industrial sales and 2% from other sales.
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers. Two other wholly-owned
subsidiaries, United Energy International, Inc. and Research Center, Inc. were
dissolved in April 1996.
Four wholly-owned subsidiaries of URI have been incorporated. A URI
subsidiary named American Payment Systems, Inc. manages a national network of
agents for the processing of bill payments made by customers of other utilities.
Souwestcon Properties, Inc. (SPI) participated as a 25% partner in the ownership
of a medical hotel building in New Haven. The building has been sold; and SPI
was dissolved in April 1996. Another wholly-owned subsidiary of URI, Thermal
Energies, Inc., is participating in the development of district heating and
cooling facilities in the downtown New Haven area, including the energy center
for an office tower and participation as a 62% partner in the energy center for
a city hall and office tower complex. A URI subsidiary named Precision Power,
Inc. provides power-related equipment and services to the owners of commercial
buildings and industrial facilities.
The Board of Directors of the Company has authorized the investment of a
maximum of $27 million, in the aggregate, of the Company's assets in all of
URI's ventures, and, at December 31, 1996, $26 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.
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.
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The location and construction of certain electric facilities is also
subject to regulation by the Connecticut Siting Council (CSC) with respect to
environmental compatibility and public need. See "Environmental Regulation".
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 Atomic
Power Company (Connecticut Yankee), in which the Company has a 9.5% common stock
ownership share, is also subject to this NRC regulatory and supervisory
jurisdiction. See Item 2. Properties - "Nuclear Generation".
The Company is subject to the jurisdiction of the New Hampshire Public
Utilities Commission for limited purposes in connection with its 17.5% ownership
interest in Seabrook Unit 1.
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.
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 that exceeds their owners needs 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. The Company now has 45 multi-year contracts with major
customers, including its largest customer. This customer is constructing a
cogeneration unit that is expected to produce enough electricity, commencing
sometime in early 1998, to supply approximately one-half of the customer's
requirements. The customer's remaining requirements will continue to be supplied
by UI under a special rate and service agreement. To the extent that the Company
loses 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.
See "Rates".
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. Competition in the wholesale power 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 may also increase in the wholesale
power market, as a result of a FERC rulemaking that seeks to promote competition
in that market by requiring electric utilities to furnish non-discriminatory
transmission service to all buyers and sellers in the marketplace, and 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
its rulemaking, the FERC has stressed the importance of allowing electric
utilities to recover the costs of existing facilities (primarily generation)
that would be rendered uneconomic ("stranded") by a competitive bulk power
market. The structure of the wholesale power market will change due to the
implementation of the market provisions of the
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amended NEPOOL agreement, which envisions separate markets for several energy,
capacity, and ancillary services products. See "Arrangements with Other
Utilities".
The FERC has stated that state regulatory commissions should address the
issue of recovery by electric utilities of the costs of existing facilities that
would be stranded by retail access. The legislatures and regulatory commissions
in several states have considered or are considering "retail access". 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 access
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. In 1995, the Connecticut
Legislature established a task force to review these issues and to make
recommendations on electric industry restructuring within Connecticut. The task
force concluded its work in December 1996 and, although no consensus report was
adopted, it is expected that the legislature will enact comprehensive
legislation in its 1997 session to introduce retail access for Connecticut
consumers over the next several years. Among many other factors, decisions and
actions concerning retail access in other states could impact the timing and
form of this transition.
Although the Company is unable to predict the future effects of competitive
forces in the electric utility industry, competition could result in a change in
the regulatory structure of the industry, and costs that have traditionally been
recoverable through the ratemaking process may not be recoverable in the future.
This effect could have a material impact on the financial condition and/or
results of operations of the Company.
In anticipation of increased competition, the Company has initiated a
continuing and focused effort to reduce and control costs, to reinforce customer
loyalty and to develop additional sources of revenue. See "Rates". See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations "Major Influences on Financial Condition" and "Looking Forward for
1997".
RATES
The Company's retail electric service rates are subject to regulation by
the Connecticut Department of Public Utility Control (DPUC).
UI's present general retail rate structure consists of various rate and
service classifications covering residential, commercial, industrial and street
lighting services.
Utilities are entitled by Connecticut law to charge rates that are
sufficient to allow them to cover their operating and capital costs, to attract
needed capital and maintain their financial integrity, while also protecting
relevant public interests.
A Connecticut statute requires the DPUC to review and investigate the
financial and operating records of each electric utility company, at intervals
of not more than four years, to determine whether the company's rates and
services comply with statutory standards. On March 28, 1996, the Company filed
with the DPUC a proposed price stability and incentive regulation plan, together
with the financial and operational data required by this statute. The purpose of
this plan was to address the challenges of an increasingly competitive electric
industry and to help position the Company to meet these challenges. The Company
proposed as part of the plan: to have no increase in base rates charged to
retail customers from January 1997 through December 31, 2001; to afford
customers additional price stability during this period by modifying the
operation of the fossil fuel adjustment clause mechanism in retail rates so that
customers could expect that reasonable changes in fossil fuel prices would not
affect their bills; to depreciate the Company's Seabrook Unit 1 plant investment
more rapidly during this period; to establish a performance-based regulation
mechanism in which performance would be measured by customer satisfaction and
reliability of service; and to establish a minimum and maximum return on common
equity.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997-2001. The DPUC did not change the retail base rates charged
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to customers. Its order increased amortization of the Company's conservation and
load management program investments during 1997-1998, accelerated the recovery
of unspecified regulatory assets during 1999-2001, reduced the level of
conservation adjustment mechanism revenues in retail rates, provided a reduction
in customer bills through a surcredit in each of the five plan years, and
accepted the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on common equity was reduced
from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer bill reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. The DPUC
did not order the accelerated depreciation of the Company's Seabrook Unit 1
plant investment costs and the establishment of a performance-based regulation
mechanism measured by customer satisfaction surveys and reliability of service
indices, which the Company had proposed. As a result of the DPUC's order,
customer bills are expected to be reduced on average by 3% in 1997-1999, 4% in
the year 2000, and 5% in the year 2001 (all compared to 1996).
FINANCING
The Company's capital requirements are presently projected as follows:
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1997 1998 1999 2000 2001
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(MILLIONS)
Cash on Hand - Beginning of Year $6.4 $18.5 $ - $ - $ -
Internally Generated Funds (less Dividends) 95.0 115.8 116.9 110.6 107.5
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Subtotal 101.4 134.3 116.9 110.6 107.5
Less:
Capital Expenditures 50.5 51.2 47.3 43.5 36.5
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Cash Available to pay Debt Maturities and Redemptions 50.9 83.1 69.6 67.1 71.0
Less:
Maturities and Mandatory Redemptions 10.8 104.6 105.0 155.5 81.0
Optional Redemptions 21.6 - - - -
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External Financing Requirements $(18.5) $21.5 $35.4 $88.4 $10.0
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Note: Internally Generated Funds (less Dividends), Capital Expenditures and
External Financing Requirements are estimates based on current earnings
and cash flow projections and are subject to change due to future events
and conditions that may be substantially different from those used in
developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
common stock, preferred stock and additional short-term and long-term debt. The
continued availability of these methods of financing will be dependent on many
factors, including conditions in the securities markets, economic conditions,
and the level of the Company's income and cash flow.
On February 15, 1996, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric
Company, a wholly-owned subsidiary of the Company that was merged with and into
the Company in September 1994.
On June 26, 1996, the Company borrowed $7.5 million from the Connecticut
Development Authority (CDA), representing the proceeds from the issuance by the
CDA of $7.5 million principal amount of tax-exempt Pollution Control Revenue
Bonds (PCRBs). The Company is obligated, under its borrowing agreement with the
CDA, to pay to a trustee for the PCRBs' bondholders such amounts as will pay,
when due, the principal of and the premium, if any, and interest on the PCRBs.
The PCRBs will mature in 2026, and their interest rate can be adjusted
periodically to reflect prevailing market conditions. The PCRBs were issued at
an initial interest rate of 3.3%, which is being adjusted
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weekly. On July 15, 1996, the Company used the proceeds of this $7.5 million
borrowing to cause the redemption and repayment of $7.5 million principal amount
of 9 1/2% PCRBs issued by the CDA in 1986.
On October 25, 1996, the Company borrowed $75 million under a Term Loan
Agreement with a group of banks for a five-year period. The Company pays
interest on the borrowing at a floating rate equal to the three-month London
Interbank Borrowing Rate plus 0.55%. The Company has entered into two separate
interest rate swap agreements that effectively convert the interest rate on $50
million of the Company's floating rate 1996 Term Loan to a fixed annual interest
rate of 7.005% for the five-year period and the interest rate on the remaining
$25 million to a fixed annual interest rate of 6.675% for a three-year period.
The Company used proceeds from the $75 million Term Loan borrowing to
purchase approximately $66.8 million principal amount of Seabrook Lease
Obligation Bonds, which were issued in connection with the sale and leaseback by
the Company of a portion of its ownership share in Seabrook Unit 1 in 1990. The
Bonds were purchased at a premium through a tender offer that expired on October
22, 1996. The Company paid 103.9% of principal amount for approximately $17.0
million principal amount of 9.76% Seabrook Lease Obligation Bonds (due 2006) and
107.17% of principal amount for approximately $49.9 million principal amount of
the 10.24% Seabrook Lease Obligation Bonds (due 2020). The premiums and other
transaction expenses will be amortized over the remaining life of the Bonds. The
Company intends to hold the Bonds until maturity and has recognized the
investment as an offset to long-term debt on its Consolidated Balance Sheet.
On June 4, 1996, June 7, 1996 and August 8, 1996, the Company purchased at
a discount in the open market, and canceled, 60,782 shares of its $100 par value
Preferred Stock. The shares purchased consisted of 9,950 shares of its 4.35%,
Series A, 12,832 shares of its 4.72%, Series B, and 38,000 shares of its 5 5/8%,
Series D, Preferred Stock. The shares, having a par value of $6,078,200, were
purchased for $4,238,387, creating a net gain of $1,839,813.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 10, 1997. 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, 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, 1996, the Company had no short-term borrowings outstanding under this
facility.
On December 30, 1996, the Company transferred $51.3 million to a trustee
under an escrow agreement. The funds, which were invested in Treasury Notes,
were used to pay $50 million principal amount of 7% Notes that matured on
January 15, 1997 plus accrued interest.
On February 15, 1997, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of
$185,328, the remaining $21.6 million outstanding principal amount of 9.44%
First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a
wholly-owned subsidiary of the Company that was merged with and into the Company
in September 1994.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1996, this coverage ratio was 2.78.
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 annual dividends on all Preferred Stock to be outstanding. The
Preferred Stock provisions also prohibit any increase in
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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, 1996 are set forth below.
PREFERRED STOCK SEABROOK LEASE
PROVISIONS PROVISIONS
------------------------- -----------------
PREFERRED LONG-TERM EARNINGS/INTEREST
YEAR STOCK INDEBTEDNESS RATIO
---- --------- ------------ -----------------
1992 3.23 3.88 2.41
1993 3.33 3.67 2.59
1994 2.72 3.14 2.86
1995 2.68 2.71 3.31
1996 2.38 2.39 2.78
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. As of December 31, 1996, the
Company's guarantee liability for this debt amounted to approximately $8.1
million.
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 1996, approximately
925,300 tons of coal, 3.0 million barrels of fuel oil and 1.9 billion cubic feet
of natural gas were consumed in the generation of electricity. The Company owns
fuel oil storage tanks at its 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, through an inventory
finance arrangement, an approximate 45-day coal supply of 157,000 tons at its
Bridgeport Harbor Station.
The Company burns coal at the largest generating unit at its Bridgeport
generating station; however this generating unit is also capable of burning oil.
The Company has a coal supply contract that extends until July 31, 2007, subject
to earlier termination provisions, and fuel oil supply contracts for its New
Haven and Bridgeport generating stations that expire on September 30, 1997.
The Company's New Haven Harbor Station has a dual-fuel capability of
burning natural gas and oil. Under an agreement that expires on December 31,
2000, the Company is obligated to burn approximately 6 billion cubic feet of gas
per year, when offered by the supplier at a price that is competitive with oil.
During 1996, approximately 0.3 billion cubic feet of natural gas was purchased
pursuant to this agreement; and an additional 1.6 billion cubic feet of natural
gas was purchased on the spot market.
- 11 -
NUCLEAR FUEL
The Company holds an ownership and leasehold interest in Seabrook Unit 1
and an ownership interest in Millstone Unit 3, both of which are nuclear-fueled
generating units. Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to uranium concentrates, the
conversion of uranium concentrates to uranium hexafluoride, enrichment of that
gas and fabrication of the enriched hexafluoride into usable fuel assemblies.
After a region (approximately 1/3 to 1/2 of the nuclear fuel assemblies in
the reactor at any time) of spent fuel is removed from a nuclear reactor, it is
placed in temporary storage in a spent fuel pool at the nuclear station for
cooling and ultimately is expected to be transported to a permanent storage
site, which has yet to be determined. See Item 2. Properties - "Nuclear
Generation".
Based on information furnished by the utility responsible for the operation
of the units in which the Company is participating, there are outstanding
contracts that cover uranium concentrate purchases for Millstone Unit 3 through
2000 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:
CONVERSION TO
HEXAFLUORIDE ENRICHMENT FABRICATION
------------- ---------- -----------
Millstone Unit 3 2003 2002 2011
Seabrook Unit 1 2002 2002 2007
ARRANGEMENTS WITH OTHER UTILITIES
NEW ENGLAND POWER POOL
The Company, in cooperation with other privately and publicly owned New
England electric utilities, established the New England Power Pool (NEPOOL) in
1971. NEPOOL was formed to assure reliable operation of the bulk power system in
the most economic manner for the region. It has achieved these objectives
through central dispatching of all generation facilities owned by its members
and through coordination of the activities of the members that can have
significant inter-utility impacts. NEPOOL is governed by an agreement that is
filed with the Federal Energy Regulatory Commission (FERC) and its provisions
are subject to continuing FERC jurisdiction. Under the terms of the NEPOOL
Agreement, the Company incurs certain obligations - such as the responsibility
to support a specified amount of power supply resources - and enjoys certain
benefits, most notably savings in the cost of its overall energy supply and the
sharing of reserve generating capacity.
Because of evolving industry-wide changes that are being driven by
deregulation efforts and by customers' desires to be able to choose from among
competing electricity suppliers, the NEPOOL Agreement is being restructured. Its
membership provisions have been broadened to cover all entities engaged in the
electricity business in New England, including power marketers and brokers,
independent power producers and load aggregators. Operation of the regional bulk
power system will be turned over to an independent corporate entity, so that
there will be no opportunity for conflicting financial interests between the
system operator and the market-driven participants. Various energy and capacity
products will be traded in open, competitive markets, with transmission access
and pricing subject to a regional tariff designed to promote competition among
power suppliers. The proposed restructuring changes have been filed with FERC as
an amendment to the NEPOOL Agreement, and the resulting FERC proceedings are
expected to take place in stages over the first two or three quarters of 1997.
Under other agreements related to the Company's participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to
the financial support of certain 345 kilovolt transmission facilities that are a
part of the New England transmission grid.
- 12 -
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, increased the capacity value of the
intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A ten-year
Firm Energy Contract, which provides for the sale of 7 million megawatt-hours
per year by Hydro-Quebec to the New England participants in the Phase II
facility, became effective on July 1, 1991. The Company is obligated to furnish
a guarantee for its participating share of the debt financing for the Phase II
facility. As of December 31, 1996, the Company's guarantee liability for this
debt was approximately $8.1 million.
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 discharge permits for the Company's
Bridgeport Harbor, English, Steel Point and New Haven Harbor Stations expired in
February, May and March of 1992, and September of 1996, respectively.
Applications for renewal of these permits had been filed in August, November and
September of 1991, and April of 1996, respectively, and while these renewal
applications are pending, the terms of the expired permits continue in effect.
The application for English Station has been modified to reflect changes in the
operating status of this generating facility and changes in the permitting
system; and in November 1995 UI withdrew the application for Steel Point Station
as a result of the demolition of the decommissioned generating units at that
location. Several new permits have been issued for specific discharges at New
Haven Harbor, Bridgeport Harbor and/or English Stations; and, although other new
permits for specific discharges have not yet been issued, the Company has not
been advised by the DEP that any of these facilities has a permitting problem.
The DEP has determined that the thermal component of the discharges at each of
the stations will not result in a violation of state water quality standards.
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 has necessitated substantial
capital and operational expenditures by UI, and it is expected that such
expenditures will continue to be required in the future.
Under the federal Clean Air Act, the federal Environmental Protection
Agency (EPA) has promulgated national primary and secondary air quality
standards for certain air pollutants, including sulfur oxides, particulate
matter, ozone 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 cause or contribute to any 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
- 13 -
to hold sufficient allowances each year to cover the emissions of SO2 from the
unit during that year. Allowances are transferable and can 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 (NOx) that are applicable to generating units
located in or near areas, such as UI's service territory, where ambient air
quality standards for photochemical oxidants have not been attained. These
amendments also require the installation and/or modification of continuous
emission monitoring systems, and require all existing generating units to obtain
operating permits. Controls installed have resulted in achievement of NOx
emissions from Bridgeport Harbor Unit 3, the largest generating unit at
Bridgeport Harbor Station, substantially below, and at a date significantly in
advance of, that required under the statute. As a result, the DEP has approved
UI's creation of transferable and marketable NOx emission reduction credits, and
supplemental approvals are anticipated for the creation of additional credits at
this generating unit through April 1999. During 1996, UI consummated twelve
sales of NOx emission reduction credits, and it continues to market these
credits. These sales have not had a significant impact on the Company's
earnings. In September 1994, the Ozone Transport Commission (consisting of the
twelve northeastern-most states plus the District of Columbia) adopted a
Memorandum of Understanding (MOU) that obligates certain of those states,
including Connecticut, to adopt regulations that will further limit emissions of
NOx from large stationary sources, including utility boilers. The MOU calls for
the reductions to occur in two steps; the first in 1999 and the second in 2003.
It is expected that the regulations, when promulgated, will become part of the
federally mandated revisions to Connecticut's plan for achieving compliance with
air quality standards for photochemical oxidants. On December 13, 1996, the EPA
published proposed changes to the national air quality standards for ozone and
particulate matter and stated its intent to promulgate final standards for these
pollutants during June of 1997. On January 10, 1997, the EPA published a notice
of intent to require states to adopt regulations to ensure that a significant
transport of ozone pollution across state boundaries in the eastern United
States is prevented. Since none of these three sets of new regulations have been
promulgated, the Company is not yet able to assess accurately the applicability
and impact of implementing these 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 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.
- 14 -
Although the scope of the remediation and the extent of UI's participation have
not yet been fully determined, in 1990 the owners of the property estimated the
total remediation cost to be immaterial.
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. UI's Bridgeport Harbor and New
Haven Harbor Stations have been registered as treatment, storage and disposal
facilities, because of historic solid waste management activities at these
sites. The Company has ceased using these sites for any of these purposes and
has filed facility closure plans with the DEP; but further corrective actions
may be required at one or more of them for documented or potential releases of
hazardous wastes. Because regulations for such corrective actions have not yet
been promulgated, the Company is unable to predict what impact, if any, such
regulations may have on these facilities.
The Company has estimated that the total cost of decontaminating and
demolishing its decommissioned and demolished Steel Point Station and completing
requisite environmental remediation of the site will be approximately $11.3
million, of which approximately $7.7 million had been incurred as of December
31, 1996, and that the value of the property following remediation will not
exceed $6.0 million. As a result of a 1992 DPUC retail rate decision, beginning
January 1, 1993, the Company has been recovering through retail rates $1.075
million of these remediation costs per year. The remediation cost, property
value and recovery from customers will be subject to true-up in the Company's
next retail rate proceeding based on actual remediation costs and actual gain on
the Company's disposition of the property.
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 15
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 modify, remove and/or replace older tanks in compliance
with federal and state regulations.
In the past, the Company has disposed of residues from operations at
landfills, as most other industries have done. In recent years it has been
determined that such disposal practices, under certain circumstances, can cause
groundwater contamination. Although the Company has no knowledge of the
existence of any such contamination, if the Company or regulatory agencies
determine that remedial actions must be taken in relation to past disposal
practices, the Company may experience substantial costs.
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.
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.
- 15 -
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 total
amount of these expenditures is not now determinable. See also "Franchises,
Regulation and Competition" and Item 2. Properties "Nuclear Generation".
EMPLOYEES
As of December 31, 1996, the Company had 1,287 employees, including 75 in
subsidiary operations. Of these, approximately 71% had been with the Company for
10 or more years.
Approximately 603 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 22, 1995, the Company and
the union agreed on a three-year contract, effective May 16, 1995. There has
been no work stoppage due to labor disagreements since 1966, other than a strike
of three days duration in May 1985; and employee relations are considered
satisfactory by the Company.
- 16 -
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1996,
based on summer ratings of the generating units, was as follows:
[Enlarge/Download Table]
YEAR OF MAX CLAIMED UI
UI OPERATED: FUEL INSTALLATION CAPABILITY, MW ENTITLEMENT
----------- ---- ------------ -------------- -----------
% Mw
Bridgeport Harbor Station 1 #6 Oil 1957 80.76 100.00 80.76(1)
Bridgeport Harbor Station 2 #6 Oil 1961 155.01 100.00 155.01
Bridgeport Harbor Station 3 #6 Oil/Coal 1968/1985 385.00 100.00 385.00(2)
Bridgeport Harbor Station 4 Jet Oil 1967 16.15 100.00 16.15
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:
---------------------------
Millstone Unit 3, Nuclear 1986 1119.60 3.685 41.26(5)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1162.00 17.50 203.35(6)
Seabrook, New Hampshire
POWER PURCHASES FROM
COGENERATION FACILITIES:
-----------------------
Bridgeport RESCO, Refuse 1988 59.45 100.00 59.45
Bridgeport, Connecticut
Shelton Landfill Gas 1995 1.74 100.00 1.74
Shelton, Connecticut -----
Total 1434.13
=======
(1) Effective January 1, 1994, Bridgeport Harbor Station 1 was removed from
operation and dispatching under NEPOOL and was placed in deactivated
reserve. The unit was reactivated in July 1996 and placed under NEPOOL
dispatch to help alleviate power shortages in Connecticut caused by the
outages of the three nuclear generating units at Millstone Station and the
Connecticut Yankee Unit. See "Nuclear Generation".
(2) The unit has burned coal since January 1985.
(3) Represents UI's 93.705% ownership share of total net capability. 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
(1.795%). 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 3.685% ownership share of total net capability.
(6) 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.
- 17 -
[Enlarge/Download Table]
TABULATION OF PEAK LOADS, RESOURCES, AND MARGINS
1996 ACTUAL, 1997 - 2001 FORECAST
(MEGAWATTS)
Actual Forecast
------ -------------------------------------------------
1996 1997 1998 1999 2000 2001
At Time of Peak Load on UI's System:
-----------------------------------
Capacity of generating units operated
by UI (1) 1065.90 1055.87 1055.87 1055.87 1055.87 1055.87
-------------------------------------
Entitlements in nuclear units (1) (2)
-----------------------------
Connecticut Yankee Unit (3) 53.21 0.00 0.00 0.00 0.00 0.00
Millstone Unit 3 41.26 41.26 41.26 41.26 41.26 41.26
Seabrook Unit 1 203.35 203.35 203.35 203.35 203.35 203.35
------ ------ ------ ------ ------ ------
297.82 244.61 244.61 244.61 244.61 244.61
------ ------ ------ ------ ------ ------
Equivalent capacity value of
entitlement in Hydro-Quebec (1) (2) 98.10 98.10 98.10 98.10 98.10 98.10
----------------------------
Purchases from cogeneration facilities
--------------------------------------
Bridgeport RESCO 59.45 59.45 59.45 59.45 59.45 59.45
Shelton Landfill 1.74 1.61 1.50 1.57 1.54 1.36
Purchase from New York Power Authority 1.14 1.14 1.14 1.14 1.14 1.14
--------------------------------------
Purchases from (sales to) other utilities
-----------------------------------------
Net power contracts - fossil (1.80) 8.20 38.20 38.20 (30.00) (30.00)
------- ------- ------- ------- ------- -------
Total generating resources 1522.35 1468.98 1498.87 1498.94 1430.71 1430.53
======= ======= ======= ======= ======= =======
Calculation of NEPOOL capability
responsibility (4)
--------------------------------
Peak load 1045.00 1151.00 1155.00 1171.00 1192.00 1200.00
Required reserve margin 322.39 249.91 266.99 278.25 282.11 340.59
------- ------- ------- ------- ------- -------
Total capability responsibility 1367.39 1400.91 1421.99 1449.25 1474.11 1540.59
======= ======= ======= ======= ======= =======
Available Margin (5) 152.08 65.32 74.24 46.98 (46.08) (112.56)
======= ======= ======= ======= ======= =======
(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):
Millstone Unit 3 - 42.22
Seabrook Unit 1 - 203.35
Hydro-Quebec - 66.22
(3) On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company voted to retire the Connecticut Yankee Unit from
commercial operation. See "Nuclear Generation".
(4) UI's required capacity as a NEPOOL participant.
(5) Total generating resources, excluding purchases from New York Power
Authority and Shelton Landfill, less capability responsibility. In
addition, UI maintains two units (English Station 7 and 8) in deactivated
reserve, representing a total of 72.55 MW of generating capacity.
- 18 -
During 1996, the peak load on the Company's system was approximately 1,045
megawatts, which occurred in July. UI's total generating capability at the time
was 1,522 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 an annual
average compound growth in peak load of 1.7% during the period 1996 to 2006
(0.8% during the 1997-2006 period). Based on current forecasts of loads, UI's
generating capability will exceed its projected July-August capability
responsibility to NEPOOL for generating capacity through at least 1999, and
English Station Units 7 and 8 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 or from the installed capability spot
market, 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 the region's generation and transmission systems to meet the
region's load. See "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 1996.
[Enlarge/Download Table]
MEGAWATTHOURS
-------------
(000's)
SOURCES USES
------- ----
OWNED Retail Customers 5,340
Nuclear (Millstone Unit 3 and Seabrook Unit 1) 1,814
Coal 2,410 Wholesale
Oil 1,792 Delivered to NEPOOL 817
Gas & Gas Turbines 181 Contracts 1,731
-----
Total Owned 6,197
Company Use & Losses 301
-----
PURCHASED
Nuclear (Connecticut Yankee Unit) 263 Total Uses 8,189
Contracts 1,011 =====
NEPOOL 430
Hydro-Quebec 288
-----
Total Sources 8,189
=====
TRANSMISSION AND DISTRIBUTION PLANT
The transmission lines of the Company consist of approximately 102 circuit
miles of overhead lines and approximately 17 circuit miles of underground lines,
all operated at 345 KV or 115 KV and located within or 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 24 bulk electric supply substations with a
capacity of 2,656,000 KVA and 42 distribution substations with a capacity of
232,500 KVA. The Company has 3,125 pole-line miles of overhead distribution
lines and 130 conduit-bank miles of underground distribution lines.
See "Capital Expenditure Program" concerning the estimated cost of
additions to the Company's transmission and distribution facilities.
- 19 -
CAPITAL EXPENDITURE PROGRAM
The Company's 1997-2001 capital expenditure program, excluding allowance
for funds used during construction (AFUDC) and its effect on certain capital
related items, is presently budgeted as follows:
[Enlarge/Download Table]
1997 1998 1999 2000 2001 Total
---- ---- ---- ---- ---- -----
(000's)
Production $18,137 $20,026 $28,363 $12,241 $19,062 $97,829
Distribution 13,207 11,961 11,992 12,870 13,113 63,143
Transmission 4,430 2,520 4,491 4,736 2,515 18,692
Other 6,813 5,387 1,245 1,296 1,239 15,980
------- ------- ------- ------- ------ -------
SUBTOTAL 42,587 39,894 46,091 31,143 35,929 195,644
Nuclear Fuel 7,891 11,282 1,200 12,323 529 33,225
------- ------- ------- ------- ------ -------
TOTAL EXPENDITURES $50,478 $51,176 $47,291 $43,466 $36,458 $228,869
======= ======= ======= ======= ======= =======
AFUDC (Pre-tax) 2,314 2,096 2,431 1,886 1,230
Depreciation
Book Plant 55,486 57,737 59,295 52,297 52,996
Conservation 10,223 10,223 8,906 6,312 4,332
Decommissioning 2,238 2,328 2,435 2,547 2,660
Additional Required
Amortization (net of tax) (1) 4,100 8,500 11,600 29,700 32,800
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after tax) 12,586 12,586 12,586 0 0
Estimated Rate Base
(end of period) 1,173,607 1,124,299 1,057,428 1,014,621 940,764
(1) Additional amortization of pre-1997 conservation costs and other
unspecified regulatory assets, as ordered by the DPUC in its December 31,
1996 Order, provided that common equity return on utility investment
exceeds 10.5%. See Item 1. Business - "Rates".
- 20 -
NUCLEAR GENERATION
UI holds ownership and leasehold interests totalling 17.5% (203.35
megawatts) in Seabrook Unit 1, and a 3.685% (41.26 megawatts) ownership interest
in Millstone Unit 3. UI also owns 9.5% of the common stock of Connecticut
Yankee, and was entitled to an equivalent percentage (53.21 megawatts) of the
generating capability of the Connecticut Yankee Unit prior to its retirement
from commercial operation on December 4, 1996.
Seabrook Unit 1 commenced commercial operation in June of 1990, pursuant to
an operating license issued by the NRC, which will expire in 2026. It is jointly
owned by eleven New England electric utility entities, including the Company,
and is operated by a service company subsidiary of Northeast Utilities (NU).
Through December 31, 1996, Seabrook Unit 1 has operated at a lifetime capacity
factor of 79.7%.
Millstone Unit 3 commenced commercial operation in April of 1986, pursuant
to a 40-year operating license issued by the NRC. It is jointly owned by
thirteen New England electric utility entities, including the Company, and is
operated by another service company subsidiary of NU. Through March 30, 1996,
when Millstone Unit 3 was taken out of service following an engineering
evaluation that determined that four safety-related valves would not be able to
perform their design function during certain postulated events, Millstone Unit 3
had operated at a lifetime capacity factor of 71.9%. In April, May and June of
1996, a series of NRC letters to NU and its operating service company subsidiary
stated: that the NRC had identified programmatic issues and design deficiencies
at Millstone Unit 3 that were similar in nature to those previously identified
at Millstone Units 1 and 2, the two other Millstone Station nuclear generating
units, which had been taken out of service in November of 1995 and February of
1996, respectively, and are owned by operating subsidiaries of NU and are also
operated by the NU service company subsidiary that operates Millstone Unit 3;
that the NRC had concluded that the corrective action program at Millstone
Station was not currently effective in resolving identified deficiencies; that
none of the generating units at Millstone Station may be restarted until the
effectiveness of a corrective action program is demonstrated; and that Millstone
Station had been placed on the NRC's "watch list" as a Category 3 facility. The
NRC deems Category 3 plants as having significant weaknesses that warrant
maintaining the plant in shutdown condition until it is demonstrated that
adequate programs have been established and implemented to ensure substantial
improvement. In October of 1996, the NRC announced that an independent NRC
review had concluded that the work environment and management failures were the
source of a high volume of employee concerns and allegations related to safety
of plant operations and harassment and intimidation of employees at Millstone
Station. Concurrently, the NRC issued an order directing NU to devise and
implement a compliance plan for handling safety concerns raised by Millstone
Station employees, and for assuring an environment free from retaliation and
discrimination, and ordering NU to contract for an independent third party to
oversee its corrective action program for the employee concerns program. NU is
engaged in an extensive effort to address and correct all of the above-described
problems at Millstone Station and to develop a comprehensive plan for returning
each of the Millstone Station nuclear generating units to service. Although UI's
management anticipates that all of the above-described problems with respect to
Millstone Unit 3 will be resolved, and although UI cannot, at this time, predict
how long it will take to resolve them, or when the NRC will allow Millstone Unit
3 to return to service, a protracted delay seems likely.
While Millstone Unit 3 is out of service, UI is incurring incremental
replacement power costs estimated at approximately $500,000 per month, and
experiencing an adverse impact on net earnings per share of approximately $.02
per month. In addition to these costs of replacement power, incremental direct
costs will be incurred to address the above-described problems with respect to
Millstone Unit 3, and the Company may be responsible for its 3.685% joint
ownership share of these costs. UI and the other non-NU owners of Millstone Unit
3 have been paying their monthly shares of the costs of the unit, but have
reserved their rights to contest whether one or more of the NU operating service
company subsidiary and the two operating NU subsidiary electric utility
companies that are joint owners of Millstone Unit 3 are responsible for the
additional costs that the other joint owners have experienced as a result of the
shutdown of Millstone Unit 3.
The Connecticut Yankee Unit commenced commercial operation in January of
1968, pursuant to a 40-year operating license issued by the NRC. It is owned,
through ownership of Connecticut Yankee's common stock, by ten New England
electric utilities, including the Company, and is operated by another service
company subsidiary of NU.
- 21 -
Prior to July 23, 1996, when the Connecticut Yankee Unit was taken out of
service following an engineering evaluation that determined that safety-related
air cooling system pipes could crack if the plant should lose its outside source
of electric power, the Connecticut Yankee Unit had operated at a lifetime
capacity factor of 75.6%. Prior to and following its removal from service in
July of 1996, NRC inspections of the Connecticut Yankee Unit revealed issues
that were similar to those previously identified at Millstone Station and
identified a number of significant deficiencies in the engineering calculations
and analyses that were relied upon to ensure the adequacy of the design of key
safety systems at the unit. Pending a resolution of these issues, an economic
study by the owners, comparing the costs of continuing to operate the
Connecticut Yankee Unit over the remaining period of its operating license,
which expires in 2007, to the costs of shutting down the unit permanently and
incurring replacement power costs for the same period, resulted in a decision,
on December 4, 1996, by the Board of Directors of Connecticut Yankee to retire
the Connecticut Yankee Unit from commercial operation. The economic study did
not consider the costs of addressing the issues and concerns raised by the NRC.
If these costs had been considered, the economic study would have been more
negative concerning the continued operation of the unit.
At December 31, 1996, UI's equity investment in Connecticut Yankee was
approximately $10 million. The preliminary estimate of the sum of future
payments for the closing, decommissioning and recovery of the remaining
investment in the Connecticut Yankee Unit is approximately $763 million. The
Company's estimate of its remaining share of costs, less return of investment
(approximately $10 million) and return on investment (approximately $7.6
million), is approximately $54.8 million. This estimate, which is subject to
ongoing review and revision, has been recorded by the Company as a regulatory
asset and an obligation on the Consolidated Balance Sheet. The power purchase
contract under which UI has purchased its 9.5% entitlement to the unit's power
output will permit Connecticut Yankee to recover UI's share of these costs from
UI. Connecticut Yankee has filed revised decommissioning cost estimates and
amendments to the power contracts with its owners, including UI, with the FERC.
Based on regulatory precedent, Connecticut Yankee believes it will continue to
collect from its power purchasers its decommissioning costs, the owners'
unrecovered investments in Connecticut Yankee and other costs associated with
the permanent shutdown of the Connecticut Yankee Unit. UI expects that it will
continue to be allowed to recover all FERC-approved costs from its customers
through retail rates.
As a result of the Connecticut Yankee Unit's being out of service, the
Company is incurring incremental replacement power costs estimated at
approximately $500,000 per month, and experiencing an adverse impact on net
earnings per share of approximately $.02 per month. This increase in replacement
power costs is expected to be offset by the reduction of operating expenses.
GENERAL CONSIDERATIONS
Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee Unit are each
subject to the licensing requirements and jurisdiction of the NRC under the
Atomic Energy Act of 1954, as amended, and to a variety of other state and
federal requirements.
The NRC regularly conducts generic reviews of numerous technical issues,
ranging from seismic design to education and fitness for duty requirements for
licensed plant operators. The outcome of reviews that are currently pending, and
the ways in which the nuclear generating units in which 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 nuclear
generating units may result from modifications of these facilities or their
operating procedures required by the NRC, or from actions taken by other joint
owners or companies having entitlements in the units. Some equipment
modifications have required and may in the future require shutdowns or deratings
of generating units that would not otherwise be necessary and that result in
additional costs 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.
- 22 -
Public controversy concerning nuclear power could also adversely affect
Seabrook Unit 1 and Millstone Unit 3. Proposals to force the premature shutdown
of nuclear plants in other New England states have in the past received serious
attention, and the licensing of Seabrook Unit 1 was a regional issue. A renewal
of the controversy could be expected to increase the costs of operating the
nuclear generating units in which UI has interests; and it is possible that one
or the other of the units could be shut down prematurely, resulting in increased
fuel and/or replacement power costs, earlier funding of costs associated with
decommissioning the unit and acceleration of depreciation expense, which could
have an adverse impact on the Company's financial condition and/or results of
operations.
INSURANCE REQUIREMENTS
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $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 $23.2 million per
incident. However, assessment would be limited to $3.1 million per incident, per
year. With respect to each of the 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 each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance.
Although each of these units has purchased $2.75 billion of property
insurance coverage, representing the limits of coverage currently available from
conventional nuclear insurance pools, the cost of a nuclear incident could
exceed available insurance proceeds. In addition, two of the nuclear insurance
pools that provide portions of this coverage may levy assessments against the
insured owner companies if pool losses exceed the accumulated funds available to
the pool. The maximum potential assessments against the Company with respect to
losses occurring during current policy years are approximately $7.5 million.
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 January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010 and possibly
not earlier than 2013, 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.
- 23 -
The DOE also announced that, absent a repository, the DOE has no statutory
obligation to begin taking high level wastes and spent nuclear fuel for disposal
by January 1998. However, numerous utilities and states have obtained a judicial
declaration that the DOE has a statutory responsibility to take title to and
dispose of high level wastes and spent nuclear fuel beginning in January 1998.
It is unclear at this time whether the United States Congress will enact
legislation to address spent fuel/high level waste disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
normal operation of nuclear generating units have increased significantly in
recent years and are expected to continue to rise. The cost increases are a
function of increased packaging and transportation costs and higher fees and
surcharges charged by the disposal facilities. Currently, the Chem Nuclear LLW
facility at Barnwell, South Carolina, is open to the Connecticut Yankee Unit,
Millstone Unit 3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW
facility at Clive, Utah, is also open to these generating units for portions of
their LLW. All three units have contracts in place for LLW disposal at these
disposal facilities.
Because access to LLW disposal may be lost at any time, the Connecticut
Yankee Unit, Millstone Unit 3 and Seabrook Unit 1 have storage plans that will
allow on-site retention of LLW for at least five years in the event that
disposal is interrupted.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
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, together with earnings on the investment of funds so
recovered, to cover expected decommissioning costs. Changes in NRC requirements
or technology, as well as inflation, can increase estimated decommissioning
costs.
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $451 million (in 1997 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $79 million. This estimate assumes the prompt removal and
dismantling of the Unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1996 was $1.6 million. UI's share of the fund at December 31, 1996 was
approximately $9.1 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $463 million (in 1997 dollars), of which the
Company's share would be approximately $17 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a
- 24 -
decommissioning trust fund managed by Northeast Utilities (NU). UI's share of
the Millstone Unit 3 decommissioning payments made during 1996 was $487,000.
UI's share of the fund at December 31, 1996 was approximately $3.8 million. The
decommissioning trust fund for the Connecticut Yankee Unit is also managed by
NU. For the Company's 9.5% equity ownership in Connecticut Yankee,
decommissioning costs of $1.4 million were funded by UI during 1996, and UI's
share of the fund at December 31, 1996 was $19.4 million. The current
decommissioning cost estimate for the Connecticut Yankee Unit, assuming the
prompt removal and dismantling of the unit commencing in 1997, is $436 million,
of which UI's share would be $41 million.
The Financial Accounting Standards Board (FASB) has issued an exposure
draft related to the accounting for the closure and removal costs of long-lived
assets, including nuclear plant decommissioning. If the proposed accounting
standard were adopted, it may result in higher annual provisions for
decommissioning to be recognized earlier in the operating life of nuclear units
and an accelerated recognition of the decommissioning obligation. The FASB will
be deliberating this issue, and the resulting final pronouncement could be
different from that proposed in the exposure draft.
Item 3. Legal Proceedings.
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. The Company is contesting each of these actions
by the City's tax assessor vigorously. On January 9, 1996, the Connecticut
Superior Court granted the Company's motion for summary judgment against the
City relative to the "updated" personal property tax bills for the tax year
1991-1992. The City appealed to the Appellate Court from the Superior Court
decision, which decision would also be applicable to and defeat the valuation
increases for the tax years 1992-1993 and 1993-1994 if it is sustained on
appeal. In June 1996, the Connecticut Supreme Court transferred this appeal to
its docket. The case was argued before the Connecticut Supreme Court in December
1996, and a decision is anticipated in the spring of 1997. It is the present
opinion of the Company that the ultimate outcome of this dispute will not have a
significant impact on the financial position of the Company.
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, 1996.
- 25 -
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:
[Enlarge/Download Table]
NAME AGE POSITION EFFECTIVE DATE
---- --- -------- --------------
Richard J. Grossi 61 Chairman of the Board of Directors May 1, 1991
and Chief Executive Officer
Robert L. Fiscus 59 President and Chief Financial Officer May 1, 1991
James F. Crowe 54 Group Vice President Power Supply Services October 1, 1996
Albert N. Henricksen 55 Group Vice President Support Services October 1, 1996
Anthony J. Vallillo 48 Group Vice President Client Services October 1, 1996
Rita L. Bowlby 58 Vice President-Corporate Affairs February 1, 1993
Raymond G. Dube 54 Vice President/Consultant October 1, 1996
Stephen F. Goldschmidt 51 Vice President Planning and Information Resources October 1, 1996
E. Jon Majkowski 54 Vice President/President Subsidiaries (URI, PPI & TEI) October 1, 1996
James L. Benjamin 55 Controller January 1, 1981
Kurt D. Mohlman 48 Treasurer and Secretary January 1, 1994
Charles J. Pepe 48 Assistant Treasurer and Assistant Secretary January 1, 1994
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 has served as Chairman of the Board of
Directors and Chief Executive Officer during the five-year period.
ROBERT L. FISCUS. Mr. Fiscus has served as President and Chief Financial
Officer during the five-year period.
JAMES F. CROWE. Mr. Crowe served as Senior Vice President-Marketing of the
Company during the period January 1, 1992 to May 1, 1992, as Executive Vice
President from May 1, 1992 to January 1, 1994, and as Executive Vice President
and Chief Customer Officer from January 1, 1994 to October 1, 1996. He has
served as Group Vice President Power Supply Services since October 1, 1996.
ALBERT N. HENRICKSEN. Mr. Henricksen served as Vice President-Human and
Environmental Resources during the period January 1, 1992 to January 1, 1994,
and as Vice President-Administration from January 1, 1994 to October 1, 1996. He
has served as Group Vice President Support Services since October 1, 1996.
ANTHONY J. VALLILLO. Mr. Vallillo served as Director of Marketing during
the period January 1, 1992 to June 1, 1992, and as Vice President-Marketing from
June 1, 1992 to October 1, 1996. He has served as Group Vice President Client
Services since October 1, 1996.
RITA L. BOWLBY. Ms. Bowlby has served as Vice President-Corporate Affairs
since February 1, 1993. Prior to joining the Company, during the period from
January 1, 1992 to February 1, 1993, she served as President of Bowlby &
Associates, a business-to-business communications agency in Farmington,
Connecticut.
- 26 -
RAYMOND G. DUBE. Mr. Dube served as Transmission Manager during the period
January 1, 1992 to July 1, 1992, as Director of Transmission & Distribution
Operations from July 1, 1992 to March 1, 1994, Director of Electric Systems from
March 1, 1994 to October 1, 1994, and as Vice President-Transmission and
Distribution from October 1, 1994 to October 1, 1996. He has served as Vice
President/Consultant since October 1, 1996.
STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served as Vice President-Planning
from January 1, 1992 to January 1, 1994, and as Vice President-Information
Resources from January 1, 1994 to October 1, 1996. He has served as Vice
President Planning and Information Resources since October 1, 1996.
E. JON MAJKOWSKI. Mr. Majkowski served as Vice President-Public Affairs of
the Company during the period January 1, 1992 to May 1, 1992, and as Vice
President/President-UI Subsidiaries from May 1, 1992 to October 1 1996. He has
served as Vice President/President Subsidiaries (URI, PPI & TEI) since October
1, 1996.
JAMES L. BENJAMIN. Mr. Benjamin has served as Controller of the Company
during the five-year period.
KURT D. MOHLMAN. Mr. Mohlman served as Director of Financial Planning and
Investor Relations during the period January 1, 1992 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, 1992 to January 1, 1994. He has served as Assistant Treasurer and
Assistant Secretary of the Company since January 1, 1994.
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 1996 and 1995 were as follows:
1996 SALE PRICE 1995 SALE PRICE
--------------- ---------------
HIGH LOW HIGH LOW
---- --- ---- ---
First Quarter 39 3/4 36 1/4 33 1/4 29 1/2
Second Quarter 38 35 3/4 33 5/8 31 1/4
Third Quarter 37 1/2 33 7/8 35 1/4 31 1/2
Fourth Quarter 35 31 3/8 38 1/2 35 3/4
UI has paid quarterly dividends on its Common Stock since 1900. The
quarterly dividends declared in 1995 and 1996 were at a rate of 70 1/2 cents per
share and 72 cents per share, respectively.
The indenture under which the Company's 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 $98.7 million
were free from such limitations at December 31, 1996.
As of January 31, 1997, there were 17,273 Common Stock shareowners of
record.
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[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA
1996 1995 1994
=====================================================================================================================
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $265,562 $260,694 $252,386
Commercial 263,609 259,715 250,771 (2)
Industrial 108,825 106,963 104,242 (2)
Other 11,880 11,736 11,469
------------- ------------- --------------
Total Retail 649,876 639,108 618,868
Wholesale (1) 72,844 48,232 34,927
Other operating revenues 3,300 3,109 2,953
------------- ------------- --------------
Total operating revenues 726,020 690,449 656,748
------------- ------------- --------------
Fuel and interchange energy -net
Retail -own load 95,359 96,538 99,589
Wholesale 65,158 41,631 27,765
Capacity purchased-net 46,830 47,420 44,769
Depreciation 65,921 61,426 58,165
Other amortization, principally deferred return and cancelled plant 13,758 13,758 1,172
Other operating expenses, excluding tax expense 219,630 (3) 183,749 193,098
Gross earnings tax 26,757 27,379 27,403
Other non-income taxes 30,382 31,564 32,458
------------- ------------- --------------
Total operating expenses, excluding income taxes 563,795 503,465 484,419
------------- ------------- --------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 2,375 2,762 3,463
Other non-operating income(loss) (7,166) (4,272) (1,907)
Interest expense
Long-term debt - net 65,046 63,431 73,772
Other 4,721 13,140 10,301
------------- ------------- --------------
Total 69,767 76,571 84,073
------------- ------------- --------------
Minority interest in preferred securities 4,813 3,583 0
Income tax expense
Operating income tax 53,090 59,828 44,937
Non-operating income tax (9,332) (4,901) (3,214)
------------- ------------- --------------
Total 43,758 54,927 41,723
------------- ------------- --------------
Income(loss) before cumulative effect of accounting change 39,096 50,393 48,089
Cumulative effect of change in accounting - net of tax 0 0 (1,294)
------------- ------------- --------------
Net income (loss) 39,096 (4) 50,393 46,795
Discount on preferred stock redemption (1,840) (2,183) 0
Preferred and preference stock dividends 330 1,329 3,323
------------- ------------- --------------
Income (loss) applicable to common stock $40,606 $51,247 $43,472
---------------------------------------------------------------------------------------------------------------------
Operating income $109,135 $127,156 $127,392
=====================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $1,258,306 $1,277,910 $1,268,145
Construction work in progress 40,998 41,817 57,669
Plant-related regulatory asset 0 0 0
Other property and investments 49,091 53,355 53,267
Current assets 163,350 137,277 157,309
Deferred charges and regulatory assets 449,150 475,258 538,601
------------- ------------- --------------
Total Assets $1,960,895 $1,985,617 $2,074,991
---------------------------------------------------------------------------------------------------------------------
Common stock equity $440,016 $439,981 $428,028
Preferred, preference stock and preferred securities 54,461 60,539 44,700
Long-term debt excluding current portion 759,680 845,684 708,340
Noncurrent liabilities (5) 138,816 65,747 59,458
Current portion of long-term debt 69,900 40,800 193,133
Notes payable 10,965 0 67,000
Other current liabilities (5) 129,007 102,336 122,084
Deferred income tax liabilities and other 358,050 430,530 452,248
------------- ------------- --------------
Total Capitalization and Liabilities $1,960,895 $1,985,617 $2,074,991
=====================================================================================================================
(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 charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(4) Includes the effect of charges of $13.4 million, after-tax, associated with
voluntary early retirement programs.
(5) Amounts for years prior to 1996 have been reclassified.
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[Enlarge/Download Table]
1993 1992 1991 1990 1989 1988 1987
========================================================================================================================
$238,185 $226,455 $226,751 $211,891 $205,183 $200,170 $188,740
256,559 253,456 (2) 255,782 234,704 219,852 208,801 195,972
97,466 97,010 (2) 91,895 94,526 92,855 96,665 100,354
11,349 11,065 10,886 10,536 9,943 9,732 9,480
--------------- -------------- -------------- -------------- -------------- -------------- -------------
603,559 587,986 585,314 551,657 527,833 515,368 494,546
45,931 75,484 84,236 85,657 77,925 63,263 54,708
3,533 3,855 3,821 3,332 3,348 3,570 3,077
--------------- -------------- -------------- -------------- -------------- -------------- -------------
653,023 667,325 673,371 640,646 609,106 582,201 552,331
--------------- -------------- -------------- -------------- -------------- -------------- -------------
98,694 108,084 123,010 119,285 128,739 121,425 131,471
39,356 55,169 61,858 69,117 62,681 53,837 51,411
47,424 43,560 44,668 42,827 50,234 35,465 17,746
56,287 50,706 48,181 36,526 35,618 24,069 37,160
1,780 10,415 10,415 4,173 10,415 10,415 10,415
203,427 (6) 183,426 178,912 176,419 144,867 133,407 127,900
27,955 27,362 27,223 25,595 24,506 23,948 22,997
29,977 31,869 28,673 24,648 20,294 21,695 17,194
--------------- -------------- -------------- -------------- -------------- -------------- -------------
504,900 510,591 522,940 498,590 477,354 424,261 416,294
--------------- -------------- -------------- -------------- -------------- -------------- -------------
7,497 15,959 17,970 21,503 0 0 0
4,067 3,232 5,190 3,443 65,443 75,656 81,419
71 18,545 2,697 22,654 (219,742) (23,369) (97,686)
80,030 88,666 90,296 94,056 91,126 90,022 88,700
12,260 12,882 9,847 15,468 22,849 12,069 9,228
--------------- -------------- -------------- -------------- -------------- -------------- -------------
92,290 101,548 100,143 109,524 113,975 102,091 97,928
--------------- -------------- -------------- -------------- -------------- -------------- -------------
0 0 0 0 0 0 0
33,309 48,712 47,231 43,493 37,963 44,045 50,633
(6,322) (12,558) (19,299) (17,409) (101,135) (14,548) (37,440)
--------------- -------------- -------------- -------------- -------------- -------------- -------------
26,987 36,154 27,932 26,084 (63,172) 29,497 13,193
--------------- -------------- -------------- -------------- -------------- -------------- -------------
40,481 56,768 48,213 54,048 (73,350) 78,639 8,649
0 0 7,337 0 0 0 0
--------------- -------------- -------------- -------------- -------------- -------------- -------------
40,481 (7) 56,768 55,550 54,048 (73,350) 78,639 8,649
0 0 0 0 0 0 0
4,318 4,338 4,530 4,751 8,233 11,348 11,953
--------------- -------------- -------------- -------------- -------------- -------------- -------------
$36,163 $52,430 $51,020 $49,297 ($81,583) $67,291 ($3,304)
------------------------------------------------------------------------------------------------------------------------
$114,814 $108,022 $103,200 $98,563 $93,789 $113,895 $85,404
========================================================================================================================
$1,243,426 $1,224,058 $1,219,871 $1,209,173 $562,473 $560,930 $563,210
77,395 59,809 54,771 50,257 675,831 812,246 737,169
0 0 0 0 81,768 88,339 68,603
58,096 65,320 79,009 90,006 91,648 83,860 76,032
187,981 247,954 164,839 161,066 170,823 166,270 122,075
567,394 556,493 554,365 553,986 605,696 653,418 610,913
--------------- -------------- -------------- -------------- -------------- -------------- -------------
$2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063 $2,178,002
------------------------------------------------------------------------------------------------------------------------
$423,324 $422,746 $401,771 $379,812 $362,584 $473,674 $438,564
60,945 60,945 62,640 69,700 70,000 104,000 110,000
875,268 893,457 909,998 899,993 868,884 862,287 767,559
62,666 44,567 110,217 110,850 117,200 119,165 100,821
143,333 92,833 37,500 41,667 18,667 3,667 28,667
0 84,099 13,000 15,000 45,000 0 0
117,343 114,757 114,280 138,173 133,459 115,043 111,258
451,413 440,230 423,449 409,293 572,445 687,227 621,133
--------------- -------------- -------------- -------------- -------------- -------------- -------------
$2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063 $2,178,002
========================================================================================================================
(6) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(7) Includes the effect of a reorganization charge of $7.8 million, after-tax.
- 29 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1996 1995 1994
=====================================================================================================================
COMMON STOCK DATA
Average number of shares outstanding 14,100,806 14,089,835 14,085,452
Number of shares outstanding at year-end 14,101,291 14,100,091 14,086,691
Earnings(loss) per share (average) $2.88 $3.64 $3.09
Recurring earnings(loss) per share (average) (1) $3.94 $3.61 $3.28
Book value per share $31.20 $31.20 $30.39
Average return on equity
Total 9.20% 11.84% 10.19%
Utility 11.51% 13.04% 12.50%
Dividends declared per share $2.88 $2.82 $2.76
Market Price:
High $39.750 $38.500 $39.500
Low $31.375 $29.500 $29.000
Year-end $31.375 $37.375 $29.500
=====================================================================================================================
Net cash provided by operating activities, less dividends ($000's) $103,943 $120,033 $94,807
Capital expenditures, excluding AFUDC $47,174 $59,363 $63,044
=====================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 1,891,988 1,890,575 1,892,955
Commercial 2,258,501 2,273,965 2,285,942 (2)
Industrial 1,141,109 1,126,458 1,135,831 (2)
Other 48,291 48,435 48,718
------------- ------------- --------------
Total 5,339,889 5,339,433 5,363,446
------------- ------------- --------------
Number of retail customers by class (average)
Residential 279,024 278,326 275,441
Commercial 28,666 28,550 28,394 (2)
Industrial 1,652 1,599 1,538 (2)
Other 1,141 1,122 1,127
------------- ------------- --------------
Total 310,483 309,597 306,500
------------- ------------- --------------
Revenue per kilowatt hour by class (cents)
Residential 14.04 13.79 13.33
Commercial 11.67 11.42 10.97
Industrial 9.54 9.50 9.18
Average large industrial customers time of use rate (cents) 8.26 8.53 8.69
System requirements (MWh) 5,640,957 5,647,690 5,652,657
Peak load - kilowatts 1,044,620 1,156,740 1,130,780
Generating capability- peak(kilowatts) 1,522,350 1,434,102 1,462,290
Load factor 61.64% 55.74% 57.07%
Fuel generation mix percentages
Coal 38 37 35
Oil 8 7 14
Nuclear 37 37 32
Cogeneration 9 9 9
Gas 3 5 4
Hydro 5 5 6
---------------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $642,106 $637,219 $619,097
Fuel adjustment clause 7,770 1,889 (229)
Sales provision adjustment 0 0 0
------------- ------------- --------------
Total $649,876 $639,108 $618,868
------------- ------------- --------------
Revenues - retail sales per kWh (cents)
Base 12.02 11.93 11.54
Fuel adjustment clause 0.15 0.04 0.00
Sales provision adjustment 0.00 0.00 0.00
------------- ------------- --------------
Total 12.17 11.97 11.54
------------- ------------- --------------
Fuel and energy cost per kWh (cents) 1.69 1.71 1.76
Fossil 2.41 2.22 2.14
Nuclear 0.46 0.85 0.94
---------------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,287 1,358 1,377
Total payroll($000 'S) $69,276 $72,984 $75,441
=====================================================================================================================
(1) Recurring earnings(loss) per share (average) is not a generally accepted
accounting principle measurement. Management provides this measurement for
informational purposes only.
(2) Includes reclassification of certain Commercial and Industrial customers.
- 30 -
[Enlarge/Download Table]
1993 1992 1991 1990 1989 1988 1987
========================================================================================================================
14,063,854 13,941,150 13,899,906 13,887,748 13,887,748 13,887,748 13,887,654
14,083,291 14,033,148 13,932,348 13,887,748 13,887,748 13,887,748 13,887,748
$2.57 $3.76 $3.67 $3.55 ($5.87) $4.85 ($0.24)
$3.13 $3.17 $2.90 $3.55 ($5.87) $4.85 ($0.24)
$30.06 $30.12 $28.84 $27.35 $26.11 $34.11 $31.58
8.45% 12.67% 13.01% 13.39% -18.88% 14.75% -0.72%
10.97% 14.46% 13.39% 13.97% 20.21% 32.91% 15.34%
$2.66 $2.56 $2.44 $2.32 $2.32 $2.32 $2.32
$45.875 $42.000 $39.125 $34.125 $34.250 $27.500 $34.000
$38.500 $34.125 $30.000 $26.875 $24.750 $19.125 $21.250
$40.250 $41.500 $39.000 $31.125 $34.250 $26.875 $26.875
========================================================================================================================
$104,547 $109,020 $73,865 $39,189 $31,437 $40,607 $37,986
$94,743 $66,390 $63,157 $64,018 $77,041 $83,735 $73,253
========================================================================================================================
1,844,041 1,799,456 1,851,447 1,826,700 1,883,363 1,870,318 1,780,333
2,359,023 2,303,216 (2) 2,347,757 2,259,340 2,254,099 2,174,200 2,046,289
1,036,547 997,168 (2) 980,071 1,060,751 1,109,119 1,186,336 1,236,151
50,715 52,984 55,118 58,013 60,427 61,303 62,246
--------------- -------------- -------------- -------------- -------------- -------------- -------------
5,290,326 5,152,824 5,234,393 5,204,804 5,307,008 5,292,157 5,125,019
--------------- -------------- -------------- -------------- -------------- -------------- -------------
273,752 273,936 274,064 275,637 276,385 274,884 271,302
28,968 28,848 (2) 29,768 29,808 29,526 28,826 28,103
959 1,017 (2) 268 319 347 367 369
1,175 1,358 1,361 1,352 1,316 1,267 1,191
--------------- -------------- -------------- -------------- -------------- -------------- -------------
304,854 305,159 305,461 307,116 307,574 305,344 300,965
--------------- -------------- -------------- -------------- -------------- -------------- -------------
12.92 12.58 12.25 11.60 10.89 10.70 10.60
10.88 11.00 10.89 10.39 9.75 9.60 9.58
9.40 9.73 9.38 8.91 8.37 8.15 8.12
8.89 8.84 8.64 8.06 7.58 7.14 7.04
5,630,581 5,475,664 5,541,477 5,501,495 5,603,502 5,581,897 5,403,519
1,114,900 1,034,440 1,145,820 1,054,600 1,094,400 1,132,100 1,039,600
1,515,420 1,402,800 1,474,190 1,449,600 1,289,800 1,271,500 1,236,000
57.65% 60.26% 55.21% 59.55% 58.45% 56.13% 59.33%
31 34 34 43 39 37 42
16 17 21 24 37 41 37
38 35 29 20 11 11 10
8 8 9 9 9 7 1
1 1 4 3 3 0 5
6 5 3 1 1 4 5
------------------------------------------------------------------------------------------------------------------------
$605,887 $608,176 $607,997 $589,346 $577,611 $574,422 $558,060
(2,328) (41,221) (37,497) (45,900) (49,778) (59,054) (63,514)
0 21,031 14,814 8,211 0 0 0
--------------- -------------- -------------- -------------- -------------- -------------- -------------
$603,559 $587,986 $585,314 $551,657 $527,833 $515,368 $494,546
--------------- -------------- -------------- -------------- -------------- -------------- -------------
11.45 11.80 11.62 11.32 10.88 10.85 10.89
(0.04) (0.80) (0.72) (0.88) (0.93) (1.11) (1.24)
0.00 0.41 0.28 0.16 0.00 0.00 0.00
--------------- -------------- -------------- -------------- -------------- -------------- -------------
11.41 11.41 11.18 10.60 9.95 9.74 9.65
--------------- -------------- -------------- -------------- -------------- -------------- -------------
1.75 2.43 2.67 2.63 2.78 2.53 2.54
2.08 2.98 3.11 2.89 2.98 2.74 2.58
1.23 1.42 1.62 1.55 0.89 0.87 0.94
------------------------------------------------------------------------------------------------------------------------
1,490 1,554 1,571 1,587 1,627 1,620 1,604
$75,305 $74,052 $71,888 $69,237 $65,175 $62,387 $57,207
========================================================================================================================
- 31 -
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, has
averaged less than 1.5%. The Company hopes to continue to restrict this average
to less than the rate of inflation in future years (see "Looking Forward for
1997").
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and regulations
and competition within the electric utility industry.
A major factor affecting the Company's earnings prospects beyond 1996 will
be the success of the Company's efforts to implement the regulatory framework
ordered by the DPUC at the end of 1996. On December 31, 1996, the DPUC completed
a financial and operational review of the Company and ordered a five-year
incentive regulation plan for the years 1997-2001. The DPUC did not change the
retail base rates charged to customers. Its order increased amortization of the
Company's conservation and load management program investments during 1997-1998,
accelerated the recovery of unspecified regulatory assets during 1999-2001,
reduced the level of conservation adjustment mechanism revenues in retail rates,
provided a reduction in customer bills through a surcredit in each of the five
plan years, and accepted the Company's proposal to modify the operation of the
fossil fuel clause mechanism. The Company's authorized return on common equity
was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are
to be utilized one-third for customer bill reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. The DPUC
did not order the accelerated depreciation of the Company's Seabrook Unit 1
plant investment costs and the establishment of a performance-based regulation
mechanism measured by customer satisfaction surveys and reliability of service
indices, which the Company had proposed. As a result of the DPUC's order,
customer bills are expected to be reduced on average by 3% in 1997-1999, 4% in
the year 2000, and 5% in the year 2001 (all compared to 1996). Also, earnings
from utility operations will be reduced from the levels requested by the
Company, such that it is unlikely that the Company will be able to achieve its
4% growth goal going forward.
The FERC has stated that state regulatory commissions should address the
issue of recovery by electric utilities of the costs of existing facilities that
would be stranded by retail access. The legislatures and regulatory commissions
in several states have considered or are considering "retail access". 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 access
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. In 1995, the Connecticut
Legislature established a task force to review these issues and to make
recommendations on electric industry restructuring within Connecticut. The task
force concluded its work in December 1996 and, although no consensus report was
adopted, it is expected that the legislature will enact comprehensive
legislation in its 1997 session to introduce retail access for Connecticut
consumers over the next several years. Among many other factors, decisions and
actions concerning retail access in other states could impact the timing and
form of this transition.
Although the Company is unable to predict the future effects of competitive
forces in the electric utility industry, competition could result in a change in
the regulatory structure of the industry, and costs that have traditionally been
recoverable through the ratemaking process may not be recoverable in the future.
This effect could have a material impact on the financial condition and/or
results of operations of the Company.
- 32 -
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation") that are not applicable to other businesses in general. These
accounting rules allow regulated utilities, where appropriate, to defer the
income statement impact of certain costs that are expected to be recovered in
future regulated service rates and to establish regulatory assets on balance
sheets for such costs. The effects of competition could cause the operations of
the Company, or a portion of its assets or operations, to cease meeting the
criteria for application of these accounting rules. While the Company expects to
continue to meet these criteria in the foreseeable future, if the Company, or a
portion of its assets or operations, were to cease meeting these criteria,
accounting standards for businesses in general would become applicable and
immediate recognition of any previously deferred costs, or a portion of deferred
costs, would be required in the year in which the criteria are no longer met. If
this change in accounting were to occur, it would have a material adverse effect
on the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as follows:
[Enlarge/Download Table]
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(MILLIONS)
Cash on Hand - Beginning of Year $6.4 $18.5 $ - $ - $ -
Internally Generated Funds (less Dividends) 95.0 115.8 116.9 110.6 107.5
---- ----- ----- ----- -----
Subtotal 101.4 134.3 116.9 110.6 107.5
Less:
Capital Expenditures 50.5 51.2 47.3 43.5 36.5
----- ----- ----- ----- -----
Cash Available to pay Debt Maturities and Redemptions 50.9 83.1 69.6 67.1 71.0
Less:
Maturities and Mandatory Redemptions 10.8 104.6 105.0 155.5 81.0
Optional Redemptions 21.6 - - - -
----- ----- ----- ----- ----
External Financing Requirements $(18.5) $21.5 $35.4 $88.4 $10.0
====== ===== ===== ===== =====
Note: Internally Generated Funds (less Dividends), Capital Expenditures and
External Financing Requirements are estimates based on current earnings
and cash flow projections and are subject to change due to future events
and conditions that may be substantially different than those used in
developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
common stock, preferred stock and additional short-term and long-term debt. The
continued availability of these methods of financing will be dependent on many
factors, including conditions in the securities markets, economic conditions,
and the level of the Company's income and cash flow.
On February 15, 1996, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric
Company, a wholly-owned subsidiary of the Company that was merged with and into
the Company in September 1994.
On June 26, 1996, the Company borrowed $7.5 million from the Connecticut
Development Authority (CDA), representing the proceeds from the issuance by the
CDA of $7.5 million principal amount of tax-exempt Pollution Control Revenue
Bonds (PCRBs). The Company is obligated, under its borrowing agreement with the
CDA, to pay to a trustee for the PCRBs' bondholders such amounts as will pay,
when due, the principal of and the premium, if any, and
- 33 -
interest on the PCRBs. The PCRBs will mature in 2026, and their interest rate
can be adjusted periodically to reflect prevailing market conditions. The PCRBs
were issued at an initial interest rate of 3.3%, which is being adjusted weekly.
On July 15, 1996, the Company used the proceeds of this $7.5 million borrowing
to cause the redemption and repayment of $7.5 million principal amount of 9 1/2%
PCRBs issued by the CDA in 1986.
On October 25, 1996, the Company borrowed $75 million under a Term Loan
Agreement with a group of banks for a five-year period. The Company pays
interest on the borrowing at a floating rate equal to the three-month London
Interbank Borrowing Rate plus 0.55%. The Company has entered into two separate
interest rate swap agreements that effectively convert the interest rate on $50
million of the Company's floating rate 1996 Term Loan to a fixed annual interest
rate of 7.005% for the five-year period and the interest rate on the remaining
$25 million to a fixed annual interest rate of 6.675% for a three-year period.
The Company used proceeds from the $75 million Term Loan borrowing to
purchase approximately $66.8 million principal amount of Seabrook Lease
Obligation Bonds, which were issued in connection with the sale and leaseback by
the Company of a portion of its ownership share in Seabrook Unit 1 in 1990. The
Bonds were purchased at a premium through a tender offer that expired on October
22, 1996. The Company paid 103.9% of principal amount for approximately $17.0
million principal amount of 9.76% Seabrook Lease Obligation Bonds (due 2006) and
107.17% of principal amount for approximately $49.9 million principal amount of
the 10.24% Seabrook Lease Obligation Bonds (due 2020). The premiums and other
transaction expenses will be amortized over the remaining life of the Bonds. The
Company intends to hold the Bonds until maturity and has recognized the
investment as an offset to long-term debt on its Consolidated Balance Sheet.
On June 4, 1996, June 7, 1996 and August 8, 1996, the Company purchased at
a discount in the open market, and canceled, 60,782 shares of its $100 par value
Preferred Stock. The shares purchased consisted of 9,950 shares of its 4.35%,
Series A, 12,832 shares of its 4.72%, Series B, and 38,000 shares of its 5 5/8%,
Series D, Preferred Stock. The shares, having a par value of $6,078,200, were
purchased for $4,238,387, creating a net gain of $1,839,813.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 10, 1997. 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, 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, 1996, the Company had no short-term borrowings outstanding under this
facility.
On December 30, 1996, the Company transferred $51.3 million to a trustee
under an escrow agreement. The funds, which were invested in Treasury Notes,
were used to pay $50 million principal amount of 7% Notes that matured on
January 15, 1997 plus accrued interest.
On February 15, 1997, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of
$185,328, the remaining $21.6 million outstanding principal amount of 9.44%
First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a
wholly-owned subsidiary of the Company that was merged with and into the Company
in September 1994.
At December 31, 1996, the Company had $6.4 million of cash and temporary
cash investments, an increase of $1.3 million from the balance at December 31,
1995. The components of this increase, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
- 34 -
[Download Table]
(Millions)
Balance, December 31, 1995 $ 5.1
-----
Net cash provided by operating activities 144.8
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments 15.6
- Dividend payments (40.8)
Net cash used in investing activities, excluding investment in plant (71.1)
Cash invested in plant, including nuclear fuel (47.2)
-----
Net Change in Cash 1.3
-----
Balance, December 31, 1996 $ 6.4
=====
The Company's long-term debt instruments do not limit the amount of short-term
debt that the Company may issue. The Company's revolving credit agreement
described above requires it to maintain an available earnings/interest charges
ratio of not less than 1.5:1.0 for each 12-month period ending on the last day
of each calendar quarter. For the 12-month period ended December 31, 1996 this
coverage ratio was 2.78.
SUBSIDIARY OPERATIONS
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers. Two other wholly-owned
subsidiaries, United Energy International, Inc. and Research Center, Inc. were
dissolved in April 1996.
Four wholly-owned subsidiaries of URI have been incorporated. A URI
subsidiary named American Payment Systems, Inc. manages a national network of
agents for the processing of bill payments made by customers of other utilities.
Souwestcon Properties, Inc. (SPI) participated as a 25% partner in the ownership
of a medical hotel building in New Haven. The building has been sold; and SPI
was dissolved in April 1996. Another wholly-owned subsidiary of URI, Thermal
Energies, Inc., is participating in the development of district heating and
cooling facilities in the downtown New Haven area, including the energy center
for an office tower and participation as a 62% partner in the energy center for
a city hall and office tower complex. A URI subsidiary named Precision Power,
Inc. provides power-related equipment and services to the owners of commercial
buildings and industrial facilities.
The after-tax impact of the subsidiaries on the consolidated financial
statements of the Company is as follows:
ASSETS
NET INCOME (LOSS) EARNINGS AT DEC. 31
(000'S) PER SHARE (000'S)
---------------- --------- ----------
1996 $(5,237) $(0.37) $36,385
1995 (2,640) (0.19) 16,323
1994 (3,245) (0.23) 15,334
In 1996, the Company made provisions for losses of $2.6 million (after-tax)
associated with agent collections (for which restitution will be vigorously
sought) and miscellaneous other items at its American Payment Systems, Inc.
subsidiary.
- 35 -
RESULTS OF OPERATIONS
1996 VS. 1995
-------------
Earnings for the year 1996 were $40.6 million, or $2.88 per share, down
$10.6 million, or $.76 per share, from 1995. Earnings from operations, which
exclude one-time items, were $55.6 million, or $3.94 per share for 1996, up $4.9
million, or $.33 per share, from 1995. The one-time items recorded in 1996, that
totaled to a charge of $1.06 per share, were: a gain of $1.8 million
(after-tax), or $.13 per share, from the purchase of preferred stock by the
Company at a discount to par value, charges of $23.0 million ($13.4 million
after-tax), or $.95 per share, reflecting the estimated costs of early
retirements and voluntary separations as part of the Company's on-going
organization review and cost reduction program, a charge of $1.4 million ($0.8
million after-tax), or $.06 per share, for the cumulative loss on an office
space sublease, and a charge of $2.6 million (after-tax), or $.18 per share,
that the Company was required to make provisions for losses associated with
agent collections (for which restitution will be vigorously sought) and
miscellaneous other items at its American Payment Systems, Inc. subsidiary. The
one-time items recorded in 1995, that totaled to a gain of $.03 per share, were:
a charge of $.12 per share, taken in the third quarter of 1995, to reflect the
effects of legislated future state income tax rate reductions that reduced
future tax benefits on plant previously written off, and gains of $.15 per share
from the purchase of preferred stock by the Company at a discount to par value.
Retail operating revenues increased by about $10.8 million in 1996 compared
to 1995:
. Retail kilowatt-hour sales for 1996 were virtually unchanged from 1995.
The Company's calculation of the impact of weather on kilowatt-hour sales
indicates that sales decreased by about 1.3% in 1996 compared to 1995 due
to weather factors. Weather was deemed to be more severe than normal in
1995, particularly in the summer months, and milder than normal in 1996,
particularly in the summer months. Retail kilowatt-hour sales also
increased by 0.3% due to the leap year day in 1996. This indicates that
there was a "real" (i.e. not attributable to abnormal weather or leap year)
kilowatt-hour sales increase of about 1.0% in 1996 compared to 1995.
Because sales were lower in the summer months when rates are generally
higher, retail revenues decreased by $0.7 million.
. Other factors increased retail revenues by $11.5 million: $6.4 million
from the recovery, through the Conservation Adjustment Mechanism, of
previously recorded and projected conservation program costs mandated by
the Department of Public Utility Control (DPUC), partially offset by
competitive pricing and other price reduction mechanisms, and a net $5.1
million increase from "pass through" charges for certain expense changes
including increases in fuel costs.
Wholesale "capacity" revenues increased by $1.1 million in 1996 compared to
1995. Wholesale "energy" revenues are a direct offset to wholesale energy
expense and do not contribute to sales margin (revenue less fuel expense and
revenue-based taxes). These energy revenues, as well as the associated fuel
expense, increased during 1996 compared to 1995.
Retail fuel and energy expenses decreased by $1.2 million in 1996 compared
to 1995. A decrease of $9.0 million was due to lower nuclear fuel prices,
primarily at the Seabrook nuclear generating unit. Higher kilowatt-hour
generation at the Seabrook nuclear generating unit, that had a refueling outage
in 1995, reduced fuel and energy expenses by $1.9 million, while lower
kilowatt-hour generation, due to the shutdowns at the Connecticut Yankee and
Millstone Unit 3 nuclear generating units, increased fuel and energy expense by
$5.3 million. For more on the status of the operation of these units, see the
LOOKING FORWARD FOR 1997 section. Other fuel and energy expenses increased by
$4.4 million, primarily from increases in "pass through" charges, including
fossil fuel costs.
- 36 -
Operating expenses for operations, maintenance and purchased capacity
charges increased by $10.9 million in 1996 compared to 1995:
. Purchased capacity expense was $0.6 million lower.
. Operation and maintenance expense increased by $11.5 million. Expenses
associated with the Company's re-engineering efforts increased by a net
$2.0 million. Expenses increased by $1.5 million at the Millstone Unit 3
nuclear generating unit, by $4.9 million for overhauls at the Company's
fossil fuel generating units, by $1.0 million for a major dredging project
at one of the generating stations, by $1.3 million from the expensing of
previously capitalized costs associated with software purchases and
development, and by $4.0 million in general. Expenses at the Seabrook
nuclear generating unit decreased by $3.2 million absent the refueling
outage that occurred in the fourth quarter of 1995.
Other operating expenses increased in 1996 compared to 1995, from higher
depreciation expense and income taxes (excluding the income tax effects of
one-time items).
Other net income increased in 1996 compared to 1995 primarily because of
the absence of expenses, associated with canceled construction projects, which
were recorded in 1995.
Interest charges continued their significant decline, decreasing by $6.8
million in 1996 compared to 1995 as a result of the Company's refinancing
program and strong cash flow. The Company was successful in purchasing $67
million of the approximately $200 million outstanding Seabrook Lease Obligation
Bonds, to hold in its own account, using proceeds from a lower cost bank term
loan. The interest income that the Company receives from its $67 million
investment in these bonds appears on the income statement as a credit to
interest expense and partially offsets the interest expense incurred on the
Seabrook lease obligation. Also, total preferred dividends (net-of-tax)
decreased slightly in 1996 compared to 1995 as a result of the purchases of
preferred stock by the Company.
1995 VS. 1994
-------------
Earnings for the year 1995 were $51.2 million, or $3.64 per share, up $7.8
million, or $.55 per share, from 1994. Earnings from operations, which exclude
one-time items, were $50.7 million, or $3.61 per share, for 1995. Earnings from
operations for 1994 were $46.2 million, or $3.28 per share. The one-time items
were: a one-time charge of $.12 per share, taken in the third quarter of 1995
and reflecting the effects of legislated future state income tax rate reductions
that reduced future tax benefits on plant previously written off, a one-time
gain of $.15 per share, recorded in the second and third quarters of 1995, from
the repurchase of preferred stock at a discount to par value, a one-time
accounting change, a charge of $.09 per share, recorded in the first quarter of
1994 to reflect the accrual of postemployment benefits under Statement of
Financial Accounting Standards (SFAS) No. 112, and a one-time charge of $.10 per
share, recorded in the fourth quarter of 1994, from the settlement of a property
tax dispute with the City of Bridgeport.
Retail operating revenues increased by $20.2 million in 1995 compared to
1994:
. Retail revenues increased by $13.1 million due to the completion of the
1994 non-cash amortization of deferred sales adjustment revenues, by $6.1
million from the recovery, through the Conservation Adjustment Mechanism,
of previously recorded and projected conservation program costs, and by a
net $3.2 million from pass-through charges for certain expense changes. The
expense changes included the absence of a property tax credit that occurred
and was refunded to customers in the third quarter of 1994 and increases in
fuel costs in 1995 compared to 1994.
. A retail kilowatt-hour sales decrease of 0.4% from the prior year reduced
retail revenues by $2.1 million. The Company believes that the sales
decrease due to weather factors was greater than 0.4% and that there was a
small but "real" (i.e. not attributable to abnormal weather) retail
kilowatt-hour sales increase of about 0.5% in 1995 compared to 1994.
- 37 -
Wholesale "capacity" revenues decreased by $0.6 million in 1995 compared to
1994. Wholesale "energy" revenues are a direct offset to wholesale energy
expense and do not contribute to sales margin.
Retail fuel and energy expenses decreased by $3.1 million in 1995 compared
to 1994. A decrease of $5.7 million was due to improved nuclear power plant
output: the 1995 Seabrook Unit 1 refueling outage was much shorter than the 1994
outage, and the Seabrook Unit 1 and Connecticut Yankee Unit had unscheduled
outages in 1994, while Millstone Unit 3 and the Connecticut Yankee Unit (much
smaller sources of generation for the Company compared to Seabrook Unit 1) had
refueling outages in the first six months of 1995 but none in 1994.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $6.7 million in 1995 compared to 1994:
. Purchased capacity was $2.7 million higher due to costs associated with
eleven weeks of scheduled refueling outage at the Connecticut Yankee Unit
in the first half of 1995 and somewhat higher cogeneration output.
. Operation and maintenance expense decreased by $9.4 million. There was a
$7.2 million reduction in fossil power plant costs reflecting reduced
scheduled maintenance activity. Employment costs decreased by $3.1 million
due primarily to the Company's 1993 reorganization and early retirement
program, which was phased-in over 1994. Other costs increased by $0.9
million.
Other amortization increased by $12.6 million (after-tax and equivalent,
approximately, to a $23 million revenue requirement) in 1995 compared to 1994,
due to commencement of the amortization of Seabrook Unit 1 phase-in costs
(deferred return that was recorded and accumulated during the period January 1,
1990 to December 31, 1993). The annual amortization amount is $12.6 million
after-tax per year for five years beginning in 1995.
Other operating expenses increased in 1995 compared to 1994 from higher
depreciation expense and income taxes as well as from the absence of a
pass-through property tax credit that occurred in the third quarter of 1994.
Interest charges decreased by $7.5 million in 1995 compared to 1994 as a
result of the Company's refinancing program and strong cash flows. Total
Preferred Stock dividends (net-of-tax) were virtually unchanged in 1995 compared
to 1994.
LOOKING FORWARD FOR 1997
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
PROJECTED. READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE
FORWARD-LOOKING STATEMENTS, WHICH SPEAK ONLY AS OF THE DATE OF THIS REPORT.)
Since 1992, the Company's long term earnings goal has been to achieve
growth in earnings per share FROM OPERATIONS of 4% annually from the 1992 level
of $3.17 per share. The Company exceeded the goal in 1995, and earnings from
operations of $3.94 per share in 1996 exceeded the 1996 goal of $3.70 per share.
As explained in RESULTS OF OPERATIONS, the Company has taken substantial
non-recurring charges to operating expense in 1996 to help it reduce future
costs, prepare for expected future competition, and minimize the need for future
employee layoffs. The Company was also required to make provisions for losses
associated with agent collections (for which restitution will be vigorously
sought) and miscellaneous other items at its American Payment Systems
subsidiary. The total of these operating and non-operating non-recurring
charges, offset by some minor gains, had a negative impact on earnings per share
of $1.06 in 1996. Earnings per share, inclusive of these charges, were $2.88.
Due to the DPUC's year-end 1996 order that will decrease earnings from
utility operations, it is unlikely that the Company will be able to achieve the
4% growth goal going forward, as a major contribution to earnings from
- 38 -
unregulated subsidiaries is not expected to occur in the foreseeable future. In
a press release dated January 2, 1997, the Company announced that it would not
challenge the DPUC's December 31, 1996 order (the Order) to reduce rates and
accelerate the recovery of certain costs associated with conservation programs,
such that the Company could earn an allowed return on common stock equity from
its utility investment of 11.5% over the period 1997 to 2001, a reduction of
nearly 1% (an amount equivalent to about $.30 per share) from the previously
allowed (and requested by the Company) return of 12.4%. Income earned from
higher sales or reduced expenses that produces a return above the 11.5% return
level will be shared by one-third being applied to customer bill reductions,
one-third applied to more rapid amortization of assets, and one-third retained
by shareowners, also by virtue of the Order. The Company indicated in the
January 2, 1997 press release that, if the Company were to achieve the 11.5%
return on its utility investment, then earnings from utility operations would be
in the $3.30-$3.40 range for 1997 and succeeding years as well.
It should be noted that, although the Order was for the five-year period
1997-2001, the Company made no commitment to agree to this multi-year plan.
Furthermore, the Connecticut legislature is expected to address the issue of
electric utility industry restructuring in 1997. This may result in new
legislation, and the DPUC, in the Order, acknowledged that it could be revisited
in the light of new legislation.
There is no assurance that the Company will achieve the 11.5% return on
utility common stock equity allowed by the DPUC. Utility income is greatly
affected by weather-related sales, fossil fuel prices and nuclear generating
unit availability...all items over which the Company has little control. As part
of the Order, the Company's traditional fuel clause that allowed for recovery of
increases in fossil fuel costs was suspended within a broad range of fuel
prices. While the Company stands to benefit if prices the Company pays for its
oil purchases falls below about $15 a barrel, current prices are above those
levels.
As a result of the Order, it is anticipated that retail revenues for 1997
will decrease from 1996 levels. A reduction of about $15 million will be due to
reductions in customer bills directly ordered by the DPUC. (These reductions
will be partially offset by about $3 million in conservation spending
reductions. New conservation spending is no longer capitalized, and changes in
conservation expense, relative to the assumptions used by the DPUC in the Order,
will be reflected in retail rates through the operation of the Conservation
Adjustment Mechanism.) Revenues will decline further by about $6 million due to
the suspension of the fossil fuel adjustment clause (FCA). While the Company
cannot predict the direction fuel prices will take in 1997 and whether it can
mitigate entirely this loss of FCA revenue, it is actively engaged in hedging
activities to limit the Company's exposure to increases in fossil fuel prices.
The Company's revenues are also dependent on the level of retail sales. The
two primary factors that affect retail sales volume are economic conditions and
weather. Overall, 1996 weather was milder than normal; however, 1996 also had a
leap year day. These two factors were offsetting in their amounts and,
therefore, the actual retail sales for 1996 of 5,340 gigawatt-hours should be
considered about "normal". This is about the same level of 1997 sales assumed by
the DPUC in its Order; so, to the extent the Company can improve upon this sales
level, sales margin relative to the Order would improve and would mitigate any
loss of FCA revenue. The Company experienced about 1% of "real" sales growth in
1996 (i.e. exclusive of weather and leap year factors) over "normal" 1995 sales.
A similar level of growth in 1997 from all customer groups would add about $6
million to sales margin. No significant change in wholesale capacity sales
revenue is anticipated for 1997.
The Company has dealt with the potential loss of customers as a result of
self-generation, relocation or discontinuation of operations, by successfully
negotiating 45 multi-year contracts with major customers, including its largest
customer, Yale University, which is constructing a cogeneration unit that will
produce approximately one-half of this customer's electricity requirements
commencing sometime in early 1998. Additional multi-year customer contracts may
be signed in 1997. While providing cost reduction and price stability for
customers and helping the Company maintain its customer base for the long term,
these contracts are expected to lead to reductions in retail revenue that have
averaged $2-$3 million per year in the recent past.
- 39 -
The Company expects that generating output from its ownership shares in
nuclear generating units to be significantly less in 1997 than in 1996. Seabrook
Unit 1 operated at nearly a 97% capacity factor in 1996, well above the assumed
"normal" 90% level between refueling outages; and a refueling outage is expected
in the spring of 1997. A more normal level of Seabrook Unit 1 operation in 1997
and the downtime for refueling will cause the Company to purchase or generate
energy using higher cost fuels, leading to about a $3 million increase in fuel
expense. Millstone Unit 3 was taken out of service on March 30, 1996, and will
remain shut down pending a comprehensive Nuclear Regulatory Commission (NRC)
review of operations. See Item 2. Properties - "Nuclear Generation". The
Connecticut Yankee Unit was taken out of service on July 23, 1996 and, by
decision of the Board of Directors of that company, has been retired. Relative
to 1996, the loss of low cost energy from these two units for all of 1997 should
add about $6 million to fuel expense. If Millstone Unit 3 returns to service
during the year, fuel expense would decline by about $500,000 for every month of
normal operation. The increased fuel expense from the retirement of the
Connecticut Yankee Unit is expected to be offset by a ramping down of its
operating expenses. However, the ability of the Company to recover any future
costs associated with the Connecticut Yankee Unit will be dependent upon the
outcome of pending regulatory filings with the Federal Energy Regulatory
Commission.
Another major factor affecting the Company's financial condition will be
the Company's ability to control operating expenses. The Company implemented
voluntary early retirement programs for union and management employees in 1996,
as well as a voluntary severance program. The cost of these programs resulted in
a pre-tax charge of $23 million and should lead to an employee reduction of 230
employees from a level of approximately 1,300 employees at year-end. A portion
of the personnel cost savings occurred in 1996, but the majority of the savings
will be realized as the Company's process re-engineering efforts are completed
over the next several years. Incremental savings in personnel costs of $4
million in 1997 and another $6 million in 1998 are expected. Other
re-engineering savings are anticipated over this time frame as well. The Company
expects an expense increase of about $3 million for nuclear plant outages in
1997 above the levels incurred or accrued in 1996, due primarily to the planned
Seabrook Unit 1 refueling outage in the spring of 1997.
Anticipated depreciation expense should increase by $2 million in 1997 from
1996 levels, a slower rate of increase than in prior years because 1996 capital
spending of $45 million (excluding nuclear fuel) was at its lowest level in over
15 years, and also because new conservation spending is no longer to be
capitalized and depreciated. In addition, the DPUC Order required accelerated
amortization of previously capitalized conservation costs of about $6 million,
providing the Company earns at least a 10.5% return on its utility common stock
equity. These amounts are reported as "depreciation" in the Company's financial
statements.
The Company expects continued reductions in interest expense of about $9
million to a 1997 level of $61 million. This reduction is due to a refinancing
of some of the Company's debt in late 1996 described in the following paragraph,
as well as a significant paydown of debt in 1997 made possible by the Company's
excellent cash flow position. In fact, although the Company had no net change in
retained earnings in 1996, it was able to improve its equity ratio from 31.7% to
33.2% as a result of debt paydown. The anticipated 1997 interest expense level
would be 46% below the 1989 level and would mark the eighth consecutive year of
net interest expense decline.
In the fall of 1996, the Company was successful in purchasing $67 million
of the approximately $200 million principal amount of outstanding Seabrook Lease
Obligation Bonds, to hold in its own account, using proceeds from a lower cost
bank term loan. The interest income that the Company receives from its $67
million investment in these bonds appears on the income statement as a credit to
interest expense and partially offsets the interest expense incurred on the
Seabrook Lease Obligation Bonds.
The Company expects a significant improvement in unregulated subsidiary
earnings in 1997 compared to the results of 1996, due partly to the
non-recurrence of one-time pre-tax charges in 1996 totaling $4.3 million and,
also, the achievement of a near "break-even" level in earnings from subsidiary
operations, which would result in an increase in pre-tax income of $3-$4
million. In the near term, the Company's investments in these subsidiaries are
- 40 -
unlikely to have a major positive effect on earnings, but the Company continues
to believe that these investments will contribute to future earnings growth.
The Company expects the 1997 quarterly earnings from operations will follow
a pattern similar to that of 1996, with third quarter earnings contributing over
half the annual total. Summer seasonal retail sales and summer pricing are the
predominant factors contributing to this pattern. The Company only expects
15-20% of its annual earnings from operations to fall in the first quarter
(versus the 28% level in 1996) reflecting the impact of weather-adjusted sales,
leap year factors, nuclear outages, and higher fossil fuel expense. The second
and fourth quarters should be similar in amount.
On February 5, 1997, the Board of Directors of the Company, at a special
meeting, declared and reaffirmed the quarterly dividend on shares of common
stock of 72 cents per share. The common stock dividend declared will be payable
April 1, 1997 to owners of record at the close of business on March 13, 1997.
The indicated annual dividend is $2.88 per share, the annual rate in 1996.
Although the dividend level for 1996 represents a payout of 100% of total
earnings, the dividend level represented a payout of only 73% of 1996 earnings
from operations that exclude net one-time charges of $1.06 per share,
principally for non-cash restructuring charges. The Company's cash flow
remained, and is expected to remain, very strong. Net cash provided by operating
activities was $144.8 million in 1996, nearly 3.6 times the Common Dividend
payout, one of the highest such "coverage" levels in the utility industry. The
December 31, 1996 DPUC Order will limit earnings from utility operations such
that further dividend increases may have to be delayed for several years.
However, the Order should allow the Company to recover some of its regulatory
assets more rapidly, help it prepare for competition in the electric industry,
and help maintain its cash flow at its excellent current level through the end
of the decade.
With the reaffirmation of the Company's dividend at the indicated annual
rate of $2.88 per share, the Board of Directors sought to assure investors of
the security of the current dividend level. However, the ability to maintain
this dividend level, or to declare future increases for the dividend, will
depend upon the level of the Company's future earnings and cash flow, which are
dependent upon other factors and events affecting the Company's financial
condition and outlook that cannot be known at this time.
- 41 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
1996 1995 1994
---- ---- ----
OPERATING REVENUES (NOTE G) $726,020 $690,449 $656,748
------------- ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 160,517 138,169 127,354
Capacity purchased 46,830 47,420 44,769
Early retirement program charges 23,033 - -
Other 158,945 147,660 151,330
Maintenance 37,652 36,089 41,768
Depreciation 65,921 61,426 58,165
Amortization of cancelled nuclear project and deferred return (Note D and J) 13,758 13,758 1,172
Income taxes (Note A and E) 53,090 59,828 44,937
Property tax settlement - - 2,536
Other taxes (Note G) 57,139 58,943 57,325
------------- ------------ ------------
Total 616,885 563,293 529,356
------------- ------------ ------------
OPERATING INCOME 109,135 127,156 127,392
------------- ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 940 390 753
Other-net (Note G) (7,166) (4,272) (1,907)
Non-operating income taxes 9,332 4,901 3,214
------------- ------------ ------------
Total 3,106 1,019 2,060
------------- ------------ ------------
INCOME BEFORE INTEREST CHARGES 112,241 128,175 129,452
------------- ------------ ------------
INTEREST CHARGES
Interest on long-term debt 66,305 63,431 73,772
Interest on Seabrook obligation bonds owned by the company (1,259) - -
Other interest (Note G) 2,092 9,002 3,731
Allowance for borrowed funds used during construction (1,435) (2,372) (2,710)
------------- ------------ ------------
65,703 70,061 74,793
Amortization of debt expense and redemption premiums 2,629 4,138 6,570
------------- ------------ ------------
Net Interest Charges 68,332 74,199 81,363
------------- ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES 4,813 3,583 -
------------- ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 39,096 50,393 48,089
------------- ------------ ------------
Cumulative effect for years prior to 1994 of accounting
change for postemployment benefits
(net of income taxes of $956) (Note H) - - (1,294)
------------- ------------ ------------
NET INCOME 39,096 50,393 46,795
Discount on preferred stock redemptions (1,840) (2,183) -
Dividends on preferred stock 330 1,329 3,323
------------- ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $40,606 $51,247 $43,472
============= ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 14,101 14,090 14,085
EARNINGS PER SHARE OF COMMON STOCK BEFORE
CUMULATIVE EFFECT OF ACCOUNTING CHANGE $2.88 $3.64 $3.18
Cumulative effect for years prior to 1994 of accounting
change for postemployment benefits - - (0.09)
------------- ------------ ------------
EARNINGS PER SHARE OF COMMON STOCK $2.88 $3.64 $3.09
============= ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.82 $2.76
The accompanying Notes to Consolidated
Financial Statements are an integral part of the
financial statements.
- 42 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(THOUSANDS OF DOLLARS)
1996 1995 1994
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $39,096 $50,393 $46,795
------------ ------------ ------------
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation and amortization 70,363 66,958 67,336
Deferred income taxes (2,276) 27,495 9,541
Deferred investment tax credits - net (762) (762) (762)
Amortization of nuclear fuel 5,690 13,571 11,632
Cumulative effect for years prior to 1994 of accounting
change for postemployment benefits - net - - 1,294
Allowance for funds used during construction (2,375) (2,762) (3,463)
Amortization of deferred return 12,586 12,586 -
Early retirement costs accrued 23,033 - -
Sales adjustment revenue - - 13,113
Changes in:
Accounts receivable - net (23,555) 9,489 2,840
Fuel, materials and supplies 239 69 (1,140)
Prepayments (557) 9,256 (7,344)
Accounts payable 22,657 2,555 (6,578)
Interest accrued (671) (6,420) (1,046)
Taxes accrued (4,794) (11,310) 9,756
Other assets and liabilities 6,078 (9,627) (4,989)
------------ ------------ ------------
Total Adjustments 105,656 111,098 90,190
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 144,752 161,491 136,985
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 40 440 109
Long-term debt 82,500 150,000 -
Preferred securities of subsidiary - 50,000 -
Notes payable 10,965 (67,000) 67,000
Securities redeemed and retired:
Preferred stock (6,078) (34,161) (16,245)
Long-term debt (72,895) (165,103) (117,391)
Discount on preferred stock redemption 1,840 2,183 387
Expenses of issues (442) (2,222) -
Lease obligations (291) (1,169) (2,362)
Dividends
Preferred stock (410) (1,944) (3,658)
Common stock (40,399) (39,514) (38,520)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (25,170) (108,490) (110,680)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (47,174) (59,363) (63,044)
Investment in debt securities (71,084) - -
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (118,258) (59,363) (63,044)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 1,324 (6,362) (36,739)
BALANCE AT BEGINNING OF PERIOD 5,070 11,432 48,171
------------ ------------ ------------
BALANCE AT END OF PERIOD $6,394 $5,070 $11,432
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $69,669 $76,271 $75,802
============ ============ ============
Income taxes $51,415 $32,100 $25,555
============ ============ ============
The accompanying Notes to Consolidated
Financial Statements are an integral part of the
financial statements.
- 43 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
December 31, 1996, 1995 and 1994
ASSETS
(Thousands of Dollars)
1996 1995 1994
---- ---- ----
Utility Plant at Original Cost
In service $1,843,952 $1,809,925 $1,761,627
Less, accumulated provision for depreciation 585,646 532,015 493,482
-------------- -------------- --------------
1,258,306 1,277,910 1,268,145
Construction work in progress 40,998 41,817 57,669
Nuclear fuel 23,010 25,967 31,443
-------------- -------------- --------------
Net Utility Plant 1,322,314 1,345,694 1,357,257
-------------- -------------- --------------
Other Property and Investments 26,081 27,388 21,824
-------------- -------------- --------------
Current Assets
Cash and temporary cash investments 6,394 5,070 11,432
Accounts receivable
Customers, less allowance for doubtful
accounts of $2,300, $6,300 and $4,900 63,722 63,987 61,042
Other 38,367 14,547 26,981
Accrued utility revenues 29,139 28,318 23,139
Fuel, materials and supplies, at average cost 22,010 22,249 22,318
Prepayments 3,608 3,051 12,307
Other 110 55 90
-------------- -------------- --------------
Total 163,350 137,277 157,309
-------------- -------------- --------------
Deferred Charges
Unamortized debt issuance expenses 6,580 7,577 5,527
Other 1,485 2,377 2,119
-------------- -------------- --------------
Total 8,065 9,954 7,646
-------------- -------------- --------------
Regulatory Assets ((future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax
differences (Note A) 289,672 358,168 403,132
Deferred return - Seabrook Unit 1 37,757 50,343 62,929
Unamortized cancelled nuclear project 13,297 24,620 25,792
Unamortized redemption costs 25,063 22,244 26,269
Uranium enrichment decommissioning costs 1,377 1,505 1,540
Connecticut Yankee 64,851 - -
Other 9,068 8,424 11,293
-------------- -------------- --------------
Total 441,085 465,304 530,955
-------------- -------------- --------------
$1,960,895 $1,985,617 $2,074,991
============== ============== ==============
The accompanying Notes to Consolidated
Financial Statements are an integral part of the
financial statements.
- 44 -
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
December 31, 1996, 1995 and 1994
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1996 1995 1994
---- ---- ----
Capitalization (Note B)
Common stock equity
Common stock $284,579 $284,542 $284,133
Paid-in capital 772 769 738
Capital stock expense (2,182) (2,207) (2,402)
Retained earnings 156,847 156,877 145,559
-------------- -------------- --------------
440,016 439,981 428,028
Preferred stock 4,461 10,539 44,700
Minority interest in preferred securities 50,000 50,000 -
Long-term debt
Long-term debt 826,527 845,684 708,340
Investment in Seabrook obligation bonds (66,847) - -
-------------- -------------- --------------
Net Long-term debt 759,680 845,684 708,340
Total 1,254,157 1,346,204 1,181,068
-------------- -------------- --------------
Noncurrent Liabilities
Obligations under capital leases 17,193 17,508 17,799
Nuclear decommissioning obligation 12,851 10,317 7,628
Pensions accrued (Note H) 49,205 33,832 30,177
Connecticut Yankee contract obligation 54,752 - -
Other 4,815 4,090 3,854
-------------- -------------- --------------
Total 138,816 65,747 59,458
-------------- -------------- --------------
Current Liabilities
Current portion of long-term debt 69,900 40,800 193,133
Notes payable 10,965 - 67,000
Accounts payable 68,058 45,401 42,846
Dividends payable 10,205 10,072 10,467
Taxes accrued 503 5,297 16,607
Interest accrued 13,835 14,506 20,926
Obligations under capital leases 315 291 1,169
Other accrued liabilities 36,091 26,769 30,069
-------------- -------------- --------------
Total 209,872 143,136 382,217
-------------- -------------- --------------
Customers' Advances for Construction 1,888 2,655 2,628
-------------- -------------- --------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 17,147 17,909 18,671
Other 1,811 1,990 2,096
-------------- -------------- --------------
Total 18,958 19,899 20,767
-------------- -------------- --------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities) 337,204 407,976 428,853
Commitments and Contingencies (Note L)
-------------- -------------- --------------
$1,960,895 $1,985,617 $2,074,991
============== ============== ==============
The accompanying Notes to Consolidated
Financial Statements are an integral part of the
financial statements.
- 45 -
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(THOUSANDS OF DOLLARS)
1996 1995 1994
---- ---- ----
BALANCE, JANUARY 1 $156,877 $145,559 $141,725
Net income 39,096 50,393 46,795
Adjustments associated with repurchase
of preferred stock 1,815 1,988 (761)
------------- ------------- -------------
Total 197,788 197,940 187,759
------------- ------------- -------------
Deduct Cash Dividends Declared
Preferred stock 330 1,329 3,323
Common stock 40,611 39,734 38,877
------------- ------------- -------------
Total 40,941 41,063 42,200
------------- ------------- -------------
BALANCE, DECEMBER 31 $156,847 $156,877 $145,559
============ ============ ============
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial
statements.
- 46 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The United Illuminating Company (UI or the Company) is an operating
electric public utility company, 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 service area, largely
urban and suburban in character, includes the principal cities of Bridgeport
(population 137,000) and New Haven (population 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals.
In addition, the Company has created, and owns, unregulated subsidiaries.
The Board of Directors of the Company has authorized the investment of a maximum
of $27 million in the unregulated subsidiaries and, at December 31, 1996,
approximately $26 million had been invested. A wholly-owned subsidiary, United
Resources, Inc., serves as the parent corporation to American Payment Systems,
Inc., (APS) which manages a national network of agents for the processing of
bill payments made by customers of other utilities.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to use estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
(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 subsidiary, United Resources Inc. Intercompany accounts and
transactions have been eliminated in consolidation.
REGULATORY ACCOUNTING
The consolidated financial statements of the Company are in conformity with
generally accepted accounting principles and with accounting for regulated
electric utilities prescribed by the Federal Energy Regulatory Commission (FERC)
and the Connecticut Department of Public Utility Control (DPUC). Generally
accepted accounting principles for regulated entities allow the Company to give
accounting recognition to the actions of regulatory authorities in accordance
with the provisions of Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation". In accordance
with SFAS No. 71, the Company has deferred recognition of costs (a regulatory
asset) or has recognized obligations (a regulatory liability) if it is probable
that such costs will be recovered or obligation relieved in the future through
the ratemaking process. In addition to the Regulatory Assets and Liabilities
shown on the Consolidated Balance Sheet, there are other regulatory assets and
liabilities such as conservation and load management costs and certain deferred
tax liabilities. The Company also has obligations under long-term power
contracts, the recovery of which is subject to regulation.
- 47 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The effects of competition could cause the operations of the Company, or a
portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. While the Company expects to continue to
meet these criteria in the foreseeable future, if the Company, or a portion of
its assets or operations, were to cease meeting these criteria, accounting
standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs,
would be required in the year in which the criteria are no longer met. If this
change in accounting were to occur, it would have a material adverse effect on
the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
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.
The Company's utility plant in service as of December 31, 1996, 1995 and
1994 was comprised as follows:
1996 1995 1994
---- ---- ----
(000's)
Production $1,124,113 $1,122,001 $1,114,755
Transmission 160,970 158,373 143,984
Distribution 387,825 375,962 364,102
General 47,889 45,924 43,600
Future use plant 32,751 32,762 31,853
Other 90,404 74,903 63,333
---------- ---------- ----------
$1,843,952 $1,809,925 $1,761,627
========== ========== ==========
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 the
allowance applicable to major construction projects semi-annually. Weighted
average AFUDC rates in effect for 1996, 1995 and 1994 were 9.0%, 8.0% and 8.19%,
respectively.
DEPRECIATION
Provisions for depreciation on utility plant for book purposes are computed
on a straight-line basis, using estimated service lives determined by
independent engineers. One-half year's depreciation is taken in the year of
addition and disposition of utility plant, except in the case of major operating
units on which depreciation commences in the month
- 48 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
they are placed in service and ceases in the month they are removed from
service. The aggregate annual provisions for depreciation for the years 1996,
1995 and 1994 were equivalent to approximately 3.50%, 3.34% and 3.27%,
respectively, of the original cost of depreciable property.
INCOME TAXES
In accordance with Statement of Financial Accounting Standards (SFAS) No.
109 "Accounting for Income Taxes", the Company has provided deferred taxes for
all temporary book-tax differences using the liability method. The liability
method requires that deferred tax balances be adjusted to reflect enacted future
tax rates that are anticipated to be in effect when the temporary differences
reverse. In accordance with generally accepted accounting principles for
regulated industries, the Company has established a regulatory asset for the net
revenue requirements to be recovered from customers for the related future tax
expense associated with certain of these temporary differences.
For ratemaking purposes, the Company normalizes all investment tax credits
(ITC) related to recoverable plant investments except for the ITC related to
Seabrook Unit 1, which was taken into income in accordance with provisions of a
1990 DPUC retail rate decision.
ACCRUED UTILITY REVENUES
The estimated amount of utility revenues (less related expenses and
applicable taxes) for service rendered but not billed is accrued at the end of
each accounting period.
CASH AND 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 records outstanding checks as accounts payable
until the checks have been honored by the banks.
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, $3.9 million and $2.3 million, at December 31, 1996,
1995 and 1994, respectively.
INVESTMENTS
The Company's investment in the Connecticut Yankee Atomic Power Company, a
nuclear generating company in which the Company has a 9 1/2% stock interest, is
accounted for on an equity basis. This investment amounted to $10.1 million,
$9.6 million and $9.6 million at December 31, 1996, 1995 and 1994, respectively,
and is included on the Consolidated Balance Sheet in "Other Property and
Investments" at December 31, 1995 and 1994 and as a regulatory asset at December
31, 1996. See Note (L), Commitments and Contingencies - Other Commitments and
Contingencies - Connecticut Yankee.
FOSSIL FUEL COSTS
Historically, the amount of fossil fuel costs that cannot be reflected
currently in customers' bills pursuant to the fossil fuel adjustment clause in
the Company's rates has been 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 ratemaking treatment of the Company's existing deferred fossil
fuel cost balances. As a result of a December 1996 DPUC decision, the Company
will suspend this deferred
- 49 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
accounting procedure unless the average fossil fuel oil prices increase or
decrease outside a certain bandwidth prescribed in the decision.
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 POSTEMPLOYMENT BENEFITS
The Company accounts for normal pension plan costs in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No. 87,
"Employers' Accounting for Pensions", and for supplemental retirement plan costs
and supplemental early retirement plan costs in accordance with the provisions
of SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and for Termination Benefits".
The Company accounts for other postemployment benefits, consisting
principally of health and life insurance, under the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions", which
requires, among other things, that the liability for such benefits be accrued
over the employment period that encompasses eligibility to receive such
benefits. The annual incremental cost of this accrual has been allowed in retail
rates in accordance with a 1992 rate decision of the DPUC.
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 112, "Employers' Accounting for Postemployment
Benefits". This statement 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
effect of adopting this statement is reported as a charge against income in the
first quarter of 1994 due to a change in accounting principle. The charge
decreased earnings for common stock for 1994 by $1.3 million, after tax, or $.09
per share.
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, 1996, the
Company's unfunded share of the obligation, based on its ownership interest in
Seabrook Unit 1 and Millstone Unit 3, was approximately $1.3 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 $2,130,000, $1,882,000 and $1,727,000
during 1996, 1995 and 1994 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1996, the Company's share of the
trust fund balances, which include accumulated earnings on the funds, were $9.1
million and $3.8 million for Seabrook Unit 1 and Millstone
- 50 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Unit 3, respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
IMPAIRMENT OF LONG-LIVED ASSETS
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets to Be Disposed Of", which is effective for
the 1996 calendar year, requires the recognition of impairment losses on
long-lived assets when the book value of an asset exceeds the sum of the
expected future undiscounted cash flows that result from the use of the asset
and its eventual disposition. This standard also requires that rate-regulated
companies recognize an impairment loss when a regulator excludes all or part of
a cost from rates, even if the regulator allows the company to earn a return on
the remaining allowable costs. Under this standard, the probability of recovery
and the recognition of regulatory assets under the criteria of SFAS No. 71 must
be assessed on an ongoing basis. Since the Company continues to follow SFAS No.
71, it does not have any assets that are impaired under this standard.
APS REVENUES AND AGENT COLLECTIONS
During 1996, APS's agent network processed approximately $5.5 billion in
customer payments for other utilities located throughout the country through
numerous bank accounts. APS recognized revenue of $19.2 million, $6.8 million
and $1.6 million for the years 1996, 1995 and 1994, respectively, based on
established fees per payment transaction processed. Cash associated with
customer payments are the property of other utilities and have not been
reflected in UI's consolidated financial statements.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
December 31,
---------------------------------------------------------------------------------------
1996 1995 1994
Shares Shares Shares
Outstanding $(000's) Outstanding $(000's) Outstanding $(000's)
-------------- ------------ -------------- ------------ -------------- ------------
COMMON STOCK EQUITY
Common stock, no par value,
at December 31(a) 14,101,291 $284,579 14,100,091 $284,542 14,086,691 $284,133
Shares authorized
1994 30,000,000
1995 30,000,000
1996 30,000,000
Paid-in capital 772 769 738
Capital stock expense (2,182) (2,207) (2,402)
Retained earnings (b) 156,847 156,877 145,559
------------ ------------ ------------
Total common stock equity 440,016 439,981 428,028
------------ ------------ ------------
PREFERRED AND PREFERENCE STOCK (C)
Cumulative preferred stock,
$100 par value, shares
authorized at December 31,
1994 1,247,005
1995 1,180,394
1996 1,119,612
Preferred stock issues:
4.35% Series A 11,297 21,247 40,425
4.72% Series B 17,658 30,490 48,280
4.64% Series C 12,945 12,945 32,100
5 5/8% Series D 2,712 40,712 51,200
7.60% Series E - - 125,000
7.60% Series F - - 150,000
-------------- -------------- --------------
44,612 4,461 105,394 10,539 447,005 44,700
-------------- ------------ -------------- ------------ -------------- ------------
Cumulative preferred stock,
$25 par value, shares
authorized at December 31,
1994 2,400,000
1995 2,400,000
1996 2,400,000
Preferred stock issues - - - - - -
Cumulative preference stock,
$25 par value, shares
authorized at December 31,
1994 5,000,000
1995 5,000,000
1996 5,000,000
Preference stock issues - - - - - -
------------ ------------ ------------
Total preferred stock not
subject to mandatory redemption 4,461 10,539 44,700
------------ ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES (D) 50,000 50,000 -
------------ ------------ ------------
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
December 31,
-------------------------------------------------
1996 1995 1994
$(000's) $(000's) $(000's)
------------- ------------- --------------
LONG-TERM DEBT (E)
First Mortgage Bonds:
9.44%, Series B, maturing serially as
to $10,800 principal amount on February 15
in each of the years 1997 to 1999. $32,400 $43,200 $54,000
10.32%, Series C - - 55,333
Other Long-term Debt
Pollution Control Revenue Bonds:
9 1/2%, 1986 Series, due June 1, 2016 - 7,500 7,500
Variable rate, 1996 Series, due June 26, 2026 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 64,460 64,460
Solid Waste Disposal Revenue Bonds:
Adjustable rate 1990 Series A
due September 1, 2015 30,000 30,000 30,000
Notes:
6.00%, 1992 Series D, due January 15, 1995 - - 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
7 3/8%, 1992 Series G, due January 15, 1998 100,000 100,000 100,000
6.20%, 1993 Series H, due January 15, 1999 100,000 100,000 100,000
Term Loans:
6.95%, due August 29, 2000 50,000 50,000 -
6.47%, due September 6, 2000 50,000 50,000 -
6.4375%, due September 6, 2000 50,000 50,000 -
6.675%, due October 25, 2001 25,000 - -
7.005% due October 25, 2001 50,000 - -
Obligation under the Seabrook Unit 1
sale/leaseback agreement 243,660 248,030 250,000
------------- ------------- --------------
896,520 886,690 901,793
Unamortized debt discount less premium (93) (206) (320)
------------- ------------- --------------
Total long-term debt 896,427 886,484 901,473
Less:
Current portion included in Current Liabilities (e) 69,900 40,800 193,133
Investment-Seabrook sale leaseback obligation bonds 66,847 - -
------------- ------------- --------------
Total long-term debt included in Capitalization 759,680 845,684 708,340
------------- ------------- --------------
TOTAL CAPITALIZATION $1,254,157 $1,346,204 $1,181,068
============= ============= ==============
- 53 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(A) COMMON STOCK
The Company issued 1,200 shares of common stock in 1996, 13,400 shares of
common stock in 1995, and 3,400 shares of common stock in 1994 pursuant to a
stock option plan.
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 Connecticut Department of
Public Utility Control (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 17,799
shares of stock at an exercise price of $30 per share, 190,600 shares of stock
at an exercise price of $30.75 per share, 600 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, 34,332 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,
1996. Options to purchase 1,200 shares of stock at an exercise price of $30.75
per share were exercised during 1996.
In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, "Accounting for Stock-Based Compensation". This statement, which is
effective for calendar year 1996, establishes financial accounting and reporting
standards for stock-based employee compensation plans, such as stock purchase
plans, stock options, restricted stock, and stock appreciation rights. The
statement defines the methods of determining the fair value of stock-based
compensation and requires the recognition of compensation expense for book
purposes. However, the statement allows entities to continue to measure
compensation expense in accordance with the prior authoritative literature, APB
No. 25, "Accounting for Stock Issued to Employees", but requires that pro forma
net income and earnings per share be disclosed for each year for which an income
statement is presented as if SFAS No. 123 had been applied. The accounting
requirements of this statement are effective for transactions entered into in
1996. However, pro forma disclosures must include the effects of all awards
granted after January 1, 1995. As of December 31, 1996, there were no options
granted to which this statement would apply. The Company has not elected to
adopt the expense recognition provisions of SFAS No. 123.
(B) RETAINED EARNINGS RESTRICTION
The indenture under which the Company's 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 $98.7 million
were free from such limitations at December 31, 1996.
(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.
On April 15, 1994, the Company redeemed all of the 600,000 outstanding
shares of its 8.80% Preferred Stock, 1976 Series, at $25.25 per share plus
accrued dividends.
In July 1994, the Company purchased 2,450 shares of its 4.72% $100 par
value Preferred Stock, Series B, at a discount, resulting in a non-taxable gain
of $116,000.
In December 1994, the Company purchased 10,000 shares of its 5 5/8% $100
par value Preferred Stock, Series D, at a discount, resulting in a non-taxable
gain of $420,000.
- 54 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On April 10, 1995, the Company called for redemption all 125,000 shares of
its outstanding $100 par value 7.60% Preferred Stock, Series E and all 150,000
shares of its outstanding $100 par value 7.60% Preferred Stock, Series F. The
Company paid a redemption premium of $275,000 in effecting these redemptions,
which were completed on May 10, 1995.
On May 10, 1995, the Company made a tender offer for all of the shares of
its outstanding $100 par value 4.35% Preferred Stock, Series A, 4.72% Preferred
Stock, Series B, 4.64% Preferred Stock, Series C, and 5.625% Preferred Stock,
Series D. On June 12 and July 17, 1995, the Company purchased and retired, at a
discount of $2,457,531, 19,178 shares of the Series A, 17,790 shares of the
Series B, 19,155 shares of the Series C and 10,488 shares of the Series D
preferred stock issues.
On June 4, 1996, the Company purchased at a discount on the open market,
and canceled, 53,450 shares of its $100 par value preferred stock. The shares
purchased consisted of 2,950 shares of its 4.35%, Series A, 12,500 shares of its
4.72%, Series B and 38,000 shares of its 5 5/8%, Series D, preferred stock. The
shares, having a par value of $5,345,000, were purchased for $3,816,169,
creating a net gain of $1,528,831.
On June 7, 1996, the Company purchased at a discount on the open market,
and canceled, 7,000 shares of its $100 par value 4.35%, Series A preferred
stock. The shares, having a par value of $700,000, were purchased for $402,730,
creating a net gain of $297,270.
On August 8, 1996, the Company purchased at a discount on the open market,
and canceled, 332 shares of its $100 par value 4.72%, Series B preferred stock.
The shares, having a par value of $33,200, were purchased for $19,488, creating
a net gain of $13,712.
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,
1996.
(D) PREFERRED CAPITAL SECURITIES
On April 3, 1995, United Capital Funding Partnership L.P. ("United
Capital"), a special purpose limited partnership in which the Company owns all
of the general partner interests, issued $50 million of its monthly income 9
5/8% Preferred Capital Securities, Series A, ("Preferred Capital Securities")
representing limited partnership interests in United Capital. United Capital
loaned the proceeds of the issuance and sale of the Preferred Capital Securities
to the Company in return for the Company's 9 5/8% Junior Subordinated Deferrable
Interest Debentures, Series A, Due 2025. The net proceeds to the Company,
approximately $48.4 million, were used to redeem, on May 10, 1995, $12.5 million
of outstanding $100 par value 7.60% Preferred Stock, Series E (including a
redemption premium of $125,000) and $15.0 million of outstanding $100 par value
7.60% Preferred Stock, Series F (including a redemption premium of $150,000) and
to reduce short-term borrowings.
United Capital and the Company have registered an additional $50 million of
Capital Securities and/or Subordinated Debentures for sale to the public from
time to time, in one or more series, under the Securities Act of 1933.
- 55 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(E) LONG-TERM DEBT
On February 15, 1996, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric
Company, a wholly-owned subsidiary of the Company that was merged with and into
the Company in September 1994.
On June 26, 1996, the Company borrowed $7.5 million from the Connecticut
Development Authority (CDA), representing the proceeds from the issuance by the
CDA of $7.5 million principal amount of tax-exempt Pollution Control Revenue
Bonds (PCRBs). The Company is obligated, under its borrowing agreement with the
CDA, to pay to a trustee for the PCRBs' bondholders such amounts as will pay,
when due, the principal of and the premium, if any, and interest on the PCRBs.
The PCRBs will mature in 2026, and their interest rate can be adjusted
periodically to reflect prevailing market conditions. The PCRBs were issued at
an initial interest rate of 3.3%, which is being adjusted weekly. On July 15,
1996, the Company used the proceeds of this $7.5 million borrowing to cause the
redemption and repayment of $7.5 million principal amount of 9 1/2% PCRBs issued
by the CDA in 1986.
On October 25, 1996, the Company borrowed $75 million under a Term Loan
Agreement with a group of banks for a five-year period. The Company pays
interest on the borrowing at a floating rate equal to the three-month London
Interbank Borrowing Rate plus 0.55%. The Company has entered into two separate
interest rate swap agreements that effectively convert the interest rate on $50
million of the Company's floating rate 1996 Term Loan to a fixed annual interest
rate of 7.005% for the five-year period and the interest rate on the remaining
$25 million to a fixed annual interest rate of 6.675% for a three-year period.
The Company used proceeds from the $75 million Term Loan borrowing to
purchase approximately $66.8 million principal amount of Seabrook Lease
Obligation Bonds, which were issued in connection with the sale and leaseback by
the Company of a portion of its ownership share in Seabrook Unit 1 in 1990. The
Bonds were purchased at a premium through a tender offer that expired on October
22, 1996. The Company paid 103.9% of principal amount for approximately $17.0
million principal amount of 9.76% Seabrook Lease Obligation Bonds (due 2006) and
107.17% of principal amount for approximately $49.9 million principal amount of
the 10.24% Seabrook Lease Obligation Bonds (due 2020). The premiums and other
transaction expenses will be amortized over the remaining life of the Bonds. The
Company intends to hold the Bonds until maturity and has recognized the
investment as an offset to long-term debt on its Consolidated Balance Sheet.
On December 30, 1996, the Company transferred $51.3 million to a trustee
under an escrow agreement. The funds, which were invested in Treasury Notes,
were used to pay $50 million principal amount of 7% Notes that matured on
January 15, 1997 plus accrued interest.
On February 15, 1997, the Company repaid $10.8 million principal amount of
maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of
$185,328, the remaining $21.6 million outstanding principal amount of 9.44%
First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a
wholly-owned subsidiary of the Company that was merged with and into the Company
in September 1994.
- 56 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Maturities and mandatory redemptions/repayments are set forth below:
[Download Table]
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(000's)
Maturities $ - $100,000 $100,000 $150,000 $75,000
Mandatory redemptions/repayments 10,800 4,635 5,051 5,507 6,003
Optional Redemptions 21,600 - - - -
------- -------- -------- -------- -------
Maturities, Mandatory and Optional
redemptions/repayments (1) $32,400 $104,635 $105,051 $155,507 $81,003
======= ======== ======== ======== =======
(1) Does not include $30 million of tax-exempt adjustable rate Solid Waste
Disposal Revenue Bonds, 1990 Series A, due September 1, 2015, or $7.5
million of tax-exempt variable rate Pollution Control Revenue Bonds, 1996
Series, due June 26, 2026 classified on the Company's Consolidated Balance
Sheet as current liabilities.
The Company has registered $200 million principal amount of Notes for sale
to the public from time to time, in one or more series, under the Securities Act
of 1933. In addition, the Company has registered $213.6 million of Seabrook Unit
1 Secured Lease Obligation Bonds for sale to the public under the Securities Act
of 1933. These Lease Obligation Bonds may only be used to refinance the
outstanding Seabrook Unit 1 Lease Obligation Bonds.
(C) RATE-RELATED REGULATORY PROCEEDINGS
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.
However, a company may earn up to 1% above this level for six consecutive months
before a mandatory review is required by the DPUC. A Connecticut statute
requires the DPUC to review and investigate the financial and operating records
of each electric utility company, at intervals of not more than four years, to
determine whether the company's rates comply with statutory standards.
In March 1996, the Company filed with the DPUC, for its approval, a
proposed price stability and incentive regulation plan. The purpose of this plan
was to help address the challenges of an increasingly competitive electric
utility industry and to help position the Company to face and meet these
challenges. The Company had proposed, as part of the plan, to have no increase
in base rates charged to retail customers through December 31, 2001, to afford
its customers additional price stability during this period by modifying the
operation of the fossil fuel adjustment clause mechanism in retail rates so that
customers can expect that this clause will not affect their bills, to depreciate
its Seabrook plant investment more rapidly during this period, and to establish
a performance-based ratemaking mechanism in which performance would be measured
by customer satisfaction and reliability of service, all subject to a minimum
and maximum return on common equity. This plan was designed to allow the Company
to continue the application of SFAS No. 71 and to recover its costs of providing
service through rates.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997-2001. The DPUC did not change the retail base rates charged to customers.
Its order increased amortization of the Company's conservation and load
management program investments during 1997-1998, accelerated the recovery of
unspecified regulatory assets during 1999-2001, reduced the level of
conservation adjustment mechanism revenues in retail rates, provided a reduction
in customer bills through a surcredit in each of the five plan years, and
accepted the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on common equity was reduced
from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer bill reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. The DPUC
did not order
- 57 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the accelerated depreciation of the Company's Seabrook Unit 1 plant investment
costs and the establishment of a performance-based regulation mechanism measured
by customer satisfaction surveys and reliability of service indices, which the
Company had proposed. As a result of the DPUC's order, customer bills are
expected to be reduced on average by 3% in 1997-1999, 4% in the year 2000, and
5% in the year 2001 (all compared to 1996).
The Company is allowed revenue increases for conservation and load
management expenditures through a Conservation Adjustment Mechanism (CAM) in its
retail rates, and accordingly received a revenue increase in 1996 of
approximately $12 million, or 2%, through operation of the CAM.
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. As a result of the DPUC Order described above, the Company's FCA
has been modified so that the clause will not be implemented unless the monthly
average price for fuel oil increases above $28 per barrel or decreases below $10
per barrel for six consecutive months.
(D) ACCOUNTING FOR PHASE-IN PLAN
The Company phased into rate base its allowable investment in Seabrook Unit
1, amounting to $640 million, during the period January 1, 1990 to January 1,
1994. In conjunction with this phase-in plan, the Company was allowed to record
a deferred return on the portion of allowable investment excluded from rate base
during the phase-in period. Accordingly, the Company is amortizing the net of
tax accumulated deferred return of $62.9 million over a five-year period that
commenced January 1, 1995.
- 58 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(E) INCOME TAXES
1996 1995 1994
---- ---- ----
Income tax expense consists of: (000's)
Income tax provisions:
Current
Federal $35,398 $18,031 $24,190
State 11,398 10,163 8,754
----------- ------------ ------------
Total current 46,796 28,194 32,944
----------- ------------ ------------
Deferred
Federal 616 24,682 11,123
State (2,892) 2,813 (2,538)
----------- ------------ ------------
Total deferred (2,276) 27,495 8,585
----------- ------------ ------------
Investment tax credits (762) (762) (762)
----------- ------------ ------------
Total income tax expense $43,758 $54,927 $40,767
=========== ============ ============
Income tax components charged as follows:
Operating expenses $53,090 $59,828 $44,937
Other income and deductions - net (9,332) (4,901) (3,214)
Cumulative effect of change in accounting
for postemployment benefits - - (956)
----------- ------------ ------------
Total income tax expense $43,758 $54,927 $40,767
=========== ============ ============
The following table details the components of the deferred income taxes:
Pension benefits ($9,066) ($1,460) $148
Tax depreciation on unrecoverable plant investment 5,745 8,889 8,170
Accelerated depreciation 5,617 9,410 11,526
Cancelled nuclear project (4,729) (467) (467)
Deferred fossil fuel costs 755 (122) (37)
Postretirement benefits 665 163 169
Seabrook sale/leaseback transaction (598) (397) (2,039)
Conservation & load management (367) 804 1,897
Alternative minimum tax - 11,404 -
Sales adjustment revenues - - (5,553)
Property tax adjustment - - (1,991)
Postemployment benefits - - (956)
Other - net (298) (729) (2,282)
----------- ------------ ------------
Deferred income taxes - net ($2,276) $27,495 $8,585
=========== ============ ============
- 59 -
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:
[Enlarge/Download Table]
1996 1995 1994
---- ---- ----
PRE-TAX TAX PRE-TAX TAX PRE-TAX TAX
------- ----- ------- ----- ------- -----
(000's)
Computed tax at federal statutory rate $28,999 $36,862 $30,646
Increases (reductions) resulting from:
Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 - -
ITC taken into income (762) (762) (762) (762) (762) (762)
Allowance for equity funds used during
construction (940) (329) (390) (136) (753) (263)
Book depreciation in excess of
non-normalized tax depreciation 22,703 7,946 21,586 7,555 20,625 7,218
State income taxes, net of federal
income tax benefits 8,506 5,529 12,976 8,434 6,216 4,040
Other items - net (5,797) (2,029) (4,090) (1,431) (320) (112)
------- ------- -------
Total income tax expense $43,759 $54,927 $40,767
======= ======= =======
Book Income Before Federal Income Taxes $82,855 $105,320 $87,561
======= ======== =======
Effective income tax rates 52.8% 52.1% 46.6%
======= ======== =======
At December 31, 1996 the Company had deferred tax liabilities for taxable
temporary differences of $463 million and deferred tax assets for deductible
temporary differences of $126 million, resulting in a net deferred tax liability
of $337 million. Significant components of deferred tax liabilities and assets
were as follows: tax liabilities on book/tax plant basis differences and on the
cumulative amount of income taxes on temporary differences previously flowed
through to ratepayers, $290 million; tax liabilities on normalization of
book/tax depreciation timing differences, $116 million and tax assets on the
disallowance of plant costs, $56 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 Company had no AMT carryforward at December 31, 1996 and 1995. The AMT
carryforward at December 31, 1994 was $11.4 million.
(F) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 10, 1997. 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, 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, 1996, the Company had no short-term borrowings outstanding under this
facility.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1996, this coverage ratio was 2.78.
Information with respect to short-term borrowings under the Company's
revolving credit agreement is as follows:
[Enlarge/Download Table]
1996 1995 1994
---- ---- ----
(000's)
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $30,000 $195,000 $75,000
Average aggregate short-term borrowings outstanding during the year* $15,380 $117,980 $57,000
Weighted average interest rate* 5.72% 6.5% 4.8%
Principal amounts outstanding at year-end $0 $0 $67,000
Annualized interest rate on principal amounts outstanding at year-end N/A N/A 6.7%
*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 $130,000, $426,500 and $250,400 paid during 1996, 1995 and
1994, respectively, are excluded from the calculation of the weighted average
interest rate.
- 61 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
1996 1995 1994
---- ---- ----
(000's)
OPERATING REVENUES
------------------
Retail $649,876 $639,108 $618,868
Wholesale - capacity 7,686 6,601 7,162
- energy 65,158 41,631 27,765
Other 3,300 3,109 2,953
------------- ------------- --------------
Total Operating Revenues $726,020 $690,449 $656,748
============= ============= ==============
SALES BY CLASS(MWH'S)
---------------------
Retail
Residential 1,891,988 1,890,575 1,892,955
Commercial 2,258,501 2,273,965 2,285,942
Industrial 1,141,109 1,126,458 1,135,831
Other 48,291 48,435 48,718
------------- ------------- --------------
5,339,889 5,339,433 5,363,446
Wholesale 2,260,423 1,708,837 1,283,492
------------- ------------- --------------
Total Sales by Class 7,600,312 7,048,270 6,646,938
============= ============= ==============
OTHER TAXES
-----------
Charged to:
Operating:
State gross earnings $26,757 $27,379 $27,403
Local real estate and personal property 24,854 25,761 26,318
Payroll taxes 5,528 5,800 6,137
Other - 3 3
------------- ------------- --------------
57,139 58,943 59,861
Nonoperating and other accounts 628 527 41
------------- ------------- --------------
Total Other Taxes $57,767 $59,470 $59,902
============= ============= ==============
OTHER INCOME AND (DEDUCTIONS) - NET
-----------------------------------
Interest and dividend income $1,505 $2,624 $2,520
Equity earnings from Connecticut Yankee 1,225 1,440 1,539
Loss from subsidiary companies (8,422) (4,898) (4,382)
Engineering study costs - (849) (1,200)
Miscellaneous other income and (deductions) - net (1,474) (2,589) (384)
------------- ------------- --------------
Total Other Income and (Deductions) - net ($7,166) ($4,272) ($1,907)
============= ============= ==============
OTHER INTEREST CHARGES
----------------------
Notes Payable $882 $7,660 $2,713
Other 1,210 1,342 1,018
------------- ------------- --------------
Total Other Interest Charges $2,092 $9,002 $3,731
============= ============= ==============
- 62 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(H) PENSION AND OTHER BENEFITS
The Company's qualified pension plan, which is based on the highest three
years of pay, covers substantially all of its employees, and its entire cost is
borne by the Company. The Company also has a non-qualified supplemental plan for
certain executives and a non-qualified retiree only plan for certain early
retirement benefits. The net pension costs for these plans for 1996, 1995 and
1994 were $18,403,000, $3,842,000 and $4,028,000, respectively.
The Company's funding policy for the qualified plan is to make annual
contributions that satisfy the minimum funding requirements of ERISA but that do
not exceed the maximum deductible limits of the Internal Revenue Code. These
amounts are determined each year as a result of an actuarial valuation of the
plan. In accordance with this policy, the Company contributed $3.3 million in
1994 for 1993 funding requirements and $3.9 million in 1994 for 1994 funding
requirements. No pension fund contributions were made in 1995. In 1996, the
Company contributed $2.8 million for 1995 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. During 1996, the Company
established a supplemental retirement benefit trust and through this trust
purchased life insurance policies on the officers of the Company to fund the
future liability under the supplemental plan. The cash surrender value of these
policies is shown as an investment on the Company's Consolidated Balance Sheet.
The qualified plan's irrevocable trust fund consists principally of equity
and fixed-income securities and real estate investments in approximately the
following percentages at December 31, 1996:
PERCENTAGE OF
ASSET CATEGORY TOTAL FUND
-------------- -------------
Equity Securities 70.2%
Fixed-income Securities 25.5%
Real Estate 4.3%
1996 1995
---- ----
(000's)
The components of net pension costs were as follows:
Service cost of benefits earned during the period $ 4,456 $ 3,680
Interest cost on projected benefit obligation 15,882 15,217
Actual return on plan assets (24,167) (41,166)
Net amortization and deferral 6,336 26,111
------- -------
Net pension cost $ 2,507* $ 3,842
======= =======
* In addition, a cost of $15,896,000 was recognized under SFAS No. 88 as a
result of special termination benefits provided under the Pension Plan.
Assumptions used to determine pension costs were:
Discount rate 7.25% 8.50%
Average wage increase 4.50% 5.50%
Return on plan assets 9.00% 9.00%
- 63 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
DECEMBER 31, 1996 DECEMBER 31, 1995
----------------- -----------------
QUALIFIED NON-QUALIFIED QUALIFIED NON-QUALIFIED
PLAN PLANS PLAN PLANS
---- ----- ---- -----
(000's)
The funded status and amounts recognized in the
balance sheet are as follows:
Actuarial present value of benefit obligations:
Vested benefit obligation $165,919 $4,512 $153,473 $3,877
======== ====== ======== ======
Accumulated benefit obligation $174,253 $4,512 $160,266 $3,877
======== ====== ======== ======
Reconciliation of accrued pension liability:
Projected benefit obligation $227,631 $5,152 $217,698 $4,746
Less fair value of plan assets 208,863 - 195,104 -
-------- ------ -------- ------
Projected benefit greater than plan assets 18,768 5,152 22,594 4,746
Unrecognized prior service cost (5,078) (81) (5,510) (96)
Unrecognized net gain (loss) from past experience 21,038 (28) 1,832 (233)
Unrecognized net asset (obligation)
at date of initial application 9,554 (120) 10,662 (163)
-------- ------ -------- ------
Accrued pension liability $ 44,282 $4,923 $ 29,578 $4,254
======== ====== ======== ======
Assumptions used in estimating benefit obligations:
Discount rate 7.75% 7.75% 7.25% 7.25%
Average wage increase 4.50% 4.50% 4.50% 4.50%
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. 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 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 established a Voluntary Employees'
Benefit Association Trust (VEBA) to fund OPEB for union employees who retire on
or after January 1, 1994. Approximately 47% of the Company's employees are
represented by Local 470-1, Utility Workers Union of America, AFL-CIO, for
collective bargaining purposes. The Company established a 401(h) account in
connection with the qualified pension plan to fund OPEB for non-union employees
who retire on or after January 1, 1994. The funding policy assumes contributions
to these trust funds to be the total OPEB expense calculated under SFAS No. 106,
adjusted to reflect a share of amounts expensed as a result of the Company's
1993 reorganization and 1996 early retirement program minus pay-as-you-go
benefit
- 64 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $1.8
million, $3.1 million and $3.8 million to the union VEBA in 1994, 1995 and 1996,
respectively. The Company contributed $2.2 million, $0, and $0.9 million to the
401(h) account in 1994, 1995 and 1996, respectively. Plan assets for both the
union VEBA and 401(h) account consist primarily of equity and fixed-income
securities.
The components of the net cost of OPEB were as follows:
1996 1995
---- ----
(000's)
Service cost $1,379 $1,106
Interest cost 2,524 2,584
Actual return on plan assets (1,838) (2,081)
Amortizations and deferrals - net 2,359 2,882
------ -------
Net Cost of Postretirement Benefit $4,424* $4,491
====== ======
*In addition, a cost of $4,126,000 was recognized as a result of special
termination programs.
Assumptions used to determine OPEB costs were:
Discount rate 7.25% 8.5%
Health Care Cost Trend Rate 5.50% 6.5%
Return on plan assets 8.50% 8.5%
A one percentage point increase in the assumed health care cost trend rate would
have increased the aggregate service cost and interest cost components of the
1996 net cost of periodic postretirement benefit by approximately $600,000 and
would increase the accumulated postretirement benefit obligation for health care
benefits by approximately $3,000,000.
The following table reconciles the funded status of the plan with the
amount recognized in the Consolidated Balance Sheet as of December 31, 1996 and
1995:
1996 1995
---- ----
(000's)
Accumulated Postretirement Benefit Obligation:
Retirees and dependents $22,614 $ 22,720
Fully eligible active plan participants 929 764
Other active plan participants 12,677 16,955
------ ------
Total Accumulated Postretirement Benefit Obligation 36,220 40,439
Plan assets at fair value 16,720 11,148
------ ------
Accumulated Postretirement Benefit Obligation in
Excess of Plan Assets 19,500 29,291
Unrecognized net gain (loss) 2,731 (8,395)
Unamortized transition obligation (19,443) (20,659)
------ ------
Accrued Postretirement Benefit Obligation $ 2,788 $ 237
====== ====
- 65 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The weighted average discount rates used to measure the accumulated
postretirement benefit obligation at December 31, 1996 and 1995 were 7.75% and
7.25%, respectively.
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 112, "Employers' Accounting for Postemployment
Benefits". This statement 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
effect of adopting this statement is reported as a charge against income in the
first quarter of 1994 due to a change in accounting principle. The charge
decreased earnings for common stock for 1994 by $1.3 million, after tax, or $.09
per share.
The Company has an Employee Savings Plan (401(k) Plan) in which
substantially all employees are eligible to participate. The 401(k) Plan enables
employees to defer receipt of up to 15% of their compensation and to invest such
funds in a number of investment alternatives. The Company makes matching
contributions in the form of Company common stock for each employee. During
1994, 1995 and the first five months of 1996, the matching contributions were
made into the 401(k) Plan. Beginning in June 1996, the matching contributions
were made into the Employee Stock Ownership Plan (ESOP). The Company's matching
contributions to the 401(k) Plan during the first five months of 1996 and the
years 1995 and 1994 were $0.8 million, $1.6 million and $1.6 million,
respectively. In June 1996, all shares of the Company's common stock in the
401(k) Plan were transferred to the ESOP.
The Company has an ESOP for substantially all its employees. In June 1996,
the Company began making matching contributions to the ESOP based on each
employee's salary deferrals in the 401(k) Plan. The matching contribution
currently equals fifty cents for each dollar of the employee's compensation
deferred, but is not more than three and one-eighth percent of the employee's
annual salary. The Company's matching contribution to the ESOP during the period
June 1996 - December 1996 was $0.8 million.
The Company pays dividends on the shares of stock in the ESOP to the
participant and the Company receives a tax deduction on the dividends paid. The
participant is given the option of reinvesting the dividends into the ESOP, as
an after-tax contribution. The Company also makes an annual contribution to the
ESOP equal to 25% of the dividends paid to each participant. The Company's
annual contributions during 1996, 1995 and 1994 were $324,000, $192,000 and $0,
respectively.
(I) JOINTLY OWNED PLANT
At December 31, 1996, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT IN ACCUMULATED
SHARE SERVICE DEPRECIATION
--------- -------- ------------
(Millions)
Seabrook Unit 1 17.5 % $646 $112
Millstone Unit 3 3.685 134 56
New Haven Harbor Station 93.7 140 71
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.
- 66 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(J) UNAMORTIZED CANCELLED NUCLEAR PROJECT
From December 1984 through December 1992, the Company had been recovering
its investment in Seabrook Unit 2, a partially constructed nuclear generating
unit that was cancelled in 1984, over a regulatory approved ten-year period
without a return on its unamortized investment. In the Company's 1992 rate
decision, the DPUC adopted a proposal by the Company to write off its remaining
investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period,
corresponding with the flowback of certain Connecticut Corporation Business Tax
(CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit
2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not
deducted from rate base during the 24-year period of amortization in recognition
of a longer period of time for amortization of the Seabrook Unit 2 balance.
(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 may acquire and/or store natural gas, coal and
fuel oil for sale to the Company, and the Company may purchase these fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in purchasing and
storing the fuel, plus a charge for maintaining an inventory of the fuel
determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to March 1998. At December 31, 1996, approximately $24.1 million of fossil fuel
purchases were being financed under this agreement.
The Company has leases (one is a capital lease), that include arrangements
for data processing equipment, office equipment, vehicles and office space. The
gross amount of assets recorded under capital leases and the related obligations
of those leases as of December 31, 1996 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:
(000's)
1997 $ 1,715
1998 1,715
1999 1,696
2000 1,696
2001 1,696
After 2001 19,392
------
Total minimum capital lease payments 27,910
Less: Amount representing interest 10,402
------
Present value of minimum capital lease payments $17,508
======
In January 1994, the Company renegotiated a lease agreement for a service
facility. Since the effect of renegotiating the lease, which continues to be
treated as a capital lease, was a noncash financing activity during 1994, it is
not reflected in the Consolidated Statement of Cash Flows.
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.
- 67 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Rental payments charged to operating expenses in 1996, 1995 and 1994
amounted to $12.8 million, $11.5 million and $12.1 million, respectively.
Operating leases, which are charged to operating expense, consist
principally of a large number of small, relatively short-term, renewable
agreements for a wide variety of equipment. In addition, the Company has an
operating lease for its corporate headquarters. Future minimum lease payments
under this lease are estimated to be as follows:
(000's)
1997 $ 5,826
1998 6,125
1999 6,426
2000 6,524
2001 6,837
2002-2012 108,502
-------
Total $140,240
=======
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at approximately $228.9 million, excluding AFUDC, for 1997 through 2001.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $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 $23.2 million per
incident. However, assessment would be limited to $3.1 million per incident, per
year. With respect to each of the 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 each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance.
Although each of these units has purchased $2.75 billion of property
insurance coverage, representing the limits of coverage currently available from
conventional nuclear insurance pools, the cost of a nuclear incident could
exceed
- 68 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
available insurance proceeds. In addition, two of the nuclear insurance pools
that provide portions of this coverage may levy assessments against the insured
owner companies if pool losses exceed the accumulated funds available to the
pool. The maximum potential assessments against the Company with respect to
losses occurring during current policy years are approximately $7.5 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee
and relied on the Connecticut Yankee Unit for approximately 3.7% of the
Company's 1995 total generating resources. The power purchase contract under
which the Company has purchased its 9.5% entitlement to the Connecticut Yankee
Unit's power output will permit Connecticut Yankee to recover UI's share of
these costs from UI. Connecticut Yankee has filed revised decommissioning cost
estimates and amendments to the power contracts with its owners, including UI,
with the Federal Energy Regulatory Commission (FERC). The preliminary estimate
of the amount of future payments for the closing, decommissioning and recovery
of the remaining investment in Connecticut Yankee is approximately $763 million.
Based on regulatory precedent, Connecticut Yankee believes it will continue to
collect from its owners its decommissioning costs, the owners' unrecovered
investment in Connecticut Yankee and other costs associated with the permanent
shutdown of the Connecticut Yankee Unit. UI expects that it will continue to be
allowed to recover all FERC-approved costs from its customers through retail
rates. The Company's estimate of its remaining share of costs, less return of
investment (approximately $10 million) and return on investment (approximately
$7.6 million), is approximately $54.8 million. This estimate, which is subject
to ongoing review and revision, has been recorded by the Company as a regulatory
asset and an obligation on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase II of this facility, in
which UI has a 5.45% participating share, increased the capacity value of the
intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A ten-year
Firm Energy Contract, which provides for the sale of 7 million megawatt-hours
per year by Hydro-Quebec to the New England participants in the Phase II
facility, became effective on July 1, 1991. The Company is obligated to furnish
a guarantee for its participating share of the debt financing for the Phase II
facility. As of December 31, 1996, the Company's guarantee liability for this
debt was approximately $8.1 million.
VOLUNTARY EARLY RETIREMENT AND SEPARATION PROGRAMS
On May 22, 1995, the Company and the union representing approximately 695
of its operating, maintenance and clerical employees agreed on a three-year
contract, effective May 16, 1995. As part of this agreement, the Company offered
a voluntary early retirement program to 74 employees, who had until January 31,
1996 to accept. The early retirement offer was accepted by 64 employees, and the
Company recognized a charge to earnings in January 1996 of $7.2 million ($4.2
million, after-tax). The employees accepting the offer retired during the first
nine months of 1996. In June 1996, the Company recognized an additional charge
to earnings of $0.9 million ($0.5 million, after-tax) to reflect additional
early retirement costs.
In July 1996, the Company offered a Voluntary Early Retirement Plan and a
Voluntary Separation Plan to virtually all of its employees. A total of 163
employees accepted one or the other of these plans. In the third quarter of
1996, the
- 69 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Company recognized a charge to earnings of $14.9 million ($8.7 million,
after-tax) to reflect the cost of these plans. The employees accepting the offer
will retire on or before December 30, 1997.
PROPERTY TAXES
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. The Company is contesting each of these actions
by the City's tax assessor vigorously. On January 9, 1996, the Connecticut
Superior Court granted the Company's motion for summary judgment against the
City relative to the "updated" personal property tax bills for the tax year
1991-1992. The City appealed to the Appellate Court from the Superior Court
decision, which decision would also be applicable to and defeat the valuation
increases for the tax years 1992-1993 and 1993-1994 if it is sustained on
appeal. In June 1996, the Connecticut Supreme Court transferred this appeal to
its docket. The case was argued before the Connecticut Supreme Court in December
1996, and a decision is anticipated in the spring of 1997. It is the present
opinion of the Company that the ultimate outcome of this dispute will not have a
significant impact on the financial position of the Company.
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water and air quality (particularly "air toxics"
and "global warming"), hazardous waste handling and disposal, toxic substances,
and electric and magnetic fields, the Company may incur substantial capital
expenditures for equipment modifications and additions, monitoring equipment and
recording devices, and it may incur additional operating expenses. Litigation
expenditures may also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful health effects of
electric and magnetic fields. The total amount of these expenditures is not now
determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its decommissioned and demolished Steel Point Station and completing
requisite environmental remediation of the site will be approximately $11.3
million, of which approximately $7.7 million had been incurred as of December
31, 1996, and that the value of the property following remediation will not
exceed $6.0 million. As a result of a 1992 Connecticut Department of Public
Utility Control retail rate decision, beginning January 1, 1993, the Company has
been recovering through retail rates $1.075 million of these remediation costs
per year. The remediation cost, property value and recovery from customers will
be subject to true-up in the Company's next retail rate proceeding based on
actual remediation costs and actual gain on the Company's disposition of the
property.
- 70 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(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 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 January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010 and possibly
not earlier than 2013, 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.
The DOE also announced that, absent a repository, the DOE has no statutory
obligation to begin taking high level wastes and spent nuclear fuel for disposal
by January 1998. However, numerous utilities and states have obtained a judicial
declaration that the DOE has a statutory responsibility to take title to and
dispose of high level wastes and spent nuclear fuel beginning in January 1998.
It is unclear at this time whether the United States Congress will enact
legislation to address spent fuel/high level waste disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
normal operation of nuclear generating units have increased significantly in
recent years and are expected to continue to rise. The cost increases are a
function of increased packaging and transportation costs and higher fees and
surcharges charged by the disposal facilities. Currently, the Chem Nuclear LLW
facility at Barnwell, South Carolina, is open to the Connecticut Yankee Unit,
Millstone Unit 3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW
facility at Clive, Utah, is also open to these generating units for portions of
their LLW. All three units have contracts in place for LLW disposal at these
disposal facilities.
Because access to LLW disposal may be lost at any time, the Connecticut
Yankee Unit, Millstone Unit 3 and Seabrook Unit 1 have storage plans that will
allow on-site retention of LLW for at least five years in the event that
disposal is interrupted.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
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
- 71 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
UI has interests estimate decommissioning costs for the units and attempt to
recover sufficient amounts through their allowed electric rates, together with
earnings on the investment of funds so recovered, to cover expected
decommissioning costs. Changes in NRC requirements or technology, as well as
inflation, can increase estimated decommissioning costs.
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $451 million (in 1997 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $79 million. This estimate assumes the prompt removal and
dismantling of the Unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1996 was $1.6 million. UI's share of the fund at December 31, 1996 was
approximately $9.1 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $463 million (in 1997 dollars), of which the
Company's share would be approximately $17 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during 1996 was $487,000. UI's share of the fund at December 31, 1996 was
approximately $3.8 million. The decommissioning trust fund for the Connecticut
Yankee Unit is also managed by NU. For the Company's 9.5% equity ownership in
Connecticut Yankee, decommissioning costs of $1.4 million were funded by UI
during 1996, and UI's share of the fund at December 31, 1996 was $19.4 million.
The current decommissioning cost estimate for the Connecticut Yankee Unit,
assuming the prompt removal and dismantling of the unit commencing in 1997, is
$436 million, of which UI's share would be $41 million.
The Financial Accounting Standards Board (FASB) has issued an exposure
draft related to the accounting for the closure and removal costs of long-lived
assets, including nuclear plant decommissioning. If the proposed accounting
standard were adopted, it may result in higher annual provisions for
decommissioning to be recognized earlier in the operating life of nuclear units
and an accelerated recognition of the decommissioning obligation. The FASB will
be deliberating this issue, and the resulting final pronouncement could be
different from that proposed in the exposure draft.
(N) PROPERTY TAX SETTLEMENT
In December 1994, the Company and the City of Bridgeport settled a dispute
regarding past taxes payable by the Company on its personal property in that
city and agreed upon a method of valuation of personal property for tax purposes
for future periods. As a result of the settlement agreement, the Company
recognized a non-recurring charge to 1994 earnings of approximately $2.5 million
($1.5 million, after-tax).
- 72 -
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:
[Download Table]
1996 1995
---- ----
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(000's) (000's)
Cash and temporary cash investments $ 6,394 $ 6,394 $ 5,070 $ 5,070
Long-term debt (2)(3)(4) $652,767 $655,582 $638,454 $648,142
(1) Equity investments were not valued because they were not considered to be
material.
(2) Excludes the 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, 1996 and 1995,
respectively.
(4) See Note (B), Capitalization - Long-Term Debt.
- 73 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(P) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1996 and 1995 are set forth below:
[Enlarge/Download Table]
OPERATING OPERATING NET EARNINGS PER SHARE OF
QUARTER REVENUES INCOME (2)(3) INCOME(2)(3)(4)(6) COMMON STOCK (1)(2)(3)(4)(5)(6)
------- --------- ------------- ------------------ -------------------------------
(000's) (000's) (000's)
1996
First $170,860 $29,042 $11,721 $ .82
Second 168,790 25,871 8,883 .75
Third 209,167 34,466 17,904 1.27
Fourth 177,203 19,756 588 .04
1995
First $165,398 $28,135 $9,470 $ .62
Second 163,429 26,535 7,774 .67
Third 200,308 47,431 26,535 1.89
Fourth 161,314 25,055 6,614 .46
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Operating income, net income and earnings per share for the first, second
and third quarters of 1996 included after-tax charges of $4.2 million, or
$.30 per share, $0.5 million, or $.03 per share and $8.7 million, or $.62
per share, respectively, for early retirement and voluntary separation
programs.
(3) Operating income, net income and earnings per share for the second quarter
of 1996 included an after-tax charge of $0.8 million, or $.06 per share,
for the cumulative loss on an office space sublease.
(4) Net income and earnings per share for the fourth quarter of 1996 included
an after-tax charge of $2.6 million, or $.18 per share, for losses
associated with the Company's unregulated subsidiaries.
(5) Earnings per share for the second and third quarter of 1995 included a
total gain of $.15 per share from the repurchase of preferred stock at a
discount to par value.
(6) Net income and earnings per share for the third quarter of 1995 included an
after-tax charge of $1.6 million, or $.12 per share, reflecting the effects
of legislated future state income tax rate reductions which will reduce
future tax benefits on plant previously written off.
- 74 -
[Letterhead of Price Waterhouse LLP]
REPORT OF INDEPENDENT ACCOUNTANTS
January 27, 1997
To the Shareowners and Board of Directors
of The United Illuminating Company
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income and retained earnings and of cash flows
present fairly, in all material respects, the consolidated financial position of
The United Illuminating Company and its subsidiaries at December 31, 1996, and
the consolidated results of their operations and their cash flows for the year
in conformity with generally accepted accounting principles. In addition, in our
opinion, the consolidated financial statement schedule (page S-1) when
considered in relation to the financial statements taken as a whole, presents
fairly, in all material respects, the information required to be included
therein. These financial statements and the financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and the financial statement schedule based
on our audits. We conducted our audit of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for the opinion expressed
above. The consolidated financial statements and the financial statement
schedule of The United Illuminating Company and its subsidiaries for the years
ended December 31, 1995 and 1994, were audited by other independent accountants
whose report dated January 29, 1996 expressed an unqualified opinion on those
financial statements and the financial statement schedule.
/s/ Price Waterhouse LLP
- 75 -
[Letterhead of Coopers & Lybrand, L.L.P]
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareowners and Directors of
The United Illuminating Company:
We have audited the accompanying consolidated balance sheets of The United
Illuminating Company as of December 31, 1995 and 1994, and the related
consolidated statements of income, retained earnings and cash flows for the
years then ended and the consolidated financial statement schedule for the years
ended December 31, 1995 and 1994 (page S-1). These financial statements and the
financial statement schedule are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements and
the financial statement schedule 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, 1995 and 1994, and the consolidated
results of its operations and its cash flows for the years then ended in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered in
relation to the basic financial statements taken as a whole, presents fairly, in
all material respects, the information required to be included therein.
/s/ Coopers & Lybrand L.L.P.
Hartford, Connecticut
January 29, 1996
- 76 -
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures.
Previously reported. See Current Report (Form 8-K, dated December 15, 1995
(amended January 2, 1996 and January 18, 1996).
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 March 27, 1997 for the
Annual Meeting of the Shareholders to be held on May 21, 1997, which Proxy
Statement will be filed with the Securities and Exchange Commission on or about
March 27, 1997, 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 EXERCISES IN 1996 AND YEAR-END OPTION VALUES," "RETIREMENT PLANS,"
"BOARD OF DIRECTORS COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE REPORT ON
EXECUTIVE COMPENSATION," "COMPENSATION COMMITTEE INTERLOCKS AND INSIDER
PARTICIPATION," "DIRECTOR COMPENSATION" and "SHAREOWNER RETURN PRESENTATION" in
the Company's definitive Proxy Statement, dated March 27, 1997, for the Annual
Meeting of the Shareholders to be held on May 21, 1997, which Proxy Statement
will be filed with the Securities and Exchange Commission on or about March 27,
1997, 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 SHAREOWNERS" and
"STOCK OWNERSHIP OF DIRECTORS AND OFFICERS" in the Company's definitive Proxy
Statement, dated March 27, 1997 for the Annual Meeting of the Shareholders to be
held on May 21, 1997, which Proxy Statement will be filed with the Securities
and Exchange Commission on or about March 27, 1997, is incorporated by reference
in answer to this item.
Item 13. Certain Relationships and Related Transactions.
Since January 1, 1996, there has been no transaction, relationship or
indebtedness of the kinds described in Item 404 of Regulation S-K.
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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,
1996, 1995 and 1994
Consolidated statement of cash flows for the years ended December 31,
1996, 1995 and 1994
Consolidated balance sheet, December 31, 1996, 1995 and 1994
Consolidated statement of retained earnings for the years ended
December 31, 1996, 1995 and 1994
Statement of accounting policies
Notes to consolidated financial statements
Reports of independent accountants
Financial Statement Schedule (see S-1)
Schedule II - Valuation and qualifying accounts for the years ended
December 31, 1996, 1995 and 1994.
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Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain
of the following listed exhibits, which are annexed as exhibits to previous
statements and reports filed by the Company, are hereby incorporated by
reference as exhibits to this report. Such statements and reports are identified
by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1996.
(4) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(5) Filed with Registration Statement No. 33-40169, effective August 12, 1991.
(6) Filed with Registration Statement No. 33-35465, effective August 1, 1990.
(7) Filed with Amendment No. 1 to Registration Statement No. 33-55461,
effective October 31, 1994.
(8) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1995.
(9) Filed with Registration Statement No. 2-57275, effective October 19, 1976.
(10) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(11) Filed with Registration Statement No. 2-66518, effective February 25, 1980.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991.
(13) Filed with Registration Statement No. 2-49669, effective December 11, 1973.
(14) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1993.
(15) Filed with Registration Statement No. 2-54876, effective November 19, 1975.
(16) Filed with Registration Statement No. 2-52657, effective February 6, 1975.
(17) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1995.
(18) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1992.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1994.
(20) Filed March 29, 1996, with proxy material for the Annual Meeting of the
Shareowners.
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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.
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(3) 3.1a (1) Copy of Restated Certificate of Incorporation of The United Illuminating
Company, dated January 23, 1995. (Exhibit 3.1)
(3) 3.1b (2) Copy of Certificate Amending Certificate of Incorporation By Action of
Board of Directors, dated August 4, 1995. (Exhibit 3.1b)
(3) 3.1c (3) Copy of Certificate Amending Certificate of Incorporation by Action of
Board of Directors, dated July 16, 1996. (Exhibit 3.1c)
(3) 3.2a (3) Copy of Bylaws of The United Illuminating Company. (Exhibit 2.3)
(3) 3.2b Copy of Article II, Section 2, of Bylaws of The United Illuminating
Company, as amended March 26, 1990, amending Exhibit 3.2a.
(3) 3.2c Copy of Article V, Section 1, of Bylaws of The United Illuminating
Company, as amended April 22, 1991, amending Exhibit 3.2a.
(4) 4.1 (5) Copy of Indenture, dated as of August 1, 1991, from The United Illuminating
Company to The Bank of New York, Trustee. (Exhibit 4)
(4),(10) 4.2 (6) Copy of Participation Agreement, dated as of August 1, 1990, among
Financial Leasing Corporation, Meridian Trust Company, The Bank of New
York and The United Illuminating Company. (Exhibits 4(a) through 4(h),
inclusive, Amendment Nos. 1 and 2).
(4) 4.3a (7) Copy of form of Amended and Restated Agreement of Limited Partnership of
United Capital Funding Partnership L.P. (Exhibit 4(c))
(4) 4.3b (8) Copy of Action of The United Illuminating Company, as General Partner of
United Capital Funding Partnership L.P., relating to the 9 5/8% Preferred
Capital Securities, Series A, of United Capital Funding Partnership L.P.
(Exhibit 4(b))
(4) 4.3c (7) Copy of form of Indenture, dated as of April 1, 1995, from The United
Illuminating Company to The Bank of New York, as Trustee. (Exhibit 4(e))
(4) 4.3d (8) Copy of First Supplemental Indenture, dated as of April 1, 1995, between
The United Illuminating Company and The Bank of New York, Trustee,
supplementing Exhibit 4.3c. (Exhibit 4(d))
(4) 4.3e (7) Copy of form of Payment and Guarantee Agreement of The United Illuminating
Company, dated as of April 1, 1995. (Exhibit 4(j))
(10) 10.1 (9) 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 (9) 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 (10) Copy of Additional Power Contract, dated as of April 30, 1984, between
Connecticut Yankee Atomic Power Company and The United Illuminating
Company.
(10) 10.2c Copy of 1987 Supplementary Power Contract, dated as of April 1, 1987,
supplementing Exhibits 10.2a and 10.2b.
(10) 10.2d Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending
Exhibits 10.2b and 10.2c.
(10) 10.2e Copy of First Supplement to 1996 Amendatory Agreement, dated as of
February 10, 1997, supplementing Exhibit 10.2d.
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[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.3 (9) 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 (9) 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 (11) 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 (4) 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 (12) Copy of NEPOOL Power Pool Agreement, dated as of September 1, 1971, as
amended to November 1, 1988. (Exhibit 10.6a)
(10) 10.6b (13) Copy of Agreement Setting Out Supplemental NEPOOL Understandings, dated as
of April 2, 1973. (Exhibit 5.7-10)
(10) 10.6c (12) Copy of Amendment to NEPOOL Power Pool Agreement, dated as of March 15,
1989, amending Exhibit 10.6a. (Exhibit 10.6c)
(10) 10.6d (12) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of October
1, 1990, amending Exhibit 10.6a. (Exhibit 10.6d)
(10) 10.6e (14) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of
September 15, 1992, amending Exhibit 10.6a. (Exhibit 10.6e)
(10) 10.6f (14) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of June 1,
1993, amending Exhibit 10.6a. (Exhibit 10.6f)
(10) 10.7a (12) 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 (15) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the
Seabrook Companies. (Exhibit 5.9-2)
(10) 10.7c 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.
(10) 10.8a (11) 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 (16) 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 (9) 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 (4) 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)
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[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.9b (12) 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 (12) 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) 10.10a (17) Copy of Agreement, effective May 16, 1995, between The United Illuminating
Company and Local 470-1, Utility Workers Union of America, AFL-CIO.
(Exhibit 10.10a)
(10) 10.10b (17) Copy of Supplemental Agreement - Part-Time Employees, effective May 16,
1995, between The United Illuminating Company and Local 470-1, Utility
Workers Union of America, AFL-CIO. (Exhibit 10.10b)
(10) 10.12 (18) 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 Copy of Fossil Fuel Supply Agreement between BLC Corporation and The United
Illuminating Company, dated as of July 1, 1991.
(10) 10.14a* (18) Copy of Employment Agreement, dated as of January 1, 1988, between The
United Illuminating Company and Richard J. Grossi. (Exhibit 10.22a)
(10) 10.14b* (10) Copy of Amendment to Employment Agreement, dated as of July 23, 1990,
between The United Illuminating Company and Richard J. Grossi, amending
Exhibit 10.14a.
(10) 10.14c* (17) Copy of Second Amendment to Employment Agreement, dated as of June 1, 1995,
between The United Illuminating Company and Richard J. Grossi, amending
Exhibit 10.14a. (Exhibit 10.15c)
(10) 10.15a* (18) Copy of Employment Agreement, dated as of January 1, 1988, between The
United Illuminating Company and Robert L. Fiscus. (Exhibit 10.23a)
(10) 10.15b* (10) Copy of Amendment to Employment Agreement, dated as of July 23, 1990,
between The United Illuminating Company and Robert L. Fiscus, amending
Exhibit 10.15a.
(10) 10.15c* (17) Copy of Second Amendment to Employment Agreement, dated as of June 1, 1995,
between The United Illuminating Company and Robert L. Fiscus, amending
Exhibit 10.15a. (Exhibit 10.16c)
(10) 10.16a* (18) Copy of Employment Agreement, dated as of January 1, 1988, between The
United Illuminating Company and James F. Crowe. (Exhibit 10.24a)
(10) 10.16b* (10) Copy of Amendment to Employment Agreement, dated as of July 23, 1990,
between The United Illuminating Company and James F. Crowe, amending
Exhibit 10.16a.
(10) 10.16c* (17) Copy of Second Amendment to Employment Agreement, dated as of June 1, 1995,
between The United Illuminating Company and James F. Crowe, amending
Exhibit 10.16a. (Exhibit 10.17c)
(10) 10.17* (12) Copy of Executive Incentive Compensation Program of The United Illuminating
Company. (Exhibit 10.24)
(10) 10.18* (10) Copy of The United Illuminating Company 1990 Stock Option Plan, as amended
on December 20, 1993, January 24, 1994 and August 22, 1994.
(10) 10.19* (19) Copy of The United Illuminating Company Dividend Equivalent Program.
(Exhibit 10.20)
(10) 10.20* (20) Copy of Directors' Deferred Compensation Plan of The United Illuminating
Company.
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[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.21* (3) Copy of The United Illuminating Company 1996 Long Term Incentive Program.
(Exhibit 10.21*)
(12),(99) 12 Statement Showing Computation of Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividend
Requirements (Twelve Months Ended December 31, 1996, 1995, 1994, 1993 and
1992).
(21) 21 List of subsidiaries of The United Illuminating Company.
(27) 27 Financial Data Schedule
(28) 28.1 (18) Copies of significant rate schedules of The United Illuminating Company.
(Exhibit 28.1)
-------------------------
*Management contract or compensatory plan or arrangement.
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The foregoing list of exhibits does not include instruments defining the
rights of the holders of certain long-term debt of the Company and its
subsidiaries where the total amount of securities authorized to be issued under
the instrument does not exceed ten (10%) of the total assets of the Company and
its subsidiaries on a consolidated basis; and the Company hereby agrees to
furnish a copy of each such instrument to the Securities and Exchange Commission
on request.
(b) Reports on Form 8-K.
None
- 84 -
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectuses
constituting parts of the Post Effective Amendment No. 1 to the Registration
Statement on Form S-3 (No. 33-50221) and the Registration Statements on Form S-3
(No. 33-50445, No. 33-55461 and No. 33-64003) of our report dated January 27,
1997, appearing in The United Illuminating Company's Annual Report on Form 10-K
for the year ended December 31, 1996.
/s/ Price Waterhouse LLP
New York, New York
March 13, 1997
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[Letterhead of Coopers & Lybrand, L.L.P]
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the Post Effective Amendment No.
1 to the Registration Statement of The United Illuminating Company on Form S-3
(File No. 33-50221) and the Registration Statements on Form S-3 (File No.
33-50445, File No. 33-55461 and File No. 33-64003), of our report, dated January
29, 1996, on our audits of the consolidated financial statements and financial
statement schedule of The United Illuminating Company as of December 31, 1995
and 1994 and for the years then ended, which report is included in this Annual
Report on Form l0-K.
/s/ Coopers & Lybrand L.L.P.
Hartford, Connecticut
January 29, 1996
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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: MARCH 13, 1997
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.
[Download Table]
SIGNATURE TITLE DATE
--------- ----- ----
Director, Chairman of the
Board of Directors and
/s/ Richard J. Grossi Chief Executive Officer March 13, 1997
---------------------------------
(Richard J. Grossi)
(Principal Executive Officer)
Director, President and
/s/ Robert L. Fiscus Chief Financial Officer March 13, 1997
---------------------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
Director March , 1997
---------------------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director March 13, 1997
---------------------------------
(F. Patrick McFadden, Jr.)
/s/ J. Hugh Devlin Director March 13, 1997
---------------------------------
(J. Hugh Devlin)
/s/ Betsy Henley-Cohn Director March 13, 1997
---------------------------------
(Betsy Henley-Cohn)
/s/Frank R. O'Keefe, Jr. Director March 13, 1997
---------------------------------
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director March 13, 1997
---------------------------------
(James A. Thomas)
/s/ David E.A. Carson Director March 13, 1997
---------------------------------
(David E.A. Carson)
/s/ John L. Lahey Director March 13, 1997
---------------------------------
(John L. Lahey)
/s/ Marc C. Breslawsky Director March 13, 1997
---------------------------------
(Marc C. Breslawsky)
/s/ Thelma R. Albright Director March 13, 1997
---------------------------------
(Thelma R. Albright)
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[Enlarge/Download Table]
SCHEDULE II
VALUATION AND
QUALIFYING ACCOUNTS
THE UNITED ILLUMINATING COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(THOUSANDS OF DOLLARS)
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
-------------- ---------- ---------- -------- ---------- ----------
RESERVE DEDUCTION FROM
ASSET TO WHICH IT APPLIES:
Reserve for uncollectible
accounts:
1996 $6,300 $9,854 - $13,854 (A) $2,300
1995 $4,900 $9,383 - $7,983 (A) $6,300
1994 $4,700 $9,976 - $9,776 (A) $4,900
------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
S-1
[Enlarge/Download Table]
EXHIBIT INDEX
(a) Exhibits
EXHIBIT
TABLE ITEM EXHIBIT
NUMBER NUMBER DESCRIPTION PAGE NO.
---------- ------- ----------- -------
(3) 3.2b Copy of Article II, Section 2, of Bylaws of The United
Illuminating Company, as amended March 26, 1990, amending
Exhibit 3.2a.
(3) 3.2c Copy of Article V, Section 1, of Bylaws of The United
Illuminating Company, as amended April 22, 1991, amending
Exhibit 3.2a.
(10) 10.2c Copy of 1987 Supplementary Power Contract, dated as of
April 1, 1987, supplementing Exhibits 10.2a and 10.2b.
(10) 10.2d Copy of 1996 Amendatory Agreement, dated as of December 4,
1996, amending Exhibits 10.2b and 10.2c.
(10) 10.2e Copy of First Supplement to 1996 Amendatory Agreement, dated
as of February 10, 1997, supplementing Exhibit 10.2d.
(10) 10.7c 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.
(10) 10.13 Copy of Fossil Fuel Supply Agreement between BLC Corporation
and The United Illuminating Company, dated as of July 1,
1991.
(12),(99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended
December 31, 1996, 1995, 1994, 1993 and 1992).
(21) 21 List of subsidiaries of The United Illuminating Company.
(27) 27 Financial Data Schedule.
Dates Referenced Herein and Documents Incorporated by Reference
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