Document/Exhibit Description Pages Size
1: 10-K Annual Report Form 10-K 94 518K
2: EX-10 Union C0Ntract, Eff. 5/16/97 124 297K
3: EX-12 Statement Re: Computation of Ratios 2 12K
4: EX-21 List of Subsidiaries of United Illuminating 1 5K
5: EX-27 FDS -- 12 Mos. of 1997 1 7K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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Commission File Number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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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
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 1998 was $617,981,481, 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 2, 1998.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 1998, was 14,278,256.
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, 1998,
for Annual Meeting of the Shareholders to be held on May 20, 1998. III
THE UNITED ILLUMINATING COMPANY
FORM 10-K
DECEMBER 31, 1997
TABLE OF CONTENTS
PAGE
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GLOSSARY 4
PART I
Item 1. Business. 6
- General 6
- Franchises, Regulation and Competition 6
- Franchises 6
- Regulation 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
- New England Transmission Grid 13
- Hydro-Quebec 13
- Environmental Regulation 13
- Employees 16
- Year 2000 Issue 17
Item 2. Properties. 18
- Generating Facilities 18
- Tabulation of Peak Loads, Resources, and Margins 19
- Transmission and Distribution Plant 20
- Capital Expenditure Program 21
- Nuclear Generation 22
- General Considerations 23
- Insurance Requirements 24
- Waste Disposal and Decommissioning 24
Item 3. Legal Proceedings. 26
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TABLE OF CONTENTS (CONTINUED)
PAGE
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Item 4. Submission of Matters to a Vote of Security Holders. 27
Executive Officers of the Company 28
PART II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters. 29
Item 6. Selected Financial Data. 30
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 34
- Major Influences on Financial Condition 34
- Liquidity and Capital Resources 35
- Subsidiary Operations 37
- Results of Operations 38
- Looking Forward 41
Item 8. Financial Statements and Supplementary Data. 45
- Consolidated Financial Statements for the Years 1997,
1996 and 1995 45
- Statement of Income 45
- Statement of Cash Flows 46
- Balance Sheet 47
- Retained Earnings 49
- Notes to Consolidated Financial Statements 50
- Statement of Accounting Policies 50
- Capitalization 56
- Rate-Related Regulatory Proceedings 61
- Accounting for Phase-in Plan 62
- Short-Term Credit Arrangements 62
- Income Taxes 64
- Supplementary Information 66
- Pension and Other Benefits 67
- Jointly Owned Plant 70
- Unamortized Cancelled Nuclear Project 70
- Fuel Financing Obligations and Other Lease Obligations 71
- Commitments and Contingencies 72
- Capital Expenditure Program 72
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TABLE OF CONTENTS (CONTINUED)
PAGE
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PART II (CONTINUED)
- Nuclear Insurance Contingencies 72
- Other Commitments and Contingencies 72
- Connecticut Yankee 72
- Hydro-Quebec 73
- Property Taxes 73
- Environmental Concerns 74
- Site Decontamination, Demolition and Remediation Costs 74
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 74
- Fair Value of Financial Instruments 77
- Quarterly Financial Data (Unaudited) 78
Reports of Independent Accountants 79
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosures. 82
PART III
Item 10. Directors and Executive Officers of the Company 82
Item 11. Executive Compensation. 82
Item 12. Security Ownership of Certain Beneficial Owners
and Management. 82
Item 13. Certain Relationships and Related Transactions. 82
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K. 83
Consents of Independent Accountants 90
Signatures 92
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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.
"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.
"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 1997 retail electric
revenues, approximately 42% was derived from residential sales, 40% from
commercial sales, 16% 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.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of other utilities. Another
subsidiary of URI, Thermal Energies, Inc., is participating in the development
of district heating and cooling facilities in the downtown New Haven area,
including the energy center for an office tower and participation as a 52%
partner in the energy center for a city hall and office tower complex. A third
URI subsidiary, Precision Power, Inc., provides power-related equipment and
services to the owners of commercial buildings and industrial facilities. URI's
fourth subsidiary, United Bridgeport Energy, Inc., is participating in a
merchant wholesale electric generating facility being constructed on land leased
from UI at its Bridgeport Harbor Station generating plant.
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 into its
unregulated subsidiary ventures, and, at December 31, 1997, $27 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 62 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 also change due to the
implementation of the restructuring of the New
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England Power Pool (NEPOOL), 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, independent power producer or power marketer. 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 issued a report and related
recommendations. In its 1997 session, the Connecticut legislature drafted, but
failed to bring to a vote, comprehensive legislation that would have introduced
retail access in Connecticut over a period of several years, with a provision
for the recovery of stranded costs by service area utilities. The legislature
is currently considering legislation of this same sort in its 1998 session.
Among many other factors, decisions and actions concerning retail access in
other states could impact the timing and form of this legislation.
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".
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.
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 existing retail base rates charged to
customers; but its order increased amortization of the Company's conservation
and load management program investments during 1997-1998, and accelerated the
recovery of unspecified regulatory assets during 1999-2001 if the Company's
common stock equity return on utility investment exceeds 10.5% after recording
the increased conservation and load management amortization. The order also
reduced the level of conservation adjustment mechanism revenues in retail
prices, provided a reduction in customer prices through a surcredit in each of
the five plan years, and accepted the Company's proposal to modify the operation
of the fossil fuel clause mechanism. The Company's authorized return on utility
common stock equity was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an
annual basis, are to be utilized one-third for customer price reductions,
one-third to increase amortization of regulatory assets, and one-third retained
as earnings. As a result of the DPUC's order, customer prices were required to
be reduced, on average, by 3% in 1997 compared to 1996. Retail revenues actually
decreased by approximately $30 million, or 4.6%, in 1997 due to customer price
reductions. Also as a
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result of the order, customer prices are required to be reduced by an additional
1% in 2000, and another 1% in 2001, compared to 1996.
By its terms, the DPUC's 1996 order should be reopened in 1998 to determine
the regulatory assets to be subjected to accelerated recovery in 1999, 2000 and
2001.
FINANCING
The Company's capital requirements are presently projected as follows:
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1998 1999 2000 2001 2002
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(millions)
Cash on Hand - Beginning of Year $ 32.0 $10.4 $ - $ - $ -
Internally Generated Funds less Dividends 118.5 108.0 109.3 97.0 68.6
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Subtotal 150.5 118.4 109.3 97.0 68.6
Less:
Capital Expenditures 35.9 32.7 39.6 31.1 30.7
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Cash Available to pay Debt Maturities and Redemptions 114.6 85.7 69.7 65.9 37.9
Less:
Maturities and Mandatory Redemptions 104.2 103.4 150.4 75.3 0.3
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External Financing Requirements (Surplus) $(10.4) $ 17.7 $ 80.7 $ 9.4 $(37.6)
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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
additional short-term and long-term debt, and by issuing preferred stock or
common stock, if necessary. The continued availability of these methods of
financing will be dependent on many factors, including conditions in the
securities markets, economic conditions, and the level of the Company's income
and cash flow.
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.
In February 1997, the Company purchased at a discount on the open market,
and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock.
The shares, having a par value of $40,300, were purchased for $21,271, creating
a net gain of $19,029.
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.
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On July 30, 1997, the Company borrowed $98.5 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $98.5 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and
their interest rate is adjusted periodically to reflect prevailing market
conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75%
at December 31, 1997. The Company has used the proceeds of this $98.5 million
borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987
Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series
B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990
Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of
tax-exempt bonds on which the Company also had a payment obligation to a trustee
for the bondholders. Expenses associated with this transaction, including
redemption premiums totaling $2,055,000 and other expenses of approximately
$1,500,000, were paid by the Company.
In August 1997, the Company purchased at a discount on the open market, and
canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and
200 shares of its $100 par value 4.64%, Series C preferred stock. These shares,
having a par value of $70,000, were purchased for $41,100, creating a net gain
of $28,900.
On November 12, 1997, the Company refinanced the secured lease obligation
bonds that were issued in 1990 in connection with the sale and leaseback by the
Company of a portion of its ownership share in Seabrook Unit 1. All of the
outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook Lease
Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of 10.24%
Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were redeemed.
The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds were
$1,884,549 and $8,589,901, respectively. The Bonds were refunded with the
proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook
Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds"), the principal of
which will be payable from time to time in installments. Transaction expenses
totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from
the proceeds of the 7.83% Bonds and will be repaid as part of the Company's
Lease payments over the remaining term of the Lease. The remainder of the
redemption premiums ($2,334,472) and transaction expenses were paid by the
Company and will be amortized over the remainder of the Lease term. The
transaction reduces the interest rate on the leaseback arrangement, which is
treated as long-term debt on the Company's Consolidated Balance Sheet, from
8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76%
Bonds and $49,850,000 principal amount of the 10.24% Bonds. The Company used the
proceeds from the redemption of these bonds ($70,662,688, including redemption
premiums totaling $3,815,688), plus available funds and short-term borrowings,
to purchase $101,388,000 principal amount of the 7.83% Bonds. The Company
intends to hold the 7.83% Bonds until maturity and has recognized the investment
as an offset to long-term debt on its Consolidated Balance Sheet.
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by 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, 1997, the Company had $30 million of short-term borrowings outstanding under
this facility.
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In addition, as of December 31, 1997, one of the Company's subsidiaries,
American Payment Systems, Inc., had borrowings of $7.8 million outstanding under
a bank line of credit agreement.
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,
1997, this coverage ratio was 3.23:1.0.
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 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, 1997 are set forth below.
Preferred Stock Seabrook Lease
Provisions Provisions
------------------------ -----------------
Preferred Long-term Earnings/Interest
Year Stock Indebtedness Ratio
---- --------- ------------ -----------------
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
1997 2.48 2.60 3.23
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, 1997, the
Company's guarantee liability for this debt amounted to approximately $7.4
million.
FUEL SUPPLY
FOSSIL FUEL
The Company burns coal, residual oil, jet oil and natural gas at its fossil
fuel generating stations in Bridgeport and New Haven. During 1997, approximately
1.1 million tons of coal, 4.9 million barrels of fuel oil and 0.3 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 34-day coal supply of 125,000 tons at its
Bridgeport Harbor Station.
- 11 -
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. The Company's fuel oil supply
contracts for its New Haven and Bridgeport generating stations will expire on
March 31, 1998, and the Company expects to meet its fuel oil needs by entering
into one or more new fuel oil supply contracts and/or through purchases on the
spot market.
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 1997, no natural gas was purchased pursuant to this agreement; and an
additional 0.3 billion cubic feet of natural gas was purchased on the spot
market.
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 2006 2002 2006
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 the evolving industry-wide changes that are described at
"Franchises, Regulation and Competition - Competition," NEPOOL has been
restructured. Its membership has been broadened to cover all entities engaged in
the electricity business in New England, including power marketers and brokers,
independent power producers and
- 12 -
load aggregators. The operation of the regional bulk power system has been
turned over to an independent entity, ISO New England, Inc., so that the
regional bulk power system will continue to be operated both in accordance with
the NEPOOL objectives and free of any adverse impact on competition in the
wholesale power market, where various energy and capacity products will be
traded in open competition among all participants. The restructuring changes
have been filed with the FERC, for its approval, as an amendment to the NEPOOL
Agreement; and the resulting FERC proceedings are expected to be completed
during 1998.
NEW ENGLAND TRANSMISSION GRID
Under other agreements related to the Company's participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to
the financial support of certain 345 kilovolt transmission facilities that are a
part of the New England transmission grid.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.75% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
ten-year Firm Energy Contract, which provides for the sale of 7 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, became effective on July 1, 1991. Additionally, the Company
is obligated to furnish a guarantee for its participating share of the debt
financing for the Phase II facility. As of December 31, 1997, the Company's
guarantee liability for this debt was approximately $7.4 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 and New Haven Harbor generating stations expired in
February and May of 1992, and September of 1996, respectively. Applications for
renewal of these permits had been filed in August and November 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, in New Haven, has been modified to reflect changes in the operating
status of this generating facility and changes in the permitting system. 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
- 13 -
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 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.
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 apply
for and obtain operating permits. The Company expects to submit applications for
such operating permits in early 1998. These applications will verify compliance
with all existing requirements applicable to the generating units at Bridgeport
Harbor, English and New Haven Harbor generating stations. 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 1997, UI consummated nineteen 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 (OTC) (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. On December 30, 1997, the Connecticut DEP proposed
regulations that would implement the requirements of the OTC MOU. 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 (Nox, ozone and particulate
matter). On July 18, 1997, the EPA published final revisions to the national air
quality standards for ozone and particulate matter. On November 7, 1997, the EPA
published a proposed rule that would 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 not all of these three sets of
new regulations have been adopted in final form, 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.
A merchant wholesale electric generating facility (Bridgeport Energy
Project) is being constructed on land leased from UI at its Bridgeport Harbor
Station. It is anticipated that UI's Bridgeport Harbor Unit 1 will be placed in
deactivated reserve status on or about July 1, 1998, when the first phase of the
Bridgeport Energy Project is completed.
- 14 -
UI has provided emission offsets necessary for the licensing of the Bridgeport
Energy Project; and UI has agreed to provide Clean Air Act allowances required
for the operation of this facility to the extent that they are available from
Bridgeport Harbor Units 1 and 2 and are not obtained for the facility from
another source. Given the very low emissions rates expected from the Bridgeport
Energy Project, it currently appears likely that UI will continue to have
surplus SO2 allowances for sale.
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. 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 approximately $346,000.
Under the federal Resource Conservation and Recovery Act (RCRA), the
generation, transportation, treatment, storage and disposal of hazardous wastes
are subject to regulations adopted by the EPA. Connecticut has adopted state
regulations that parallel RCRA regulations but are more stringent in some
respects. The Company has complied with the notification and application
requirements of present regulations, and the procedures by which UI handles,
stores, treats and disposes of hazardous waste products have been revised, where
necessary, to comply with these regulations. 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 Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of December 31, 1997, 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.
The Company is presently remediating an area of PCB contamination at its
English Station generating site, including repair and/or replacement of
approximately 560 linear feet of sheet piling. The total cost of the remediation
and sheet piling repair is presently estimated at $3.5 million, and the Company
plans to repair/replace a major portion of the remaining sheet piling at this
location at an estimated cost of $6 million.
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
- 15 -
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.
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, 1997, the Company had 1,175 employees, including 127 in
subsidiary operations. Of the electric utility employees, approximately 79% had
been with the Company for 10 or more years.
Approximately 545 of the Company's operating, maintenance and clerical
employees are represented by Local 470-1, Utility Workers Union of America,
AFL-CIO, for collective bargaining purposes. On June 30, 1997, the Company's
unionized employees accepted a new five-year agreement, amending and extending
the existing agreement that was scheduled to remain in effect through May 15,
1998. The new agreement provides for, among other things, 2% annual wage
increases beginning in May 1998, and annual lump sum bonuses of 2.5% of base
annual straight time wages (not cumulative). These provisions will restrict the
growth of the Company's bargaining unit base wage expense to about $500,000 per
year. The agreement also provides for job security for longer-term bargaining
unit employees and will allow the Company some flexibility in adjusting work
methods as part of its ongoing process re-engineering efforts.
- 16 -
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.
YEAR 2000 ISSUE
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct all
deficiencies in its computer systems and in the computer systems of the critical
suppliers and other persons with whom data must be exchanged. A complete
inventory and assessment of the Company's computer system applications,
hardware, software and embedded technologies has been completed, and recommended
solutions to all identified risks and exposures have been generated. A
remediation, retirement, renovation and testing program has commenced. Necessary
upgrades to mainframe hardware and software are expected to be completed and
tested during 1998, and a parallel program with respect to desktop hardware and
software is currently projected to be completed and tested by March 31, 1999.
Request for documented compliance information have been sent to all critical
suppliers, data sharers and facility building owners and, as responses are
received, appropriate solutions and testing programs are being developed and
executed. The Company believes that the successful implementation of this
program, which is currently estimated to cost approximately $2.6 million, will
preclude any significant adverse impact of the Year 2000 Issue on its operations
and financial condition.
- 17 -
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1997,
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 76.09 100.00 76.09(1)
Bridgeport Harbor Station 2 #6 Oil 1961 170.00 100.00 170.00(2)
Bridgeport Harbor Station 3 #6 Oil/Coal 1968/1985 385.00 100.00 385.00(3)
Bridgeport Harbor Station 4 Jet Oil 1967 16.15 100.00 16.15
New Haven Harbor Station #6 Oil/Gas 1975 466.00 93.71 436.69(4)
English Station 7 #6 Oil 1948 34.06 100.00 34.06(5)
English Station 8 #6 Oil 1953 38.49 100.00 38.49(5)
OPERATED BY OTHER UTILITIES:
---------------------------
Millstone Unit 3, Nuclear 1986 1119.60 3.685 41.26(6)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1162.00 17.50 203.35(7)
Seabrook, New Hampshire
POWER PURCHASES FROM
COGENERATION FACILITIES:
-----------------------
Bridgeport RESCO, Refuse 1988 59.45 100.00 59.45
Bridgeport, Connecticut
Shelton Landfill Gas 1995 1.61 100.00 1.61
Shelton, Connecticut
-------
Total 1462.15
=======
(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". It is anticipated that
Bridgeport Harbor Station 1 will be returned to deactivated reserve status
on or about July 1, 1998, when the first phase of a merchant wholesale
electric generating facility (Bridgeport Energy Project) being constructed
on land leased from UI at Bridgeport Harbor Station.
(2) Commencing with the completion of the second phase of the Bridgeport Energy
Project, scheduled for July of 1999, a wholesale power marketer will have
an option to purchase the capability and energy generated by Bridgeport
Harbor Station 2, for a period of twelve years, pursuant to a wholesale
power contract.
(3) The unit has burned coal since January 1985.
(4) 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".
(5) English Station 7 and 8 were placed in deactivated reserve, effective
January 1, 1992.
(6) Represents UI's 3.685% ownership share of total net capability. This unit
is currently shut down for safety reasons, awaiting NRC authorization for
restart. See "Nuclear Generation".
(7) Represents UI's 17.5% ownership share of total net capability. In August
1990, UI sold to and leased back from an owner trust established for the
benefit of an institutional investor a portion of UI's 17.5% ownership
interest in this unit. This portion of the unit is subject to the lien of a
first mortgage granted by the owner trustee.
- 18 -
TABULATION OF PEAK LOADS, RESOURCES, AND MARGINS
1997 ACTUAL, 1998 - 2002 FORECAST
(MEGAWATTS)
[Enlarge/Download Table]
Actual Forecast
------ --------------------------------------------------
1997 1998 1999 2000 2001 2002
At Time of Peak Load on UI's System:
-----------------------------------
Capacity of generating units operated
by UI (1) 1070.77 1088.55 1088.55 1088.55 1088.55 l088.55
-------------------------------------
Entitlements in nuclear units (1) (2)
-----------------------------
Millstone Unit 3 (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
------ ------ ------ ------ ------ ------
244.61 244.61 244.61 244.61 244.61 244.61
------ ------ ------ ------ ------ ------
Equivalent capacity value of
entitlement in Hydro-Quebec (1) (2) 98.08 98.08 98.08 98.08 98.08 0
----------------------------
Purchases from cogeneration facilities
--------------------------------------
Bridgeport RESCO 59.45 59.45 59.45 59.45 59.45 59.45
Shelton Landfill 1.61 1.50 1.57 1.54 1.36 1.32
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 (119.56) 2.56 2.56 (30.64) (30.64) (30.64)
------- ------- ------- ------- ------- -------
Total generating resources 1356.10 1495.89 1495.96 1462.73 1462.55 1364.43
======= ======= ======= ======= ======= =======
Calculation of UI's capability
responsibility (4)
------------------------------
Peak load 1173.00 1179.00 1190.00 1207.00 1220.00 1230.00
Required reserve margin 167.06 214.86 257.24 260.91 263.72 184.50
------- ------- ------- ------- ------- -------
Total capability responsibility 1340.06 1393.86 1447.24 1467.91 1483.72 1414.50
======= ======= ======= ======= ======= =======
Available Margin (5) 13.29 99.39 46.01 (7.86) (23.67) (52.53)
======= ======= ======= ======= ======= =======
(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 - 34.34
(3) At the time of 1997 summer peak, Millstone Unit 3 still retained capability
rating for the purposes of satisfying UI's required capacity as a NEPOOL
participant. It is assumed that unit will be back in operation by the time
of 1998 summer peak.
(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.
- 19 -
During 1997, the peak load on the Company's system was approximately 1,173
megawatts, which occurred in July. UI's total generating capability at the time
was 1,356 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 0.8% during the period 1997 to 2007.
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 1997.
MEGAWATT-HOURS
(000's)
SOURCES USES
------- ----
OWNED Retail Customers 5,376
Nuclear (Seabrook Unit 1) 1,390
Coal 2,760 Wholesale
Oil 2,951 Delivered to NEPOOL 1,256
Gas & Gas Turbines 28 Contracts 1,745
-----
Total Owned 7,129
Company Use & Losses 255
PURCHASED -----
Contracts 962 Total Uses 8,632
NEPOOL 240 =====
Hydro-Quebec 301
-----
Total Sources 8,632
=====
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 25 bulk electric supply substations with a
capacity of 2,634,000 KVA and 40 distribution substations with a capacity of
212,500 KVA. The Company has 3,150 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.
- 20 -
CAPITAL EXPENDITURE PROGRAM
The Company's 1998-2002 capital expenditure program, excluding allowance
for funds used during construction (AFUDC), and its effect on certain capital
related items is presently budgeted as follows:
[Enlarge/Download Table]
1998 1999 2000 2001 2002 TOTAL
---- ---- ---- ---- ---- -----
(000's)
Production $7,747 $13,911 $12,620 $9,615 $11,920 $55,813
Distribution 15,686 12,783 14,213 13,983 14,405 71,070
Transmission 875 1,923 3,408 783 467 7,456
Other 3,281 3,361 789 612 959 9,002
------ ------ ------ ------ ------ -------
SUBTOTAL 27,589 31,978 31,030 24,993 27,751 143,341
Nuclear Fuel 8,325 746 8,569 6,160 2,892 26,692
------ ------ ------ ------ ------ -------
Total Expenditures $35,914 $32,724 $39,599 $31,153 $30,643 $170,033
====== ====== ====== ====== ====== =======
Rate Base and Other Selected Data:
---------------------------------
AFUDC (Pre-tax) 1,683 1,836 1,853 1,563 1,505
Depreciation
Book Plant 57,192 58,213 58,158 57,945 58,778
Conservation Assets 10,309 5,390 0 0 0
Decommissioning 2,676 2,781 2,892 3,007 3,128
Additional Required
Amortization (pre-tax)(1)
Conservation Assets 13,000 0 0 0 0
Other Regulatory Assets 0 20,300 49,500 54,500 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 12,586 0 0 0
Estimated Rate Base
(end of period) 1,106,666 1,042,700 989,995 928,513 895,962
(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, as expected, common equity return on utility
investment exceeds 10.5% after recording the additional amortization.
Note: Capital Expenditures and their effect on certain capital related items
are estimates subject to change due to future events and conditions that
may be substantially different than those used in developing the
projections.
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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, 1997, Seabrook Unit 1 has operated at a lifetime capacity
factor of 79%.
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, 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.
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, substantial
incremental direct costs are being 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 nine
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 service company subsidiary that is the operator of Millstone Unit 3
and two operating NU subsidiary electric utility companies that are the majority
joint owners of Millstone Unit 3 are responsible for the additional costs that
the other joint owners have experienced as a result of the shutdown of Millstone
Unit 3. On August 7, 1997, the Company and the other nine minority, non-NU joint
owners of Millstone Unit 3 filed lawsuits against NU and its trustees, as well
as a demand for arbitration against The Connecticut Light and Power Company and
Western Massachusetts Electric Company, the operating electric utility
subsidiaries of NU that are the majority joint owners of the unit and have
contracted with the minority joint owners to operate it. The ten non-NU joint
owners, who together own about 19.5% of the unit, claim that NU and its
subsidiaries failed to comply with NRC regulations, failed to operate
- 22 -
Millstone Station in accordance with good utility operating practice and
concealed their failures from the non-operating joint owners and the NRC. The
arbitration and lawsuits seek to recover costs of purchasing replacement power
and increased operation and maintenance costs resulting from the shutdown of
Millstone Unit 3.
The Connecticut Yankee Unit commenced commercial operation in January of
1968, pursuant to a 40-year operating license issued by the NRC. It is owned,
through ownership of Connecticut Yankee's common stock, by ten New England
electric utilities, including the Company, and is operated by another service
company subsidiary of NU. Prior to July 23, 1996, when the Connecticut Yankee
Unit was taken out of service following an engineering evaluation that
determined that safety-related air cooling system pipes could crack if the plant
should lose its outside source of electric power, the Connecticut Yankee Unit
had operated at a lifetime capacity factor of 75.6%. Prior to and following its
removal from service in July of 1996, NRC inspections of the Connecticut Yankee
Unit revealed issues that were similar to those previously identified at
Millstone Station and identified a number of significant deficiencies in the
engineering calculations and analyses that were relied upon to ensure the
adequacy of the design of key safety systems at the unit. Pending a resolution
of these issues, an economic study by the owners, comparing the costs of
continuing to operate the Connecticut Yankee Unit over the remaining period of
its operating license, which expires in 2007, to the costs of shutting down the
unit permanently and incurring replacement power costs for the same period,
resulted in a decision, on December 4, 1996, by the Board of Directors of
Connecticut Yankee to retire the Connecticut Yankee Unit from commercial
operation. The 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, 1997, UI's equity investment in Connecticut Yankee was
approximately $10.5 million. The estimate of the sum of future payments for the
closing, decommissioning and recovery of the remaining investment in the
Connecticut Yankee Unit is approximately $606 million. The Company's estimate of
its remaining share of costs, including decommissioning, less return of
investment (approximately $10.5 million) and return on investment (approximately
$6.3 million), is approximately $40.8 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.
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.
- 23 -
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. With respect to each of the three nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $23.2 million per incident. However, any
assessment would be limited to $3.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$5.0 million.
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 was required to take
title to and dispose of the utilities' high level wastes and spent nuclear fuel
beginning no later than January 1998. However, the DOE has announced that its
first high level waste repository will not be in operation earlier than 2010 and
possibly not earlier than 2013, 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.
- 24 -
The DOE also announced that, absent a repository, the DOE had no statutory
obligation to begin accepting high level wastes and spent nuclear fuel for
disposal by January 31, 1998; and the DOE did not begin accepting such wastes
and fuel by the date. Numerous utilities and state governments have obtained a
judicial determination that the DOE had and has a statutory and contractual
responsibility to take title to and dispose of high level wastes and spent
nuclear fuel commencing not later than January 31, 1998, and that the contracts
between the DOE and the plant owners and generators of such wastes and fuel will
provide a potentially adequate remedy for the latter in the event of a breach of
the contracts. The DOE is contesting these judicial declarations; and it is
unclear at this time whether the United States Congress will enact legislation
to address high level wastes/spent fuel disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
operation or decommissioning of nuclear generating units have increased
significantly in recent years and may continue to rise. The cost increases are a
function of increased packaging and transportation costs, and higher fees and
surcharges imposed 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, Millstone Unit 3
and Seabrook Unit 1 have storage plans that will allow on-site retention of LLW
for at least five years in the event that disposal is interrupted. The
Connecticut Yankee Unit, which has been retired from commercial operation, has a
similar storage program, although disposal of its LLW will take place in
connection with its decommissioning.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
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 $473 million (in 1998 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $83 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1997 was $1.9 million. UI's share of the fund at December 31, 1997 was
approximately $12.4 million.
- 25 -
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $557 million (in 1998 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during 1997 was $487,000. UI's share of the fund at December 31, 1997 was
approximately $5.1 million. The decommissioning trust fund for the Connecticut
Yankee Unit is also managed by NU. For the Company's 9.5% equity ownership in
Connecticut Yankee, decommissioning costs of $2.1 million were funded by UI
during 1997, and UI's share of the fund at December 31, 1997 was $24.9 million.
The current decommissioning cost estimate for the Connecticut Yankee Unit,
assuming the prompt removal and dismantling of the unit commencing in 1997, is
$456 million, of which UI's share would be $43 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. On March 7, 1997, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1997-1998, which notices purport to increase said
assessed value by approximately 54% over the valuations declared by the Company
and are expected to generate tax claims of approximately $3.7 million. The
Company is vigorously contesting each of these actions by the City's tax
assessor. In January 1996, the Connecticut Superior Court granted the Company's
motion for summary judgment against the City relative to the earliest tax year
at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had
no statutory authority to revalue personal property listed and valued on the
Company's tax list for the tax year 1991-1992. This Superior Court decision,
which would also have been applicable to and defeated the assessor's valuation
increases for the two subsequent tax years, 1992-1993 and 1993-1994, was
appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed
the Superior Court's decisions in this and two other companion cases involving
other taxpayers, ruling that the tax assessor had a three-year period in which
to audit and revalue personal property listed and valued on the Company's tax
list for the tax year 1991-1992. It is currently anticipated that all of the
pending cases for all of the tax years in dispute will now be scheduled for
trial in the Superior Court relative to the Company's claim that the tax
assessor's increases in personal property tax assessments for the three earliest
years were unlawful for other reasons and relative to the vigorously contested
issue, for all of the tax years, as to the reasonableness of the tax assessor's
valuation method, both as to amount and methodology. It is the present opinion
of the Company that the
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ultimate outcome of this dispute will not have a significant impact on the
long-term financial position of the Company. The Company would seek permission
from the DPUC to recover from its retail customers the expense of any adverse
court decision or settlement.
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, 1997.
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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 62 Chairman of the Board of Directors May 1, 1991
and Chief Executive Officer
Robert L. Fiscus 60 Vice Chairman of the Board of Directors
and Chief Financial Officer February 23, 1998
Nathaniel D. Woodson 56 President February 23, 1998
James F. Crowe 55 Group Vice President Power Supply Services October 1, 1996
Albert N. Henricksen 56 Group Vice President Support Services October 1, 1996
Anthony J. Vallillo 49 Group Vice President Client Services October 1, 1996
Rita L. Bowlby 59 Vice President-Corporate Affairs February 1, 1993
Stephen F. Goldschmidt 52 Vice President Planning and Information Resources October 1, 1996
E. Jon Majkowski 55 Vice President/President Subsidiaries (URI, PPI & TEI) October 1, 1996
James L. Benjamin 56 Controller January 1, 1981
Kurt D. Mohlman 49 Treasurer and Secretary January 1, 1994
Charles J. Pepe 49 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. Messrs. Grossi, Fiscus, Crowe, Henricksen,
Vallillo, Goldschmidt, Benjamin, Mohlman, Pepe and Ms. Bowlby have entered into
employment agreements with the Company. There is no arrangement or understanding
between any executive officer of the Company and any other person pursuant to
which such officer was selected as an officer.
A brief account of the business experience during the past five years of
each executive officer of the Company is as follows:
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 served as President and Chief Financial
Officer during the period January 1, 1993 to February 23, 1998. He has served as
Vice Chairman of the Board of Directors and Chief Financial Officer since
February 23, 1998.
NATHANIEL D. WOODSON. Mr. Woodson served as Vice President and General
Manager of the Energy Systems Business Unit of Westinghouse Electric Corporation
during the period January 1, 1993 to April 30, 1996. He has served as President
of the Company since February 23, 1998.
JAMES F. CROWE. Mr. Crowe served as Executive Vice President during the
period January 1, 1993 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, 1993 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.
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ANTHONY J. VALLILLO. Mr. Vallillo served as Vice President-Marketing during
the period January 1, 1993 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
during the five-year period.
STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served as Vice President-Planning
during the period January 1, 1993 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/President-UI
Subsidiaries during the period January 1, 1993 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, 1993 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, 1993 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 1997 and 1996 were as follows:
1997 SALE PRICE 1996 SALE PRICE
--------------- ---------------
HIGH LOW HIGH LOW
---- --- ---- ---
First Quarter 32 5/8 24 1/2 39 3/4 36 1/4
Second Quarter 30 7/8 24 1/2 38 35 3/4
Third Quarter 37 31 1/2 37 1/2 33 7/8
Fourth Quarter 45 15/16 37 35 31 3/8
UI has paid quarterly dividends on its Common Stock since 1900. The
quarterly dividends declared in 1996 and 1997 were at a rate of 72 cents per
share.
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$104.1 million were free from such limitations at December 31, 1997.
As of December 31, 1997, there were 16,057 Common Stock shareowners of
record.
- 29 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA
1997 1996 1995
=====================================================================================================================
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $259,842 $265,562 $260,694
Commercial 248,984 263,609 259,715
Industrial 102,967 108,825 106,963
Other 11,778 11,880 11,736
------------- -------------- -------------
Total Retail 623,571 649,876 639,108
Wholesale (1) 82,871 72,844 48,232
Other operating revenues 3,825 3,300 3,109
------------- -------------- -------------
Total operating revenues 710,267 726,020 690,449
------------- -------------- -------------
Fuel and interchange energy -net
Retail -own load 109,542 95,359 96,538
Wholesale 73,124 65,158 41,631
Capacity purchased-net 39,976 46,830 47,420
Depreciation 74,618 (3) 65,921 61,426
Other amortization, principally deferred return and cancelled plant 13,758 13,758 13,758
Other operating expenses, excluding tax expense 200,803 219,630 (5) 183,749
Gross earnings tax 23,618 26,757 27,379
Other non-income taxes 28,922 30,382 31,564
------------- -------------- -------------
Total operating expenses, excluding income taxes 564,361 563,795 503,465
------------- -------------- -------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 1,575 2,375 2,762
Other non-operating income(loss) 4,186 (7,166) (4,272)
Interest expense
Long-term debt - net 56,158 65,046 63,431
Other 6,068 4,721 13,140
------------- -------------- -------------
Total 62,226 69,767 76,571
------------- -------------- -------------
Minority interest in preferred securities 4,813 4,813 3,583
Income tax expense
Operating income tax 41,333 (4) 53,090 59,828
Non-operating income tax (2,496) (9,332) (4,901)
------------- -------------- -------------
Total 38,837 43,758 54,927
------------- -------------- -------------
Income(loss) before cumulative effect of accounting change 45,791 39,096 50,393
Cumulative effect of change in accounting - net of tax 0 0 0
------------- -------------- -------------
Net income (loss) 45,791 39,096 (6) 50,393
Discount on preferred stock redemption (48) (1,840) (2,183)
Preferred and preference stock dividends 205 330 1,329
------------- -------------- -------------
Income (loss) applicable to common stock $45,634 $40,606 $51,247
---------------------------------------------------------------------------------------------------------------------
Operating income $104,573 $109,135 $127,156
=====================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $1,222,174 $1,258,306 $1,277,910
Construction work in progress 25,448 40,998 41,817
Plant-related regulatory asset 0 0 0
Other property and investments 58,441 49,091 53,355
Current assets 165,027 163,350 137,277
Deferred charges and regulatory assets 360,635 449,150 475,258
------------- -------------- -------------
Total Assets $1,831,725 $1,960,895 $1,985,617
---------------------------------------------------------------------------------------------------------------------
Common stock equity $438,963 $440,016 $439,981
Preferred, preference stock and preferred securities 54,351 54,461 60,539
Long-term debt excluding current portion 644,670 759,680 845,684
Noncurrent liabilities (7) 119,868 138,816 65,747
Current portion of long-term debt 100,000 69,900 40,800
Notes payable 37,751 10,965 0
Other current liabilities (7) 130,993 129,007 102,336
Deferred income tax liabilities and other 305,129 358,050 430,530
------------- -------------- -------------
Total Capitalization and Liabilities $1,831,725 $1,960,895 $1,985,617
=====================================================================================================================
(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 $6.4 million, before-tax, for
additional amortization of conservation & load management costs.
(4) Includes the effect of credits of $6.7 million, before-tax, to provide tax
provision for fossil generation decommissioning.
(5) Includes the effect of charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(6) Includes the effect of charges of $13.4 million, after-tax,associated with
voluntary early retirement programs.
- 30 -
[Enlarge/Download Table]
1994 1993 1992 1991 1990 1989 1988
============================================================================================================================
$252,386 $238,185 $226,455 $226,751 $211,891 $205,183 $200,170
250,771 (2) 256,559 253,456 (2) 255,782 234,704 219,852 208,801
104,242 (2) 97,466 97,010 (2) 91,895 94,526 92,855 96,665
11,469 11,349 11,065 10,886 10,536 9,943 9,732
--------------- -------------- -------------- ------------- -------------- -------------- --------------
618,868 603,559 587,986 585,314 551,657 527,833 515,368
34,927 45,931 75,484 84,236 85,657 77,925 63,263
2,953 3,533 3,855 3,821 3,332 3,348 3,570
--------------- -------------- -------------- ------------- -------------- -------------- --------------
656,748 653,023 667,325 673,371 640,646 609,106 582,201
--------------- -------------- -------------- ------------- -------------- -------------- --------------
99,589 98,694 108,084 123,010 119,285 128,739 121,425
27,765 39,356 55,169 61,858 69,117 62,681 53,837
44,769 47,424 43,560 44,668 42,827 50,234 35,465
58,165 56,287 50,706 48,181 36,526 35,618 24,069
1,172 1,780 10,415 10,415 4,173 10,415 10,415
193,098 203,427 (8) 183,426 178,912 176,419 144,867 133,407
27,403 27,955 27,362 27,223 25,595 24,506 23,948
32,458 29,977 31,869 28,673 24,648 20,294 21,695
--------------- -------------- -------------- ------------- -------------- -------------- --------------
484,419 504,900 510,591 522,940 498,590 477,354 424,261
--------------- -------------- -------------- ------------- -------------- -------------- --------------
0 7,497 15,959 17,970 21,503 0 0
3,463 4,067 3,232 5,190 3,443 65,443 75,656
(1,907) 71 18,545 2,697 22,654 (219,742) (23,369)
73,772 80,030 88,666 90,296 94,056 91,126 90,022
10,301 12,260 12,882 9,847 15,468 22,849 12,069
--------------- -------------- -------------- ------------- -------------- -------------- --------------
84,073 92,290 101,548 100,143 109,524 113,975 102,091
--------------- -------------- -------------- ------------- -------------- -------------- --------------
0 0 0 0 0 0 0
44,937 33,309 48,712 47,231 43,493 37,963 44,045
(3,214) (6,322) (12,558) (19,299) (17,409) (101,135) (14,548)
--------------- -------------- -------------- ------------- -------------- -------------- --------------
41,723 26,987 36,154 27,932 26,084 (63,172) 29,497
--------------- -------------- -------------- ------------- -------------- -------------- --------------
48,089 40,481 56,768 48,213 54,048 (73,350) 78,639
(1,294) 0 0 7,337 0 0 0
--------------- -------------- -------------- ------------- -------------- -------------- --------------
46,795 40,481 (9) 56,768 55,550 54,048 (73,350) 78,639
0 0 0 0 0 0 0
3,323 4,318 4,338 4,530 4,751 8,233 11,348
--------------- -------------- -------------- ------------- -------------- -------------- --------------
$43,472 $36,163 $52,430 $51,020 $49,297 ($81,583) $67,291
----------------------------------------------------------------------------------------------------------------------------
$127,392 $114,814 $108,022 $103,200 $98,563 $93,789 $113,895
============================================================================================================================
$1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173 $562,473 $560,930
57,669 77,395 59,809 54,771 50,257 675,831 812,246
0 0 0 0 0 81,768 88,339
53,267 58,096 65,320 79,009 90,006 91,648 83,860
157,309 187,981 247,954 164,839 161,066 170,823 166,270
538,601 567,394 556,493 554,365 553,986 605,696 653,418
--------------- -------------- -------------- ------------- -------------- -------------- --------------
$2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063
----------------------------------------------------------------------------------------------------------------------------
$428,028 $423,324 $422,746 $401,771 $379,812 $362,584 $473,674
44,700 60,945 60,945 62,640 69,700 70,000 104,000
708,340 875,268 893,457 909,998 899,993 868,884 862,287
59,458 62,666 44,567 110,217 110,850 117,200 119,165
193,133 143,333 92,833 37,500 41,667 18,667 3,667
67,000 0 84,099 13,000 15,000 45,000 0
122,084 117,343 114,757 114,280 138,173 133,459 115,043
452,248 451,413 440,230 423,449 409,293 572,445 687,227
--------------- -------------- -------------- ------------- -------------- -------------- --------------
$2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063
============================================================================================================================
(7) Amounts for years prior to 1996 were reclassified in 1996.
(8) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(9) Includes the effect of a reorganization charge of $7.8 million, after-tax.
- 31 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1997 1996 1995
=====================================================================================================================
COMMON STOCK DATA
Average number of shares outstanding 13,975,802 14,100,806 14,089,835
Number of shares outstanding at year-end 13,907,824 14,101,291 14,100,091
Earnings(loss) per share (average) - basic $3.27 $2.88 $3.64
Earnings(loss) per share (average) - diluted $3.26 $2.87 $3.63
Recurring earnings(loss) per share (average) (1) $3.11 $3.94 $3.61
Book value per share $31.56 $31.20 $31.20
Average return on equity
Total 10.45% 9.20% 11.84%
Utility 11.54% 11.51% 13.04%
Dividends declared per share $2.88 $2.88 $2.82
Market Price:
High $45.9375 $39.750 $38.500
Low $24.5000 $31.375 $29.500
Year-end $45.9375 $31.375 $37.375
=====================================================================================================================
Net cash provided by operating activities, less dividends ($000's) $127,807 $103,943 $120,033
Capital expenditures, excluding AFUDC $33,436 $47,174 $59,363
=====================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 1,903,096 1,891,988 1,890,575
Commercial 2,253,488 2,258,501 2,273,965
Industrial 1,170,815 1,141,109 1,126,458
Other 48,717 48,291 48,435
------------- -------------- -------------
Total 5,376,116 5,339,889 5,339,433
------------- -------------- -------------
Number of retail customers by class (average)
Residential 280,283 279,024 278,326
Commercial 29,228 28,666 28,550
Industrial 1,697 1,652 1,599
Other 1,163 1,141 1,122
------------- -------------- -------------
Total 312,371 310,483 309,597
------------- -------------- -------------
Revenue per kilowatt hour by class (cents)
Residential 13.65 14.04 13.79
Commercial 11.05 11.67 11.42
Industrial 8.79 9.54 9.50
Average large industrial customers time of use rate (cents) 8.12 8.26 8.53
System requirements (MWh) 5,631,296 5,640,957 5,647,690
Peak load - kilowatts 1,173,160 1,044,620 1,156,740
Generating capability- peak(kilowatts) 1,356,100 1,522,350 1,434,102
Load factor 54.80% 61.64% 55.74%
Fuel generation mix percentages
Coal 44 38 37
Oil 15 8 7
Nuclear 25 37 37
Cogeneration 9 9 9
Gas 2 3 5
Hydro 5 5 5
---------------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $621,874 $642,106 $637,219
Fuel adjustment clause 1,697 7,770 1,889
Sales provision adjustment 0 0 0
------------- -------------- -------------
Total $623,571 $649,876 $639,108
------------- -------------- -------------
Revenues - retail sales per kWh (cents)
Base 11.57 12.02 11.93
Fuel adjustment clause 0.03 0.15 0.04
Sales provision adjustment 0.00 0.00 0.00
------------- -------------- -------------
Total 11.60 12.17 11.97
------------- -------------- -------------
Fuel and energy cost per kWh (cents) 1.95 1.69 1.71
Fossil 2.39 2.41 2.22
Nuclear 0.61 0.46 0.85
---------------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,175 1,287 1,358
Total payroll($000'S) $68,640 $69,276 $72,984
=====================================================================================================================
(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.
- 32 -
[Enlarge/Download Table]
1994 1993 1992 1991 1990 1989 1988
============================================================================================================================
14,085,452 14,063,854 13,941,150 13,899,906 13,887,748 13,887,748 13,887,748
14,086,691 14,083,291 14,033,148 13,932,348 13,887,748 13,887,748 13,887,748
$3.09 $2.57 $3.76 $3.67 $3.55 ($5.87) $4.85
$3.08 $2.56 $3.74 $3.66 $3.55 ($5.87) $4.85
$3.28 $3.13 $3.17 $2.90 $3.55 ($5.87) $4.85
$30.39 $30.06 $30.12 $28.84 $27.35 $26.11 $34.11
10.19% 8.45% 12.67% 13.01% 13.39% -18.88% 14.75%
12.50% 10.97% 14.46% 13.39% 13.97% 20.21% 32.91%
$2.76 $2.66 $2.56 $2.44 $2.32 $2.32 $2.32
$39.500 $45.875 $42.000 $39.125 $34.125 $34.250 $27.500
$29.000 $38.500 $34.125 $30.000 $26.875 $24.750 $19.125
$29.500 $40.250 $41.500 $39.000 $31.125 $34.250 $26.875
============================================================================================================================
$94,807 $104,547 $109,020 $73,865 $39,189 $31,437 $40,607
$63,044 $94,743 $66,390 $63,157 $64,018 $77,041 $83,735
============================================================================================================================
1,892,955 1,844,041 1,799,456 1,851,447 1,826,700 1,883,363 1,870,318
2,285,942 (2) 2,359,023 2,303,216 (2) 2,347,757 2,259,340 2,254,099 2,174,200
1,135,831 (2) 1,036,547 997,168 (2) 980,071 1,060,751 1,109,119 1,186,336
48,718 50,715 52,984 55,118 58,013 60,427 61,303
--------------- -------------- -------------- ------------- -------------- -------------- --------------
5,363,446 5,290,326 5,152,824 5,234,393 5,204,804 5,307,008 5,292,157
--------------- -------------- -------------- ------------- -------------- -------------- --------------
275,441 273,752 273,936 274,064 275,637 276,385 274,884
28,394 (2) 28,968 28,848 (2) 29,768 29,808 29,526 28,826
1,538 (2) 959 1,017 (2) 268 319 347 367
1,127 1,175 1,358 1,361 1,352 1,316 1,267
--------------- -------------- -------------- ------------- -------------- -------------- --------------
306,500 304,854 305,159 305,461 307,116 307,574 305,344
--------------- -------------- -------------- ------------- -------------- -------------- --------------
13.33 12.92 12.58 12.25 11.60 10.89 10.70
10.97 10.88 11.00 10.89 10.39 9.75 9.60
9.18 9.40 9.73 9.38 8.91 8.37 8.15
8.69 8.89 8.84 8.64 8.06 7.58 7.14
5,652,657 5,630,581 5,475,664 5,541,477 5,501,495 5,603,502 5,581,897
1,130,780 1,114,900 1,034,440 1,145,820 1,054,600 1,094,400 1,132,100
1,462,290 1,515,420 1,402,800 1,474,190 1,449,600 1,289,800 1,271,500
57.07% 57.65% 60.26% 55.21% 59.55% 58.45% 56.13%
35 31 34 34 43 39 37
14 16 17 21 24 37 41
32 38 35 29 20 11 11
9 8 8 9 9 9 7
4 1 1 4 3 3 0
6 6 5 3 1 1 4
----------------------------------------------------------------------------------------------------------------------------
$619,097 $605,887 $608,176 $607,997 $589,346 $577,611 $574,422
(229) (2,328) (41,221) (37,497) (45,900) (49,778) (59,054)
0 0 21,031 14,814 8,211 0 0
--------------- -------------- -------------- ------------- -------------- -------------- --------------
$618,868 $603,559 $587,986 $585,314 $551,657 $527,833 $515,368
--------------- -------------- -------------- ------------- -------------- -------------- --------------
11.54 11.45 11.80 11.62 11.32 10.88 10.85
0.00 (0.04) (0.80) (0.72) (0.88) (0.93) (1.11)
0.00 0.00 0.41 0.28 0.16 0.00 0.00
--------------- -------------- -------------- ------------- -------------- -------------- --------------
11.54 11.41 11.41 11.18 10.60 9.95 9.74
--------------- -------------- -------------- ------------- -------------- -------------- --------------
1.76 1.75 2.43 2.67 2.63 2.78 2.53
2.14 2.08 2.98 3.11 2.89 2.98 2.74
0.94 1.23 1.42 1.62 1.55 0.89 0.87
----------------------------------------------------------------------------------------------------------------------------
1,377 1,490 1,554 1,571 1,587 1,627 1,620
$75,441 $75,305 $74,052 $71,888 $69,237 $65,175 $62,387
============================================================================================================================
- 33 -
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, has
averaged less than 1.5% during the past 5 years. The Company hopes to continue
to restrict this average to less than the rate of inflation in future years (see
"Looking Forward").
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and regulations
and competition within the electric utility industry.
A major factor affecting the Company's earnings prospects 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
existing retail base rates charged to customers; but its order increased
amortization of the Company's conservation and load management program
investments during 1997-1998, and accelerated the recovery of unspecified
regulatory assets during 1999-2001 if the Company's common stock equity return
on utility investment exceeds 10.5% after recording the increased conservation
and load management amortization. The order also reduced the level of
conservation adjustment mechanism revenues in retail prices, provided a
reduction in customer prices through a surcredit in each of the five plan years,
and accepted the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are
to be utilized one-third for customer price reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. As a
result of the DPUC's order, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Retail revenues actually decreased by
approximately $30 million, or 4.6%, in 1997 due to customer price reductions.
Also as a result of the order, customer prices are required to be reduced by an
additional 1% in 2000, and another 1% in 2001, compared to 1996.
By its terms, the DPUC's 1996 order should be reopened in 1998 to determine
the regulatory assets to be subjected to accelerated recovery in 1999, 2000 and
2001.
Federal legislation has fostered competition in the wholesale electric
power market, as has a FERC rulemaking requiring electric utilities to furnish
transmission service to all buyers and sellers in the marketplace. In its
rulemaking, the FERC stated that state regulatory commissions should address the
issue of recovery by electric utilities of the costs of existing facilities
that, on account of "retail access", become unrecoverable by the utilities
through the regulated rates charged to their service territory customers.
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 has 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, independent power producer or power marketer. The costs
of existing facilities that become unrecoverable by the service area electric
utility on account of the loss of sales to these customers are said to be
"stranded costs". 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 issued a report and related recommendations. In its 1997 session, the
Connecticut legislature drafted, but failed to bring to a
- 34 -
vote, comprehensive legislation that would have introduced retail access in
Connecticut over a period of several years, with a provision for the recovery of
stranded costs by service area utilities. The legislature is currently
considering legislation of this same sort in its 1998 session. Among many other
factors, decisions and actions concerning retail access in other states could
impact the timing and form of this legislation.
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.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow 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 or a change in the
cost-based regulatory structure could cause the operations of the Company, or a
portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. While the Company expects to continue to
meet these criteria in the foreseeable future, if the Company, or a portion of
its assets or operations, were to cease meeting these criteria, accounting
standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs,
would be required in the year in which the criteria are no longer met, if such
deferred costs are not recoverable in that portion of the business that
continues to meet the criteria for the application of SFAS No. 71. If this
change in accounting were to occur, it would have a material adverse effect on
the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as follows:
[Enlarge/Download Table]
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year $ 32.0 $10.4 $ - $ - $ -
Internally Generated Funds less Dividends 118.5 108.0 109.3 97.0 68.6
----- ----- ----- ---- ----
Subtotal 150.5 118.4 109.3 97.0 68.6
Less:
Capital Expenditures 35.9 32.7 39.6 31.1 30.7
----- ----- ----- ---- ----
Cash Available to pay Debt Maturities and Redemptions 114.6 85.7 69.7 65.9 37.9
Less:
Maturities and Mandatory Redemptions 104.2 103.4 150.4 75.3 0.3
----- ----- ----- ---- ----
External Financing Requirements (Surplus) $(10.4) $ 17.7 $ 80.7 $ 9.4 $(37.6)
===== ===== ===== ==== =====
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.
- 35 -
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
additional short-term and long-term debt, and by issuing preferred stock or
common stock, if necessary. The continued availability of these methods of
financing will be dependent on many factors, including conditions in the
securities markets, economic conditions, and the level of the Company's income
and cash flow.
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.
In February 1997, the Company purchased at a discount on the open market,
and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock.
The shares, having a par value of $40,300, were purchased for $21,271, creating
a net gain of $19,029.
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.
On July 30, 1997, the Company borrowed $98.5 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $98.5 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and
their interest rate is adjusted periodically to reflect prevailing market
conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75%
at December 31, 1997. The Company has used the proceeds of this $98.5 million
borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987
Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series
B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990
Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of
tax-exempt bonds on which the Company also had a payment obligation to a trustee
for the bondholders. Expenses associated with this transaction, including
redemption premiums totaling $2,055,000 and other expenses of approximately
$1,500,000, were paid by the Company.
In August 1997, the Company purchased at a discount on the open market, and
canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and
200 shares of its $100 par value 4.64%, Series C preferred stock. These shares,
having a par value of $70,000, were purchased for $41,100, creating a net gain
of $28,900.
On November 12, 1997, the Company refinanced the secured lease obligation
bonds that were issued in 1990 in connection with the sale and leaseback by the
Company of a portion of its ownership share in Seabrook Unit 1. All of the
outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook Lease
Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of 10.24%
Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were redeemed.
The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds were
$1,884,549 and $8,589,901, respectively. The Bonds were refunded with the
proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook
Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds"), the principal of
which will be payable from time to time in installments. Transaction expenses
totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from
the proceeds of the 7.83% Bonds and will be repaid as part of the Company's
Lease payments over the remaining term of the Lease. The remainder of the
redemption premiums ($2,334,472) and transaction expenses were paid by the
Company and will be amortized over the remainder of the Lease term. The
transaction reduces the interest rate on the leaseback arrangement, which is
treated as long-term debt on the Company's Consolidated Balance Sheet, from
8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76%
Bonds and $49,850,000 principal amount of the 10.24% Bonds.
- 36 -
The Company used the proceeds from the redemption of these bonds ($70,662,688,
including redemption premiums totaling $3,815,688), plus available funds and
short-term borrowings, to purchase $101,388,000 principal amount of the 7.83%
Bonds. The Company intends to hold the 7.83% Bonds until maturity and has
recognized the investment as an offset to long-term debt on its Consolidated
Balance Sheet.
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by 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, 1997, the Company had $30 million of short-term borrowings outstanding under
this facility.
In addition, as of December 31, 1997, one of the Company's subsidiaries,
American Payment Systems, Inc., had borrowings of $7.8 million outstanding under
a bank line of credit agreement.
At December 31, 1997, the Company had $32.0 million of cash and temporary
cash investments, an increase of $25.6 million from the balance at December 31,
1996. The components of this increase, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
--------
Balance, December 31, 1996 $ 6.4
-----
Net cash provided by operating activities 168.4
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (34.2)
- Dividend payments (40.6)
Net cash used in investing activities, excluding
investment in plant (34.6)
Cash invested in plant, including nuclear fuel (33.4)
----
Net Change in Cash 25.6
----
Balance, December 31, 1997 $32.0
====
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, 1997 this
coverage ratio was 3.23:1.0.
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
- 37 -
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of other utilities. Another
subsidiary of URI, Thermal Energies, Inc., is participating in the development
of district heating and cooling facilities in the downtown New Haven area,
including the energy center for an office tower and participation as a 52%
partner in the energy center for a city hall and office tower complex. A third
URI subsidiary, Precision Power, Inc., provides power-related equipment and
services to the owners of commercial buildings and industrial facilities. URI's
fourth subsidiary, United Bridgeport Energy, Inc., is participating in a
merchant wholesale electric generating facility being constructed on land leased
from UI at its Bridgeport Harbor Station generating plant.
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)
---------------- --------- ----------
(Basic & Diluted)
1997 $(542) $(0.04) $27,873
1996 (5,237) (0.37) 36,385
1995 (2,640) (0.19) 16,323
In 1996, the Company made provisions for losses of $2.6 million (after-tax)
associated with agent collections and miscellaneous other items at its American
Payment Systems, Inc. subsidiary.
RESULTS OF OPERATIONS
1997 VS. 1996
-------------
Earnings for the year 1997 were $45.6 million, or $3.27 basic earnings per
share, up $5.0 million, or $.39 per share, from 1996. Earnings from operations,
which exclude one-time items and accelerated amortization of costs attributable
to one-time items, decreased by $12.2 million, or $.83 per share, in 1997
compared to 1996. The most significant one-time item recorded in 1997 was a gain
from an income tax expense reduction of $6.7 million in the second quarter, or
$.48 per share, which makes provision for the cumulative deferred tax benefits
associated with the future decommissioning of fossil-fueled generating plants.
By order of the Connecticut Department of Public Utility Control (DPUC), the
Company was required to accelerate the amortization of regulatory assets by as
much as $6.4 million ($4.1 million after-tax), or $.30 per share, provided that
the 1997 return on utility common stock equity would exceed 10.5 percent for the
year. As a result of the tax benefit, the full $6.4 million was charged in the
second quarter of 1997. SEE THE LOOKING FORWARD SECTION FOR MORE INFORMATION ON
THE DPUC ORDER.
Additional 1997 one-time items include a $.05 per share gain related to
subleasing office space, a gain of $2.5 million ($1.5 million after-tax), or
$.11 per share, related to forgone benefits associated with the 1996 voluntary
retirement and separation programs, and a charge of $4.3 million ($2.5 million
after-tax), or $.18 per share, for terminating a consulting contract. The
one-time items recorded in 1996, which amounted to a net loss of $1.06 per share
were: charges of $23.0 million ($13.4 million after-tax), or $.95 per share,
from early retirement and voluntary severance programs, a charge of $1.4 million
($0.8 million after-tax), or $.06 per share, for the cumulative loss on an
office space sublease, a charge of $2.6 million (after-tax), or $.18 per share,
related to subsidiary operations, and a gain of $1.8 million (after-tax), or
$.13 per share, from the repurchase of preferred stock at a discount to par
value.
Retail operating revenues decreased by about $26.3 million in 1997 compared
to 1996:
- 38 -
. Results for 1997 reflect an ADJUSTMENT TO RETAIL KILOWATT-HOUR SALES AND
REVENUE, made in the fourth quarter of 1997, to reverse prior period
overestimates of transmission losses. The adjustment added 25 million
kilowatt-hours, a 0.5 percent increase compared to 1996 kilowatt-hour
sales, and $2.7 million of revenues.
. An additional retail kilowatt-hour sales increase of 0.2% from the prior
year increased retail revenues by $1.6 million and sales margin (revenue
less fuel expense and revenue-based taxes) by $1.1 million. The Company
believes that weather factors had a negative impact on retail kilowatt-hour
sales of about 0.5 percent. There was one less day in 1997 (1996 was a leap
year), which decreased retail kilowatt-hour sales by 0.3 percent. This
would indicate that "real" (i.e. not attributable to abnormal weather or
the leap year day in 1996) kilowatt-hour sales increased by about 1.0-1.5
percent for the year.
. Reductions in customer bills, as agreed to by the Company and the DPUC in
December 1996, decreased retail revenues by about $23.0 million, including
suspension of the fossil fuel adjustment clause (FAC) mechanism that
reduced revenues by $6.0 million. This was a somewhat greater decrease than
expected, principally because of a decrease in conservation spending. Other
reductions in customer bills, due to rate mix, contract pricing and other
pass-through reductions, amounted to $7.6 million.
Wholesale "capacity" revenues increased $2.1 million in 1997 compared to
1996. Wholesale "energy" revenues, which increased during 1997 compared to 1996
as a result of nuclear generating unit outages in the region, are a direct
offset to wholesale energy expense and do not contribute to sales margin.
Retail fuel and energy expenses increased by $14.2 million in 1997 compared
to 1996. These expenses increased by $12.6 million due to the need for more
expensive energy to replace generation by nuclear generating units: for the
Connecticut Yankee unit, which ran at nearly full capacity in the first six and
one-half months of 1996, for Millstone Unit 3, which ran at nearly full capacity
in the first quarter of 1996, for an unplanned eight-day extension of a Seabrook
unit refueling outage in the second quarter of 1997 that increased the Company's
replacement generation cost by about $0.7 million, and for an unplanned Seabrook
unit outage that began on December 5, 1997. The Seabrook unit was returned to
service from the last outage on January 17, 1998. Millstone Unit 3 was taken out
of service on March 30, 1996 and Connecticut Yankee was taken out of service on
July 23, 1996. For more on the status of the Connecticut Yankee and Millstone
Unit 3 units, see the LOOKING FORWARD section. Retail fuel and energy expenses
also increased by about $1.6 million in 1997 compared to 1996, due to higher
fossil fuel prices. By order of the DPUC, these costs are not passed on to
customers through the FAC.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $1.7 million, excluding the impact of one-time items, in
1997 compared to 1996:
. Purchased capacity expense decreased $6.9 million, due to declining costs
from the retired Connecticut Yankee nuclear generating unit, and also due
to slightly lower cogeneration costs.
. Operation and maintenance expense increased by $5.1 million. General,
refueling and unscheduled outage expenses at the Seabrook nuclear
generating unit increased about $2.9 million, and general expenses at the
Millstone 3 nuclear generating unit increased $4.8 million. Expenses
associated with the Company's re-engineering efforts increased by a net
$1.0 million. Other general expenses increased by about $2.9 million. These
increases were partly offset by a $4.6 million reduction in pension expense
due to investment performance and changes in actuarial assumptions and
methodologies, and health benefit reductions of $1.9 million. The increase
at Millstone Unit 3 was partly offset by the reversal of a portion of a
1996 provision in "Other income (deductions)".
Depreciation expense, excluding the impact of one-time items, increased by
$2.3 million in 1997 compared to 1996. Income taxes, exclusive of the effects of
one-time items, changed based on changes in taxable income and tax rates.
- 39 -
Other net income increased by $4.6 million in 1997 compared to 1996 due to
an improvement in earnings (reduction in losses) from unregulated subsidiaries.
The Company's largest unregulated subsidiary, American Payment Systems, earned
about $101,000 ($47,000 after-tax) in 1997, an improvement of $3.8 million ($2.2
million after-tax) over 1996 losses, excluding one-time items, of about $3.7
million ($2.1 million after-tax). Other UI subsidiaries lost $1.0 million ($0.6
million after-tax) compared to a loss of $0.8 million in 1996. The remainder of
the improvement in other net income was due to an increase of $0.8 million in
interest income.
Interest charges continued their significant decline, decreasing by $7.5
million, or 11 percent, in 1997 compared to 1996 as a result of the Company's
refinancing program and strong cash flow. Also, total preferred dividends
(net-of-tax) decreased slightly in 1997 compared to 1996 as a result of
purchases of preferred stock by the Company in 1996.
1996 VS. 1995
-------------
Earnings for the year 1996 were $40.6 million, or $2.88 basic earnings 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 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.
- 40 -
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 section. Other fuel and energy expenses increased by $4.4
million, primarily from increases in "pass through" charges, including fossil
fuel costs.
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.
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year rate plan
-------------------
On December 31, 1996, the DPUC issued an order (the Order) that implemented
a 5-year regulatory framework that would reduce the Company's retail prices and
accelerate the recovery of certain "regulatory" assets beginning with deferred
conservation costs. The Order's schedule of price reductions and accelerated
amortizations was based on a DPUC pro forma financial analysis that anticipated
the Company would be able to implement such changes and earn an allowed return
on common stock equity invested in utility assets of 11.5% over the period 1997
to 2001. The Order established a set formula to share any income that would
produce a return above the 11.5% level: one-third would be applied to customer
bill reductions, one-third would be applied to additional amortization of
regulatory assets, and one-third would be retained by shareowners.
- 41 -
It should be noted that, although the Order was for the five-year period
1997-2001 and the Company agreed that it would begin to implement the multi-year
plan, it did not agree to commit to the five-year period. In addition, the DPUC,
in the Order, acknowledged that the Order could be revisited in the light of any
new legislation. The Connecticut legislature did not pass an electric utility
restructuring bill in the 1997 legislative session, but such legislation has
been reintroduced in 1998.
1998 Earnings
-------------
The Company's income from its utility business is greatly affected by:
retail sales that fluctuate with weather conditions and economic activity,
fossil fuel prices, nuclear generating unit availability and operating costs,
and interest rates. These are all items over which the Company has little
control, although the Company engages in economic development activities to
increase sales, and hedges its exposure to volatile fuel costs and interest
rates.
The Company's revenues are principally dependent on the level of retail
sales. The two primary factors that affect retail sales volume are economic
conditions and weather. The Company estimates that mild 1997 weather reduced
retail kilowatt-hour sales by about 0.5 percent for the year. Because much of
the mild weather occurred in the summer months, when prices are higher than
average, the revenue impact was exacerbated. It is estimated that mild weather
may have reduced revenues by as much as $5.2 million for the year, and sales
margin (revenue less fuel expense and revenue-based taxes) by as much as $4.2
million. Weather corrected retail sales for 1997 were probably in the
5,375-5,420 gigawatt-hour range. On this basis, the Company experienced about
1-1.5 percent of "real" sales growth in 1997 (i.e. exclusive of weather and leap
year factors) over "normal" 1996 sales, with almost all of the growth occurring
in the last half of the year. A similar level of growth in 1998 compared to 1997
from all customer groups would add about $6-$8 million to sales margin.
Reductions in revenues could occur for several reasons. The Company has
dealt with the potential loss of customers as a result of self-generation,
relocation or discontinuation of operations by successfully negotiating 62
multi-year contracts with major customers. Such a contract has been signed with
Yale University, the Company's largest customer, which is constructing a
cogeneration unit that will produce approximately one half of its annual
electricity requirements (about 1.5 percent of the Company's total 1997 retail
sales) commencing sometime in early 1998. While providing cost reduction and
price stability for customers and helping the Company maintain its customer base
for the long term, these contracts are expected to cause future reductions in
retail revenues. They reduced retail revenues by about $3 million in 1997
compared to 1996, but are not expected to approach that level of change in 1998.
Additionally, rate migration (customers switching to rates that are more
favorable because of usage patterns) reduced retail revenues by about $3 million
in 1997 compared to 1996; but the impact of rate migration on revenues in 1998
compared to 1997 is expected to be less than $1 million. Also, as part of the
Order, the operation of the Company's long-standing fossil fuel adjustment
clause (FAC) mechanism that allowed for recovery in retail rates of changes in
fossil fuel costs was suspended within a broad range of fuel prices. FAC
revenues will decline by about $2 million in 1998, to zero, compared to 1997,
due to this suspension of the FAC.
To summarize, assuming 1997 rates of "real" growth and the expected loss of
sales due to Yale University cogeneration, little change in retail kilowatt-hour
sales is expected in 1998 compared to 1997. Retail revenues should decline by
several million dollars or more if the Company is in the "sharing" range above
an 11.5% return on common stock equity. The overall average retail price
anticipated for 1998 is about 11.6 cents per kilowatt-hour, almost 5 percent
below the 1996 peak level.
Wholesale capacity prices strengthened in short-term markets during 1997,
due to outages of regional nuclear generating plants and changes in the New
England Power Pool (NEPOOL) capability responsibility requirements for its
participants. Wholesale capacity and transmission sales revenues increased $2.1
million in 1997 compared to 1996. The strength of these markets for 1998 will
depend on the timing of the return to service of the nuclear units at Millstone
Station, on the addition of new generation sources, and on how the capacity and
energy markets perform under the new NEPOOL open competition system, designed to
meet Federal Energy Regulatory Commission (FERC) open access orders, when it is
implemented. Implementation of this system is currently
- 42 -
expected in mid-1998; but this date is subject to NEPOOL information system
development and testing and further orders from the FERC. No significant sales
margin improvement is expected from wholesale capacity sales. Wholesale energy
revenues should remain similar to wholesale energy expense and not contribute
significantly to sales margin.
Another major factor affecting the Company's 1998 earnings prospects will
be the Company's ability to control operating expenses. The Company offered
voluntary early retirement programs and a voluntary severance program to union,
nonunion and management employees in 1996. A portion of the resulting personnel
cost savings occurred in 1996 and 1997, but the majority of the savings will be
realized in 1998. Savings of $6 million from personnel reductions are estimated.
The Company is expecting other significant expense declines in 1998
compared to 1997 from a number of sources. From the nuclear generating units, it
is expected that operation and maintenance expenses associated with the Seabrook
and Connecticut Yankee units should decline by a total of about $9 million. The
Seabrook unit should have no refueling outage in 1998 and, if it operates at an
assumed 95% availability (it was available virtually 100% between outages in
1997), net fuel expense should decline by about $2 million.
Millstone Unit 3 was taken out of service on March 30, 1996, and will
remain shut down pending a comprehensive Nuclear Regulatory Commission (NRC)
inquiry into the conformity of the unit and its operations with all applicable
NRC regulations and standards. The Company anticipates that, once NRC
deficiencies are corrected and Unit 3 is returned to service, operating costs
should ramp down to more normal levels for an efficient and safe nuclear unit of
this class. Also, if Millstone Unit 3 returns to service, net fuel expense
should decline by $400,000 per month for every month of operation, net of the
replacement fuel provision of about $100,000 per month...up to $3.6 million for
the year, if full power is reached by May 1, 1998.
Pension and health benefit expenses, excluding one-time items, are expected
to decrease by about $2.5 million in 1998 compared to 1997. NEPOOL expenses are
expected to increase by about $1.0 million, and information system expenses
associated with the "year 2000 issue" are expected to increase by $2.0 million.
Other operation and maintenance expenses may increase or decrease by amounts
that cannot be predicted at this time.
Interest costs are expected to continue to decline by about $10 million in
1998, reaching a level of about $52 million, a level that was last experienced
in 1984. This interest cost reduction is largely a result of 1997 debt
refinancings and debt paydown (long-term debt was reduced by $85 million in
1997) and an expected 1998 debt paydown of more than $70 million.
Other factors should increase costs. Other operation and maintenance
expense should increase in 1998, compared to 1997, by about $6 million,
reflecting increased fossil-fueled generating unit scheduled maintenance and
provisions for future outages. Base depreciation, excluding accelerated
amortization, should increase about $2.0 million; and accelerated amortization
per the DPUC Order will increase by about $7 million. Other operating expenses
will have some increases and some decreases that should more or less offset one
another.
In summary, the Company expects substantial net expense reductions that
should more than compensate for the loss of one-time items realized in 1997,
cover the increase in accelerated conservation and load management amortization,
and allow utility earnings to increase above an 11.5% return on common stock
equity into the "sharing" range of the DPUC Order. The 11.5% return level would
produce utility earnings of about $3.40-$3.45 per share, while "shared" earnings
should add an additional $.05-$.10 per share. Non-utility earnings should
increase by about $.05-$.10 per share in 1998 compared to 1997, primarily from
an anticipated improvement in the earnings of American Payment Systems, Inc. The
other subsidiaries are expected to break even in 1998. The Company expects that
1998 quarterly earnings from operations will follow a pattern similar to that of
1997 on a weather-normalized basis.
Although the current $2.88 indicated annual common stock dividend level for
1997 represented a payout of 88% of total 1997 earnings, the Company's cash flow
remains, and is expected to remain, very strong. Net cash
- 43 -
provided by operating activities was $168 million in 1997, over 4 times the
common stock dividend payout, one of the highest such "coverage" levels in the
utility industry. The 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 regulatory assets more
rapidly, help it prepare for competition in the electric utility industry, and
help maintain cash flow at its excellent current level through the end of the
decade. If the Company is able to grow income and earnings in 1998 to the extent
indicated above, the common stock dividend payout ratio at the current indicated
annual dividend rate would be reduced to approximately 80%.
Longer Term
-----------
On June 30, 1997, the Company's unionized employees accepted a new
five-year agreement, amending and extending the existing agreement that was
scheduled to remain in effect through May 15, 1998. The new agreement provides
for, among other things, 2% annual wage increases beginning in May 1998, and
annual lump sum bonuses of 2.5% of base annual straight time wages (not
cumulative). These provisions will restrict the growth of the Company's
bargaining unit base wage expense to about $500,000 per year. The agreement also
provides for job security for longer-term bargaining unit employees, and will
allow the Company some flexibility in adjusting work methods, as part of its
ongoing process re-engineering efforts.
Connecticut Yankee expenses are expected to continue to decline by
substantial amounts before leveling out at about $6 million per year after 1999,
compared to $11.8 million in 1997, until decommissioning is complete. However,
the ability of the Company to recover its ownership share of future costs
associated with the retirement of the Connecticut Yankee unit will be dependent
upon the outcome of pending regulatory filings with the Federal Energy
Regulatory Commission.
On August 7, 1997, the Company and the other nine minority joint owners
of Millstone Unit 3 that are not subsidiaries of Northeast Utilities (NU) filed
lawsuits against NU and its trustees, as well as a demand for arbitration
against The Connecticut Light and Power Company and Western Massachusetts
Electric Company, the operating electric utility subsidiaries of NU that are the
majority joint owners of the unit and have contracted with the minority joint
owners to operate it. The ten non-NU joint owners, who together own about 19.5%
of the unit, claim that NU and its subsidiaries failed to comply with NRC
regulations, failed to operate Millstone Station in accordance with good utility
operating practice and concealed their failures from the non-operating joint
owners and the NRC. The arbitration and lawsuits seek to recover costs of
purchasing replacement power and increased operation and maintenance costs
resulting from the shutdown of Millstone Unit 3.
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct all
deficiencies in its computer systems and in the computer systems of the critical
suppliers and other persons with whom data must be exchanged. A complete
inventory and assessment of the Company's computer system applications,
hardware, software and embedded technologies has been completed, and recommended
solutions to all identified risks and exposures have been generated. A
remediation, retirement, renovation and testing program has commenced. Necessary
upgrades to mainframe hardware and software are expected to be completed and
tested during 1998, and a parallel program with respect to desktop hardware and
software is currently projected to be completed and tested by March 31, 1999.
Request for documented compliance information have been sent to all critical
suppliers, data sharers and facility building owners and, as responses are
received, appropriate solutions and testing programs are being developed and
executed. The Company believes that the successful implementation of this
program, which is currently estimated to cost approximately $2.6 million, will
preclude any significant adverse impact of the Year 2000 Issue on its operations
and financial condition.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
1997 1996 1995
---- ---- ----
OPERATING REVENUES (NOTE G) $710,267 $726,020 $690,449
------------- ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 182,666 160,517 138,169
Capacity purchased 39,976 46,830 47,420
Early retirement program charges - 23,033 -
Other 158,600 158,945 147,660
Maintenance 42,203 37,652 36,089
Depreciation 74,618 65,921 61,426
Amortization of cancelled nuclear project and deferred return (Note D and J) 13,758 13,758 13,758
Income taxes (Note A and F) 41,333 53,090 59,828
Other taxes (Note G) 52,540 57,139 58,943
------------- ------------ ------------
Total 605,694 616,885 563,293
------------- ------------ ------------
OPERATING INCOME 104,573 109,135 127,156
------------- ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 336 940 390
Other-net (Note G) 4,186 (7,166) (4,272)
Non-operating income taxes 2,496 9,332 4,901
------------- ------------ ------------
Total 7,018 3,106 1,019
------------- ------------ ------------
INCOME BEFORE INTEREST CHARGES 111,591 112,241 128,175
------------- ------------ ------------
INTEREST CHARGES
Interest on long-term debt 63,063 66,305 63,431
Interest on Seabrook obligation bonds owned by the company (6,905) (1,259) -
Other interest (Note G) 3,280 2,092 9,002
Allowance for borrowed funds used during construction (1,239) (1,435) (2,372)
------------- ------------ ------------
58,199 65,703 70,061
Amortization of debt expense and redemption premiums 2,788 2,629 4,138
------------- ------------ ------------
Net Interest Charges 60,987 68,332 74,199
------------- ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES 4,813 4,813 3,583
------------- ------------ ------------
NET INCOME 45,791 39,096 50,393
Discount on preferred stock redemptions (48) (1,840) (2,183)
Dividends on preferred stock 205 330 1,329
------------- ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $45,634 $40,606 $51,247
============= ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 13,976 14,101 14,090
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 13,992 14,131 14,108
EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.27 $2.88 $3.64
============= ============ ============
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.26 $2.87 $3.63
============= ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.82
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 CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(THOUSANDS OF DOLLARS)
1997 1996 1995
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $45,791 $39,096 $50,393
------------ ------------ ------------
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 79,487 70,363 66,958
Deferred income taxes 7,986 (2,276) 27,495
Deferred investment tax credits - net (762) (762) (762)
Amortization of nuclear fuel 5,799 5,690 13,571
Allowance for funds used during construction (1,575) (2,375) (2,762)
Amortization of deferred return 12,586 12,586 12,586
Early retirement costs accrued - 23,033 -
Changes in:
Accounts receivable - net 16,944 (23,555) 9,489
Fuel, materials and supplies 2,863 239 69
Prepayments 211 (557) 9,256
Accounts payable 641 22,657 2,555
Interest accrued (3,569) (671) (6,420)
Taxes accrued 3,663 (4,794) (11,310)
Other assets and liabilities (1,644) 6,078 (9,627)
------------ ------------ ------------
Total Adjustments 122,630 105,656 111,098
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 168,421 144,752 161,491
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock (6,432) 40 440
Long-term debt 98,500 82,500 150,000
Preferred securities of subsidiary - - 50,000
Notes payable 26,786 10,965 (67,000)
Securities redeemed and retired:
Preferred stock (110) (6,078) (34,161)
Long-term debt (151,199) (72,895) (165,103)
Discount on preferred stock redemption 48 1,840 2,183
Expenses of issues (1,500) (442) (2,222)
Lease obligations (315) (291) (1,169)
Dividends
Preferred stock (206) (410) (1,944)
Common stock (40,408) (40,399) (39,514)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (74,836) (25,170) (108,490)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (33,436) (47,174) (59,363)
Investment in Seabrook obligation bonds (34,541) (71,084) -
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (67,977) (118,258) (59,363)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 25,608 1,324 (6,362)
BALANCE AT BEGINNING OF PERIOD 6,394 5,070 11,432
------------ ------------ ------------
BALANCE AT END OF PERIOD $32,002 $6,394 $5,070
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $59,441 $69,669 $76,271
============ ============ ============
Income taxes $26,773 $51,415 $32,100
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 46 -
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1997, 1996 AND 1995
ASSETS
(Thousands of Dollars)
1997 1996 1995
---- ---- ----
Utility Plant at Original Cost
In service $1,867,145 $1,843,952 $1,809,925
Less, accumulated provision for depreciation 644,971 585,646 532,015
-------------- -------------- ---------------
1,222,174 1,258,306 1,277,910
Construction work in progress 25,448 40,998 41,817
Nuclear fuel 25,990 23,010 25,967
-------------- -------------- ---------------
Net Utility Plant 1,273,612 1,322,314 1,345,694
-------------- -------------- ---------------
Other Property and Investments 32,451 26,081 27,388
-------------- -------------- ---------------
Current Assets
Cash and temporary cash investments 32,002 6,394 5,070
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800, $2,300 and $6,300 57,231 63,722 63,987
Other 27,914 38,367 14,547
Accrued utility revenues 25,269 29,139 28,318
Fuel, materials and supplies, at average cost 19,147 22,010 22,249
Prepayments 3,397 3,608 3,051
Other 67 110 55
-------------- -------------- ---------------
Total 165,027 163,350 137,277
-------------- -------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 6,611 6,580 7,577
Other 5,727 1,485 2,377
-------------- -------------- ---------------
Total 12,338 8,065 9,954
-------------- -------------- ---------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax
differences (Note A) 228,992 289,672 358,168
Connecticut Yankee 51,313 64,851 -
Deferred return - Seabrook Unit 1 25,171 37,757 50,343
Unamortized redemption costs 23,027 25,063 22,244
Unamortized cancelled nuclear project 12,125 13,297 24,620
Uranium enrichment decommissioning costs 1,312 1,377 1,505
Other 6,357 9,068 8,424
-------------- -------------- ---------------
Total 348,297 441,085 465,304
-------------- -------------- ---------------
$1,831,725 $1,960,895 $1,985,617
============== ============== ===============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 47 -
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
December 31, 1997, 1996 and 1995
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1997 1996 1995
---- ---- ----
Capitalization (Note B)
Common stock equity
Common stock $288,730 $284,579 $284,542
Paid-in capital 1,349 772 769
Capital stock expense (2,182) (2,182) (2,207)
Unearned employee stock ownership plan equity (11,160) - -
Retained earnings 162,226 156,847 156,877
-------------- -------------- ---------------
438,963 440,016 439,981
Preferred stock 4,351 4,461 10,539
Minority interest in preferred securities 50,000 50,000 50,000
Long-term debt
Long-term debt 746,058 826,527 845,684
Investment in Seabrook obligation bonds (101,388) (66,847) -
-------------- -------------- ---------------
Net long-term debt 644,670 759,680 845,684
Total 1,137,984 1,254,157 1,346,204
-------------- -------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 40,821 54,752 -
Pensions accrued (Note H) 39,149 49,205 33,832
Nuclear decommissioning obligation 17,538 12,851 10,317
Obligations under capital leases 16,853 17,193 17,508
Other 5,507 4,815 4,090
-------------- -------------- ---------------
Total 119,868 138,816 65,747
-------------- -------------- ---------------
Current Liabilities
Current portion of long-term debt 100,000 69,900 40,800
Notes payable 37,751 10,965 -
Accounts payable 68,699 68,058 45,401
Dividends payable 10,051 10,205 10,072
Taxes accrued 4,166 503 5,297
Interest accrued 10,266 13,835 14,506
Obligations under capital leases 340 315 291
Other accrued liabilities 37,471 36,091 26,769
-------------- -------------- ---------------
Total 268,744 209,872 143,136
-------------- -------------- ---------------
Customers' Advances for Construction 1,878 1,888 2,655
-------------- -------------- ---------------
Regulatory Liabilitie (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 16,385 17,147 17,909
Other 2,356 1,811 1,990
-------------- -------------- ---------------
Total 18,741 18,958 19,899
-------------- -------------- ---------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities) 284,510 337,204 407,976
Commitments and Contingencies (Note L)
-------------- -------------- ---------------
$1,831,725 $1,960,895 $1,985,617
============== ============== ===============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 48 -
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THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(THOUSANDS OF DOLLARS)
1997 1996 1995
---- ---- ----
BALANCE, JANUARY 1 $156,847 $156,877 $145,559
Net income 45,791 39,096 50,393
Adjustments associated with repurchase
of preferred stock 48 1,815 1,988
------------- ------------- -------------
Total 202,686 197,788 197,940
------------- ------------- -------------
Deduct Cash Dividends Declared
Preferred stock 205 330 1,329
Common stock 40,255 40,611 39,734
------------- ------------- -------------
Total 40,460 40,941 41,063
------------- ------------- -------------
BALANCE, DECEMBER 31 $162,226 $156,847 $156,877
============= ============= =============
The accompanying Notes to Consolidated Financial Statements are
an integral part of the financial statements.
- 49 -
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, 1997, $27
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.
(A) STATEMENT OF ACCOUNTING POLICIES
ACCOUNTING RECORDS
The accounting records are maintained in accordance with the uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC) and the Connecticut Department of Public Utility Control (DPUC).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to use estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, United Resources Inc. Intercompany accounts and
transactions have been eliminated in consolidation.
REGULATORY ACCOUNTING
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 obligations relieved in the future through
the ratemaking process. In addition to the Regulatory Assets and Liabilities
separately identified on the Consolidated Balance Sheet, there are other
regulatory assets and liabilities such as conservation and load management costs
and certain deferred tax liabilities. The Company also has obligations under
long-term power contracts, the recovery of which is subject to regulation.
- 50 -
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 could have a material adverse effect on
the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
See Note (C), Rate-Related Regulatory Proceedings.
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, 1997, 1996 and
1995 was comprised as follows:
1997 1996 1995
---- ---- ----
(000's)
Production $1,131,285 $1,124,113 $1,122,001
Transmission 161,288 160,970 158,373
Distribution 401,426 387,825 375,962
General 52,776 47,889 45,924
Future use plant 30,594 32,751 32,762
Other 89,776 90,404 74,903
--------- --------- ---------
$1,867,145 $1,843,952 $1,809,925
========= ========= =========
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 1997, 1996 and 1995 were 7.5%, 9.0% and 8.0%,
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
- 51 -
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 1997,
1996 and 1995 were equivalent to approximately 3.15%, 3.12% and 3.07%,
respectively, of the original cost of depreciable property.
INCOME TAXES
In accordance with Statement of Financial Accounting Standards (SFAS) No.
109 "Accounting for Income Taxes", the Company has provided deferred taxes for
all temporary book-tax differences using the liability method. The liability
method requires that deferred tax balances be adjusted to reflect enacted future
tax rates that are anticipated to be in effect when the temporary differences
reverse. In accordance with generally accepted accounting principles for
regulated industries, the Company has established a regulatory asset for the net
revenue requirements to be recovered from customers for the related future tax
expense associated with certain of these temporary differences.
For ratemaking purposes, the Company normalizes all investment tax credits
(ITC) related to recoverable plant investments except for the ITC related to
Seabrook Unit 1, which was taken into income in accordance with provisions of a
1990 DPUC retail rate decision.
ACCRUED UTILITY REVENUES
The estimated amount of utility revenues (less related expenses and
applicable taxes) for service rendered but not billed is accrued at the end of
each accounting period.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments. The Company 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 $2.3 million, $3.4 million and $3.9 million, at December 31, 1997,
1996 and 1995, 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 $10.5 million,
$10.1 million and $9.6 million at December 31, 1997, 1996 and 1995,
respectively, and is included on the Consolidated Balance Sheet in "Other
Property and Investments" at December 31, 1995 and as a regulatory asset at
December 31, 1997 and 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
has suspended this deferred
- 52 -
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.
INTEREST RATE AND FUEL PRICE MANAGEMENT
The Company utilizes interest rate and fuel oil price management
instruments to manage interest rate and fuel oil price risk. Interest rate swap
agreements have been entered into that effectively convert the interest rates on
$225 million of variable rate term loan borrowings to fixed rate borrowings.
Amounts receivable or payable under these swap agreements are accrued and
charged to interest expense. The Company enters into basic fuel oil price
management instruments to help minimize fuel oil price risk by fixing the future
price for fuel oil used for generation. Amounts receivable or payable under
these instruments are recognized in income when realized.
As of December 31, 1997, the Company had entered into swap agreements
for 1998 for 795,000 barrels of fuel oil at a weighted average price of $16.33
per barrel and had call options for 590,000 barrels of fuel oil at a weighted
average price of $18.45 per barrel.
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.
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, 1997, the
Company's unfunded share of the obligation, based on its ownership interest in
Seabrook Unit 1 and Millstone Unit 3, was approximately $1.2 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.
- 53 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $2,571,000, $2,130,000 and $1,882,000
during 1997, 1996 and 1995 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1997, the Company's shares of the
trust fund balances, which included accumulated earnings on the funds, were
$12.4 million and $5.1 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
IMPAIRMENT OF LONG-LIVED ASSETS
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets to Be Disposed Of" requires the recognition
of impairment losses on long-lived assets when the book value of an asset
exceeds the sum of the expected future undiscounted cash flows that result from
the use of the asset and its eventual disposition. This standard also requires
that rate-regulated companies recognize an impairment loss when a regulator
excludes all or part of a cost from rates, even if the regulator allows the
company to earn a return on the remaining allowable costs. Under this standard,
the probability of recovery and the recognition of regulatory assets under the
criteria of SFAS No. 71 must be assessed on an ongoing basis. The Company does
not have any assets that are impaired under this standard.
APS REVENUES AND AGENT COLLECTIONS
APS recognized revenue of $31.7 million, $19.2 million and $6.8 million for
the years 1997, 1996 and 1995, 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.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued SFAS No.
128, "Earnings per Share". This statement, which is effective for financial
statements issued for periods ending after December 15, 1997, including interim
periods, establishes simplified standards for computing and presenting earnings
per share (EPS). It requires dual presentation of basic and diluted EPS on the
face of the income statement for entities with complex capital structures and
disclosure of the calculation of each EPS amount.
- 54 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table presents a reconciliation of the numerators and
denominators of the basic and diluted earnings per share calculations for the
years 1997, 1996 and 1995:
[Enlarge/Download Table]
(In thousands except per share amounts)
Income Applicable to Average Number of
Common Stock Shares Outstanding Earnings
(Numerator) (Denominator) per Share
----------- ------------- ---------
1997
----
Basic earnings per share $45,634 13,976 $3.27
Effect of dilutive stock options - 16 (.01)
------ ------ ----
Diluted earnings per share $45,634 13,992 $3.26
====== ====== ====
1996
----
Basic earnings per share $40,606 14,101 $2.88
Effect of dilutive stock options - 30 (.01)
------ ------ ----
Diluted earnings per share $40,606 14,131 $2.87
====== ====== ====
1995
----
Basic earnings per share $51,247 14,090 $3.64
Effect of dilutive stock options - 18 (.01)
------ ------ ----
Diluted earnings per share $51,247 14,108 $3.63
====== ====== ====
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation". This statement establishes financial accounting and
reporting standards for stock-based employee compensation plans, such as stock
purchase plans, stock options, restricted stock, and stock appreciation rights.
The statement defines the methods of determining the fair value of stock-based
compensation and requires the recognition of compensation expense for book
purposes. However, the statement allows entities to continue to measure
compensation expense in accordance with the prior authoritative literature, APB
No. 25, "Accounting for Stock Issued to Employees", but requires that pro forma
net income and earnings per share be disclosed for each year for which an income
statement is presented as if SFAS No. 123 had been applied. The accounting
requirements of this statement are effective for transactions entered into after
1995. However, pro forma disclosures must include the effects of all awards
granted after January 1, 1995. As of December 31, 1997, 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.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information". This
statement, which is effective for financial statements issued for fiscal years
beginning after December 15, 1997, requires entities to disclose specific
financial and descriptive information about its reportable operating segments.
Reportable operating segments are components of an entity about which separate
financial information is available that is regularly used when evaluating
segment performance and determining the allocation of resources. The Company
currently does not have separate reportable segments to which this standard
would apply.
- 55 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
December 31,
---------------------------------------------------------------------------------------
1997 1996 1995
Shares Shares Shares
Outstanding $(000's) Outstanding $(000's) Outstanding $(000's)
-------------- ------------ -------------- ------------ -------------- ------------
COMMON STOCK EQUITY
Common stock, no par value,
at December 31(a) 13,907,824 $288,730 14,101,291 $284,579 14,100,091 $284,542
Shares authorized
1995 30,000,000
1996 30,000,000
1997 30,000,000
Paid-in capital 1,349 772 769
Capital stock expense (2,182) (2,182) (2,207)
Unearned employee stock ownership plan equity (11,160) - -
Retained earnings (b) 162,226 156,847 156,877
------------ ------------ ------------
Total common stock equity 438,963 440,016 439,981
------------ ------------ ------------
PREFERRED AND PREFERENCE STOCK (C)
Cumulative preferred stock,
$100 par value, shares
authorized at December 31,
1995 1,180,394
1996 1,119,612
1997 1,119,612
Preferred stock issues:
4.35% Series A 10,894 11,297 21,247
4.72% Series B 17,158 17,658 30,490
4.64% Series C 12,745 12,945 12,945
5 5/8% Series D 2,712 2,712 40,712
-------------- -------------- --------------
43,509 4,351 44,612 4,461 105,394 10,539
-------------- ------------ -------------- ------------ -------------- ------------
Cumulative preferred stock, $25 par
value: 2,400,000 shares authorized
Preferred stock issues - - - - - -
Cumulative preference stock, $25 par
value: 5,000,000 shares authorized
Preference stock issues - - - - - -
------------ ------------ ------------
Total preferred stock not
subject to mandatory redemption 4,351 4,461 10,539
------------ ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES (D) 50,000 50,000 50,000
------------ ------------ ------------
- 56 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
December 31,
-------------------------------------------------
1997 1996 1995
$(000's) $(000's) $(000's)
------------- ------------- --------------
LONG-TERM DEBT (E)
First Mortgage Bonds:
9.44%, Series B - $32,400 $43,200
Other Long-term Debt
Pollution Control Revenue Bonds:
9 1/2%, 1986 Series, due June 1, 2016 - - 7,500
Variable rate, 1996 Series, due June 26, 2026 7,500 7,500 -
9 3/8%, 1987 Series, due July 1, 2012 - 25,000 25,000
10 3/4%, 1987 Series, due November 1, 2012 - 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
Pollution Control Refunding Revenue Bonds:
Variable rate, 1997 Series, due July 30, 2027 98,500 - -
Notes:
7.00%, 1992 Series E, due January 15, 1997 - - 50,000
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 50,000
6.47%, due September 6, 2000 50,000 50,000 50,000
6.4375%, due September 6, 2000 50,000 50,000 50,000
6.675%, due October 25, 2001 25,000 25,000 -
7.005% due October 25, 2001 50,000 50,000 -
Obligation under the Seabrook Unit 1
sale/leaseback agreement 225,601 243,660 248,030
------------- ------------- --------------
846,061 896,520 886,690
Unamortized debt discount less premium (3) (93) (206)
------------- ------------- --------------
Total long-term debt 846,058 896,427 886,484
Less:
Current portion included in Current Liabilities (e) 100,000 69,900 40,800
Investment-Seabrook Lease Obligation Bonds 101,388 66,847 -
------------- ------------- --------------
Total long-term debt included in Capitalization 644,670 759,680 845,684
------------- ------------- --------------
TOTAL CAPITALIZATION $1,137,984 $1,254,157 $1,346,204
============= ============= ==============
- 57 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(A) COMMON STOCK
The Company had 14,236,124 shares of its common stock, no par value,
outstanding at December 31, 1997, of which 328,300 shares were unallocated
shares held by the Company's Employee Stock Ownership Plan ("ESOP") and not
recognized as outstanding for accounting purposes.
The Company issued 134,833 shares of common stock in 1997, 1,200 shares of
common stock in 1996 and 13,400 shares of common stock in 1995, 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 from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date of the grant. Options to purchase 17,799 shares
of stock at an exercise price of $30 per share, 54,500 shares of stock at an
exercise price of $30.75 per share, 4,000 shares of stock at an exercise price
of $35.625 per share, 33,799 shares of stock at an exercise price of $39.5625
per share, and 5,000 shares of stock at an exercise price of $42.375 per share
have been granted by the Board of Directors and remained outstanding at December
31, 1997.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of December 31, 1997, 328,300 shares, with a fair market value of
$15.1 million, had been purchased by the ESOP and had not been committed to be
released or allocated to ESOP participants.
(B) RETAINED EARNINGS RESTRICTION
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$104.1 million were free from such limitations at December 31, 1997.
(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.
In February 1997, the Company purchased at a discount on the open market,
and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock.
The shares, having a par value of $40,300, were purchased for $21,271, creating
a net gain of $19,029.
In August 1997, the Company purchased at a discount on the open market, and
canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and
200 shares of its $100 par value 4.64%, Series C preferred stock. These shares,
having a par value of $70,000, were purchased for $41,100, creating a net gain
of $28,900.
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
- 58 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
quarters, or if certain other events 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,
1997.
(D) PREFERRED CAPITAL SECURITIES
United Capital Funding Partnership L.P. ("United Capital") is a special
purpose limited partnership in which the Company owns all of the general partner
interests. United Capital has $50 million of its monthly income 9 5/8% Preferred
Capital Securities, Series A, ("Preferred Capital Securities") outstanding,
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.
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.
(E) LONG-TERM DEBT
The expenses to issue long-term debt are deferred and amortized over the
life of the respective debt issue.
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.
On July 30, 1997, the Company borrowed $98.5 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $98.5 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and
their interest rate is adjusted periodically to reflect prevailing market
conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75%
at December 31, 1997. The Company has used the proceeds of this $98.5 million
borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987
Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series
B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990
Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of
tax-exempt bonds on which the Company also had a payment obligation to a trustee
for the bondholders. Expenses associated with this transaction, including
redemption premiums totaling $2,055,000 and other expenses of approximately
$1,500,000, were paid by the Company.
On November 12, 1997, the Company refinanced the secured lease obligation
bonds that were issued in 1990 in connection with the sale and leaseback by the
Company of a portion of its ownership share in Seabrook Unit 1. All
- 59 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
of the outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook
Lease Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of
10.24% Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were
redeemed. The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds
were $1,884,549 and $8,589,901, respectively. The Bonds were refunded with the
proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook
Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds") the principal of
which will be payable from time to time in installments. Transaction expenses
totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from
the proceeds of the 7.83% Bonds and will be repaid as part of the Company's
Lease payments over the remaining term of the Lease. The remainder of the
redemption premiums ($2,334,472) and transaction expenses were paid by the
Company and will be amortized over the remainder of the Lease term. The
transaction reduces the interest rate on the leaseback arrangement, which is
treated as long-term debt on the Company's Consolidated Balance Sheet, from
8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76%
Bonds and $49,850,000 principal amount of the 10.24% Bonds. The Company used the
proceeds from the redemption of these bonds ($70,662,688, including redemption
premiums totaling $3,815,688), plus available funds and short-term borrowings,
to purchase $101,388,000 principal amount of the 7.83% Bonds. The Company
intends to hold the 7.83% Bonds until maturity and has recognized the investment
as an offset to long-term debt on its Consolidated Balance Sheet.
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
- 60 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Maturities and mandatory redemptions/repayments are set forth below:
[Download Table]
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(000's)
Maturities $100,000 $100,000 $150,000 $75,000 $ -
Mandatory redemptions/repayments (1) 4,194 3,410 430 333 338
------- ------- ------- ------ ---
Maturities, Mandatory and Optional
redemptions/repayments $104,194 $103,410 $150,430 $75,333 $338
======= ======= ======= ====== ===
(1) Principal component of Seabrook lease obligation, net of principal
repayment of Seabrook Lease Obligation Bonds held as an investment.
As of December 31, 1997, the Company had $200 million principal amount of
Notes for sale to the public from time to time, in one or more series,
registered under the Securities Act of 1933. On January 13, 1998, the Company
issued and sold $100 million principal amount of these Notes.
(C) RATE-RELATED REGULATORY PROCEEDINGS
Utilities are entitled by Connecticut law to charge retail rates that are
determined by the DPUC to be 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 its DPUC-authorized return on equity 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.
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 existing retail base rates charged to
customers; but its order increased amortization of the Company's conservation
and load management program investments during 1997-1998, and accelerated the
recovery of unspecified regulatory assets during 1999-2001 if the Company's
common stock equity return on utility investment exceeds 10.5% after recording
the increased conservation and load management amortization. The order also
reduced the level of conservation adjustment mechanism revenues in retail
prices, provided a reduction in customer prices through a surcredit in each of
the five plan years, and accepted the Company's proposal to modify the operation
of the fossil fuel clause mechanism. The Company's authorized return on utility
common stock equity was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an
annual basis, are to be utilized one-third for customer price reductions,
one-third to increase amortization of regulatory assets, and one-third retained
as earnings.
A reopening of this docket will be requested by the Company in 1998 to
determine the regulatory assets to be subjected to accelerated recovery in 1999,
2000 and 2001.
In its 1997 session, the Connecticut legislature drafted, but failed to
bring to a vote, comprehensive legislation that would have introduced retail
access in Connecticut over a period of several years, with a provision for the
recovery of stranded costs by service area utilities. The legislature is
currently considering legislation of this same sort in its 1998 session. Among
many other factors, decisions and actions concerning retail access in other
states could impact the timing and form of this legislation.
Since January 1971, UI has had a fossil fuel adjustment clause (FCA) in
virtually all of its retail rates. As a result of the DPUC Order described
above, the Company's FCA has been modified so that the clause will not be
implemented
- 61 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks that
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by 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, 1997, the Company had $30 million of short-term borrowings outstanding under
this facility.
In addition, as of December 31, 1997, one of the Company's subsidiaries,
American Payment Systems, Inc., had borrowings of $7.8 million outstanding under
a bank line of credit agreement.
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,
1997, this coverage ratio was 3.23:1.0.
- 62 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Information with respect to short-term borrowings under the Company's
revolving credit agreement is as follows:
[Enlarge/Download Table]
1997 1996 1995
---- ---- ----
(000's)
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $50,000 $30,000 $195,000
Average aggregate short-term borrowings outstanding during the year* $41,441 $15,380 $117,980
Weighted average interest rate* 5.9% 5.7% 6.5%
Principal amounts outstanding at year-end $30,000 $0 $0
Annualized interest rate on principal amounts outstanding at year-end 6.2% N/A N/A
*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 $114,000, $130,000 and $426,500 paid during 1997, 1996 and
1995, respectively, are excluded from the calculation of the weighted average
interest rate.
- 63 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
1997 1996 1995
----- ----- ----
Income tax expense consists of: (000's)
Income tax provisions:
Current
Federal $23,940 $35,398 $18,031
State 7,673 11,398 10,163
----------- ------------ ------------
Total current 31,613 46,796 28,194
----------- ------------ ------------
Deferred
Federal 7,008 616 24,682
State 978 (2,892) 2,813
----------- ------------ ------------
Total deferred 7,986 (2,276) 27,495
----------- ------------ ------------
Investment tax credits (762) (762) (762)
----------- ------------ ------------
Total income tax expense $38,837 $43,758 $54,927
=========== ============ ============
Income tax components charged as follows:
Operating expenses $41,333 $53,090 $59,828
Other income and deductions - net (2,496) (9,332) (4,901)
----------- ------------ ------------
Total income tax expense $38,837 $43,758 $54,927
=========== ============ ============
The following table details the components
of the deferred income taxes:
Tax depreciation on unrecoverable plant investment $8,089 $5,745 $8,889
Fossil plants decommissioning reserve (7,286) - -
Conservation & load management (5,768) (367) 804
Accelerated depreciation 5,681 5,617 9,410
Pension benefits 4,911 (9,066) (1,460)
Seabrook sale/leaseback transaction 2,664 (598) (397)
Deferred fossil fuel costs (686) 755 (122)
Cancelled nuclear project (467) (4,729) (467)
Unit overhaul and replacement power costs 212 (1,491) -
Alternative minimum tax - - 11,404
Other - net 636 1,858 (566)
----------- ------------ ------------
Deferred income taxes - net $7,986 ($2,276) $27,495
=========== ============ ============
- 64 -
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]
1997 1996 1995
---- ---- ----
Pre-Tax Tax Pre-Tax Tax Pre-Tax Tax
------- --- ------- --- ------- ---
(000's)
Computed tax at federal statutory rate $29,619 $28,999 $36,862
Increases (reductions) resulting from:
Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 12,586 4,405
ITC taken into income (762) (762) (762) (762) (762) (762)
Allowance for equity funds used during
construction (336) (118) (940) (329) (390) (136)
Fossil plant decommissioning reserve (15,591) (5,457) - - - -
Book depreciation in excess of
non-normalized tax depreciation 23,926 8,374 22,703 7,946 21,586 7,555
State income taxes, net of federal
income tax benefits 8,651 5,622 8,506 5,529 12,976 8,434
Other items - net (8,134) (2,846) (5,797) (2,030) (4,090) (1,431)
------ ------ ------
Total income tax expense $38,837 $43,758 $54,927
====== ====== ======
Book income before income taxes $84,628 $82,854 $105,320
====== ====== =======
Effective income tax rates 45.9% 52.8% 52.1%
===== ===== =====
At December 31, 1997 the Company had deferred tax liabilities for taxable
temporary differences of $400 million and deferred tax assets for deductible
temporary differences of $115 million, resulting in a net deferred tax liability
of $285 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, $237 million; tax liabilities on normalization of
book/tax depreciation timing differences, $122 million and tax assets on the
disallowance of plant costs, $47 million.
- 65 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
1997 1996 1995
----- ----- ----
(000'S)
OPERATING REVENUES
------------------
Retail $623,571 $649,876 $639,108
Wholesale - capacity 9,747 7,686 6,601
- energy 73,124 65,158 41,631
Other 3,825 3,300 3,109
------------- ------------- --------------
Total Operating Revenues $710,267 $726,020 $690,449
============= ============= ==============
SALES BY CLASS(MWH'S) - UNAUDITED
---------------------------------
Retail
Residential 1,903,096 1,891,988 1,890,575
Commercial 2,253,488 2,258,501 2,273,965
Industrial 1,170,815 1,141,109 1,126,458
Other 48,717 48,291 48,435
------------- ------------- --------------
5,376,116 5,339,889 5,339,433
Wholesale 2,700,393 2,260,423 1,708,837
------------- ------------- --------------
Total Sales by Class 8,076,509 7,600,312 7,048,270
============= ============= ==============
OTHER TAXES
-----------
Charged to:
Operating:
State gross earnings $23,618 $26,757 $27,379
Local real estate and personal property 22,974 24,854 25,761
Payroll taxes 5,948 5,528 5,800
Other - - 3
------------- ------------- --------------
52,540 57,139 58,943
Nonoperating and other accounts 459 628 527
------------- ------------- --------------
Total Other Taxes $52,999 $57,767 $59,470
============= ============= ==============
OTHER INCOME AND (DEDUCTIONS) - NET
-----------------------------------
Interest income $2,317 $1,505 $2,624
Equity earnings from Connecticut Yankee 1,343 1,225 1,440
Loss from subsidiary companies (814) (8,422) (4,898)
Engineering study costs - - (849)
Miscellaneous other income and (deductions) - net 1,340 (1,474) (2,589)
------------- ------------- --------------
Total Other Income and (Deductions) - net $4,186 ($7,166) ($4,272)
============= ============= ==============
OTHER INTEREST CHARGES
----------------------
Notes Payable $2,462 $882 $7,660
Other 818 1,210 1,342
------------- ------------- --------------
Total Other Interest Charges $3,280 $2,092 $9,002
============= ============= ==============
- 66 -
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 1997, 1996 and
1995 were ($4,626,000), $18,403,000 and $3,842,000, 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, no pension fund contributions were made in
1995. In 1996, the Company contributed $2.8 million for 1995 funding
requirements. In 1997, the Company contributed $2.7 million for 1996 funding
requirements and $2.5 million for 1997 funding requirements. 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, 1997:
PERCENTAGE OF
ASSET CATEGORY TOTAL FUND
-------------- -------------
Equity Securities 72.8%
Fixed-income Securities 24.2%
Real Estate 3.0%
1997 1996
---- ----
(000's)
The components of net pension costs were as follows:
Service cost of benefits earned during the period $ 3,791 $ 4,456
Interest cost on projected benefit obligation 17,565 15,882
Actual return on plan assets (43,225) (24,167)
Net amortization and deferral 19,967 6,336
------ ------
Net pension cost $ (1,902)** $ 2,507*
===== ======
* 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.
** In addition, a credit of $2,724,000 was recognized under SFAS No. 88 as a
curtailment gain resulting from a 1996 voluntary early retirement program.
Assumptions used to determine pension costs were:
Discount rate 7.75% 7.25%
Average wage increase 4.50% 4.50%
Return on plan assets 11.00% 9.00%
- 67 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
DECEMBER 31, 1997 DECEMBER 31, 1996
----------------- -----------------
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 $184,055 $4,716 $165,919 $4,512
======= ===== ======= =====
Accumulated benefit obligation $192,556 $4,720 $174,253 $4,512
======= ===== ======= =====
Reconciliation of accrued pension liability:
Projected benefit obligation $254,192 $5,353 $227,631 $5,152
Less fair value of plan assets (243,739) - 208,863 -
------- ----- ------- -----
Projected benefit greater than plan assets 10,453 5,353 18,768 5,152
Unrecognized prior service cost (4,217) (68) (5,078) (81)
Unrecognized net gain (loss) from past experience 19,272 (13) 21,038 (28)
Unrecognized net asset (obligation)
at date of initial application 8,446 (77) 9,554 (120)
------- ----- ------- -----
Accrued pension liability $ 33,954 $5,195 $ 44,282 $4,923
======= ===== ======= =====
Assumptions used in estimating benefit obligations:
Discount rate 7.25% 7.25% 7.75% 7.75%
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.
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 46% 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 voluntary early
retirement programs minus pay-as-you-go benefit payments for pre-January 1, 1994
retirees, allocated in a manner that minimizes current income tax liability,
without exceeding maximum tax deductible limits. In accordance with this policy,
the Company contributed approximately $3.1 million, $3.8 million and $0 to the
union VEBA in 1995, 1996 and 1997, respectively. The Company contributed $0,
$0.9 million and $1.7 million to the 401(h) account in 1995, 1996 and 1997,
respectively. Plan assets for both the union VEBA and 401(h) account consist
primarily of equity and fixed-income securities.
- 68 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The components of the net cost of OPEB were as follows:
1997 1996
---- ----
(000's)
Service cost $ 925 $1,379
Interest cost 2,434 2,524
Actual return on plan assets (3,836) (1,838)
Amortizations and deferrals - net 3,527 2,359
----- -----
Net Cost of Postretirement Benefit $3,050** $4,424*
===== =====
* In addition, a cost of $4,126,000 was recognized as a result of special
termination programs.
** Includes a credit of $186,000 recognized under SFAS No. 88 as a curtailment
gain resulting from a 1996 voluntary early retirement program.
Assumptions used to determine OPEB costs were:
Discount rate 7.75% 7.25%
Health Care Cost Trend Rate 5.50% 5.50%
Return on plan assets 11.00% 8.50%
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
1997 net cost of periodic postretirement benefit by approximately $400,000 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, 1997 and
1996:
1997 1996
---- ----
(000's)
Accumulated Postretirement Benefit Obligation:
Retirees and dependents $22,847 $22,614
Fully eligible active plan participants 299 929
Other active plan participants 11,966 12,677
------ ------
Total Accumulated Postretirement Benefit Obligation 35,112 36,220
Plan assets at fair value 21,168 16,720
------ ------
Accumulated Postretirement Benefit Obligation in
Excess of Plan Assets 13,944 19,500
Unrecognized net gain (loss) 6,380 2,731
Unamortized transition obligation (17,537) (19,443)
------ ------
Accrued Postretirement Benefit Obligation $ 2,787 $ 2,788
====== ======
The weighted average discount rates used to measure the accumulated
postretirement benefit obligation at December 31, 1997 and 1996 were 7.25% and
7.75%, respectively.
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
- 69 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
funds in a number of investment alternatives. The Company makes matching
contributions in the form of Company common stock for each employee. During 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 1995 and the first five months of 1996 were $1.6
million and $0.8 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 three-eighths percent of the employee's
annual salary. The Company's matching contributions to the ESOP during the
period June 1996 - December 1996 and the year 1997 were $0.8 million and $1.7
million, respectively.
The Company pays dividends on the shares of stock in the ESOP to the
participant and the Company receives a tax deduction 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 1997, 1996 and 1995 were $417,000, $324,000 and
$192,000, respectively.
(I) JOINTLY OWNED PLANT
At December 31, 1997, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT IN ACCUMULATED
SHARE SERVICE DEPRECIATION
--------- -------- ------------
(Millions)
Seabrook Unit 1 17.5 % $650 $131
Millstone Unit 3 3.685 135 59
New Haven Harbor Station 93.7 143 74
The Company's share of the operating costs of jointly owned plants is
included in the appropriate expense captions in the Consolidated Statement of
Income.
(J) UNAMORTIZED CANCELLED NUCLEAR PROJECT
From December 1984 through December 1992, the Company had been recovering
its investment in Seabrook Unit 2, a partially constructed nuclear generating
unit that was cancelled in 1984, over a regulatory approved ten-year period
without a return on its unamortized investment. In the Company's 1992 rate
decision, the DPUC adopted a proposal by the Company to write off its remaining
investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period,
corresponding with the flowback of certain Connecticut Corporation Business Tax
(CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit
2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not
deducted from rate base during the 24-year period of amortization in recognition
of a longer period of time for amortization of the Seabrook Unit 2 balance. As a
result of reducing its remaining unamortized investment in Seabrook Unit 2 with
proceeds from the sale of certain Seabrook Unit 2 equipment, the Company expects
to completely amortize its unamortized investment in the year 2008.
- 70 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for financing up to $37.5 million of fossil fuel purchases. Under this
agreement, the financing entity may acquire and/or store natural gas, coal and
fuel oil for sale to the Company, and the Company may purchase these fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in purchasing and
storing the fuel, plus a charge for maintaining an inventory of the fuel
determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to March 1999. At December 31, 1997, approximately $28.1 million of fossil fuel
purchases were being financed under this agreement.
The Company also has lease arrangements for data processing equipment,
office equipment, vehicles and office space, including the lease of a
distribution service facility, which is recognized as a capital lease. The gross
amount of assets recorded under capital leases and the related obligations of
those leases as of December 31, 1997 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)
1998 $ 1,715
1999 1,696
2000 1,696
2001 1,696
2002 1,696
After 2002 17,695
------
Total minimum capital lease payments 26,194
Less: Amount representing interest 9,001
------
Present value of minimum capital lease payments $17,193
======
Capitalization of leases has no impact on income, since the sum of the
amortization of a leased asset and the interest on the lease obligation equals
the rental expense allowed for ratemaking purposes.
Operating leases, which are charged to operating expense, consist
principally of a large number of small, relatively short-term, renewable
agreements for a wide variety of equipment. In addition, the Company has an
operating lease for its corporate headquarters. Future minimum lease payments
under this lease are estimated to be as follows:
(000's)
1998 $ 6,125
1999 6,426
2000 6,524
2001 6,837
2002 8,168
2003-2012 100,334
-------
Total $134,414
=======
- 71 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Rental payments charged to operating expenses in 1997, 1996 and 1995,
including rental payments for its corporate headquarters, were $12.2 million,
$12.8 million and $11.5 million, respectively.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at approximately $170.0 million, excluding AFUDC, for 1998 through 2002.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $75.5 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $75.5 million, or
$3.775 million. The maximum assessment is adjusted at least every five years to
reflect the impact of inflation. With respect to each of the three nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $23.2 million per incident. However, any
assessment would be limited to $3.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$5.0 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee
and had relied on the Connecticut Yankee Unit for approximately 3.7% of the
Company's 1995 total generating resources. The power purchase contract under
which the Company has purchased its 9.5% entitlement to the Connecticut Yankee
Unit's power output permits Connecticut Yankee to recover 9.5% of all of its
costs from UI. Connecticut Yankee has filed
- 72 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
revised decommissioning cost estimates and amendments to the power contracts
with its owners with the Federal Energy Regulatory Commission (FERC). The
estimate of the sum of future payments for the closing, decommissioning and
recovery of the remaining investment in the Connecticut Yankee Unit is
approximately $606 million at December 31, 1997. Based on regulatory precedent,
Connecticut Yankee believes it will continue to collect from its owners its
decommissioning costs, the unrecovered investment in the Connecticut Yankee Unit
and other costs associated with the permanent shutdown of the Connecticut Yankee
Unit. UI expects that it will continue to be allowed to recover all
FERC-approved costs from its customers through retail rates. The Company's
estimate of its remaining share of costs, including decommissioning, less return
of investment (approximately $10.5 million) and return on investment
(approximately $6.3 million) at December 31, 1997, is approximately $40.8
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 I of this facility, which
became operational in 1986 and in which the Company has a 5.75% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
ten-year Firm Energy Contract, which provides for the sale of 7 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, became effective on July 1, 1991. Additionally, the Company
is obligated to furnish a guarantee for its participating share of the debt
financing for the Phase II facility. As of December 31, 1997, the Company's
guarantee liability for this debt was approximately $7.4 million.
PROPERTY TAXES
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. On March 7, 1997, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1997-1998, which notices purport to increase said
assessed value by approximately 54% over the valuations declared by the Company
and are expected to generate tax claims of approximately $3.7 million. The
Company is vigorously contesting each of these actions by the City's tax
assessor. In January 1996, the Connecticut Superior Court granted the Company's
motion for summary judgment against the City relative to the earliest tax year
at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had
no statutory authority to revalue personal property listed and valued on the
Company's tax list for the tax year 1991-1992. This Superior Court decision,
which would also have been applicable to and defeated the assessor's valuation
increases for
- 73 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the two subsequent tax years, 1992-1993 and 1993-1994, was appealed by the City.
On April 11, 1997, the Connecticut Supreme Court reversed the Superior Court's
decisions in this and two other companion cases involving other taxpayers,
ruling that the tax assessor had a three-year period in which to audit and
revalue personal property listed and valued on the Company's tax list for the
tax year 1991-1992. It is currently anticipated that all of the pending cases
for all of the tax years in dispute will now be scheduled for trial in the
Superior Court relative to the Company's claim that the tax assessor's increases
in personal property tax assessments for the three earliest years were unlawful
for other reasons and relative to the vigorously contested issue, for all of the
tax years, as to the reasonableness of the tax assessor's valuation method, both
as to amount and methodology. It is the present opinion of the Company that the
ultimate outcome of this dispute will not have a significant impact on the
long-term financial position of the Company. The Company would seek permission
from the DPUC to recover from its retail customers the expense of any adverse
court decision or settlement.
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water and air quality (particularly "air toxics"
and "global warming"), hazardous waste handling and disposal, toxic substances,
and electric and magnetic fields, the Company may incur substantial capital
expenditures for equipment modifications and additions, monitoring equipment and
recording devices, and it may incur additional operating expenses. Litigation
expenditures may also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful health effects of
electric and magnetic fields. The total amount of these expenditures is not now
determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of December 31, 1997, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at its
English Station generating site, including repair and/or replacement of
approximately 560 linear feet of sheet piling. The total cost of the remediation
and sheet piling repair is presently estimated at $3.5 million, and the Company
plans to repair/replace a major portion of the remaining sheet piling at this
location at an estimated cost of $6 million.
(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 was required to take
title to and dispose of the utilities' high level wastes and spent nuclear fuel
beginning no later than January 1998. However, the DOE has announced that its
first high level waste repository will
- 74 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
and that the contracts between the DOE and the plant owners and generators of
such waste will provide a potentially adequate remedy for the latter if the DOE
fails to fulfill its contractual obligations by that date. The DOE is contesting
these judicial declarations; and it is unclear at this time whether the United
States Congress will enact legislation to address spent fuel/high level waste
disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
operation or decommissioning of nuclear generating units have increased
significantly in recent years and may continue to rise. The cost increases are a
function of increased packaging and transportation costs, and higher fees and
surcharges imposed 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, Millstone Unit 3
and Seabrook Unit 1 have storage plans that will allow on-site retention of LLW
for at least five years in the event that disposal is interrupted. The
Connecticut Yankee Unit, which has been retired from commercial operation, has a
similar storage program, although disposal of its LLW will take place in
connection with its decommissioning.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
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 $473 million (in 1998 dollars) as the
decommissioning cost estimate for Seabrook
- 75 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Unit 1, of which the Company's share would be approximately $83 million. This
estimate assumes the prompt removal and dismantling of the unit at the end of
its estimated 36-year energy producing life. Monthly decommissioning payments
are being made to the state-managed decommissioning trust fund. UI's share of
the decommissioning payments made during 1997 was $1.9 million. UI's share of
the fund at December 31, 1997 was approximately $12.4 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $557 million (in 1998 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during 1997 was $487,000. UI's share of the fund at December 31, 1997 was
approximately $5.1 million. The decommissioning trust fund for the Connecticut
Yankee Unit is also managed by NU. For the Company's 9.5% equity ownership in
Connecticut Yankee, decommissioning costs of $2.1 million were funded by UI
during 1997, and UI's share of the fund at December 31, 1997 was $24.9 million.
The current decommissioning cost estimate for the Connecticut Yankee Unit,
assuming the prompt removal and dismantling of the unit commencing in 1997, is
$456 million, of which UI's share would be $43 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.
- 76 -
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:
1997 1996
---- ----
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(000's) (000's)
Cash and temporary cash investments $32,002 $32,002 $ 6,394 $ 6,394
Long-term debt (2)(3)(4) $620,457 $624,192 $652,767 $655,582
(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, 1997 and 1996,
respectively.
(4) See Note (B), Capitalization - Long-Term Debt.
- 77 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(P) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1997 and 1996 are set forth below:
[Download Table]
OPERATING OPERATING NET EARNINGS PER SHARE OF
QUARTER REVENUES INCOME INCOME COMMON STOCK(1)
------- --------- --------- ------ ---------------------
(000's) (000's) (000's) Basic Diluted
----- -------
1997
First $180,325 $22,150 $7,710 $ .54 $.54
Second(2)(3) 163,774 22,692 8,542 .61 .61
Third 196,563 38,351 23,402 1.68 1.68
Fourth 169,605 21,380 6,137 .44 .44
1996
First(4) $170,860 $29,042 $11,721 $ .82 $ .82
Second(4)(5) 168,790 25,871 8,883 .75 .75
Third(4) 209,167 34,466 17,904 1.27 1.26
Fourth(6) 177,203 19,756 588 .04 .04
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Operating income, net income and earnings per share for the second quarter
of 1997 included an after-tax credit of $6.7 million, or $.48 per share, to
provide for the cumulative tax benefits associated with future fossil
generation decommissioning.
(3) Operating income, net income and earnings per share for the second quarter
of 1997 included an after-tax charge of $4.1 million, or $.30 per share, to
record additional amortization of conservation and load management costs.
(4) 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.
(5) 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.
(6) 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.
- 78 -
REPORT OF INDEPENDENT ACCOUNTANTS
January 26, 1998
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, of cash flows and of retained earnings
present fairly, in all material respects, the consolidated financial position of
The United Illuminating Company and its subsidiaries at December 31, 1997 and
1996, and the consolidated results of their operations and their cash flows for
each of the two years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with 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
audits provide a reasonable basis for the opinion expressed above.
/s/ Price Waterhouse LLP
- 79 -
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
January 26, 1998
To the Board of Directors
of The United Illuminating Company
Our audits of the consolidated financial statements referred to in our report
dated January 26, 1998 appearing on page 79 of the 1997 Annual Report on Form
10-K also included an audit of the Financial Statement Schedule on page S-1 of
this Form 10-K. In our opinion, this Financial Statement Schedule presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements.
/s/ Price Waterhouse LLP
- 80 -
[Letterhead of Coopers & Lybrand]
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Shareowners and Directors of
The United Illuminating Company:
We have audited the consolidated balance sheet of The United Illuminating
Company as of December 31, 1995, and the related consolidated statements of
income, retained earnings and cash flows for the year then ended and the
consolidated financial statement schedule for the year ended December 31, 1995
(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 audit.
We conducted our audit 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 audit provides 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 the consolidated results of
its operations and its cash flows for the year 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
- 81 -
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 "SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE" in the
Company's definitive Proxy Statement, dated March 27, 1998 for the Annual
Meeting of the Shareholders to be held on May 20, 1998, which Proxy Statement
will be filed with the Securities and Exchange Commission on or about March 27,
1998, 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 1997 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, 1998, for the Annual
Meeting of the Shareholders to be held on May 20, 1998, which Proxy Statement
will be filed with the Securities and Exchange Commission on or about March 27,
1998, 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, 1998 for the Annual Meeting of the Shareholders to be
held on May 20, 1998, which Proxy Statement will be filed with the Securities
and Exchange Commission on or about March 27, 1998, is incorporated by reference
in answer to this item.
Item 13. Certain Relationships and Related Transactions.
Since January 1, 1997, there has been no transaction, relationship or
indebtedness of the kinds described in Item 404 of Regulation S-K.
- 82 -
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, 1997,
1996 and 1995
Consolidated statement of cash flows for the years ended December 31,
1997, 1996 and 1995
Consolidated balance sheet, December 31, 1997, 1996 and 1995
Consolidated statement of retained earnings for the years ended
December 31, 1997, 1996 and 1995
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, 1997, 1996 and 1995.
- 83 -
Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain
of the following listed exhibits, which are annexed as exhibits to previous
statements and reports filed by the Company, are hereby incorporated by
reference as exhibits to this report. Such statements and reports are identified
by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1996.
(4) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1997.
(5) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(6) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1996.
(7) Filed with Registration Statement No. 33-40169, effective August 12, 1991.
(8) Filed with Registration Statement No. 33-35465, effective August 1, 1990.
(9) Filed with Amendment No. 1 to Registration Statement No. 33-55461,
effective October 31, 1994.
(10) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1995.
(11) Filed with Registration Statement No. 2-57275, effective October 19, 1976.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(13) Filed with Registration Statement No. 2-66518, effective February 25, 1980.
(14) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991.
(15) Filed with Registration Statement No. 2-49669, effective December 11, 1973.
(16) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1993.
(17) Filed with Registration Statement No. 2-54876, effective November 19, 1975.
(18) Filed with Registration Statement No. 2-52657, effective February 6, 1975.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1997.
(20) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1992.
(21) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1997.
(22) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1994.
(23) Filed March 29, 1996, with proxy material for the Annual Meeting of the
Shareowners.
- 84 -
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) 3.1d (4) Copy of Certificate Amending Certificate of Incorporation By Action of
Board of Directors, dated December 11, 1996. (Exhibit 3.1d)
(3) 3.2a (5) Copy of Bylaws of The United Illuminating Company. (Exhibit 2.3)
(3) 3.2b (6) Copy of Article II, Section 2, of Bylaws of The United Illuminating
Company, as amended March 26, 1990, amending Exhibit 3.2a. (Exhibit 3.2b)
(3) 3.2c (6) Copy of Article V, Section 1, of Bylaws of The United Illuminating Company,
as amended April 22, 1991, amending Exhibit 3.2a. (Exhibit 3.2c)
(4) 4.1 (7) Copy of Indenture, dated as of August 1, 1991, from The United Illuminating
Company to The Bank of New York, Trustee. (Exhibit 4)
(4),(10) 4.2 (8) Copy of Participation Agreement, dated as of August 1, 1990, among
Financial Leasing Corporation, Meridian Trust Company, The Bank of New
York and The United Illuminating Company. (Exhibits 4(a) through 4(h),
inclusive, Amendment Nos. 1 and 2).
(4) 4.3a (9) Copy of form of Amended and Restated Agreement of Limited Partnership of
United Capital Funding Partnership L.P. (Exhibit 4(c))
(4) 4.3b (10) Copy of Action of The United Illuminating Company, as General Partner of
United Capital Funding Partnership L.P., relating to the 9 5/8% Preferred
Capital Securities, Series A, of United Capital Funding Partnership L.P.
(Exhibit 4(b))
(4) 4.3c (9) Copy of form of Indenture, dated as of April 1, 1995, from The United
Illuminating Company to The Bank of New York, as Trustee. (Exhibit 4(e))
(4) 4.3d (10) Copy of First Supplemental Indenture, dated as of April 1, 1995, between
The United Illuminating Company and The Bank of New York, Trustee,
supplementing Exhibit 4.3c. (Exhibit 4(d))
(4) 4.3e (9) Copy of form of Payment and Guarantee Agreement of The United Illuminating
Company, dated as of April 1, 1995. (Exhibit 4(j))
(10) 10.1 (11) Copy of Stockholder Agreement, dated as of July 1, 1964, among the various
stockholders of Connecticut Yankee Atomic Power Company, including The
United Illuminating Company. (Exhibit 5.1-1)
(10) 10.2a (11) Copy of Power Contract, dated as of July 1, 1964, between Connecticut
Yankee Atomic Power Company and The United Illuminating Company.
(Exhibit 5.1-2)
(10) 10.2b (12) Copy of Additional Power Contract, dated as of April 30, 1984, between
Connecticut Yankee Atomic Power Company and The United Illuminating
Company.
(10) 10.2c (6) Copy of 1987 Supplementary Power Contract, dated as of April 1, 1987,
supplementing Exhibits 10.2a and 10.2b. (Exhibit 10.2c)
(10) 10.2d (6) Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending
Exhibits 10.2b and 10.2c. (Exhibit 10.2d)
- 85 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.2e (6) Copy of First Supplement to 1996 Amendatory Agreement, dated as of
February 10, 1997, supplementing Exhibit 10.2d. (Exhibit 10.2e)
(10) 10.3 (11) Copy of Capital Funds Agreement, dated as of September 1, 1964, between
Connecticut Yankee Atomic Power Company and The United Illuminating
Company. (Exhibit 5.1-3)
(10) 10.4a (11) 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 (13) 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 (5) 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 (14) Copy of NEPOOL Power Pool Agreement, dated as of September 1, 1971, as
amended to November 1, 1988. (Exhibit 10.6a)
(10) 10.6b (15) Copy of Agreement Setting Out Supplemental NEPOOL Understandings, dated as
of April 2, 1973. (Exhibit 5.7-10)
(10) 10.6c (14) Copy of Amendment to NEPOOL Power Pool Agreement, dated as of March 15,
1989, amending Exhibit 10.6a. (Exhibit 10.6c)
(10) 10.6d (14) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of October
1, 1990, amending Exhibit 10.6a. (Exhibit 10.6d)
(10) 10.6e (16) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of
September 15, 1992, amending Exhibit 10.6a. (Exhibit 10.6e)
(10) 10.6f (16) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of June 1,
1993, amending Exhibit 10.6a. (Exhibit 10.6f)
(10) 10.7a (14) 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 (17) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the
Seabrook Companies. (Exhibit 5.9-2)
(10) 10.7c (6) Copy of Twenty-third Amendment to Agreement for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units, dated as of
November 1, 1990, amending Exhibit 10.7a. (Exhibit 10.7c)
(10) 10.8a (13) 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 (18) 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 (11) 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 (5) 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)
- 86 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.9b (14) 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 (14) 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) 10.9d (19) Copy of Notice, dated April 22, 1997, of The United Illuminating Company's
intention to extend term of Transmission Line Agreement, Exhibit 10.9a, as
supplemented and modified by Exhibit 10.9c. (Exhibit 10.9d)
(10) 10.10 Copy of Agreement, effective May 16, 1997, between The United Illuminating
Company and Local 470-1, Utility Workers Union of America, AFL-CIO.
(10) 10.11 (20) 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) 10.12 (6) Copy of Fossil Fuel Supply Agreement between BLC Corporation and The United
Illuminating Company, dated as of July 1, 1991. (Exhibit 10.13)
(10) 10.13* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1,
1997, between The United Illuminating Company and Richard J. Grossi.
(Exhibit 10.22)
(10) 10.14* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1,
1997, between The United Illuminating Company and Robert L. Fiscus.
(Exhibit 10.23)
(10) 10.15* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1,
1997, between The United Illuminating Company and James F. Crowe.
(Exhibit 10.24)
(10) 10.16* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Albert N. Henricksen. (Exhibit 10.25)
(10) 10.17* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Anthony J. Vallillo. (Exhibit 10.26)
(10) 10.18* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Rita L. Bowlby. (Exhibit 10.27)
(10) 10.19* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Stephen F. Goldschmidt. (Exhibit 10.28)
` (10) 10.20* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and James L. Benjamin. (Exhibit 10.29)
(10) 10.21* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Kurt D. Mohlman. (Exhibit 10.30)
(10) 10.22* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Charles J. Pepe. (Exhibit 10.31)
(10) 10.23* (14) Copy of Executive Incentive Compensation Program of The United Illuminating
Company. (Exhibit 10.24)
(10) 10.24* (12) Copy of The United Illuminating Company 1990 Stock Option Plan, as amended
on December 20, 1993, January 24, 1994 and August 22, 1994.
(10) 10.25* (22) Copy of The United Illuminating Company Dividend Equivalent Program.
(Exhibit 10.20)
(10) 10.26* (23) Copy of Directors' Deferred Compensation Plan of The United Illuminating
Company.
(10) 10.27* (3) Copy of The United Illuminating Company 1996 Long Term Incentive Program.
(Exhibit 10.21*)
- 87 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(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, 1997, 1996, 1995, 1994 and
1993).
(21) 21 List of subsidiaries of The United Illuminating Company.
(27) 27 Financial Data Schedule
(28) 28.1 (20) Copies of significant rate schedules of The United Illuminating Company.
(Exhibit 28.1)
------------------------
*Management contract or compensatory plan or arrangement.
- 88 -
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
- 89 -
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 33-50221, No.
33-50445, No. 33-55461 and No. 33-64003) of our reports dated January 26, 1998
appearing on page 79 and page 80 of The United Illuminating Company's Annual
Report on Form 10-K for the year ended December 31, 1997.
/s/ Price Waterhouse LLP
New York, New York
March 3, 1998
- 90 -
[Letterhead of Coopers & Lybrand]
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 audit of the consolidated financial statements and financial
statement schedule of The United Illuminating Company as of December 31, 1995
and for the year then ended, which report is included in this Annual Report on
Form 10-K.
/s/ Coopers & Lybrand L.L.P.
Hartford, Connecticut
March 2, 1998
- 91 -
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 3, 1998
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 3, 1998
------------------------------
(Richard J. Grossi)
(Principal Executive Officer)
Director, Vice Chairman and
/s/ Robert L. Fiscus Chief Financial Officer March 3, 1998
------------------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
/s/ John F. Croweak Director March 3, 1998
------------------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director March 3, 1998
------------------------------
(F. Patrick McFadden, Jr.)
/s/ J. Hugh Devlin Director March 3, 1998
------------------------------
(J. Hugh Devlin)
/s/ Betsy Henley-Cohn Director March 3, 1998
------------------------------
(Betsy Henley-Cohn)
/s/Frank R. O'Keefe, Jr. Director March 3, 1998
------------------------------
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director March 3, 1998
------------------------------
(James A. Thomas)
/s/ David E.A. Carson Director March 3, 1998
------------------------------
(David E.A. Carson)
/s/ John L. Lahey Director March 3, 1998
------------------------------
(John L. Lahey)
/s/ Marc C. Breslawsky Director March 3, 1998
------------------------------
(Marc C. Breslawsky)
/s/ Thelma R. Albright Director March 3, 1998
------------------------------
(Thelma R. Albright)
- 92 -
[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, 1997, 1996 AND 1995
(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:
1997 $2,300 $6,407 - $6,907 (A) $1,800
1996 $6,300 $9,854 - $13,854 (A) $2,300
1995 $4,900 $9,383 - $7,983 (A) $6,300
------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
S-1
Dates Referenced Herein and Documents Incorporated by Reference
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