Document/Exhibit Description Pages Size
1: 10-K Annual Report Form 10-K 101 583K
2: EX-3.2B Article Iii, SEC. 2, of Bylaws, Amended 12/14/98 1 4K
3: EX-10.9B Memrndm of Agrmt Dtd 1/27/99 Betw Ui & Union 4 17K
4: EX-12 Statement Re: Computation of Ratios 2 12K
5: EX-27 FDS -- 12 Mos. of 1998 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, 1998
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
---------------------------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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NAME OF EACH EXCHANGE ON
REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED
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The United Illuminating Company Common Stock, no par value New York Stock Exchange
United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange
Securities, Series A (Liquidation
Preference $25 per Security)
(1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3,
1995 by United Capital Funding Partnership L.P., a special purpose limited
partnership in which The United Illuminating Company owns all of the
general partner interests, and are guaranteed by The United Illuminating
Company.
SECURITIES REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE,
OF THE UNITED ILLUMINATING COMPANY
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 1999 was $699,286,165, computed on the basis of
the average of the high and low sale prices of said stock reported in the
listing of composite transactions for New York Stock Exchange listed securities,
published in The Wall Street Journal on February 1, 1999.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 1999, was 14,334,922.
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 30, 1999,
FOR ANNUAL MEETING OF THE SHAREHOLDERS TO BE HELD ON MAY 19, 1999. III
THE UNITED ILLUMINATING COMPANY
FORM 10-K
DECEMBER 31, 1998
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 9
- Financing 11
- Fuel Supply 13
- Fossil Fuel 13
- Nuclear Fuel 13
- Arrangements with Other Utilities 14
- New England Power Pool 14
- New England Transmission Grid 14
- Hydro-Quebec 14
- Environmental Regulation 15
- Employees 18
Item 2. Properties. 20
- Generating Facilities 20
- Tabulation of Peak Loads, Resources, and Margins 21
- Transmission and Distribution Plant 23
- Capital Expenditure Program 24
- Nuclear Generation 25
- General Considerations 26
- Insurance Requirements 27
- Waste Disposal and Decommissioning 27
Item 3. Legal Proceedings. 29
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TABLE OF CONTENTS (CONTINUED)
PAGE
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Item 4. Submission of Matters to a Vote of Security Holders. 30
Executive Officers of the Company 31
PART II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters. 32
Item 6. Selected Financial Data. 33
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 37
- Major Influences on Financial Condition 37
- Liquidity and Capital Resources 40
- Subsidiary Operations 42
- Year 2000 Issue 43
- Results of Operations 44
- Looking Forward 49
Item 8. Financial Statements and Supplementary Data. 52
- Consolidated Financial Statements for the Years 1998,
1997 and 1996 52
- Statement of Income 52
- Statement of Cash Flows 53
- Balance Sheet 54
- Statement of Retained Earnings 56
- Notes to Consolidated Financial Statements 57
- Statement of Accounting Policies 57
- Capitalization 63
- Rate-Related Regulatory Proceedings 67
- Accounting for Phase-in Plan 70
- Short-Term Credit Arrangements 70
- Income Taxes 72
- Supplementary Information 74
- Pension and Other Benefits 75
- Jointly Owned Plant 79
- Unamortized Cancelled Nuclear Project 79
- Fuel Financing Obligations and Other Lease Obligations 79
- Commitments and Contingencies 80
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TABLE OF CONTENTS (CONTINUED)
PAGE
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PART II (CONTINUED)
- Capital Expenditure Program 80
- Nuclear Insurance Contingencies 80
- Other Commitments and Contingencies 81
- Connecticut Yankee 81
- Hydro-Quebec 82
- Property Taxes 82
- Environmental Concerns 82
- Site Decontamination, Demolition and Remediation Costs 83
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 83
- Fair Value of Financial Instruments 86
- Quarterly Financial Data (Unaudited) 87
Report of Independent Accountants 88
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosures. 90
PART III
Item 10. Directors and Executive Officers of the Company 90
Item 11. Executive Compensation. 90
Item 12. Security Ownership of Certain Beneficial Owners and
Management. 90
Item 13. Certain Relationships and Related Transactions. 90
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K. 91
Consent of Independent Accountants 98
Signatures 99
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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.
"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.
"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.
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GLOSSARY (CONTINUED)
"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 1998 retail electric
revenues, approximately 42% was derived from residential sales, 40% from
commercial sales, 16% from industrial sales and 2% from other sales. For a
description of the changes in the Company's electric public utility company
business that will result from the 1998 Connecticut legislation designed to
restructure the State's electric utility industry, see "Franchises, Regulation
and Competition - Competition".
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement UI's regulated electric utility business and provide long-term
rewards to UI's shareowners.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional buildings, and is participating
in the development of district heating and cooling facilities in the downtown
New Haven area, including the energy center for an office tower and
participation as a 52% partner in the energy center for a city hall and office
tower complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial buildings,
government buildings and industrial facilities. URI's fourth subsidiary, United
Bridgeport Energy, Inc., is 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 $32.25 million, in the aggregate, of the Company's assets into its
unregulated subsidiary ventures, and, at February 28, 1999, $30 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" and
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"Competition". The DPUC consists of five Commissioners, appointed by the
Governor of Connecticut with the advice and consent of both houses of the
Connecticut legislature.
The location and construction of certain electric facilities is also
subject to regulation by the Connecticut Siting Council (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 April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from among competing
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the charge for electricity
generation services from the charge for delivering the electricity and all other
charges. On July 29, 1998, the DPUC issued the first of what are expected to be
several orders relative to this "unbundling" requirement, and has now reopened
its proceeding to consider the amount of the generation services charge to be
included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to
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certain adjustments, at least 10% below its fully bundled prices for electricity
at rates in effect on December 31, 1996, as discussed below. The standard offer
is required, subject to certain adjustments, to be the total rate charged under
the standard offer, including generation and transmission and distribution
services, the competitive transition assessment, the systems benefits charge,
the energy conservation and load management program charge and the renewable
energy investment charge.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of other
above-market generation costs eligible for the competitive transition
assessment, such as regulated plant costs and tax-related regulatory assets or
other costs related to the restructuring transition, such that there will be no
net income effect of the sale. Net cash proceeds from the sale are expected to
be in the range of $160-$165 million. The Company anticipates using these
proceeds to reduce debt.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a
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holding company, and each share of the common stock of the Company will be
converted into a share of common stock of the holding company. In connection
with the formation of the holding company structure, all of the Company's
interests in all of its operating unregulated subsidiaries will be transferred
to the holding company and, to the extent new businesses are subsequently
acquired or commenced, they will also be financed and owned by the holding
company. An application for the DPUC's approval of this corporate restructuring
was filed on November 13, 1998. DPUC hearings on the corporate unbundling plan
and corporate restructuring commenced on February 18, 1999.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. In order
to mitigate the financial risk that these regulated service mandates will pose
to the Company in an unregulated power generation environment, its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates, effective July 1, 2000, as permitted by the Restructuring Act. This
clause, similar to and based on the purchased gas adjustment clauses used by
Connecticut's natural gas local distribution companies, would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay competitive market rates for power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
The Restructuring Act provides for the Distribution Company to recover its
reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
other state and federal agencies, and the Company's common stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order (see below) anticipated
sufficient income in 2000 to accelerate amortization of regulatory assets of
about $50 million, equivalent to about 8% of retail revenues. Substantially all
of this accelerated amortization may have to be eliminated to allow for the
additional standard offer price reduction requirement of 10%, at a minimum,
while providing for the added costs imposed by the restructuring legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.
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 a reasonable opportunity to cover their reasonable
operating and capital costs, to attract needed capital and maintain their
financial integrity, while also protecting relevant public interests.
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On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers; but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. As a
result of the Rate Plan, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Also as a result of the Rate Plan,
customer prices are required to be reduced by an additional 1% in 2000, and
another 1% in 2001, compared to 1996. Retail revenues have decreased by
approximately 4.8% through 1998 compared to 1996 due to customer price
reductions. The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act, the Rate Plan may be
reopened and modified. See "Franchises, Regulation and Competition-Competition".
However, aside from implementing an additional price reduction in 2000 to
achieve the minimum 10% price reduction required by the Restructuring Act and
the probable reductions in the accelerated amortizations scheduled in the Rate
Plan, the Company is unable to predict, at this time, in what other respects the
Rate Plan may be modified on account of this legislation.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income statement impact of certain costs that are expected to be
recovered in future regulated service rates and to establish regulatory assets
on its balance sheet for such costs. The effects of competition or a change in
the cost-based regulatory structure could cause the operations of the Company,
or a portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. If the Company, or a portion of its assets or
operations, were to cease meeting these criteria, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met, if such deferred costs are not
recoverable in that portion of the business that continues to meet the criteria
for the application of SFAS No. 71. If this change in accounting were to occur,
it 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.
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FINANCING
The Company's capital requirements are presently projected as follows:
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1999 2000 2001 2002 2003
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(millions)
Cash on Hand - Beginning of Year $101.4 $34.5 $9.0 $42.7 $ -
Internally Generated Funds less Dividends 98.4 59.4 57.4 64.4 72.7
Net Proceeds from Sale of Fossil Generation Plants 160.0 - - - -
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Subtotal 359.8 93.9 66.4 107.1 72.7
Less:
Capital Expenditures (excluding AFUDC) 30.7 34.5 23.4 18.9 23.3
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Cash Available to pay Debt Maturities and Redemptions 329.1 59.4 43.0 88.2 49.4
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 145.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
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External Financing Requirements (Surplus) $(34.5) $(9.0) $(42.7) $12.1 $51.1
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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, including the implementation of the legislative
mandate to achieve a minimum 10% price reduction from December 31, 1996
price levels by the year 2000. Connecticut's Restructuring Act, described
at "Franchises, Regulation and Competition - Competition," requires the
Company to divest itself of its fossil-fueled generating plants prior to
January 1, 2000 and to attempt to divest itself of its ownership interests
in nuclear-fueled generating units prior to January 1, 2004. This forecast
reflects the estimated net after-tax proceeds ($160-$165 million) from a
proposed divestiture of fossil-fueled generation plants on or about April
1, 1999. All of these estimates are subject to change due to future events
and conditions that may be substantially different from those used in
developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement and an $80 million revolving credit
agreement, 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 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 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.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
On June 8, 1998, the Company repaid a $50 million Term Loan prior to its
August 29, 2000 due date. On June 8, 1998, the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.
- 11 -
On December 18, 1998, the Company issued and sold $100 million principal
amount of 6% five-year Notes. The yield on the Notes, which were issued at a
discount, is 6.034%; and the Notes will mature on December 15, 2003. The
proceeds from the sale of the Notes were used to repay $66.2 million principal
amount of 6.2% Notes, which matured on January 15, 1999, and for general
corporate purposes.
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and will be paid semi-annually beginning on
August 1, 1999. In addition, on February 1, 1999, the Company converted $98.5
million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds will
be paid semi-annually beginning on August 1, 1999.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 1999. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
December 31, 1998, the Company had no short-term borrowings outstanding under
this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of December 31, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
In addition, as of December 31, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $6.8 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,
1998, this coverage ratio was 3.6:1.0.
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
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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, 1998 are set forth below.
PREFERRED STOCK SEABROOK LEASE
PROVISIONS PROVISIONS
------------------------ -----------------
PREFERRED LONG-TERM EARNINGS/INTEREST
YEAR STOCK INDEBTEDNESS RATIO
---- --------- ------------ -----------------
1994 2.7 3.1 2.9
1995 2.7 2.7 3.3
1996 2.4 2.4 2.8
1997 2.5 2.6 3.2
1998 2.5 2.5 3.6
The Company is obligated to furnish a guarantee for its participating share
of the debt financing for the Hydro-Quebec Phase II transmission intertie
facility linking New England and Quebec, Canada. As of December 31, 1998, the
Company's guarantee liability for this debt was approximately $6.8 million. See
"Arrangements with Other Utilities - Hydro Quebec".
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 1998, approximately
590,000 tons of coal and 4.6 million barrels of fuel oil 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 an approximate 35-day coal supply of 112,000 tons at its
Bridgeport Harbor Station.
The Company's largest generating unit at its Bridgeport generating station
is capable of burning either coal or oil. A coal supply contract for this unit
extends until July 31, 2007, subject to earlier termination provisions. Fuel oil
supply contracts for the New Haven and Bridgeport generating stations will
expire on March 31, 2000.
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 station 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 1998, no natural gas was purchased pursuant to this agreement.
On October 2, 1998, the Company agreed to sell both of its operating
fossil-fueled generating stations, Bridgeport Harbor Station and New Haven
Harbor Station, to Wisvest-Connecticut, LLC, a single-purpose subsidiary of
Wisvest Corporation. Wisvest Corporation is a non-utility subsidiary of
Wisconsin Energy Corporation, Milwaukee, Wisconsin. The transaction is expected
to close during the spring of 1999. Fuel supply contracts will be assigned to
Wisvest-Connecticut, LLC on the closing date of the transaction.
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.
- 13 -
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 2002. In addition, there are outstanding
contracts, to the extent indicated below, for conversion, enrichment and
fabrication services for these units extending through the following years:
CONVERSION TO
HEXAFLUORIDE ENRICHMENT FABRICATION
------------- ---------- -----------
Millstone Unit 3 2003 2002 2011
Seabrook Unit 1 2006 2002 2008
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 load aggregators. An independent entity, ISO New
England, Inc., has the responsibility for the operation of the regional bulk
power system, so that the regional bulk power system will continue to be
operated both in accordance with the NEPOOL objectives and free of any adverse
impact on competition in the wholesale power markets, where various energy and
capacity products will be traded in open competition among all participants.
Amendments to the NEPOOL Agreement establishing the markets were filed with and
have been approved by the FERC and the markets are expected to become
operational on April 1, 1999.
NEW ENGLAND TRANSMISSION GRID
Under other agreements related to the Company's participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to
the financial support of certain 345 kilovolt transmission facilities that are a
part of the New England transmission grid.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45%
- 14 -
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, 1998, the Company's guarantee liability
for this debt was approximately $6.8 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 and English generating stations expired in February and May of
1992, respectively. Applications for renewal of these permits had been filed in
August and November of 1991, respectively, and while these renewal applications
are pending, the terms of the expired permits continue in effect. On January 23,
1999, the DEP issued a public notice that it has made a tentative determination
to renew the permit for Bridgeport Harbor Station. The application for English
Station, in New Haven, which has been deactivated, 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 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. A
discharge permit for the Company's New Haven Harbor Station was issued on
January 4, 1999 and will expire on January 4, 2004. The DEP has determined that
the thermal component of the discharges at each of the Company's three stations
will not result in a violation of state water quality standards. However, 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 such expenditures will continue
to be required for Bridgeport Harbor Station and New Haven Harbor Station until
these facilities are sold. See "Franchises, Regulation and Competition -
Competition".
Under the federal Clean Air Act, the federal Environmental Protection
Agency (EPA) has promulgated national primary and secondary air quality
standards for certain air pollutants, including sulfur oxides, particulate
matter, ozone and nitrogen oxides. The DEP has adopted regulations for the
attainment, maintenance and enforcement of these standards. In order to comply
with these regulations, the Company is required to burn fuel oil with a sulfur
content not in excess of 1%, and Bridgeport Harbor Unit 3 is required to burn a
low-sulfur, low-ash content coal, the sulfur dioxide (SO2) emissions from which
are not to exceed 1.1 pounds of SO2 per million BTU of heat input. Current air
pollution regulations also include other air quality standards, emission
performance standards and monitoring, testing and reporting requirements that
are applicable to the Company's generating stations and further restrict the
construction of new sources of air pollution or the modification of existing
sources by requiring that both construction and operating permits be obtained
and that a new or modified source will not cause or contribute to any violation
of the EPA's national air quality standards or its regulations for the
prevention of significant deterioration of air quality.
Amendments to the Clean Air Act in 1990 will require a significant
reduction in nationwide SO2 emissions by fossil fuel-fired generating units to a
permanent total emissions cap in the year 2000. This reduction is to be achieved
by the allotment of allowances to emit SO2, measured in tons per year, to each
owner of a unit, and requiring the owner 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, the
- 15 -
Bridgeport Harbor Station, New Haven Harbor Station and English Station
generating units will hold more than sufficient allowances to permit their
continued operation without incurring substantial expenditures for additional
SO2 controls.
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 submitted applications for such
operating permits in early 1998. These applications have verified compliance
with all existing requirements applicable to the generating units at Bridgeport
Harbor, New Haven Harbor and English generating stations, with the exception
that the generating units at Bridgeport Harbor and New Haven Harbor generating
stations are not in continuous compliance with regulations governing the maximum
opacity of stack emissions. The Company is discussing this continuous compliance
issue with Connecticut DEP staff and expects that the issue will be resolved
without any material expenditures for additional control equipment at these
units. 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 the 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 1998, UI consummated 7 sales of NOx
emission reduction credits, and it will continue to market these credits until
this generating unit is sold. See "Financing, Regulation and Competition -
Competition". 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. On July 18, 1997, the EPA published final revisions to
the national air quality standards for ozone and particulate matter. On
September 24, 1998, the EPA published a final rule that will require 22 states
in the eastern United States and the District of Columbia to adopt regulations
no later than September 30, 1999 to ensure that a significant transport of ozone
pollution across state boundaries in the eastern United States is prevented.
Since not all of these new state 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 the generating facilities at Bridgeport
Harbor, New Haven Harbor and English generating stations. Compliance may require
substantial additional capital and operational expenditures by the owner of
these facilities 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.
A merchant wholesale electric generating facility (Bridgeport Energy
Project) is being constructed on land leased from UI at its Bridgeport Harbor
Station. UI's Bridgeport Harbor Unit 1 was placed in deactivated reserve status
on August 1, 1998, when the first phase of the Bridgeport Energy Project was
completed. 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 Bridgeport Harbor, New Haven Harbor and English generating stations
comply with the air quality and emission performance standards adopted by their
host cities.
- 16 -
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 generating station. 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. The Bridgeport Harbor and New Haven
Harbor generating 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, 1998, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities.
Remediation costs, including the repair and/or replacement of approximately 560
linear feet of sheet piling, are currently estimated at $7.5 million. In
addition, the Company is planning to repair and/or replace the remaining
deteriorated sheet piling bordering the English Station property, at an
additional estimated cost of $10 million.
The Company has contracted to sell its Bridgeport Harbor Station and New
Haven Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. See "Franchises, Regulation and
Competition - Competition". Environmental assessments performed in connection
with the marketing of these plants indicate that substantial remediation
expenditures will be required in order to bring the plant sites into compliance
with applicable Connecticut minimum standards following their sale. The proposed
purchaser of the plants has agreed to undertake and pay for the major portion of
this remediation. However, the Company will be responsible for remediation of
the portions of the plant sites that will be retained by it.
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
- 17 -
respects, are more stringent than the federal requirements. The Company
currently owns 13 underground storage tanks, which are used primarily for
gasoline and fuel oil, that are subject to these regulations. A testing program
has been installed to detect leakage from any of these tanks, and substantial
costs may be incurred for future actions taken to prevent tanks from leaking, to
remedy any contamination of groundwater, and to modify, remove and/or replace
older tanks in compliance with federal and state regulations.
In the past, the Company has disposed of residues from operations at
landfills, as most other industries have done. In recent years it has been
determined that such disposal practices, under certain circumstances, can cause
groundwater contamination. Although the Company has no knowledge of the
existence of any such contamination, if the Company or regulatory agencies
determine that remedial actions must be taken in relation to past disposal
practices, the Company may experience substantial costs.
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. These
laws will be applicable to the Company's proposed sale of its Bridgeport Harbor
Station and New Haven Harbor Station generating stations. See "Franchises,
Regulation and Competition - Competition". 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, 1998, the Company had 1,193 employees, including 181 in
subsidiary operations. Of the electric utility employees, approximately 84% had
been with the Company for 10 or more years.
Approximately 523 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.
- 18 -
The Company has contracted to sell its Bridgeport Harbor Station and New
Haven Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. See "Franchises, Regulation and
Competition - Competition". As part of the sale of these assets, the buyer has
offered employment to all bargaining unit and administrative/technical employees
at the facilities, contingent on the closing of the transaction. The buyer has
also interviewed all management employees at the facilities and those management
and administrative/technical support employees in power supply, supply chain and
environmental management whose jobs will be eliminated as a result of the sale
and offered employment to most employees contingent on the closing of the
transaction. In total, out of 218 employees, 192 have accepted employment offers
from the buyer.
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.
- 19 -
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1998,
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)(7)
Bridgeport Harbor Station 2 #6 Oil 1961 170.00 100.00 170.00(2)(7)
Bridgeport Harbor Station 3 #6 Oil/Coal 1968/1985 385.00 100.00 385.00(7)
Bridgeport Harbor Station 4 Jet Oil 1967 14.60 100.00 14.60(7)
New Haven Harbor Station #6 Oil/Gas 1975 466.00 93.71 436.69(3)(7)
English Station 7 #6 Oil 1948 34.06 100.00 34.06(4)
English Station 8 #6 Oil 1953 38.49 100.00 38.49(4)
OPERATED BY OTHER UTILITIES:
---------------------------
Millstone Unit 3, Nuclear 1986 1119.60 3.685 41.26(5)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1162.00 17.50 203.35(6)
Seabrook, New Hampshire
POWER PURCHASES FROM
COGENERATION FACILITIES:
-----------------------
Bridgeport RESCO, Refuse 1988 59.50 100.00 59.50
Bridgeport, Connecticut
Shelton Landfill Gas 1995 1.50 100.00 1.50
-----
Shelton, Connecticut
Total 1460.54
=======
(1) Bridgeport Harbor Station 1 was placed in deactivated reserve status on
August 1, 1998, when the first phase of a merchant wholesale electric
generating facility (Bridgeport Energy Project), constructed on land leased
from UI at Bridgeport Harbor Station, was completed.
(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, under a series of one-year option agreements that end in
2010, pursuant to a wholesale power contract.
(3) Represents UI's 93.705% ownership share of total net capability. This unit
is jointly owned by UI (93.705%), Fitchburg Gas and Electric Light Company
(4.5%) and the electric departments of three Massachusetts municipalities
(1.795%).
(4) English Station 7 and 8 were placed in deactivated reserve status,
effective January 1, 1992.
(5) Represents UI's 3.685% ownership share of total net capability.
(6) Represents UI's 17.5% ownership share of total net capability. In August
1990, UI sold to and leased back from an owner trust established for the
benefit of an institutional investor a portion of UI's 17.5% ownership
interest in this unit. This portion of the unit is subject to the lien of a
first mortgage granted by the owner trustee.
(7) The Company has contracted to sell its Bridgeport Harbor Station and New
Haven Harbor Station generating plants in compliance with Connecticut's
electric utility industry restructuring legislation. See Item 1. Business -
"Franchises, Regulation and Competition - Competition".
- 20 -
[Enlarge/Download Table]
TABULATION OF PEAK LOADS, RESOURCES, AND MARGINS
1998 ACTUAL, 1999 - 2003 FORECAST
(MEGAWATTS)
Actual Forecast
------ -------------------------------------------------
1998 1999 2000 2001 2002 2003
At Time of Peak Load on UI's System:
-----------------------------------
Capacity of generating units operated
by UI (1) 1082.38 1006.29 1006.29 1006.29 1006.29 1006.29
-------------------------------------
Entitlements in nuclear units (1) (2)
-----------------------------
Millstone Unit 3 0.00 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
-------- -------- -------- -------- ------ ------
203.35 244.61 244.61 244.61 244.61 244.61
-------- -------- -------- -------- ------ ------
Equivalent capacity value of
entitlement in Hydro-Quebec (1) (2) 98.08 98.08 98.08 98.08 0 0
----------------------------
Purchases from cogeneration facilities
--------------------------------------
Bridgeport RESCO 59.50 59.50 59.50 59.50 59.50 59.50
Shelton Landfill 1.50 1.57 1.54 1.36 1.32 1.30
Purchase from New York Power Authority 1.14 1.14 1.14 0.00 0.00 0.00
--------------------------------------
Purchases from (sales to) other utilities
-----------------------------------------
Net power contracts - fossil (122.57) 78.65 (30.64) (30.64) (30.64) (30.64)
------- ------- ------- ------- ------- -------
Total generating resources 1323.38 1489.84 1380.52 1379.20 1281.08 1281.06
======= ======= ======= ======= ======= =======
Calculation of UI's capability
responsibility (3)
------------------------------
Peak load 1142.67 1201.00 1231.00 1243.00 1254.00 1264.00
Required reserve margin 139.19 131.94 135.24 136.56 137.77 138.87
------- ------- ------- ------- ------- -------
Total capability responsibility 1281.86 1332.94 1366.24 1379.56 1391.77 1402.87
======= ======= ======= ======= ======= =======
Available Margin (4) 38.88 154.19 11.60 (1.72) (112.01) (123.11)
====== ======= ======= ======= ======= =======
(1) Capacity shown reflects summer ratings of generating units. In conjunction
with the proposed sale of its two operating fossil-fueled generating
stations, the Company will enter into wholesale power supply contracts for
the sale of power to the Company to replace the power currently being
generated by the Company at the two generating stations.
(2) Winter ratings of UI nuclear and Hydro-Quebec interconnection's equivalent
capacity value entitlements (megawatts):
Millstone Unit 3 - 42.01
Seabrook Unit 1 - 203.35
Hydro-Quebec - 34.34
(3) UI's required capacity as a NEPOOL participant.
(4) Total generating resources, excluding purchases from New York Power
Authority and Shelton Landfill, less capability responsibility. In
addition, UI maintains three units (English Station 7, English Station 8
and Bridgeport Harbor Station 1) in deactivated reserve, representing a
total of 148.64 MW of generating capacity.
- 21 -
During 1998, the peak load on the Company's system was approximately 1,143
megawatts, which occurred in July. UI's total generating capability at the time
was 1,323 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 0.85% during the period 1998 to 2008.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from among competing
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the charge for electricity
generation services from the charge for delivering the electricity and all other
charges. On July 29, 1998, the DPUC issued the first of what are expected to be
several orders relative to this "unbundling" requirement, and has now reopened
its proceeding to consider the amount of the generation services charge to be
included on consumers' bills.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. On and after
January 1, 2000 and until January 1, 2004, the Company will be required to offer
fully-bundled service to customers under a regulated "standard offer" rate and
will also become the power supply provider to each customer who does not choose
an alternate power supply provider, even though the Company will no longer be in
the business of retail power generation. The Company is also required under the
Restructuring Act to provide back-up power supply service to customers whose
electric supplier fails to provide power supply services for reasons other than
the customers' failure to pay for such services.
In conjunction with the proposed sale of its two operating fossil-fueled
generating stations to Wisvest-Connecticut, LLC (Wisvest), the Company will
enter into a wholesale power supply contract with Wisvest for the sale of power
to the Company, through June 30, 2000, to replace the power currently being
generated by the Company at the two
- 22 -
generating stations. If, due to the permanent loss of a generating unit or
higher than expected load growth, UI's own generating capability and the
generating capability of its wholesale supplier become inadequate to meet its
customer service obligations and 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 - "Franchises, Regulation and Competition - Competition" and
"Arrangements with Other Utilities".
Shown below is a summary of the Company's sources and uses of electricity
for 1998.
MEGAWATT-HOURS
--------------
(000'S)
SOURCES USES
------- ----
OWNED Retail Customers 5,452
Nuclear 1,594
Coal 1,514 Wholesale
Oil 2,756 Delivered to NEPOOL 975
Gas & Gas Turbines 5 Contracts 878
-----
Total Owned 5,869
Company Use & Losses 276
-----
PURCHASED
Contracts 782 Total Uses 7,581
=====
NEPOOL 628
Hydro-Quebec 302
-----
Total Sources 7,581
=====
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 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 38 distribution substations with a capacity of
80,050 KVA. The Company has 3,170 pole-line miles of overhead distribution lines
and 130 conduit-bank miles of underground distribution lines.
See "Capital Expenditure Program" concerning the estimated cost of
additions to the Company's transmission and distribution facilities.
- 23 -
CAPITAL EXPENDITURE PROGRAM
The Company's 1999-2003 capital expenditure program, excluding allowance
for funds used during construction and its effect on certain capital-related
items, is presently budgeted as follows:
[Enlarge/Download Table]
1999 2000 2001 2002 2003 Total
---- ---- ---- ---- ---- -----
(000's)
Generation (1) $4,891 $4,229 $2,435 $1,851 $1,280 $14,686
Distribution and Transmission 16,954 15,761 11,470 11,509 12,816 68,510
Other 6,443 5,238 2,731 2,543 1,949 18,904
------ ------ ------ ------ ------ -------
Subtotal 28,288 25,228 16,636 15,903 16,045 102,100
Nuclear Fuel 2,413 9,298 6,774 2,953 7,302 28,740
------ ------ ------ ------ ------ -------
Total Expenditures $30,701 $34,526 $23,410 $18,856 $23,347 $130,840
======= ======= ======= ======= ======= ========
Rate Base and Other Selected Data:
---------------------------------
Depreciation
Book Plant (1) $50,200 $48,120 $48,636 $48,910 $49,531
Conservation Assets 5,048 0 0 0 0
Decommissioning 2,781 2,892 3,007 3,128 3,253
Additional Required Amortization
Regulatory Tax Assets (pre-tax
and after-tax) 12,096 0 0 0 0
Other Regulatory Assets (pre-tax)(2) 0 49,500 54,500 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 0 0 0 0
Estimated Rate Base
(end of period) 849,684
(average) 920,367
(1) Reflects divestiture of fossil-fueled generation plant on April 1, 1999.
Remaining generation is nuclear, excluding nuclear fuel. See Item 1.
Business - "Franchises, Regulation and Competition - Competition".
(2) Additional amortization of unspecified regulatory assets, as ordered by
the Connecticut Department of Public Utility Control in its December 31,
1996 retail rate order, provided that, as expected, common equity return
on utility investment exceeds 10.5% after recording the additional
amortization. Substantially all of this accelerated amortization may have
to be eliminated in order to achieve the minimum 10% price reduction
(compared to the average fully bundled prices in effect on December 31,
1996), while providing for the added costs imposed by Public Act 98-28, a
statute enacted by Connecticut, designed to restructure the State's
regulated electric utility industry. See Item 1. Business "Franchises,
Regulation and Competition - Competition".
- 24 -
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, 1998, Seabrook Unit 1 has operated at a lifetime capacity
factor of 80%.
Millstone Unit 3 commenced commercial operation in April of 1986, pursuant
to a 40-year operating license issued by the NRC. It is jointly owned by
thirteen New England electric utility entities, including the Company, and is
operated by another service company subsidiary of NU. Through March 30, 1996,
when Millstone Unit 3 was taken out of service following an engineering
evaluation that determined that four safety-related valves would not be able to
perform their design function during certain postulated events, Millstone Unit 3
had operated at a lifetime capacity factor of 71.9%. A comprehensive Nuclear
Regulatory Commission (NRC) inquiry into the conformity of the unit and its
operations with all applicable NRC regulations and standards was completed and
the unit was allowed to resume operation beginning on July 4, 1998. It achieved
full power production on July 14, 1998, and has operated at a capacity factor of
70.5% from that date through December 31, 1998.
While Millstone Unit 3 was out of service, UI incurred incremental
replacement power costs estimated at approximately $500,000 per month, and
experienced an adverse impact on net earnings per share of approximately $.02
per month. In addition to these costs of replacement power, substantial
incremental direct costs were incurred to address the above-described problems
with respect to Millstone Unit 3. UI and the other nine non-NU owners of
Millstone Unit 3 paid their monthly shares of the costs of the unit, but
reserved their rights to contest whether the NU service company subsidiary that
is the operator of Millstone Unit 3 and/or one or both of the two operating NU
subsidiary electric utility companies that are the majority joint owners of
Millstone Unit 3 are responsible for the additional costs that the other joint
owners experienced as a result of the shutdown of Millstone Unit 3. On August 7,
1997, the Company and the other nine minority, non-NU joint owners of Millstone
Unit 3 filed lawsuits against NU and its trustees, as well as a demand for
arbitration against The Connecticut Light and Power Company and Western
Massachusetts Electric Company, 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 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.
- 25 -
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from UI. In December of 1996,
Connecticut Yankee filed decommissioning cost estimates and amendments to the
power contracts with its owners with the Federal Energy Regulatory Commission
(FERC). Based on regulatory precedent, this filing seeks confirmation that
Connecticut Yankee will continue to collect from its owners its decommissioning
costs, the unrecovered investment in the Connecticut Yankee Unit and other costs
associated with the permanent shutdown of the Connecticut Yankee Unit. On August
31, 1998, a FERC Administrative Law Judge (ALJ) released an initial decision
regarding Connecticut Yankee's December 1996 filing. The initial decision
contains provisions that would allow Connecticut Yankee to recover, through the
power contracts with its owners, the balance of its net unamortized investment
in the Connecticut Yankee Unit, but would disallow recovery of a portion of the
return on Connecticut Yankee's investment in the unit. The ALJ's decision also
states that decommissioning cost collections by Connecticut Yankee, through the
power contracts, should continue to be based on a previously-approved estimate
until a new, more reliable estimate has been prepared and tested. During October
of 1998, Connecticut Yankee and its owners filed briefs setting forth exceptions
to the ALJ's initial decision. If this initial decision is upheld by the FERC,
Connecticut Yankee could be required to write off a portion of the regulatory
asset on its Balance Sheet associated with the retirement of the Connecticut
Yankee Unit. In this event, however, the Company would not be required to record
any write-off on account of its 9.5% ownership share in Connecticut Yankee,
because the Company has recorded its regulatory asset associated with the
retirement of the Connecticut Yankee Unit net of any return on investment. The
Company cannot predict, at this time, the outcome of the FERC proceeding.
However, the Company will continue to support Connecticut Yankee's efforts to
contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $9.9
million) and return on investment (approximately $4.7 million) at December 31,
1998, is approximately $32.7 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
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.
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.
- 26 -
INSURANCE REQUIREMENTS
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the three nuclear generating
units in which the Company has an interest, the Company will be obligated to pay
its ownership and/or leasehold share of any statutory assessment resulting from
a nuclear incident at any nuclear generating unit. Based on its interests in
these nuclear generating units, the Company estimates its maximum liability
would be $17.8 million per incident. However, any assessment would be limited to
$2.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$3.1 million.
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 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.
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 that 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.
- 27 -
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 $497 million (in 1999 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1998 was $2.1 million. UI's share of the fund at December 31, 1998 was
approximately $16.5 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $560 million (in 1999 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made
during 1998 was $487,000. UI's share of the fund at December 31, 1998 was
approximately $6.5 million. The current decommissioning cost estimate for the
Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit
commencing in 1997, is $476 million, of which UI's share would be $45 million.
Through December 31, 1998, $85 million has been expended for decommissioning.
The projected remaining decommissioning
- 28 -
cost is $391 million, of which UI's share would be $37 million. The
decommissioning trust fund for the Connecticut Yankee Unit is also managed by
NU. For the Company's 9.5% equity ownership in Connecticut Yankee,
decommissioning costs of $2.4 million were funded by UI during 1998, and UI's
share of the fund at December 31, 1998 was $25 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 has vigorously contested 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. On May 8, 1998, the City and the Company
reached a comprehensive settlement of all of the Company's contested personal
property tax assessments and tax bills for the tax years 1991-1992 through
1997-1998 and the Company's personal property tax assessments for the tax year
1998-1999 and subsequent years. Under the terms of this settlement, the Company
agreed to pay the City $14.025 million, subject to Superior Court approval of
the settlement and conditioned on the Company receiving authorization from the
DPUC to recover the settlement amount from its retail customers. The DPUC denied
the Company's initial application for such authorization, and the City agreed to
extend to December 31, 1998 the time period for satisfying this condition of the
settlement in return for payments by the Company of $6 million. The Company
filed a second application with the DPUC on July 9, 1998, and on December 8,
1998 a Joint Stipulation among the Company, the Office of Consumer Counsel and
the Connecticut Attorney General relative to the recovery of the settlement
amount was filed with the DPUC. On December 30, 1998, the DPUC issued a draft
decision rejecting this Joint Stipulation. The Company filed written exceptions
to this draft decision and requested oral argument on the draft decision; and
the City agreed to extend to March 1, 1999 the time period for obtaining a
favorable DPUC authorization, in return for
- 29 -
payment by the Company of an additional $6 million. On February 10, 1999, the
DPUC issued a final decision rejecting the Joint Stipulation. The Company
subsequently waived the condition to the settlement with the City that the DPUC
authorize recovery of the settlement amount from the Company's retail customers
and, on March 5, 1999, the settlement was approved by the Superior Court. The
Company will pay the remaining $2.025 million of the settlement amount to the
City promptly.
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, 1998.
- 30 -
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
---- --- -------- --------------
Nathaniel D. Woodson 57 Chairman of the Board of Directors, President
and Chief Executive Officer December 31, 1998
Robert L. Fiscus 61 Vice Chairman of the Board of Directors
and Chief Financial Officer February 23, 1998
James F. Crowe 56 Group Vice President Power Supply Services October 1, 1996
Albert N. Henricksen 57 Group Vice President Support Services October 1, 1996
Anthony J. Vallillo 50 Group Vice President Client Services October 1, 1996
Rita L. Bowlby 60 Vice President Corporate Affairs February 1, 1993
Stephen F. Goldschmidt 53 Vice President Planning and Information Resources October 1, 1996
James L. Benjamin 57 Controller January 1, 1981
Kurt D. Mohlman 50 Treasurer and Secretary January 1, 1994
Charles J. Pepe 50 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. All of the above executive officers have
entered into employment agreements with the Company. There is no arrangement or
understanding between any executive officer of the Company and any other person
pursuant to which such officer was selected as an officer.
A brief account of the business experience during the past five years of
each executive officer of the Company is as follows:
NATHANIEL D. WOODSON. Mr. Woodson served as Vice President and General
Manager of the Energy Systems Business Unit of Westinghouse Electric Corporation
during the period January 1, 1994 to April 30, 1996. He served as President of
the Company during the period February 23, 1998 to May 20, 1998 and President
and Chief Executive Officer during the period May 20, 1998 to December 31, 1998.
He has served as Chairman of the Board of Directors, President and Chief
Executive Officer since December 31, 1998.
ROBERT L. FISCUS. Mr. Fiscus served as President and Chief Financial
Officer during the period January 1, 1994 to February 23, 1998. He has served as
Vice Chairman of the Board of Directors and Chief Financial Officer since
February 23, 1998.
JAMES F. CROWE. Mr. Crowe served 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-Administration from January 1, 1994 to October 1, 1996. He has served
as Group Vice President Support Services since October 1, 1996.
ANTHONY J. VALLILLO. Mr. Vallillo served as Vice President-Marketing during
the period January 1, 1994 to October 1, 1996. He has served as Group Vice
President Client Services since October 1, 1996.
RITA L. BOWLBY. Ms. Bowlby has served as Vice President-Corporate Affairs
of the Company during the five-year period.
- 31 -
STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served 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.
JAMES L. BENJAMIN. Mr. Benjamin has served as Controller of the Company
during the five-year period.
KURT D. MOHLMAN. Mr. Mohlman has served as Treasurer and Secretary of the
Company during the five-year period.
CHARLES J. PEPE. Mr. Pepe has served as Assistant Treasurer and Assistant
Secretary of the Company during the five-year period.
PART II
Item 5. Market for the Company's Common Equity and Related Stockholder Matters.
UI's Common Stock is traded on the New York Stock Exchange, where the high
and low sale prices during 1998 and 1997 were as follows:
1998 Sale Price 1997 Sale Price
--------------- ---------------
High Low High Low
---- --- ---- ---
First Quarter 48 9/16 42 5/8 32 5/8 24 1/2
Second Quarter 51 15/16 46 15/16 30 7/8 24 1/2
Third Quarter 53 9/16 49 37 31 1/2
Fourth Quarter 53 3/4 48 1/16 45 15/16 37
UI has paid quarterly dividends on its Common Stock since 1900. The
quarterly dividends declared in 1997 and 1998 were at a rate of 72 cents per
share.
The indenture under which $266.2 million principal amount of Notes are
issued places limitations on the payment of cash dividends on common stock and
on the purchase or redemption of common stock. Retained earnings in the amount
of $105.7 million were free from such limitations at December 31, 1998.
As of December 31, 1998, there were 14,735 Common Stock shareowners of
record.
- 32 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA
1998 1997 1996
===================================================================================================================================
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $262,974 $259,842 $265,562
Commercial 254,765 248,984 263,609
Industrial 102,201 102,967 108,825
Other 11,667 11,778 11,880
------------------ ---------------- -----------------
Total Retail 631,607 623,571 649,876
Wholesale (1) 44,948 82,871 72,844
Other operating revenues 9,636 3,825 3,300
------------------ ---------------- -----------------
Total operating revenues 686,191 710,267 726,020
------------------ ---------------- -----------------
Fuel and interchange energy -net
Retail - own load 116,769 109,542 95,359
Wholesale 34,775 73,124 65,158
Capacity purchased-net 34,515 39,976 46,830
Depreciation 82,809 (3) 74,618 (3) 65,921
Other amortization, principally deferred return and cancelled plant 13,758 13,758 13,758
Other operating expenses, excluding tax expense 188,946 200,803 219,630 (7)
Gross earnings tax 24,039 23,618 26,757
Other non-income taxes 40,635 (4) 28,922 30,382
------------------ ---------------- -----------------
Total operating expenses, excluding income taxes 536,246 564,361 563,795
------------------ ---------------- -----------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 468 1,575 2,375
Other non-operating income(loss) (3,803)(5) 4,186 (7,166)(5)
Interest expense
Long-term debt - net 42,836 56,158 65,046
Other 9,018 6,068 4,721
------------------ ---------------- -----------------
Total 51,854 62,226 69,767
------------------ ---------------- -----------------
Minority interest in preferred securities 4,813 4,813 4,813
Income tax expense
Operating income tax 53,619 41,333 (6) 53,090
Non-operating income tax (5,866) (2,496) (9,332)
------------------ ---------------- -----------------
Total 47,753 38,837 43,758
------------------ ---------------- -----------------
Income(loss) before cumulative effect of accounting change 42,190 45,791 39,096
Cumulative effect of change in accounting - net of tax 0 0 0
------------------ ---------------- -----------------
Net income (loss) 42,190 45,791 39,096 (8)
Discount on preferred stock redemption (21) (48) (1,840)
Preferred and preference stock dividends 201 205 330
------------------ ---------------- -----------------
Income (loss) applicable to common stock $42,010 $45,634 $40,606
-----------------------------------------------------------------------------------------------------------------------------------
Operating income $96,326 $104,573 $109,135
===================================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $1,172,555 $1,222,174 $1,258,306
Construction work in progress 33,695 25,448 40,998
Plant-related regulatory asset 0 0 0
Other property and investments 58,047 58,441 49,091
Current assets 255,365 165,027 163,350
Deferred charges and regulatory assets 371,674 408,993 449,150
------------------ ---------------- -----------------
Total Assets $1,891,336 $1,880,083 $1,960,895
-----------------------------------------------------------------------------------------------------------------------------------
Common stock equity $445,507 $438,963 $440,016
Preferred, preference stock and preferred securities 54,299 54,351 54,461
Long-term debt excluding current portion 664,510 644,670 759,680
Noncurrent liabilities (9) 109,981 119,868 138,816
Current portion of long-term debt 66,202 100,000 69,900
Notes payable 86,892 37,751 10,965
Other current liabilities (9) 123,006 130,993 129,007
Deferred income tax liabilities and other 340,939 353,487 358,050
------------------ ---------------- -----------------
Total Capitalization and Liabilities $1,891,336 $1,880,083 $1,960,895
===================================================================================================================================
(1) Operating Revenues, for years prior to 1992, include wholesale power
exchange contract sales that were reclassified from Fuel and Capacity
expenses in accordance with Federal Energy Regulatory Commission
requirements.
(2) Includes reclassification of certain Commercial and Industrial customers.
(3) Includes the before-tax effect of charges for additional amortization of
conservation & load management costs: $13.1 million in 1998 and $6.6
million in 1997.
(4) Includes the effect of charges of $14.0 million, before-tax, associated
with property tax settlement.
(5) Includes the before-tax effect of charges for losses associated with
unregulated subsidiaries: $4.9 million in 1998 and $4.5 million in 1996.
- 33 -
[Enlarge/Download Table]
1995 1994 1993 1992 1991 1990 1989
=============================================================================================================================
$260,694 $252,386 $238,185 $226,455 $226,751 $211,891 $205,183
259,715 250,771 (2) 256,559 253,456 (2) 255,782 234,704 219,852
106,963 104,242 (2) 97,466 97,010 (2) 91,895 94,526 92,855
11,736 11,469 11,349 11,065 10,886 10,536 9,943
--------------- -------------- -------------- ------------- ------------- ------------- --------------
639,108 618,868 603,559 587,986 585,314 551,657 527,833
48,232 34,927 45,931 75,484 84,236 85,657 77,925
3,109 2,953 3,533 3,855 3,821 3,332 3,348
--------------- -------------- -------------- ------------- ------------- ------------- --------------
690,449 656,748 653,023 667,325 673,371 640,646 609,106
--------------- -------------- -------------- ------------- ------------- ------------- --------------
96,538 99,589 98,694 108,084 123,010 119,285 128,739
41,631 27,765 39,356 55,169 61,858 69,117 62,681
47,420 44,769 47,424 43,560 44,668 42,827 50,234
61,426 58,165 56,287 50,706 48,181 36,526 35,618
13,758 1,172 1,780 10,415 10,415 4,173 10,415
183,749 193,098 203,427 (10) 183,426 178,912 176,419 144,867
27,379 27,403 27,955 27,362 27,223 25,595 24,506
31,564 32,458 29,977 31,869 28,673 24,648 20,294
--------------- -------------- -------------- ------------- ------------- ------------- --------------
503,465 484,419 504,900 510,591 522,940 498,590 477,354
--------------- -------------- -------------- ------------- ------------- ------------- --------------
0 0 7,497 15,959 17,970 21,503 0
2,762 3,463 4,067 3,232 5,190 3,443 65,443
(4,272) (1,907) 71 18,545 2,697 22,654 (219,742)
63,431 73,772 80,030 88,666 90,296 94,056 91,126
13,140 10,301 12,260 12,882 9,847 15,468 22,849
--------------- -------------- -------------- ------------- ------------- ------------- --------------
76,571 84,073 92,290 101,548 100,143 109,524 113,975
--------------- -------------- -------------- ------------- ------------- ------------- --------------
3,583 0 0 0 0 0 0
59,828 44,937 33,309 48,712 47,231 43,493 37,963
(4,901) (3,214) (6,322) (12,558) (19,299) (17,409) (101,135)
--------------- -------------- -------------- ------------- ------------- ------------- --------------
54,927 41,723 26,987 36,154 27,932 26,084 (63,172)
--------------- -------------- -------------- ------------- ------------- ------------- --------------
50,393 48,089 40,481 56,768 48,213 54,048 (73,350)
0 (1,294) 0 0 7,337 0 0
--------------- -------------- -------------- ------------- ------------- ------------- --------------
50,393 46,795 40,481 (11) 56,768 55,550 54,048 (73,350)
(2,183) 0 0 0 0 0 0
1,329 3,323 4,318 4,338 4,530 4,751 8,233
--------------- -------------- -------------- ------------- ------------- ------------- --------------
$51,247 $43,472 $36,163 $52,430 $51,020 $49,297 ($81,583)
-----------------------------------------------------------------------------------------------------------------------------
$127,156 $127,392 $114,814 $108,022 $103,200 $98,563 $93,789
=============================================================================================================================
$1,277,910 $1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173 $562,473
41,817 57,669 77,395 59,809 54,771 50,257 675,831
0 0 0 0 0 0 81,768
53,355 53,267 58,096 65,320 79,009 90,006 91,648
137,277 157,309 187,981 247,954 164,839 161,066 170,823
475,258 538,601 567,394 556,493 554,365 553,986 605,696
--------------- -------------- -------------- ------------- ------------- ------------- --------------
$1,985,617 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239
-----------------------------------------------------------------------------------------------------------------------------
$439,981 $428,028 $423,324 $422,746 $401,771 $379,812 $362,584
60,539 44,700 60,945 60,945 62,640 69,700 70,000
845,684 708,340 875,268 893,457 909,998 899,993 868,884
65,747 59,458 62,666 44,567 110,217 110,850 117,200
40,800 193,133 143,333 92,833 37,500 41,667 18,667
0 67,000 0 84,099 13,000 15,000 45,000
102,336 122,084 117,343 114,757 114,280 138,173 133,459
430,530 452,248 451,413 440,230 423,449 409,293 572,445
--------------- -------------- -------------- ------------- ------------- ------------- --------------
$1,985,617 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239
=============================================================================================================================
(6) Includes the effect of credits of $6.7 million to provide tax provision for
fossil generation decommissioning.
(7) Includes the effect of charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(8) Includes the effect of charges of $13.4 million, after-tax, associated with
voluntary early retirement programs.
(9) Amounts for years prior to 1996 were reclassified in 1996.
(10) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(11) Includes the effect of a reorganization charge of $7.8 million, after-tax.
- 34 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1998 1997 1996
=============================================================================================================================
COMMON STOCK DATA
Average number of shares outstanding 14,017,644 13,975,802 14,100,806
Number of shares outstanding at year-end 14,034,562 13,907,824 14,101,291
Earnings(loss) per share (average) - basic $3.00 $3.27 $2.88
Earnings(loss) per share (average) - diluted $3.00 $3.26 $2.87
Recurring earnings(loss) per share (average) (1) $3.42 $3.11 $3.94
Book value per share $31.74 $31.56 $31.20
Average return on equity
Total 9.44% 10.45% 9.20%
Utility 11.43% 11.54% 11.51%
Dividends declared per share $2.88 $2.88 $2.88
Market Price:
High $53.750 $45.938 $39.750
Low $42.625 $24.500 $31.375
Year-end $51.500 $45.938 $31.375
=============================================================================================================================
Net cash provided by operating activities, less dividends ($000's) $69,573 $127,807 $103,943
Capital expenditures, excluding AFUDC $38,040 $33,436 $47,174
=============================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 1,924,724 1,903,096 1,891,988
Commercial 2,324,507 2,253,488 2,258,501
Industrial 1,154,935 1,170,815 1,141,109
Other 48,166 48,717 48,291
------------------ ---------------- -----------------
Total 5,452,332 5,376,116 5,339,889
------------------ ---------------- -----------------
Number of retail customers by class (average)
Residential 281,591 280,283 279,024
Commercial 29,468 29,228 28,666
Industrial 1,752 1,697 1,652
Other 1,172 1,163 1,141
------------------ ---------------- -----------------
Total 313,983 312,371 310,483
------------------ ---------------- -----------------
Revenue per kilowatt hour by class (cents)
Residential 13.66 13.65 14.04
Commercial 10.96 11.05 11.67
Industrial 8.85 8.79 9.54
Average large industrial customers time of use rate (cents) 8.16 8.12 8.26
System requirements (MWh) 5,728,222 5,631,296 5,640,957
Peak load - kilowatts 1,142,670 1,173,160 1,044,620
Generating capability- peak(kilowatts) 1,323,380 1,356,100 1,522,350
Load factor 57.23% 54.80% 61.64%
Fuel generation mix percentages
Coal 21 44 38
Oil 46 15 8
Nuclear 23 25 37
Cogeneration 6 9 9
Gas 0 2 3
Hydro 4 5 5
-----------------------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $629,446 $621,874 $642,106
Base rate adjustments 2,161 1,697 7,770
Sales provision adjustment 0 0 0
------------------ ---------------- -----------------
Total $631,607 $623,571 $649,876
------------------ ---------------- -----------------
Revenues - retail sales per kWh (cents)
Base 11.54 11.57 12.02
Base rate adjustments 0.04 0.03 0.15
Sales provision adjustment 0.00 0.00 0.00
------------------ ---------------- -----------------
Total 11.58 11.60 12.17
------------------ ---------------- -----------------
Fuel and energy cost per kWh (cents) 2.04 1.95 1.69
Fossil 2.60 2.39 2.41
Nuclear 0.58 0.61 0.46
-----------------------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,193 1,175 1,287
Total payroll($000 'S) $65,294 $68,640 $69,276
=============================================================================================================================
(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.
- 35 -
[Enlarge/Download Table]
1995 1994 1993 1992 1991 1990 1989
=============================================================================================================================
14,089,835 14,085,452 14,063,854 13,941,150 13,899,906 13,887,748 13,887,748
14,100,091 14,086,691 14,083,291 14,033,148 13,932,348 13,887,748 13,887,748
$3.64 $3.09 $2.57 $3.76 $3.67 $3.55 ($5.87)
$3.63 $3.08 $2.56 $3.74 $3.66 $3.55 ($5.87)
$3.61 $3.28 $3.13 $3.17 $2.90 $3.55 ($5.87)
$31.20 $30.39 $30.06 $30.12 $28.84 $27.35 $26.11
11.84% 10.19% 8.45% 12.67% 13.01% 13.39% -18.88%
13.04% 12.50% 10.97% 14.46% 13.39% 13.97% 20.21%
$2.82 $2.76 $2.66 $2.56 $2.44 $2.32 $2.32
$38.500 $39.500 $45.875 $42.000 $39.125 $34.125 $34.250
$29.500 $29.000 $38.500 $34.125 $30.000 $26.875 $24.750
$37.375 $29.500 $40.250 $41.500 $39.000 $31.125 $34.250
=============================================================================================================================
$120,033 $94,807 $104,547 $109,020 $73,865 $39,189 $31,437
$59,363 $63,044 $94,743 $66,390 $63,157 $64,018 $77,041
=============================================================================================================================
1,890,575 1,892,955 1,844,041 1,799,456 1,851,447 1,826,700 1,883,363
2,273,965 2,285,942 (2) 2,359,023 2,303,216 (2) 2,347,757 2,259,340 2,254,099
1,126,458 1,135,831 (2) 1,036,547 997,168 (2) 980,071 1,060,751 1,109,119
48,435 48,718 50,715 52,984 55,118 58,013 60,427
--------------- -------------- -------------- ------------- ------------- ------------- --------------
5,339,433 5,363,446 5,290,326 5,152,824 5,234,393 5,204,804 5,307,008
--------------- -------------- -------------- ------------- ------------- ------------- --------------
278,326 275,441 273,752 273,936 274,064 275,637 276,385
28,550 28,394 (2) 28,968 28,848 (2) 29,768 29,808 29,526
1,599 1,538 (2) 959 1,017 (2) 268 319 347
1,122 1,127 1,175 1,358 1,361 1,352 1,316
--------------- -------------- -------------- ------------- ------------- ------------- --------------
309,597 306,500 304,854 305,159 305,461 307,116 307,574
--------------- -------------- -------------- ------------- ------------- ------------- --------------
13.79 13.33 12.92 12.58 12.25 11.60 10.89
11.42 10.97 10.88 11.00 10.89 10.39 9.75
9.50 9.18 9.40 9.73 9.38 8.91 8.37
8.53 8.69 8.89 8.84 8.64 8.06 7.58
5,647,690 5,652,657 5,630,581 5,475,664 5,541,477 5,501,495 5,603,502
1,156,740 1,130,780 1,114,900 1,034,440 1,145,820 1,054,600 1,094,400
1,434,102 1,462,290 1,515,420 1,402,800 1,474,190 1,449,600 1,289,800
55.74% 57.07% 57.65% 60.26% 55.21% 59.55% 58.45%
37 35 31 34 34 43 39
7 14 16 17 21 24 37
37 32 38 35 29 20 11
9 9 8 8 9 9 9
5 4 1 1 4 3 3
5 6 6 5 3 1 1
-----------------------------------------------------------------------------------------------------------------------------
$637,219 $619,097 $605,887 $608,176 $607,997 $589,346 $577,611
1,889 (229) (2,328) (41,221) (37,497) (45,900) (49,778)
0 0 0 21,031 14,814 8,211 0
--------------- -------------- -------------- ------------- ------------- ------------- --------------
$639,108 $618,868 $603,559 $587,986 $585,314 $551,657 $527,833
--------------- -------------- -------------- ------------- ------------- ------------- --------------
11.93 11.54 11.45 11.80 11.62 11.32 10.88
0.04 0.00 (0.04) (0.80) (0.72) (0.88) (0.93)
0.00 0.00 0.00 0.41 0.28 0.16 0.00
--------------- -------------- -------------- ------------- ------------- ------------- --------------
11.97 11.54 11.41 11.41 11.18 10.60 9.95
--------------- -------------- -------------- ------------- ------------- ------------- --------------
1.71 1.76 1.75 2.43 2.67 2.63 2.78
2.22 2.14 2.08 2.98 3.11 2.89 2.98
0.85 0.94 1.23 1.42 1.62 1.55 0.89
-----------------------------------------------------------------------------------------------------------------------------
1,358 1,377 1,490 1,554 1,571 1,587 1,627
$72,984 $75,441 $75,305 $74,052 $71,888 $69,237 $65,175
=============================================================================================================================
- 36 -
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. Total operation and maintenance expense, excluding
one-time items and cogeneration capacity purchases, declined by 1.1 percent, on
average, during the past 5 years. There will be significant changes to operation
and maintenance expense and other expenses in 1999, partly as a result of the
Generation Asset Divestiture (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.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers; but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. As a
result of the Rate Plan, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Also as a result of the Rate Plan,
customer prices are required to be reduced by an additional 1% in 2000, and
another 1% in 2001, compared to 1996. Retail revenues have decreased by
approximately 4.8% through 1998 compared to 1996 due to customer price
reductions. The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act described below, the Rate
Plan may be reopened and modified. However, aside from implementing an
additional price reduction in 2000 to achieve the minimum 10% price reduction
required by the Restructuring Act and the probable reductions in the accelerated
amortizations scheduled in the Rate Plan, the Company is unable to predict, at
this time, in what other respects the Rate Plan may be modified on account of
this legislation.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from among competing
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the
- 37 -
charge for electricity generation services from the charge for delivering the
electricity and all other charges. On July 29, 1998, the DPUC issued the first
of what are expected to be several orders relative to this "unbundling"
requirement, and has now reopened its proceeding to consider the amount of the
generation services charge to be included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to certain adjustments, at least 10%
below its fully bundled prices for electricity at rates in effect on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments, to be the total rate charged under the standard offer, including
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment charge.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of other
above-market generation costs eligible for the competitive transition
assessment, such as regulated plant costs and tax-related regulatory assets or
other costs related to the restructuring transition, such that there will be no
net income effect of the sale. Net cash proceeds from the sale are expected to
be in the range of $160-$165 million. The Company anticipates using these
proceeds to reduce debt.
The October 2, 1998 sale agreement for Bridgeport Harbor Station and New
Haven Harbor Station resulted from a bidding process. The Company's only other
fossil-fueled generating station is its small deactivated English Station, in
New Haven. English Station was also offered for sale in the bidding process, but
it attracted no bids. Also offered for sale were two long-term contracts for the
purchase of power from refuse-to-energy facilities located in Bridgeport and
Shelton, Connecticut, one long-term contract for the purchase of power from a
small
- 38 -
hydroelectric generating station located in Derby, Connecticut, and the
Company's 5.45% participating share in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. None of these contracts
attracted an acceptable bid.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. In order
to mitigate the financial risk that these regulated service mandates will pose
to the Company in an unregulated power generation environment, its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates, effective July 1, 2000, as permitted by the Restructuring Act. This
clause, similar to and based on the purchased gas adjustment clauses used by
Connecticut's natural gas local distribution companies, would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay competitive market rates for power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
The Restructuring Act provides for the Distribution Company to recover its
reasonable costs of providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
other state and federal agencies, and the Company's common stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order anticipated sufficient
income in 2000 to accelerate amortization of regulatory assets of about $50
million, equivalent to about 8% of retail revenues. Substantially all of this
accelerated amortization may have to be eliminated to allow for the additional
standard offer price reduction requirement of 10%, at a minimum,
- 39 -
while providing for the added costs imposed by the restructuring legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income statement impact of certain costs that are expected to be
recovered in future regulated service rates and to establish regulatory assets
on its balance sheet for such costs. The effects of competition or a change in
the cost-based regulatory structure could cause the operations of the Company,
or a portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. If the Company, or a portion of its assets or
operations, were to cease meeting these criteria, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met, if such deferred costs are not
recoverable in that portion of the business that continues to meet the criteria
for the application of SFAS No. 71. If this change in accounting were to occur,
it 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]
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year $101.4 $34.5 $9.0 $42.7 $ -
Internally Generated Funds less Dividends 98.4 59.4 57.4 64.4 72.7
Net Proceeds from Sale of Fossil Generation Plants 160.0 - - - -
----- ----- ----- ----- ----
Subtotal 359.8 93.9 66.4 107.1 72.7
Less:
Capital Expenditures (excluding AFUDC) 30.7 34.5 23.4 18.9 23.3
----- ----- ----- ----- -----
Cash Available to pay Debt Maturities and Redemptions 329.1 59.4 43.0 88.2 49.4
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 145.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
----- ----- ----- ----- -----
External Financing Requirements (Surplus) $(34.5) $(9.0) $(42.7) $12.1 $51.1
===== ==== ===== ==== ====
Note:Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections, including the implementation of the legislative
mandate to achieve a 10% price reduction from December 31, 1996 price
levels by the year 2000. Connecticut's Restructuring Act, described at
"Major Influences on Financial Condition", requires the Company to divest
itself of its fossil-fueled generating plants prior to January 1, 2000 and
to attempt to divest itself of its ownership interests in nuclear-fueled
generating units prior to January 1, 2004. This forecast reflects the
estimated net after-tax proceeds ($160-$165 million) from a proposed
divestiture of fossil-fueled generation
- 40 -
plants on or about April 1, 1999. All of these estimates are subject to
change due to future events and conditions that may be substantially
different from those used in developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement and an $80 million revolving credit
agreement, 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 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 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.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
On June 8, 1998, the Company repaid a $50 million Term Loan prior to its
August 29, 2000 due date. On June 8, 1998, the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of December 31, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
On December 18, 1998, the Company issued and sold $100 million principal
amount of 6% five-year Notes. The yield on the Notes, which were issued at a
discount, is 6.034%; and the Notes will mature on December 15, 2003. The
proceeds from the sale of the Notes were used to repay $66.2 million principal
amount of 6.2% Notes, which matured on January 15, 1999, and for general
corporate purposes.
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and will be paid semi-annually beginning on
August 1, 1999. In addition, on February 1, 1999, the Company converted $98.5
million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds will
be paid semi-annually beginning on August 1, 1999.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 1999. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business,
- 41 -
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, 1998, the
Company had no short-term borrowings outstanding under this facility.
In addition, as of December 31, 1998, one of the Company's subsidiaries,
American Payment Systems, Inc., had borrowings of $6.8 million outstanding under
a bank line of credit agreement.
At December 31, 1998, the Company had $101.4 million of cash and temporary
cash investments, an increase of $69.4 million from the balance at December 31,
1997. The components of this increase, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
Balance, December 31, 1997 $ 32.0
-----
Net cash provided by operating activities 110.0
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments 29.4
- Dividend payments (40.5)
Net cash provided by investing activities, excluding investment
in plant 8.5
Cash invested in plant, including nuclear fuel (38.0)
-----
Net Change in Cash 69.4
-----
Balance, December 31, 1998 $101.4
=====
The Company's long-term debt instruments do not limit the amount of short-term
debt that the Company may issue. The Company's revolving credit agreement
described above requires it to maintain an available earnings/interest charges
ratio of not less than 1.5:1.0 for each 12-month period ending on the last day
of each calendar quarter. For the 12-month period ended December 31, 1998, this
coverage ratio was 3.6:1.0.
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
complement UI's regulated electric utility business and provide long-term
rewards to UI's shareowners.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of UI and other utilities. It
manages agent networks in 36 states and processed approximately $7.5 billion in
customer payments during 1998, generating operating revenues of approximately
$33.7 million and operating income of approximately $1.7 million. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional buildings, and is participating
in the development of district heating and cooling facilities in the downtown
New Haven area, including the energy center for an office tower and
participation as a 52% partner in the energy center for a city hall and office
tower complex. A third URI subsidiary, Precision Power, Inc., provides
power-related equipment and services to the owners of commercial buildings,
government buildings and industrial facilities. URI's fourth subsidiary, United
Bridgeport Energy, Inc., is participating in a merchant wholesale electric
generating facility being constructed on land leased from UI at its Bridgeport
Harbor Station generating plant.
- 42 -
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)
1998 $(3,993) $(0.28) $33,482
1997 (542) (0.04) 27,873
1996 (5,237) (0.37) 36,385
In 1996 and 1998, the Company made provisions for losses of $2.6 million
(after-tax) and $2.8 million (after-tax), respectively, associated with
collection agent errors and defaults and miscellaneous other items at its
American Payment Systems, Inc. subsidiary.
YEAR 2000 ISSUE
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct
deficiencies in its computer systems. This comprehensive program includes all
information technology systems and encompasses systems critical to the
generation, transmission and distribution of electric energy as well as
traditional business systems. Critical systems have been defined as those
business processes, including embedded technology, which if not remediated may
have a significant impact on safety, customers, revenue or regulatory
compliance. The Company has also identified critical suppliers and other persons
with whom data must be exchanged and is asking for assurance of their Year 2000
compliance.
An inventory and assessment of the Company's computer system applications,
hardware, software and embedded technologies have been completed, and
recommended solutions to all identified risks and exposures have been generated.
A testing, remediation, renovation, replacement and retirement program has been
in progress since early 1998. Both external and internal resources are being
utilized to accomplish the testing, remediation and renovation efforts. A total
of 378 affected business processes have been identified and 229 of them have
been verified as Year 2000 compliant through testing, remediation, replacement
or retirement. The remediation methodology utilized has been Fixed Windowing,
and totally independent platforms have been installed for testing all of the
applications. Necessary upgrades to mainframe hardware and software are expected
to be completed and tested by June 30, 1999. A parallel program for desktop
hardware and application software on all platforms is currently projected to be
completed and tested, for all critical systems, by June 1, 1999, except in a
minority of cases where a business specific need dictates a later date - but not
later than December 31, 1999. Requests for documented compliance information
have been sent to all critical suppliers, data sharers and facility building
owners and, as responses are received, appropriate solutions and testing
programs are being developed and executed.
While failure to achieve Year 2000 compliance by any one of a number of
critical suppliers and data sharers could have some adverse effect on the
success of the Company's implementation program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications providers, the other participants in the New England Power
Pool (NEPOOL), and the Independent System Operator (ISO) that operates the
NEPOOL bulk power supply system. Year 2000 compliance failures by any of these
entities could have a material effect on electricity delivery and telemetering.
In its efforts to mitigate these risks the Company has taken several actions. UI
has communicated its concerns to its principal telecommunications provider and a
joint effort to design and plan appropriate testing to insure that all critical
telecommunications functions will be operational has commenced. The Year 2000
Issue is also being addressed at the regional level by NEPOOL and the ISO.
Coordination efforts with NEPOOL to establish utility testing and readiness are
underway. The Company is a participant in all of the subcommittees working
within NEPOOL/ISO on efforts to assure operational reliability.
- 43 -
The Company is also actively involved with NEPOOL/ISO in the planning effort for
integrated contingency planning, as directed by the North American Electric
Reliability Council.
Aside from telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant risk to the success of the Company's Year 2000 compliance
implementation program. In order to minimize these risks, the Company will be
actively involved in contingency planning. While the Company's knowledge and
experience in electric system recovery planning and execution has been
demonstrated in the past, the Company recognizes the need for, and importance
of, Year 2000-specific contingency planning, because the complex interaction of
today's computing and communications systems precludes certainty that all
critical system remediation will be successful. At this time, contingency
planning for essential business functions is under investigation in most areas,
but specific needs have not been fully identified. These plans will be developed
by the end of first quarter of 1999, after the majority of business processes
are scheduled to be tested and within the timeframe when the NEPOOL/ISO process
is due to develop region-wide contingency plans for operations. As a part of the
contingency planning process, consideration will be given to potential frequency
and duration of interruptions in the generating, financial and communications
infrastructures. Since contingency planning is, by nature, a speculative
process, there can be no assurance that this planning will completely eliminate
the risk of material impacts to the Company's business due to Year 2000
problems. However, the Company recognizes the importance to its customers of a
reliable supply of electricity, and it intends to devote whatever resources are
necessary to assure that both the program and its implementation are successful.
The Company believes that the successful implementation of this program
should ultimately cost no more than $6 million for existing information systems
and embedded technology. A total of $2.4 million had been expended as of the end
of 1998. As systems testing progresses and more embedded technology vendor
product information is forthcoming, business decisions made and testing results
verified, the need for increased expenditures, if necessary, will be determined.
The Company believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.
RESULTS OF OPERATIONS
1998 VS. 1997
-------------
Earnings for the twelve months of 1998 were $42.0 million, or $3.00 per
share (both basic and diluted), down $3.6 million, or $.27 per share, from the
twelve months of 1997. Excluding one-time items, accelerated amortization due to
one-time items and associated regulated "sharing" effects, 1998 earnings from
operations were $47.9 million, or $3.42 per share, up $.31 per share from 1997.
The one-time items and their earnings per share impacts recorded in these
periods are shown at "One-time items recorded in 1997 and 1998" below.
Retail operating revenues increased by about $8.0 million in the twelve
months of 1998 compared to 1997. Retail fuel and energy expense increased by
$7.2 million and there was an increase of $0.4 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $0.4 million. The principal components of the
retail sales margin change, year over year, include:
- 44 -
$ millions
------------------------------------------------------------------ ---------
Revenue from:
------------------------------------------------------------------ ---------
DPUC rate order, excluding "sharing" (1.3)
------------------------------------------------------------------ ---------
Other price changes (0.3)
------------------------------------------------------------------ ---------
Estimate of "real" retail sales growth, up 1.1% 10.8
------------------------------------------------------------------ ---------
Estimate of weather effect on retail sales, up 0.2 % 1.8
------------------------------------------------------------------ ---------
Sales decrease from Yale University cogeneration, (0.9) % (3.0)
------------------------------------------------------------------ ---------
Fuel and energy, margin effect:
------------------------------------------------------------------ ---------
Sales increase (2.7)
------------------------------------------------------------------ ---------
Increased nuclear availability 0.4
------------------------------------------------------------------ ---------
Unscheduled outage at Bridgeport Unit 3 (see Note A) (2.5)
------------------------------------------------------------------ ---------
Fossil price and other (2.4)
------------------------------------------------------------------ ---------
Note A: Saltwater contamination caused a shutdown of the Bridgeport Harbor Unit
3 generating unit on May 22, 1998. The unit returned to full service
on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale energy expense)
increased slightly in the twelve months of 1998 compared to the twelve months of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $5.8 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $15.0 million in the twelve months of 1998 compared to the
twelve months of 1997. The principal components of these expense changes, year
over year, include:
$ millions
------------------------------------------------------------------ ---------
Capacity expense:
------------------------------------------------------------------ ---------
Connecticut Yankee preparing for decommissioning (4.2)
------------------------------------------------------------------ ---------
Cogeneration and other purchases (1.3)
------------------------------------------------------------------ ---------
Other O&M expense:
------------------------------------------------------------------ ---------
Seabrook (4.6)
------------------------------------------------------------------ ---------
Millstone Unit 3 (4.0)
------------------------------------------------------------------ ---------
Fossil generation unit overhauls and outages 7.5
------------------------------------------------------------------ ---------
Pension investment performance and assumptions (3.0)
------------------------------------------------------------------ ---------
Personnel reductions (6.0)
------------------------------------------------------------------ ---------
NEPOOL transmission expense 3.1
------------------------------------------------------------------ ---------
Other (2.5)
------------------------------------------------------------------ ---------
Depreciation expense, excluding accelerated amortization, increased by $1.5
million in the twelve months of 1998 compared to 1997. According to the
Company's current regulatory Rate Plan, "accelerated" amortization of past
utility investments is scheduled for every year that the Rate Plan is in effect,
contingent upon the Company earning a 10.5% return on utility common stock
equity. All of the accelerated amortization in 1997 was recorded in the second
quarter of that year as a result of a one-time gain recorded in that quarter.
All of the accelerated amortization for 1998, $13.1 million, was recorded
against earnings from operations. In addition, as part of the "sharing"
mechanism, the Company would have accrued an additional amortization of about
$2.6 million ($1.7 million after-tax) in 1998 against utility earnings from
operations. Because of the one-time items in 1998, no "sharing" was actually
recorded. The one-time charge for property tax expense incurred in the fourth
quarter was a utility expense and negated the "sharing" that would have occurred
from operations.
Other net income from operations decreased by about $4.7 million in the
twelve months of 1998 compared to 1997. The Company's largest unregulated
subsidiary, American Payment Systems, Inc. (APS), earned about $1.6 million
(before-tax) in 1998, before one-time charges, compared to a breakeven result in
1997. This was more than
- 45 -
offset by greater losses, compared to 1997, in the Company's other unregulated
subsidiaries: $1.2 million (before-tax) at Precision Power, Inc. from the
write-off of previously deferred costs and a review of reserves, and $1.2
million (before-tax) from start-up costs in other unregulated activities. By
DPUC order, since consolidation at the unregulated subsidiary level produced no
net taxable income in either year, the tax benefits associated with the losses,
about $0.8 million in 1998 and $0.4 million in 1997, were treated as benefits to
utility income for the purposes of calculating return on utility common equity
and "sharing". Other net income also decreased due to the absence of other
non-utility income accruals made in 1997, cancelled project write-offs, lower
income from non-operating utility investments, and higher unallocated interest
charges.
Interest charges, excluding allowance for borrowed funds used during
construction, continued on their downward trend, decreasing by $10.4 million in
the twelve months of 1998 compared to 1997, as a result of the Company's
refinancing program and strong cash flow.
OVERVIEW OF "SHARING" AND THE IMPACT ON EARNINGS
------------------------------------------------
As previously indicated, the Company's regulatory Rate Plan requires a
"sharing" of regulated utility income that produces a return on utility equity
exceeding 11.5%. The measurement of this utility income and resulting return
calculation includes the effects of any utility one-time items. Under the Rate
Plan, one-third of the income above the 11.5% return would be applied to
customer bill reductions, one-third would be applied to additional amortization
of regulatory assets, and one-third would be retained by shareowners.
Earnings from operations, which excludes the impact of one-time items,
should reflect an appropriate imputed amount of "sharing" to reflect accurately
what the earnings would have been had neither the one-time items, nor their
impact on "sharing", occurred. The Company estimates that the "sharing" that
would have occurred had there been no one-time items in 1998 would have been: a
revenue reduction of about $3.0 million or $.12 per share, increased
amortization of about $1.7 million (after-tax) or $.12 per share, and retention
by the Company of $1.7 million of income (after-tax) or $.12 per share. To
summarize for 1998:
[Download Table]
1998 Earnings per share (EPS) From One-time
Operations Items
and and "Sharing"
"Sharing" Reversals Total
---------- ------------- -----
Utility earnings before "sharing" $3.79 $(.45) $3.34
Less: Utility earnings to be "shared" (.36) .36 .00
---- ---- ----
Utility EPS at 11.5 percent utility return $3.43 $(.09) $3.34
Plus: 1/3 Retained "Sharing" benefit .12 (.12) .00
---- ---- ----
Net Utility EPS 3.55 (.21) 3.34
Unregulated Subsidiaries (.13) (.21) (.34)
---- ---- ----
Total 1998 EPS $3.42 $(.42) $3.00
Earnings reported through 3rd quarter 3.02 (.12) 2.90
---- ---- ----
Imputed 4th quarter earnings $ .40 $(.30) $ .10
===== ===== =====
- 46 -
ONE-TIME ITEMS RECORDED IN 1997 AND 1998
----------------------------------------
[Enlarge/Download Table]
One-time Items EPS
------------------------------------------------------------------------------------------------
1997 Quarter 2 Cumulative deferred tax benefits associated with future $ .48
Decommissioning of fossil fuel generating plants
------------------------------------------------------------------------------------------------
1997 Quarter 2 Accelerated amortization associated with one-time item $(.30)
------------------------------------------------------------------------------------------------
1997 Quarter 3 Gain from subleasing office space $ .05
------------------------------------------------------------------------------------------------
1997 Quarter 4 Pension benefit adjustments associated with 1996 VERP and VSP $ .11
------------------------------------------------------------------------------------------------
1997 Quarter 4 Contract termination charge $(.18)
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
1998 Quarter 2 Subsidiary reserve for agent collection shortfalls and other
potentially uncollectible receivables $(.21)
------------------------------------------------------------------------------------------------
1998 Quarter 3 Refund of prior period transmission charges, with interest $ .14
"Sharing" due to one-time items recorded through third quarter $(.05)
------------------------------------------------------------------------------------------------
1998 Quarter 4 Property tax settlement with the City of New Haven, CT $(.59)
Reversal of "sharing" imputed to property tax settlement $ .29
------------------------------------------------------------------------------------------------
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 fuel generating plants. By order of
the DPUC, the Company was instructed 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% for the year. As a result of the tax benefit, the full $6.4 million
was charged in the second quarter of 1997.
Additional 1997 one-time items included 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.
A one-time charge of $4.9 million ($2.9 million after-tax), or $.21 per
share, was recorded in the second quarter of 1998 to address errors in reporting
the results of prior years' activity in UI's subsidiary, American Payment
Systems, Inc. This is reflected in Other Income and (Deductions), Other-net. See
the Company's Form 8-K filing with the SEC, dated June 30, 1998, for a more
complete description of this event.
The one-time gain recorded in the third quarter of 1998 was to record a
refund of prior period transmission charges. It amounted to $3.4 million or $.14
per share, but was recorded as two separate items; $1.8 million, or a gain of
$.07 per share, as a credit to operation expense and $1.6 million, or $.07 per
share, of interest income recorded as Other Income and (Deductions), Other-net.
At the time this one-time item was recorded, in the third quarter of 1998, the
Company estimated that it would be in the Rate Plan "sharing" range of earnings
for the year of 1998 in total, and recorded, therefore, a "sharing" revenue
reduction and increased amortization expense to reflect that estimate. The
"sharing" related to the utility portion of this one-time item, the operation
expense credit, was a charge of $.05 per share. The net result of the one-time
gain for the period was, therefore, $.09 per share.
The one-time charge recorded in the fourth quarter of 1998 as property tax
expense of $14 million, or $.59 per share, reflected the DPUC's rejection of the
Company's proposed accounting treatment of a property tax settlement between the
Company and the City of New Haven. Upon that rejection, the Company was required
to write-off immediately the full effect of that settlement. As a result of this
one-time charge, the Company's final 1998 earnings results eliminated the
requirement to record any Rate Plan "sharing" in 1998. The one-time charge
eliminated "sharing" revenue reductions and increased amortization expense
amounting to $.29 per share. The net result of the one-time charge for the
period was, therefore, $.30 per share. See Note (L), Commitments and
Contingencies - Other Commitments and Contingencies - Property Taxes.
- 47 -
1997 VS. 1996
-------------
Earnings for the twelve months of 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 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:
o 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.
o 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.
o 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 and
the corresponding decrease in conservation revenues. 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. 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:
o 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.
- 48 -
o 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.
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.
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 and restructuring legislation
-------------------------------------------------
The reader is referred to "Major Influences on Financial Condition", above,
for a description of the Company's five-year Rate Plan and Connecticut's
electric utility industry restructuring legislation.
1999 Earnings
-------------
1999 will be a year of transition to the January 1, 2000 effective date of
electric utility restructuring legislation passed by the Connecticut legislature
in 1998. The Company has taken one major step toward restructuring by proceeding
with the sale of its fossil fuel generation plants...referred to as the
Generation Asset Divestiture (GAD). That sale is expected to close on or about
April 1, 1999.
One result of the generation plant sale will be a reduction in the
Company's electric utility rate base, the basis for measuring return on utility
common stock equity. Rate base is expected to decline from an average of $1,128
million in 1998 to about $920 million in 1999. Offsetting the decline is the
Company's longstanding policy of debt paydown that increases the portion of rate
base financed by equity. During 1998, a return of 11.5% on utility common stock
equity would have produced earnings of about $3.43 per share. Utility earnings
from operations above this range would have given rise to an imputed "sharing"
benefit of $.12 per share. Because of the rate base reduction expected in 1999,
the allowed return is expected to produce utility earnings in the $3.35-$3.40
per share range. Currently, the Company expects to be in a Rate Plan "sharing"
position in 1999, to a somewhat greater extent than was the case for earnings
from operations in 1998.
- 49 -
The Company's earnings from its utility business are affected principally
by: retail sales that fluctuate with weather conditions and economic activity,
nuclear generating unit availability and operating costs, and interest rates.
These are all items over which the Company has little control, although the
Company engages in economic development activities to increase sales, and hedges
its exposure to volatility in interest rates.
The Company's revenues are principally dependent on the level of retail
electricity sales. The two primary factors that affect the volume of these
retail sales are economic conditions and weather. The Company's retail sales for
1998 of 5,452 gigawatt-hours set an all-time record for the Company and were up
1.4% from the 1997 level.
The Company estimates that mild 1998 weather reduced retail kilowatt-hour
sales by about 0.5%, retail revenues by about $3.4 million, and retail sales
margin by about $2.7 million. Weather corrected retail sales for 1998 were
probably in the 5,470-5,500 gigawatt-hour range. On this weather-adjusted basis,
the Company experienced about 1.0-1.5% of "real" sales growth in 1998 over
weather-adjusted 1997 sales, with most of the growth appearing to occur in the
first three quarters of the year.
Aside from "real" economic growth, reductions in retail electricity sales
will occur in 1999 compared to 1998 as a result of the operation of a
cogeneration unit at Yale University that produces approximately one half of
Yale's annual electricity requirements (about 1.5% of the Company's total 1998
retail sales). This unit commenced operations in mid-1998, and has reduced total
Company retail kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The
remaining impact will be reflected in the first half of 1999. Thus, it would
require "real" growth of 0.5 percent in 1999 compared to 1998 just to maintain
the 1998 level of "real" sales. Retail kilowatt-hour sales growth of 1.0%
produces a margin improvement of about $5.0 million, before any "sharing" effect
considerations.
Prices in individual customer rate classes will not change in 1999 relative
to 1998, exclusive of any "sharing". However, sales growth is occurring in rate
classes with higher than average prices, and the Company expects to have an
increase in retail revenue of about $3.0 million in 1999 compared to 1998 from
this price mix improvement.
Other operating revenues are expected to increase as a result of NEPOOL
related transmission revenues by about $4.0 million due to NEPOOL restructuring
changes; but this would have no net income effect as the higher revenues are due
to higher transmission operating expense. Other than the NEPOOL impact, these
revenues are expected to decrease by about $2 million to a more normal level.
The Company does not anticipate, at this time, any other significant revenue
reductions in 1999 retail revenues compared to 1998, unless the Company is
achieving a "sharing" level of earnings.
As a result of GAD, wholesale capacity revenues will decrease by about $7.7
million in 1999 compared to 1998, because existing wholesale sales contracts
were part of the asset sale. Also as a result of GAD, the Company's fuel and
purchased energy charges will increase in 1999 compared to 1998 by about $40
million, to replace the power previously provided by the Company's fossil-fueled
generation plants. This power supply purchase agreement was part of the GAD
plant sale and it will help to ensure adequate resources to meet customer energy
demands under a short-term fixed price agreement until July 2000 (the price
declines somewhat in 2000 compared to 1999) when all customers will have a
choice of generation suppliers. The Company expects that its projected 1999
energy requirements that are not met by the GAD power supply purchase agreement
will be met at lower prices than those experienced in 1998, primarily because of
lower projected fossil fuel prices and energy prices in general. This is
expected to result in energy cost savings of about $5 million.
Purchased capacity costs should decrease by about $2 million in 1999, due
primarily to the retirement of the Connecticut Yankee nuclear generation plant.
Several other expense categories are expected to be reduced substantially
in 1999 because of GAD and the Company's other cost reduction efforts,
offsetting the impact of the increase in purchased energy. Operation and
maintenance expense is projected to decrease by a net $22 million, reflecting a
decrease of $32 million due to GAD and other general changes, partly offset by
increases of about $5 million for nuclear unit refueling outages, $1 million for
Y2K costs and $4 million due to NEPOOL transmission charges. The latter would
have no net income
- 50 -
effect, as the higher transmission expense would be covered by higher
transmission revenues. Total Y2K costs for 1999 are currently projected at about
$3.6 million. Other operation and maintenance expenses in 1999 should be fairly
stable compared to 1998, unless an event occurs that cannot be predicted at this
time.
Interest costs are expected to decline by about $14 million in 1999
compared to 1998, to about $38 million, a level that was last experienced in
1982. This anticipated interest cost reduction will result largely from debt
paydown through use of the after-tax cash proceeds from GAD. The Company also
expects to generate substantial cash flow from operations after dividend and
capital spending, that will also be used to pay down debt.
Depreciation, excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to GAD but also from the near
completion in 1998 of amortization of previously capitalized conservation
program expenditures. A significant portion of the decrease in depreciation
related to GAD will not affect taxable income and will not increase income
taxes, and will therefore supplement the $13 million decrease with an additional
tax benefit, comparing 1999 to 1998, of about $2.5 million, or $.18 per share.
Accelerated amortization, per the Rate Plan, will increase by about $7
million in 1999 compared to 1998. Property taxes should decrease by about $2
million, due mostly to GAD. Other operating expenses can be expected to have
some increases and some decreases that should, more or less, offset one another.
In summary, the Company expects substantial net expense reductions as a
result of GAD and ongoing cost control measures that should more than compensate
for increased charges for purchased power and increased accelerated amortization
costs in 1999. Such performance should allow utility earnings to increase above
an 11.5% return on common stock equity into the Rate Plan "sharing" range. The
11.5% return level would produce utility earnings from operations of about
$3.35-$3.40 per share, while the "shared" earnings benefit is currently
anticipated to contribute about $.20 per share, although the size of this
benefit will fluctuate with every event that affects utility operations during
the year. The Company expects that 1999 quarterly earnings from operations will
follow a pattern similar to that of 1998 on a weather-normalized basis.
Unregulated subsidiaries are expected to experience a loss of up to $.10
per share to earnings in 1999. American Payment Systems, Inc. is expected to
build on 1998's contribution to earnings from operations of $.07 per share.
However, this will depend on its ability to expand sales to its utility
customers. Precision Power, Inc. (PPI) increased its organizational
infrastructure in 1998, also in an effort to increase its presence in its
principal markets of distributed power systems and services. At its current
level of expense, PPI would lose $.10 to $.15 per share in 1999 if no
substantial new contracts are obtained. PPI may also engage in acquisition
activities in 1999 that may have short-term dilutive effects on earnings beyond
those indicated above.
As a result of the earnings contributions anticipated from all of its
different business activities described above, the Company expects earnings per
share from operations to be in the range of $3.45 to $3.65 in 1999. These
estimates are subject to all of the contingencies and uncertainties detailed in
the preceding discussion and the reader is cautioned to read the "Looking
Forward" and "Major Influences on Financial Condition" sections in their
entirety.
- 51 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
1998 1997 1996
---- ---- ----
OPERATING REVENUES (NOTE G) $686,191 $710,267 $726,020
------------- ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 151,544 182,666 160,517
Capacity purchased 34,515 39,976 46,830
Early retirement program charges - - 23,033
Other 146,058 158,600 158,945
Maintenance 42,888 42,203 37,652
Depreciation (Note G) 82,809 74,618 65,921
Amortization of cancelled nuclear project and deferred
return (Note D and J) 13,758 13,758 13,758
Income taxes (Note A and F) 53,619 41,333 53,090
Other taxes (Note G) 64,674 52,540 57,139
------------- ------------ ------------
Total 589,865 605,694 616,885
------------- ------------ ------------
OPERATING INCOME 96,326 104,573 109,135
------------- ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 13 336 940
Other-net (Note G) (3,803) 4,186 (7,166)
Non-operating income taxes 5,866 2,496 9,332
------------- ------------ ------------
Total 2,076 7,018 3,106
------------- ------------ ------------
INCOME BEFORE INTEREST CHARGES 98,402 111,591 112,241
------------- ------------ ------------
INTEREST CHARGES
Interest on long-term debt 50,129 63,063 66,305
Interest on Seabrook obligation bonds owned by the company (7,293) (6,905) (1,259)
Other interest (Note G) 6,507 3,280 2,092
Allowance for borrowed funds used during construction (455) (1,239) (1,435)
------------- ------------ ------------
48,888 58,199 65,703
Amortization of debt expense and redemption premiums 2,511 2,788 2,629
------------- ------------ ------------
Net Interest Charges 51,399 60,987 68,332
------------- ------------ ------------
MINORITY INTEREST IN PREFERRED SECURITIES 4,813 4,813 4,813
------------- ------------ ------------
NET INCOME 42,190 45,791 39,096
Discount on preferred stock redemptions (21) (48) (1,840)
Dividends on preferred stock 201 205 330
------------- ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $42,010 $45,634 $40,606
============= ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,018 13,976 14,101
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,023 13,992 14,131
EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.00 $3.27 $2.88
============= ============ ============
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.00 $3.26 $2.87
============= ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.88
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 52 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(THOUSANDS OF DOLLARS)
1998 1997 1996
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $42,190 $45,791 $39,096
------------ ------------ ------------
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 88,099 79,487 70,363
Deferred income taxes 1,056 7,986 (2,276)
Deferred investment tax credits - net (762) (762) (762)
Amortization of nuclear fuel 6,892 5,799 5,690
Allowance for funds used during construction (468) (1,575) (2,375)
Amortization of deferred return 12,586 12,586 12,586
Early retirement costs accrued - - 23,033
Changes in:
Accounts receivable - net (6,505) 16,944 (23,555)
Fuel, materials and supplies (14,466) 2,863 239
Prepayments (4,027) 211 (557)
Accounts payable (15,259) 641 22,657
Interest accrued (63) (3,569) (671)
Taxes accrued 4,849 3,663 (4,794)
Other assets and liabilities (4,062) (1,644) 6,078
------------ ------------ ------------
Total Adjustments 67,870 122,630 105,656
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 110,060 168,421 144,752
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 4,923 (6,432) 40
Long-term debt 199,636 98,500 82,500
Notes payable 49,141 26,786 10,965
Securities redeemed and retired:
Preferred stock (52) (110) (6,078)
Long-term debt (222,348) (151,199) (72,895)
Discount on preferred stock redemption 21 48 1,840
Expenses of issues (1,600) (1,500) (442)
Lease obligations (339) (315) (291)
Dividends
Preferred stock (202) (206) (410)
Common stock (40,285) (40,408) (40,399)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (11,105) (74,836) (25,170)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (38,040) (33,436) (47,174)
Investment in Seabrook obligation bonds 8,528 (34,541) (71,084)
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (29,512) (67,977) (118,258)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD 69,443 25,608 1,324
BALANCE AT BEGINNING OF PERIOD 32,002 6,394 5,070
------------ ------------ ------------
BALANCE AT END OF PERIOD $101,445 $32,002 $6,394
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $51,481 $59,441 $69,669
============ ============ ============
Income taxes $42,450 $26,773 $51,415
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 53 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1998, 1997 AND 1996
ASSETS
(Thousands of Dollars)
1998 1997 1996
---- ---- ----
Utility Plant at Original Cost
In service $1,886,930 $1,867,145 $1,843,952
Less, accumulated provision for depreciation 714,375 644,971 585,646
---------------- -------------- --------------
1,172,555 1,222,174 1,258,306
Construction work in progress 33,695 25,448 40,998
Nuclear fuel 20,174 25,990 23,010
---------------- -------------- --------------
Net Utility Plant 1,226,424 1,273,612 1,322,314
---------------- -------------- --------------
Other Property and Investments 37,873 32,451 26,081
---------------- -------------- --------------
Current Assets
Cash and temporary cash investments 101,445 32,002 6,394
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800, $1,800 and $2,300 54,178 57,231 63,722
Other 37,472 27,914 38,367
Accrued utility revenues 21,079 25,269 29,139
Fuel, materials and supplies, at average cost 33,613 19,147 22,010
Prepayments 7,424 3,397 3,608
Other 154 67 110
---------------- -------------- --------------
Total 255,365 165,027 163,350
---------------- -------------- --------------
Deferred Charges
Unamortized debt issuance expenses 9,421 6,611 6,580
Other 1,664 5,727 1,485
---------------- -------------- --------------
Total 11,085 12,338 8,065
---------------- -------------- --------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax
differences (Note A) 264,811 277,350 289,672
Connecticut Yankee 42,633 51,313 64,851
Deferred return - Seabrook Unit 1 12,586 25,171 37,757
Unamortized redemption costs 23,468 23,027 25,063
Unamortized cancelled nuclear project 10,952 12,125 13,297
Uranium enrichment decommissioning costs 1,177 1,312 1,377
Other 4,962 6,357 9,068
---------------- -------------- --------------
Total 360,589 396,655 441,085
---------------- -------------- --------------
$1,891,336 $1,880,083 $1,960,895
================ ============== ==============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 54 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1998, 1997 AND 1996
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1998 1997 1996
---- ---- ----
Capitalization (Note B)
Common stock equity
Common stock $292,006 $288,730 $284,579
Paid-in capital 2,046 1,349 772
Capital stock expense (2,182) (2,182) (2,182)
Unearned employee stock ownership plan equity (10,210) (11,160) -
Retained earnings 163,847 162,226 156,847
---------------- -------------- --------------
445,507 438,963 440,016
Preferred stock 4,299 4,351 4,461
Minority interest in preferred securities 50,000 50,000 50,000
Long-term debt
Long-term debt 757,370 746,058 826,527
Investment in Seabrook obligation bonds (92,860) (101,388) (66,847)
---------------- -------------- --------------
Net long-term debt 664,510 644,670 759,680
Total 1,164,316 1,137,984 1,254,157
---------------- -------------- --------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 32,711 40,821 54,752
Pensions accrued (Note H) 31,097 39,149 49,205
Nuclear decommissioning obligation 23,045 17,538 12,851
Obligations under capital leases 16,506 16,853 17,193
Other 6,622 5,507 4,815
---------------- -------------- --------------
Total 109,981 119,868 138,816
---------------- -------------- --------------
Current Liabilities
Current portion of long-term debt 66,202 100,000 69,900
Notes payable 86,892 37,751 10,965
Accounts payable 53,440 68,699 68,058
Dividends payable 10,155 10,051 10,205
Taxes accrued 9,015 4,166 503
Interest accrued 10,203 10,266 13,835
Obligations under capital leases 348 340 315
Other accrued liabilities 39,845 37,471 36,091
---------------- -------------- --------------
Total 276,100 268,744 209,872
---------------- -------------- --------------
Customers' Advances for Construction 1,867 1,878 1,888
---------------- -------------- --------------
Regulatory Liabilitie (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,623 16,385 17,147
Other 2,065 2,356 1,811
---------------- -------------- --------------
Total 17,688 18,741 18,958
---------------- -------------- --------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities) 321,384 332,868 337,204
Commitments and Contingencies (Note L)
---------------- -------------- --------------
$1,891,336 $1,880,083 $1,960,895
================ ============== ==============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 55 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(THOUSANDS OF DOLLARS)
1998 1997 1996
---- ---- ----
BALANCE, JANUARY 1 $162,226 $156,847 $156,877
Net income 42,190 45,791 39,096
Adjustments associated with repurchase
of preferred stock 21 48 1,815
------------ ------------ ------------
Total 204,437 202,686 197,788
------------ ------------ ------------
Deduct Cash Dividends Declared
Preferred stock 201 205 330
Common stock 40,389 40,255 40,611
------------ ------------ ------------
Total 40,590 40,460 40,941
------------ ------------ ------------
BALANCE, DECEMBER 31 $163,847 $162,226 $156,847
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 56 -
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 $32.25 million in the unregulated subsidiaries, and, at February 28, 1999,
$30 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.
- 57 -
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. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. If the Company, or a portion of its assets or
operations, were to cease meeting these criteria, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met. If 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, 1998, 1997 and
1996 was comprised as follows:
1998 1997 1996
---- ---- ----
(000's)
Production $1,133,984 $1,131,285 $1,124,113
Transmission 161,643 161,288 160,970
Distribution 408,845 401,426 387,825
General 56,264 52,776 47,889
Future use plant 30,505 30,594 32,751
Other 95,689 89,776 90,404
------- ------- -------
$1,886,930 $1,867,145 $1,843,952
========== ========== ==========
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 1998, 1997 and 1996 were 7.0%, 7.5% and 9.0%,
respectively.
- 58 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
DEPRECIATION
Provisions for depreciation on utility plant for book purposes are computed
on a straight-line basis, using estimated service lives determined by
independent engineers. One-half year's depreciation is taken in the year of
addition and disposition of utility plant, except in the case of major operating
units on which depreciation commences in the month they are placed in service
and ceases in the month they are removed from service. The aggregate annual
provisions for depreciation for the years 1998, 1997 and 1996 were equivalent to
approximately 3.26%, 3.15% and 3.12%, 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 $3.8 million, $2.3 million and $3.4 million, at December 31, 1998,
1997 and 1996, 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 $9.9 million,
$10.5 million and $10.1 million at December 31, 1998, 1997 and 1996,
respectively, and is included on the Consolidated Balance Sheet as a regulatory
asset. See Note (L), Commitments and Contingencies - Other Commitments and
Contingencies - Connecticut Yankee.
- 59 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 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 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.
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, 1998, the
Company's unfunded share of the obligation, based on its ownership interest in
Seabrook Unit 1 and Millstone Unit 3, was approximately $1.1 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.
- 60 -
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 $2,580,000, $2,571,000 and $2,130,000
during 1998, 1997 and 1996 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1998, the Company's shares of the
trust fund balances, which included accumulated earnings on the funds, were
$16.5 million and $6.5 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 $33.7 million, $31.7 million and $19.2 million
for the years 1998, 1997 and 1996, 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
The following table presents a reconciliation of the numerators and
denominators of the basic and diluted earnings per share calculations for the
years 1998, 1997 and 1996:
- 61 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
(In thousands except per share amounts)
Income Applicable to Average Number of
Common Stock Shares Outstanding Earnings
(Numerator) (Denominator) per Share
-------------------- ------------------ ---------
1998
----
Basic earnings per share $42,010 14,018 $3.00
Effect of dilutive stock options - 5 (.00)
------ ------ -----
Diluted earnings per share $42,010 14,023 $3.00
======= ====== =====
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
======= ====== =====
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, 1998, 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 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". This statement,
which is effective for fiscal quarters of fiscal years beginning after June 15,
1999, establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires entities to recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The accounting for the changes in the fair
value of a derivative (gains and losses) would depend on the intended use and
designation of the derivative. The Company currently does not anticipate
utilizing derivative instruments of the type defined in this statement, on or
after the effective date of this statement.
- 62 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(B) CAPITALIZATION
December 31,
--------------------------------------------------------------------------------------
1998 1997 1996
Shares Shares Shares
Outstanding $(000's) Outstanding $(000's) Outstanding $(000's)
------------- ----------- ------------- ----------- ------------- ------------
COMMON STOCK EQUITY
Common stock, no par value,
at December 31(a) 14,034,562 $292,006 13,907,824 $288,730 14,101,291 $284,579
Shares authorized
1996 30,000,000
1997 30,000,000
1998 30,000,000
Paid-in capital 2,046 1,349 772
Capital stock expense (2,182) (2,182) (2,182)
Unearned employee stock ownership plan equity (10,210) (11,160) -
Retained earnings (b) 163,847 162,226 156,847
----------- ----------- ------------
Total common stock equity 445,507 438,963 440,016
----------- ----------- ------------
PREFERRED AND PREFERENCE STOCK (c)
Cumulative preferred stock,
$100 par value, shares
authorized at December 31,
1996 1,119,612
1997 1,119,612
1998 1,119,612
Preferred stock issues:
4.35% Series A 10,370 10,894 11,297
4.72% Series B 17,158 17,158 17,658
4.64% Series C 12,745 12,745 12,945
5 5/8% Series D 2,712 2,712 2,712
------------- ------------- -------------
42,985 4,299 43,509 4,351 44,612 4,461
------------- ----------- ------------- ----------- ------------- ------------
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 4,299 4,351 4,461
----------- ----------- ------------
MINORITY INTEREST IN PREFERRED SECURITIES (d) 50,000 50,000 50,000
----------- ----------- ------------
- 63 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
December 31,
--------------------------------------------------
1998 1997 1996
$(000's) $(000's) $(000's)
-------------- -------------- --------------
LONG-TERM DEBT (e)
First Mortgage Bonds:
9.44%, Series B - - $32,400
Other Long-term Debt
Pollution Control Revenue Bonds:
Variable rate, 1996 Series, due June 26, 2026 7,500 7,500 7,500
9 3/8%, 1987 Series, due July 1, 2012 - - 25,000
10 3/4%, 1987 Series, due November 1, 2012 - - 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
Pollution Control Refunding Revenue Bonds:
Variable rate, 1997 Series, due July 30, 2027 98,500 98,500 -
Notes:
7 3/8%, 1992 Series G, due January 15, 1998 - 100,000 100,000
6.20%, 1993 Series H, due January 15, 1999 66,202 100,000 100,000
6.25%, 1998 Series I, due December 15, 2002 100,000 - -
6.00%, 1998 Series J, due December 15, 2003 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
6.4375%, due September 6, 2000 20,000 50,000 50,000
6.675%, due October 25, 2001 25,000 25,000 25,000
7.005% due October 25, 2001 50,000 50,000 50,000
Obligation under the Seabrook Unit 1
sale/leaseback agreement 217,230 225,601 243,660
-------------- -------------- --------------
823,892 846,061 896,520
Unamortized debt discount less premium (320) (3) (93)
-------------- -------------- --------------
Total long-term debt 823,572 846,058 896,427
Less:
Current portion included in Current Liabilities (e) 66,202 100,000 69,900
Investment-Seabrook Lease Obligation Bonds 92,860 101,388 66,847
-------------- -------------- --------------
Total long-term debt included in Capitalization 664,510 644,670 759,680
-------------- -------------- --------------
TOTAL CAPITALIZATION $1,164,316 $1,137,984 $1,254,157
============== ============== ==============
- 64 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(a) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at December 31, 1998, of which 300,360 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 98,798 shares of common stock in 1998, 134,833 shares of
common stock in 1997 and 1,200 shares of common stock in 1996, pursuant to a
stock option plan.
In 1990, the Company's Board of Directors and the shareowners approved a
stock option plan for officers and key employees of the Company. The plan
provides for the awarding of options to purchase up to 750,000 shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date of the grant. Options to purchase 3,500 shares of
stock at an exercise price of $30 per share, 7,800 shares of stock at an
exercise price of $39.5625 per share, and 5,000 shares of stock at an exercise
price of $42.375 per share have been granted by the Board of Directors and
remained outstanding at December 31, 1998. Options to purchase 14,299 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, and 25,999 shares of stock at an exercise price of
$39.5625 per share were exercised during 1998.
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, 1998 and 1997, 300,360 shares and 328,300 shares,
with a fair market value of $15.5 million and $15.1 million, respectively, 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 $266.2 million principal amount of Notes are
issued places limitations on the payment of cash dividends on common stock and
on the purchase or redemption of common stock. Retained earnings in the amount
of $105.7 million were free from such limitations at December 31, 1998.
(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 April 1998, the Company purchased at a discount on the open market, and
canceled, 524 shares of its $100 par value 4.35%, Series A preferred stock. The
shares, having a par value of $52,400 were purchased for $31,440, creating a net
gain of $20,960.
Shares of preferred stock have preferential dividend and liquidation rights
over shares of common stock. Preferred shareholders are not entitled to general
voting rights. However, if any preferred dividends are in arrears for six or
more quarters, or if certain other events of default occurs, preferred
shareholders are entitled to elect a majority of the Board of Directors until
all preferred dividend arrearages are paid and any event of default is
terminated.
- 65 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
1998.
(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 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.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
On June 8, 1998, the Company repaid a $50 million Term Loan prior to its
August 29, 2000 due date. On June 8, 1998, the Company also repaid $30 million
of a $50 million Term Loan prior to its due date of September 6, 2000.
On December 18, 1998, the Company issued and sold $100 million principal
amount of 6% five-year Notes. The yield on the Notes, which were issued at a
discount, is 6.034%; and the Notes will mature on December 15, 2003. The
proceeds from the sale of the Notes were used to repay $66.2 million principal
amount of 6.2% Notes, which matured on January 15, 1999, and for general
corporate purposes.
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and will be paid semi-annually beginning on
August 1, 1999. In addition, on February 1, 1999, the Company converted $98.5
million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds will
be paid semi-annually beginning on August 1, 1999.
- 66 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Maturities and mandatory redemptions/repayments are set forth below:
[Enlarge/Download Table]
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(000's)
Maturities $66,202 $70,000 $75,000 $100,000 $100,000
Mandatory redemptions/repayments (1) 3,410 430 333 338 485
------ ------ ------ ------- -------
Maturities and Mandatory
redemptions/repayments $69,612 $70,430 $75,333 $100,338 $100,485
====== ====== ====== ======= ========
(1) Principal component of Seabrook lease obligation, net of principal
repayment of Seabrook Lease Obligation Bonds held as an investment.
(C) RATE-RELATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. Beginning in 2000, each retail consumer of electricity
in Connecticut (excluding consumers served by municipal electric systems) will
be able to choose his, her or its supplier of electricity from among competing
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the charge for electricity
generation services from the charge for delivering the electricity and all other
charges. On July 29, 1998, the DPUC issued the first of what are expected to be
several orders relative to this "unbundling" requirement, and has now reopened
its proceeding to consider the amount of the generation services charge to be
included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to certain adjustments, at least 10%
below its fully bundled prices for electricity at rates in effect on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments, to be the total rate charged under the standard offer, including
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment charge.
- 67 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin.
The sale price is $272 million in cash, including payment for some non-plant
items, and the transaction is expected to close during the spring of 1999. It is
contingent upon the receipt of approvals from the DPUC, the Federal Energy
Regulatory Commission (FERC), and other federal and state agencies. A petition
seeking the DPUC's approval was filed on October 30, 1998 and, on March 5, 1999,
the DPUC issued a decision approving the sale. An application seeking the FERC's
authorization for the sale of the facilities subject to its jurisdiction was
filed on December 21, 1998 and, on February 24, 1999, the FERC issued an order
authorizing the sale.
The Company will realize a book gain from the sale proceeds net of taxes
and plant investment. However, this gain will be offset by a writedown of other
above-market generation costs eligible for the competitive transition
assessment, such as regulated plant costs and tax-related regulatory assets or
other costs related to the restructuring transition, such that there will be no
net income effect of the sale. The Company anticipates using the net cash
proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the Company proposed to
satisfy, on a functional basis, the Restructuring Act's requirement that nuclear
generating assets be separated from its transmission and distribution assets.
This would be accomplished by transferring the nuclear generating assets into a
separate new division of the Company, using divisional financial statements and
accounting to segregate all revenues, expenses, assets and liabilities
associated with nuclear ownership interests.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not
- 68 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
choose an alternate power supply provider, even though the Company will no
longer be in the business of retail power generation. In order to mitigate the
financial risk that these regulated service mandates will pose to the Company in
an unregulated power generation environment, its unbundling plan proposes that a
purchased power adjustment clause be added to its regulated rates, effective
July 1, 2000, as permitted by the Restructuring Act. This clause, similar to and
based on the purchased gas adjustment clauses used by Connecticut's natural gas
local distribution companies, would work in tandem with the Company's
procurement of power supplies to assure that "standard offer" customers pay
competitive market rates for power supply services and that the Company collects
its costs of providing such services. The Distribution Company is also required
under the Restructuring Act to provide back-up power supply service to customers
whose electric supplier fails to provide power supply services for reasons other
than the customers' failure to pay for such services. The Restructuring Act
provides for the Distribution Company to recover its reasonable costs of
providing this back-up service.
In addition to approval by the DPUC, the several features of the Company's
unbundling plan will be subject to approvals and consents by federal regulators,
other state and federal agencies, and the Company's common stock shareowners.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order (see below) anticipated
sufficient income in 2000 to accelerate amortization of regulatory assets of
about $50 million, equivalent to about 8% of retail revenues. Substantially all
of this accelerated amortization may have to be eliminated to allow for the
additional standard offer price reduction requirement of 10%, at a minimum,
while providing for the added costs imposed by the restructuring legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers; but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of regulatory assets, and one-third retained as earnings. As a
result of the Rate Plan, customer prices were required to be reduced, on
average, by 3% in 1997 compared to 1996. Also as a result of the Rate Plan,
customer prices are required to be reduced by an additional 1% in 2000, and
another 1% in 2001, compared to 1996. Retail revenues have decreased by
approximately 4.8% through 1998 compared to 1996 due to customer price
reductions. The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998
- 69 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Restructuring Act described above, the Rate Plan may be reopened and modified.
However, aside from implementing an additional price reduction in 2000 to
achieve the minimum 10% price reduction required by the Restructuring Act and
the probable reductions in the accelerated amortizations scheduled in the Rate
Plan, the Company is unable to predict, at this time, in what other respects the
Rate Plan may be modified on account of this legislation.
(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, which
currently extends to December 8, 1999. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
December 31, 1998, the Company had no short-term borrowings outstanding under
this facility.
On June 8, 1998, the Company borrowed $80 million under a new revolving
credit agreement with a group of banks. The funds were used to repay $80 million
of Term Loans prior to their due dates. The borrowing limit of this facility,
which extends to June 7, 1999, is $80 million. The facility permits the Company
to borrow funds at a fluctuating interest rate determined by the prime lending
market in New York, and also permits the Company to borrow money for fixed
periods of time specified by the Company at fixed interest rates determined by
the Eurodollar interbank market in London. If a material adverse change in the
business, operations, affairs, assets or condition, financial or otherwise, or
prospects of the Company and its subsidiaries, on a consolidated basis, should
occur, the banks may decline to lend additional money to the Company under this
revolving credit agreement, although borrowings outstanding at the time of such
an occurrence would not then become due and payable. As of December 31, 1998,
the Company had $80 million of short-term borrowings outstanding under this
facility.
In addition, as of December 31, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $6.8 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,
1998, this coverage ratio was 3.6:1.0.
- 70 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Information with respect to short-term borrowings under the Company's
revolving credit agreements is as follows:
[Enlarge/Download Table]
1998 1997 1996
---- ---- ----
(000's)
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $130,000 $50,000 $30,000
Average aggregate short-term borrowings outstanding during the year* $115,753 $41,441 $15,380
Weighted average interest rate* 6.1% 5.9% 5.7%
Principal amounts outstanding at year-end $80,000 $30,000 $0
Annualized interest rate on principal amounts outstanding at year-end 5.7% 6.2% 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 $381,000, $114,000 and $130,000 paid during 1998, 1997 and
1996, respectively, are excluded from the calculation of the weighted average
interest rate.
- 71 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
1998 1997 1996
---- ---- ----
Income tax expense consists of: (000's)
Income tax provisions:
Current
Federal $36,774 $23,940 $35,398
State 10,685 7,673 11,398
------------ ------------ ------------
Total current 47,459 31,613 46,796
------------ ------------ ------------
Deferred
Federal 1,412 7,008 616
State (356) 978 (2,892)
------------ ------------ ------------
Total deferred 1,056 7,986 (2,276)
------------ ------------ ------------
Investment tax credits (762) (762) (762)
------------ ------------ ------------
Total income tax expense $47,753 $38,837 $43,758
============ ============ ============
Income tax components charged as follows:
Operating expenses $53,619 $41,333 $53,090
Other income and deductions - net (5,866) (2,496) (9,332)
------------ ------------ ------------
Total income tax expense $47,753 $38,837 $43,758
============ ============ ============
The following table details the components
of the deferred income taxes:
Tax depreciation on unrecoverable plant investment $6,291 $8,089 $5,745
Fossil plants decommissioning reserve (329) (7,286) -
Conservation & load management (8,026) (5,768) (367)
Accelerated depreciation 5,449 5,681 5,617
Pension benefits 3,463 4,911 (9,066)
Seabrook sale/leaseback transaction 304 2,664 (598)
Deferred fossil fuel costs - (686) 755
Cancelled nuclear project (467) (467) (4,729)
Unit overhaul and replacement power costs (1,157) 212 (1,491)
Other - net (4,472) 636 1,858
------------ ------------ ------------
Deferred income taxes - net $1,056 $7,986 ($2,276)
============ ============ ============
- 72 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
[Enlarge/Download Table]
1998 1997 1996
---- ---- ----
PRE-TAX TAX PRE-TAX TAX PRE-TAX TAX
------- --- ------- --- ------- ---
(000's)
Computed tax at federal statutory rate $31,480 $29,619 $28,999
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 (13) (5) (336) (118) (940) (329)
Fossil plant decommissioning reserve (723) (253) (15,591) (5,457) - -
Book depreciation in excess of
non-normalized tax depreciation 22,789 7,976 23,926 8,374 22,703 7,946
State income taxes, net of federal
income tax benefits 10,329 6,714 8,651 5,622 8,506 5,529
Other items - net (5,149) (1,802) (8,134) (2,846) (5,797) (2,030)
------- ------- -------
Total income tax expense $47,753 $38,837 $43,758
======= ======= =======
Book income before income taxes $89,943 $84,628 $82,854
======= ======= =======
Effective income tax rates 53.1% 45.9% 52.8%
===== ===== =====
At December 31, 1998 the Company had deferred tax liabilities for taxable
temporary differences of $430 million and deferred tax assets for deductible
temporary differences of $109 million, resulting in a net deferred tax liability
of $321 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, $282 million; tax liabilities on normalization of
book/tax depreciation timing differences, $127 million and tax assets on the
disallowance of plant costs, $41 million.
The Company has reflected on its Consolidated Balance Sheet as of December
31, 1997 an additional amount of deferred tax liabilities associated with plant
book/tax basis differences. An offsetting regulatory asset, representing the
future amounts to be collected from customers for the recovery of the tax
expense associated with these additional tax liabilities, has also been
reflected.
- 73 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(G) SUPPLEMENTARY INFORMATION
1998 1997 1996
----- ----- ----
(000's)
OPERATING REVENUES
------------------
Retail $631,607 $623,571 $649,876
Wholesale - capacity 11,524 9,747 7,686
- energy 33,424 73,124 65,158
Other 9,636 3,825 3,300
------------- ------------ ------------
Total Operating Revenues $686,191 $710,267 $726,020
============= ============ ============
SALES BY CLASS(MWH'S) - UNAUDITED
---------------------------------
Retail
Residential 1,924,724 1,903,096 1,891,988
Commercial 2,324,507 2,253,488 2,258,501
Industrial 1,154,935 1,170,815 1,141,109
Other 48,166 48,717 48,291
------------- ------------ ------------
5,452,332 5,376,116 5,339,889
Wholesale 1,551,109 2,700,393 2,260,423
------------- ------------ ------------
Total Sales by Class 7,003,441 8,076,509 7,600,312
============= ============ ============
DEPRECIATION
------------
Plant in service $67,143 $65,585 $63,618
Accelerated conservation and load management 13,086 6,636 -
Nuclear decommissioning 2,580 2,397 2,303
------------- ------------ ------------
$82,809 $74,618 $65,921
============= ============ ============
OTHER TAXES
-----------
Charged to:
Operating:
State gross earnings $24,039 $23,618 $26,757
Local real estate and personal property (1) 35,088 22,974 24,854
Payroll taxes 5,547 5,948 5,528
------------- ------------ ------------
64,674 52,540 57,139
Nonoperating and other accounts 510 459 628
------------- ------------ ------------
Total Other Taxes $65,184 $52,999 $57,767
============= ============ ============
(1) 1998 includes $14,025 charge for property tax settlement.
OTHER INCOME AND (DEDUCTIONS) - NET
-----------------------------------
Interest income $3,181 $2,317 $1,505
Equity earnings from Connecticut Yankee 854 1,343 1,225
Loss from subsidiary companies (2) (6,648) (814) (8,422)
Miscellaneous other income and (deductions) - net (1,190) 1,340 (1,474)
------------- ------------ ------------
Total Other Income and (Deductions) - net ($3,803) $4,186 ($7,166)
============= ============ ============
(2) Includes before-tax non-recurring charges in 1998
and 1996 of $4,900 and $4,471, respectively.
OTHER INTEREST CHARGES
----------------------
Notes Payable $5,050 $2,462 $882
Other 1,457 818 1,210
------------- ------------ ------------
Total Other Interest Charges $6,507 $3,280 $2,092
============= ============ ============
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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 1998, 1997 and
1996 were $(5,138,000), ($4,626,000) and $18,403,000, 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 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. In 1998, the
Company contributed $2.6 million for 1998 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.
1998 1997
---- ----
(000's)
The components of net pension costs were as follows:
Service cost of benefits earned during the period $4,389 $ 3,791
Interest cost on projected benefit obligation 17,828 17,565
Expected return on plan assets (25,934) (22,293)
Amortization of:
Prior service cost 406 406
Transition obligation (asset) (1,095) (1,065)
Actuarial (gain) loss (1,132) (498)
Settlements (curtailments) 400 (2,724)
Other amortization and deferrals-net - 192
----- -----
Net pension cost $(5,138) $(4,626)
====== ======
Assumptions used to determine pension costs were:
Discount rate 7.25% 7.75%
Average wage increase 4.50% 4.50%
Return on plan assets 11.00% 11.00%
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
1998 1997
---- ----
(000's)
The pension benefit obligations and plan assets as of December 31:
Change in Projected Pension Benefit Obligation:
Pension Benefit Obligation - January 1 $259,545 $232,783
Service cost 4,389 3,791
Interest cost 17,828 17,565
Curtailments/settlements - (3,193)
Actuarial (gain) loss 14,064 21,656
Benefits paid (15,080) (13,057)
-------- --------
Pension Benefit Obligation - December 31 $280,746 $259,545
======= =======
Change in Plan Assets:
Fair Value of Plan Assets - January 1 $243,739 $208,863
Actual return on plan assets 38,224 43,225
Employer contributions 2,914 5,429
Benefits paid (including expenses) (16,193) (13,778)
-------- --------
Fair Value of Plan Assets - December 31 $268,684 $243,739
======= =======
Funded Status:
Projected benefits greater than plan assets $12,062 $15,806
Unrecognized prior service cost (3,878) (4,285)
Unrecognized net gain (loss) from past experience 15,639 19,259
Unrecognized transition asset 7,274 8,369
------ ------
Accrued pension liability $31,097 $39,149
====== ======
Assumptions used in estimating benefit obligations at December 31:
Discount rate 6.75% 7.25%
Average wage increase 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. Approximately
44% 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 non-union retirees, allocated in a
manner that minimizes current income tax liability, without exceeding maximum
tax deductible limits. In accordance with this policy, the Company contributed
approximately $0, $0 and $3.8 million to the union VEBA in 1998, 1997 and 1996,
respectively. The Company contributed $0.9 million, $1.7 million and $0.9
million to the 401(h) account in 1998, 1997 and 1996,
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
respectively. Plan assets for both the union VEBA and 401(h) account consist
primarily of equity and fixed-income securities.
The components of the net cost of OPEB were as follows:
1998 1997
---- ----
(000's)
Service cost $1,078 $ 925
Interest cost 2,576 2,434
Expected return on plan assets (2,249) (1,787)
Amortization of:
Prior service cost (71) (86)
Transition obligation (asset) 1,169 1,906
Actuarial (gain) loss (361) (648)
Settlements (curtailments) - (186)
Other amortization and deferrals-net - 492
--- ----
Net Cost of Postretirement Benefit $2,142 $3,050
===== =====
Assumptions used to determine OPEB costs were:
Discount rate 7.25% 7.75%
Health Care Cost Trend Rate 5.50% 5.50%
Return on plan assets 11.00% 11.00%
A one percentage point change in the assumed health care cost trend rate would
have the following effects:
1% Increase 1% Decrease
----------- -----------
(000's)
Aggregate service and interest cost components $463 $(372)
Accumulated postretirement benefit obligation $4,246 $(3,498)
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
1998 1997
---- ----
(000's)
The postretirement benefit obligations and plan assets as of December 31:
Change in Projected Postretirement Benefit Obligation:
Postretirement Benefit Obligation - January 1 $35,112 $36,220
Service cost 1,078 925
Interest cost 2,576 2,434
Amendments - (409)
Curtailments/settlements - 204
Actuarial (gain) loss 4,002 (1,923)
Benefits paid (2,539) (2,339)
------- -------
Postretirement Benefit Obligation - December 31 $40,229 $35,112
====== ======
Change in Plan Assets:
Fair Value of Plan Assets - January 1 $21,168 $16,720
Actual return on plan assets 2,491 3,836
Employer contributions 910 1,737
Benefits paid (including expenses) (1,366) (1,125)
------- -------
Fair Value of Plan Assets - December 31 $23,203 $21,168
====== ======
Funded Status:
Projected benefits greater than plan assets $17,026 $13,944
Unrecognized prior service cost 946 1,017
Unrecognized net gain (loss) from past experience 1,241 5,363
Unrecognized transition asset (16,368) (17,537)
------- ---------
Accrued Postretirement liability $ 2,845 $ 2,787
====== ======
Assumptions used in estimating benefit obligations at December 31:
Discount rate 6.75% 7.25%
Average wage increase 4.50% 4.50%
The Company has an Employee Savings Plan (401(k) Plan) in which
substantially all employees are eligible to participate. The 401(k) Plan enables
employees to defer receipt of up to 15% of their compensation and to invest such
funds in a number of investment alternatives. The Company makes matching
contributions in the form of Company common stock for each employee. During 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 contribution to the
401(k) Plan during the first five months of 1996 was $0.8 million. 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 1998,
1997 and the period June 1996 - December 1996 were $1.7 million, $1.7 million
and $0.8 million, respectively.
- 78 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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
Company also makes contributions to the ESOP equal to 25% of the dividends paid
to each participant. The Company's annual contributions during 1998, 1997 and
1996 were $270,000, $417,000 and $324,000, respectively.
(I) JOINTLY OWNED PLANT
At December 31, 1998, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT IN ACCUMULATED
SHARE SERVICE DEPRECIATION
---------- -------- ------------
(Millions)
Seabrook Unit 1 17.5 % $648 $146
Millstone Unit 3 3.685 135 63
New Haven Harbor Station 93.7 143 78
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.
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases.
Under this agreement, the financing entity may acquire and/or store natural gas,
coal and fuel oil for sale to the Company, and the Company may purchase these
fossil fuels from the financing entity at a price for each type of fuel that
reimburses the financing entity for the direct costs it has incurred in
purchasing and storing the fuel, plus a charge for maintaining an inventory of
the fuel determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to March 2000. At December 31, 1998, no 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, 1998 are recorded on the balance sheet.
- 79 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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)
1999 $ 1,696
2000 1,696
2001 1,696
2002 1,696
2003 1,696
After 2003 16,000
--------
Total minimum capital lease payments 24,480
Less: Amount representing interest 7,626
--------
Present value of minimum capital lease payments $16,854
========
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)
1999 $ 6,426
2000 6,524
2001 6,837
2002 8,168
2003 9,125
2004-2012 91,209
--------
Total $128,289
Rental payments charged to operating expenses in 1998, 1997 and 1996,
including rental payments for its corporate headquarters, were $11.7 million,
$12.2 million and $12.8 million, respectively.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $130.8 million, excluding AFUDC, for 1999 through 2003.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
- 80 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the three nuclear generating
units in which the Company has an interest, the Company will be obligated to pay
its ownership and/or leasehold share of any statutory assessment resulting from
a nuclear incident at any nuclear generating unit. Based on its interests in
these nuclear generating units, the Company estimates its maximum liability
would be $17.8 million per incident. However, any assessment would be limited to
$2.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$3.1 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee.
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from UI. In December of 1996,
Connecticut Yankee filed decommissioning cost estimates and amendments to the
power contracts with its owners with the Federal Energy Regulatory Commission
(FERC). Based on regulatory precedent, this filing seeks confirmation that
Connecticut Yankee will continue to collect from its owners its decommissioning
costs, the unrecovered investment in the Connecticut Yankee Unit and other costs
associated with the permanent shutdown of the Connecticut Yankee Unit. On August
31, 1998, a FERC Administrative Law Judge (ALJ) released an initial decision
regarding Connecticut Yankee's December 1996 filing. The initial decision
contains provisions that would allow Connecticut Yankee to recover, through the
power contracts with its owners, the balance of its net unamortized investment
in the Connecticut Yankee Unit, but would disallow recovery of a portion of the
return on Connecticut Yankee's investment in the unit. The ALJ's decision also
states that decommissioning cost collections by Connecticut Yankee, through the
power contracts, should continue to be based on a previously-approved estimate
until a new, more reliable estimate has been prepared and tested. During October
of 1998, Connecticut Yankee and its owners filed briefs setting forth exceptions
to the ALJ's initial decision. If this initial decision is upheld by the FERC,
Connecticut Yankee could be required to write off a portion of the regulatory
asset on its Balance Sheet associated with the retirement of the Connecticut
Yankee Unit. In this event, however, the Company would not be required to record
any write-off on account of its 9.5% ownership share in Connecticut Yankee,
because the Company has recorded its regulatory asset associated with the
retirement of the Connecticut Yankee Unit net of any return on investment. The
Company cannot predict, at this time, the outcome
- 81 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
of the FERC proceeding. However, the Company will continue to support
Connecticut Yankee's efforts to contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $9.9
million) and return on investment (approximately $4.7 million) at December 31,
1998, is approximately $32.7 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
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, 1998, the Company's
guarantee liability for this debt was approximately $6.8 million.
PROPERTY TAXES
The City of New Haven (the City) and the Company have been involved in a
dispute over the amount of personal property taxes owed to the City for tax
years beginning with 1991-1992. On May 8, 1998, the City and the Company reached
a comprehensive settlement of all of the Company's contested personal property
tax assessments and tax bills for the tax years 1991-1992 through 1997-1998 and
the Company's personal property tax assessments for the tax year 1998-1999 and
subsequent years. Under the terms of this settlement, the Company agreed to pay
the City $14.025 million, subject to Connecticut Superior Court approval of the
settlement and conditioned on the Company receiving authorization from the DPUC
to recover the settlement amount from its retail customers. The DPUC denied the
Company's initial application for such authorization and the City agreed to
extend to December 31, 1998 the time period for satisfying this condition of the
settlement in return for a payment by the Company of $6 million. The Company
filed a second application with the DPUC on July 9, 1998, and on December 8,
1998 a Joint Stipulation among the Company, the Office of Consumer Counsel and
the Connecticut Attorney General relative to the recovery of the settlement
amount was filed with the DPUC. On December 30, 1998, the DPUC issued a draft
decision rejecting this Joint Stipulation. The Company filed written exceptions
to this draft decision and requested oral argument on the draft decision; and
the City agreed to extend to March 1, 1999 the time period for obtaining a
favorable DPUC authorization, in return for payment by the Company of an
additional $6 million. On February 10, 1999, the DPUC issued a final decision
rejecting the Joint Stipulation. The Company subsequently waived the condition
to the settlement with the City that the DPUC authorize recovery of the
settlement amount from the Company's retail customers and, on March 5, 1999, the
settlement was approved by the Superior Court. The Company will pay the
remaining $2.025 million of the settlement amount to the City promptly. Based on
the DPUC's final decision, the Company has expensed the $14.025 million
settlement amount in 1998.
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
- 82 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, 1998, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities.
Remediation costs, including the repair and/or replacement of approximately 560
linear feet of sheet piling, are currently estimated at $7.5 million. In
addition, the Company is planning to repair and/or replace the remaining
deteriorated sheet piling bordering the English Station property, at an
additional estimated cost of $10 million.
As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company has contracted to sell its Bridgeport Harbor Station and New Haven
Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. Environmental assessments performed
in connection with the marketing of these plants indicate that substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable Connecticut minimum standards following their sale.
The proposed purchaser of the plants has agreed to undertake and pay for the
major portion of this remediation. However, the Company will be responsible for
remediation of the portions of the plant sites that will be retained by it.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
Costs associated with nuclear plant operations include amounts for disposal
of nuclear wastes, including spent fuel, and for the ultimate decommissioning of
the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department
of Energy (DOE) is required to design, license, construct and operate a
permanent repository for high level radioactive wastes and spent nuclear fuel.
The Act requires the DOE to provide for the disposal of spent nuclear fuel and
high level radioactive waste from commercial nuclear plants through contracts
with the owners and generators of such waste; and the DOE has established
disposal fees that are being paid to the federal government by electric
utilities owning or operating nuclear generating units. In return for payment of
the prescribed fees, the federal government was required to take title to and
dispose of the utilities' high level wastes and spent nuclear fuel beginning no
later than January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010 and possibly
not earlier than 2013, 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.
- 83 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 $497 million (in 1999 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during 1998 was $2.1 million. UI's share of the fund at December 31, 1998 was
approximately $16.5 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $560 million (in 1999 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a
- 84 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
decommissioning trust fund managed by Northeast Utilities (NU). UI's share of
the Millstone Unit 3 decommissioning payments made during 1998 was $487,000.
UI's share of the fund at December 31, 1998 was approximately $6.5 million. The
current decommissioning cost estimate for the Connecticut Yankee Unit, assuming
the prompt removal and dismantling of the unit commencing in 1997, is $476
million, of which UI's share would be $45 million. Through December 31, 1998,
$85 million has been expended for decommissioning. The projected remaining
decommissioning cost is $391 million, of which UI's share would be $37 million.
The decommissioning trust fund for the Connecticut Yankee Unit is also managed
by NU. For the Company's 9.5% equity ownership in Connecticut Yankee,
decommissioning costs of $2.4 million were funded by UI during 1998, and UI's
share of the fund at December 31, 1998 was $25 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.
- 85 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(N) FAIR VALUE OF FINANCIAL INSTRUMENTS (1)
The estimated fair values of the Company's financial instruments are as
follows:
1998 1997
---- ----
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(000's) (000's)
Cash and temporary cash investments $101,445 $101,445 $32,002 $32,002
Long-term debt (2)(3)(4) $606,342 $611,524 $620,457 $624,192
(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, 1998 and 1997,
respectively.
(4) See Note (B), Capitalization - Long-Term Debt.
- 86 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(O) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1998 and 1997 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
----- -------
1998
First $162,474 $22,677 $8,962 $.64 $.64
Second (2) 159,792 21,174 5,497 .39 .39
Third 198,601 37,462 26,236 1.87 1.87
Fourth (3) 165,324 15,013 1,495 .10 .10
1997
First $180,325 $22,150 $7,710 $ .54 $.54
Second (4)(5) 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
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Net income and earnings per share for the second quarter of 1998 included
an after-tax charge of $2.9 million, for losses associated with the
Company's unregulated subsidiaries.
(3) Operating income, net income and earnings per share for the fourth quarter
of 1998 included an after-tax charge of $8.3 million, associated with a
property tax settlement. See Note (L), "Commitments and Contingencies -
Property Taxes".
(4) 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.
(5) 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.
- 87 -
[Letterhead of PricewaterhouseCoopers LLP]
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders
of The United Illuminating Company
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of retained earnings and of cash flows
present fairly, in all material respects, the financial position of The United
Illuminating Company and its subsidiaries (the "Company") at December 31, 1998,
1997 and 1996 and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, 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/ PricewaterhouseCoopers LLP
February 12, 1999
- 88 -
[Letterhead of PricewaterhouseCoopers LLP]
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors
of The United Illuminating Company
Our audits of the consolidated financial statements referred to in our report
dated February 12, 1999 appearing on page 88 of the 1998 Annual Report on Form
10-K also included an audit of the Financial Statement Schedule on page S-1 of
this Form 10-K. In our opinion, this Financial Statement Schedule presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
February 12, 1999
- 89 -
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures.
Not Applicable
PART III
Item 10. Directors and Executive Officers of the Company.
The information appearing under the captions "NOMINEES FOR ELECTION AS
DIRECTORS" AND "SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE" in the
Company's definitive Proxy Statement, dated March 30, 1999 for the Annual
Meeting of the Shareholders to be held on May 19, 1999, which Proxy Statement
will be filed with the Securities and Exchange Commission on or about March 30,
1999, 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 1998 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 30, 1999, for the Annual
Meeting of the Shareholders to be held on May 19, 1999, which Proxy Statement
will be filed with the Securities and Exchange Commission on or about March 30,
1999, 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 30, 1999 for the Annual Meeting of the Shareholders to be
held on May 19, 1999, which Proxy Statement will be filed with the Securities
and Exchange Commission on or about March 30, 1999, is incorporated by reference
in answer to this item.
Item 13. Certain Relationships and Related Transactions.
Since January 1, 1998, there has been no transaction, relationship or
indebtedness of the kinds described in Item 404 of Regulation S-K.
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PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
Financial Statements (see Item 8):
Consolidated statement of income for the years ended December 31, 1998,
1997 and 1996
Consolidated statement of cash flows for the years ended December 31,
1998, 1997 and 1996
Consolidated balance sheet, December 31, 1998, 1997 and 1996
Consolidated statement of retained earnings for the years ended
December 31, 1998, 1997 and 1996
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, 1998, 1997 and 1996.
- 91 -
Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain
of the following listed exhibits, which are annexed as exhibits to previous
statements and reports filed by the Company, are hereby incorporated by
reference as exhibits to this report. Such statements and reports are identified
by reference numbers as follows:
(1 Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1996.
(4) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1997.
(5) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1998.
(6) Filed with Registration Statement No. 33-40169, effective August 12, 1991.
(7) Filed with Registration Statement No. 33-35465, effective August 1, 1990.
(8) Filed with Amendment No. 1 to Registration Statement No. 33-55461,
effective October 31, 1994.
(9) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1995.
(10) Filed with Registration Statement No. 2-57275, effective October 19, 1976.
(11) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1996.
(13) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(14) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1998.
(15) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991.
(16) Filed with Registration Statement No. 2-54876, effective November 19, 1975.
(17) Filed with Registration Statement No. 2-66518, effective February 25, 1980.
(18) Filed with Registration Statement No. 2-52657, effective February 6, 1975.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1997.
(20) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1997.
(21) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1992.
(22) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1997.
(23) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1994.
(24) Filed March 29, 1996, with proxy material for the Annual Meeting of the
Shareowners.
- 92 -
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) 3.1e (5) Copy of Certificate Amending Certificate of Incorporation By Action of
Board of Directors and Shareholders, dated May 28, 1998. (Exhibit 3.1d)
(3) 3.2a (5) Copy of Bylaws of The United Illuminating Company. (Exhibit 3.2)
(3) 3.2b Copy of Article III, Section 2, of Bylaws of The United Illuminating
Company, as amended December 14, 1998, amending Exhibit 3.2a.
(4) 4.1 (6) 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 (7) 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 (8) Copy of form of Amended and Restated Agreement of Limited Partnership of
United Capital Funding Partnership L.P. (Exhibit 4(c))
(4) 4.3b (9) 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 (8) 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 (9) 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 (8) 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 (10) 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 (10) 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 (11) 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 (12) 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 (12) Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending
Exhibits 10.2b and 10.2c. (Exhibit 10.2d)
- 93 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
-------- ------- --------- -----------
(10) 10.2e (12) Copy of First Supplement to 1996 Amendatory Agreement, dated as of
February 10, 1997, supplementing Exhibit 10.2d. (Exhibit 10.2e)
(10) 10.3 (10) Copy of Capital Funds Agreement, dated as of September 1, 1964, between
Connecticut Yankee Atomic Power Company and The United Illuminating
Company. (Exhibit 5.1-3)
(10) 10.4 (13) Copy of Capital Contributions Agreement, dated October 16, 1967, between
The United Illuminating Company and Connecticut Yankee Atomic Power
Company. (Exhibit 5.1-5)
(10) 10.5 (14) Copy of Restated New England Power Pool Agreement, as amended to
December 1, 1996. (Exhibit 10.6g)
(10) 10.6a (15) Copy of Agreement for Joint Ownership, Construction and Operation of New
Hampshire Nuclear Units, dated May 1, 1973, as amended to February 1,
1990. (Exhibit 10.7a)
(10) 10.6b (16) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the
Seabrook Companies. (Exhibit 5.9-2)
(10) 10.6c (12) Copy of Twenty-third Amendment to Agreement for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units, dated as of
November 1, 1990, amending Exhibit 10.6a. (Exhibit 10.7c)
(10) 10.7a (17) Copy of Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of
September 1, 1973, among The Connecticut Light and Power Company, The
Hartford Electric Light Company, Western Massachusetts Electric Company,
New England Power Company, The United Illuminating Company, Public Service
Company of New Hampshire, Central Vermont Public Service Company, Montaup
Electric Company and Fitchburg Gas and Electric Light Company, relating to
a nuclear fueled generating unit in Connecticut. (Exhibit 5.8-1)
(10) 10.7b (18) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit,
dated as of August 1, 1974, amending Exhibit 10.7a. (Exhibit 5.9-2)
(10) 10.7c (10) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit,
dated as of December 15, 1975, amending Exhibit 10.7a. (Exhibit 5.8-4,
Post-effective Amendment No. 2)
(10) 10.8a (13) Copy of Transmission Line Agreement, dated January 13, 1966, between the
Trustees of the Property of The New York, New Haven and Hartford Railroad
Company and The United Illuminating Company. (Exhibit 5.4)
(10) 10.8b (15) Notice, dated April 24, 1978, of The United Illuminating Company's
intention to extend term of Transmission Line Agreement dated January 13,
1966, Exhibit 10.8a. (Exhibit 10.9b)
(10) 10.8c (15) Copy of Letter Agreement, dated March 28, 1985, between The United
Illuminating Company and National Railroad Passenger Corporation,
supplementing and modifying Exhibit 10.8a. (Exhibit 10.9c)
(10) 10.8d (19) Copy of Notice, dated April 22, 1997, of The United Illuminating Company's
intention to extend term of Transmission Line Agreement, Exhibit 10.9a, as
supplemented and modified by Exhibit 10.8c. (Exhibit 10.9d)
(10) 10.9a (20) Copy of Agreement, effective May 16, 1997, between The United
Illuminating Company and Local 470-1, Utility Workers Union of America,
AFL-CIO. (Exhibit 10.10)
(10) 10.9b Copy of Memorandum of Agreement, dated January 27, 1999, between The United
Illuminating Company and Local 470-1, Utility Workers Union of America,
AFL-CIO.
- 94 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
-------- ------- --------- -----------
(10) 10.10 (21) 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) 10.11 (12) Copy of Fossil Fuel Supply Agreement between BLC Corporation and The United
Illuminating Company, dated as of July 1, 1991. (Exhibit 10.13)
(10) 10.12a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1,
1997, between The United Illuminating Company and Robert L. Fiscus.
(Exhibit 10.23)
(10) 10.12b* (14) Copy of First Amendment to Amended and Restated Employment Agreement
between The United Illuminating Company and Robert L. Fiscus, dated as of
February 1, 1998, amending Exhibit 10.12a. (Exhibit 10.14a)
(10) 10.13a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1,
1997, between The United Illuminating Company and James F. Crowe.
(Exhibit 10.24)
(10) 10.13b* (14) Copy of First Amendment to Amended and Restated Employment Agreement
between The United Illuminating Company and James F. Crowe, dated as of
February 1, 1998, amending Exhibit 10.13a. (Exhibit 10.15a)
(10) 10.14a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Albert N. Henricksen. (Exhibit 10.25)
(10) 10.14b* (14) Copy of First Amendment to Amended and Restated Employment Agreement
between The United Illuminating Company and Albert N. Henricksen, dated as
of February 1, 1998, amending Exhibit 10.14a. (Exhibit 10.16a)
(10) 10.15a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Anthony J. Vallillo. (Exhibit 10.26)
(10) 10.15b* (14) Copy of First Amendment to Amended and Restated Employment Agreement
between The United Illuminating Company and Anthony J. Vallillo, dated as
of February 1, 1998, amending Exhibit 10.15a. (Exhibit 10.17a)
(10) 10.16* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Rita L. Bowlby. (Exhibit 10.27)
(10) 10.17* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Stephen F. Goldschmidt. (Exhibit 10.28)
(10) 10.18* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and James L. Benjamin. (Exhibit 10.29)
(10) 10.19* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Kurt D. Mohlman. (Exhibit 10.30)
(10) 10.20* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United
Illuminating Company and Charles J. Pepe. (Exhibit 10.31)
(10) 10.21* (14) Copy of Employment Agreement, dated as of February 23, 1998, between The
United Illuminating Company and Nathaniel D. Woodson. (Exhibit 10.28)
(10) 10.22* (14) Copy of The United Illuminating Company Phantom Stock Option Agreement,
dated as of February 23, 1998, between The United Illuminating Company and
Nathaniel D. Woodson. (Exhibit 10.29)
(10) 10.23* (15) Copy of Executive Incentive Compensation Program of The United Illuminating
Company. (Exhibit 10.24)
(10) 10.24* (11) 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* (23) Copy of The United Illuminating Company Dividend Equivalent Program.
(Exhibit 10.20)
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[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
-------- ------- --------- -----------
(10) 10.26* (24) 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)
(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, 1998, 1997, 1996, 1995 and
1994).
(21) 21 (20) List of subsidiaries of The United Illuminating Company. (Exhibit 21)
(27) 27 Financial Data Schedule
(28) 28.1 (21) Copies of significant rate schedules of The United Illuminating Company.
(Exhibit 28.1)
--------------------------
*Management contract or compensatory plan or arrangement.
- 96 -
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.
Item Financial
Reported Statements Date of Report
-------- ---------- --------------
2, 5 None October 1, 1998
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[Letterhead of PricewaterhouseCoopers LLP]
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 February 12, 1999
appearing on page 88 and page 89 of The United Illuminating Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
/s/ PricewaterhouseCoopers LLP
February 12, 1999
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SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the Company has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson
--------------------------------------
Nathaniel D. Woodson
Chairman of the Board of Directors,
President and Chief Executive Officer
Date: March 11, 1999
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.
[Enlarge/Download Table]
SIGNATURE TITLE DATE
--------- ----- ----
Director, Chairman of the
Board of Directors and
/s/ Nathaniel D. Woodson Chief Executive Officer March 11, 1999
-------------------------------------
(Nathaniel D. Woodson)
(Principal Executive Officer)
Director, Vice Chairman of the
Board of Directors and
/s/ Robert L. Fiscus Chief Financial Officer March 11, 1999
-------------------------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
/s/ John F. Croweak Director March 11, 1999
-------------------------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director March 11, 1999
-------------------------------------
(F. Patrick McFadden, Jr.)
/s/ Betsy Henley-Cohn Director March 11, 1999
(Betsy Henley-Cohn)
/s/Frank R. O'Keefe, Jr. Director March 11, 1999
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director March 11, 1999
-------------------------------------
(James A. Thomas)
/s/ David E.A. Carson Director March 11, 1999
-------------------------------------
(David E.A. Carson)
/s/ John L. Lahey Director March 11, 1999
-------------------------------------
(John L. Lahey)
/s/ Marc C. Breslawsky Director March 11, 1999
-------------------------------------
(Marc C. Breslawsky)
/s/ Thelma R. Albright Director March 11, 1999
-------------------------------------
(Thelma R. Albright)
- 99 -
[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, 1998, 1997 AND 1996
(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:
1998 $1,800 $5,032 - $5,032 (A) $1,800
1997 $2,300 $6,407 - $6,907 (A) $1,800
1996 $6,300 $9,854 - $13,854 (A) $2,300
------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
Dates Referenced Herein and Documents Incorporated by Reference
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