Document/Exhibit Description Pages Size
1: 10-K Annual Report Form 10-K 105 618K
4: EX-10.16B 1st Amend to Employ Agrmt - R. Bowlby 2 12K
5: EX-10.17B 1st Amend. to Employ Agrmt - S. Goldschmidt 2 11K
6: EX-10.19B 1st Amend. to Employ Agrmt - C. J. Pepe 2 12K
7: EX-10.20B 1st Amend to Employ Agrmt - N.D. Woodson 2 10K
8: EX-10.25B Resolution of Bd of Dir of Ui Adpted 12/13/99 1 8K
2: EX-10.5 Restated Nepool Agrmt - as of 3/1/2000 298 676K
3: EX-10.9C Memrndm of Agrmt Dtd 3/05/1999 Betw Ui & Union 7 36K
9: EX-12 Statement Re: Computation of Ratios 2 12K
10: EX-21 Subsidiaries of the Registrant 1 7K
11: EX-27 FDS -- 12 Mos. of 1999 1 8K
12: EX-28.1 Rate Schedules 82 221K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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COMMISSION FILE NUMBER 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
CONNECTICUT 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000
---------------------------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
[Enlarge/Download Table]
NAME OF EACH EXCHANGE ON
REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED
---------- ------------------- ------------------------
The United Illuminating Company Common Stock, no par value New York Stock Exchange
United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange
Securities, Series A (Liquidation
Preference $25 per Security)
(1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3,
1995 by United Capital Funding Partnership L.P., a special purpose limited
partnership in which The United Illuminating Company owns all of the
general partner interests, and are guaranteed by The United Illuminating
Company.
SECURITIES REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE,
OF THE UNITED ILLUMINATING COMPANY
---------------------------------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the registrant's voting stock held by
non-affiliates on January 31, 2000 was $716,746,100, computed on the basis of
the average of the high and low sale prices of said stock reported in the
listing of composite transactions for New York Stock Exchange listed securities,
published in The Wall Street Journal on February 1, 2000.
The number of shares outstanding of the registrant's only class of common stock,
as of January 31, 2000, was 14,334,922.
DOCUMENTS INCORPORATED BY REFERENCE
None
THE UNITED ILLUMINATING COMPANY
FORM 10-K
DECEMBER 31, 1999
TABLE OF CONTENTS
PAGE
----
GLOSSARY 4
PART I
Item 1. Business. 5
- General 5
- Franchises, Regulation and Rates 5
- Franchises 5
- Regulation 5
- Rates 6
- Financing 6
- Fuel Supply 6
- Fossil Fuel 6
- Nuclear Fuel 7
- Power Supply Arrangements 7
- Arrangements with Other Utilities 8
- New England Power Pool 8
- New England Transmission Grid 8
- Hydro-Quebec 8
- Environmental Regulation 9
- Employees 10
Item 2. Properties. 11
- Generating Facilities 11
- Transmission and Distribution Plant 11
- Capital Expenditure Program 12
- Nuclear Generation 12
- General Considerations 14
- Insurance Requirements 14
- Waste Disposal and Decommissioning 15
Item 3. Legal Proceedings. 15
TABLE OF CONTENTS (CONTINUED)
PAGE
----
Item 4. Submission of Matters to a Vote of Security Holders. 15
Executive Officers of the Company 16
PART II
Item 5. Market for the Company's Common Equity and Related
Stockholder Matters. 17
Item 6. Selected Financial Data. 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 22
- Major Influences on Financial Condition 22
- Liquidity and Capital Resources 25
- Subsidiary Operations 27
- New Accounting Standards 28
- Results of Operations 28
- Looking Forward 37
Item 8. Financial Statements and Supplementary Data. 39
- Consolidated Financial Statements 39
- Statement of Income for the Years 1999, 1998 and 1997 39
- Statement of Cash Flows for the Years 1999, 1998 and 1997 40
- Balance Sheet as of December 31, 1999 and 1998 41
- Statement of Changes in Shareholders' Equity for the Years
1999, 1998 and 1997 43
- Notes to Consolidated Financial Statements 44
- Statement of Accounting Policies 44
- Capitalization 49
- Rate-Related Regulatory Proceedings 53
- Accounting for Phase-in Plan 57
- Short-Term Credit Arrangements 57
- Income Taxes 58
- Supplementary Information 60
- Pension and Other Benefits 61
- Jointly Owned Plant 64
- Unamortized Cancelled Nuclear Project 64
- Fuel Financing Obligations and Other Lease Obligations 64
- Commitments and Contingencies 66
- 2 -
TABLE OF CONTENTS (CONTINUED)
PAGE
----
PART II (CONTINUED)
- Capital Expenditure Program 66
- Nuclear Insurance Contingencies 66
- Other Commitments and Contingencies 67
- Connecticut Yankee 67
- Hydro-Quebec 67
- Environmental Concerns 68
- Site Decontamination, Demolition and Remediation Costs 68
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 68
- Fair Value of Financial Instruments 70
- Quarterly Financial Data (Unaudited) 71
- Segment Information 71
- Restatement of Financial Results 72
Report of Independent Accountants 75
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures. 77
PART III
Item 10. Directors and Executive Officers of the Company 77
Item 11. Executive Compensation. 80
Item 12. Security Ownership of Certain Beneficial Owners
and Management. 91
Item 13. Certain Relationships and Related Transactions. 94
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K. 95
Consent of Independent Accountants 102
Signatures 103
- 3 -
GLOSSARY
Certain capitalized terms used in this Annual Report have the following
meanings, and such meanings shall apply to terms both singular and plural unless
the context clearly requires otherwise:
"APS" means American Payment Systems, Inc., a wholly-owned subsidiary of
URI.
"the Company" means The United Illuminating Company.
"CSC" means the Connecticut Siting Council.
"Connecticut Yankee" means the Connecticut Yankee Atomic Power Company.
"Connecticut Yankee Unit" means the nuclear electric generating unit owned
by Connecticut Yankee and located in Haddam Neck, Connecticut.
"DEP" means the Connecticut Department of Environmental Protection.
"DOE" means the United States Department of Energy.
"DPUC" means the Connecticut Department of Public Utility Control.
"EPA" means the United States Environmental Protection Agency.
"FERC" means the United States Federal Energy Regulatory Commission.
"LLW" means low-level radioactive wastes.
"Millstone Unit 3" means the nuclear electric generating unit located in
Waterford, Connecticut, which is jointly owned by the Company and twelve
other New England electric utility entities.
"NEPOOL" means the New England Power Pool.
"NRC" means the United States Nuclear Regulatory Commission.
"NU" means Northeast Utilities.
"PCBs" means polychlorinated biphenyls.
"Preferred Stock" means capital stock of the Company having preferential
dividend and liquidation rights over shares of the Company's other classes
of capital stock.
"RCRA" means the federal Resource Conservation and Recovery Act.
"Restructuring Act" means Connecticut Public Act 98-28, enacted in 1998 and
designed to restructure the State's regulated electric utility industry.
"Seabrook Unit 1" means nuclear generating unit No. 1 located in Seabrook,
New Hampshire, which is jointly owned by the Company and ten other New
England electric utility entities.
"TSCA" means the federal Toxic Substances Control Act.
"URI" means United Resources, Inc., a wholly-owned subsidiary of the
Company.
- 4 -
PART I
Item 1. Business.
GENERAL
The United Illuminating Company (the Company) is an operating electric
public utility company, incorporated under the laws of the State of Connecticut
in 1899. It is engaged principally in the purchase, transmission, distribution
and sale of electricity for residential, commercial and industrial purposes in a
service area of about 335 square miles in the southwestern part of the State of
Connecticut. The population of this area is approximately 704,000 or 21% of the
population of the State. The service area, largely urban and suburban in
character, includes the principal cities of Bridgeport (population approximately
137,000) and New Haven (population approximately 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals. Of the Company's 1999 retail electric revenues,
approximately 42% was derived from residential sales, 40% from commercial sales,
16% from industrial sales and 2% from other sales. For a description of the
changes in the Company's electric public utility company business resulting from
the 1998 Connecticut legislation designed to restructure the State's electric
utility industry, see PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition."
The Company has one wholly-owned subsidiary, United Resources, Inc. (URI),
that serves as the parent corporation for several unregulated businesses, each
of which is incorporated separately to participate in business ventures that
will complement the Company's regulated electric utility business and provide
long-term rewards to the Company's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
FRANCHISES, REGULATION AND RATES
FRANCHISES
Subject to the power of alteration, amendment or repeal by the Connecticut
legislature, and subject to certain approvals, permits and consents of public
authorities and others prescribed by statute, the Company has valid franchises
to engage in the purchase, transmission, distribution and sale of electricity in
the area served by it, the right to erect and maintain certain facilities on
public highways and grounds, and the power of eminent domain.
REGULATION
The Company is subject to regulation by the Connecticut Department of
Public Utility Control (DPUC), which has jurisdiction with respect to, among
other things, retail electric service rates, accounting procedures, certain
dispositions of property and plant, mergers and consolidations, the issuance of
securities, certain standards of service, management efficiency, operation and
construction, and the location and construction of certain electric facilities.
The DPUC consists of five Commissioners, appointed by the Governor of
Connecticut with the advice and consent of both houses of the Connecticut
legislature. See PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition," regarding the restructuring of Connecticut's regulated electric
utility industry.
- 5 -
The location and construction of certain electric facilities is also
subject to regulation by the Connecticut Siting Council (CSC) with respect to
environmental compatibility and public need. See "Environmental Regulation."
The Company is a "public utility" within the meaning of Part II of the
Federal Power Act and is subject to regulation by the Federal Energy Regulatory
Commission (FERC), which has jurisdiction with respect to interconnection and
coordination of facilities, wholesale electric service rates and accounting
procedures, among other things. See "Arrangements with Other Utilities."
In connection with ownership and leasehold interests in Seabrook Unit 1 and
Millstone Unit 3, the Company is a holder of licenses under the Atomic Energy
Act of 1954, as amended, and, as such, is subject to the jurisdiction of the
United States Nuclear Regulatory Commission (NRC), which has broad regulatory
and supervisory jurisdiction with respect to the construction and operation of
nuclear reactors, including matters of public health and safety, financial
qualifications, antitrust considerations and environmental impact. Connecticut
Yankee Atomic Power Company (Connecticut Yankee), in which the Company has a
9.5% common stock ownership share, is also subject to this NRC regulatory and
supervisory jurisdiction. See Item 2," Properties - Nuclear Generation."
The Company is subject to the jurisdiction of the New Hampshire Public
Utilities Commission for limited purposes in connection with its 17.5% ownership
and leasehold interests in Seabrook Unit 1.
RATES
The Company's retail electric service rates are subject to regulation by
the DPUC.
The Company's present general retail rate structure consists of various
rate and service classifications covering residential, commercial, industrial
and street lighting services.
Utilities are entitled by Connecticut law to charge rates that are
sufficient to allow them an opportunity to cover their reasonable operating and
capital costs, to attract needed capital and maintain their financial integrity,
while also protecting relevant public interests.
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Major Influences on Financial Condition"
regarding the five-year incentive rate regulation plan, for the years 1997
through 2001, that is currently in effect for the Company and the standard offer
rates established by the DPUC pursuant to Public Act 98-28, which was enacted in
1998 and designed to restructure Connecticut's regulated electric utility
industry.
FINANCING
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources,"
regarding the Company's capital requirements and resources and its financings
and financial commitments.
FUEL SUPPLY
FOSSIL FUEL
On April 16, 1999, the Company sold both of its operating fossil-fueled
generating stations, Bridgeport Harbor Station and New Haven Harbor Station, to
Wisvest-Connecticut, LLC, (Wisvest) a single-purpose subsidiary of Wisvest
Corporation, which is a non-utility subsidiary of Wisconsin Energy Corporation,
Milwaukee, Wisconsin. See PART II, Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Major Influences on Financial
Condition." All of the Company's fossil fuel supply contracts were assigned to
Wisvest-Connecticut, LLC on the closing date of the transaction.
- 6 -
NUCLEAR FUEL
The Company holds an ownership and leasehold interest in Seabrook Unit 1
and an ownership interest in Millstone Unit 3, both of which are nuclear-fueled
generating units. Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to uranium concentrates, the
conversion of uranium concentrates to uranium hexafluoride, enrichment of that
gas and fabrication of the enriched hexafluoride into usable fuel assemblies.
After a region (approximately 1/3 to 1/2 of the nuclear fuel assemblies in
the reactor at any time) of spent fuel is removed from a nuclear reactor, it is
placed in temporary storage in a spent fuel pool at the nuclear station for
cooling and ultimately is expected to be transported to a permanent storage
site, which has yet to be determined. See Item 2, "Properties - Nuclear
Generation."
Based on information furnished by the utility responsible for the operation
of the units in which the Company is participating, there are outstanding
contracts that cover uranium concentrate purchases for Millstone Unit 3 through
2003 and for Seabrook Unit 1 through 2002. In addition, there are outstanding
contracts, to the extent indicated below, for conversion, enrichment and
fabrication services for these units extending through the following years:
CONVERSION TO
HEXAFLUORIDE ENRICHMENT FABRICATION
------------- ---------- -----------
Millstone Unit 3 2003 2002 2010
Seabrook Unit 1 2002 2002 2008
POWER SUPPLY ARRANGEMENTS
In 1998, Connecticut enacted Public Act 98-28 (the Restructuring Act)
designed to restructure the State's electric utility industry. For a description
of the changes in the Company's electric public utility company business
resulting from the Restructuring Act, see PART II, Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Major
Influences on Financial Condition."
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. On and after
January 1, 2000 and until January 1, 2004, the Company is required to offer full
retail service to its customers under a regulated "standard offer" rate and is
also required to be the power supply provider to each customer who does not
choose an alternate power supply provider, even though the Company will no
longer be in the business of retail power generation. The Company is also
required under the Restructuring Act to provide back-up power supply service to
customers whose alternate power supply provider fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
In conjunction with the sale of its operating non-nuclear generating
stations to Wisvest on April 16, 1999, the Company entered into a wholesale
power supply contract with the purchaser for the sale of power to the Company,
through June 30, 2000, to replace the power that had been generated by the
Company at these generating stations. On December 28, 1999, the Company entered
into a series of agreements with Enron Power Marketing, Inc. (EPMI), a
subsidiary of Enron Corp., Houston, Texas, for the supply of all of the power
needed by the Company to meet its standard offer obligations until the end of
the four-year standard offer period and the power needed to serve the Company's
special contract customers for the remaining contract terms. From January 1,
2000 through June 30, 2000, EPMI will sell to the Company energy beyond that
supplied by Wisvest as described above. The agreements also provide for the sale
to EPMI of the Company's entitlements under all of its wholesale purchased power
agreements (PPAs). However, unless or until a PPA is terminated or formally
assigned to EPMI, the Company remains legally liable to pay the applicable power
supplier all amounts due under the PPA. The agreements with EPMI also include a
financially settled contract for differences related to certain call rights of
EPMI and put rights of the Company with respect to the Company's entitlements in
Seabrook Unit 1 and in Millstone Unit 3, and the Company's provision to EPMI of
certain ancillary products and services associated with those nuclear
entitlements, which provisions terminate at the earlier of December 31, 2003 or
the date that the Company sells its nuclear interests. The agreements do not
- 7 -
restrict the Company's right to sell to third parties the Company's ownership
interests in those nuclear generation units or the generated energy actually
attributable to its ownership interests.
If the generation resources available to the Company's wholesale suppliers
become inadequate to meet its customer service obligations, the Company expects
to be able to reduce the load on its system by the implementation of demand-side
management programs, to acquire other demand-side and supply-side resources,
and/or to purchase capacity from other utilities or from the installed
capability spot market, as necessary. However, because the generation and
transmission systems of the major New England utilities, including the Company,
are operated as if they were a single system, the ability of the Company to meet
its customer service obligations is and will be dependent on the ability of the
region's generation and transmission systems to meet the region's load. See Item
1, "Business - Arrangements with Other Utilities."
ARRANGEMENTS WITH OTHER UTILITIES
NEW ENGLAND POWER POOL
The Company, in cooperation with other privately and publicly owned New
England electric utilities, established the New England Power Pool (NEPOOL) in
1971. NEPOOL was formed to assure reliable operation of the bulk power system in
the most economic manner for the region. It has achieved these objectives
through central dispatching of all generation facilities owned by its members
and through coordination of the activities of the members that can have
significant inter-utility impacts. NEPOOL is governed by an agreement (NEPOOL
Agreement) that is filed with the Federal Energy Regulatory Commission (FERC);
and its provisions are subject to continuing FERC jurisdiction.
Because of evolving industry-wide changes, NEPOOL has been restructured.
Its membership has been broadened to cover all entities engaged in the
electricity business in New England, including power marketers and brokers,
independent power producers and load aggregators. An independent entity, ISO New
England, Inc., has the responsibility for the operation of the regional bulk
power system, so that the regional bulk power system will continue to be
operated both in accordance with the NEPOOL objectives and free of any adverse
impact on competition in the wholesale power markets, where various energy and
capacity products are traded in open competition among all participants.
Amendments to the NEPOOL Agreement establishing the markets were filed with and
have been approved by the FERC, and the markets became operational on May 1,
1999. Further significant amendments to the NEPOOL Agreement, to implement a
transmission congestion management and multi-settlement system, are expected to
be filed with the FERC prior to March 31, 2000.
NEW ENGLAND TRANSMISSION GRID
Under other agreements related to the Company's participation in the
ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to
the financial support of certain 345 kilovolt transmission facilities that are a
part of the New England transmission grid.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. The
Company is obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. As of December 31, 1999, the Company's
guarantee liability for this debt was approximately $6.2 million.
- 8 -
ENVIRONMENTAL REGULATION
The National Environmental Policy Act requires that detailed statements of
the environmental effect of the Company's facilities be prepared in connection
with the issuance of various federal permits and licenses, some of which are
described below. Federal agencies are required by that Act to make an
independent environmental evaluation of the facilities as part of their actions
during proceedings with respect to these permits and licenses.
Under the federal Toxic Substances Control Act (TSCA), the EPA has issued
regulations that control the use and disposal of polychlorinated biphenyls
(PCBs). PCBs had been widely used as insulating fluids in many electric utility
transformers and capacitors manufactured before TSCA prohibited any further
manufacture of such PCB equipment. Fluids with a concentration of PCBs higher
than 500 parts per million and materials (such as electrical capacitors) that
contain such fluids must be disposed of through burning in high temperature
incinerators approved by the EPA. Solid wastes containing PCBs must be disposed
of in either secure chemical waste landfills or in high-efficiency incinerators.
In response to EPA regulations, the Company has phased out the use of certain
PCB capacitors and has tested all Company-owned transformers located inside
customer-owned buildings and replaced all transformers found to have fluids with
detectable levels of PCBs (higher than 1 part per million) with transformers
that have no detectable PCBs. Presently, no transformers having fluids with
levels of PCBs higher than 500 parts per million are known by the Company to
remain in service in its system, except at one generating station. Compliance
with TSCA regulations has necessitated substantial capital and operational
expenditures by the Company, and such expenditures may continue to be required
in the future, although their magnitude cannot now be estimated. The Company
agreed to participate financially in the remediation of a source of PCB
contamination attributed to the Company-owned electrical equipment on property
in New Haven. In 1999, the Company made a $100,000 payment toward that
remediation activity and was released from any and all future claims.
Under the federal Resource Conservation and Recovery Act (RCRA), the
generation, transportation, treatment, storage and disposal of hazardous wastes
are subject to regulations adopted by the EPA. Connecticut has adopted state
regulations that parallel RCRA regulations but are more stringent in some
respects. The Company has complied with the notification and application
requirements of present regulations, and the procedures by which the Company
handles, stores, treats and disposes of hazardous waste products have been
revised, where necessary, to comply with these regulations.
As described in PART II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Major Influences on Financial
Condition," the Company has sold its Bridgeport Harbor Station and New Haven
Harbor Station generating plants in compliance with Connecticut's electric
utility industry restructuring legislation. Environmental assessments performed
in connection with the marketing of these plants indicated that substantial
remediation expenditures will be required in order to bring the plant sites into
compliance with applicable Connecticut minimum standards following their sale.
The purchaser of the plants undertook liability for payment of any remediation
required with respect to the purchased assets. However, the Company will be
responsible for remediation of the portions of the plant sites that it has
retained, and no estimate of the potential costs is available.
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.4 million had been incurred as of December 31, 1999, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities. In
addition, the Company is currently replacing the bulkhead that surrounds this
site, at an estimated cost of $13.5 million. Of this amount, $4.2 million
represents the portion of the costs to protect the Company's transmission
facilities and will be capitalized as plant in service. The remaining estimated
cost of $9.3 million was expensed in 1999.
- 9 -
RCRA also regulates underground tanks storing petroleum products or
hazardous substances, and Connecticut has adopted state regulations governing
underground tanks storing petroleum and petroleum products that, in some
respects, are more stringent than the federal requirements. The Company
currently owns 8 underground storage tanks, which are used primarily for
gasoline and fuel oil, that are subject to these regulations. A testing program
has been installed to detect leakage from any of these tanks, and substantial
costs may be incurred for future actions taken to prevent tanks from leaking, to
remedy any contamination of groundwater, and to modify, remove and/or replace
older tanks in compliance with federal and state regulations.
In the past, the Company has disposed of residues from operations at
landfills, as most other industries have done. In recent years it has been
determined that such disposal practices, under certain circumstances, can cause
groundwater contamination. Although the Company has no knowledge of the
existence of any such contamination, if the Company or regulatory agencies
determine that remedial actions must be taken in relation to past disposal
practices, the Company may experience substantial costs.
Connecticut statutes prohibit the commencement of construction or
reconstruction of electric generation or transmission facilities, or
modification of such facilities, unless the Connecticut Siting Council has
issued a certificate of environmental compatibility and public need or a
declaratory ruling that no certificate is required because the facility or
modification will not have a substantial adverse environmental effect.
In complying with existing environmental statutes and regulations and
further developments in these and other areas of environmental concern,
including legislation and studies in the fields of water and air quality,
hazardous waste handling and disposal, toxic substances, and electric and
magnetic fields, the Company may incur substantial capital expenditures for
equipment modifications and additions, monitoring equipment and recording
devices, and it may incur additional operating expenses. Litigation expenditures
may also increase as a result of scientific investigations, and speculation and
debate, concerning the possibility of harmful health effects of electric and
magnetic fields. The total amount of these expenditures is not now determinable.
See also "Franchises, Regulation and Rates" and Item 2, "Properties - Nuclear
Generation."
EMPLOYEES
As of December 31, 1999, the Company had 827 employees; and its
wholly-owned subsidiaries employed 412 persons in their non-regulated
businesses. Of the Company's employees, approximately 89.4% had been with the
Company for 10 or more years.
Approximately 389 of the Company's operating, maintenance and clerical
employees are represented by Local 470-1, Utility Workers Union of America,
AFL-CIO, for collective bargaining purposes. On June 30, 1997, the unionized
employees accepted a five-year agreement. The agreement provides for, among
other things, 2% annual wage increases beginning in May 1998, and annual lump
sum bonuses of 2.5% of base annual straight time wages (not cumulative). The
agreement also provides for job security for longer-term bargaining unit
employees. There has been no work stoppage due to labor disagreements since
1966, other than a strike of three days duration in May 1985; and employee
relations are considered satisfactory.
- 10 -
Item 2. Properties
GENERATING FACILITIES
The electric generating capability of the Company as of December 31, 1999,
based on summer ratings of the generating units, was as follows:
YEAR OF MAX CLAIMED COMPANY
COMPANY OPERATED: FUEL INSTALLATION CAPABILITY, MW ENTITLEMENT
---------------- ---- ------------ -------------- -----------
% Mw
English Station 7 #6 Oil 1948 34.06 100.00 34.06(1)
English Station 8 #6 Oil 1953 38.49 100.00 38.49(1)
OPERATED BY OTHER
UTILITIES:
-----------------
Millstone Unit 3, Nuclear 1986 1154.56 3.685 42.55(2)
Waterford, Connecticut
Seabrook Unit 1, Nuclear 1990 1161.00 17.50 203.18(3)
Seabrook, New Hampshire
(1) English Station 7 and 8 were placed in deactivated reserve status,
effective January 1, 1992.
(2) Represents the Company's 3.685% ownership share of total net capability.
(3) Represents the Company's 17.5% ownership and leasehold share of total net
capability. In August 1990, the Company sold to and leased back from an
owner trust established for the benefit of an institutional investor a
portion of the Company's 17.5% ownership interest in this unit. This
portion of the unit is subject to the lien of a first mortgage granted by
the owner trustee.
See PART II, Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Major Influences on Financial Condition,"
regarding the Company's sale of both of its operating non-nuclear generating
stations, on April 16, 1999, and its plan to divest its nuclear generation, in
compliance with Connecticut's electric utility industry Restructuring Act.
English Station is the Company's only remaining non-nuclear generating
station. Since June of 1998, the Company has been attempting to sell this
deactivated station, which is situated on a site bordering the Mill River in New
Haven, in order to avoid incurring the expense, estimated at $20 million, of
decommissioning and demolishing the generating units and buildings on the site.
On March 2, 2000, the Company agreed to sell the station to Quinnipiac Energy,
LLC, (QE) a privately-owned independent power producer. QE intends to reactivate
the generating units at the station. Under the terms of the purchase and sale
agreement for the transaction, the consummation of which is subject to a number
of conditions, including obtaining state and federal regulatory approvals, the
Company will retain a permanent right of occupancy on and over the station
property for the Company's existing New Haven harbor transmission line towers
and cables. QE will complete the bulkhead replacement project that the Company
has commenced to preserve and protect the station property; and QE will assume
responsibility for any and all environmental liability associated with the
Company's prior ownership and operation of the station. The Company has agreed
to pay for the cost of completing the bulkhead replacement project, the
estimated cost of which the Company recognized in 1999, to pay for 61% of the
environmental remediation costs (estimated at $750,000) that will be incurred by
QE under Connecticut's Transfer Act as a result of QE's acquisition of the
station, and to pay QE $4.25 million for QE's assumption of the remaining
Transfer Act remediation costs and any and all environmental liability
associated with the Company's prior ownership and operation of the station.
TRANSMISSION AND DISTRIBUTION PLANT
The transmission lines of the Company consist of approximately 102 circuit
miles of overhead lines and approximately 17 circuit miles of underground lines,
all operated at 345 KV or 115 KV and located within or
- 11 -
immediately adjacent to the territory served by the Company. These transmission
lines interconnect the Bridgeport Harbor and New Haven Harbor generating
stations and are part of the New England transmission grid through connections
with the transmission lines of The Connecticut Light and Power Company. A major
portion of the Company's transmission lines is constructed on railroad
right-of-way pursuant to two Transmission Line Agreements. One of the Agreements
expires in May 2000 and the Company expects to extend this Agreement. The other
Agreement has been extended to May 2040.
The Company owns and operates 25 bulk electric supply substations with a
capacity of 1,756,300 KVA and 32 distribution substations with a capacity of
153,520 KVA. The Company has 3,170 pole-line miles of overhead distribution
lines and 130 conduit-bank miles of underground distribution lines.
See "Capital Expenditure Program" concerning the estimated cost of
additions to the Company's transmission and distribution facilities.
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program for 2000 through 2004
is presently estimated at $187.5 million, excluding allowance for funds used
during construction. See PART II, Item 8, "Financial Statements and
Supplementary Data - Notes to Consolidated Financial Statements - Note (L),
Commitments and Contingencies."
NUCLEAR GENERATION
The Company holds ownership and leasehold interests totalling 17.5% (203.18
megawatts) in Seabrook Unit 1, and a 3.685% (42.55 megawatts) ownership interest
in Millstone Unit 3. The Company also owns 9.5% of the common stock of
Connecticut Yankee, and was entitled to an equivalent percentage (53.21
megawatts) of the generating capability of the Connecticut Yankee Unit prior to
its retirement from commercial operation on December 4, 1996.
Seabrook Unit 1 commenced commercial operation in June of 1990, pursuant to
an operating license issued by the NRC, which will expire in 2026. It is jointly
owned by eleven New England electric utility entities, including the Company,
and is operated by a service company subsidiary of Northeast Utilities (NU).
Through December 31, 1999, Seabrook Unit 1 has operated at a lifetime capacity
factor of 80.5%.
Millstone Unit 3 commenced commercial operation in April of 1986, pursuant
to a 40-year operating license issued by the NRC. It is jointly owned by
thirteen New England electric utility entities, including the Company, and is
operated by another service company subsidiary of NU. Through March 30, 1996,
when Millstone Unit 3 was taken out of service following an engineering
evaluation that determined that four safety-related valves would not be able to
perform their design function during certain postulated events, Millstone Unit 3
had operated at a lifetime capacity factor of 71.9%. A comprehensive Nuclear
Regulatory Commission (NRC) inquiry into the conformity of the unit and its
operations with all applicable NRC regulations and standards was completed and
the unit was allowed to resume operation beginning on July 4, 1998. It achieved
full power production on July 14, 1998. Through December 31, 1999, Millstone
Unit 3 has operated at a lifetime capacity factor of 60.6%.
During the twenty-seven months that Millstone Unit 3 was out of service,
the Company incurred incremental replacement power costs estimated at
approximately $500,000 per month, and experienced an adverse impact on net
earnings per share of approximately $.02 per month. In addition to these costs
of replacement power, substantial incremental direct costs were incurred to
address the above-described problems with respect to Millstone Unit 3. The
Company and the other nine non-NU owners of Millstone Unit 3, who together own
about 19.5% of the unit, paid their monthly shares of the costs of the unit, but
reserved their rights to contest whether the NU service company subsidiary that
is the operator of Millstone Unit 3 and/or one or both of the two operating NU
subsidiary electric utility companies that are the majority joint owners of
Millstone Unit 3 are responsible for the additional costs that the other joint
owners experienced as a result of the shutdown of Millstone Unit 3. On August 7,
1997, the Company and the other nine minority, non-NU joint owners of Millstone
Unit 3 filed lawsuits against NU and its trustees, as well as a demand for
arbitration against The Connecticut Light and Power Company and Western
Massachusetts Electric Company
- 12 -
the operating electric utility subsidiaries of NU that are the majority joint
owners of the unit and have contracted with the minority joint owners to operate
it. In the arbitration proceeding and lawsuits, which NU and its subsidiaries
are contesting vigorously, the non-NU joint owners claim that NU and its
subsidiaries failed to comply with NRC regulations, failed to operate Millstone
Station in accordance with good utility operating practice and concealed their
failures from the non-operating joint owners and the NRC, and seek to recover
costs of purchasing replacement power and increased operation and maintenance
costs resulting from the shutdown of Millstone Unit 3. Three of the non-NU joint
owners, who together own about 11.5% of the unit, have settled their claims
against NU and its subsidiaries and have withdrawn from the prosecution of the
arbitration proceeding and lawsuits.
The DPUC is currently considering the Company's plan for divesting its
ownership interest in Millstone Unit 3 through an auction process to be
conducted by a consultant to be selected by the DPUC.
The Connecticut Yankee Unit commenced commercial operation in January of
1968, pursuant to a 40-year operating license issued by the NRC. It is owned,
through ownership of Connecticut Yankee's common stock, by ten New England
electric utilities, including the Company, and is operated by another service
company subsidiary of NU. Prior to July 23, 1996, when the Connecticut Yankee
Unit was taken out of service following an engineering evaluation that
determined that safety-related air cooling system pipes could crack if the plant
should lose its outside source of electric power, the Connecticut Yankee Unit
had operated at a lifetime capacity factor of 75.6%. Prior to and following its
removal from service in July of 1996, NRC inspections of the Connecticut Yankee
Unit revealed issues that were similar to those previously identified at
Millstone Station and identified a number of significant deficiencies in the
engineering calculations and analyses that were relied upon to ensure the
adequacy of the design of key safety systems at the unit. Pending a resolution
of these issues, an economic study by the owners, comparing the costs of
continuing to operate the Connecticut Yankee Unit over the remaining period of
its operating license, which expires in 2007, to the costs of shutting down the
unit permanently and incurring replacement power costs for the same period,
resulted in a decision, on December 4, 1996, by the Board of Directors of
Connecticut Yankee to retire the Connecticut Yankee Unit from commercial
operation.
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from the Company. In December of
1996, Connecticut Yankee filed decommissioning cost estimates and amendments to
the power contracts with its owners with the Federal Energy Regulatory
Commission (FERC). Based on regulatory precedent, this filing sought
confirmation that Connecticut Yankee will continue to collect from its owners
its decommissioning costs, the unrecovered investment in the Connecticut Yankee
Unit and other costs associated with the permanent shutdown of the Connecticut
Yankee Unit. On August 31, 1998, a FERC Administrative Law Judge (ALJ) released
an initial decision regarding Connecticut Yankee's December 1996 filing. The
initial decision contains provisions that would allow Connecticut Yankee to
recover, through the power contracts with its owners, the balance of its net
unamortized investment in the Connecticut Yankee Unit, but would disallow
recovery of a portion of the return on Connecticut Yankee's investment in the
unit. The ALJ's decision also states that decommissioning cost collections by
Connecticut Yankee, through the power contracts, should continue to be based on
a previously-approved estimate until a new, more reliable estimate has been
prepared and tested. During October of 1998, Connecticut Yankee and its owners
filed briefs setting forth exceptions to the ALJ's initial decision. If this
initial decision is upheld by the FERC, Connecticut Yankee could be required to
write off a portion of the regulatory asset on its Balance Sheet associated with
the retirement of the Connecticut Yankee Unit. In this event, however, the
Company would not be required to record any write-off on account of its 9.5%
ownership share in Connecticut Yankee, because the Company has recorded its
regulatory asset associated with the retirement of the Connecticut Yankee Unit
net of any return on investment. The Company cannot predict, at this time, the
outcome or timing of the FERC proceeding. However, the Company will continue to
support Connecticut Yankee's efforts to contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.0
million) and return on investment (approximately $3.8 million) at December 31,
1999, is approximately $27.1 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
- 13 -
GENERAL CONSIDERATIONS
Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee Unit are each
subject to the licensing requirements and jurisdiction of the NRC under the
Atomic Energy Act of 1954, as amended, and to a variety of other state and
federal requirements.
The NRC regularly conducts generic reviews of numerous technical issues,
ranging from seismic design to education and fitness for duty requirements for
licensed plant operators. The outcome of reviews that are currently pending, and
the ways in which the nuclear generating units in which the Company has
interests may be affected by these reviews, cannot be determined; and the cost
of complying with any new requirements that might result from the reviews cannot
be estimated. However, such costs could be substantial.
Additional capital expenditures and increased operating costs for nuclear
generating units may result from modifications of these facilities or their
operating procedures required by the NRC, or from actions taken by other joint
owners or companies having entitlements in the units. Some equipment
modifications have required and may in the future require shutdowns or deratings
of generating units that would not otherwise be necessary and that result in
additional costs. The amounts of additional capital expenditures and increased
costs cannot now be predicted, but they have been and may in the future be
substantial.
Public controversy concerning nuclear power could also adversely affect
Seabrook Unit 1 and Millstone Unit 3. Proposals to force the premature shutdown
of nuclear plants in other New England states have in the past received serious
attention, and the licensing of Seabrook Unit 1 was a regional issue. A renewal
of the controversy could be expected to increase the costs of operating the
nuclear generating units in which the Company has interests; and it is possible
that one or the other of the units could be shut down prematurely, resulting in
earlier funding of costs associated with decommissioning the unit and
acceleration of depreciation expense, which could have an adverse impact on the
Company's financial condition and/or results of operations.
INSURANCE REQUIREMENTS
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $83.9 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $83.9 million, or $4.2
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the two operating nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $17.8 million per incident. However, any
assessment would be limited to $2.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the two
operating nuclear generating units in which the Company has an interest, the
Company is required to pay its ownership and/or leasehold share of the cost of
purchasing such insurance. Although each of these units has purchased $2.75
billion of property insurance coverage, representing the limits of coverage
currently available from conventional nuclear insurance pools, the cost of a
nuclear incident could exceed available insurance proceeds. Under those
circumstances, the nuclear insurance pools that provide this coverage may levy
assessments against the insured owner companies if pool losses exceed the
accumulated funds available to the pool. The maximum potential
- 14 -
assessments against the Company with respect to losses occurring during current
policy years are approximately $3.0 million.
WASTE DISPOSAL AND DECOMMISSIONING
See PART II, Item 8, "Financial Statements and Supplementary Data - Notes
to Consolidated Financial Statements - Note (M), Nuclear Fuel Disposal and
Nuclear Plant Decommissioning" regarding the disposal of spent nuclear fuel and
high-level and low-level radioactive wastes in connection with the operation and
decommissioning of Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee
Unit.
Item 3. Legal Proceedings.
See Item 2, "Properties - Nuclear Generation" regarding the Company's
participation in an arbitration proceeding and lawsuits against Northeast
Utilities and its subsidiaries with respect to their operation of Millstone Unit
3.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders, through the
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year ended December 31, 1999.
- 15 -
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 58 Chairman of the Board of Directors, President
and Chief Executive Officer December 31, 1998
Robert L. Fiscus 62 Vice Chairman of the Board of Directors, Chief
Financial Officer, Treasurer and Secretary October 25, 1999
James F. Crowe 57 Group Vice President Power Supply Services October 1, 1996
Albert N. Henricksen 58 Group Vice President Support Services October 1, 1996
Anthony J. Vallillo 51 Group Vice President Client Services October 1, 1996
Rita L. Bowlby 61 Vice President Corporate Affairs February 1, 1993
Stephen F. Goldschmidt 54 Vice President Planning May 1, 1999
James L. Benjamin 58 Controller January 1, 1981
Charles J. Pepe 51 Assistant Treasurer and Assistant Secretary January 1, 1994
There is no family relationship between any director, executive officer, or
person nominated or chosen to become a director or executive officer of the
Company. All executive officers of the Company hold office during the pleasure
of the Company's Board of Directors. All of the above executive officers have
entered into employment agreements with the Company. There is no arrangement or
understanding between any executive officer of the Company and any other person
pursuant to which such officer was selected as an officer.
A brief account of the business experience during the past five years of
each executive officer of the Company is as follows:
NATHANIEL D. WOODSON. Mr. Woodson served as Vice President and General
Manager of the Energy Systems Business Unit of Westinghouse Electric Corporation
during the period January 1, 1995 to April 30, 1996. He served as President of
the Company during the period February 23, 1998 to May 20, 1998 and President
and Chief Executive Officer during the period May 20, 1998 to December 31, 1998.
He has served as Chairman of the Board of Directors, President and Chief
Executive Officer since December 31, 1998.
ROBERT L. FISCUS. Mr. Fiscus served as President and Chief Financial
Officer during the period January 1, 1995 to February 23, 1998, and as Vice
Chairman of the Board of Directors and Chief Financial Officer from February 23,
1998 to October 25, 1999. He has served as Vice Chairman of the Board of
Directors, Chief Financial Officer, Treasurer and Secretary since October 25,
1999.
JAMES F. CROWE. Mr. Crowe served as Executive Vice President and Chief
Customer Officer during the period January 1, 1995 to October 1, 1996. He has
served as Group Vice President Power Supply Services since October 1, 1996.
ALBERT N. HENRICKSEN. Mr. Henricksen served as Vice
President-Administration during the period January 1, 1995 to October 1, 1996.
He has served as Group Vice President Support Services since October 1, 1996.
ANTHONY J. VALLILLO. Mr. Vallillo served as Vice President-Marketing during
the period January 1, 1995 to October 1, 1996. He has served as Group Vice
President Client Services since October 1, 1996.
RITA L. BOWLBY. Ms. Bowlby has served as Vice President-Corporate Affairs
of the Company during the five-year period.
- 16 -
STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served as Vice
President-Information Resources during the period January 1, 1995 to October 1,
1996, and as Vice President Planning and Information Resources from October 1,
1996 to May 1, 1999. He has served as Vice President Planning since May 1, 1999.
JAMES L. BENJAMIN. Mr. Benjamin has served as Controller of the Company
during the five-year period.
CHARLES J. PEPE. Mr. Pepe has served as Assistant Treasurer and Assistant
Secretary of the Company during the five-year period.
PART II
Item 5. Market for the Company's Common Equity and Related Stockholder Matters.
The Company 's Common Stock is traded on the New York Stock Exchange, where
the high and low sale prices during 1999 and 1998 were as follows:
1999 SALE PRICE 1998 SALE PRICE
--------------- ---------------
HIGH LOW HIGH LOW
---- --- ---- ---
First Quarter 52 11/16 41 7/8 48 9/16 42 5/8
Second Quarter 44 11/16 39 5/16 51 15/16 46 15/16
Third Quarter 50 11/16 43 1/8 53 9/16 49
Fourth Quarter 53 3/16 47 15/16 53 3/4 48 1/16
The Company has paid quarterly dividends on its Common Stock since 1900.
The quarterly dividends declared in 1998 and 1999 were at a rate of 72 cents per
share.
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$117.3 million were free from such limitations at December 31, 1999.
As of December 31, 1999, there were 13,664 Common Stock shareowners of
record.
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[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997
=====================================================================================================================
FINANCIAL RESULTS OF OPERATION ($000'S)
Sales of electricity
Retail
Residential $271,605 $262,974 $259,325
Commercial 256,246 254,765 248,490
Industrial 100,437 102,201 102,763
Other 11,308 11,667 11,755
------------- ------------- -------------
Total Retail 639,596 631,607 622,333
Wholesale (1) 24,334 44,948 82,871
Other operating revenues 16,045 9,636 3,825
------------- ------------- -------------
Total operating revenues 679,975 686,191 709,029
------------- ------------- -------------
Fuel and interchange energy -net
Retail -own load 134,851 116,769 109,542
Wholesale 24,552 34,775 73,124
Capacity purchased-net 33,873 34,515 39,976
Depreciation 57,351 82,809 (3) 74,618 (3)
Other amortization, principally deferred return, cancelled plant
and regulatory tax assets 36,393 13,758 13,758
Other operating expenses, excluding tax expense 185,696 188,946 200,803
Gross earnings tax 24,518 24,039 23,571
Other non-income taxes 22,622 40,635 (4) 28,922
------------- ------------- -------------
Total operating expenses, excluding income taxes 519,856 536,246 564,314
------------- ------------- -------------
Deferred return - Seabrook Unit 1 0 0 0
AFUDC 2,235 468 1,575
Other non-operating income(loss) (838) 1,097 (5) 1,361
Interest expense
Long-term debt - net 35,260 42,836 56,158
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other 7,319 9,018 6,068
------------- ------------- -------------
Total 47,392 56,667 67,039
------------- ------------- -------------
Income tax expense
Operating income tax 66,564 53,619 40,833 (6)
Non-operating income tax (4,664) (3,848) (3,678)
------------- ------------- -------------
Total 61,900 49,771 37,155
------------- ------------- -------------
Income before cumulative effect of accounting change 52,224 45,072 43,457
Cumulative effect of change in accounting - net of tax 0 0 0
------------- ------------- -------------
Net income 52,224 45,072 43,457
Premium (Discount) on preferred stock redemption 53 (21) (48)
Preferred and preference stock dividends 66 201 205
------------- ------------- -------------
Income applicable to common stock $52,105 $44,892 $43,300
---------------------------------------------------------------------------------------------------------------------
Operating income $93,555 $96,326 $103,882
=====================================================================================================================
FINANCIAL CONDITION ($000'S)
Plant in service-net $474,656 (12) $1,172,555 $1,222,174
Construction work in progress 25,708 33,695 25,448
Other property and investments 152,948 (13) 58,047 58,441
Current assets 220,126 305,189 204,474
Deferred charges and regulatory assets 924,772 (12) 371,674 408,993
------------- ------------- -------------
Total Assets $1,798,210 $1,941,160 $1,919,530
---------------------------------------------------------------------------------------------------------------------
Common stock equity $458,298 $445,507 $436,081
Preferred, preference stock and company-obligated mandatorily
redeemable securities of subsidiaries holding solel
parent debentures 50,000 54,299 54,351
Long-term debt excluding current portion 518,228 664,510 644,670
Noncurrent liabilities (9) 245,268 109,981 119,868
Current portion of long-term debt 25,000 66,202 100,000
Notes payable 17,131 86,892 37,751
Other current liabilities (9) 166,213 172,830 175,340
Deferred income tax liabilities and other 318,072 340,939 351,469
------------- ------------- -------------
Total Capitalization and Liabilities $1,798,210 $1,941,160 $1,919,530
=====================================================================================================================
(1) Operating Revenues, for years prior to 1992, include wholesale power
exchange contract sales that were reclassified from Fuel and Capacity
expenses in accordance with Federal Energy Regulatory Commission
requirements.
(2) Includes reclassification of certain Commercial and Industrial customers.
(3) Includes the before-tax effect of charges for additional amortization of
conservation & load management costs: $13.1 million in 1998 and $6.6
million in 1997.
(4) Includes the effect of charges of $14.0 million, before-tax, associated
with property tax settlement.
(5) Includes the before-tax effect of charges for losses associated with
unregulated subsidiaries: $2.8 million in 1997 and $5.8 million in 1996.
(6) Includes the effect of credits of $6.7 million to provide tax provision for
fossil generation decommissioning.
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[Enlarge/Download Table]
1996 1995 1994 1993 1992 1991 1990
==========================================================================================================
$266,068 $260,694 $252,386 $238,185 $226,455 $226,751 $211,891
264,111 259,715 250,771 (2) 256,559 253,456 (2) 255,782 234,704
109,032 106,963 104,242 (2) 97,466 97,010 (2) 91,895 94,526
11,903 11,736 11,469 11,349 11,065 10,886 10,536
---------------- ----------- ----------- ------------ ----------- ----------- ------------
651,114 639,108 618,868 603,559 587,986 585,314 551,657
72,844 48,232 34,927 45,931 75,484 84,236 85,657
3,300 3,109 2,953 3,533 3,855 3,821 3,332
---------------- ----------- ----------- ------------ ----------- ----------- ------------
727,258 690,449 656,748 653,023 667,325 673,371 640,646
---------------- ----------- ----------- ------------ ----------- ----------- ------------
95,359 96,538 99,589 98,694 108,084 123,010 119,285
65,158 41,631 27,765 39,356 55,169 61,858 69,117
46,830 47,420 44,769 47,424 43,560 44,668 42,827
65,921 61,426 58,165 56,287 50,706 48,181 36,526
13,758 13,758 1,172 1,780 10,415 10,415 4,173
219,630 (7) 183,749 193,098 203,427 (10) 183,426 178,912 176,419
26,804 27,379 27,403 27,955 27,362 27,223 25,595
30,382 31,564 32,458 29,977 31,869 28,673 24,648
---------------- ----------- ----------- ------------ ----------- ----------- ------------
563,842 503,465 484,419 504,900 510,591 522,940 498,590
---------------- ----------- ----------- ------------ ----------- ----------- ------------
0 0 0 7,497 15,959 17,970 21,503
2,375 2,762 3,463 4,067 3,232 5,190 3,443
(8,445) (5) (5,068) (1,907) 71 18,545 2,697 22,654
65,046 63,431 73,772 80,030 88,666 90,296 94,056
4,813 3,583 0 0 0 0 0
4,721 12,841 10,301 12,260 12,882 9,847 15,468
---------------- ----------- ----------- ------------ ----------- ----------- ------------
74,580 79,855 84,073 92,290 101,548 100,143 109,524
---------------- ----------- ----------- ------------ ----------- ----------- ------------
53,590 59,828 44,937 33,309 48,712 47,231 43,493
(9,869) (4,901) (3,214) (6,322) (12,558) (19,299) (17,409)
---------------- ----------- ----------- ------------ ----------- ----------- ------------
43,721 54,927 41,723 26,987 36,154 27,932 26,084
---------------- ----------- ----------- ------------ ----------- ----------- ------------
39,045 49,896 48,089 40,481 56,768 48,213 54,048
0 0 (1,294) 0 0 7,337 0
---------------- ----------- ----------- ------------ ----------- ----------- ------------
39,045 (8) 49,896 46,795 40,481 (11) 56,768 55,550 54,048
(1,840) (2,183) 0 0 0 0 0
330 1,329 3,323 4,318 4,338 4,530 4,751
---------------- ----------- ----------- ------------ ----------- ----------- ------------
$40,555 $50,750 $43,472 $36,163 $52,430 $51,020 $49,297
----------------------------------------------------------------------------------------------------------
$109,826 $127,156 $127,392 $114,814 $108,022 $103,200 $98,563
==========================================================================================================
$1,258,306 $1,277,910 $1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173
40,998 41,817 57,669 77,395 59,809 54,771 50,257
49,091 53,355 53,267 58,096 65,320 79,009 90,006
199,097 136,481 157,309 187,981 247,954 164,839 161,066
449,150 475,258 538,601 567,394 556,493 554,365 553,986
---------------- ----------- ----------- ------------ ----------- ----------- ------------
$1,996,642 $1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488
----------------------------------------------------------------------------------------------------------
$439,468 $439,484 $428,028 $423,324 $422,746 $401,771 $379,812
54,461 60,539 44,700 60,945 60,945 62,640 69,700
759,680 845,684 708,340 875,268 893,457 909,998 899,993
138,816 65,747 59,458 62,666 44,567 110,217 110,850
69,900 40,800 193,133 143,333 92,833 37,500 41,667
10,965 0 67,000 0 84,099 13,000 15,000
166,138 102,336 122,084 117,343 114,757 114,280 138,173
357,214 430,231 452,248 451,413 440,230 423,449 409,293
---------------- ----------- ----------- ------------ ----------- ----------- ------------
$1,996,642 $1,984,821 $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488
==========================================================================================================
(7) Includes the effect of charges of $23.0 million, before-tax, associated
with voluntary early retirement programs.
(8) Includes the effect of charges of $13.4 million, after-tax, associated with
voluntary early retirement programs.
(9) Amounts for years prior to 1996 were reclassified in 1996.
(10) Includes the effect of a reorganization charge of $13.6 million,
before-tax, associated with a voluntary early retirement program.
(11) Includes the effect of a reorganization charge of $7.8 million, after-tax.
(12) Reflects reclassification of $518.3 million of nuclear assets from plant in
service to regulatory asset.
(13) Includes $83.5 million investment in a generation facility as of December
31, 1999.
- 19 -
[Enlarge/Download Table]
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
1999 1998 1997
=================================================================================================================
COMMON STOCK DATA
Average number of shares outstanding 14,052,091 14,017,644 13,975,802
Number of shares outstanding at year-end 14,062,502 14,034,562 13,907,824
Earnings per share (average) - basic $3.71 $3.20 $3.10
Earnings per share (average) - diluted $3.71 $3.20 $3.09
Book value per share $32.59 $31.74 $31.35
Average return on equity
Total 11.45% 9.44% 10.45%
Utility 14.00% 11.43% 11.54%
Dividends declared per share $2.88 $2.88 $2.88
Market Price:
High $53.188 $53.750 $45.938
Low $39.313 $42.625 $24.500
Year-end $51.375 $51.500 $45.938
=================================================================================================================
Net cash provided by operating activities, less dividends ($000's) $57,907 $71,566 $132,189
Capital expenditures, excluding AFUDC $34,772 $38,040 $33,436
=================================================================================================================
OTHER FINANCIAL AND STATISTICAL DATA
Sales by class (MWh's)
Residential 2,053,927 1,924,724 1,899,284
Commercial 2,388,240 2,324,507 2,248,974
Industrial 1,161,856 1,154,935 1,168,470
Other 48,027 48,166 48,619
------------- ------------- -------------
Total 5,652,050 5,452,332 5,365,347
------------- ------------- -------------
Number of retail customers by class (average)
Residential 282,986 281,591 280,283
Commercial 29,757 29,468 29,228
Industrial 1,746 1,752 1,697
Other 1,185 1,172 1,163
------------- ------------- -------------
Total 315,674 313,983 312,371
------------- ------------- -------------
Revenue per kilowatt hour by class (cents)
Residential 13.22 13.66 13.65
Commercial 10.73 10.96 11.05
Industrial 8.64 8.85 8.79
Average large industrial customers time of use rate (cents) 8.21 8.16 8.12
-----------------------------------------------------------------------------------------------------------------
Revenues - retail sales ($000's)
Base $655,327 $629,446 $620,636
Base rate adjustments (15,731) 2,161 1,697
Sales provision adjustment 0 0 0
------------- ------------- -------------
Total $639,596 $631,607 $622,333
------------- ------------- -------------
Revenues - retail sales per kWh (cents)
Base 11.59 11.54 11.57
Base rate adjustments (0.28) 0.04 0.03
Sales provision adjustment 0.00 0.00 0.00
------------- ------------- -------------
Total 11.31 11.58 11.60
------------- ------------- -------------
Fuel and energy cost per kWh (cents) 2.27 2.04 1.95
Fossil 3.02 2.60 2.39
Nuclear 0.58 0.58 0.61
-----------------------------------------------------------------------------------------------------------------
Number of employees at year-end 1,239 1,193 1,175
Total utility employees payroll($000 'S) $66,155 $65,294 $68,640
=================================================================================================================
(1) Includes reclassification of certain Commercial and Industrial customers.
- 20 -
[Enlarge/Download Table]
1996 1995 1994 1993 1992 1991 1990
==========================================================================================================
14,100,806 14,089,835 14,085,452 14,063,854 13,941,150 13,899,906 13,887,748
14,101,291 14,100,091 14,086,691 14,083,291 14,033,148 13,932,348 13,887,748
$2.88 $3.60 $3.09 $2.57 $3.76 $3.67 $3.55
$2.87 $3.59 $3.08 $2.56 $3.74 $3.66 $3.55
$31.16 $31.16 $30.39 $30.06 $30.12 $28.84 $27.35
9.20% 11.84% 10.19% 8.45% 12.67% 13.01% 13.39%
11.51% 13.04% 12.50% 10.97% 14.46% 13.39% 13.97%
$2.88 $2.82 $2.76 $2.66 $2.56 $2.44 $2.32
$39.750 $38.500 $39.500 $45.875 $42.000 $39.125 $34.125
$31.375 $29.500 $29.000 $38.500 $34.125 $30.000 $26.875
$31.375 $37.375 $29.500 $40.250 $41.500 $39.000 $31.125
==========================================================================================================
$120,624 $120,033 $94,807 $104,547 $109,020 $73,865 $39,189
$47,174 $59,363 $63,044 $94,743 $66,390 $63,157 $64,018
==========================================================================================================
1,895,804 1,890,575 1,892,955 1,844,041 1,799,456 1,851,447 1,826,700
2,263,056 2,273,965 2,285,942 (1) 2,359,023 2,303,216 (1) 2,347,757 2,259,340
1,143,410 1,126,458 1,135,831 (1) 1,036,547 997,168 (1) 980,071 1,060,751
48,388 48,435 48,718 50,715 52,984 55,118 58,013
---------------- ----------- ----------- ------------ ----------- ----------- ------------
5,350,658 5,339,433 5,363,446 5,290,326 5,152,824 5,234,393 5,204,804
---------------- ----------- ----------- ------------ ----------- ----------- ------------
279,024 278,326 275,441 273,752 273,936 274,064 275,637
28,666 28,550 28,394 (1) 28,968 28,848 (1) 29,768 29,808
1,652 1,599 1,538 (1) 959 1,017 (1) 268 319
1,141 1,122 1,127 1,175 1,358 1,361 1,352
---------------- ----------- ----------- ------------ ----------- ----------- ------------
310,483 309,597 306,500 304,854 305,159 305,461 307,116
---------------- ----------- ----------- ------------ ----------- ----------- ------------
14.03 13.79 13.33 12.92 12.58 12.25 11.60
11.67 11.42 10.97 10.88 11.00 10.89 10.39
9.54 9.50 9.18 9.40 9.73 9.38 8.91
8.26 8.53 8.69 8.89 8.84 8.64 8.06
----------------------------------------------------------------------------------------------------------
$643,344 $637,219 $619,097 $605,887 $608,176 $607,997 $589,346
7,770 1,889 (229) (2,328) (41,221) (37,497) (45,900)
0 0 0 0 21,031 14,814 8,211
---------------- ----------- ----------- ------------ ----------- ----------- ------------
$651,114 $639,108 $618,868 $603,559 $587,986 $585,314 $551,657
---------------- ----------- ----------- ------------ ----------- ----------- ------------
12.02 11.93 11.54 11.45 11.80 11.62 11.32
0.15 0.04 0.00 (0.04) (0.80) (0.72) (0.88)
0.00 0.00 0.00 0.00 0.41 0.28 0.16
---------------- ----------- ----------- ------------ ----------- ----------- ------------
12.17 11.97 11.54 11.41 11.41 11.18 10.60
---------------- ----------- ----------- ------------ ----------- ----------- ------------
1.69 1.71 1.76 1.75 2.43 2.67 2.63
2.41 2.22 2.14 2.08 2.98 3.11 2.89
0.46 0.85 0.94 1.23 1.42 1.62 1.55
----------------------------------------------------------------------------------------------------------
1,287 1,358 1,377 1,490 1,554 1,571 1,587
$69,276 $72,984 $75,441 $75,305 $74,052 $71,888 $69,237
==========================================================================================================
- 21 -
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its utility retail sales and the Company's ability to control expenses,
as well as on the performance of the non-regulated businesses of the Company's
subsidiaries. The two primary factors that affect utility sales volume are
economic conditions and weather. Total utility operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, declined
by 1.6%, on average, during the five years 1995-1999.
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and
regulations.
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized one-third for customer price reductions, one-third to increase
amortization of assets, and one-third retained as earnings. As a result of the
Rate Plan, customer prices were required to be reduced, on average, by 3% in
1997 compared to 1996. Also as a result of the Rate Plan, customer prices were
required to be reduced by an additional 1% in 2000, and another 1% in 2001,
compared to 1996. Retail revenues decreased by approximately 7.0% through 1999
compared to 1996 due to customer price reductions. The Rate Plan was reopened in
1998, in accordance with its terms, to determine the assets to be subjected to
accelerated recovery in 1999. The DPUC decided on February 10, 1999 to subject
$12.1 million of the Company's regulatory tax assets to accelerated recovery in
1999.
The Rate Plan includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999, the DPUC issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates, as directed by the Restructuring Act described in detail below.
These standard offer customer rates are in effect for the period 2000-2001 and
supercede the rate reductions for this period that were included in the Rate
Plan. The decision also reduced the required amount of accelerated amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect through 2001. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. As a result of the Act, the business of
generating and selling electricity directly to consumers is opened to
competition. These business activities are separated from the business of
delivering electricity to consumers, also known as the transmission and
distribution business. The business of delivering electricity remains with the
incumbent franchised utility companies (including the Company), which continues
to be regulated by the DPUC as Distribution Companies. Since mid-1999,
Distribution Companies have been required to separate on consumers' bills the
electricity generation services component from the charge for delivering the
electricity and all other charges.
- 22 -
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge." The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interests in its nuclear-fueled power plants prior to 2004.
On October 2, 1998, the Company agreed to sell both of its operating
fossil-fueled generating stations, Bridgeport Harbor Station and New Haven
Harbor Station, to Wisvest-Connecticut, LLC, a single-purpose subsidiary of
Wisvest Corporation. Wisvest Corporation is a non-utility subsidiary of
Wisconsin Energy Corporation, Milwaukee, Wisconsin On April 16, 1999, the
transaction closed and the Company received approximately $277.9 million from
this sale. The Company realized a before-tax book gain of $86.5 million from the
sale of these plant investments. However, under the Restructuring Act, this gain
was offset by a writedown of the stranded costs eligible for collection by the
Company under the Restructuring Act's competitive transition assessment, such
that there was no net income effect of the sale. The Company used the net cash
proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, and in other regulatory dockets, the Company stated that
it plans to divest its nuclear generation ownership interests (17.5% of Seabrook
Unit 1 in New Hampshire and 3.685% of Millstone Station Unit 3 in Connecticut)
by the end of 2003, in accordance with the Restructuring Act. The DPUC is
currently considering the Company's plan for divesting its ownership interest in
Millstone Unit 3 through an auction process to be conducted by a consultant to
be selected by the DPUC. The divestiture process for Seabrook Unit 1 has not yet
been determined. In anticipation of ultimate divestiture, the Company has
satisfied the Restructuring Act's requirement that nuclear generating assets be
separated from its transmission and distribution assets. This was accomplished
by transferring the nuclear generating assets into a separate new division of
the Company, using divisional financial statements and accounting to segregate
all revenues, expenses, assets and liabilities associated with nuclear ownership
interests. In a decision dated May 19, 1999, the DPUC approved the Company's
proposal in this regard.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998 and, in a decision dated May 19, 1999, the DPUC approved the
proposed corporate restructuring. The Company has filed applications with the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission
seeking approval of the proposed corporate restructuring, and a special meeting
of the Company's shareowners will be held on March 17, 2000 to vote on approval
of the restructuring.
- 23 -
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the market value of the
Company's generating assets in an appeal taken to the Superior Court from the
DPUC's decision.
Under the Restructuring Act, retail customers representing a total of up
to 35% of the Company's retail customer load became able to choose their power
supply providers on and after January 1, 2000, and all of the Company's
customers will be able to choose their power supply providers as of July 1,
2000. On and after January 1, 2000 and through December 31, 2003, the Company is
required to offer fully-bundled "standard offer" electric service, under
regulated rates, to all customers who do not choose an alternate power supply
provider. The standard offer rates must include the fully-bundled price of
generation, transmission and distribution services, the competitive transition
assessment, the systems benefits charge and the conservation and renewable
energy charges. The fully-bundled standard offer rates must also be at least 10%
below the average fully-bundled prices in 1996.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be under the above requirements of the
Restructuring Act. In April, May and June of 1999, the Company filed descriptive
material, data and supporting testimony with the DPUC setting forth the
Company's overall approach for determining the components of its standard offer
rates, and for continuation of the five-year Rate Plan ordered by the DPUC in
its 1996 financial and operational review of the Company (see above) through the
four-year standard offer period. On July 27, 1999, the Company and Enron Capital
& Trade Resources Corp. (ECTR), an affiliate of Enron Corp., Houston, Texas
(Enron) filed with the DPUC a joint stipulation and settlement proposal to
resolve simultaneously all of the issues in the Company's standard offer rate
proceeding. The proposal included an arrangement between the Company and ECTR
whereby ECTR will supply all of the generation services needed by the Company to
meet its standard offer obligations for the four-year standard offer period, and
an assumption by ECTR of all of the Company's long-term purchased power
agreement (PPA) obligations. The stipulation and settlement proposal also
provided for the Company's standard offer rates at a fully-bundled level that
complies with the 10% reduction required by the Restructuring Act, including the
generation services component of these rates, the Company's stranded costs for
purposes of future recovery, the competitive transition assessment, systems
benefits charge, delivery (transmission and distribution) charges, and
conservation, load management and renewable energy charges. The Company also
requested that a purchased power adjustment clause authorized by the
Restructuring Act be put in place to adjust standard offer rates for limited
purposes, and that the Company's five-year Rate Plan, as modified and
supplemented by the stipulation and settlement proposal, be continued during the
four-year standard offer period. In its decision, dated October 1, 1999, on the
Company's standard offer rates, the DPUC approved elements of the stipulation
and settlement proposal, including the arrangements with ECTR, subject to
specified changes, including changes in the level of the generation services
component of customers' rates. On October 15, 1999, the Company filed its
standard offer generation services component of rates in compliance with the
DPUC's decision, and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal. These filings were approved by the DPUC on
December 9, 1999 and, on December 28, 1999, the Company and Enron Power
Marketing, Inc. (EPMI), another affiliate of Enron, entered into a Wholesale
Power Supply Agreement, a PPA Entitlements Transfer Agreement and related
agreements documenting the approved four-year standard offer power supply
arrangement and the assumption of all of the Company's PPAs, effective January
1, 2000. From January 1, 2000 through June 30, 2000, EPMI will sell to the
Company energy beyond that supplied by Wisvest as described above. The
agreements also provide for the sale to EPMI of the Company's entitlements under
all of its wholesale purchased power agreements (PPAs). However, unless or until
a PPA is terminated or formally assigned to EPMI, the Company remains legally
liable to pay the applicable power supplier all
- 24 -
amounts due under the PPA. The agreements with EPMI also include a financially
settled contract for differences related to certain call rights of EPMI and put
rights of the Company with respect to the Company's entitlements in Seabrook
Unit 1 and in Millstone Unit 3, and the Company's provision to EPMI of certain
ancillary products and services associated with those nuclear entitlements,
which provisions terminate at the earlier of December 31, 2003 or the date that
the Company sells its nuclear interests. The agreements do not restrict the
Company's right to sell to third parties the Company's ownership interests in
those nuclear generation units or the generated energy actually attributable to
its ownership interests.
Based on the decisions in the regulatory proceedings described above, the
sale of the Company's fossil-generation assets in the second quarter of 1999,
the planned divestiture of its nuclear generation ownership interests by the end
of 2003, and in anticipation of the Restructuring Act becoming effective on
January 1, 2000, the Company ceased applying SFAS No. 71 to the generation
portion of its assets and operations as of December 31, 1999. Based on the
favorable DPUC decisions that allow full recovery, through the Company's rates,
of all historically incurred stranded costs, the Company did not record any
write-offs in connection with this event.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are presently projected as follows:
[Enlarge/Download Table]
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(millions)
Cash on Hand - Beginning of Year (1) $39.1 $ - $ - $ - $ -
Internally Generated Funds less Dividends (2) 76.5 87.8 88.8 98.9 76.7
----- ---- ---- ---- ----
Subtotal 115.6 87.8 88.8 98.9 76.7
Less:
Utility Capital Expenditures (2) 58.1 36.1 18.9 21.8 30.8
Non-Regulated Business Capital Expenditures 4.3 5.4 3.9 4.0 4.2
---- ---- ---- ---- ----
Cash Available to pay Debt Maturities and Redemptions 53.2 46.3 66.0 73.1 41.7
Less:
Maturities and Mandatory Redemptions - - 100.0 100.0 -
Optional Redemptions 75.0 - - - -
Repayment of Short-Term Borrowings 17.0 - - - -
---- ---- ----- ----- ----
External Financing Requirements (Surplus) (2) $38.8 $(46.3) $34.0 $26.9 $(41.7)
==== ===== ==== ==== =====
(1) Excludes $2.3 million Seabrook Unit 1 operating deposit and restricted cash
of American Payment Systems, Inc. of $26.9 million.
(2) Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections. All of these estimates are subject to change due to
future events and conditions that may be substantially different from those
used in developing the projections.
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $60
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
additional short-term and long-term debt. The continued availability of these
methods of financing will be dependent on many factors, including conditions in
the securities markets, economic conditions, and the level of the Company's
income and cash flow.
On January 16, 1999, the Company repaid $66.2 million principal amount of
6.20% Notes at maturity.
- 25 -
On February 1, 1999, the Company converted $7.5 million principal amount of
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and interest is payable semi-annually on
August 1 and February 1. In addition, on February 1, 1999, the Company converted
$98.5 million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds is
payable semi-annually on August 1 and February 1.
On March 8, 1999, the Company prepaid and terminated $20 million of the
remaining $70 million outstanding debt under its $150 million Term Loan
Agreement dated August 29, 1995. On April 16, 1999, the Company prepaid and
terminated the entire remaining $50 million outstanding debt under said $150
million Term Loan Agreement, and the entire $75 million outstanding debt under
its Term Loan Agreement dated October 25, 1996.
On April 8, 1999, the Company called for redemption all 10,370 shares of
its outstanding $100 par value 4.35% Preferred Stock, Series A, all 17,158
shares of its outstanding $100 par value 4.72% Preferred Stock, Series B, all
12,745 shares of its outstanding $100 par value 4.64% Preferred Stock, Series C
and all 2,712 shares of its outstanding $100 par value 5 5/8% Preferred Stock,
Series D. The Company paid a redemption premium of $53,355 in effecting these
redemptions, which were completed on May 14, 1999.
On December 16, 1999, the Company borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $25 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2029, and
their interest rate is fixed at 5.4% for the three-year period ending December
1, 2002. At December 31, 1999, these proceeds were held by a trustee and were
recognized as cash and long-term debt on the Consolidated Balance Sheet. The
Company has used the proceeds of this $25 million borrowing to cause the
redemption and repayment of $25 million of 8.0%, 1989 Series A, Pollution
Control Revenue Bonds, an outstanding series of tax-exempt bonds on which the
Company also had a payment obligation to a trustee for the bondholders. Expenses
associated with this transaction, including redemption premiums totaling
$750,000 and other expenses of approximately $417,000, were paid by the Company.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London. If a material adverse change in the business, operations, affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries, on a consolidated basis, should occur, the banks may decline to
lend additional money to the Company under this revolving credit agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and payable. As of December 31, 1999, the Company had $17 million in
short-term borrowings outstanding under this facility.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1999, this coverage ratio was 4.7:1.0.
The provisions of the financing documents under which the Company leases a
portion of its entitlement in Seabrook Unit 1 from an owner trust established
for the benefit of an institutional investor presently require the Company to
maintain its consolidated annual after-tax cash earnings available for the
payment of interest at a level that is at least one and one-half times the
aggregate interest charges paid on all indebtedness outstanding during the year.
- 26 -
On the basis of the formula contained in the Seabrook Unit 1 lease financing
documents, the coverage for the year ended December 31, 1999 was 4.7.
The Company is obligated to furnish a guarantee for its participating share
of the debt financing for the Hydro-Quebec Phase II transmission intertie
facility linking New England and Quebec, Canada. As of December 31, 1999, the
Company's guarantee liability for this debt was approximately $6.2 million.
At December 31, 1999, the Company had $68.3 million of cash and temporary
cash investments, a decrease of $56.2 million from the corresponding balance at
December 31, 1998. The components of this decrease, which are detailed in the
Consolidated Statement of Cash Flows, are summarized as follows:
(Millions)
--------
Balance, December 31, 1998 $124.5
-----
Net cash provided by operating activities 98.5
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (266.9)
- Dividend payments (40.6)
Investment in debt securities 5.5
Net cash provided from sale of generation assets 270.6
Cash invested in unregulated businesses (88.5)
Cash invested in plant, including nuclear fuel (34.8)
-----
Net Change in Cash (56.2)
-----
Balance, December 31, 1999 $68.3
=====
SUBSIDIARY OPERATIONS
The Company has one wholly-owned subsidiary, United Resources, Inc. (URI),
that serves as the parent corporation for several unregulated businesses, each
of which is incorporated separately to participate in business ventures that
will complement the Company's regulated electric utility business and provide
long-term rewards to the Company 's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
- 27 -
The after-tax impact of the subsidiaries on the consolidated financial
statements of the Company is as follows:
ASSETS
NET LOSS LOSS AT DEC. 31
(000'S) PER SHARE (000'S)
-------- --------- ----------
(Basic & Diluted)
1999 $2,256 $0.16 $194,642
1998 1,111 0.08 83,306
1997 2,185 0.16 69,338
In 1997, the Company made provisions for losses of $1.6 million (after-tax)
associated with collection agent errors and defaults and miscellaneous other
items at its American Payment Systems, Inc. subsidiary.
NEW ACCOUNTING STANDARDS
See the discussion included in PART II, Item 8, "Financial Statements and
Supplementary Data - Notes to Consolidated Financial Statements - Note (A),
Statement of Accounting Policies."
RESULTS OF OPERATIONS
1999 VS. 1998
-------------
Earnings for the twelve months of 1999 were $52.1 million, or $3.71 per
share (on both a basic and diluted basis), up $7.2 million, or $.51 per share,
from the twelve months of 1998. Excluding one-time items recorded during both
periods, earnings from operations for 1999 were $51.5 million, or $3.67 per
share (on both a basic and diluted basis), up $3.7 million, or $.26 per share,
from the twelve months of 1998.
Earnings from operations for 1999 before earnings "sharing" were $5.09 per
share, $1.44 per share or 39% higher than 1998. "Sharing" reduced the 1999
earnings from operations to $3.67 per share.
The one-time items recorded in 1999 and 1998 were:
EPS
-------------- --------------------------------------------------------- -------
1999 Quarter 1 Purchased power expense refund $ .12
Sharing due to refund $(.08)
-------------- --------------------------------------------------------- -------
1998 Quarter 3 Refund of prior period transmission charges,
with interest $ .14
Sharing due to one time items recorded through
3rd quarter $(.05)
-------------- --------------------------------------------------------- -------
1998 Quarter 4 Property tax settlement with the City of New Haven $(.59)
Reversal of sharing imputed to property tax settlement $ .29
-------------- --------------------------------------------------------- -------
Utility Earnings from Operations
--------------------------------
Overall, retail sales margin decreased by $13.2 million in 1999 compared to
1998, and retail sales margin from operations decreased by $9.4 million. Retail
revenues from operations increased by $11.9 million as electric revenues
increased for the reasons detailed below. Retail revenues decreased by $3.9
million because of "sharing" required under the current regulatory structure as
applied to the one-time items recorded in both periods. Retail fuel and energy
expense from operations increased by $20.7 million, primarily from higher
purchased power prices as a result of the Company's transition from a producer
to a purchaser of its customers' energy requirements, and the need to purchase
additional energy to replace power lost from nuclear plant refueling outages.
The principal components of the retail sales margin change for 1999, compared to
1998, include:
- 28 -
[Enlarge/Download Table]
---------------------------------------------------------------- ----------- ---------- ----------
From From
Retail Sales Margin: $ millions Operations One-time Total
---------------------------------------------------------------- ----------- ---------- ----------
Revenue from:
---------------------------------------------------------------- ----------- ---------- ----------
Sharing: for 1999 (see Note A) (14.4) (3.9) (18.3)
---------------------------------------------------------------- ----------- ---------- ----------
Estimate of "real" retail sales growth, up 3.2% 20.2 0 20.2
---------------------------------------------------------------- ----------- ---------- ----------
Estimate of weather effect on retail sales, up 1.1% 7.1 0 7.1
---------------------------------------------------------------- ----------- ---------- ----------
Sales decrease from Yale University cogeneration, (0.6)% (3.6) 0 (3.6)
---------------------------------------------------------------- ----------- ---------- ----------
Price mix of sales and other 2.6 0 2.6
---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL REVENUE 11.9 (3.9) 8.0
---------------------------------------------------------------- ----------- ---------- ----------
REVENUE BASED TAXES (0.6) 0.1 (0.5)
---------------------------------------------------------------- ----------- ---------- ----------
Fuel and energy, margin effect:
---------------------------------------------------------------- ----------- ---------- ----------
Sales increase (4.7) 0 (4.7)
---------------------------------------------------------------- ----------- ---------- ----------
Nuclear fuel prices and outage replacement power costs (0.5) 0 (0.5)
---------------------------------------------------------------- ----------- ---------- ----------
Purchased energy prices (see Note B) (15.5) 0 (15.5)
---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL FUEL AND ENERGY (20.7) 0 (20.7)
---------------------------------------------------------------- ----------- ---------- ----------
TOTAL RETAIL SALES MARGIN (9.4) (3.8) (13.2)
---------------------------------------------------------------- ----------- ---------- ----------
A. The Company's preliminary return on regulated utility common stock
equity for the twelve months of 1999 exceeded the 11.5% "sharing"
trigger by a total amount of about $53 million of pre-tax income. As a
result, and excluding "sharing" associated with one-time items, a book
revenue "sharing" reduction from operations of $17.4 million,
including a gross earnings tax component, was recorded in 1999,
approximately $14.4 million more than the $3.0 million book revenue
"sharing" reduction imputed from operations in 1998. All 1998 sharing
from operations was offset by the impact of sharing associated with a
one-time item recorded in December of 1998.
B. On April 16, 1999, the Company completed the sale of its operating
fossil-fueled generating plants and existing wholesale sales contracts
that was required by Connecticut's electric utility industry
restructuring legislation. As a result, the "geography" of the
Company's costs on the income statement and, hence, the year-over-year
variances, changed significantly beginning in the second quarter. This
particularly relates to wholesale revenue, retail purchased energy and
fossil fuel expenses, operation and maintenance expense, depreciation,
interest charges and property taxes. For example, the increased
purchased energy costs included in the table above are more than
offset by some of the decline in miscellaneous operation and
maintenance expense, due principally to the sale of generating plants,
shown in the table below, and to decreases in depreciation and
property taxes.
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $10.4 million in 1999 compared to 1998 from lower wholesale sales. Other
operating revenues, which include NEPOOL related transmission revenues,
increased by $6.4 million. NEPOOL transmission revenues are recoveries, for the
most part, of NEPOOL transmission expense and simply reflect new accounting
requirements implemented by the Federal Energy Regulatory Commission.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $5.7 million in 1999 compared to 1998. The principal
components of these expense changes include:
- 29 -
$millions
--------------------------------------------------------------------- ----------
Capacity expense:
--------------------------------------------------------------------- ----------
Connecticut Yankee (2.4)
--------------------------------------------------------------------- ----------
Cogeneration and other purchases (see Note A) 1.8
--------------------------------------------------------------------- ----------
TOTAL CAPACITY EXPENSE (0.6)
--------------------------------------------------------------------- ----------
Other O&M expense:
--------------------------------------------------------------------- ----------
Seabrook Unit 1 (refueling outage costs and accruals) 4.1
--------------------------------------------------------------------- ----------
Millstone Unit 3 (refueling outage costs and accruals) 1.1
--------------------------------------------------------------------- ----------
Other expenses at nuclear units (0.8)
--------------------------------------------------------------------- ----------
Fossil generation unit operating and maintenance costs (23.1)
--------------------------------------------------------------------- ----------
NEPOOL transmission expense 3.4
--------------------------------------------------------------------- ----------
Site remediation costs (see Note B) 7.8
--------------------------------------------------------------------- ----------
Other miscellaneous, including impact of generation asset sale 2.4
--------------------------------------------------------------------- ----------
TOTAL O&M EXPENSE (5.1)
--------------------------------------------------------------------- ----------
Note A: A cogeneration facility was out of service for about a
month in the first quarter of 1998 but has operated normally in
1999.
Note B: These costs were incurred to repair a bulkhead at English
Station and for remediation of environmental conditions at
another site. No further material expenses are currently
anticipated for remediation of these sites.
Depreciation expense decreased by $12.4 million in 1999 compared to 1998,
due primarily to the generation asset sale.
On December 31, 1996, the Connecticut Department of Public Utility Control
issued an order that implemented a five-year Rate Plan to reduce the Company's
retail prices and accelerate the recovery of certain "regulatory assets."
According to the Rate Plan, under which the Company is currently operating,
"accelerated" amortization of past utility investments is scheduled for every
year that the Rate Plan is in effect, contingent upon the Company earning a
10.5% return on utility common stock equity. All of the scheduled accelerated
amortization for 1998, amounting to $13.1 million before-tax ($8.5 million
after-tax), was recorded against earnings from operations in 1998. The Company
recorded all of the scheduled accelerated amortization for 1999 by amortizing
regulatory income tax assets, totaling $12.1 million after-tax ($20 million
pre-tax equivalent).
The Company can also incur additional accelerated amortization expense as a
result of the "sharing" mechanism in the Rate Plan, if the Company achieves a
return on utility common stock equity above 11.5%, which the Company did achieve
during the third quarter of 1999. One-time items recorded against the return on
utility common stock equity, before the Company achieves the 11.5%, are recorded
with an appropriate "sharing" effect if the Company projects, at that time, that
there will be total "sharing" for the year adequate to cover the "sharing" for
the one-time item. Such "sharing" amortization was recorded in the first quarter
of 1999, in the amount of $1.0 million before-tax ($0.6 million after-tax), as a
result of the one-time gain recorded in that quarter. "Sharing" amortization
from operations of $10.0 million after-tax ($16.7 million before-tax) was
recorded in 1999. "Sharing" amortizations recorded and imputed in the first nine
months of 1998 were: $0.5 million before-tax ($0.3 million after-tax) as a
result of a one-time item, and $2.1 million before-tax ($1.2 million after-tax)
from operations. "Sharing" amortization recorded against earnings from
operations in the fourth quarter of 1998 was imputed to be $0.6 million
before-tax ($0.3 million after-tax). All of those 1998 "sharing" amortizations
were reversed in the fourth quarter of 1998 as a result of the impact of a
one-time charge recorded in that quarter.
Interest charges continued on a downward trend, decreasing by $12.8 million
for the regulated business in 1999 compared to 1998, partly offset by an
increase of $3.5 million in interest charges for non-regulated subsidiaries.
Most of the reduction in utility interest charges occurred after the generation
asset sale, which was completed on
- 30 -
April 16, 1999. On that date, the Company used proceeds received from the sale
of plant to pay off $205 million of debt.
Non-regulated Business Earnings from Operations
-----------------------------------------------
Overall, non-regulated businesses, after parent-allocated interest but
before income taxes, lost approximately $3.8 million in 1999 compared to losses
of about $1.8 million in 1998. American Payment Systems, Inc. (APS) earned
approximately $2.6 million (before-tax) in 1999, reflecting an increase of $1.0
million over 1998. Precision Power, Inc. (PPI) lost approximately $5.1 million
(before-tax) in 1999, compared to a loss of approximately $2.4 million in 1998,
reflecting increased infrastructure costs and lower than anticipated contract
margins.
On May 11, 1999, the Company's non-regulated subsidiary, United Bridgeport
Energy, Inc. (UBE), increased its 4% passive investment in Bridgeport Energy LLC
(BE) to 33 1/3%. The second phase of BE's merchant wholesale electric generating
project went into commercial operation in July 1999, adding 180 megawatts of
generation capacity for a total of 520 megawatts. UBE lost approximately $0.1
million (before-tax) in 1999, as a result of the second quarter shutdown of the
first phase generator to allow for construction of the second phase, and
additional unscheduled outages and higher gas prices in the fourth quarter of
1999. Other non-regulated subsidiary operations lost approximately $1.2 million
in 1999, compared to a similar loss in 1998.
Non-regulated business before-tax income is reported as part of "Other net"
income; parent interest charges allocated to the non-regulated businesses are
reported as part of "Interest charges"; and related income tax expense is
reported as part of "Non-operating income taxes."
[Enlarge/Download Table]
------------------------------------------------------------------ -------- ---------
12 mos.
ended 12 mos.
Summary of Non-regulated Business Unit Pre-tax Income: $millions Dec. 99 99 vs. 98
------------------------------------------------------------------ -------- ---------
American Payment Systems, Inc. 2.6 1.0
------------------------------------------------------------------ -------- ---------
Precision Power, Inc. (5.1) (2.7)
------------------------------------------------------------------ -------- ---------
United Bridgeport Energy, Inc. (0.1) (0.1)
------------------------------------------------------------------ -------- ---------
United Resources, Inc. Capital Projects (1.2) -
------------------------------------------------------------------ -------- ---------
TOTAL NON-REGULATED BUSINESSES (3.8) (1.8)
------------------------------------------------------------------ -------- ---------
1998 VS. 1997
-------------
Earnings for the twelve months of 1998 were $44.9 million, or $3.20 per
share (both basic and diluted), up $1.6 million, or $.11 per share, from the
twelve months of 1997, diluted. Excluding one-time items, accelerated
amortization due to one-time items and associated regulated "sharing" effects,
1998 earnings from operations were $47.8 million, or $3.41 per share, up $.48
per share from 1997. The one-time items and their earnings per share impacts
recorded in these periods are shown at "One-time items recorded in 1997 and
1998" below.
Retail operating revenues increased by about $9.3 million in the twelve
months of 1998 compared to 1997. Retail fuel and energy expense increased by
$7.2 million and there was an increase of $0.4 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $1.7 million. The principal components of the
retail sales margin change, year over year, include:
- 31 -
$ millions
------------------------------------------------------------------ ---------
Revenue from:
------------------------------------------------------------------ ---------
DPUC rate order, excluding "sharing" (1.3)
------------------------------------------------------------------ ---------
Other price changes (0.3)
------------------------------------------------------------------ ---------
Estimate of "real" retail sales growth, up 1.3% 12.1
------------------------------------------------------------------ ---------
Estimate of weather effect on retail sales, up 0.2 % 1.8
------------------------------------------------------------------ ---------
Sales decrease from Yale University cogeneration, (0.9) % (3.0)
------------------------------------------------------------------ ---------
TOTAL REVENUE IMPACT 9.3
------------------------------------------------------------------ ---------
Fuel and energy, margin effect:
------------------------------------------------------------------ ---------
Sales increase (2.7)
------------------------------------------------------------------ ---------
Increased nuclear availability 0.4
------------------------------------------------------------------ ---------
Unscheduled outage at Bridgeport Unit 3 (see Note A) (2.5)
------------------------------------------------------------------ ---------
Fossil price and other (2.4)
------------------------------------------------------------------ ---------
TOTAL FUEL AND ENERGY IMPACT (7.2)
------------------------------------------------------------------ ---------
Note A: Saltwater contamination caused a shutdown of the Bridgeport
Harbor Unit 3 generating unit on May 22, 1998. The unit
returned to full service on August 23, 1998.
Net wholesale margin (wholesale revenue less wholesale energy expense)
increased slightly in the twelve months of 1998 compared to the twelve months of
1997. Other operating revenues, which include NEPOOL related transmission
revenues, increased by $5.8 million.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $15.0 million in the twelve months of 1998 compared to the
twelve months of 1997. The principal components of these expense changes, year
over year, include:
$ millions
------------------------------------------------------------------ ---------
Capacity expense:
------------------------------------------------------------------ ---------
Connecticut Yankee preparing for decommissioning (4.2)
------------------------------------------------------------------ ---------
Cogeneration and other purchases (1.3)
------------------------------------------------------------------ ---------
Other O&M expense:
------------------------------------------------------------------ ---------
Seabrook (4.6)
------------------------------------------------------------------ ---------
Millstone Unit 3 (4.0)
------------------------------------------------------------------ ---------
Fossil generation unit overhauls and outages 7.5
------------------------------------------------------------------ ---------
Pension investment performance and assumptions (3.0)
------------------------------------------------------------------ ---------
Personnel reductions (6.0)
------------------------------------------------------------------ ---------
NEPOOL transmission expense 3.1
------------------------------------------------------------------ ---------
Other (2.5)
------------------------------------------------------------------ ---------
Depreciation expense, excluding accelerated amortization, increased by $1.5
million in the twelve months of 1998 compared to 1997. According to the
Company's current regulatory Rate Plan, "accelerated" amortization of past
utility investments is scheduled for every year that the Rate Plan is in effect,
contingent upon the Company earning a 10.5% return on utility common stock
equity. All of the accelerated amortization in 1997 was recorded ratably
throughout the year as a charge to depreciation expense. All of the accelerated
amortization for 1998, $13.1 million, was recorded against earnings from
operations. In addition, as part of the "sharing" mechanism, the Company would
have accrued an additional amortization of about $2.6 million ($1.7 million
after-tax) in 1998 against utility earnings from operations. Because of the
one-time items in 1998, no "sharing" was actually recorded. The one-time charge
for property tax expense incurred in the fourth quarter was a utility expense
and negated the "sharing" that would have occurred from operations.
- 32 -
Other net income from operations decreased by about $1.9 million in the
twelve months of 1998 compared to 1997. The Company's largest unregulated
subsidiary, American Payment Systems, Inc. (APS), earned about $1.6 million
(before-tax) in 1998 compared to a $2.7 million loss in 1997. This was more than
offset by greater losses, compared to 1997, in the Company's other unregulated
subsidiaries: $1.2 million (before-tax) at Precision Power, Inc. from the
write-off of previously deferred costs and a review of reserves, and $1.2
million (before-tax) from start-up costs in other unregulated activities. By
DPUC order, since consolidation at the unregulated subsidiary level produced no
net taxable income in either year, the tax benefits associated with the losses,
about $0.8 million in 1998 and $0.4 million in 1997, were treated as benefits to
utility income for the purposes of calculating return on utility common equity
and "sharing." Other net income also decreased due to the absence of other
non-utility income accruals of about $1 million made in 1997 that reversed a
provision for 1997 Millstone 3 expense made in 1996 and charged to operating
expenses in 1997, cancelled project costs of about $0.8 million for merger and
acquisition advisor fees and analysis and lower income from non-operating
utility investments.
Interest charges, excluding allowance for borrowed funds used during
construction, continued on their downward trend, decreasing by $10.4 million in
the twelve months of 1998 compared to 1997, as a result of the Company's
refinancing program and strong cash flow.
OVERVIEW OF "SHARING" AND THE IMPACT ON EARNINGS
------------------------------------------------
As previously indicated, the Company's regulatory Rate Plan requires a
"sharing" of regulated utility income that produces a return on utility equity
exceeding 11.5%. The measurement of this utility income and resulting return
calculation includes the effects of any utility one-time items. Under the Rate
Plan, one-third of the income above the 11.5% return would be applied to
customer bill reductions, one-third would be applied to additional amortization
of regulatory assets, and one-third would be retained by shareowners.
Earnings from operations, which excludes the impact of one-time items,
should reflect an appropriate imputed amount of "sharing" to reflect accurately
what the earnings would have been had neither the one-time items, nor their
impact on "sharing," occurred. The Company estimates that the "sharing" that
would have occurred had there been no one-time items in 1998 would have been: a
revenue reduction of about $3.0 million or $.12 per share, increased
amortization of about $1.7 million (after-tax) or $.12 per share, and retention
by the Company of $1.7 million of income (after-tax) or $.12 per share. To
summarize for 1998:
1998 Earnings per share (EPS) From One-time
Operations Items
and and "Sharing"
"Sharing" Reversals Total
--------- ------------- -----
Utility earnings before "sharing" $3.73 $(.45) $3.28
Less: Utility earnings to be "shared" (.36) .36 -
---- --- ----
Utility EPS at 11.5% utility return $3.37 $(.09) $3.28
Plus: 1/3 Retained "Sharing" benefit .12 (.12) -
---- ---- ----
Net Utility EPS 3.49 (.21) 3.28
Unregulated Subsidiaries (.08) - (.08)
---- ---- ----
Total 1998 EPS $3.41 $(.21) $3.20
Earnings reported through 3rd quarter 3.02 (.12) 2.90
---- ----- ----
Imputed 4th quarter earnings $ .39 $(.09) $ .30
==== ===== ====
- 33 -
ONE-TIME ITEMS RECORDED IN 1997 AND 1998
----------------------------------------
One-time Items EPS
--------------------------------------------------------------------------------
1997 Cumulative deferred operating income tax benefits associated $ .48
with future decommissioning of fossil fuel generating plants
(see explanation below)
--------------------------------------------------------------------------------
1997 Accelerated amortization associated with one-time item $(.30)
--------------------------------------------------------------------------------
1997 Gain from subleasing office space $ .05
--------------------------------------------------------------------------------
1997 Pension benefit adjustments associated with 1996 VERP and VSP $ .11
--------------------------------------------------------------------------------
1997 Contract termination charge $(.18)
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
1998 Refund of prior period transmission charges, with interest $ .14
"Sharing" due to one-time items recorded through third quarter $(.05)
--------------------------------------------------------------------------------
1998 Property tax settlement with the City of New Haven, CT $(.59)
Reversal of "sharing" imputed to property tax settlement $ .29
--------------------------------------------------------------------------------
In accordance with a DPUC decision issued December 31, 1996 and effective
for years 1997-2001, related to a financial and operational review of the
Company (the Rate Plan), the Company was directed to explore and implement ways
to reduce its potentially stranded costs. In addition, the decision required the
Company to record a specified amount of accelerated amortization of conservation
and load management costs during 1997 ($6.4 million before-tax, $4.1 million
after-tax) as a stranded costs mitigation effort if the Company's return on its
utility common stock equity exceeded 10.5% for that year. Based on these
requirements, the Company recorded an operating income tax expense reduction of
$6.7 million, or $.48 per share, in the first quarter of 1997, which made
provision for the cumulative deferred tax benefit associated with the estimated
future decommissioning costs of fossil fuel generating plants for which the
Company had made provision in prior years without accruing the tax benefit. This
tax benefit, originally recorded in the second quarter of 1997, has been
restated to the first quarter of 1997 following consultations with the staff of
the Securities and Exchange Commission and the Company's independent accountants
to coincide with the effective date of the Rate Plan. As a result of recording
the tax benefit, the Company exceeded the 10.5% utility common stock equity
return and therefore was able to record the specified amount of accelerated
amortization required in the Rate Plan for 1997. The accelerated amortization,
which was originally recorded in the second quarter of 1997, has been restated
and is now recorded ratably throughout 1997 as a charge to depreciation expense
on the consolidated income statement. The after-tax amount of accelerated
amortization was less than the cumulative deferred tax benefit because the
after-tax amount of additional amortization was specified in the Rate Plan while
the deferred tax benefit was calculated based upon the cumulative amount of
estimated future decommissioning costs that had been recovered through rates at
that time.
During prior years, the Company had recognized, on a net basis, the
deferred tax assets and offsetting regulatory tax liability related to these tax
benefits associated with the future decommissioning of its fossil generating
plants on its consolidated balance sheet in accordance with Statement of
Financial Accounting Standards No. 109. The Company had recognized this
regulatory tax liability through the systematic recovery of before-tax future
decommissioning costs for its fossil generating units in its rates over the
useful lives of these units.
Additional 1997 one-time items included: a $.05 per share gain related to
subleasing office space; a "curtailment" gain of $2.5 million ($1.5 million
after-tax), or $.11 per share, related to forgone pension benefits associated
with the approximate 230 employees who left the Company as a result of 1996
voluntary retirement and separation programs; and a charge of $4.3 million ($2.5
million after-tax), or $.18 per share, for early termination of a contract with
consultants that assisted the Company with its restructuring efforts, after the
Company determined that the early termination option was more economic than the
multi-year performance-based payout option. All of these one-time items were
recorded as "Operating Expense - Operations - other."
As reported in its Quarterly Report on Form 10-Q for the period ending
March 31, 1998, filed with the Securities and Exchange Commission, the Company
had been investigating potential errors in the accounting
- 34 -
procedure of APS. As a result of the investigation, the Company determined that
APS should create additional reserves for shortfalls in agent collections and
other potentially uncollectible receivables of $4.9 million. Of the total of
$4.9 million, $2.8 million and $2.1 million were restated to 1997 and 1996,
respectively, to provide for the reserves in the relevant periods. See PART II,
Item 8, "Financial Statements and Supplementary Data - Notes to Consolidated
Financial Statements - Note (Q), Restatement of Financial Results."
The principal business of APS is to operate a network of field agents for
the purpose of accepting cash and check payments of clients' bills and
forwarding those payments, through APS accounts, to the client. APS experienced
rapid growth in 1996 and 1997. The number of agents in the APS network increased
from 2,537 in 1995 to 4,904 in 1997; and the dollar volume of payment
transactions increased from $2.3 billion on 17.2 million transactions in 1995 to
$7.5 billion on 73.2 million transactions in 1997.
At year-end 1996, APS created a reserve to provide for losses associated
with agent collections and uncollectible check deposits totaling $4.4 million
before-tax. The Company has restated its 1996 earnings to move $0.7 million of
this loss to 1995. See PART II, Item 8, "Financial Statements and Supplementary
Data - Notes to Consolidated Financial Statements - Note (Q), Restatement of
Financial Results." These losses stemmed from inadequate "back-office" banking
systems and controls that failed to detect a significant amount of deposit
shortfalls from agents and failed to identify a substantial number of
uncollectible check deposits that were reimbursable from the clients serviced.
Specifically, APS agent bank accounts were not fully reconciled at the time the
APS balance sheet items were prepared to allow for the identification,
measurement and enforcement of material claims for recovery from APS agents for
defalcated amounts or from APS customers for checks returned by banks due to
insufficient funds.
In 1997, under new management with added banking expertise, APS began
implementing new systems and controls to manage the agent collection/deposit
process. These changes included the increased use of daily cash reporting and
account reconciliation on high volume agents, extensive reconciliation
procedures, and agent monitors that interact daily with agents to investigate
discrepancies in deposits. These new procedures were fully implemented by the
4th quarter of 1997.
In March of 1998, APS contracted for an insurance policy with an A+ rated
carrier to protect against future losses from robberies, missing deposits, and
agent fraud. The effect of the policy is to "cap" the cost of such losses at
$200,000 per event per agent. The level of detected agent fraud in 1998 was well
below that level, averaging $23,000 per month in total, or .004% of the monthly
transaction dollar volume.
Also in 1998, APS implemented new procedures to correct difficulties in
tracking agent deposits in bank merger or acquisition situations. During this
process, it was discovered that certain large agent depository bank accounts
were not reconciled appropriately and that the amount of APS working capital
invested in the agent depository accounts to cover timing delays for cash
transfers was over-estimated and the amount due to utilities underestimated.
These cash flow discrepancies were masked by the rapid growth of cash deposits
from the expansion in the agent network and the failure to properly take into
account the cash effects of uncleared bank transfers from agent depository
accounts to utilities. APS accounting procedures, which failed to detect the
cash flow discrepancies, have been rectified.
At December 31, 1998, the consolidated balance sheet reflected $54.5
million of accounts payable owed to APS customers. This payable was relieved by
$23.1 million of APS restricted cash, representing collections by APS agents
prior to transmittal to the respective APS customers and $31.4 million of
accounts receivable representing collections by APS agents that had not yet been
deposited into APS bank accounts. Of the accounts payable and accounts
receivable amounts, $4.7 million had originally been recorded on the
consolidated balance sheet as of December 31, 1998.
The following table summarizes the effect of the restatements described
above to the provision for APS losses, restricted cash, other accounts
receivable, and accounts payable - APS customers:
- 35 -
[Enlarge/Download Table]
FOR THE YEAR ENDED DECEMBER 31,
1998 1997 1996 1995
---- ---- ---- ----
(In Thousands)
Provision for APS losses (before-tax), as originally reported $4,900 $ - $4,471 $ -
Effect of restatement, described above (4,900) 2,825 1,279 796
----- ----- ----- ---
Provision for APS losses (before-tax), as restated $ - $2,825 $5,750 $796
===== ===== ===== ===
[Download Table]
AS OF DECEMBER 31,
1998 1997 1996
---- ---- ----
(In Thousands)
Restricted cash, as originally reported $ - $ - $ -
Effect of restatement, described above 23,056 21,063 16,681
------ ------ ------
Restricted cash, as restated $23,056 $21,063 $16,681
====== ====== ======
Other accounts receivable, as originally reported (1) $37,472 $27,914 $38,367
Effect of restatement, described above
Additional accounts receivable for APS agents 26,768 23,284 19,903
Additional APS agent collection reserves - (4,900) (2,075)
------ ------ ------
Other accounts receivable, as restated $64,240 $46,298 $56,195
====== ====== ======
[Download Table]
AS OF DECEMBER 31,
1998 1997 1996
---- ---- ----
(In Thousands)
Accounts payable-APS customers, as originally reported $ - $ - $ -
Accounts payable-APS customers reclassed
from accounts payable 4,691 6,147 7,588
Effect of restatement, described above
Restricted cash 23,056 21,063 16,681
Additional amounts owed to APS customers 26,768 23,284 19,903
------ ------ ------
Accounts payable-APS customers, as restated $54,515 $50,494 $44,172
====== ====== ======
(1) Includes accounts receivable from APS agents originally included in other
accounts receivable of $4,691,000, $6,147,000 and $7,588,000 as of December
31, 1998, 1997 and 1996, respectively.
The one-time gain recorded in the third quarter of 1998 was to record a
refund of prior period transmission charges. It amounted to $3.4 million or $.14
per share, but was recorded as two separate items; $1.8 million, or a gain of
$.07 per share, as a credit to operation expense and $1.6 million, or $.07 per
share, of interest income recorded as Other Income and (Deductions), Other-net.
At the time this one-time item was recorded, in the third quarter of 1998, the
Company estimated that it would be in the Rate Plan "sharing" range of earnings
for the year of 1998 in total, and recorded, therefore, a "sharing" revenue
reduction and increased amortization expense to reflect that estimate. The
"sharing" related to the utility portion of this one-time item, the operation
expense credit, was a charge of $.05 per share. The net result of the one-time
gain for the period was, therefore, $.09 per share. The one-time charge recorded
in the fourth quarter of 1998 as property tax expense of $14 million, or $.59
per share, reflected the DPUC's rejection of the Company's proposed accounting
treatment of a property tax settlement between the Company and the City of New
Haven. Upon that rejection, the Company was required to write-off immediately
the full effect of that settlement. As a result of this one-time charge, the
Company's final 1998 earnings results eliminated the requirement to record any
Rate Plan "sharing" in 1998. The one-time charge eliminated "sharing" revenue
reductions and increased amortization expense amounting to $.29 per share. The
net result of the one-time charge for the period was, therefore, $.30 per share.
- 36 -
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year Rate Plan
-------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework to reduce the Company's retail prices and accelerate the recovery of
certain "regulatory assets," beginning with deferred conservation costs. The
Company has operated under the terms of this Order since January 1, 1997. The
Order's schedule of price reductions and accelerated amortizations was based on
a DPUC pro-forma financial analysis that anticipated the Company would be able
to implement such changes and earn an allowed annual return on common stock
equity invested in utility assets of 11.5% over the period 1997 through 2001.
The Order established a set formula to share (see "Sharing Implementation"
below) any utility income that would produce a return above the 11.5% level:
one-third to be applied to customer price reductions, one-third to be applied to
additional amortization of regulatory assets, and one-third to be retained by
shareowners. Utility income is inclusive of earnings from operations and
one-time items. See "Major Influences on Financial Condition" for a more
extensive description of the five-year Rate Plan.
Sharing Implementation
----------------------
Based on the traditional quarterly earnings pattern, the Company realizes
about one-half of its pre-sharing utility earnings in the third quarter of each
year. The Company will not likely ever exceed the sharing level of utility
earnings before the third quarter of any year that "sharing" is in effect.
Assuming the sharing level of utility earnings is exceeded in the third quarter
of a particular year, then all positive utility earnings recorded in the fourth
quarter of that year will be subject to "sharing."
A look at 2000; continued growth of non-regulated business value
----------------------------------------------------------------
On January 1, 2000, the Company completed the restructuring process
required by the Connecticut electric utility industry restructuring legislation
in 1998 and its regulated business became an electricity delivery business. All
--------
customers are now seeing at least a 10% reduction in their electric rates from
1996 levels.
The framework of the current Rate Plan, including the "sharing" mechanism,
is expected to continue through 2001. Regulatory decisions during 1999 did not
alter the Company's allowed return of 11.5% on utility equity, and did not
impinge upon the Company's ability to achieve that return.
If the Company were to earn 11.5% on equity in the regulated business, that
level of earnings should generate $3.25 - $3.35 per share. In addition,
operation of the Company's nuclear entitlements should contribute to earnings
until such time as the units are sold. The Company expects that utility income
for common stock above 11.5% return will be greatly reduced from 1999 levels,
due to mandates in the restructuring legislation; and the Company expects that
the shareowners' portion of shared utility income will contribute no more than
$.10 - $.15 per share. Under these assumptions, customers also will see reduced
benefits.
Non-regulated businesses are expected to make significant contributions to
earnings in 2000. Both American Payment Systems and United Bridgeport Energy
should each contribute $.10 - $.15 per share in 2000. Precision Power and the
balance of United Resources, Inc. are expected to lose up to $.05 per share. As
a result of management's continued confidence in the potential of the
non-regulated businesses, the Company is evaluating further investments in this
area. However, additional losses could be incurred due to new growth initiatives
if the potential for future benefits warrant such losses.
- 37 -
Total earnings for 2000, including the regulated business with sharing and
the non-regulated business units, are now estimated to be in the range of $3.60
to $3.80 per share. This estimate is contingent upon normal weather and normal
operation of the nuclear units.
- 38 -
[Enlarge/Download Table]
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(THOUSANDS EXCEPT PER SHARE AMOUNTS)
1999 1998 1997
---- ---- ----
OPERATING REVENUES (NOTE G) $679,975 $686,191 $709,029
------------ ------------ ------------
OPERATING EXPENSES
Operation
Fuel and energy 159,403 151,544 182,666
Capacity purchased 33,873 34,515 39,976
Other (Note G) 147,709 146,058 158,600
Maintenance 37,987 42,888 42,203
Depreciation (Note G) 57,351 82,809 74,618
Amortization of cancelled nuclear project, 36,393 13,758 13,758
deferred return and regulatory tax asset (Note D and J)
Income taxes (Note A and F) 66,564 53,619 40,833
Other taxes (Note G) 47,140 64,674 52,493
------------ ------------ ------------
Total 586,420 589,865 605,147
------------ ------------ ------------
OPERATING INCOME 93,555 96,326 103,882
------------ ------------ ------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 575 13 336
Other-net (Note G) (838) 1,097 1,361
Non-operating income taxes 4,664 3,848 3,678
------------ ------------ ------------
Total 4,401 4,958 5,375
------------ ------------ ------------
INCOME BEFORE INTEREST CHARGES 97,956 101,284 109,257
------------ ------------ ------------
INTEREST CHARGES
Interest on long-term debt 42,104 50,129 63,063
Interest on Seabrook obligation bonds owned by the company (6,844) (7,293) (6,905)
Dividend requirement of mandatorily redeemable securities 4,813 4,813 4,813
Other interest (Note G) 4,927 6,507 3,280
Allowance for borrowed funds used during construction (1,660) (455) (1,239)
------------ ------------ ------------
43,340 53,701 63,012
Amortization of debt expense and redemption premiums 2,392 2,511 2,788
------------ ------------ ------------
Net Interest Charges 45,732 56,212 65,800
------------ ------------ ------------
NET INCOME 52,224 45,072 43,457
Premium (Discount) on preferred stock redemptions 53 (21) (48)
Dividends on preferred stock 66 201 205
------------ ------------ ------------
INCOME APPLICABLE TO COMMON STOCK $52,105 $44,892 $43,300
============ ============ ============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,052 14,018 13,976
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,055 14,023 13,992
EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.71 $3.20 $3.10
============ ============ ============
EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.71 $3.20 $3.09
============ ============ ============
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.88
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 39 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(THOUSANDS OF DOLLARS)
1999 1998 1997
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $52,224 $45,072 $43,457
------------ ------------ ------------
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 83,374 88,099 79,487
Deferred income taxes 17,451 3,074 6,804
Deferred income taxes-generation asset sale (70,222) - -
Deferred investment tax credits - net (468) (762) (762)
Amortization of nuclear fuel 8,425 6,892 5,799
Allowance for funds used during construction (2,235) (468) (1,575)
Amortization of deferred return 12,586 12,586 12,586
Changes in:
Accounts receivable - net 8,749 (14,889) 17,626
Fuel, materials and supplies (1,202) (14,466) 2,863
Prepayments 4,368 (4,027) 211
Accounts payable 2,025 (9,782) 8,404
Interest accrued (1,770) (63) (3,569)
Taxes accrued (6,446) 4,849 3,116
Other assets and liabilities (8,386) (4,062) (1,644)
------------ ------------ ------------
Total Adjustments 46,249 66,981 129,346
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 98,473 112,053 172,803
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 1,157 4,923 (6,432)
Long-term debt 25,000 199,636 98,500
Notes payable (69,761) 49,141 26,786
Securities redeemed and retired:
Preferred stock (4,299) (52) (110)
Long-term debt (218,008) (222,348) (151,199)
(Premium) Discount on preferred stock redemption (53) 21 48
Expenses of issues (550) (1,600) (1,500)
Lease obligations (348) (339) (315)
Dividends
Preferred stock (116) (202) (206)
Common stock (40,450) (40,285) (40,408)
------------ ------------ ------------
NET CASH USED IN FINANCING ACTIVITIES (307,428) (11,105) (74,836)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in unregulated businesses (88,489) - -
Net cash received from sale of generation assets 270,590 - -
Plant expenditures, including nuclear fuel (34,772) (38,040) (33,436)
Investment in debt securities 5,447 8,528 (34,541)
------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 152,776 (29,512) (67,977)
------------ ------------ ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (56,179) 71,436 29,990
BALANCE AT BEGINNING OF PERIOD 124,501 53,065 23,075
------------ ------------ ------------
BALANCE AT END OF PERIOD 68,322 124,501 53,065
LESS: RESTRICTED CASH 29,223 26,812 23,392
------------ ------------ ------------
BALANCE: UNRESTRICTED CASH AND TEMPORARY CASH INVESTMENTS $39,099 $97,689 $29,673
============ ============ ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $40,020 $51,481 $59,441
============ ============ ============
Income taxes $121,450 $42,450 $26,773
============ ============ ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 40 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 AND 1998
ASSETS
(Thousands of Dollars)
1999 1998
----- ----
Utility Plant at Original Cost
In service $1,007,065 $1,886,930
Less, accumulated provision for depreciation 532,409 714,375
-------------- ------------
474,656 1,172,555
Construction work in progress 25,708 33,695
Nuclear fuel 21,101 20,174
-------------- ------------
Net Utility Plant 521,465 1,226,424
-------------- ------------
Other Property and Investments
Investment in generation facility 83,494 -
Nuclear decommissioning trust fund assets 28,255 23,045
Other 20,098 14,828
-------------- ------------
131,847 37,873
-------------- ------------
Current Assets
Unrestricted cash and temporary cash investments 39,099 97,689
Restricted cash 29,223 26,812
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 56,057 54,178
Other, less allowance for doubtful accounts of
$508 and $631 53,612 64,240
Accrued utility revenues 25,019 21,079
Fuel, materials and supplies, at average cost 9,259 33,613
Prepayments 3,056 7,424
Other 4,801 154
-------------- ------------
Total 220,126 305,189
-------------- ------------
Deferred Charges
Unamortized debt issuance expenses 8,688 9,421
Other 6,099 1,664
-------------- ------------
Total 14,787 11,085
-------------- ------------
Regulatory Assets (FUTURE AMOUNTS DUE FROM CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Nuclear plant investments-above market 518,268 -
Income taxes due principally to book-tax
differences (Note A) 166,965 264,811
Long-term purchase power contracts-above market 144,406 -
Connecticut Yankee 37,013 42,633
Unamortized redemption costs 22,314 23,468
Unamortized cancelled nuclear project 8,780 10,952
Displaced worker protection costs 5,746 -
Uranium enrichment decommissioning costs 1,040 1,177
Deferred return - Seabrook Unit 1 - 12,586
Other 5,453 4,962
-------------- ------------
Total 909,985 360,589
-------------- ------------
$1,798,210 $1,941,160
============== ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 41 -
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 AND 1998
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
1999 1998
----- ----
Capitalization (Note B)
Common stock equity
Common stock (no par value, 14,062,502 and $292,006 $292,006
14,034,562 shares outstanding in 1999
and 1998)
Paid-in capital 2,253 2,046
Capital stock expense (2,170) (2,182)
Unearned employee stock ownership plan equity (9,261) (10,210)
Retained earnings 175,470 163,847
-------------- ------------
458,298 445,507
Preferred stock - 4,299
Company-obligated mandatorily redeemable
securities of subsidiary holding solely
parent debentures 50,000 50,000
Long-term debt
Long-term debt 605,641 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
-------------- ------------
Net long-term debt 518,228 664,510
Total 1,026,526 1,164,316
-------------- ------------
Noncurrent Liabilities
Purchase power contract obligation 144,406 -
Nuclear decommissioning obligation 28,255 23,045
Connecticut Yankee contract obligation 27,056 32,711
Pensions accrued (Note H) 19,026 31,097
Obligations under capital leases 16,131 16,506
Other 10,394 6,622
-------------- ------------
Total 245,268 109,981
-------------- ------------
Current Liabilities
Current portion of long-term debt 25,000 66,202
Notes payable 17,131 86,892
Accounts payable 49,069 48,749
Accounts payable - APS customers 56,220 54,515
Dividends payable 10,125 10,155
Taxes accrued 2,570 9,015
Interest accrued 8,433 10,203
Obligations under capital leases 375 348
Other accrued liabilities 39,421 39,845
-------------- ------------
Total 208,344 325,924
-------------- ------------
Customers' Advances for Construction 1,867 1,867
-------------- ------------
Regulatory Liabilities (FUTURE AMOUNTS OWED TO CUSTOMERS
THROUGH THE RATEMAKING PROCESS)
Accumulated deferred investment tax credits 15,157 15,623
Deferred gains on sale of property 15,901 4
Customer refund 18,381 -
Other 2,543 2,061
-------------- ------------
Total 51,982 17,688
-------------- ------------
Deferred Income Taxes (FUTURE TAX LIABILITIES OWED
TO TAXING AUTHORITIES) 264,223 321,384
Commitments and Contingencies (Note L)
-------------- ------------
$1,798,210 $1,941,160
============== ============
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 42 -
[Enlarge/Download Table]
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
DECEMBER 31, 1999, 1998 AND 1997
(DOLLAR AMOUNTS IN THOUSANDS)
CAPITAL UNEARNED
COMMON STOCK PREFERRED STOCK PAID-IN STOCK ESOP RETAINED
SHARES(A) AMOUNT SHARES(B) AMOUNT CAPITAL EXPENSE EQUITY EARNINGS TOTAL
------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1996 14,101,291 284,579 44,612 4,461 772 (2,182) - $156,299 $443,929
------------------------------------------------------------------------------------------------------------------------------------
Net income for 1997 43,457 43,457
Cash dividends on common stock
- $2.88 per share (40,255) (40,255)
Cash dividends on preferred stock (205) (205)
Issuance of 134,844 shares common stock
- no par value 134,833 4,151 577 4,728
ESOP purchase of 328,300 common shares (328,300) (11,160) (11,160)
Repurchase and cancellation of
preferred stock (1,103) (110) (110)
Discount on preferred stock repurchase 48 48
------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1997 13,907,824 288,730 43,509 4,351 1,349 (2,182) (11,160) $159,344 $440,432
------------------------------------------------------------------------------------------------------------------------------------
Net income for 1998 45,072 45,072
Cash dividends on common stock
- $2.88 per share (40,389) (40,389)
Cash dividends on preferred stock (201) (201)
Issuance of 98,798 shares common stock
- no par value 98,798 3,276 459 3,735
Allocation of benefits - ESOP 27,940 238 950 1,188
Repurchase and cancellation of
preferred stock (524) (52) (52)
Discount on preferred stock repurchase 21 21
------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1998 14,034,562 292,006 42,985 4,299 2,046 (2,182) (10,210) 163,847 449,806
------------------------------------------------------------------------------------------------------------------------------------
Net income for 1999 52,224 52,224
Cash dividends on common stock
- $2.88 per share (40,470) (40,470)
Cash dividends on preferred stock (66) (66)
Allocation of benefits - ESOP 27,940 207 949 1,156
Repurchase and cancellation of
preferred stock (42,985) (4,299) 12 (12) (4,299)
Premium on preferred stock repurchase (53) (53)
------------------------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 1999 14,062,502 $292,006 $0 $0 $2,253 ($2,170) ($9,261) $175,470 $458,298
------------------------------------------------------------------------------------------------------------------------------------
(a) There were 30,000,000 shares authorized in 1999, 1998 and 1997
(b) There were 1,119,612 shares authorized in 1999, 1998 and 1997
The accompanying Notes to Consolidated Financial Statements
are an integral part of the financial statements.
- 43 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The United Illuminating Company (the Company) is an operating electric
public utility company, engaged principally in the purchase, transmission,
distribution and sale of electricity for residential, commercial and industrial
purposes in a service area of about 335 square miles in the southwestern part of
the State of Connecticut. The service area, largely urban and suburban in
character, includes the principal cities of Bridgeport (population approximately
137,000) and New Haven (population approximately 124,000) and their surrounding
areas. Situated in the service area are retail trade and service centers, as
well as large and small industries producing a wide variety of products,
including helicopters and other transportation equipment, electrical equipment,
chemicals and pharmaceuticals.
In addition, the Company has created, and owns, unregulated subsidiaries.
The Company has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement the Company's regulated electric utility business and provide
long-term rewards to the Company's shareowners.
URI has four wholly-owned subsidiaries. American Payment Systems, Inc.
manages a national network of agents for the processing of bill payments made by
customers of the Company and other companies. Another subsidiary of URI, United
Capital Investments, Inc., and its subsidiaries, participate in business
ventures that complement the Company's business. A third URI subsidiary,
Precision Power, Inc. and its subsidiaries, provide specialty electrical,
telecommunications and mechanical contracting and power-related services to the
owners of commercial buildings and industrial and institutional facilities.
URI's fourth subsidiary, United Bridgeport Energy, Inc., is a participant in a
merchant wholesale electric generating facility located in Bridgeport,
Connecticut.
(A) STATEMENT OF ACCOUNTING POLICIES
ACCOUNTING RECORDS
The accounting records are maintained in accordance with the uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC) and the Connecticut Department of Public Utility Control (DPUC).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to use estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, United Resources, Inc. Intercompany accounts
and transactions have been eliminated in consolidation.
REGULATORY ACCOUNTING
Generally accepted accounting principles for regulated entities in the
United States allow the Company to give accounting recognition to the actions of
regulatory authorities in accordance with the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." In accordance with SFAS No. 71, the Company has
deferred recognition of costs (a regulatory asset) or has recognized obligations
(a regulatory liability) if it is probable that such costs will be recovered or
obligations relieved in the
- 44 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
future through the ratemaking process. In addition to the Regulatory Assets and
Liabilities separately identified on the Consolidated Balance Sheet, there are
other regulatory assets and liabilities such as conservation and load management
costs and certain deferred tax liabilities. The Company also has obligations
under long-term power contracts, the recovery of which is subject to regulation.
If the Company, or a portion of its assets or operations, were to cease meeting
the criteria for application of these accounting rules, accounting standards for
businesses in general would become applicable and immediate recognition of any
previously deferred costs, or a portion of deferred costs, would be required in
the year in which the criteria are no longer met, if such deferred costs are not
recoverable in the portion of the business that continues to meet the criteria
for application of SFAS No. 71.
The Restructuring Act enacted in Connecticut in 1998 provides for the
Company to recover previously deferred costs through ongoing assessments to be
included in future regulated service rates. See Note (C), "Rate-Related
Regulatory Proceedings" for a discussion of the nature, amount and timing of
recovery of the Company's stranded costs associated with the generation portion
of its assets and operations, as well as a discussion of the regulatory
decisions that provide for such recovery. Based on these regulatory decisions,
the sale of the Company's fossil-generation assets in the second quarter of
1999, the planned divestiture of its nuclear generation ownership interests by
the end of 2003, and, in anticipation of the Restructuring Act becoming
effective on January 1, 2000, on December 31, 1999 the Company discontinued
applying SFAS No. 71 to the generation portion of its assets and operations.
However, based on the recovery mechanism that allows recovery of all of its
stranded costs through its standard offer rates, the Company was not required to
take any write-offs in connection with this event. The Company expects to
continue to meet the criteria for application of SFAS No. 71 for the remaining
portion of its assets and operations for the foreseeable future. If a change in
accounting were to occur to the non-generation portion of the Company's
operations, it could have a material adverse effect on the Company's earnings
and retained earnings in that year and could have a material adverse effect on
the Company's ongoing financial condition as well.
UTILITY PLANT
The cost of additions to utility plant and the cost of renewals and
betterments are capitalized. Cost consists of labor, materials, services and
certain indirect construction costs, including an allowance for funds used
during construction (AFUDC). The cost of current repairs and minor replacements
is charged to appropriate operating expense accounts. The original cost of
utility plant retired or otherwise disposed of and the cost of removal, less
salvage, are charged to the accumulated provision for depreciation.
The Company's utility plant in service as of December 31, 1999 and 1998 was
comprised as follows:
1999 1998
---- ----
(000's)
Production (1) $271,012 $1,133,984
Transmission (1) 148,419 161,643
Distribution 415,892 408,845
General (1) 46,578 56,264
Future use plant 30,167 30,505
Other (1) 94,997 95,689
------- -------
$1,007,065 $1,886,930
========== ==========
(1) As of December 31, 1999, the Company had reclassified $496.9 million of
production plant, $7.4 million of transmission plant, $7.5 million of
general plant and $0.6 million of other plant associated with its nuclear
entitlements from utility plant in service to a regulatory asset.
- 45 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
See Note (C), "Rate-related Regulatory Proceedings" for a discussion of the
sale by the Company of its two operating fossil-fueled generating stations and
the regulatory decisions allowing for recovery of stranded costs, including the
above-market investment in nuclear generating units.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
In accordance with the uniform systems of accounts, the Company capitalizes
AFUDC, which represents the approximate cost of debt and equity capital devoted
to plant under construction. The portion of the allowance applicable to borrowed
funds is presented in the Consolidated Statement of Income as a reduction of
interest charges, while the portion of the allowance applicable to equity funds
is presented as other income. Although the allowance does not represent current
cash income, it has historically been recoverable under the ratemaking process
over the service lives of the related properties. The Company compounds the
allowance applicable to major construction projects semi-annually. Weighted
average AFUDC rates in effect for 1999, 1998 and 1997 were 7.75%, 7.0% and 7.5%,
respectively.
DEPRECIATION
Provisions for depreciation on utility plant for book purposes are computed
on a straight-line basis, using estimated service lives determined by
independent engineers. One-half year's depreciation is taken in the year of
addition and disposition of utility plant, except in the case of major operating
units on which depreciation commences in the month they are placed in service
and ceases in the month they are removed from service. The aggregate annual
provisions for depreciation for the years 1999, 1998 and 1997 were equivalent to
approximately 3.10%, 3.26% and 3.15%, respectively, of the original cost of
depreciable property.
INCOME TAXES
In accordance with Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes," the Company has provided deferred taxes for
all temporary book-tax differences using the liability method. The liability
method requires that deferred tax balances be adjusted to reflect enacted future
tax rates that are anticipated to be in effect when the temporary differences
reverse. In accordance with generally accepted accounting principles for
regulated industries, the Company has established a regulatory asset for the net
revenue requirements to be recovered from customers for the related future tax
expense associated with certain of these temporary differences.
For ratemaking purposes, the Company normalizes all investment tax credits
(ITC) related to recoverable plant investments except for the ITC related to
Seabrook Unit 1, which was taken into income in accordance with provisions of a
1990 DPUC retail rate decision.
ACCRUED UTILITY REVENUES
The estimated amount of utility revenues (less related expenses and
applicable taxes) for service rendered but not billed is accrued at the end of
each accounting period.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments.
The Company is required to maintain an operating deposit with the project
disbursing agent related to its 17.5% ownership interest in Seabrook Unit 1.
This operating deposit, which is the equivalent to one and one half months of
- 46 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the funding requirement for operating expenses, is restricted for use and
amounted to $2.3 million and $3.8 million at December 31, 1999 and 1998,
respectively.
The Company's wholly-owned subsidiary, American Payment Systems, Inc.,
maintains separate bank accounts for holding cash received from clients'
customers before the amounts are transferred to clients. The amount of this
restricted cash at December 31, 1999 and 1998 was $26.9 million and $23.1
million, respectively.
At December 31, 1999, the Company included in the cash balance $25 million
of proceeds from the issuance by the Business Finance Authority of the State of
New Hampshire of $25 million principal amount of tax-exempt Pollution Control
Refunding Revenue Bonds that were held by a trustee.
INVESTMENTS
The Company's investment in the Connecticut Yankee Atomic Power Company, a
nuclear generating company in which the Company has a 9 1/2% stock interest, is
accounted for on an equity basis. This investment amounted to $10.0 million and
$9.9 million at December 31, 1999 and 1998, respectively, and is included on the
Consolidated Balance Sheet as a regulatory asset. See Note (L), "Commitments and
Contingencies - Other Commitments and Contingencies - Connecticut Yankee."
RESEARCH AND DEVELOPMENT COSTS
Research and development costs, including environmental studies, are
charged to expense as incurred.
PENSION AND OTHER POSTEMPLOYMENT BENEFITS
The Company accounts for normal pension plan costs in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No. 87,
"Employers' Accounting for Pensions," and for supplemental retirement plan costs
and supplemental early retirement plan costs in accordance with the provisions
of SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and for Termination Benefits."
The Company accounts for other postemployment benefits, consisting
principally of health and life insurance, under the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions," which
requires, among other things, that the liability for such benefits be accrued
over the employment period that encompasses eligibility to receive such
benefits. The annual incremental cost of this accrual has been allowed in retail
rates in accordance with a 1992 rate decision of the DPUC.
URANIUM ENRICHMENT OBLIGATION
Under the Energy Policy Act of 1992 (Energy Act), the Company will be
assessed for its proportionate share of the costs of the decontamination and
decommissioning of uranium enrichment facilities operated by the Department of
Energy. The Energy Act imposes an overall cap of $2.25 billion on the obligation
assessed to the nuclear utility industry and limits the annual assessment to
$150 million each year over a 15-year period. The Company has recovered these
assessments in rates as a component of fuel expense. Accordingly, the Company
has recognized the unrecovered costs as a regulatory asset on its Consolidated
Balance Sheet. At December 31, 1999, the Company's remaining share of the
obligation, based on its ownership and leasehold interests in Seabrook Unit 1
and Millstone Unit 3, was approximately $1.0 million.
- 47 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $4.0 million, $2.6 million and $2.6 million
during 1999, 1998 and 1997 into the decommissioning trust funds for Seabrook
Unit 1 and Millstone Unit 3. At December 31, 1999, the Company's shares of the
trust fund balances, which included accumulated earnings on the funds, were
$20.5 million and $7.8 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
IMPAIRMENT OF LONG-LIVED ASSETS
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets to Be Disposed Of" requires the recognition
of impairment losses on long-lived assets when the book value of an asset
exceeds the sum of the expected future undiscounted cash flows that result from
the use of the asset and its eventual disposition. This standard also requires
that rate-regulated companies recognize an impairment loss when a regulator
excludes all or part of a cost from rates, even if the regulator allows the
company to earn a return on the remaining allowable costs. Under this standard,
the probability of recovery and the recognition of regulatory assets under the
criteria of SFAS No. 71 must be assessed on an ongoing basis. The Company does
not have any assets that are impaired under this standard.
EARNINGS PER SHARE
The following table presents a reconciliation of the numerators and
denominators of the basic and diluted earnings per share calculations for the
years 1999, 1998 and 1997:
[Enlarge/Download Table]
INCOME APPLICABLE TO AVERAGE NUMBER OF
COMMON STOCK SHARES OUTSTANDING EARNINGS
(NUMERATOR) (DENOMINATOR) PER SHARE
----------- ------------- ---------
(000's, except per share amounts)
1999
----
Basic earnings per share $52,105 14,052 $3.71
Effect of dilutive stock options - 3 (.00)
------- ------ -----
Diluted earnings per share $52,105 14,055 $3.71
======= ====== =====
1998
----
Basic earnings per share $44,892 14,018 $3.20
Effect of dilutive stock options - 5 (.00)
------- ------ ------
Diluted earnings per share $44,892 14,023 $3.20
======= ====== =====
1997
----
Basic earnings per share $43,300 13,976 $3.10
Effect of dilutive stock options - 16 (.01)
------- ------ -----
Diluted earnings per share $43,300 13,992 $3.09
======= ====== =====
- 48 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation." This statement establishes financial accounting and
reporting standards for stock-based employee compensation plans, such as stock
purchase plans, stock options, restricted stock, and stock appreciation rights.
The statement defines the methods of determining the fair value of stock-based
compensation and requires the recognition of compensation expense for book
purposes. However, the statement allows entities to continue to measure
compensation expense in accordance with the prior authoritative literature, APB
No. 25, "Accounting for Stock Issued to Employees," but requires that pro forma
net income and earnings per share be disclosed for each year for which an income
statement is presented as if SFAS No. 123 had been applied. The accounting
requirements of this statement are effective for transactions entered into after
1995. However, pro forma disclosures must include the effects of all awards
granted after January 1, 1995. As of December 31, 1999, there were no options to
which this statement would apply. Options granted in 1999 are not yet
exercisable.
NEW ACCOUNTING STANDARDS
On January 1, 1998, the Company adopted Statement of Financial Standards
(SFAS) No. 130, "Reporting Comprehensive Income," which provides authoritative
guidance on the reporting and display of comprehensive income and its
components. For the years ended December 31, 1999, 1998 and 1997 comprehensive
income was equal to net income as reported.
On January 1, 1998, the Company adopted SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information," which provides guidance
about segment reporting. As described in Note (P), "Segment Information," the
Company has only one reportable segment, that of regulated generation,
distribution and sale of electricity.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement,
which is effective for fiscal quarters of fiscal years beginning after June 15,
2000, establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires entities to recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The accounting for the changes in the fair
value of a derivative (gains and losses) would depend on the intended use and
designation of the derivative. The Company cannot reasonably assess what effect
applying SFAS No. 133 will have on its financial condition and results of
operations in the future.
(B) CAPITALIZATION
COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at December 31, 1999 and 1998, of which 272,420 shares and 300,360
shares were unallocated shares held by the Company's Employee Stock Ownership
Plan (ESOP) and not recognized as outstanding for accounting purposes as of
December 31, 1999 and 1998, respectively.
In 1990, the Company's Board of Directors and the shareowners approved a
stock option plan for officers and key employees of the Company. The plan
provides for the awarding of options to purchase up to 750,000 shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date
- 49 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
of the grant. Options to purchase 3,500 shares of stock at an exercise price of
$30 per share, 7,800 shares of stock at an exercise price of $39.5625 per share,
and 5,000 shares of stock at an exercise price of $42.375 per share have been
granted by the Board of Directors and remained outstanding at December 31, 1999.
No options were exercised during 1999.
[Enlarge/Download Table]
1999 1998 1997
---- ---- ----
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ ----- ------ ----- ------ -----
Balance - Beginning of Year 16,300 $38.37 115,098 $33.90 252,331 $32.20
Granted - - - - - -
Forfeited - - - - (2,400) $30.75
Exercised - - (98,798) $33.16 (134,833) $30.79
Balance - End of Year 16,300 $38.37 16,300 $38.37 115,098 $33.90
------ ------- -------
Exercisable at End of Year 16,300 $38.37 16,300 $38.37 96,698 $34.51
====== ======= =======
On March 22, 1999, the Company's Board of Directors approved a stock option
plan for directors, officers and key employees of the Company. The plan provides
for the awarding of options to purchase up to 650,000 shares of the Company's
common stock over periods of from one to ten years following the dates when the
options are granted. The exercise price of each option cannot be less than the
market value of the stock on the date of the grant. On June 28, 1999, the
Company's shareowners approved the plan. Options to purchase 137,000 shares of
stock at an exercise price of $43 7/32 per share have been granted by the Board
of Directors and remained outstanding at December 31, 1999. No options to
purchase shares of the Company's common stock can be exercised without the
approval of the DPUC; and, as December 31, 1999, the Company had not requested
approval by the DPUC.
On February 23, 1998, the Board of Directors granted 80,000 "phantom" stock
options to Nathaniel D. Woodson upon his appointment as President of the
Company. On each of the first five anniversaries of the grant date, 16,000
phantom stock options become exercisable and can be exercised at any time within
Mr. Woodson's period of employment with the Company by means of the Company
paying him the difference between the prevailing market price for each share and
the phantom stock option price of $45.16 per share. At ten years after the grant
date any unexercised phantom stock options will expire. At December 31, 1999,
16,000 phantom stock options were exercisable. Due to the immaterial effect on
results of operations, no expense was recognized with regard to the phantom
stock options.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company Employee Stock Ownership Plan (ESOP).
The trustee for the ESOP used the funds to purchase shares of the Company's
common stock in open market transactions. The shares will be allocated to
employees' ESOP accounts, as the loan is repaid, to cover a portion of the
Company's required ESOP contributions. The loan will be repaid by the ESOP over
a twelve-year period, using the Company's contributions and dividends paid on
the unallocated shares of the stock held by the ESOP. As of December 31, 1999,
272,420 shares, with a fair market value of $14.0 million, had been purchased by
the ESOP and had not been committed to be released or allocated to ESOP
participants.
RETAINED EARNINGS RESTRICTION
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$117.3 million were free from such limitations at December 31, 1999.
- 50 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
PREFERRED AND PREFERENCE STOCK
The par value of each of these issues was credited to the appropriate stock
account and expenses related to these issues were charged to capital stock
expense.
On April 8, 1999, the Company called for redemption all 10,370 shares of
its outstanding $100 par value 4.35% Preferred Stock, Series A, all 17,158
shares of its outstanding $100 par value 4.72% Preferred Stock, Series B, all
12,745 shares of its outstanding $100 par value 4.64% Preferred Stock, Series C
and all 2,712 shares of its outstanding $100 par value 5 5/8% Preferred Stock,
Series D. The Company paid a redemption premium of $53,355 in effecting these
redemptions, which were completed on May 14, 1999.
Shares of preferred stock have preferential dividend and liquidation rights
over shares of common stock. Preferred shareholders are not entitled to general
voting rights. However, if any preferred dividends are in arrears for six or
more quarters, or if certain other events of default occur, preferred
shareholders are entitled to elect a majority of the Board of Directors until
all preferred dividend arrearages are paid and any event of default is remedied.
There were no shares of preferred stock outstanding at December 31, 1999.
Preference stock is a form of stock that is junior to preferred stock but
senior to common stock. It is not subject to the earnings coverage requirements
or minimum capital and surplus requirements governing the issuance of preferred
stock. There were no shares of preference stock outstanding at December 31,
1999.
COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITIES OF SUBSIDIARY HOLDING SOLELY
PARENT DEBENTURES
United Capital Funding Partnership L.P. (United Capital) is a special
purpose limited partnership in which the Company owns all of the general partner
interests. United Capital has issued $50 million of 9 5/8% Preferred Capital
Securities, Series A, (Preferred Securities), the dividends on which are accrued
and paid monthly.
The sole holding of United Capital is the $50 million of 9 5/8% Junior
Subordinated Deferrable Interest Debentures, Series A, due April 30, 2025, (the
Series A Debentures) issued by United Illuminating in 1995.
Holders of the Preferred Securities will be entitled to receive, to the
extent of funds held by United Capital, cumulative preferential dividends, at an
annual rate 9 5/8% of the liquidation preference of $25 per security, payable
monthly in arrears on the last day of each calendar month. The payment of
dividends and payments on redemption with respect to the Preferred Securities to
the extent of funds held by United Capital, will be guaranteed under a Payment
and Guarantee Agreement (the Guarantee) of United Illuminating. The Guarantee
does not cover payment of amounts in respect of the Preferred Securities to the
extent that United Capital does not have available funds for the payment thereof
and cash on hand sufficient to make such payment. Such funds and cash on hand
will be limited to payments by United Illuminating on the Series A Debentures.
If United Illuminating fails to make interest payments on the Series A
Debentures, United Capital will have insufficient funds to pay dividends on the
Preferred Securities and the Guarantee will not cover payment of dividends.
The Preferred Securities are subject to mandatory redemption when the
Series A Debentures mature or are redeemed.
- 51 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
LONG-TERM DEBT
[Enlarge/Download Table]
DECEMBER 31,
1999 1998
---- ----
(000's)
Other Long-Term Debt
Pollution Control Revenue Bonds:
4.35%, 1996 Series, due June 26, 2026 (1) $ 7,500 $ 7,500
8%, 1989 Series A, due December 1, 2014 25,000 25,000
5 7/8%, 1993 Series, due October 1, 2033 64,460 64,460
Pollution Control Refunding Revenue Bonds:
4.35%, 1997 Series, due July 30, 2027 (2) 27,500 27,500
4.55%, 1997 Series, due July 30, 2027 (1) 71,000 71,000
5.40%, 1999 Series, due December 1, 2029 (3) 25,000 -
Notes:
6.20%, 1993 Series H, due January 15, 1999 - 66,202
6.25%, 1998 Series I, due December 15, 2002 100,000 100,000
6.00%, 1998 Series J, due December 15, 2003 100,000 100,000
Term Loans:
6.95%, due August 29, 2000 (4) - 50,000
6.4375%, due September 6, 2000 (4) - 20,000
6.675%, due October 25, 2001 (4) - 25,000
7.005%, due October 25, 2001 (4) - 50,000
Obligation under the Seabrook Unit 1 sale/leaseback agreement 210,424 217,230
------- -------
630,884 823,892
Unamortized debt discount less premium (243) (320)
------- -------
630,641 823,572
Less:
Current portion included in Current Liabilities 25,000 66,202
Investment-Seabrook Lease Obligation Bonds 87,413 92,860
------- -------
Total Long-Term Debt $518,228 $664,510
======= =======
(1) The interest rate for these Bonds was fixed on February 1, 1999 for the
five-year period ending January 30, 2004. Prior to February 1, 1999, the
interest rate was variable.
(2) The interest rate for these Bonds was fixed on February 1, 1999 for the
three-year period ending January 30, 2002. Prior to February 1, 1999, the
interest rate was variable.
(3) The interest rate for these Bonds was fixed on December 16, 1999 for the
three-year period ending December 1, 2002.
(4) The fixed interest rate for these variable interest rate term loans
reflected the effect of the associated interest rate swaps.
- 52 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
On January 16, 1999, the Company repaid $66.2 million principal amount of
6.20% Notes at maturity.
On February 1, 1999, the Company converted $7.5 million principal amount of
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and interest is payable semi-annually on
August 1 and February 1. In addition, on February 1, 1999, the Company converted
$98.5 million principal amount Business Finance Authority of the State of New
Hampshire Bonds from a weekly reset mode to a multiannual mode. The interest
rate on $27.5 million principal amount of the Bonds is 4.35% for a three-year
period beginning February 1, 1999. The interest rate on $71 million principal
amount of the Bonds is 4.55% for a five-year period. Interest on the Bonds is
payable semi-annually on August 1 and February 1.
On March 8, 1999, the Company prepaid and terminated $20 million of the
remaining $70 million outstanding debt under its $150 million Term Loan
Agreement dated August 29, 1995. On April 16, 1999, the Company prepaid and
terminated the entire remaining $50 million outstanding debt under said $150
million Term Loan Agreement, and the entire $75 million outstanding debt under
its Term Loan Agreement dated October 25, 1996.
On December 16, 1999, the Company borrowed $25 million from the Business
Finance Authority of the State of New Hampshire (BFA), representing the proceeds
from the issuance by the BFA of $25 million principal amount of tax-exempt
Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated,
under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs'
bondholders such amounts as will pay, when due, the principal of and the
premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2029, and
their interest rate is fixed at 5.4% for the three-year period ending December
1, 2002. At December 31, 1999, these proceeds were held by a trustee and were
recognized as cash and long-term debt on the Consolidated Balance Sheet. The
Company has used the proceeds of this $25 million borrowing to cause the
redemption and repayment of $25 million of 8.0%, 1989 Series A, Pollution
Control Revenue Bonds, an outstanding series of tax-exempt bonds on which the
Company also had a payment obligation to a trustee for the bondholders. Expenses
associated with this transaction, including redemption premiums totaling
$750,000 and other expenses of approximately $417,000, were paid by the Company.
The expenses to issue long-term debt are deferred and amortized over the
life of the respective debt issue.
Maturities and mandatory redemptions/repayments are set forth below:
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
(000's)
Maturities $ - $ - $100,000 $100,000 $ -
(C) RATE-RELATED REGULATORY PROCEEDINGS
On December 31, 1996, the DPUC completed a financial and operational review
of the Company and ordered a five-year incentive regulation plan for the years
1997 through 2001 (the Rate Plan). The DPUC did not change the existing retail
base rates charged to customers, but the Rate Plan increased amortization of the
Company's conservation and load management program investments during 1997-1998,
and accelerated the amortization and recovery of unspecified assets during
1999-2001 if the Company's common stock equity return on utility investment
exceeds 10.5% after recording the amortization. The Rate Plan also provided for
retail price reductions of about 5%, compared to 1996 and phased-in over
1997-2001, primarily through reductions of conservation adjustment mechanism
revenues, through a surcredit in each of the five plan years, and through
acceptance of the Company's proposal to modify the operation of the fossil fuel
clause mechanism. The Company's authorized return on utility common stock equity
during the period is 11.5%. Earnings above 11.5%, on an annual basis, are to be
utilized
- 53 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
one-third for customer price reductions, one-third to increase amortization of
assets, and one-third retained as earnings. As a result of the Rate Plan,
customer prices were required to be reduced, on average, by 3% in 1997 compared
to 1996. Also as a result of the Rate Plan, customer prices were required to be
reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996.
Retail revenues decreased by approximately 7.0% through 1999 compared to 1996
due to customer price reductions. The Rate Plan was reopened in 1998, in
accordance with its terms, to determine the assets to be subjected to
accelerated recovery in 1999. The DPUC decided on February 10, 1999 to subject
$12.1 million of the Company's regulatory tax assets to accelerated recovery in
1999.
The Rate Plan includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut.
On October 1, 1999, the DPUC issued its decision establishing the Company's
standard offer customer rates, commencing January 1, 2000, at a level 10% below
1996 rates, as directed by the Restructuring Act described in detail below.
These standard offer customer rates are in effect for the period 2000-2001 and
supercede the rate reductions for this period that were included in the Rate
Plan. The decision also reduced the required amount of accelerated amortization
in 2000 and 2001. Under this decision, all other components of the Rate Plan are
expected to remain in effect through 2001. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the level of the Company's 1996
rates in an appeal taken to the Superior Court from the DPUC's decision.
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. As a result of the Act, the business of
generating and selling electricity directly to consumers is opened to
competition. These business activities are separated from the business of
delivering electricity to consumers, also known as the transmission and
distribution business. The business of delivering electricity remains with the
incumbent franchised utility companies (including the Company), which continues
to be regulated by the DPUC as Distribution Companies. Since mid-1999,
Distribution Companies have been required to separate on consumers' bills the
electricity generation services component from the charge for delivering the
electricity and all other charges.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge." The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely not otherwise be recoverable in a
competitive generation and supply market. These costs include above-market
long-term purchased power contract obligations, regulatory asset recovery and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interests in its nuclear-fueled power plants prior to 2004.
On October 2, 1998, the Company agreed to sell both of its operating
fossil-fueled generating stations, Bridgeport Harbor Station and New Haven
Harbor Station, to Wisvest-Connecticut, LLC, a single-purpose subsidiary of
Wisvest Corporation. Wisvest Corporation is a non-utility subsidiary of
Wisconsin Energy Corporation, Milwaukee, Wisconsin On April 16, 1999, the
transaction closed and the Company received
- 54 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
approximately $277.9 million from this sale. The Company realized a before-tax
book gain of $86.5 million from the sale of these plant investments. However,
under the Restructuring Act, this gain was offset by a writedown of the stranded
costs eligible for collection by the Company under the Restructuring Act's
competitive transition assessment, such that there was no net income effect of
the sale. The Company used the net cash proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, and in other regulatory dockets, the Company stated that
it plans to divest its nuclear generation ownership interests (17.5% of Seabrook
Unit 1 in New Hampshire and 3.685% of Millstone Station Unit 3 in Connecticut)
by the end of 2003, in accordance with the Restructuring Act. The DPUC is
currently considering the Company's plan for divesting its ownership interest in
Millstone Unit 3 through an auction process to be conducted by a consultant to
be selected by the DPUC. The divestiture process for Seabrook Unit 1 has not yet
been determined. In anticipation of ultimate divestiture, the Company has
satisfied the Restructuring Act's requirement that nuclear generating assets be
separated from its transmission and distribution assets. This was accomplished
by transferring the nuclear generating assets into a separate new division of
the Company, using divisional financial statements and accounting to segregate
all revenues, expenses, assets and liabilities associated with nuclear ownership
interests. In a decision dated May 19, 1999, the DPUC approved the Company's
proposal in this regard.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998 and, in a decision dated May 19, 1999, the DPUC approved the
proposed corporate restructuring. The Company has filed applications with the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission
seeking approval of the proposed corporate restructuring, and a special meeting
of the Company's shareowners will be held on March 17, 2000 to vote on approval
of the restructuring.
On March 24, 1999, the Company applied to the DPUC for a calculation of
the Company's stranded costs that will be recovered by it in the future through
the competitive transition assessment under the Restructuring Act. In a decision
dated August 4, 1999, the DPUC determined that the Company's stranded costs
total $801.3 million, consisting of $160.4 million of above-market long-term
purchased power contract obligations, $153.3 million of generation-related
regulatory assets (net of related tax and accounting offsets), and $487.6
million of above-market investments in nuclear generating units (net of $26.4
million of gains from generation asset sales and other offsets related to
generation assets). The DPUC decision provides that these stranded cost amounts
are subject to true-ups, adjustments and potential additional future offsets, in
accordance with the Restructuring Act. The Connecticut Office of Consumer
Counsel, the statutory representative of consumer interests in public utility
matters, is contesting the DPUC's calculation of the market value of the
Company's generating assets in an appeal taken to the Superior Court from the
DPUC's decision.
Under the Restructuring Act, retail customers representing a total of up
to 35% of the Company's retail customer load became able to choose their power
supply providers on and after January 1, 2000, and all of the Company's
customers will be able to choose their power supply providers as of July 1,
2000. On and after January 1, 2000 and through December 31, 2003, the Company is
required to offer fully-bundled "standard offer" electric service, under
regulated rates, to all customers who do not choose an alternate power supply
provider. The
- 55 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
standard offer rates must include the fully-bundled price of generation,
transmission and distribution services, the competitive transition assessment,
the systems benefits charge and the conservation and renewable energy charges.
The fully-bundled standard offer rates must also be at least 10% below the
average fully-bundled prices in 1996.
In March of 1999, the DPUC commenced a proceeding to determine what the
Company's standard offer rates should be under the above requirements of the
Restructuring Act. In April, May and June of 1999, the Company filed descriptive
material, data and supporting testimony with the DPUC setting forth the
Company's overall approach for determining the components of its standard offer
rates, and for continuation of the five-year Rate Plan ordered by the DPUC in
its 1996 financial and operational review of the Company (see above) through the
four-year standard offer period. On July 27, 1999, the Company and Enron Capital
& Trade Resources Corp. (ECTR), an affiliate of Enron Corp., Houston, Texas
(Enron) filed with the DPUC a joint stipulation and settlement proposal to
resolve simultaneously all of the issues in the Company's standard offer rate
proceeding. The proposal included an arrangement between the Company and ECTR
whereby ECTR will supply all of the generation services needed by the Company to
meet its standard offer obligations for the four-year standard offer period, and
an assumption by ECTR of all of the Company's long-term purchased power
agreement (PPA) obligations. The stipulation and settlement proposal also
provided for the Company's standard offer rates at a fully-bundled level that
complies with the 10% reduction required by the Restructuring Act, including the
generation services component of these rates, the Company's stranded costs for
purposes of future recovery, the competitive transition assessment, systems
benefits charge, delivery (transmission and distribution) charges, and
conservation, load management and renewable energy charges. The Company also
requested that a purchased power adjustment clause authorized by the
Restructuring Act be put in place to adjust standard offer rates for limited
purposes, and that the Company's five-year Rate Plan, as modified and
supplemented by the stipulation and settlement proposal, be continued during the
four-year standard offer period. In its decision, dated October 1, 1999, on the
Company's standard offer rates, the DPUC approved elements of the stipulation
and settlement proposal, including the arrangements with ECTR, subject to
specified changes, including changes in the level of the generation services
component of customers' rates. On October 15, 1999, the Company filed its
standard offer generation services component of rates in compliance with the
DPUC's decision, and the Company and ECTR concurrently filed a revised
stipulation and settlement proposal. These filings were approved by the DPUC on
December 9, 1999 and, on December 28, 1999, the Company and Enron Power
Marketing, Inc., another affiliate of Enron, entered into a Wholesale Power
Supply Agreement, a PPA Entitlements Transfer Agreement and related agreements
documenting the approved four-year standard offer power supply arrangement and
the assumption of all of the Company's PPAs, effective January 1, 2000. From
January 1, 2000 through June 30, 2000, EPMI will sell to the Company energy
beyond that supplied by Wisvest as described above. The agreements also provide
for the sale to EPMI of the Company's entitlements under all of its wholesale
purchased power agreements (PPAs). However, unless or until a PPA is terminated
or formally assigned to EPMI, the Company remains legally liable to pay the
applicable power supplier all amounts due under the PPA. The agreements with
EPMI also include a financially settled contract for differences related to
certain call rights of EPMI and put rights of the Company with respect to the
Company's entitlements in Seabrook Unit 1 and in Millstone Unit 3, and the
Company's provision to EPMI of certain ancillary products and services
associated with those nuclear entitlements, which provisions terminate at the
earlier of December 31, 2003 or the date that the Company sells its nuclear
interests. The agreements do not restrict the Company's right to sell to third
parties the Company's ownership interests in those nuclear generation units or
the generated energy actually attributable to its ownership interests.
Based on the decisions in the regulatory proceedings described above, the
sale of the Company's fossil-generation assets in the second quarter of 1999,
the planned divestiture of its nuclear generation ownership interests by the end
of 2003, and in anticipation of the Restructuring Act becoming effective on
January 1, 2000, the Company ceased applying SFAS No. 71 to the generation
portion of its assets and operations as of December 31, 1999. Based on the
favorable DPUC decisions that allow full recovery, through the Company's rates,
of all historically incurred stranded costs, the Company did not record any
write-offs in connection with this event.
- 56 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(D) ACCOUNTING FOR PHASE-IN PLAN
The Company phased into rate base its allowable investment in Seabrook Unit
1, amounting to $640 million, during the period January 1, 1990 to January 1,
1994. In conjunction with this phase-in plan, the Company was allowed to record
a deferred return on the portion of allowable investment excluded from rate base
during the phase-in period. The Company amortized the net-of-tax accumulated
deferred return of $62.9 million over the five-year period that ended on
December 31, 1999.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 7, 2000. The borrowing limit of this facility is
$60 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by the Eurodollar interbank market in
London. If a material adverse change in the business, operations, affairs,
assets or condition, financial or otherwise, or prospects of the Company and its
subsidiaries, on a consolidated basis, should occur, the banks may decline to
lend additional money to the Company under this revolving credit agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and payable. As of December 31, 1999, the Company had $17 million in
short-term borrowings outstanding under this facility.
The Company's long-term debt instruments do not limit the amount of
short-term debt that the Company may issue. The Company's revolving credit
agreement described above requires it to maintain an available earnings/interest
charges ratio of not less than 1.5:1.0 for each 12-month period ending on the
last day of each calendar quarter. For the 12-month period ended December 31,
1999, this coverage ratio was 4.7:1.0.
Information with respect to short-term borrowings under the Company's
revolving credit agreements is as follows:
[Enlarge/Download Table]
1999 1998 1997
---- ---- ----
(000's)
Maximum aggregate principal amount of short-term borrowings
outstanding at any month-end $80,000 $130,000 $50,000
Average aggregate short-term borrowings outstanding during the year* $45,300 $115,753 $41,441
Weighted average interest rate* 5.5% 6.1% 5.9%
Principal amounts outstanding at year-end $17,000 $80,000 $30,000
Annualized interest rate on principal amounts outstanding at year-end 7.0% 5.7% 6.2%
*Average short-term borrowings represent the sum of daily borrowings
outstanding, weighted for the number of days outstanding and divided by the
number of days in the period. The weighted average interest rate is determined
by dividing interest expense by the amount of average borrowings. Commitment
fees of approximately $291,000 and $381,000 paid during 1999 and 1998,
respectively, are excluded from the calculation of the weighted average interest
rate.
- 57 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
[Enlarge/Download Table]
1999 1998 1997
--- ---- ----
Income tax expense consists of: (In thousands)
Income tax provisions:
Current
Federal $91,247 $36,774 $23,568
State 23,891 10,685 7,545
------------ ----------- -----------
Total current 115,138 47,459 31,113
------------ ----------- -----------
Deferred
Federal (39,767) 2,964 6,123
State (13,004) 110 681
------------ ----------- -----------
Total deferred (52,771) 3,074 6,804
------------ ----------- -----------
Investment tax credits (467) (762) (762)
------------ ----------- -----------
Total income tax expense $61,900 $49,771 $37,155
============ =========== ===========
Income tax components charged as follows:
Operating expenses $66,564 $53,619 $40,833
Other income and deductions - net (4,664) (3,848) (3,678)
------------ ----------- -----------
Total income tax expense $61,900 $49,771 $37,155
============ =========== ===========
The following table details the components
of the deferred income taxes:
Gain on sale of utility property ($70,573) ($697) ($272)
Tax depreciation on unrecoverable plant investment 5,902 6,291 8,089
Fossil plants decommissioning reserve (116) (329) (7,286)(1)
Conservation & load management (2,181) (8,026) (5,768)
Accelerated depreciation 4,996 5,449 5,681
Pension benefits 4,192 3,463 4,911
Seabrook sale/leaseback transaction (69) 304 2,664
Cancelled nuclear project (467) (467) (467)
Unit overhaul and replacement power costs 1,523 (1,157) 212
Displaced worker protection costs 2,329 - -
Deferred fossil fuel costs - - (686)
Bond redemption costs (1,014) (1,039) 172
Property tax settlement 834 (834) -
Other 1,873 116 (446)
------------ ----------- -----------
Deferred income taxes - net ($52,771) $3,074 $6,804
============ =========== ===========
(1) $6,719 of this amount is for deferred income tax benefits from prior years.
- 58 -
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]
1999 1998 1997
---- ---- ----
PRE-TAX TAX PRE-TAX TAX PRE-TAX TAX
------- ------- ------- ------- ------- -------
(000's) (000's) (000's)
Computed tax at federal statutory rate $39,943 $33,195 $28,214
Increases (reductions) resulting from:
Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 12,586 4,405
ITC taken into income (468) (468) (762) (762) (762) (762)
Allowance for equity funds used during
construction (575) (201) (13) (5) (336) (118)
Fossil plant decommissioning reserve (262) (92) (723) (253) (15,591) (5,457)
Amortization of regulatory asset 22,635 7,922 - - - -
Book depreciation in excess of
non-normalized tax depreciation 16,155 5,654 22,789 7,976 23,926 8,374
State income taxes, net of federal
income tax benefits 10,887 7,076 10,795 7,017 8,226 5,345
Other items - net (6,683) (2,339) (5,149) (1,802) (8,134) (2,846)
------- ------- -------
Total income tax expense $61,900 $49,771 $37,155
======= ======= =======
Book income before income taxes $114,124 $94,843 $80,612
======== ======= =======
Effective income tax rates 54.2% 52.5% 46.1%
===== ===== =====
At December 31, 1999 the Company had deferred tax liabilities for taxable
temporary differences of $352 million and deferred tax assets for deductible
temporary differences of $88 million, resulting in a net deferred tax liability
of $264 million. Significant components of deferred tax liabilities and assets
were as follows: tax liabilities on book/tax plant basis differences and on the
cumulative amount of income taxes on temporary differences previously flowed
through to ratepayers, $215 million; tax liabilities on normalization of
book/tax depreciation timing differences, $125 million and tax assets on the
disallowance of plant costs, $35 million.
- 59 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
[Enlarge/Download Table]
1999 1998 1997
----- ----- ----
(000'S)
OPERATING REVENUES
------------------
Retail $639,596 $631,607 $622,333
Wholesale - capacity 2,235 11,524 9,747
- energy 22,099 33,424 73,124
Other 16,045 9,636 3,825
----------- ----------- -----------
Total Operating Revenues $679,975 $686,191 $709,029
=========== =========== ===========
SALES BY CLASS(MWH'S) - UNAUDITED
---------------------------------
Retail
Residential 2,053,927 1,924,724 1,899,284
Commercial 2,388,240 2,324,507 2,248,974
Industrial 1,161,856 1,154,935 1,168,470
Other 48,027 48,166 48,619
----------- ----------- -----------
5,652,050 5,452,332 5,365,347
Wholesale 1,009,866 1,551,109 2,700,393
----------- ----------- -----------
Total Sales 6,661,916 7,003,441 8,065,740
=========== =========== ===========
OTHER OPERATION EXPENSES
------------------------
Production $20,850 $28,427 $26,203
Transmission & Distribution 42,336 35,681 36,926
Customer Service 26,923 26,582 28,957
Administrative & General 57,600 55,368 66,514
----------- ----------- -----------
Total $147,709 $146,058 $158,600
=========== =========== ===========
DEPRECIATION
------------
Plant in service $53,347 $67,143 $65,585
Accelerated conservation and load management 0 13,086 6,636
Nuclear decommissioning 4,004 2,580 2,397
----------- ----------- -----------
$57,351 $82,809 $74,618
=========== =========== ===========
OTHER TAXES
-----------
Charged to:
Operating:
State gross earnings $24,518 $24,039 $23,571
Local real estate and personal property (1) 17,745 35,088 22,974
Payroll taxes 4,877 5,547 5,948
----------- ----------- -----------
47,140 64,674 52,493
Nonoperating and other accounts 598 510 459
----------- ----------- -----------
Total Other Taxes $47,738 $65,184 $52,952
=========== =========== ===========
OTHER INCOME AND (DEDUCTIONS) - NET
-----------------------------------
Interest income $1,801 $3,181 $2,317
Equity earnings from Connecticut Yankee 36 854 1,343
Loss from subsidiary companies (2) (590) (1,748) (3,639)
Miscellaneous other income and (deductions) - net (2,085) (1,190) 1,340
----------- ----------- -----------
Total Other Income and (Deductions) - net ($838) $1,097 $1,361
=========== =========== ===========
OTHER INTEREST CHARGES
----------------------
Notes Payable $2,662 $5,050 $2,462
Other 2,265 1,457 818
----------- ----------- -----------
Total Other Interest Charges $4,927 $6,507 $3,280
=========== =========== ===========
(1) 1998 includes $14,025 charge for property tax settlement.
(2) Includes before-tax non-recurring charges in 1997 of $2,825 resulting from
losses at American Payment Systems, Inc.
- 60 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(H) PENSION AND OTHER BENEFITS
The Company's qualified pension plan, which is based on the highest three
years of pay, covers substantially all of its employees, and its entire cost is
borne by the Company. The Company also has a non-qualified supplemental plan for
certain executives and a non-qualified retiree only plan for certain early
retirement benefits. The net pension costs for these plans for 1999, 1998 and
1997 were ($7,960,000), ($5,138,000), and ($4,626,000), respectively.
The Company's funding policy for the qualified plan is to make annual
contributions that satisfy the minimum funding requirements of ERISA but that do
not exceed the maximum deductible limits of the Internal Revenue Code. These
amounts are determined each year as a result of an actuarial valuation of the
plan. In 1997, the Company contributed $2.7 million for 1996 funding
requirements and $2.5 million for 1997 funding requirements. In 1998, the
Company contributed $2.6 million for 1998 funding requirements. The Company did
not make a contribution in 1999. The Company has established a supplemental
retirement benefit trust and through this trust purchased life insurance
policies on the officers of the Company to fund the future liability under the
supplemental plan. The cash surrender value of these policies is shown as an
investment on the Company's Consolidated Balance Sheet.
In addition to providing pension benefits, the Company also provides other
postretirement benefits (OPEB), consisting principally of health care and life
insurance benefits, for retired employees and their dependents. Employees whose
sum of age and years of service at time of retirement is equal to or greater
than 85 (or who are 62 with at least 20 years of service) are eligible for
benefits partially subsidized by the Company. The amount of benefits subsidized
by the Company is determined by age and years of service at retirement.
For funding purposes, the Company established a Voluntary Employees'
Benefit Association Trust (VEBA) to fund OPEB for the Company's union employees.
Approximately 47% of the Company's employees are represented by Local 470-1,
Utility Workers Union of America, AFL-CIO, for collective bargaining purposes.
The Company established a 401(h) account in connection with the qualified
pension plan to fund OPEB for the Company's non-union employees who retire on or
after January 1, 1994. The funding policy assumes contributions to these trust
funds to be the total OPEB expense calculated under SFAS No. 106, adjusted to
reflect a share of amounts expensed as a result of voluntary early retirement
programs minus pay-as-you-go benefit payments for pre-January 1, 1994 non-union
retirees, allocated in a manner that minimizes current income tax liability,
without exceeding maximum tax deductible limits. In accordance with this policy,
the Company did not make contributions to the union VEBA in 1999, 1998 and 1997.
The Company did not make a contribution to the 401(h) account in 1999 and
contributed $0.9 million and $1.7 million to the 401(h) account in 1998 and
1997, respectively. Plan assets for both the union VEBA and 401(h) account
consist primarily of equity and fixed-income securities.
The following table represents the plans' beginning benefit obligation
balance reconciled to the ending benefit obligation balance, beginning fair
value of plan assets balance reconciled to the ending fair value of plan assets
balance and the respective funded status reconciled to the Consolidated Balance
Sheet.
- 61 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
[Enlarge/Download Table]
AT DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
(000's)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $280,746 $259,545 $40,229 $35,112
Service Cost 5,334 4,389 549 1,078
Interest cost 17,470 17,828 2,276 2,576
Amendments 994 - 1,364 -
Actuarial (gain) loss (34,672) 14,064 (9,322) 4,002
Benefits paid (including expenses) (18,979) (15,080) (1,935) (2,539)
Acquisition/(Divestiture) (18,500) - (1,570) -
------- ------- ------ ------
Benefit obligation at end of year $232,393 $280,746 $31,591 $40,229
======= ======= ====== ======
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning
of year $268,684 $243,739 $23,203 $21,168
Actual return on plan assets 39,757 38,224 555 2,491
Employer contributions 2,525 2,914 208 910
Benefits paid (including expenses) (18,979) (16,193) (1,935) (1,366)
Acquisition/(Divestiture) (14,000) - (1,350) -
------- ------- ------ ------
Fair value of plan assets at end of year $277,987 $268,684 $20,681 $23,203
======= ======= ====== ======
Funded Status at December 31:
Projected benefits (less than) greater
than plan assets $(45,594) $12,062 $10,910 $17,026
Unrecognized prior service cost (3,731) (3,878) (291) 946
Unrecognized transition asset 5,552 7,274 (13,435) (16,368)
Unrecognized net gain (loss) from
past experience 62,799 15,639 7,674 1,241
------- ------ ------ ------
Accrued benefit obligation $ 19,026 $31,097 $ 4,858 $ 2,845
======= ====== ====== ======
[Enlarge/Download Table]
AT DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
The following actuarial assumptions were used
in calculating the benefit obligations at
December 31:
Discount rate 7.50% 6.75% 7.50% 6.75%
Average wage increase 4.50% 4.50% 4.50% 4.50%
Health care cost trend rate N/A N/A 5.50% 5.50%
- 62 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The components of net periodic benefit cost are:
[Enlarge/Download Table]
FOR THE YEAR ENDED DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
(000's)
Components of net periodic benefit cost:
Service cost $ 5,334 $ 4,389 $ 549 $ 1,078
Interest cost 17,470 17,828 2,276 2,576
Expected return on plan assets (28,677) (25,934) (2,463) (2,249)
Amortization of:
Prior service costs 537 406 11 (71)
Transition obligation (asset) (1,097) (1,095) 1,169 1,169
Actuarial (gain) loss (1,527) (1,132) (801) (361)
Settlements (curtailments) - 400 - -
------ ------ ----- ------
Net periodic benefit cost $(7,960) $(5,138) $ 741 $ 2,142
======= ======= ==== ======
[Enlarge/Download Table]
FOR THE YEAR ENDED DECEMBER 31,
PENSION BENEFITS OTHER POST-RETIREMENT BENEFITS
1999 1998 1999 1998
---- ---- ---- ----
The following actuarial assumptions were used
in calculating net periodic benefit cost:
Discount rate 6.75% 7.25% 6.75% 7.25%
Average wage increase 4.50% 4.50% 4.50% 4.50%
Return on plan assets 11.00% 11.00% 11.00% 11.00%
Health care cost trend rate N/A N/A 5.50% 5.50%
A one percentage point change in the assumed health care cost trend rate would
have the following effects:
1% INCREASE 1% DECREASE
----------- -----------
(000's)
Aggregate service and interest cost components $346 $(344)
Accumulated postretirement benefit obligation $3,316 $(3,608)
The Company has an Employee Savings Plan (401(k) Plan) in which
substantially all employees are eligible to participate. The 401(k) Plan enables
employees to defer receipt of up to 15% of their compensation and to invest such
funds in a number of investment alternatives. The Company also has an Employee
Stock Ownership Plan (ESOP) for substantially all its employees. The Company
makes matching contributions to the ESOP, in the form of Company common stock,
based on each employee's salary deferrals in the 401(k) Plan. The matching
contribution currently equals fifty cents for each dollar of the employee's
compensation deferred, but is not more than three and three-eighths percent of
the employee's annual salary. The Company's matching contributions to the ESOP
during 1999, 1998 and 1997 were $1.5 million, $1.7 million and $1.7 million,
respectively.
The Company pays dividends on the shares of stock in the ESOP to the
participant and the Company receives a tax deduction for the dividends paid. The
Company also makes contributions to the ESOP equal to 25% of the dividends paid
to each participant. The Company's annual contributions during 1999, 1998 and
1997 were $319,000, $270,000 and $417,000, respectively.
- 63 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(I) JOINTLY OWNED PLANT
At December 31, 1999, the Company had the following interests in jointly
owned plants:
OWNERSHIP/
LEASEHOLD PLANT ACCUMULATED
SHARE INVESTMENT (1) DEPRECIATION
--------- ---------- ------------
(Millions)
Seabrook Unit 1 17.5 % $658 $164
Millstone Unit 3 3.685 136 66
(1) Of the plant investment amounts, $456 million for Seabrook Unit 1 and $62
million for Millstone Unit 3 are reflected on the consolidated balance
sheet as regulatory assets.
The Company's share of the operating costs of jointly owned plants is
included in the appropriate expense captions in the Consolidated Statement of
Income.
(J) UNAMORTIZED CANCELLED NUCLEAR PROJECT
From December 1984 through December 1992, the Company had been recovering
its investment in Seabrook Unit 2, a partially constructed nuclear generating
unit that was cancelled in 1984, over a regulatory approved ten-year period
without a return on its unamortized investment. In the Company's 1992 rate
decision, the DPUC adopted a proposal by the Company to write off its remaining
investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period,
corresponding with the flowback of certain Connecticut Corporation Business Tax
(CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit
2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not
deducted from rate base during the 24-year period of amortization in recognition
of a longer period of time for amortization of the Seabrook Unit 2 balance. As a
result of reducing its remaining unamortized investment in Seabrook Unit 2 with
proceeds from the sale of certain Seabrook Unit 2 equipment, the Company expects
to completely amortize its unamortized investment in the year 2007.
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company had a Fossil Fuel Supply Agreement with a financial institution
providing for the financing of up to $37.5 million of fossil fuel purchases. On
April 16, 1999, the Company sold all of its operating non-nuclear generation
facilities to an unaffiliated entity. See Note (C), "Rate-Related Regulatory
Proceedings." As a result, the Company no longer has a need to acquire fossil
fuel. The Company and the financial institution agreed to terminate this
agreement as of May 31,1999 at no cost to the Company.
The Company also has lease arrangements for data processing equipment,
office equipment, vehicles and office space, including the lease of a
distribution service facility, which is recognized as a capital lease. The gross
amount of assets recorded under capital leases and the related obligations of
those leases as of December 31, 1999 are recorded on the balance sheet.
Future minimum lease payments under capital leases, excluding the Seabrook
sale/leaseback transaction, which is being treated as a long-term financing, are
estimated to be as follows:
- 64 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(000's)
2000 $ 1,696
2001 1,696
2002 1,696
2003 1,696
2004 16,000
After 2004 -
------
Total minimum capital lease payments 22,784
Less: Amount representing interest 6,278
------
Present value of minimum capital lease payments $16,506
=======
Capitalization of leases has no impact on income, since the sum of the
amortization of a leased asset and the interest on the lease obligation equals
the rental expense allowed for ratemaking purposes.
Operating leases, which are charged to operating expense, consist
principally of a large number of small, relatively short-term, renewable
agreements for a wide variety of equipment. In addition, the Company has an
operating lease for its corporate headquarters. Future minimum lease payments
under this lease are estimated to be as follows:
(000's)
2000 $ 6,524
2001 6,837
2002 8,168
2003 9,125
2004 9,242
2005-2012 81,966
-------
Total $121,862
========
Rental payments charged to operating expenses in 1999, 1998 and 1997,
including rental payments for its corporate headquarters, were $11.0 million,
$11.7 million and $12.2 million, respectively.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM (UNAUDITED)
The Company's 2000-2004 estimated capital expenditure program, excluding
allowance for funds used during construction, is presently budgeted as follows:
[Enlarge/Download Table]
2000 2001 2002 2003 2004 TOTAL
---- ---- ---- ---- ---- -----
(000's)
Nuclear Generation (1) $ 3,113 $ 3,591 $ - $ - $ - $ 6,704
Distribution and Transmission 46,652 25,393 16,068 13,450 30,850 132,413
------ ------ ------ ------ ------ -------
Subtotal 49,765 28,984 16,068 13,450 30,850 139,117
Nuclear Fuel 8,317 7,090 2,880 8,394 - 26,681
------ ------ ------ ------ ------ -------
Total Utility Expenditures 58,082 36,074 18,948 21,844 30,850 165,798
Total Non-Regulated Business
Expenditures 4,294 5,364 3,864 4,038 4,167 21,727
------ ------ ------ ------ ------ -------
Total $62,376 $41,438 $22,812 $25,882 $35,017 $187,525
======= ======= ======= ======= ======= ========
(1) The Connecticut Restructuring Act and decisions of the Connecticut DPUC do
not allow for the capitalization of nuclear generation costs, other than
for nuclear fuel, beyond 2001.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $88.1 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $88.1 million, or $4.4
million. The maximum assessment is adjusted at least every five years to reflect
the impact of inflation. With respect to each of the two operating nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $18.6 million per incident. However, any
assessment would be limited to $2.1 million per incident per year.
The NRC requires each operating nuclear generating unit to obtain property
insurance coverage in a minimum amount of $1.06 billion and to establish a
system of prioritized use of the insurance proceeds in the event of a nuclear
incident. The system requires that the first $1.06 billion of insurance proceeds
be used to stabilize the nuclear reactor to prevent any significant risk to
public health and safety and then for decontamination and cleanup operations.
Only following completion of these tasks would the balance, if any, of the
segregated insurance proceeds become available to the unit's owners. For each of
the two operating nuclear generating units in which the Company has an interest,
the Company is required to pay its ownership and/or leasehold share of the cost
of purchasing such insurance. Although each of these units has purchased $2.75
billion of property insurance coverage, representing the limits of coverage
currently available from conventional nuclear insurance pools, the cost of a
nuclear incident could exceed available
- 66 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
insurance proceeds. Under those circumstances, the nuclear insurance pools that
provide this coverage may levy assessments against the insured owner companies
if pool losses exceed the accumulated funds available to the pool. The maximum
potential assessments against the Company with respect to losses occurring
during current policy years are approximately $3.1 million.
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee.
The power purchase contract under which the Company has purchased its 9.5%
entitlement to the Connecticut Yankee Unit's power output permits Connecticut
Yankee to recover 9.5% of all of its costs from the Company. In December of
1996, Connecticut Yankee filed decommissioning cost estimates and amendments to
the power contracts with its owners with the Federal Energy Regulatory
Commission (FERC). Based on regulatory precedent, this filing seeks confirmation
that Connecticut Yankee will continue to collect from its owners its
decommissioning costs, the unrecovered investment in the Connecticut Yankee Unit
and other costs associated with the permanent shutdown of the Connecticut Yankee
Unit. On August 31, 1998, a FERC Administrative Law Judge (ALJ) released an
initial decision regarding Connecticut Yankee's December 1996 filing. The
initial decision contains provisions that would allow Connecticut Yankee to
recover, through the power contracts with its owners, the balance of its net
unamortized investment in the Connecticut Yankee Unit, but would disallow
recovery of a portion of the return on Connecticut Yankee's investment in the
unit. The ALJ's decision also states that decommissioning cost collections by
Connecticut Yankee, through the power contracts, should continue to be based on
a previously-approved estimate until a new, more reliable estimate has been
prepared and tested. During October of 1998, Connecticut Yankee and its owners
filed briefs setting forth exceptions to the ALJ's initial decision. If this
initial decision is upheld by the FERC, Connecticut Yankee could be required to
write off a portion of the regulatory asset on its Balance Sheet associated with
the retirement of the Connecticut Yankee Unit. In this event, however, the
Company would not be required to record any write-off on account of its 9.5%
ownership share in Connecticut Yankee, because the Company has recorded its
regulatory asset associated with the retirement of the Connecticut Yankee Unit
net of any return on investment. The Company cannot predict, at this time, the
outcome of the FERC proceeding. However, the Company will continue to support
Connecticut Yankee's efforts to contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.0
million) and return on investment (approximately $3.8 million) at December 31,
1999, is approximately $27.1 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.45% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. The
Company is obligated to furnish a guarantee for its participating share of the
debt financing for the Phase II facility. As of December 31, 1999, the Company's
guarantee liability for this debt was approximately $6.2 million.
- 67 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water quality, hazardous waste handling and
disposal, toxic substances, and electric and magnetic fields, the Company may
incur substantial capital expenditures for equipment modifications and
additions, monitoring equipment and recording devices, and it may incur
additional operating expenses. Litigation expenditures may also increase as a
result of scientific investigations, and speculation and debate, concerning the
possibility of harmful health effects of electric and magnetic fields. The total
amount of these expenditures is not now determinable.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.4 million had been incurred as of December 31, 1999, and that
the value of the property following remediation will not exceed $6.0 million. As
a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and the deactivated English Station generation facilities. In
addition, the Company is currently replacing the bulkhead that surrounds this
site, at an estimated cost of $13.5 million. Of this amount, $4.2 million
represents the portion of the costs to protect the Company's transmission
facilities and will be capitalized as plant in service. The remaining estimated
cost of $9.3 million was expensed in 1999.
As described at Note (C), "Rate-Related Regulatory Proceedings," the
Company has sold its Bridgeport Harbor Station and New Haven Harbor Station
generating plants in compliance with Connecticut's electric utility industry
restructuring legislation. Environmental assessments performed in connection
with the marketing of these plants indicate that substantial remediation
expenditures will be required in order to bring the plant sites into compliance
with applicable Connecticut minimum standards following their sale. The
purchaser of the plants has agreed to undertake and pay for the major portion of
this remediation. However, the Company will be responsible for remediation of
the portions of the plant sites that will be retained by it.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
Costs associated with nuclear plant operations include amounts for disposal
of nuclear wastes, including spent fuel, and for the ultimate decommissioning of
the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department
of Energy (DOE) is required to design, license, construct and operate a
permanent repository for high level radioactive wastes and spent nuclear fuel.
The Act requires the DOE to provide for the disposal of spent nuclear fuel and
high level radioactive waste from commercial nuclear plants through contracts
with the owners and generators of such waste; and the DOE has established
disposal fees that are being paid to the federal government by electric
utilities owning or operating nuclear generating units. In return for payment of
the prescribed fees, the federal government was required to take title to and
dispose of the utilities' high level wastes and spent nuclear fuel beginning no
later than January 1998. However, the DOE has announced that its first high
level waste repository will not be in operation earlier than 2010, and possibly
not earlier than 2013, and that, absent a repository, the DOE has no statutory
obligation to begin taking high level wastes and spent nuclear fuel for disposal
by January 1998. However, numerous utilities and states have obtained a judicial
declaration that the DOE has a statutory responsibility to take title to and
dispose of high level wastes and spent nuclear fuel beginning in January 1998,
and that the contracts between the DOE and the plant
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
owners and generators of such waste will provide a potentially adequate remedy
to owners and generators in monetary damages for breach of the contracts. The
DOE is contesting these judicial declarations; and it is unclear at this time
whether the United States Congress will enact legislation to address spent
fuel/high level waste disposal issues.
Until the federal government begins receiving such materials, nuclear
generating units will need to retain high level wastes and spent nuclear fuel
on-site or make other provisions for their storage. Storage facilities for the
Connecticut Yankee Unit are deemed adequate, and storage facilities for
Millstone Unit 3 are expected to be adequate for the projected life of the unit.
Storage facilities for Seabrook Unit 1 are expected to be adequate until at
least 2010. Fuel consolidation and compaction technologies are being considered
for Seabrook Unit 1 and may provide adequate storage capability for the
projected life of the unit. In addition, other licensed technologies, such as
dry storage casks, may satisfy spent nuclear fuel storage requirements.
Disposal costs for low-level radioactive wastes (LLW) that result from
operation or decommissioning of nuclear generating units decreased in 1999, as a
result of negotiations between the generators of such wastes and the owners of
licensed disposal facilities. Currently, the Chem Nuclear LLW facility at
Barnwell, South Carolina, is open to the Connecticut Yankee Unit, Millstone Unit
3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW facility at
Clive, Utah, is also open to these generating units for portions of their LLW.
All three units have contracts in place for LLW disposal at these disposal
facilities.
Because access to a LLW disposal facility may be lost at any time,
Millstone Unit 3 and Seabrook Unit 1 have storage plans that will allow on-site
retention of LLW for at least five years in the event that disposal is
interrupted. The Connecticut Yankee Unit, which has been retired from commercial
operation, has a similar storage program, although disposal of its LLW will take
place in connection with its decommissioning.
The Company cannot predict whether or when a LLW disposal site will be
designated in Connecticut. The State of New Hampshire has not met deadlines for
compliance with the Low-Level Radioactive Waste Policy Act and has stated that
the state is unsuitable for a LLW disposal facility. Both Connecticut and New
Hampshire are also pursuing other options for out-of-state disposal of LLW.
Connecticut and New Jersey, who have formed the Northeast Interstate LLW
Compact, are negotiating terms for South Carolina to join them, which would
increase the likelihood that the Connecticut Yankee Unit and Millstone Unit 3
will have access to the Chem Nuclear LLW facility at Barnwell, South Carolina,
through the end of their decommissioning.
NRC licensing requirements and restrictions are also applicable to the
decommissioning of nuclear generating units at the end of their service lives,
and the NRC has adopted comprehensive regulations concerning decommissioning
planning, timing, funding and environmental reviews. The Company and the other
owners of the nuclear generating units in which the Company has interests
estimate decommissioning costs for the units and attempt to recover sufficient
amounts through their allowed electric rates, together with earnings on the
investment of funds so recovered, to cover expected decommissioning costs.
Changes in NRC requirements or technology, as well as inflation, can increase
estimated decommissioning costs.
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $565 million (in 2000 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $99 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. The Company's share of the decommissioning payments
made during 1999 was $3.3 million. The Company's share of the fund at December
31, 1999 was approximately $20.5 million.
- 69 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $619 million (in 2000 dollars), of which the
Company's share would be approximately $23 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). The Company's share of the Millstone Unit 3 decommissioning
payments made during 1999 was $0.7 million. The Company's share of the fund at
December 31, 1999 was approximately $7.8 million. The current decommissioning
cost estimate for the Connecticut Yankee Unit, assuming the prompt removal and
dismantling of the unit, is $498 million, of which the Company's share would be
$47 million. Through December 31, 1999, $169 million has been expended for
decommissioning. The projected remaining decommissioning cost is $329 million,
of which the Company's share would be $31 million. The decommissioning trust
fund for the Connecticut Yankee Unit is also managed by NU. For the Company's
9.5% equity ownership in Connecticut Yankee, decommissioning costs of $2.4
million were funded by the Company during 1999, and the Company's share of the
fund at December 31, 1999 was $17.7 million.
The Financial Accounting Standards Board (FASB) expects to issue a revised
exposure draft related to the accounting for the closure and removal costs of
long-lived assets, including nuclear plant decommissioning. If the proposed
accounting standard were adopted, it may result in higher annual provisions for
decommissioning to be recognized earlier in the operating life of nuclear units
and an accelerated recognition of the decommissioning obligation. The FASB will
be deliberating this issue, and the resulting final pronouncement is not
expected to be effective prior to 2002.
(N) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments are as
follows:
[Enlarge/Download Table]
1999 1998
---- ----
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(000's) (000's)
Unrestricted cash and temporary cash investments $39,099 $39,099 $97,689 $97,689
Long-term debt (1)(2)(3) $420,217 $399,767 $606,342 $611,524
(1) Excludes the obligation under the Seabrook Unit 1 sale/leaseback agreement.
(2) The fair market value of the Company's long-term debt is estimated by
brokers based on market conditions at December 31, 1999 and 1998,
respectively.
(3) See Note (B), "Capitalization - Long-Term Debt."
- 70 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(O) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1999 and 1998 are set forth below:
[Enlarge/Download Table]
OPERATING OPERATING NET EARNINGS PER SHARE OF
QUARTER REVENUES INCOME INCOME COMMON STOCK(1)
------- --------- ------ ------ ---------------
(000's) (000's) (000's) Basic Diluted
----- -------
1999
----
First Quarter $168,667 $23,207 $ 9,901 $ .70 $ .70
Second Quarter 164,533 25,193 13,986 .99 .99
Third Quarter 199,071 34,183 24,997 1.78 1.78
Fourth Quarter 147,704 10,972 3,340 .24 .24
1998
----
First Quarter $162,474 $22,677 $8,962 $0.64 $0.64
Second-Originally Reported $159,792 $21,174 $5,497 $0.39 $0.39
Provision - APS accounts receivable - - 2,882 0.21 0.21
------- ------ ------ ----- -----
Second-As Restated $159,792 $21,174 $8,379 $0.60 $0.60
======== ======= ====== ===== =====
Third Quarter $198,601 $37,462 $26,236 $1.87 $1.87
Fourth Quarter (2) $165,324 $15,013 $1,495 $0.10 $0.10
------------------
(1) Based on weighted average number of shares outstanding each quarter.
(2) Operating income, net income and earnings per share for the fourth quarter
of 1998 included an after-tax charge of $8.3 million, associated with a
property tax settlement.
(P) SEGMENT INFORMATION
The Company has one reportable operating segment, that of regulated
generation, distribution and sale of electricity. The accounting policies used
for that segment do not differ from those used for nonreportable operating
segments. Revenues from inter-segment transactions are not material and all of
the Company's revenues are derived in the United States.
The revenues from external customers, interest income, interest expense and
depreciation charges of the one reportable segment are identical to the amounts
shown on the Consolidated Statement of Income for each year presented. Income
before taxes of the reportable segment is not materially different from that of
the Company as a whole.
The following table reconciles the total assets of the reportable segment
with the total assets shown on the Consolidated Balance Sheet at December 31:
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1999 1998
---- ----
(000's)
Total Assets - Regulated Utility $1,809,451 $1,943,328
Total Assets - Unregulated Subsidiaries 194,642 83,306
Total Assets - Elimination (205,883) (85,474)
--------- ---------
Total Consolidated Assets $1,798,210 $1,941,160
========= =========
(Q) RESTATEMENT OF FINANCIAL RESULTS
AMERICAN PAYMENT SYSTEMS, INC. (APS) RESTATEMENTS
-------------------------------------------------
During the third quarter of 1999, the Company has restated its financial
statements for 1998, 1997 and 1996 for matters related to the timing of American
Payment Systems ("APS") agency collection reserves, for certain line loss
factors that affect the calculation of unbilled revenues and for cash, accounts
receivable and accounts payable amounts related to APS's collection agent
network. The Company had consultations with the staff of the Securities and
Exchange Commission and its independent accountants in determining these
restated amounts.
During 1997 and 1996, APS agent bank accounts were not fully reconciled at
the time APS balance sheet items were prepared to allow for the identification,
measurement and enforcement of material claims for recovery from APS agents for
defalcated amounts or from APS customers for checks returned by banks due to
insufficient funds. As a result, losses associated with collection agent errors
and defaults went undetected for extended periods of time. In the second quarter
of 1998, the Company performed a review of the accounting records at APS and
identified significantly past due agent collections of $4.9 million ($2.8
million, after-tax) that represented agent deposit shortfalls and uncollectible
agent check deposits. Pursuant to the result of this review, APS increased its
provision against their receivable balance by $4.9 million ($2.8 million,
after-tax) in the second quarter of 1998. The Company applied similar procedures
during 1996 and, based on the results, recorded a $4.5 million ($2.6 million,
after-tax) increase in its provision in the fourth quarter of 1996. Due to the
fact that these adjustments related to losses incurred in both current and prior
periods, the Company has restated the effects of these adjustments back to the
periods in which the losses occurred as shown below. The impact of the
adjustments described above was to reduce retained earnings as of January 1,
1998 by $2.8 million.
The restatement of cash, accounts receivable and accounts payable amounts
related to APS's collection agent network was recorded so as to include on the
Company's consolidated balance sheet amounts that had previously been recorded
on a net basis.
UNBILLED REVENUE RESTATEMENT
----------------------------
During the third quarter of 1999, the Company reviewed an adjustment of
$2.7 million ($1.6 million, after-tax) made to retail operating revenues in the
fourth quarter of 1997 related to the reversal of prior period overestimates of
transmission line losses. The Company uses an estimated line loss factor, based
upon a 24 month-moving historical line loss factor, to calculate the amount of
revenue from electricity sales that is unbilled during the period and therefore
should be accrued. This loss factor is applied to the known amount of
electricity delivered to the Company's transmission grid from internal and
external sources. Historically, this methodology provided a reasonable estimate
of the amount of unbilled revenue.
Beginning in the first quarter of 1996, the outages of four nuclear
generating units resulted in the Company purchasing power from other sources.
The electricity from other sources followed different transmission paths and
exhibited different line loss characteristics than the electricity generated by
the nuclear generating units. During this
- 72 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
period of time, the Company continued to utilize the 24 month-moving average
loss factor in order to smooth the impact of changes in the line loss factors in
the calculation of unbilled revenue amounts.
Based upon a review of the actual New England Power Pool line loss factors
during this period and the pattern of when they occurred, the Company has
restated the $1.2 million ($0.7 million, after-tax) of the adjustment made to
retail operating revenues, originally recorded in the fourth quarter of 1997, to
1996.
The following tables summarize the restatements that the Company has made
on net income, earnings per share and retained earnings.
Increase (decrease) in net income:
FOR THE YEAR ENDED DECEMBER 31,
1998 1997
---- ----
DESCRIPTION (000's)
-----------
1998 APS charge $ 2,882 $(1,643)
1997 unbilled revenues - (691)
------ -----
Net increase (decrease) to net income 2,882 (2,334)
Net income applicable to common shareholders,
as originally reported 42,010 45,634
------ ------
Net income applicable to common shareholders,
as restated $44,892 $43,300
====== ======
FOR THE YEAR ENDED DECEMBER 31,
DESCRIPTION 1998 1997
----------- ---- ----
Earnings per share, as originally reported
- Basic $3.00 $3.27
- Diluted $3.00 $3.26
Earnings per share, as restated
- Basic $3.20 $3.10
- Diluted $3.20 $3.09
AS OF DECEMBER 31,
1998 1997
---- ----
DESCRIPTION (000's)
-----------
Retained earnings, as originally reported $163,847 $162,226
Net effect of restatements, described above - (2,882)
------- --------
Retained earnings, as restated $163,847 $159,344
======== ========
Included in restricted cash at December 31, 1998 is $23,056, representing
collections by APS agents that are held in APS agent accounts prior to
transmittal to the respective APS customers. In addition, included in other
accounts receivable at December 31, 1998 is $26,768, representing collections by
APS agents not yet deposited into APS bank accounts. A corresponding accounts
payable has been recorded to reflect the portions of these collections owed to
APS customers, as well as the amount of restricted cash presented above. The
Company had previously presented its consolidated balance sheet net of these
accounts receivable and accounts payable amounts.
The following table summarizes the effect of the restatements described
above to restricted cash, other accounts receivable, and accounts payable - APS
customers:
- 73 -
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
AS OF DECEMBER 31,
1998
----
(000's)
Restricted cash, as originally reported $ -
Effect of restatement, described above 23,056
------
Restricted cash, as restated $23,056
======
Other accounts receivable, as originally reported (1) $37,472
Effect of restatement, described above
Additional accounts receivable for APS agents 26,768
Additional APS agent collection reserves -
------
Other accounts receivable, as restated $64,240
======
Accounts payable-APS customers, as originally reported $ -
Accounts payable-APS customers reclassed
from accounts payable 4,691
Effect of restatement, described above
Restricted cash 23,056
Additional amounts owed to APS customers 26,768
------
Accounts payable-APS customers, as restated $54,515
======
(1) Includes accounts receivable from APS agents originally included in other
accounts receivable of $4,691,000 as of December 31, 1998.
In addition, the Company has revised Schedule II on page S1 to reflect the
restatement of additional reserves for uncollectible accounts related to APS
agent collections.
- 74 -
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders
of The United Illuminating Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, and of changes in shareholders' equity and of
cash flows present fairly, in all material respects, the financial position of
The United Illuminating Company and its subsidiaries (the "Company") at December
31, 1999 and 1998, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 75 -
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and the Shareholders
of The United Illuminating Company:
Our audits of the consolidated financial statements referred to in our report
dated January 24, 2000 appearing in the 1999 Annual Report on Form 10-K also
included an audit of the financial statement schedule on page S-1 of this Form
10-K. In our opinion, this Financial Statement Schedule presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 76 -
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures.
Not Applicable
PART III
Item 10. Directors and Executive Officers of the Company.
DIRECTORS OF THE COMPANY
The following table provides information regarding all persons who were
directors at any time during the fiscal year ended December 31, 1999 and all
persons who will be nominated to become directors at the Company's 2000 Annual
Meeting of the Shareowners. All of the persons named below will be nominated to
become directors at the 2000 Annual Meeting of the Shareowners except Frank R.
O'Keefe, Jr., who will retire on the date of the Annual Meeting.
[Enlarge/Download Table]
NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
Thelma R. Albright 53 1995
President, Carter Products Division, Carter-Wallace, Inc., Cranbury, New Jersey.
During 1995, Ms. Albright was General Manager and Executive Vice President of
Revlon Beauty Care Division. Also, Director, Cosmetics, Toiletry and Fragrance
Association and Consumer Healthcare Products Association.
Marc C. Breslawsky 57 1995
President and Chief Operating Officer, Pitney Bowes, Inc., Stamford,
Connecticut. Also, Director, Pitney Bowes, Inc., Pitney Bowes Credit Corp., C.R.
Bard, Inc., Pittston Corp., The Family Foundation of North America, Connecticut
Business and Industry Association and United Way of Eastern Fairfield County;
Vice Chairman of the Governor's Council of Economic Competitiveness and
Technology; Member, Board of Governors, the State of Connecticut/Red Cross
Disaster Relief Cabinet and the Landmark Club; and Trustee, Norwalk Hospital.
David E. A. Carson 65 1993
Director, People's Bank, Bridgeport, Connecticut, and Trustee, People's Mutual
Holdings, Bridgeport, Connecticut. From 1985-1999 Mr. Carson was Chief Executive
Officer of People's Bank and People's Mutual Holdings. Also, Chairman,
Bridgeport Public Education Fund, Business Advisory Committee of Connecticut
Commission on Children and Bridgeport Area Foundation; and Director, Mass Mutual
Institutional Funds, MML Series Investment Funds, American Skandia Trust, Old
State House, Hartford, Connecticut, The Bushnell, Hartford, Connecticut, and
Hartford Stage Company.
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NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
Arnold L. Chase 48 1999
President, Gemini Networks, Inc., and Executive Vice President, Chase
Enterprises, Hartford, Connecticut. Also, Director, First International Bank,
Juvenile Diabetes Foundation International, Old State House Association,
Connecticut Historic Society and Science Center of Connecticut.
John F. Croweak 63 1987
Chairman of the Board of Directors, Anthem Blue Cross & Blue Shield of
Connecticut, Inc., North Haven, Connecticut. Prior to his retirement in 1997,
Mr. Croweak served as Chairman of the Board of Directors and Chief Executive
Officer of Anthem Blue Cross & Blue Shield of Connecticut and its predecessor,
Blue Cross & Blue Shield of Connecticut, Inc. Also Chairman of the Board of
Directors, Connecticut American Insurance Company, ProMed Systems, Inc., OPTIMED
Medical Systems and Signal Medical Services, Inc.; and Director, BCS Financial,
The New Haven Savings Bank, Quinnipiac College, Opticare and Anthem, Inc.
Robert L. Fiscus 62 1992
Vice Chairman of the Board of Directors, Chief Financial Officer, Treasurer and
Secretary, The United Illuminating Company. Mr. Fiscus served as President and
Chief Financial Officer of the Company during the period January 1995 to
February 1998 and as Vice Chairman of the Board of Directors and Chief Financial
Officer from February 1998 to October 1999. He has served as Vice Chairman of
the Board of Directors, Chief Financial Officer, Treasurer and Secretary since
October 1999. Also, Director, Bridgeport Regional Business Council, Griffin
Health Services Corporation, The Aristotle Corporation, Bridgeport Area
Foundation and Susquehanna University; Governor, University of New Haven; and
Trustee, Central Connecticut Coast Young Men's Christian Association, Inc.
Betsy Henley-Cohn 47 1989
Chairman of the Board of Directors, Joseph Cohn & Son, Inc., New Haven,
Connecticut. Also, Chairwoman of Birmingham Utilities, Inc.; and Director, The
Aristotle Corporation and Citizens Bank of Connecticut.
John L. Lahey 53 1994
President, Quinnipiac College, Hamden, Connecticut. Also, Director, Yale-New
Haven Hospital and The Aristotle Corporation; Vice Chairman and Director,
Regional Plan Association Board, New York, New York; and Member, Greater New
Haven Regional Leadership Council and Accreditation Committee of the American
Bar Association.
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NAME, PRINCIPAL OCCUPATION, OTHER
CORPORATE AFFILIATIONS AND PRINCIPAL OCCUPATIONS DIRECTOR
DURING THE PAST FIVE YEARS OF NOMINEE AGE SINCE
------------------------------------- --- -----
F. Patrick McFadden, Jr. 62 1987
Retired Chairman, Citizen's Bank of Connecticut, New Haven, Connecticut. During
the period 1995 through 1997, Mr. McFadden was President, Chief Executive
Officer and Director, The Bank of New Haven and BNH Bancshares, Inc. Also,
Chairman of the Board of Directors, Yale-New Haven Health Services Corporation;
and Member, Representative Policy Board of the South Central Connecticut
Regional Water District.
Daniel J. Miglio 59 1999
Formerly Chairman, President and Chief Executive Officer of Southern New England
Telecommunications Corporation during the period 1995 through 1998. Director,
The Aristotle Corporation, Yale-New Haven Health Services Corporation and
Connecticut Public Television and Radio; and Chairman, International Festival of
Arts and Ideas.
Frank R. O'Keefe, Jr. 70 1989
Retired; former President, Long Wharf Capital Partners, Inc. 1988-1990; retired
Chairman, President and Chief Executive Officer, Armtek Corporation 1986-1988;
President and Chief Operating Officer, Armstrong Rubber Company 1980-1986; and
Director, Aetna Inc.
James A. Thomas 60 1992
Associate Dean, Yale Law School. Also, Trustee, Yale-New Haven Hospital and
People's Mutual Holdings; and Director, People's Bank and Sea Research
Foundation.
Nathaniel D. Woodson 58 1998
Chairman of the Board of Directors, President and Chief Executive Officer, The
United Illuminating Company. Mr. Woodson served as President of the Energy
Systems Business Unit of Westinghouse Electric Corporation during the period
January 1995 to April 1996. He has served as President of the Company since
February 1998, Chief Executive Officer since May 1998 and Chairman of the Board
of Directors since January 1999.
There is no arrangement or understanding between any of the persons listed
above and any other person pursuant to which the person listed above was or is
selected as a director or director-nominee. There is no family relationship
between any of the persons listed above, or between any person listed above and
any executive officer, or person chosen to be an executive officer, of the
Company.
EXECUTIVE OFFICERS OF THE COMPANY
See "EXECUTIVE OFFICERS OF THE COMPANY" in PART I of this Annual Report on
Form 10-K for information regarding the Company's Executive Officers.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's
directors and officers, and persons who own more than ten percent of the
Company's Common Stock, to file with the Securities and Exchange Commission
(SEC) and The New York Stock Exchange initial reports of ownership and reports
of changes in ownership of Common Stock and other equity securities of the
Company. Directors, officers and certain greater-than-ten-percent shareowners
are required by SEC regulations to furnish the Company with copies of all
Section 16(a) forms they file.
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To the Company's knowledge, based solely on review of reports furnished to
the Company and written representations that no other reports were required,
during the fiscal year ended December 31, 1999 all Section 16(a) filing
requirements applicable to its directors, officers and greater-than-ten-percent
shareowners were complied with.
Item 11. Executive Compensation.
EXECUTIVE COMPENSATION
The following table shows the annual and long-term compensation, for
services in all capacities to the Company for the years 1999, 1998 and 1997, of
the person who served as the chief executive officer during 1999 and of the four
other most highly compensated persons during 1999 who were serving as executive
officers at December 31, 1999:
[Enlarge/Download Table]
LONG-TERM COMPENSATION
----------------------
NAME AND ANNUAL COMPENSATION SECURITIES UNDERLYING LTIP ALL OTHER
-------------------
PRINCIPAL POSITION(1) YEAR SALARY($) BONUS($)(2) OPTIONS/SARS(#) PAYOUTS($) COMPENSATION(6)
------------------ ---- --------- -------- --------------- ---------- ------------
Nathaniel D. Woodson 1999 $412,000 $220,000 21,000(7) $169,338
Chairman of the Board of 1998 341,668 105,000 80,000(8) 38,756
Directors, President and Chief
Executive Officer
Robert L. Fiscus 1999 $233,200 $110,000 15,500(7) $334,141(3) $8,471
Vice Chairman of the Board of 1998 224,900 55,000 260,691(4) 7,745
Directors, Chief Financial 1997 220,400 70,000 59,850(5) 7,360
Officer, Treasurer and Secretary
James F. Crowe 1999 $187,900 $70,000 8,000(7) $257,031(3) $7,750
Group Vice President 1998 181,200 37,000 200,531(4) 7,235
1997 177,600 55,000 42,750(5) 6,830
Anthony J. Vallillo 1999 $185,900 $68,000 8,000(7) $257,031(3) $7,105
Group Vice President 1998 175,700 46,000 72,191(4) 6,679
1997 170,000 55,000 6,840(5) 6,144
Albert N. Henricksen 1999 $162,700 $60,000 8,000(7) $154,219(3) $7,304
Group Vice President 1998 147,650 36,000 96,255(4) 6,876
1997 140,600 38,000 13,680(5) 6,401
-----------------------
(1) None of the persons named received any cash compensation in any of the
years shown other than the amounts appearing in the columns captioned
"Salary," "Bonus," "LTIP Payouts" and "All Other Compensation." None of
these persons received, in any of the years shown, any cash-equivalent form
of compensation, other than through participation in the Company's group
life, health and hospitalization plans, which are available on a uniform
basis to all salaried employees of the Company and the dollar value of
which, together with the dollar value of all other non-cash perquisites and
other personal benefits received by such person, did not exceed the lesser
of $50,000 or 10% of the total salary and bonus compensation received by
him for such year.
(2) The amounts appearing in this column are awards earned in the years 1997,
1998 and 1999 pursuant to the Executive Incentive Compensation Program
described below.
(3) This is the amount earned for the 1997-1999 performance period under the
1996 Long-Term Incentive Program as described below. The cash payouts were
made in February 2000.
(4) This is the amount earned for the 1996-1998 performance period under the
1996 Long-Term Incentive Program. The cash payouts were made in March 1999.
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(5) This is the amount earned for the 1995-1997 performance period under the
1993 Dividend Equivalent Program. Under this program, which was terminated
when the Long-Term Incentive Program described below was established in
1996, each officer of the Company was awarded a number of Dividend
Equivalent Units (Units) prior to the commencement of the 1995 performance
period and, due to the ranking of the Company's total shareowner return
during the performance period relative to the total shareowner returns of a
preselected peer group of companies, the officer earned a number of Units
that resulted in a cash payment equal to that number of Units multiplied by
the sum of all dividends paid per share on the Company's Common Stock
during the performance period. The cash payments were made in February,
1998.
(6) The amounts appearing in this column, except the amounts shown for Mr.
Woodson, are cash contributions by the Company to its Employee Stock
Ownership Plan (ESOP) on behalf of each of the persons named for (i) a
match of pre-tax elective deferral contributions by him to the Company's
401(k) Plan from his salary and bonus compensation (included in the columns
captioned "Salary" and "Bonus"), and (ii) an additional contribution by the
Company equal to 25% of the dividends paid on his shares in the ESOP. Cash
contributions of $5,403 and $5,521 were made on behalf of Mr. Woodson for
these purposes during 1998 and 1999 respectively, and are included in the
amount appearing in this column. In addition, during 1998, Mr. Woodson
received a reimbursement of his relocation expenses, in the amount of
$33,355, when he moved from Pennsylvania to Connecticut at the commencement
of his employment by the Company. In 1999, Mr. Woodson received $163,817 as
reimbursement for the costs associated with the selling of his residence in
Pennsylvania.
(7) These are stock options on shares of the Company's Common Stock granted on
March 22, 1999. The options are exercisable at the rate of one-third of the
options on each of the first three anniversaries of the grant date pursuant
to the terms of the 1999 Stock Option Plan as described below.
(8) These are phantom stock options on shares of the Company's Common Stock
granted to Mr. Woodson in February of 1998 at the time of his employment by
the Company as its President. The options are exercisable at the rate of
16,000 options on each of the first five anniversaries of the grant date
during the term of Mr. Woodson's employment agreement with the Company,
which is described below.
The Company's Executive Incentive Compensation Program was established in
1985 for the purposes of (i) helping to attract and retain executives and key
managers of high ability, (ii) heightening the motivation of those executives
and key managers to attain goals that are in the interests of shareowners and
customers, and (iii) encouraging effective management teamwork among the
executives and key managers of the Company. Under this program, cash awards may
be made each year to officers and key employees based on their achievement of
pre-established performance levels with respect to specific shareowner goals,
customer goals and individual goals for the preceding year, and upon an
assessment of the officers' performance as a group with respect to strategic
opportunities during that year, and based on such other factors as the Committee
deems relevant. Eligible officers, performance levels and specific goals are
determined each year by directors who are not employees of the Company, and
incentive awards are paid following action by the Board of Directors after the
close of the year. Incentive awards for the achievement of performance levels
and specific goals are made from individual target incentive award amounts,
which are prescribed percentages of the individual participants' salaries,
ranging from 20% to 35% depending on each participant's payroll salary grade. A
participant may, by achieving his or her pre-established performance levels with
respect to specific shareowner goals, customer goals and individual goals for a
year, become eligible for an incentive award for this achievement of up to 150%
of his or her target incentive award amount for that year.
The Company's 1996 Long-Term Incentive Program was established for the
purposes of (i) promoting the long-term success of the Company by attracting,
retaining and providing financial incentives to key employees who are in a
position to make significant contributions toward that success, (ii) linking the
interests of these key employees to the interests of the shareowners, and (iii)
encouraging these key employees to maintain proprietary interests in the Company
and achieve extraordinary job performance levels. Under the program, an initial
three-year Performance Period commenced on January 1, 1996, three-year
Performance Periods commenced on January 1, 1997 and January 1, 1998, and a
series of three-year Performance Periods was to commence on January 1, 1999 and
on each January 1 thereafter to and including January 1, 2005. In 1999, the
Board of Directors determined to substitute stock options, under the 1999 Stock
Option Plan described below, for the 1996 Long-Term
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Incentive Program. Under this Program, the Board of Directors has designated the
officer-participants in the program for each Performance Period, the number of
Contingent Performance Shares awarded each officer-participant for that
Performance Period, and a peer group of companies comparable to the Company for
that Performance Period. Each Contingent Performance Share is a share unit,
equivalent to one share of the Company's Common Stock, credited to an
officer-participant's performance share account in the program on a conditional
basis at the beginning of a Performance Period. At the end of each Performance
Period, the number of Performance Shares earned for the Performance Period is
calculated on the basis of the Company's total shareowner return during the
Performance Period relative to the peer group of companies preselected by the
Board of Directors for that Performance Period. Total shareowner return for the
Company, and for each member of the peer group, for a Performance Period is
measured by the formula:
Change in Market Price from + Dividends Declared During the Period
Beginning to End of Period
------------------------------------------------------------------------
Market Price at Beginning of Period
If the Company's total shareowner return for the Performance Period ranks at the
ninetieth percentile among the total shareowner returns of the peer group
companies, the number of Performance Shares earned by the officer-participant is
equal to the number of Contingent Performance Shares awarded to that
officer-participant at the commencement of the Performance Period. If the
Company's total shareowner return ranks below the thirtieth percentile among
those of the peer group companies, no Performance Shares are earned for the
Performance Period. If the Company's total shareowner return ranks between the
thirtieth and the ninetieth percentiles, the number of Performance Shares earned
is calculated from a scale rising from 15% to 100%. On each dividend payment
date with respect to the Company's Common Stock, the earned Performance Shares
in an officer-participant's Performance Share account are credited with an
additional number of Performance Shares in an amount equal to the dividend
payable on the earned Performance Shares in the account divided by the market
price of the Company's Common Stock on the dividend payment date. Upon the
termination of an officer-participant's employment by the Company, the
officer-participant is paid, in cash, an amount equal to the number of earned
Performance Shares in his or her Performance Share account multiplied by the
market price of the Company's Common Stock on the employment termination date.
An officer-participant is also entitled to payment at any time, in cash, of the
value of the earned Performance Shares in his or her Performance Share account,
provided that the officer-participant is in compliance with the minimum stock
ownership requirement for such officer prescribed by the Board of Directors at
that time.
The Company's 1999 Stock Option Plan is intended to promote the
profitability of the Company and its subsidiaries by providing directors,
officers and key full-time employees with incentives to contribute to the
Company's success, and enable the Company to attract, retain and reward the best
available directors and managerial employees. A maximum of 650,000 shares of
Common Stock may be purchased under the 1999 Stock Option Plan, and the maximum
number of shares that may be purchased through options granted in any one year
to any optionee may not exceed 50,000. Options under the 1999 Stock Option Plan
may be granted as incentive stock options, intended to qualify for favorable tax
treatment under federal tax law, or as nonqualified stock options. When
incentive stock options or nonqualified stock options become exercisable and are
exercised by the optionee to whom they have been granted, the optionee pays the
Company the exercise price per share fixed on the date of the option grant and
receives shares of Common Stock equal to the number of incentive stock options
or nonqualified stock options exercised. Directors who are not employees of the
Company select the optionees, determine the number of stock options to be
granted to each optionee, whether the stock options will be nonqualified stock
options or incentive stock options, and whether any stock option will include a
right to purchase an additional share of Common Stock contingent upon the option
holder's having exercised the stock option and having paid its exercise price in
full in shares of Common Stock (a "Reload Right"). The non-employee directors
also determine the period within which each stock option granted will be
exercisable, and may provide that the stock options will become exercisable in
installments.
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The following rules must be observed under the 1999 Stock Option Plan:
o the exercise price for each option must be equal to or greater than the
fair market value of the Common Stock on the date of the creation of the
option, determined by averaging the high and low sales prices of the Common
Stock on the New York Stock Exchange on that date,
o no option may be repriced after the date of its creation,
o no stock option may be exercisable less than one year, or more than ten
years, from the date it is granted,
o no more than 1/3 of the number of stock options granted to any optionee
on any date may first become exercisable in any twelve-month period,
o in the case of the grant of an incentive stock option to an optionee who,
at the time of the grant, owns more than 10% of the total combined voting
power of all classes of the stock of the Company or any of its
subsidiaries, in no event may the stock option be exercisable more than
five years from the date it is granted,
o in the case of incentive stock options, the number of stock options granted
to an optionee on any date that may first become exercisable in any
calendar year must be limited to $100,000 divided by the exercise price per
share,
o an option arising from the exercise of a Reload Right cannot be exercised
before the six-month anniversary of the date when the Reload Right was
exercised, and it will expire on the same date on which the option from
which it arose would have expired if it had not been exercised,
o except as otherwise provided in the 1999 Stock Option Plan, an employee
optionee may exercise a stock option only if he or she is, and has
continuously been since the date of the stock option was granted, a
full-time employee of the Company or one of its subsidiaries.
The Company has entered into an employment agreement with Mr. Woodson,
which will continue in effect until terminated by the Company at any time or by
the officer on six months' notice. This agreement provides that the annual
salary rate of Mr. Woodson will be $400,000, subject to upward revision by the
Board of Directors at such times as the salary rates for other officers of the
Company are reviewed by the Directors, and subject to downward revision by the
Board of Directors contemporaneously with any general reduction of the salary
rates of other officers of the Company, except in the event of a change in
control of the Company. The salary paid to Mr. Woodson in 1998 and 1999, shown
on the above table, was paid pursuant to this agreement. This agreement also
provides that when the officer's employment by the Company terminates after he
has served in accordance with its terms, the Company will pay him an annual
supplemental retirement benefit in an amount equal to the excess, if any, of (A)
over (B), where (A) is 2.0% of his highest three-year average total salary and
bonus compensation from the Company times the number of years (not to exceed 30)
of his deemed service as an employee of the Company, and (B) is the annual
benefit payable to him under the Company's pension plan. If the Company
terminates the officer's employment on less than three years' notice and without
cause, he will be paid the actuarial present value of this supplemental
retirement benefit and either a severance payment of up to two years'
compensation at his then-current salary and bonus rate, or an increase of a
total of six years of age and/or service in the calculation of his supplemental
retirement benefit and/or the benefits payable to him under the Company's
retiree medical benefit plans. Under the Company's Change in Control Severance
Plan, if Mr. Woodson's employment is terminated without cause within two years
following a change in control of the Company, he will be entitled to receive, in
lieu of his employment agreement termination benefits, a severance payment of
three years' compensation at his then-current salary and bonus rate, an increase
of three years of service in the calculation of his supplemental retirement
benefit and the benefits payable under the Company's retiree medical benefit
plans, and three years of continued participation in the Company's employee
benefit plans and programs.
The Company has also entered into employment agreements with Messrs. Fiscus
and Crowe, each of which will continue in effect until terminated by the Company
on three years' notice or by the officer on six months' notice. These agreements
provide that the annual salary rates of Messrs. Fiscus and Crowe will be
$218,400 and $176,600, respectively, subject to upward revision by the Board of
Directors at such times as the salary rates of other officers of the Company are
reviewed by the Directors, and subject to downward revision by the Board of
Directors contemporaneously with any general reduction of the salary rates of
other officers of the Company, except in the event of a change in control of the
Company. The salaries paid to Messrs. Fiscus and Crowe in 1997, 1998
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and 1999, shown on the above table, were paid pursuant to these agreements. Each
of these agreements also provides that when the officer's employment by the
Company terminates after he has served in accordance with its terms, the Company
will pay him an annual supplemental retirement benefit in an amount equal to the
excess, if any, of (A) over (B), where (A) is 2.2% of his highest three-year
average total salary and bonus compensation from the Company times the number of
years (not to exceed 30) of his service deemed as an employee of the Company,
and (B) is the annual benefit payable to him under the Company's pension plan.
If the Company terminates the officer's employment on less than three years'
notice and without cause, he will be paid the actuarial present value of this
supplemental retirement benefit and, if the termination occurs in connection
with a change in control of the Company, the officer will be entitled to either
a severance payment of two years' compensation at his then-current salary and
bonus rate, or an increase of a total of six years of age and/or service in the
calculation of his supplemental retirement benefit and/or the benefits payable
to him under the Company's retiree medical benefit plans. Under the Company's
Change in Control Severance Plan, if the officer's employment is terminated
without cause within two years following a change in control of the Company, he
will be entitled to receive, in lieu of his employment agreement termination
benefits, a severance payment of two years' compensation at his then-current
salary and bonus rate, an increase of two years of service in the calculation of
his supplemental retirement benefit and the benefits payable under the Company's
retiree medical benefit plans, and two years of continued participation in the
Company's employee benefit plans and programs.
The Company has also entered into employment agreements with Messrs.
Vallillo and Henricksen, each of which will continue in effect until terminated
by the Company at any time or by the officer on six months' notice. These
agreements provide that the annual salary rates of Messrs. Vallillo and
Henricksen will be $140,000 and $136,900, respectively, subject to upward
revision by the Board of Directors at such times as the salary rates for other
officers of the Company are reviewed by the Directors, and subject to downward
revision by the Board of Directors contemporaneously with any general reduction
of the salary rates of other officers of the Company, except in the event of a
change in control of the Company. The salaries paid to Messrs. Vallillo and
Henricksen in 1997, 1998 and 1999, shown on the above table, were paid pursuant
to these agreements. Each of these agreements also provides that when the
officer's employment by the Company terminates after he has served in accordance
with its terms, the Company will pay him an annual supplemental retirement
benefit in an amount equal to the excess, if any, of (A) over (B), where (A) is
2.0% of his highest three-year average total salary and bonus compensation from
the Company times the number of years (not to exceed 30) of his service as an
employee of the Company, and (B) is the annual benefit payable to him under the
Company's pension plan. If the Company terminates the officer's employment
without cause, he will be paid the actuarial present value of this supplemental
retirement benefit and either a severance payment of two years' compensation at
his then-current salary and bonus rate, or an increase of a total of six years
of age and/or service in the calculation of his supplemental retirement benefit
and/or the benefits payable to him under the Company's retiree medical benefit
plans. Under the Company's Change in Control Severance Plan, if the officer's
employment is terminated without cause within two years following a change in
control of the Company, he will be entitled to receive, in lieu of his
employment agreement termination benefits, a severance payment of two years'
compensation at his then-current salary and bonus rate, an increase of two years
of service in the calculation of his supplemental retirement benefit and the
benefits payable under the Company's retiree medical benefit plans, and two
years of continued participation in the Company's employee benefit plans and
programs
A trust fund has been established by the Company for the funding of the
supplemental retirement benefits accruing under the employment agreements with
Messrs. Woodson, Fiscus, Crowe, Vallillo and Henricksen, and to ensure the
performance of the Company's other payment obligations under each of these
employment agreements in the event of a change in control of the Company.
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OPTION/SAR GRANTS IN LAST FISCAL YEAR
[Enlarge/Download Table]
NUMBER OF % OF TOTAL POTENTIAL REALIZABLE VALUE
SECURITIES OPTIONS/SARS AT ASSUMED ANNUAL RATES
UNDERLYING GRANTED TO EXERCISE OR OF STOCK PRICE APPRECIATION
OPTIONS/SARS EMPLOYEES IN BASE PRICE EXPIRATION FOR OPTION TERM
----------------------------
NAME GRANTED (#) FISCAL YEAR ($/SHARE) DATE 5%($) 10%($)
---- ----------- ----------- --------- ---- ----- ------
Nathaniel D. Woodson 21,000 15.3% $43.2188 03/22/09 $453,797 $907,594
Robert L. Fiscus 15,500 11.3% 43.2188 03/22/09 334,945 669,891
James F. Crowe 8,000 5.8% 43.2188 03/22/09 172,875 345,750
Anthony J. Vallillo 8,000 5.8% 43.2188 03/22/09 172,875 345,750
Albert N. Henricksen 8,000 5.8% 43.2188 03/22/09 172,875 345,750
-------------------
These are stock options on shares of the Company's Common Stock granted on
March 22, 1999. The options are exercisable at the rate of one-third of the
options on each of the first three anniversaries of the grant date.
STOCK OPTION EXERCISES IN 1999 AND YEAR-END OPTION VALUES
The following table shows aggregated Common Stock option exercises during
1999 by the chief executive officers and each of the other four most highly
compensated executive officers of the Company, including the aggregate value of
gains realized on the dates of exercise. In addition, this table shows the
number of shares covered by both exercisable and non-exercisable options as of
December 31, 1999. Also reported are the values as of December 31, 1999 for
"in-the-money" options, calculated as the positive spread between the exercise
price of existing options and the year-end fair market value of the Company's
Common Stock.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
[Enlarge/Download Table]
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS/SARS
ACQUIRED ON VALUE OPTIONS/SARS AT FY-END(#) AT FY-END ($)(2)
------------------------- -------------
NAME EXERCISE(#) REALIZED($)(1) EXERCISABLE NOT EXERCISABLE EXERCISABLE NOT EXERCISABLE
---- ----------- ----------- --------------------------- ----------- ---------------
Nathaniel D. Woodson 0 $0 16,000 85,000 $ 99,499 $569,278
Robert L. Fiscus 0 0 10,500 15,500 157,500 126,422
James F. Crowe 0 0 0 8,000 0 65,250
Anthony J. Vallillo 0 0 0 8,000 0 65,250
Albert N. Henricksen 0 0 0 8,000 0 65,250
-------------------------
(1) Fair market value at exercise date less exercise price.
(2) Fair market value of shares at December 31, 1999 ($51.375) less exercise
price.
RETIREMENT PLANS
The following table shows the estimated annual benefits payable as a single
life annuity under the Company's qualified defined benefit pension plan on
retirement at age 65 to persons in the earnings classifications and with the
years of service shown. Retirement benefits under the plan are determined by a
fixed formula, based on years of service and the person's average annual
earnings from the Company during the three years during which the person's
earnings from the Company were the highest, applied uniformly to all persons.
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[Enlarge/Download Table]
AVERAGE
ANNUAL EARNINGS DURING
THE HIGHEST 3 ESTIMATED ANNUAL BENEFITS PAYABLE AT AGE 65(3)
-------------------------------------------
YEARS OF SERVICE(1)(2) 20 YEARS(4) 25 YEARS(4) 30 YEARS(4) 35 YEARS(4) 40 YEARS(4)
---------------- -------- -------- -------- -------- --------
$100,000 $32,000 $40,000 $48,000 $48,000 $48,000
$150,000 $48,000 $60,000 $72,000 $72,000 $72,000
$200,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$250,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$300,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$350,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$400,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
$450,000 $51,200(2) $64,000(2) $76,800(2) $76,800(2) $76,800(2)
-------------------------
(1) Earnings include annual salary and cash bonus awards paid pursuant to the
Company's Executive Incentive Compensation Program. See "Executive
Compensation" above.
(2) Internal Revenue Code Section 401(a)(17) limits earnings used to calculate
qualified plan benefits to $160,000 for 1999. This limit was used in the
preparation of this table. (In addition, qualified plan benefits cannot
exceed an Internal Revenue Code Section 415(b) limit of $130,000 for 1999).
The Board of Directors has adopted a supplemental executive retirement plan
that will pay supplemental retirement benefits to Messrs. Woodson, Fiscus,
Crowe, Vallillo and Henricksen and other officers of the Company in amounts
sufficient to prevent these Internal Revenue Code limitations from
adversely affecting their retirement benefits determined by the pension
plan's fixed formula.
(3) The amounts shown in the table are not subject to any deduction for Social
Security or other offset amounts.
(4) As of their last employment anniversary dates, Messrs. Woodson, Fiscus,
Crowe, Vallillo and Henricksen had accrued 2, 27, 35, 31, and 36 years of
service, respectively.
BOARD OF DIRECTORS
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
All of the members of the Compensation and Executive Development Committee
of the Board of Directors (the Committee) are non-employee Directors.
The Committee, with the assistance of an outside compensation consulting
firm, formulates all of the objectives and policies relative to the compensation
of the officers of the Company, subject to approval by the entire Board of
Directors; and the Committee recommends to the Board of Directors all of the
elements of the officers' compensation arrangements, including the design and
adoption of compensation programs, the identity of program participants, salary
grades and structure, annual payments of salaries, and any awards under the
annual incentive compensation program and the long-term incentive program.
The Company's basic executive compensation program consists of three
components: annual salaries, bonuses under an annual incentive compensation
program, and long-term incentive program awards. The overall objective of this
program is to attract and retain qualified executives and to produce strong
financial performance for the benefit of the Company's shareowners, while
providing a high level of customer service and value for its customers.
Accordingly, all of the Committee's decisions, in 1999 and in prior years, have
ultimately been based on the Committee's assessment of the Company's performance
in these regards. As benchmarks, the Committee compares the Company's overall
performance relative to other electric utilities of comparable size, the
compensation practices and programs of other companies that are most likely to
compete with the Company for services of executive officers, the Company's
strategic objectives, and the challenges it faces.
The Committee formulates annual salary ranges for officers by periodic
comparisons to rates of pay for comparable positions in other electric
utilities, as reported in the Edison Electric Institute's Executive Compensation
- 86 -
Survey (the EEI Survey). Within the applicable range, each individual officer's
annual salary is then set at a level that will compensate the officer for
day-to-day performance, in the light of the officer's level of responsibility,
past performance, prior year's salary and bonus, and potential future
contributions to the Company's strategic objectives.
As described in detail above at "Executive Compensation," the Company's
annual incentive compensation program and its long-term incentive program have
somewhat different purposes. Under the annual Executive Incentive Compensation
Program, cash awards may be made each year to officers based on their
achievement of performance levels formulated by the Committee with respect to
(1) specific shareowner financial goals, (2) specific business unit goals, (3)
specific team/individual goals, and (4) a qualitative assessment of the
officers' performance as a group with respect to strategic opportunities of the
Company during that year, and based on such other factors as the Committee deems
relevant. The Company's Long-Term Incentive Program rewards officers for
achieving a return to shareowners over three-year periods of time. Under the
Long-Term Incentive Program that was replaced by the 1999 Stock Option Plan
approved by the shareowners last year, long-term incentive awards have been
linked to the total return to the shareholders compared to a peer group of
electric utilities. This program continues to provide strong incentives for
superior future performance under the three-year contingent performance share
awards granted in 1998; and it also encourages officers to continue serving UI,
because the earning of each incentive award is conditioned upon the officer's
continued service for the award's three-year performance period. Continued
service is also a key feature of the Company's 1999 Stock Option Plan. As
described above at "Executive Compensation," this plan provides officers with
incentives to contribute to the Company's success as measured by the market
value of its Common Stock. Except as otherwise provided in the plan, an officer
optionee may exercise a stock option only if he or she is, and has continuously
been since the date that the stock option was granted, a full-time employee of
the Company or one of its affiliates.
For 1999, the bonus opportunities of the Company's officers were targeted
by the Committee such that the combination of each officer's 1999 salary and
annual Executive Incentive Compensation Program award, assuming that
pre-established performance goals were met, would approximate, on average, the
50th percentile of compensation for comparable positions as reported in the 1998
EEI Survey. Goals were established to focus the officers' attention at the
corporate level on shareowner financial measures and at the business unit level
on a "balanced scorecard," covering business unit financial, operational,
customer and human resource measures. A prerequisite threshold level of
recurring earnings per share was specified in order for any bonus to be earned.
For 1999 the pre-established shareowner financial goals, accounting for 70% of
both the Chairman, President and Chief Executive Officer and the Vice Chairman
and Chief Financial Officer bonus awards and 40% of the business unit leaders'
bonus awards, included two measures: recurring earnings per share from
operations and recurring cash from operations available to pay down debt. For
each of the business unit leaders, 40% of the bonus award for 1999 was based on
the achievement of business unit "balanced scorecard" goals. The remaining 30%
of the Chairman, President and Chief Executive Officer and the Vice Chairman and
Chief Financial Officer bonus awards and 20% of the business unit leaders' bonus
awards for 1999 were based on the Committee's qualitative assessment of the
performance of the Company's officers as a group with respect to 1999 strategic
opportunities. For 1999, this assessment focused on the officers' achievements
in the implementation of the Company's vision, which is to position the Company
to be the premier regulated distribution utility to the regional community and
the leading value-added energy services supplier to the Company's specific
customers. The implementation plan was to include items such as: addressing the
issues of (i) sale of the non-nuclear generating assets, (ii) successful
commencement of retail access on January 1, 2000, (iii) Year-2000 rollover
without interruption of services or any major business system, (iv) formation of
a holding company, and (v) an investment in non-regulated businesses.
The officers' achievements with respect to 1999 pre-established shareowner
financial goals were especially strong: 150% of the recurring earnings per share
from operations goal and 150% of the recurring cash available to pay down debt
goal. Business unit leader achievements of business unit goals were likewise
strong, and ranged between 116% and 125% of the several business unit goals.
- 87 -
Overall, the Committee's bonus awards for 1999 under the Executive
Incentive Compensation Program ranged between 133% and 163% of the
pre-established targeted awards, depending on the individual officer's
achievements, reflecting a strong performance by the Company's officers.
Long-term incentives, in recognition of the increasingly competitive
business environment for utilities, are based on a competitive blend of utility
and general industry award levels. It is the intention of the Committee to
transition, over a period of several years, to a 50%/50% blend of median utility
and general industry long-term incentive awards. The partial use of general
industry data recognizes the more competitive environment for utilities, and was
deemed by the Committee to be an important step toward ensuring the Company's
ability to continue attracting, retaining and motivating experienced executive
talent, given similar changes in the compensation programs at other utilities.
Under the Company's Long-Term Incentive Program, which is now the 1999
Stock Option Plan, a total of 132,000 Nonqualified Stock Options were awarded in
1999 to a total of 29 directors, officers and key employees of the Company. The
number of options granted to each officer in 1999 was based on a weighted blend
of 70% median utility and 30% general industry long-term award levels for
comparably-sized companies. Grants made in 2000 will be based on a weighted
blend of 60% median utility and 40% general industry competitive long-term
incentive data.
It is not expected that any compensation paid to an executive officer
during 2000 will become non-deductible under Internal Revenue Code Section
162(m) (the "million dollar pay cap").
CHIEF EXECUTIVE OFFICER COMPENSATION FOR 1999
In March of 1999, the Committee recommended, and the Board of Directors
approved, a 1999 annual salary of $412,000 for Mr. Woodson, as Chairman,
President and Chief Executive Officer of the Company. This annual salary was
between the median and the 75th percentile salary for this officership position
at other electric utilities of comparable size, as reported in the 1998 EEI
Survey, and below the 25th percentile of general industry sample for companies
of similar size. It was the Committee's judgment that the salary was appropriate
for an executive with the skills and abilities of Mr. Woodson to lead the
Company forward in the competitive business environment for utilities. Mr.
Woodson's bonus performance target for 1999 under the annual Executive Incentive
Compensation Program was set at $144,200, consisting of a prerequisite threshold
level of recurring earnings per share from operations goal and pre-established
goals with respect to recurring cash from operations available to pay down debt
and strategic opportunities, as detailed above. At the conclusion of 1999, the
Committee recommended, and the Board of Directors approved, a 1999 bonus award
of $220,000 to Mr. Woodson, representing 143% of his prorated targeted annual
performance bonus based on the achievements as described above and an additional
sum of $14,515 based on the Committee's judgment that Mr. Woodson's performance
during 1999 had been extraordinary.
The Committee's qualitative assessment of the performance of the officers
as a group with respect to strategic opportunities during 1999 was very positive
and, in the judgment of the Committee, reflected favorably on Mr. Woodson's
leadership.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
Thelma R. Albright, Chair
Marc C. Breslawsky
David E. A. Carson
F. Patrick McFadden, Jr.
Daniel J. Miglio
James A. Thomas
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COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No director of the Company who served as a member of the Compensation and
Executive Development Committee during 1999 was, during 1999 or at any time
prior thereto, an officer or employee of the Company. During 1999, no director
of the Company was an executive officer of any other entity on whose Board of
Directors an executive officer of the Company served.
DIRECTOR COMPENSATION
Directors who are employees of the Company receive no compensation for
their service as directors of the Company.
The remuneration of non-employee directors of the Company includes an
annual retainer fee of $21,000, payable $9,000 for service during the first
quarter of the year and $4,000 each for service during the second, third and
fourth quarters of the year (the $9,000 retainer fee payable for service during
the first quarter of the year is payable in shares of the Company's Common Stock
or by credit to a stock account under the Non-Employee Directors' Common Stock
and Deferred Compensation Plan described below), plus a fee of $1,000 for each
meeting of the Board of Directors or committee of the Board of Directors
attended. Committee chairpersons receive an additional fee of $750 per quarter
year. Non-employee directors are also provided travel/accident insurance
coverage in the amount of $200,000.
The Company's Non-Employee Directors' Common Stock and Deferred
Compensation Plan (the Plan) has two features: a mandatory Common Stock feature;
and an optional Deferred Compensation feature. Each non-employee director has
two accounts in the Plan: a stock account for the accumulation of units that are
equivalent to shares of Common Stock (Stock Units), and on which amounts equal
to cash dividends on the shares of the Company's Common Stock represented by
Stock Units in the account accrue as additional Stock Units; and a cash account
for accumulation of the director's fees payable in cash that the director elects
to defer, and on which interest accrues at the prime rate in effect at the
beginning of each month at Citibank, N.A.
Under the Common Stock feature of the Plan, a credit of Stock Units to each
non-employee director's stock account in the Plan is made on or about the first
day of March in each year, unless the director elects to receive shares of
Common Stock in lieu of having an equivalent number of Stock Units credited to
his or her stock account. Each annual credit consists of a number of whole and
fractional Stock Units equal to the sum of 200 plus the quotient resulting from
dividing the retainer fee for the first quarter of the year by the market value
of Common Stock on the date of the credit.
Under the Deferred Compensation feature of the Plan, a non-employee
director may elect to defer receipt of all or part of (i) his or her retainer
fee for service during the second, third and fourth quarters of each year, (ii)
his or her committee chairperson fees, and/or (iii) his or her meeting fees,
which are payable in cash. All amounts deferred are credited when payable, at
the director's election, to either the director's cash account or to the
director's stock account (in a number of whole and fractional Stock Units based
on the market value of the Company's Common Stock on the date the fee is
payable) in the Plan.
All amounts credited to a non-employee director's cash account or stock
account in the Plan are at all times fully vested and nonforfeitable, and are
payable only upon termination of the director's service on the Board of
Directors. At that time, the cash account is payable in cash and the stock
account is payable in an equivalent number of shares of Common Stock or, at the
director's election, in cash based on the market value of an equivalent number
of shares of Common Stock.
Under the Company's 1999 Stock Option Plan described above, each
non-employee director was granted 4,500 stock options, with Reload Rights, on
March 22, 1999. These options are exercisable at the rate of one-third of the
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options on each of the first three anniversaries of the grant date, at an
exercise price per share of $43 7/32, which was the fair market value of the
Common Stock on March 22, 1999.
SHAREOWNER RETURN PRESENTATION
Set forth below is a line graph comparing the yearly change in the
Company's cumulative total shareowner return on its Common Stock with the
cumulative total return on the S&P Composite-500 Stock Index, the S&P Public
Utility Index and the S&P Electric Power Companies Index for the period of five
fiscal years commencing 1995 and ending 1999.
[GRAPH]
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
UIL $100 $134 $124 $190 $224 $236
S&P 500 100 138 169 226 290 351
S&P PUB. UTY. 100 142 147 183 210 191
S&P EL. CO. 100 131 131 165 191 154
* ASSUMES THAT THE VALUE OF THE INVESTMENT IN THE COMPANY'S COMMON STOCK AND
EACH INDEX WAS $100 ON DECEMBER 31, 1994 AND THAT ALL DIVIDENDS WERE
REINVESTED. FOR PURPOSES OF THIS GRAPH, THE YEARLY CHANGE IN CUMULATIVE
SHAREOWNER RETURN IS MEASURED BY DIVIDING (I) THE SUM OF (A) THE CUMULATIVE
AMOUNT OF DIVIDENDS FOR THE YEAR, ASSUMING DIVIDEND REINVESTMENT, AND (B) THE
DIFFERENCE IN THE FAIR MARKET VALUE AT THE END AND THE BEGINNING OF THE YEAR,
BY (II) THE FAIR MARKET VALUE AT THE BEGINNING OF THE YEAR. THE CHANGES
DISPLAYED ARE NOT NECESSARILY INDICATIVE OF FUTURE RETURNS MEASURED BY THIS
OR ANY METHOD.
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Item 12. Security Ownership of Certain Beneficial Owners and Management.
PRINCIPAL SHAREOWNERS
In statements filed with the Securities and Exchange Commission, the
persons identified in the table below have disclosed beneficial ownership of
shares of common stock as shown in the table. The percentages shown in the
right-hand column are calculated based on the 14,334,922 shares of common stock
outstanding as of the close of business on January 18, 2000. In the statements
filed with the Securities and Exchange Commission, none of the persons
identified in the table, except David T. Chase, has admitted beneficial
ownership of any shares not held in their individual names. All of the persons
identified in the table, including David T. Chase, have denied that they have
acted, or are acting, as a partnership, limited partnership or syndicate, or as
a group of any kind for the purpose of acquiring, holding or disposing of common
stock.
AMOUNT AND NATURE
NAME AND ADDRESS OF BENEFICIAL
TITLE OF CLASS OF BENEFICIAL OWNER OWNERSHIP PERCENT OF CLASS
-------------- ------------------- --------- ----------------
Common Stock Rhoda L. Chase 560,000 shares, 3.91%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock Cheryl A. Chase 79,200 shares, 0.55%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock Arnold L. Chase 230,300 shares, 1.61%
One Commercial Plaza owned directly
Hartford, CT 06103
Common Stock The Darland Trust 146,000 shares, 1.02%
St. Peter's House, owned directly
Le Bordage
St. Peter Port
Guernsey GY16AX
Channel Islands(1)
Common Stock David T. Chase 1,010,000 shares 7.05%
One Commercial Plaza owned indirectly(2)
Hartford, CT 06103
Common Stock DTC Holdings Corporation(3) 210,000 shares 1.46%
One Commercial Plaza owned directly
Hartford, CT 06103
---------------------------
(1) The Darland Trust is a trust for the benefit of Cheryl A.. Chase and her
children. The trustee of this trust is Rothschild Trust Cayman Limited.
(2) All of the shares listed for David T. Chase are included in the shares
listed for Rhoda L. Chase, his wife, Cheryl A. Chase, his daughter, Arnold
L. Chase, his son, and The Darland Trust.
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(3) DTC Holdings Corporation was formerly known as American Ranger, Inc. It is
a wholly-owned subsidiary of D.T. Chase Enterprises, Inc. and is indirectly
owned and controlled by David T. Chase, Rhoda L. Chase, Cheryl A. Chase,
Arnold L. Chase, trusts for the benefit of Arnold L. Chase and his
children, and trusts for the benefit of Cheryl A. Chase and her children.
D.T. Chase Enterprises, Inc. has its address at One Commercial Plaza,
Hartford, CT 06103.
STOCK OWNERSHIP OF DIRECTORS AND OFFICERS
The following table indicates the number of shares of common stock
beneficially owned, directly or indirectly, as of January 31, 2000, by each
Company director, by the person who served as the Chief Executive Officer of the
Company during 1999, and by each of the four other most highly compensated
officers of the Company during 1999, and by all directors and officers of the
Company as a group.
SHARES
NAME OF INDIVIDUAL OR BENEFICIALLY
NUMBER OF PERSONS IN OWNED DIRECTLY
GROUP OR INDIRECTLY
----------------------------------------------------------
Thelma R. Albright 4,095
Marc C. Breslawsky 5,648
David E.A. Carson 9,833
Arnold L. Chase 230,300
John F. Croweak 3,834
Robert L. Fiscus 34,257
Betsy Henley-Cohn 3,993
John L. Lahey 2,477
F. Patrick McFadden, Jr. 4,149
Daniel J. Miglio 3,000
Frank R. O'Keefe, Jr. 5,327
James A. Thomas 2,363
Nathaniel D. Woodson 12,216
James F. Crowe 7,027
Albert N. Henricksen 3,147
Anthony J. Vallillo 2,430
20 Directors and Officers as a
group, including those named above 349,318
The number of shares listed in the table above includes those held for the
benefit of officers that are participating in the Company's Employee Stock
Ownership Plan and, in the cases of Robert L. Fiscus, 10,500 shares, and, in the
case of all directors and officers as a group, 16,300 shares, that may be
acquired currently through the exercise of stock options under the Company's
1990 Stock Option Plan.
The numbers in the above table are based on reports furnished by the
directors and officers. The shares reported for Mr. Chase do not include shares
held by other members of his family and entities owned by them, which are
described at "Principal Shareowners" above. Mr. Chase does not admit beneficial
ownership of any shares other than those shown in the foregoing table, and he
has denied that he has acted, or is acting, as a member of a partnership,
limited partnership or syndicate, or group of any kind for the purpose of
acquiring, holding or disposing of the Company's Common Stock. With respect to
other directors and officers, the shares reported in the foregoing table
include, in some instances, shares held by the immediate families of directors
and officers or entities controlled by directors and officers, the reporting of
which is not to be construed as an admission of beneficial ownership.
- 92 -
Each of the persons included in the above table has sole voting and
investment power as to the shares of Common Stock beneficially owned, directly
or indirectly, by him or her, except as described below:
o each person listed below shares investment and voting power for the
number of shares listed opposite his or her name below with his or her
spouse:
NAME NUMBER OF SHARES
---- ----------------
James F. Crowe 751
Albert N. Henricksen 449
All directors and officers
as a group 1,392
o voting and investment power is held by the other people or entities
described below on behalf of the persons included in the above table
with respect to the number of shares listed opposite their respective
names below:
NAME OF OTHER PERSON OR
ENTITY HOLDING VOTING
NAME NUMBER OF SHARES AND INVESTMENT POWER
---- ---------------- ---------------------
David E.A. Carson 159 Spouse
Robert L. Fiscus 700 Trust
Betsy Henley-Cohn 2,035 Trust
Frank R. O'Keefe, Jr. 669 Trust
Nathaniel D. Woodson 12,000 Trust
James F. Crowe 10 Child
All directors and officers
as a group 15,806 Spouse, Trust or Child
The number of shares listed in the stock ownership table above also
includes the number of stock units listed opposite each person's name below, for
which neither investment nor voting power is held:
NAME NUMBER OF SHARES
---- ----------------
Thelma R. Albright 3,857
Marc C. Breslawsky 5,548
David E.A. Carson 8,853
John F. Croweak 2,917
Betsy Henley-Cohn 425
John L. Lahey 239
F. Patrick McFadden, Jr. 2,215
Frank R. O'Keefe, Jr. 4,418
James A. Thomas 825
These stock units are in stock accounts under the Company's Non-Employee
Directors' Common Stock and Deferred Compensation Plan, described at "Director
Compensation." Stock units in this plan are payable, in an equivalent number of
shares of the Company's Common Stock, upon termination of service on the Board
of Directors.
The number of shares of Common Stock beneficially owned by Mr. Chase, as
listed in the above stock ownership table, is approximately 1.6% of the
14,334,922 shares of common stock outstanding as of January 18, 2000. The number
of shares of Common Stock beneficially owned by each of the other persons
included in th
- 93 -
foregoing table is less than 1% of the outstanding shares of common stock as of
January 31, 2000; and the number of shares of Common Stock beneficially owned by
all of the directors, and officers as a group represents approximately 2.4% of
the outstanding shares of Common Stock as of January 31, 2000.
Item 13. Certain Relationships and Related Transactions.
Under a lease agreement dated May 7, 1991, the Company leased its
corporate headquarters offices in New Haven from Connecticut Financial Center
Associates Limited Partnership (CFCALP). CFCALP is a limited partnership
controlled by the David T. Chase family, including Arnold L. Chase, a Director
of the Company since June 28, 1999, and members of his immediate family. During
1999, the Company's lease payments to CFCALP totaled $6,162,000.
A subsidiary of the Company, United Capital Investments, Inc. (UCI),
intends to purchase, for $3,750,000, a minority ownership interest in a
newly-formed corporation, Gemini-United, Inc. (GUI), that proposes to develop,
build and operate an open-access, hybrid fiber coaxial communications network
serving business and residential customers located in the Company's franchised
service area. UCI also intends to provide marketing, management of system
customer base, and network deployment and maintenance consulting services to
GUI, for an annual fee of $70,000, for a period of five years, subject to early
termination in certain limited circumstances. The majority owner of GUI is
Gemini Networks, Inc., a corporation controlled by the David T. Chase family;
and Arnold L. Chase is the Chairman of the Board of Directors of GUI and the
President and a Director of Gemini Networks, Inc.
Since January 1, 1999, there has been no other transaction, relationship or
indebtedness of the kinds described in Item 404 of Regulation S-K.
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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, 1999,
1998 and 1997
Consolidated statement of cash flows for the years ended December 31,
1999, 1998 and 1997
Consolidated balance sheet, December 31, 1999 and 1998
Consolidated statement of changes in shareholders' equity for the years
ended December 31, 1999, 1998 and 1997
Notes to consolidated financial statements
Report of independent accountants
Financial Statement Schedule (see S-1)
Schedule II - Valuation and qualifying accounts for the years ended
December 31, 1999, 1998 and 1997.
- 95 -
Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain
of the following listed exhibits, which are annexed as exhibits to previous
statements and reports filed by the Company, are hereby incorporated by
reference as exhibits to this report. Such statements and reports are identified
by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1996.
(4) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1997.
(5) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1998.
(6) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1999.
(7) Filed with Registration Statement No. 33-40169, effective August 12, 1991.
(8) Filed with Registration Statement No. 33-35465, effective August 1, 1990.
(9) Filed with Amendment No. 1 to Registration Statement No. 33-55461,
effective October 31, 1994.
(10) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1995.
(11) Filed with Registration Statement No. 2-57275, effective October 19, 1976.
(12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1995.
(13) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1996.
(14) Filed with Registration Statement No. 2-60849, effective July 24, 1978.
(15) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1991.
(16) Filed with Registration Statement No. 2-54876, effective November 19, 1975.
(17) Filed with Registration Statement No. 2-66518, effective February 25, 1980.
(18) Filed with Registration Statement No. 2-52657, effective February 6, 1975.
(19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1997.
(20) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1997.
(21) Filed with Annual Report (Form 10-K) for fiscal year ended December 31,
1998.
(22) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September
30, 1997.
(23) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1998.
(24) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30,
1999.
(25) Filed March 29, 1996, with proxy material for the Annual Meeting of the
Shareowners.
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The exhibit number in the statement or report referenced is set forth in
the parenthesis following the description of the exhibit. Those of the following
exhibits not so identified are filed herewith.
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(3) 3.1a (1) Copy of Restated Certificate of Incorporation of The United Illuminating Company, dated January
23, 1995. (Exhibit 3.1)
(3) 3.1b (2) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
August 4, 1995. (Exhibit 3.1b)
(3) 3.1c (3) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
July 16, 1996. (Exhibit 3.1c)
(3) 3.1d (4) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated
December 11, 1996. (Exhibit 3.1d)
(3) 3.1e (5) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors and
Shareholders, dated May 28, 1998. (Exhibit 3.1d)
(3) 3.2 (6) Copy of Bylaws of The United Illuminating Company. (Exhibit 3.2c)
(4) 4.1 (7) Copy of Indenture, dated as of August 1, 1991, from The United Illuminating Company to The Bank
of New York, Trustee. (Exhibit 4)
(4),(10) 4.2 (8) Copy of Participation Agreement, dated as of August 1, 1990, among Financial Leasing
Corporation, Meridian Trust Company, The Bank of New York and The United Illuminating
Company. (Exhibits 4(a) through 4(h), inclusive, Amendment Nos. 1 and 2).
(4) 4.3a (9) Copy of form of Amended and Restated Agreement of Limited Partnership of United Capital Funding
Partnership L.P. (Exhibit 4(c))
(4) 4.3b (10) Copy of Action of The United Illuminating Company, as General Partner of United Capital Funding
Partnership L.P., relating to the 9 5/8% Preferred Capital Securities, Series A, of United
Capital Funding Partnership L.P. (Exhibit 4(b))
(4) 4.3c (9) Copy of form of Indenture, dated as of April 1, 1995, from The United Illuminating Company to
The Bank of New York, as Trustee. (Exhibit 4(e))
(4) 4.3d (10) Copy of First Supplemental Indenture, dated as of April 1, 1995, between The United Illuminating
Company and The Bank of New York, Trustee, supplementing Exhibit 4.3c. (Exhibit 4(d))
(4) 4.3e (9) Copy of form of Payment and Guarantee Agreement of The United Illuminating Company, dated as of
April 1, 1995. (Exhibit 4(j))
(10) 10.1 (11) Copy of Stockholder Agreement, dated as of July 1, 1964, among the various stockholders of
Connecticut Yankee Atomic Power Company, including The United Illuminating Company. (Exhibit
5.1-1)
(10) 10.2a (11) Copy of Power Contract, dated as of July 1, 1964, between Connecticut Yankee Atomic Power
Company and The United Illuminating Company. (Exhibit 5.1-2)
(10) 10.2b (12) Copy of Additional Power Contract, dated as of April 30, 1984, between Connecticut Yankee Atomic
Power Company and The United Illuminating Company.
(10) 10.2c (13) Copy of 1987 Supplementary Power Contract, dated as of April 1, 1987, supplementing Exhibits
10.2a and 10.2b. (Exhibit 10.2c)
(10) 10.2d (13) Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending Exhibits 10.2b and
10.2c. (Exhibit 10.2d)
(10) 10.2e (13) Copy of First Supplement to 1996 Amendatory Agreement, dated as of February 10, 1997,
supplementing Exhibit 10.2d. (Exhibit 10.2e)
- 97 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.3 (11) Copy of Capital Funds Agreement, dated as of September 1, 1964, between Connecticut Yankee
Atomic Power Company and The United Illuminating Company. (Exhibit 5.1-3)
(10) 10.4 (14) Copy of Capital Contributions Agreement, dated October 16, 1967, between The United Illuminating
Company and Connecticut Yankee Atomic Power Company. (Exhibit 5.1-5)
(10) 10.5 Copy of Restated New England Power Pool Agreement, as amended to March 1, 2000.
(10) 10.6a (15) Copy of Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear
Units, dated May 1, 1973, as amended to February 1, 1990. (Exhibit 10.7a)
(10) 10.6b (16) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the Seabrook Companies.
(Exhibit 5.9-2)
(10) 10.6c (13) Copy of Twenty-third Amendment to Agreement for Joint Ownership, Construction and Operation of
New Hampshire Nuclear Units, dated as of November 1, 1990, amending Exhibit 10.6a. (Exhibit
10.7c)
(10) 10.7a (17) Copy of Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of September 1, 1973, among
The Connecticut Light and Power Company, The Hartford Electric Light Company, Western
Massachusetts Electric Company, New England Power Company, The United Illuminating Company,
Public Service Company of New Hampshire, Central Vermont Public Service Company, Montaup
Electric Company and Fitchburg Gas and Electric Light Company, relating to a nuclear fueled
generating unit in Connecticut. (Exhibit 5.8-1)
(10) 10.7b (18) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of August 1,
1974, amending Exhibit 10.7a. (Exhibit 5.9-2)
(10) 10.7c (11) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of December 15,
1975, amending Exhibit 10.7a. (Exhibit 5.8-4, Post-effective Amendment No. 2)
(10) 10.8a (14) Copy of Transmission Line Agreement, dated January 13, 1966, between the Trustees of the
Property of The New York, New Haven and Hartford Railroad Company and The United Illuminating
Company. (Exhibit 5.4)
(10) 10.8b (15) Notice, dated April 24, 1978, of The United Illuminating Company's intention to extend term of
Transmission Line Agreement dated January 13, 1966, Exhibit 10.8a. (Exhibit 10.9b)
(10) 10.8c (15) Copy of Letter Agreement, dated March 28, 1985, between The United Illuminating Company and
National Railroad Passenger Corporation, supplementing and modifying Exhibit 10.8a. (Exhibit
10.9c)
(10) 10.8d (19) Copy of Notice, dated April 22, 1997, of The United Illuminating Company's intention to extend
term of Transmission Line Agreement, Exhibit 10.9a, as supplemented and modified by Exhibit
10.8c. (Exhibit 10.9d)
(10) 10.9a (20) Copy of Agreement, effective May 16, 1997, between The United Illuminating Company and Local
470-1, Utility Workers Union of America, AFL-CIO. (Exhibit 10.10)
(10) 10.9b (21) Copy of Memorandum of Agreement, dated January 27, 1999, between The United Illuminating Company
and Local 470-1, Utility Workers Union of America, AFL-CIO.
- 98 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.9c Copy of Memorandum of Agreement, dated March 5, 1999, between The United Illuminating Company
and Local 470-1, Utility Workers Union of America, AFL-CIO.
(10) 10.12a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The
United Illuminating Company and Robert L. Fiscus. (Exhibit 10.23)
(10) 10.12b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Robert L. Fiscus, dated as of February 1, 1998, amending Exhibit
10.12a. (Exhibit 10.14a)
(10) 10.13a* (22) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The
United Illuminating Company and James F. Crowe. (Exhibit 10.24)
(10) 10.13b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and James F. Crowe, dated as of February 1, 1998, amending Exhibit
10.13a. (Exhibit 10.15a)
(10) 10.14a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Albert N. Henricksen. (Exhibit 10.25)
(10) 10.14b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Albert N. Henricksen, dated as of February 1, 1998, amending Exhibit
10.14a. (Exhibit 10.16a)
(10) 10.15a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Anthony J. Vallillo. (Exhibit 10.26)
(10) 10.15b* (23) Copy of First Amendment to Amended and Restated Employment Agreement between The United
Illuminating Company and Anthony J. Vallillo, dated as of February 1, 1998, amending Exhibit
10.15a. (Exhibit 10.17a)
(10) 10.16a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Rita L. Bowlby. (Exhibit 10.27)
(10) 10.16b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Rita L. Bowlby, dated as of December 13, 1999.
(10) 10.17a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Stephen F. Goldschmidt. (Exhibit 10.28)
(10) 10.17b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Stephen F. Goldschmidt, dated as of May 5, 1999.
(10) 10.18* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and James L. Benjamin. (Exhibit 10.29)
(10) 10.19a* (22) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company
and Charles J. Pepe. (Exhibit 10.31)
(10) 10.19b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Charles J. Pepe, dated as of December 13, 1999.
(10) 10.20a* (23) Copy of Employment Agreement, dated as of February 23, 1998, between The United Illuminating
Company and Nathaniel D. Woodson. (Exhibit 10.28)
(10) 10.20b* Copy of First Amendment to Employment Agreement between The United Illuminating Company and
Nathaniel D. Woodson, dated as of December 13, 1999.
(10) 10.21* (23) Copy of The United Illuminating Company Phantom Stock Option Agreement, dated as of February 23,
1998, between The United Illuminating Company and Nathaniel D. Woodson. (Exhibit 10.29)
(10) 10.22* (15) Copy of Executive Incentive Compensation Program of The United Illuminating Company. (Exhibit
10.24)
- 99 -
[Enlarge/Download Table]
Exhibit
Table Exhibit Reference
Item No. No. No. Description
------- ------- --------- -----------
(10) 10.23* (13) Copy of The United Illuminating Company 1990 Stock Option Plan, as amended on December 20, 1993,
January 24, 1994 and August 22, 1994.
(10) 10.24* (24) Copy of The United Illuminating Company 1999 Stock Option Plan. (Exhibit 10.29)
(10) 10.25a* (25) Copy of Non-Employee Directors' Common Stock and Deferred Compensation Plan of The United
Illuminating Company.
(10) 10.25b* Copy of Resolution adopted by the Board of Directors of The United Illuminating Company on
December 13, 1999, amending Subsection 6.01(b) of the Non-Employee Directors' Common Stock and
Deferred Compensation Plan.
(10) 10.27* (3) Copy of The United Illuminating Company 1996 Long-Term Incentive Program. (Exhibit 10.21)
(12),(99) 12 Statement Showing Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred
Stock Dividend Requirements (Twelve
Months Ended December 31, 1999, 1998,
1997, 1996 and 1995).
(21) 21 List of subsidiaries of The United Illuminating Company.
(27) 27 Financial Data Schedule
(28) 28.1 Copies of significant rate schedules of The United Illuminating Company.
---------------------------
*Management contract or compensatory plan or arrangement.
- 100 -
The foregoing list of exhibits does not include instruments defining the
rights of the holders of certain long-term debt of the Company and its
subsidiaries where the total amount of securities authorized to be issued under
the instrument does not exceed ten (10%) of the total assets of the Company and
its subsidiaries on a consolidated basis; and the Company hereby agrees to
furnish a copy of each such instrument to the Securities and Exchange Commission
on request.
(b) Reports on Form 8-K.
None
- 101 -
PRICEWATERHOUSECOOPERS
PricewaterhouseCoopers LLP
1301 Avenue of the Americas
New York, NY 10019-6013
Telephone (212) 259 1000
Facsimile (212) 259 1301
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 33-50221 and
No. 33-64003) of our report dated January 24, 2000 relating to the financial
statements and financial statement schedule appearing in The United Illuminating
Company's Annual Report on Form 10-K for the year ended December 31, 1999.
/s/ PricewaterhouseCoopers LLP
January 24, 2000
New York, NY
- 102 -
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the Company has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson
------------------------------
Nathaniel D. Woodson
Chairman of the Board of Directors,
President and Chief Executive Officer
DATE: MARCH 10, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
[Enlarge/Download Table]
SIGNATURE TITLE DATE
--------- ----- ----
Director, Chairman of the
Board of Directors and
/s/ Nathaniel D. Woodson Chief Executive Officer March 10, 2000
-------------------------------------
(Nathaniel D. Woodson)
(Principal Executive Officer)
Director, Vice Chairman of the
Board of Directors, Chief Financial
/s/ Robert L. Fiscus Officer, Treasurer and Secretary March 10, 2000
-------------------------------------
(Robert L. Fiscus)
(Principal Financial and
Accounting Officer)
/s/ John F. Croweak Director March 10, 2000
-------------------------------------
(John F. Croweak)
/s/ F. Patrick McFadden, Jr. Director March 10, 2000
-------------------------------------
(F. Patrick McFadden, Jr.)
/s/ Betsy Henley-Cohn Director March 10, 2000
-------------------------------------
(Betsy Henley-Cohn)
/s/Frank R. O'Keefe, Jr. Director March 10, 2000
-------------------------------------
(Frank R. O'Keefe, Jr.)
/s/ James A. Thomas Director March 10, 2000
-------------------------------------
(James A. Thomas)
/s/ David E.A. Carson Director March 10, 2000
-------------------------------------
(David E.A. Carson)
/s/ John L. Lahey Director March 10, 2000
-------------------------------------
(John L. Lahey)
/s/ Marc C. Breslawsky Director March 10, 2000
-------------------------------------
(Marc C. Breslawsky)
/s/ Thelma R. Albright Director March 10, 2000
-------------------------------------
(Thelma R. Albright)
/s/ Arnold L. Chase Director March 10, 2000
-------------------------------------
(Arnold L. Chase)
/s/ Daniel J. Miglio Director March 10, 2000
-------------------------------------
(Daniel J. Miglio)
- 103 -
[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, 1999 AND 1998
(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 (consolidated):
1999 $2,431 $4,772 - $4,895 (A) $2,308
1998 $7,197 $5,745 - $10,511 (A) $2,431
Reserve for uncollectible
accounts (American
Payment Systems,
agent collections (B))
1999 $545 ($498) - ($123)(A) $170
1998 $5,392 $361 - $5,208 (A) $545
------------------------------------
NOTE:
(A) Accounts written off, less recoveries.
(B) Included in consolidated amounts above.
S-1
Dates Referenced Herein and Documents Incorporated by Reference
| Referenced-On Page |
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This ‘10-K’ Filing | | Date | | First | | Last | | | Other Filings |
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| | |
| | 12/1/29 | | 53 |
| | 7/30/27 | | 53 |
| | 6/26/26 | | 53 |
| | 4/30/25 | | 52 |
| | 1/1/05 | | 82 |
| | 1/30/04 | | 53 |
| | 1/1/04 | | 8 |
| | 12/31/03 | | 8 | | 57 |
| | 12/1/02 | | 27 | | 54 |
| | 8/1/02 | | 15 | | 67 |
| | 1/30/02 | | 53 |
| | 10/25/01 | | 53 |
| | 12/7/00 | | 27 | | 58 |
| | 9/6/00 | | 53 |
| | 8/29/00 | | 53 |
| | 7/1/00 | | 25 | | 56 |
| | 6/30/00 | | 8 | | 57 | | | 10-Q |
| | 6/15/00 | | 50 |
| | 3/31/00 | | 9 | | | | | 10-Q |
| | 3/17/00 | | 24 | | 56 | | | 8-K, DEF 14A |
Filed on: | | 3/10/00 | | 104 |
| | 3/2/00 | | 12 |
| | 3/1/00 | | 99 |
| | 2/1/00 | | 1 |
| | 1/31/00 | | 1 | | 95 |
| | 1/24/00 | | 76 | | 103 |
| | 1/18/00 | | 92 | | 94 |
| | 1/1/00 | | 8 | | 88 |
For Period End: | | 12/31/99 | | 1 | | 105 |
| | 12/28/99 | | 8 | | 57 |
| | 12/16/99 | | 27 | | 54 |
| | 12/13/99 | | 100 | | 101 |
| | 12/9/99 | | 25 | | 57 |
| | 10/25/99 | | 17 |
| | 10/15/99 | | 25 | | 57 |
| | 10/1/99 | | 23 | | 57 |
| | 8/4/99 | | 25 | | 56 |
| | 7/27/99 | | 25 | | 57 |
| | 6/30/99 | | 97 | | | | | 10-Q, 10-Q/A |
| | 6/28/99 | | 51 | | 95 | | | 3, DEF 14A |
| | 5/19/99 | | 24 | | 56 |
| | 5/14/99 | | 27 | | 52 | | | 10-Q |
| | 5/11/99 | | 32 |
| | 5/5/99 | | 100 |
| | 5/1/99 | | 9 | | 18 |
| | 4/16/99 | | 7 | | 65 | | | 8-K |
| | 4/8/99 | | 27 | | 52 |
| | 3/31/99 | | 97 | | | | | 10-Q, 10-Q/A |
| | 3/24/99 | | 25 | | 56 |
| | 3/22/99 | | 51 | | 91 |
| | 3/8/99 | | 27 | | 54 |
| | 3/5/99 | | 100 |
| | 2/10/99 | | 23 | | 55 |
| | 2/1/99 | | 27 | | 54 |
| | 1/27/99 | | 99 |
| | 1/16/99 | | 26 | | 54 |
| | 1/15/99 | | 53 |
| | 1/1/99 | | 82 | | 95 |
| | 12/31/98 | | 3 | | 105 | | | 10-K, 10-K/A |
| | 11/13/98 | | 24 | | 56 | | | 10-Q |
| | 10/2/98 | | 24 | | 55 |
| | 10/1/98 | | 24 | | 56 | | | 8-K |
| | 8/31/98 | | 14 | | 68 |
| | 8/23/98 | | 33 |
| | 7/14/98 | | 13 |
| | 7/4/98 | | 13 |
| | 6/30/98 | | 97 | | | | | 10-Q, 8-K |
| | 5/28/98 | | 98 | | | | | 8-K |
| | 5/22/98 | | 33 |
| | 5/20/98 | | 17 | | | | | 8-K, DEF 14A, PRE 14A |
| | 3/31/98 | | 35 | | 97 | | | 10-Q |
| | 2/23/98 | | 17 | | 100 |
| | 2/1/98 | | 100 |
| | 1/1/98 | | 50 | | 82 |
| | 12/31/97 | | 37 | | 101 | | | 10-K |
| | 9/30/97 | | 97 | | | | | 10-Q |
| | 8/7/97 | | 13 |
| | 6/30/97 | | 11 | | 97 | | | 10-Q |
| | 5/16/97 | | 99 |
| | 4/22/97 | | 99 |
| | 3/31/97 | | 97 | | | | | 10-Q |
| | 3/1/97 | | 100 |
| | 2/10/97 | | 98 |
| | 1/1/97 | | 38 | | 82 |
| | 12/31/96 | | 23 | | 101 | | | 10-K, 10-K/A |
| | 12/11/96 | | 98 |
| | 12/4/96 | | 13 | | 98 |
| | 10/25/96 | | 27 | | 54 |
| | 10/1/96 | | 17 | | 18 |
| | 7/23/96 | | 14 |
| | 7/16/96 | | 98 |
| | 6/30/96 | | 97 | | | | | 10-Q |
| | 4/30/96 | | 17 |
| | 3/30/96 | | 13 |
| | 3/29/96 | | 97 | | | | | DEF 14A |
| | 1/1/96 | | 82 |
| | 12/31/95 | | 97 | | 101 | | | 10-K, 10-K/A |
| | 9/30/95 | | 97 | | | | | 10-Q |
| | 8/29/95 | | 27 | | 54 |
| | 8/4/95 | | 98 |
| | 4/3/95 | | 1 |
| | 4/1/95 | | 98 |
| | 3/31/95 | | 97 | | | | | 10-Q |
| | 1/23/95 | | 98 |
| | 1/1/95 | | 17 | | 50 |
| | 12/31/94 | | 91 | | | | | 10-K |
| | 10/31/94 | | 97 |
| | 8/22/94 | | 101 |
| | 1/24/94 | | 101 |
| | 1/1/94 | | 17 | | 62 |
| | 12/20/93 | | 101 |
| | 2/1/93 | | 17 |
| | 1/1/93 | | 10 | | 69 |
| | 1/1/92 | | 12 |
| List all Filings |
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