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.
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The location and construction of certain electric facilities is also subject to regulation by the Connecticut Siting Council (CSC) with respect to environmental compatibility and public need. See "Environmental Regulation."
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.
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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
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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.
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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.
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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.
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Item 2.
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
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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
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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.
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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
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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.
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.
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.
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EXECUTIVE OFFICERS OF THE COMPANY
The names and ages of all executive officers of the Company and all such persons chosen to become executive officers, all positions and offices with the Company held by each such person, and the period during which he or she has served as an officer in the office indicated, are as follows:
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.
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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.
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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(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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(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.
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(1) Includes reclassification of certain Commercial and Industrial customers.
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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.
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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.
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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
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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:
(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.
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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.
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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.
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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:
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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 $5.7 million in 1999 compared to 1998. The principal components of these expense changes include:
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$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
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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."
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 $1.7 million. The principal components of the retail sales margin change, year over year, include:
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$ 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.
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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 ==== ===== ====
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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
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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:
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(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.
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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.
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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.
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The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
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The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
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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.
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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.
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(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.
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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
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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.
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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
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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.
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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:
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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
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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.
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.
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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.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
LONG-TERM DEBT
(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.
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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
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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
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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
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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.
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(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:
*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.
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(F) INCOME TAXES
(1) $6,719 of this amount is for deferred income tax benefits from prior years.
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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:
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.
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(G) SUPPLEMENTARY INFORMATION
(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.
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(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.
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The components of net periodic benefit cost are:
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.
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(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:
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(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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(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:
(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
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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.
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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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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.
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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:
(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."
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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:
------------------
(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
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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:
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
AS OF DECEMBER 31, ---- (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.
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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
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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
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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.
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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:
- ----------------------- (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
- ------------------- 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
- ------------------------- (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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- -------------------------
(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
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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.
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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
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(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.
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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
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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.
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Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain of the following listed exhibits, which are annexed as exhibits to previous statements and reports filed by the Company, are hereby incorporated by reference as exhibits to this report. Such statements and reports are identified by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September 30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30, 1996.
(4) Filed with 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.
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- --------------------------- *Management contract or compensatory plan or arrangement.
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The foregoing list of exhibits does not include instruments defining the rights of the holders of certain long-term debt of the Company and its subsidiaries where the total amount of securities authorized to be issued under the instrument does not exceed ten (10%) of the total assets of the Company and its subsidiaries on a consolidated basis; and the Company hereby agrees to furnish a copy of each such instrument to the Securities and Exchange Commission on request.
(b) Reports on Form 8-K.
None
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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
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SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson ------------------------------ Nathaniel D. Woodson Chairman of the Board of Directors, President and Chief Executive Officer
DATE: MARCH 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.
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NOTE: (A) Accounts written off, less recoveries. (B) Included in consolidated amounts above.
S-1
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.
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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.
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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
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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:
(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.
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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.
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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.
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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:
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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 $5.7 million in 1999 compared to 1998. The principal components of these expense changes include:
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$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
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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."
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 $1.7 million. The principal components of the retail sales margin change, year over year, include:
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$ 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.
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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 ==== ===== ====
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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
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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:
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(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.
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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.
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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.
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The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
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The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
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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.
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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.
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(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.
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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
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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.
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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
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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.
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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:
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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
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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.
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.
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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.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
LONG-TERM DEBT
(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.
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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
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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
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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
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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.
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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:
*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.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
(1) $6,719 of this amount is for deferred income tax benefits from prior years.
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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:
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.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
(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.
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(H) PENSION AND OTHER BENEFITS
The Company's qualified pension plan, which is based on the highest three years of pay, covers substantially all of its employees, and its entire cost is borne by the Company. The Company also has a non-qualified supplemental plan for certain executives and a non-qualified retiree only plan for certain early retirement benefits. The net pension costs for these plans for 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The components of net periodic benefit cost are:
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.
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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:
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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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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:
(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
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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.
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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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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.
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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:
(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."
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(O) QUARTERLY FINANCIAL DATA (UNAUDITED)
Selected quarterly financial data for 1999 and 1998 are set forth below:
------------------
(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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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
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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:
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THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
AS OF DECEMBER 31, ---- (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.
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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
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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
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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.
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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:
- ----------------------- (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
- ------------------- 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
- ------------------------- (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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- -------------------------
(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
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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.
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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
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(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.
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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
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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.
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Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain of the following listed exhibits, which are annexed as exhibits to previous statements and reports filed by the Company, are hereby incorporated by reference as exhibits to this report. Such statements and reports are identified by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September 30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30, 1996.
(4) Filed with 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.
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- --------------------------- *Management contract or compensatory plan or arrangement.
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The foregoing list of exhibits does not include instruments defining the rights of the holders of certain long-term debt of the Company and its subsidiaries where the total amount of securities authorized to be issued under the instrument does not exceed ten (10%) of the total assets of the Company and its subsidiaries on a consolidated basis; and the Company hereby agrees to furnish a copy of each such instrument to the Securities and Exchange Commission on request.
(b) Reports on Form 8-K.
None
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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
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SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson ------------------------------ Nathaniel D. Woodson Chairman of the Board of Directors, President and Chief Executive Officer
DATE: MARCH 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.
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- ------------------------------------
NOTE: (A) Accounts written off, less recoveries. (B) Included in consolidated amounts above.
S-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.
Not Applicable
PART III
Item 10.
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.
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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.
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:
- ----------------------- (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
- ------------------- 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
- ------------------------- (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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- -------------------------
(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
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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.
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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.
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
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(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.
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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
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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.
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.
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.
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Exhibits:
Pursuant to Rule 12b-32 under the Securities Exchange Act of 1934, certain of the following listed exhibits, which are annexed as exhibits to previous statements and reports filed by the Company, are hereby incorporated by reference as exhibits to this report. Such statements and reports are identified by reference numbers as follows:
(1) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1995.
(2) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September 30, 1995.
(3) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30, 1996.
(4) Filed with 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.
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- --------------------------- *Management contract or compensatory plan or arrangement.
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The foregoing list of exhibits does not include instruments defining the rights of the holders of certain long-term debt of the Company and its subsidiaries where the total amount of securities authorized to be issued under the instrument does not exceed ten (10%) of the total assets of the Company and its subsidiaries on a consolidated basis; and the Company hereby agrees to furnish a copy of each such instrument to the Securities and Exchange Commission on request.
(b) Reports on Form 8-K.
None
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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
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SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE UNITED ILLUMINATING COMPANY
By /s/ Nathaniel D. Woodson ------------------------------ Nathaniel D. Woodson Chairman of the Board of Directors, President and Chief Executive Officer
DATE: MARCH 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.
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NOTE: (A) Accounts written off, less recoveries. (B) Included in consolidated amounts above.
S-1