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United Illuminating Co · 10-K · For 12/31/97

Filed On 3/3/98   ·   Accession Number 101265-98-2   ·   SEC File 1-06788

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  As Of                Filer                Filing    For/On/As Docs:Size

 3/03/98  United Illuminating Co            10-K       12/31/97    5:476K

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report Form 10-K                               94    518K 
 2: EX-10       Union C0Ntract, Eff. 5/16/97                         124    297K 
 3: EX-12       Statement Re: Computation of Ratios                    2     12K 
 4: EX-21       List of Subsidiaries of United Illuminating            1      4K 
 5: EX-27       FDS -- 12 Mos. of 1997                                 1      6K 


10-K   —   Annual Report Form 10-K
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
2Table of Contents
"Item 1. Business
"Item 2. Properties
"Item 3. Legal Proceedings
3Item 5. Market for the Company's Common Equity and Related Stockholder Matters
"Item 6. Selected Financial Data
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 8. Financial Statements and Supplementary Data
4Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
"Item 11. Executive Compensation
"Item 12. Security Ownership of Certain Beneficial Owners and Management
"Item 13. Certain Relationships and Related Transactions
"Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
7Franchises, Regulation and Competition
8Competition
9Rates
12Fuel Supply
13Arrangements with Other Utilities
14Hydro-Quebec
"Environmental Regulation
18Year 2000 Issue
22Capital Expenditure Program
23Nuclear Generation
28Item 4. Submission of Matters to a Vote of Security Holders
29Executive Officers of the Company
35Major Influences on Financial Condition
42Looking Forward
49Noncurrent Liabilities
55Earnings per Share
73Connecticut Yankee
83Item 10. Directors and Executive Officers of the Company
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SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------ FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to -------------- --------------- Commission File Number 1-6788 THE UNITED ILLUMINATING COMPANY (Exact name of registrant as specified in its charter) CONNECTICUT 06-0571640 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 157 CHURCH STREET, NEW HAVEN, CONNECTICUT 06506 (Address of principal executive offices) (Zip Code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 203-499-2000 ------------------------------------------------------ SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: [Enlarge/Download Table] NAME OF EACH EXCHANGE ON REGISTRANT TITLE OF EACH CLASS WHICH REGISTERED ---------- ------------------- ------------------------ The United Illuminating Company Common Stock, no par value New York Stock Exchange United Capital Funding Partnership L.P.(1) 9 5/8% Preferred Capital New York Stock Exchange Securities, Series A (Liquidation Preference $25 per Security) (1) The 9 5/8% Preferred Capital Securities, Series A, were issued on April 3, 1995 by United Capital Funding Partnership L.P., a special purpose limited partnership in which The United Illuminating Company owns all of the general partner interests, and are guaranteed by The United Illuminating Company. SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: COMMON STOCK, NO PAR VALUE, OF THE UNITED ILLUMINATING COMPANY Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The aggregate market value of the registrant's voting stock held by non-affiliates on January 31, 1998 was $617,981,481, computed on the basis of the average of the high and low sale prices of said stock reported in the listing of composite transactions for New York Stock Exchange listed securities, published in The Wall Street Journal on February 2, 1998. The number of shares outstanding of the registrant's only class of common stock, as of January 31, 1998, was 14,278,256. DOCUMENTS INCORPORATED BY REFERENCE [Enlarge/Download Table] Document Part of this Form 10-K into which document is incorporated -------- ---------------------------------------------------------- Definitive Proxy Statement, dated March 27, 1998, for Annual Meeting of the Shareholders to be held on May 20, 1998. III
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THE UNITED ILLUMINATING COMPANY FORM 10-K DECEMBER 31, 1997 TABLE OF CONTENTS PAGE ---- GLOSSARY 4 PART I Item 1. Business. 6 - General 6 - Franchises, Regulation and Competition 6 - Franchises 6 - Regulation 6 - Competition 7 - Rates 8 - Financing 9 - Fuel Supply 11 - Fossil Fuel 11 - Nuclear Fuel 12 - Arrangements with Other Utilities 12 - New England Power Pool 12 - New England Transmission Grid 13 - Hydro-Quebec 13 - Environmental Regulation 13 - Employees 16 - Year 2000 Issue 17 Item 2. Properties. 18 - Generating Facilities 18 - Tabulation of Peak Loads, Resources, and Margins 19 - Transmission and Distribution Plant 20 - Capital Expenditure Program 21 - Nuclear Generation 22 - General Considerations 23 - Insurance Requirements 24 - Waste Disposal and Decommissioning 24 Item 3. Legal Proceedings. 26 - 1 -
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TABLE OF CONTENTS (CONTINUED) PAGE ---- Item 4. Submission of Matters to a Vote of Security Holders. 27 Executive Officers of the Company 28 PART II Item 5. Market for the Company's Common Equity and Related Stockholder Matters. 29 Item 6. Selected Financial Data. 30 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 34 - Major Influences on Financial Condition 34 - Liquidity and Capital Resources 35 - Subsidiary Operations 37 - Results of Operations 38 - Looking Forward 41 Item 8. Financial Statements and Supplementary Data. 45 - Consolidated Financial Statements for the Years 1997, 1996 and 1995 45 - Statement of Income 45 - Statement of Cash Flows 46 - Balance Sheet 47 - Retained Earnings 49 - Notes to Consolidated Financial Statements 50 - Statement of Accounting Policies 50 - Capitalization 56 - Rate-Related Regulatory Proceedings 61 - Accounting for Phase-in Plan 62 - Short-Term Credit Arrangements 62 - Income Taxes 64 - Supplementary Information 66 - Pension and Other Benefits 67 - Jointly Owned Plant 70 - Unamortized Cancelled Nuclear Project 70 - Fuel Financing Obligations and Other Lease Obligations 71 - Commitments and Contingencies 72 - Capital Expenditure Program 72 - 2 -
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TABLE OF CONTENTS (CONTINUED) PAGE ---- PART II (CONTINUED) - Nuclear Insurance Contingencies 72 - Other Commitments and Contingencies 72 - Connecticut Yankee 72 - Hydro-Quebec 73 - Property Taxes 73 - Environmental Concerns 74 - Site Decontamination, Demolition and Remediation Costs 74 - Nuclear Fuel Disposal and Nuclear Plant Decommissioning 74 - Fair Value of Financial Instruments 77 - Quarterly Financial Data (Unaudited) 78 Reports of Independent Accountants 79 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures. 82 PART III Item 10. Directors and Executive Officers of the Company 82 Item 11. Executive Compensation. 82 Item 12. Security Ownership of Certain Beneficial Owners and Management. 82 Item 13. Certain Relationships and Related Transactions. 82 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 83 Consents of Independent Accountants 90 Signatures 92 - 3 -
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GLOSSARY Certain capitalized terms used in this Annual Report have the following meanings, and such meanings shall apply to terms both singular and plural unless the context clearly requires otherwise: "AFUDC" means allowance for funds used during construction. "APS" means American Payment Systems, Inc., a wholly-owned subsidiary of URI. "the Company" or "UI" means The United Illuminating Company. "CSC" means the Connecticut Siting Council. "Connecticut Yankee" means the Connecticut Yankee Atomic Power Company. "Connecticut Yankee Unit" means the nuclear electric generating unit owned by Connecticut Yankee and located in Haddam Neck, Connecticut. "DEP" means the Connecticut Department of Environmental Protection. "DOE" means the United States Department of Energy. "DPUC" means the Connecticut Department of Public Utility Control. "EPA" means the United States Environmental Protection Agency. "FERC" means the United States Federal Energy Regulatory Commission. "LLW" means low-level radioactive wastes. "Millstone Unit 3" means the nuclear electric generating unit located in Waterford, Connecticut, which is jointly owned by UI and twelve other New England electric utility entities. "NDFC" means the Nuclear Decommissioning Finance Committee. "NEPOOL" means the New England Power Pool. "NOx " means nitrogen oxides. "NRC" means the United States Nuclear Regulatory Commission. "NU" means Northeast Utilities. "PCBs" means polychlorinated biphenyls. "Preferred Stock" means capital stock of the Company having preferential dividend and liquidation rights over shares of the Company's other classes of capital stock. "RCRA" means the federal Resource Conservation and Recovery Act. - 4 -
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GLOSSARY (CONTINUED) "Seabrook Unit 1" means nuclear generating unit No. 1 located in Seabrook, New Hampshire, which is jointly owned by UI and ten other New England electric utility entities. "SO2" means sulfur dioxide. "TSCA" means the federal Toxic Substances Control Act. "UI" or "the Company" means The United Illuminating Company. "URI" means United Resources, Inc., a wholly-owned subsidiary of UI. - 5 -
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PART I Item 1. Business. GENERAL The United Illuminating Company (UI or the Company) is an operating electric public utility company, incorporated under the laws of the State of Connecticut in 1899. It is engaged principally in the production, purchase, transmission, distribution and sale of electricity for residential, commercial and industrial purposes in a service area of about 335 square miles in the southwestern part of the State of Connecticut. The population of this area is approximately 704,000 or 21% of the population of the State. The service area, largely urban and suburban in character, includes the principal cities of Bridgeport (population 137,000) and New Haven (population 124,000) and their surrounding areas. Situated in the service area are retail trade and service centers, as well as large and small industries producing a wide variety of products, including helicopters and other transportation equipment, electrical equipment, chemicals and pharmaceuticals. Of the Company's 1997 retail electric revenues, approximately 42% was derived from residential sales, 40% from commercial sales, 16% from industrial sales and 2% from other sales. UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that serves as the parent corporation for several unregulated businesses, each of which is incorporated separately to participate in business ventures that will complement and enhance UI's electric utility business and serve the interests of the Company and its shareholders and customers. URI has four wholly-owned subsidiaries. The largest URI subsidiary, American Payment Systems, Inc., manages a national network of agents for the processing of bill payments made by customers of other utilities. Another subsidiary of URI, Thermal Energies, Inc., is participating in the development of district heating and cooling facilities in the downtown New Haven area, including the energy center for an office tower and participation as a 52% partner in the energy center for a city hall and office tower complex. A third URI subsidiary, Precision Power, Inc., provides power-related equipment and services to the owners of commercial buildings and industrial facilities. URI's fourth subsidiary, United Bridgeport Energy, Inc., is participating in a merchant wholesale electric generating facility being constructed on land leased from UI at its Bridgeport Harbor Station generating plant. The Board of Directors of the Company has authorized the investment of a maximum of $27 million, in the aggregate, of the Company's assets into its unregulated subsidiary ventures, and, at December 31, 1997, $27 million had been so invested. FRANCHISES, REGULATION AND COMPETITION FRANCHISES Subject to the power of alteration, amendment or repeal by the Connecticut legislature, and subject to certain approvals, permits and consents of public authorities and others prescribed by statute, the Company has valid franchises to engage in the production, purchase, transmission, distribution and sale of electricity in the area served by it, the right to erect and maintain certain facilities on public highways and grounds, and the power of eminent domain. REGULATION The Company is subject to regulation by the Connecticut Department of Public Utility Control (DPUC), which has jurisdiction with respect to, among other things, retail electric service rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, the issuance of securities, certain standards of service, management efficiency, operation and construction, and the location and construction of certain electric facilities. See "Rates". The DPUC consists of five Commissioners, appointed by the Governor of Connecticut with the advice and consent of both houses of the Connecticut legislature. - 6 -
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The location and construction of certain electric facilities is also subject to regulation by the Connecticut Siting Council (CSC) with respect to environmental compatibility and public need. See "Environmental Regulation". UI is a "public utility" within the meaning of Part II of the Federal Power Act and is subject to regulation by the Federal Energy Regulatory Commission (FERC), which has jurisdiction with respect to interconnection and coordination of facilities, wholesale electric service rates and accounting procedures, among other things. See "Arrangements with Other Utilities". The Company is a holder of licenses under the Atomic Energy Act of 1954, as amended, and, as such, is subject to the jurisdiction of the United States Nuclear Regulatory Commission (NRC), which has broad regulatory and supervisory jurisdiction with respect to the construction and operation of nuclear reactors, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. Connecticut Yankee Atomic Power Company (Connecticut Yankee), in which the Company has a 9.5% common stock ownership share, is also subject to this NRC regulatory and supervisory jurisdiction. See Item 2. Properties - "Nuclear Generation". The Company is subject to the jurisdiction of the New Hampshire Public Utilities Commission for limited purposes in connection with its 17.5% ownership interest in Seabrook Unit 1. COMPETITION The electric utility industry has become, and can be expected to be, increasingly competitive, due to a variety of economic, regulatory and technological developments; and UI is exposed to competitive forces in varying degrees. In UI's principal market, retail sales of electricity in the Company's franchised service territory, competitive pressures are rising from several sources. Industrial and large commercial customers may have the ability to own and operate facilities that generate their own electric energy requirements. If these facilities satisfy certain statutory requirements, UI can be required to purchase their output that exceeds their owners' needs, at UI's avoided cost. These customers may also substitute natural gas or oil for electricity as fuel for heating and cooling purposes, and industrial customers may have the option of relocating their facilities to a lower-cost environment. As a result of these pressures, and with the approval of the DPUC, UI offers special rate and service agreements to induce industrial and large commercial customers to remain on the Company's system. The Company now has 62 multi-year contracts with major customers, including its largest customer. This customer is constructing a cogeneration unit that is expected to produce enough electricity, commencing sometime in early 1998, to supply approximately one-half of the customer's requirements. The customer's remaining requirements will continue to be supplied by UI under a special rate and service agreement. To the extent that the Company loses revenues from customers leaving the system or paying for service under special rate or service agreements, the Company's only opportunity to replace such revenues will be through increased wholesale sales and retail sales growth. The Company is not capitalizing these "lost" revenues for future rate recovery. See "Rates". Although UI has not historically been a major wholesale supplier of bulk electric power (power sold to other utilities), it has marketed generating capacity and energy aggressively in recent years, seeking to sell outside its service territory the power it produces in excess of the present needs of its own customers. Competition in the wholesale power market can be expected to increase by reason of the Federal Energy Policy Act of 1992, which was designed to foster competition in the wholesale market by facilitating the ownership and operation of independently-owned generating facilities and authorizing the FERC to order electric utilities to furnish transmission service to the owners of these generating facilities. Competition may also increase in the wholesale power market as a result of a FERC rulemaking that seeks to promote competition in that market by requiring electric utilities to furnish non-discriminatory transmission service to all buyers and sellers in the marketplace, and due to the entry of brokers and marketers, who buy and sell generating capacity and energy without owning or operating any generating or transmission facilities. In its rulemaking, the FERC has stressed the importance of allowing electric utilities to recover the costs of existing facilities (primarily generation) that would be rendered uneconomic ("stranded") by a competitive bulk power market. The structure of the wholesale power market will also change due to the implementation of the restructuring of the New - 7 -
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England Power Pool (NEPOOL), which envisions separate markets for several energy, capacity, and ancillary services products. See "Arrangements with Other Utilities". The FERC has stated that state regulatory commissions should address the issue of recovery by electric utilities of the costs of existing facilities that would be stranded by retail access. The legislatures and regulatory commissions in several states have considered or are considering "retail access". This, in general terms, means the transmission by an electric utility of energy produced by another entity over the utility's transmission and distribution system to a retail customer in the utility's own service territory. A retail access requirement would have the effect of permitting retail customers to purchase electric capacity and energy, at the election of such customers, from the electric utility in whose service area they are located or from any other electric utility, independent power producer or power marketer. In 1995, the Connecticut Legislature established a task force to review these issues and to make recommendations on electric industry restructuring within Connecticut. The task force concluded its work in December 1996 and issued a report and related recommendations. In its 1997 session, the Connecticut legislature drafted, but failed to bring to a vote, comprehensive legislation that would have introduced retail access in Connecticut over a period of several years, with a provision for the recovery of stranded costs by service area utilities. The legislature is currently considering legislation of this same sort in its 1998 session. Among many other factors, decisions and actions concerning retail access in other states could impact the timing and form of this legislation. Although the Company is unable to predict the future effects of competitive forces in the electric utility industry, competition could result in a change in the regulatory structure of the industry, and costs that have traditionally been recoverable through the ratemaking process may not be recoverable in the future. This effect could have a material impact on the financial condition and/or results of operations of the Company. In anticipation of increased competition, the Company has initiated a continuing and focused effort to reduce and control costs, to reinforce customer loyalty and to develop additional sources of revenue. See "Rates". See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Major Influences on Financial Condition" and "Looking Forward". RATES The Company's retail electric service rates are subject to regulation by the Connecticut Department of Public Utility Control (DPUC). UI's present general retail rate structure consists of various rate and service classifications covering residential, commercial, industrial and street lighting services. Utilities are entitled by Connecticut law to charge rates that are sufficient to allow them to cover their operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. On December 31, 1996, the DPUC completed a financial and operational review of the Company and ordered a five-year incentive regulation plan for the years 1997-2001. The DPUC did not change the existing retail base rates charged to customers; but its order increased amortization of the Company's conservation and load management program investments during 1997-1998, and accelerated the recovery of unspecified regulatory assets during 1999-2001 if the Company's common stock equity return on utility investment exceeds 10.5% after recording the increased conservation and load management amortization. The order also reduced the level of conservation adjustment mechanism revenues in retail prices, provided a reduction in customer prices through a surcredit in each of the five plan years, and accepted the Company's proposal to modify the operation of the fossil fuel clause mechanism. The Company's authorized return on utility common stock equity was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are to be utilized one-third for customer price reductions, one-third to increase amortization of regulatory assets, and one-third retained as earnings. As a result of the DPUC's order, customer prices were required to be reduced, on average, by 3% in 1997 compared to 1996. Retail revenues actually decreased by approximately $30 million, or 4.6%, in 1997 due to customer price reductions. Also as a - 8 -
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result of the order, customer prices are required to be reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996. By its terms, the DPUC's 1996 order should be reopened in 1998 to determine the regulatory assets to be subjected to accelerated recovery in 1999, 2000 and 2001. FINANCING The Company's capital requirements are presently projected as follows: [Enlarge/Download Table] 1998 1999 2000 2001 2002 ---- ---- ---- ---- ---- (millions) Cash on Hand - Beginning of Year $ 32.0 $10.4 $ - $ - $ - Internally Generated Funds less Dividends 118.5 108.0 109.3 97.0 68.6 ----- ----- ----- ---- ---- Subtotal 150.5 118.4 109.3 97.0 68.6 Less: Capital Expenditures 35.9 32.7 39.6 31.1 30.7 ----- ----- ----- ---- ---- Cash Available to pay Debt Maturities and Redemptions 114.6 85.7 69.7 65.9 37.9 Less: Maturities and Mandatory Redemptions 104.2 103.4 150.4 75.3 0.3 ----- ----- ----- ---- ---- External Financing Requirements (Surplus) $(10.4) $ 17.7 $ 80.7 $ 9.4 $(37.6) ====== ====== ====== ===== ======= Note: Internally Generated Funds less Dividends, Capital Expenditures and External Financing Requirements are estimates based on current earnings and cash flow projections and are subject to change due to future events and conditions that may be substantially different from those used in developing the projections. All of the Company's capital requirements that exceed available cash will have to be provided by external financing. Although the Company has no commitment to provide such financing from any source of funds, other than a $75 million revolving credit agreement with a group of banks, described below, the Company expects to be able to satisfy its external financing needs by issuing additional short-term and long-term debt, and by issuing preferred stock or common stock, if necessary. The continued availability of these methods of financing will be dependent on many factors, including conditions in the securities markets, economic conditions, and the level of the Company's income and cash flow. On December 30, 1996, the Company transferred $51.3 million to a trustee under an escrow agreement. The funds, which were invested in Treasury Notes, were used to pay $50 million principal amount of 7% Notes that matured on January 15, 1997 plus accrued interest. In February 1997, the Company purchased at a discount on the open market, and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock. The shares, having a par value of $40,300, were purchased for $21,271, creating a net gain of $19,029. On February 15, 1997, the Company repaid $10.8 million principal amount of maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of $185,328, the remaining $21.6 million outstanding principal amount of 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a wholly-owned subsidiary of the Company that was merged with and into the Company in September 1994. - 9 -
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On July 30, 1997, the Company borrowed $98.5 million from the Business Finance Authority of the State of New Hampshire (BFA), representing the proceeds from the issuance by the BFA of $98.5 million principal amount of tax-exempt Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated, under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs' bondholders such amounts as will pay, when due, the principal of and the premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and their interest rate is adjusted periodically to reflect prevailing market conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75% at December 31, 1997. The Company has used the proceeds of this $98.5 million borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987 Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990 Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of tax-exempt bonds on which the Company also had a payment obligation to a trustee for the bondholders. Expenses associated with this transaction, including redemption premiums totaling $2,055,000 and other expenses of approximately $1,500,000, were paid by the Company. In August 1997, the Company purchased at a discount on the open market, and canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and 200 shares of its $100 par value 4.64%, Series C preferred stock. These shares, having a par value of $70,000, were purchased for $41,100, creating a net gain of $28,900. On November 12, 1997, the Company refinanced the secured lease obligation bonds that were issued in 1990 in connection with the sale and leaseback by the Company of a portion of its ownership share in Seabrook Unit 1. All of the outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook Lease Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of 10.24% Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were redeemed. The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds were $1,884,549 and $8,589,901, respectively. The Bonds were refunded with the proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds"), the principal of which will be payable from time to time in installments. Transaction expenses totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from the proceeds of the 7.83% Bonds and will be repaid as part of the Company's Lease payments over the remaining term of the Lease. The remainder of the redemption premiums ($2,334,472) and transaction expenses were paid by the Company and will be amortized over the remainder of the Lease term. The transaction reduces the interest rate on the leaseback arrangement, which is treated as long-term debt on the Company's Consolidated Balance Sheet, from 8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76% Bonds and $49,850,000 principal amount of the 10.24% Bonds. The Company used the proceeds from the redemption of these bonds ($70,662,688, including redemption premiums totaling $3,815,688), plus available funds and short-term borrowings, to purchase $101,388,000 principal amount of the 7.83% Bonds. The Company intends to hold the 7.83% Bonds until maturity and has recognized the investment as an offset to long-term debt on its Consolidated Balance Sheet. On January 13, 1998, the Company issued and sold $100 million principal amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which were issued at a discount, is 6.30%; and the Notes will mature on December 15, 2002. The proceeds from the sale of the Notes were used to repay $100 million principal amount of 7 3/8% Notes, which matured on January 15, 1998. The Company has a revolving credit agreement with a group of banks, which currently extends to December 9, 1998. The borrowing limit of this facility is $75 million. The facility permits the Company to borrow funds at a fluctuating interest rate determined by the prime lending market in New York, and also permits the Company to borrow money for fixed periods of time specified by the Company at fixed interest rates determined by the Eurodollar interbank market in London, or by bidding, at the Company's option. If a material adverse change in the business, operations, affairs, assets or condition, financial or otherwise, or prospects of the Company and its subsidiaries, on a consolidated basis, should occur, the banks may decline to lend additional money to the Company under this revolving credit agreement, although borrowings outstanding at the time of such an occurrence would not then become due and payable. As of December 31, 1997, the Company had $30 million of short-term borrowings outstanding under this facility. - 10 -
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In addition, as of December 31, 1997, one of the Company's subsidiaries, American Payment Systems, Inc., had borrowings of $7.8 million outstanding under a bank line of credit agreement. The Company's long-term debt instruments do not limit the amount of short-term debt that the Company may issue. The Company's revolving credit agreement described above requires it to maintain an available earnings/interest charges ratio of not less than 1.5:1.0 for each 12-month period ending on the last day of each calendar quarter. For the 12-month period ended December 31, 1997, this coverage ratio was 3.23:1.0. The Company's Preferred Stock provisions prohibit the issuance of additional Preferred Stock unless the Company's after-tax income for a period of twelve consecutive months ending not more than 90 days prior to such issuance is at least one and one-half times the aggregate of annual interest charges on all indebtedness and annual dividends on all Preferred Stock to be outstanding. The Preferred Stock provisions also prohibit any increase in long-term indebtedness unless the Company's after-tax income for a period of twelve consecutive months ending not more than 90 days prior to such increase is at least twice the annualized interest charges on all long-term indebtedness to be outstanding. The provisions of the financing documents under which the Company leases a portion of its entitlement in Seabrook Unit 1 from an owner trust established for the benefit of an institutional investor presently require UI to maintain its consolidated annual after-tax cash earnings available for the payment of interest at a level that is at least one and one-half times the aggregate interest charges paid on all indebtedness outstanding during the year. On the basis of the formulas contained in the Preferred Stock provisions and the Seabrook Unit 1 lease financing documents, the coverages for each of the five years ended December 31, 1997 are set forth below. Preferred Stock Seabrook Lease Provisions Provisions ------------------------ ----------------- Preferred Long-term Earnings/Interest Year Stock Indebtedness Ratio ---- --------- ------------ ----------------- 1993 3.33 3.67 2.59 1994 2.72 3.14 2.86 1995 2.68 2.71 3.31 1996 2.38 2.39 2.78 1997 2.48 2.60 3.23 The Company has a 5.45% participating share in Phase II of the Hydro-Quebec transmission intertie facility linking New England and Quebec, Canada. See "Arrangements with Other Utilities - Hydro-Quebec". As a participant, the Company is obligated to furnish a guarantee for its participating share of the debt financing for Phase II of the facility. As of December 31, 1997, the Company's guarantee liability for this debt amounted to approximately $7.4 million. FUEL SUPPLY FOSSIL FUEL The Company burns coal, residual oil, jet oil and natural gas at its fossil fuel generating stations in Bridgeport and New Haven. During 1997, approximately 1.1 million tons of coal, 4.9 million barrels of fuel oil and 0.3 billion cubic feet of natural gas were consumed in the generation of electricity. The Company owns fuel oil storage tanks at its generating stations in Bridgeport and New Haven that have maximum capacities of approximately 680,000 and 650,000 barrels of oil, respectively. In addition, the Company maintains, through an inventory finance arrangement, an approximate 34-day coal supply of 125,000 tons at its Bridgeport Harbor Station. - 11 -
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The Company burns coal at the largest generating unit at its Bridgeport generating station; however, this generating unit is also capable of burning oil. The Company has a coal supply contract that extends until July 31, 2007, subject to earlier termination provisions. The Company's fuel oil supply contracts for its New Haven and Bridgeport generating stations will expire on March 31, 1998, and the Company expects to meet its fuel oil needs by entering into one or more new fuel oil supply contracts and/or through purchases on the spot market. The Company's New Haven Harbor Station has a dual-fuel capability of burning natural gas and oil. Under an agreement that expires on December 31, 2000, the Company is obligated to burn approximately 6 billion cubic feet of gas per year, when offered by the supplier at a price that is competitive with oil. During 1997, no natural gas was purchased pursuant to this agreement; and an additional 0.3 billion cubic feet of natural gas was purchased on the spot market. NUCLEAR FUEL The Company holds an ownership and leasehold interest in Seabrook Unit 1 and an ownership interest in Millstone Unit 3, both of which are nuclear-fueled generating units. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of that gas and fabrication of the enriched hexafluoride into usable fuel assemblies. After a region (approximately 1/3 to 1/2 of the nuclear fuel assemblies in the reactor at any time) of spent fuel is removed from a nuclear reactor, it is placed in temporary storage in a spent fuel pool at the nuclear station for cooling and ultimately is expected to be transported to a permanent storage site, which has yet to be determined. See Item 2. Properties - "Nuclear Generation". Based on information furnished by the utility responsible for the operation of the units in which the Company is participating, there are outstanding contracts that cover uranium concentrate purchases for Millstone Unit 3 through 2000 and for Seabrook Unit 1 through 1999. In addition, there are outstanding contracts, to the extent indicated below, for conversion, enrichment and fabrication services for these units extending through the following years: CONVERSION TO HEXAFLUORIDE ENRICHMENT FABRICATION ------------- ---------- ----------- Millstone Unit 3 2003 2002 2011 Seabrook Unit 1 2006 2002 2006 ARRANGEMENTS WITH OTHER UTILITIES NEW ENGLAND POWER POOL The Company, in cooperation with other privately and publicly owned New England electric utilities, established the New England Power Pool (NEPOOL) in 1971. NEPOOL was formed to assure reliable operation of the bulk power system in the most economic manner for the region. It has achieved these objectives through central dispatching of all generation facilities owned by its members and through coordination of the activities of the members that can have significant inter-utility impacts. NEPOOL is governed by an agreement that is filed with the Federal Energy Regulatory Commission (FERC) and its provisions are subject to continuing FERC jurisdiction. Under the terms of the NEPOOL Agreement, the Company incurs certain obligations - such as the responsibility to support a specified amount of power supply resources - and enjoys certain benefits, most notably savings in the cost of its overall energy supply and the sharing of reserve generating capacity. Because of the evolving industry-wide changes that are described at "Franchises, Regulation and Competition - Competition," NEPOOL has been restructured. Its membership has been broadened to cover all entities engaged in the electricity business in New England, including power marketers and brokers, independent power producers and - 12 -
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load aggregators. The operation of the regional bulk power system has been turned over to an independent entity, ISO New England, Inc., so that the regional bulk power system will continue to be operated both in accordance with the NEPOOL objectives and free of any adverse impact on competition in the wholesale power market, where various energy and capacity products will be traded in open competition among all participants. The restructuring changes have been filed with the FERC, for its approval, as an amendment to the NEPOOL Agreement; and the resulting FERC proceedings are expected to be completed during 1998. NEW ENGLAND TRANSMISSION GRID Under other agreements related to the Company's participation in the ownership of Seabrook Unit 1 and Millstone Unit 3, the Company contributes to the financial support of certain 345 kilovolt transmission facilities that are a part of the New England transmission grid. HYDRO-QUEBEC The Company is a participant in the Hydro-Quebec transmission intertie facility linking New England and Quebec, Canada. Phase I of this facility, which became operational in 1986 and in which the Company has a 5.75% participating share, has a 690 megawatt equivalent capacity value; and Phase II, in which the Company has a 5.45% participating share, increased the equivalent capacity value of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A ten-year Firm Energy Contract, which provides for the sale of 7 million megawatt-hours per year by Hydro-Quebec to the New England participants in the Phase II facility, became effective on July 1, 1991. Additionally, the Company is obligated to furnish a guarantee for its participating share of the debt financing for the Phase II facility. As of December 31, 1997, the Company's guarantee liability for this debt was approximately $7.4 million. ENVIRONMENTAL REGULATION The National Environmental Policy Act requires that detailed statements of the environmental effect of the Company's facilities be prepared in connection with the issuance of various federal permits and licenses, some of which are described below. Federal agencies are required by that Act to make an independent environmental evaluation of the facilities as part of their actions during proceedings with respect to these permits and licenses. The federal Clean Water Act requires permits for discharges of effluents into navigable waters and requires that all discharges of pollutants comply with federally approved state water quality standards. The Connecticut Department of Environmental Protection (DEP) has adopted, and the federal government has approved, water quality standards for receiving waters in Connecticut. A joint federal and state permit system, administered by the DEP, has been established to assure that applicable effluent limitations and water quality standards are met in connection with the construction and operation of facilities that affect or discharge into these waters. The discharge permits for the Company's Bridgeport Harbor, English and New Haven Harbor generating stations expired in February and May of 1992, and September of 1996, respectively. Applications for renewal of these permits had been filed in August and November of 1991, and April of 1996, respectively, and while these renewal applications are pending, the terms of the expired permits continue in effect. The application for English Station, in New Haven, has been modified to reflect changes in the operating status of this generating facility and changes in the permitting system. Several new permits have been issued for specific discharges at New Haven Harbor, Bridgeport Harbor and/or English Stations; and, although other new permits for specific discharges have not yet been issued, the Company has not been advised by the DEP that any of these facilities has a permitting problem. The DEP has determined that the thermal component of the discharges at each of the stations will not result in a violation of state water quality standards. All discharge permits may be reopened and amended to incorporate more stringent standards and effluent limitations that may be adopted by federal and state authorities. Compliance with this permit system has necessitated substantial capital and operational expenditures by UI, and it is expected that such expenditures will continue to be required in the future. Under the federal Clean Air Act, the federal Environmental Protection Agency (EPA) has promulgated national primary and secondary air quality standards for certain air pollutants, including sulfur oxides, particulate matter, ozone - 13 -
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and nitrogen oxides. The DEP has adopted regulations for the attainment, maintenance and enforcement of these standards. In order to comply with these regulations, the Company is required to burn fuel oil with a sulfur content not in excess of 1%, and Bridgeport Harbor Unit 3 is required to burn a low-sulfur, low-ash content coal, the sulfur dioxide (SO2) emissions from which are not to exceed 1.1 pounds of SO2 per million BTU of heat input. Current air pollution regulations also include other air quality standards, emission performance standards and monitoring, testing and reporting requirements that are applicable to the Company's generating stations and further restrict the construction of new sources of air pollution or the modification of existing sources by requiring that both construction and operating permits be obtained and that a new or modified source will not cause or contribute to any violation of the EPA's national air quality standards or its regulations for the prevention of significant deterioration of air quality. Amendments to the Clean Air Act in 1990 will require a significant reduction in nationwide SO2 emissions by fossil fuel-fired generating units to a permanent total emissions cap in the year 2000. This reduction is to be achieved by the allotment of allowances to emit SO2, measured in tons per year, to each owner of a unit, and requiring the owner to hold sufficient allowances each year to cover the emissions of SO2 from the unit during that year. Allowances are transferable and can be bought and sold. The Company believes that, under the allowances allocation formula, it will hold more than sufficient allowances to permit continued operation of its existing generating units without incurring substantial expenditures for additional SO2 controls. The Company is marketing its surplus allowances. The same 1990 Clean Air Act amendments also contain major new requirements for the control of nitrogen oxides (NOx) that are applicable to generating units located in or near areas, such as UI's service territory, where ambient air quality standards for photochemical oxidants have not been attained. These amendments also require the installation and/or modification of continuous emission monitoring systems, and require all existing generating units to apply for and obtain operating permits. The Company expects to submit applications for such operating permits in early 1998. These applications will verify compliance with all existing requirements applicable to the generating units at Bridgeport Harbor, English and New Haven Harbor generating stations. Controls installed have resulted in achievement of NOx emissions from Bridgeport Harbor Unit 3, the largest generating unit at Bridgeport Harbor Station, substantially below, and at a date significantly in advance of, that required under the statute. As a result, the DEP has approved UI's creation of transferable and marketable NOx emission reduction credits, and supplemental approvals are anticipated for the creation of additional credits at this generating unit through April 1999. During 1997, UI consummated nineteen sales of NOx emission reduction credits, and it continues to market these credits. These sales have not had a significant impact on the Company's earnings. In September 1994, the Ozone Transport Commission (OTC) (consisting of the twelve northeastern-most states plus the District of Columbia) adopted a Memorandum of Understanding (MOU) that obligates certain of those states, including Connecticut, to adopt regulations that will further limit emissions of NOx from large stationary sources, including utility boilers. The MOU calls for the reductions to occur in two steps; the first in 1999 and the second in 2003. On December 30, 1997, the Connecticut DEP proposed regulations that would implement the requirements of the OTC MOU. It is expected that the regulations, when promulgated, will become part of the federally mandated revisions to Connecticut's plan for achieving compliance with air quality standards for photochemical oxidants (Nox, ozone and particulate matter). On July 18, 1997, the EPA published final revisions to the national air quality standards for ozone and particulate matter. On November 7, 1997, the EPA published a proposed rule that would require states to adopt regulations to ensure that a significant transport of ozone pollution across state boundaries in the eastern United States is prevented. Since not all of these three sets of new regulations have been adopted in final form, the Company is not yet able to assess accurately the applicability and impact of implementing these regulations to and on its generating facilities. Compliance may require substantial additional capital and operational expenditures in the future. In addition, due to the 1990 amendments and other provisions of the Clean Air Act, future construction or modification of fossil-fired generating units and all other sources of air pollution in southwestern Connecticut will be conditioned on installing state-of-the-art nitrogen oxides controls and obtaining nitrogen oxide emission offsets -- in the form of reductions in emissions from other sources -- which may hinder or preclude such construction or modification programs in UI's service area, depending on ambient pollutant levels over which the Company has no control. A merchant wholesale electric generating facility (Bridgeport Energy Project) is being constructed on land leased from UI at its Bridgeport Harbor Station. It is anticipated that UI's Bridgeport Harbor Unit 1 will be placed in deactivated reserve status on or about July 1, 1998, when the first phase of the Bridgeport Energy Project is completed. - 14 -
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UI has provided emission offsets necessary for the licensing of the Bridgeport Energy Project; and UI has agreed to provide Clean Air Act allowances required for the operation of this facility to the extent that they are available from Bridgeport Harbor Units 1 and 2 and are not obtained for the facility from another source. Given the very low emissions rates expected from the Bridgeport Energy Project, it currently appears likely that UI will continue to have surplus SO2 allowances for sale. The Company's generating stations in Bridgeport and New Haven comply with the air quality and emission performance standards adopted by those cities. Under the federal Toxic Substances Control Act (TSCA), the EPA has issued regulations that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating fluids in many electric utility transformers and capacitors manufactured before TSCA prohibited any further manufacture of such PCB equipment. Fluids with a concentration of PCBs higher than 500 parts per million and materials (such as electrical capacitors) that contain such fluids must be disposed of through burning in high temperature incinerators approved by the EPA. Solid wastes containing PCBs must be disposed of in either secure chemical waste landfills or in high-efficiency incinerators. In response to EPA regulations, UI has phased out the use of certain PCB capacitors and has tested all Company-owned transformers located inside customer-owned buildings and replaced all transformers found to have fluids with detectable levels of PCBs (higher than 1 part per million) with transformers that have no detectable PCBs. Presently, no transformers having fluids with levels of PCBs higher than 500 parts per million are known by UI to remain in service in its system, except at one of UI's generating stations. Compliance with TSCA regulations has necessitated substantial capital and operational expenditures by UI, and such expenditures may continue to be required in the future, although their magnitude cannot now be estimated. The Company has agreed to participate financially in the remediation of a source of PCB contamination attributed to UI-owned electrical equipment on property in New Haven. Although the scope of the remediation and the extent of UI's participation have not yet been fully determined, in 1990 the owners of the property estimated the total remediation cost to be approximately $346,000. Under the federal Resource Conservation and Recovery Act (RCRA), the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to regulations adopted by the EPA. Connecticut has adopted state regulations that parallel RCRA regulations but are more stringent in some respects. The Company has complied with the notification and application requirements of present regulations, and the procedures by which UI handles, stores, treats and disposes of hazardous waste products have been revised, where necessary, to comply with these regulations. UI's Bridgeport Harbor and New Haven Harbor Stations have been registered as treatment, storage and disposal facilities, because of historic solid waste management activities at these sites. The Company has ceased using these sites for any of these purposes and has filed facility closure plans with the DEP; but further corrective actions may be required at one or more of them for documented or potential releases of hazardous wastes. Because regulations for such corrective actions have not yet been promulgated, the Company is unable to predict what impact, if any, such regulations may have on these facilities. The Company has estimated that the total cost of decontaminating and demolishing its Steel Point Station and completing requisite environmental remediation of the site will be approximately $11.3 million, of which approximately $8.3 million had been incurred as of December 31, 1997, and that the value of the property following remediation will not exceed $6.0 million. As a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the Company has been recovering through retail rates $1.075 million of these remediation costs per year. The remediation cost, property value and recovery from customers will be subject to true-up in the Company's next retail rate proceeding based on actual remediation costs and actual gain on the Company's disposition of the property. The Company is presently remediating an area of PCB contamination at its English Station generating site, including repair and/or replacement of approximately 560 linear feet of sheet piling. The total cost of the remediation and sheet piling repair is presently estimated at $3.5 million, and the Company plans to repair/replace a major portion of the remaining sheet piling at this location at an estimated cost of $6 million. RCRA also regulates underground tanks storing petroleum products or hazardous substances, and Connecticut has adopted state regulations governing underground tanks storing petroleum and petroleum products that, in some - 15 -
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respects, are more stringent than the federal requirements. The Company has 15 underground storage tanks, which are used primarily for gasoline and fuel oil, that are subject to these regulations. The Company has a testing program to detect leakage from any of its tanks, and it may incur substantial costs for future actions taken to prevent tanks from leaking, to remedy any contamination of groundwater, and to modify, remove and/or replace older tanks in compliance with federal and state regulations. In the past, the Company has disposed of residues from operations at landfills, as most other industries have done. In recent years it has been determined that such disposal practices, under certain circumstances, can cause groundwater contamination. Although the Company has no knowledge of the existence of any such contamination, if the Company or regulatory agencies determine that remedial actions must be taken in relation to past disposal practices, the Company may experience substantial costs. A Connecticut statute authorizes the creation of a lien against all real estate owned by a person causing a discharge of hazardous waste, in favor of the DEP, for the costs incurred by the DEP to contain and remove or mitigate the effects of the discharge. Another Connecticut law requires a person intending to transfer ownership of an establishment that generates more than 100 kilograms per month of hazardous waste to provide the purchaser and the DEP with a declaration that no release of hazardous waste has occurred on the site, or that any wastes on the site are under control, or that the waste will be cleaned up in accordance with a schedule approved by the DEP. Failure to comply with this law entitles the transferee to recover damages from the transferor and renders the transferor strictly liable for the cleanup costs. In addition, the DEP can levy a civil penalty of up to $100,000 for providing false information. UI does not believe that any material claims against the Company will arise under these Connecticut laws. A Connecticut statute prohibits the commencement of construction or reconstruction of electric generation or transmission facilities without a certificate of environmental compatibility and public need from the Connecticut Siting Council (CSC). In certification proceedings, the CSC holds public hearings, evaluates the basis of the public need for the facility, assesses its probable environmental impact and may impose specific conditions for protection of the environment in any certificate issued. In complying with existing environmental statutes and regulations and further developments in these and other areas of environmental concern, including legislation and studies in the fields of water and air quality (particularly "air toxics" and "global warming"), hazardous waste handling and disposal, toxic substances, and electric and magnetic fields, the Company may incur substantial capital expenditures for equipment modifications and additions, monitoring equipment and recording devices, and it may incur additional operating expenses. Litigation expenditures may also increase as a result of scientific investigations, and speculation and debate, concerning the possibility of harmful health effects of electric and magnetic fields. The total amount of these expenditures is not now determinable. See also "Franchises, Regulation and Competition" and Item 2. Properties - "Nuclear Generation". EMPLOYEES As of December 31, 1997, the Company had 1,175 employees, including 127 in subsidiary operations. Of the electric utility employees, approximately 79% had been with the Company for 10 or more years. Approximately 545 of the Company's operating, maintenance and clerical employees are represented by Local 470-1, Utility Workers Union of America, AFL-CIO, for collective bargaining purposes. On June 30, 1997, the Company's unionized employees accepted a new five-year agreement, amending and extending the existing agreement that was scheduled to remain in effect through May 15, 1998. The new agreement provides for, among other things, 2% annual wage increases beginning in May 1998, and annual lump sum bonuses of 2.5% of base annual straight time wages (not cumulative). These provisions will restrict the growth of the Company's bargaining unit base wage expense to about $500,000 per year. The agreement also provides for job security for longer-term bargaining unit employees and will allow the Company some flexibility in adjusting work methods as part of its ongoing process re-engineering efforts. - 16 -
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There has been no work stoppage due to labor disagreements since 1966, other than a strike of three days duration in May 1985; and employee relations are considered satisfactory by the Company. YEAR 2000 ISSUE The Company's planning and operations functions, and its cash flow, are dependent on the timely flow of electronic data to and from its customers, suppliers and other electric utility system managers and operators. In order to assure that this data flow will not be disturbed by the problems emanating from the fact that many existing computer programs were designed without considering the impact of the year 2000 and use only two digits to identify the year in the date field of the programs (the Year 2000 Issue), the Company initiated in mid-1997, and is pursuing, an aggressive program to identify and correct all deficiencies in its computer systems and in the computer systems of the critical suppliers and other persons with whom data must be exchanged. A complete inventory and assessment of the Company's computer system applications, hardware, software and embedded technologies has been completed, and recommended solutions to all identified risks and exposures have been generated. A remediation, retirement, renovation and testing program has commenced. Necessary upgrades to mainframe hardware and software are expected to be completed and tested during 1998, and a parallel program with respect to desktop hardware and software is currently projected to be completed and tested by March 31, 1999. Request for documented compliance information have been sent to all critical suppliers, data sharers and facility building owners and, as responses are received, appropriate solutions and testing programs are being developed and executed. The Company believes that the successful implementation of this program, which is currently estimated to cost approximately $2.6 million, will preclude any significant adverse impact of the Year 2000 Issue on its operations and financial condition. - 17 -
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Item 2. Properties GENERATING FACILITIES The electric generating capability of the Company as of December 31, 1997, based on summer ratings of the generating units, was as follows: [Enlarge/Download Table] YEAR OF MAX CLAIMED UI UI OPERATED: FUEL INSTALLATION CAPABILITY, MW ENTITLEMENT --------------------------- ---- ------------ -------------- ----------- % Mw Bridgeport Harbor Station 1 #6 Oil 1957 76.09 100.00 76.09(1) Bridgeport Harbor Station 2 #6 Oil 1961 170.00 100.00 170.00(2) Bridgeport Harbor Station 3 #6 Oil/Coal 1968/1985 385.00 100.00 385.00(3) Bridgeport Harbor Station 4 Jet Oil 1967 16.15 100.00 16.15 New Haven Harbor Station #6 Oil/Gas 1975 466.00 93.71 436.69(4) English Station 7 #6 Oil 1948 34.06 100.00 34.06(5) English Station 8 #6 Oil 1953 38.49 100.00 38.49(5) OPERATED BY OTHER UTILITIES: --------------------------- Millstone Unit 3, Nuclear 1986 1119.60 3.685 41.26(6) Waterford, Connecticut Seabrook Unit 1, Nuclear 1990 1162.00 17.50 203.35(7) Seabrook, New Hampshire POWER PURCHASES FROM COGENERATION FACILITIES: ----------------------- Bridgeport RESCO, Refuse 1988 59.45 100.00 59.45 Bridgeport, Connecticut Shelton Landfill Gas 1995 1.61 100.00 1.61 Shelton, Connecticut ------- Total 1462.15 ======= (1) Effective January 1, 1994, Bridgeport Harbor Station 1 was removed from operation and dispatching under NEPOOL and was placed in deactivated reserve. The unit was reactivated in July 1996 and placed under NEPOOL dispatch to help alleviate power shortages in Connecticut caused by the outages of the three nuclear generating units at Millstone Station and the Connecticut Yankee Unit. See "Nuclear Generation". It is anticipated that Bridgeport Harbor Station 1 will be returned to deactivated reserve status on or about July 1, 1998, when the first phase of a merchant wholesale electric generating facility (Bridgeport Energy Project) being constructed on land leased from UI at Bridgeport Harbor Station. (2) Commencing with the completion of the second phase of the Bridgeport Energy Project, scheduled for July of 1999, a wholesale power marketer will have an option to purchase the capability and energy generated by Bridgeport Harbor Station 2, for a period of twelve years, pursuant to a wholesale power contract. (3) The unit has burned coal since January 1985. (4) Represents UI's 93.705% ownership share of total net capability. This unit is jointly owned by UI (93.705%), Fitchburg Gas and Electric Light Company (4.5%) and the electric departments of three Massachusetts municipalities (1.795%). See Item 1. Business - "Fuel Supply". (5) English Station 7 and 8 were placed in deactivated reserve, effective January 1, 1992. (6) Represents UI's 3.685% ownership share of total net capability. This unit is currently shut down for safety reasons, awaiting NRC authorization for restart. See "Nuclear Generation". (7) Represents UI's 17.5% ownership share of total net capability. In August 1990, UI sold to and leased back from an owner trust established for the benefit of an institutional investor a portion of UI's 17.5% ownership interest in this unit. This portion of the unit is subject to the lien of a first mortgage granted by the owner trustee. - 18 -
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TABULATION OF PEAK LOADS, RESOURCES, AND MARGINS 1997 ACTUAL, 1998 - 2002 FORECAST (MEGAWATTS) [Enlarge/Download Table] Actual Forecast ------ -------------------------------------------------- 1997 1998 1999 2000 2001 2002 At Time of Peak Load on UI's System: ----------------------------------- Capacity of generating units operated by UI (1) 1070.77 1088.55 1088.55 1088.55 1088.55 l088.55 ------------------------------------- Entitlements in nuclear units (1) (2) ----------------------------- Millstone Unit 3 (3) 41.26 41.26 41.26 41.26 41.26 41.26 Seabrook Unit 1 203.35 203.35 203.35 203.35 203.35 203.35 ------ ------ ------ ------ ------ ------ 244.61 244.61 244.61 244.61 244.61 244.61 ------ ------ ------ ------ ------ ------ Equivalent capacity value of entitlement in Hydro-Quebec (1) (2) 98.08 98.08 98.08 98.08 98.08 0 ---------------------------- Purchases from cogeneration facilities -------------------------------------- Bridgeport RESCO 59.45 59.45 59.45 59.45 59.45 59.45 Shelton Landfill 1.61 1.50 1.57 1.54 1.36 1.32 Purchase from New York Power Authority 1.14 1.14 1.14 1.14 1.14 1.14 -------------------------------------- Purchases from (sales to) other utilities ----------------------------------------- Net power contracts - fossil (119.56) 2.56 2.56 (30.64) (30.64) (30.64) ------- ------- ------- ------- ------- ------- Total generating resources 1356.10 1495.89 1495.96 1462.73 1462.55 1364.43 ======= ======= ======= ======= ======= ======= Calculation of UI's capability responsibility (4) ------------------------------ Peak load 1173.00 1179.00 1190.00 1207.00 1220.00 1230.00 Required reserve margin 167.06 214.86 257.24 260.91 263.72 184.50 ------- ------- ------- ------- ------- ------- Total capability responsibility 1340.06 1393.86 1447.24 1467.91 1483.72 1414.50 ======= ======= ======= ======= ======= ======= Available Margin (5) 13.29 99.39 46.01 (7.86) (23.67) (52.53) ======= ======= ======= ======= ======= ======= (1) Capacity shown reflects summer ratings of generating units. (2) Winter ratings of UI nuclear and Hydro-Quebec interconnection's equivalent capacity value entitlements (megawatts): Millstone Unit 3 - 42.22 Seabrook Unit 1 - 203.35 Hydro-Quebec - 34.34 (3) At the time of 1997 summer peak, Millstone Unit 3 still retained capability rating for the purposes of satisfying UI's required capacity as a NEPOOL participant. It is assumed that unit will be back in operation by the time of 1998 summer peak. (4) UI's required capacity as a NEPOOL participant. (5) Total generating resources, excluding purchases from New York Power Authority and Shelton Landfill, less capability responsibility. In addition, UI maintains two units (English Station 7 and 8) in deactivated reserve, representing a total of 72.55 MW of generating capacity. - 19 -
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During 1997, the peak load on the Company's system was approximately 1,173 megawatts, which occurred in July. UI's total generating capability at the time was 1,356 megawatts, including a 98 megawatt increase in capability provided by the equivalent capacity value of UI's entitlements in the Hydro-Quebec facility and reflecting the net effect of temporary arrangements with other electric utilities and cogenerators. The Company is currently forecasting an annual average compound growth in peak load of 0.8% during the period 1997 to 2007. Based on current forecasts of loads, UI's generating capability will exceed its projected July-August capability responsibility to NEPOOL for generating capacity through at least 1999, and English Station Units 7 and 8 can be reactivated if higher than anticipated load growth occurs. If, due to the permanent loss of a generating unit or higher than expected load growth, UI's own generating capability becomes inadequate to meet its capability responsibility to NEPOOL, UI expects to be able to reduce the load on its system by the implementation of additional demand-side management programs, to acquire other demand-side and supply-side resources, and/or to purchase capacity from other utilities or from the installed capability spot market, as necessary. However, because the generation and transmission systems of the major New England utilities, including UI, are operated as if they were a single system, the ability of UI to meet its load is and will be dependent on the ability of the region's generation and transmission systems to meet the region's load. See "Nuclear Generation" and Item 1. Business - "Competition" and "Arrangements with Other Utilities". Shown below is a summary of the Company's sources and uses of electricity for 1997. MEGAWATT-HOURS (000's) SOURCES USES ------- ---- OWNED Retail Customers 5,376 Nuclear (Seabrook Unit 1) 1,390 Coal 2,760 Wholesale Oil 2,951 Delivered to NEPOOL 1,256 Gas & Gas Turbines 28 Contracts 1,745 ----- Total Owned 7,129 Company Use & Losses 255 PURCHASED ----- Contracts 962 Total Uses 8,632 NEPOOL 240 ===== Hydro-Quebec 301 ----- Total Sources 8,632 ===== TRANSMISSION AND DISTRIBUTION PLANT The transmission lines of the Company consist of approximately 102 circuit miles of overhead lines and approximately 17 circuit miles of underground lines, all operated at 345 KV or 115 KV and located within or immediately adjacent to the territory served by the Company. These transmission lines interconnect the Company's English, Bridgeport Harbor and New Haven Harbor generating stations and are part of the New England transmission grid through connections with the transmission lines of The Connecticut Light and Power Company. A major portion of the Company's transmission lines is constructed on a railroad right-of-way pursuant to a Transmission Line Agreement that expires in May 2000. The Company owns and operates 25 bulk electric supply substations with a capacity of 2,634,000 KVA and 40 distribution substations with a capacity of 212,500 KVA. The Company has 3,150 pole-line miles of overhead distribution lines and 130 conduit-bank miles of underground distribution lines. See "Capital Expenditure Program" concerning the estimated cost of additions to the Company's transmission and distribution facilities. - 20 -
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CAPITAL EXPENDITURE PROGRAM The Company's 1998-2002 capital expenditure program, excluding allowance for funds used during construction (AFUDC), and its effect on certain capital related items is presently budgeted as follows: [Enlarge/Download Table] 1998 1999 2000 2001 2002 TOTAL ---- ---- ---- ---- ---- ----- (000's) Production $7,747 $13,911 $12,620 $9,615 $11,920 $55,813 Distribution 15,686 12,783 14,213 13,983 14,405 71,070 Transmission 875 1,923 3,408 783 467 7,456 Other 3,281 3,361 789 612 959 9,002 ------ ------ ------ ------ ------ ------- SUBTOTAL 27,589 31,978 31,030 24,993 27,751 143,341 Nuclear Fuel 8,325 746 8,569 6,160 2,892 26,692 ------ ------ ------ ------ ------ ------- Total Expenditures $35,914 $32,724 $39,599 $31,153 $30,643 $170,033 ====== ====== ====== ====== ====== ======= Rate Base and Other Selected Data: --------------------------------- AFUDC (Pre-tax) 1,683 1,836 1,853 1,563 1,505 Depreciation Book Plant 57,192 58,213 58,158 57,945 58,778 Conservation Assets 10,309 5,390 0 0 0 Decommissioning 2,676 2,781 2,892 3,007 3,128 Additional Required Amortization (pre-tax)(1) Conservation Assets 13,000 0 0 0 0 Other Regulatory Assets 0 20,300 49,500 54,500 0 Amortization of Deferred Return on Seabrook Unit 1 Phase-In (after-tax) 12,586 12,586 0 0 0 Estimated Rate Base (end of period) 1,106,666 1,042,700 989,995 928,513 895,962 (1) Additional amortization of pre-1997 conservation costs and other unspecified regulatory assets, as ordered by the DPUC in its December 31, 1996 Order, provided that, as expected, common equity return on utility investment exceeds 10.5% after recording the additional amortization. Note: Capital Expenditures and their effect on certain capital related items are estimates subject to change due to future events and conditions that may be substantially different than those used in developing the projections. - 21 -
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NUCLEAR GENERATION UI holds ownership and leasehold interests totalling 17.5% (203.35 megawatts) in Seabrook Unit 1, and a 3.685% (41.26 megawatts) ownership interest in Millstone Unit 3. UI also owns 9.5% of the common stock of Connecticut Yankee, and was entitled to an equivalent percentage (53.21 megawatts) of the generating capability of the Connecticut Yankee Unit prior to its retirement from commercial operation on December 4, 1996. Seabrook Unit 1 commenced commercial operation in June of 1990, pursuant to an operating license issued by the NRC, which will expire in 2026. It is jointly owned by eleven New England electric utility entities, including the Company, and is operated by a service company subsidiary of Northeast Utilities (NU). Through December 31, 1997, Seabrook Unit 1 has operated at a lifetime capacity factor of 79%. Millstone Unit 3 commenced commercial operation in April of 1986, pursuant to a 40-year operating license issued by the NRC. It is jointly owned by thirteen New England electric utility entities, including the Company, and is operated by another service company subsidiary of NU. Through March 30, 1996, when Millstone Unit 3 was taken out of service following an engineering evaluation that determined that four safety-related valves would not be able to perform their design function during certain postulated events, Millstone Unit 3 had operated at a lifetime capacity factor of 71.9%. In April, May and June of 1996, a series of NRC letters to NU and its operating service company subsidiary stated: that the NRC had identified programmatic issues and design deficiencies at Millstone Unit 3 that were similar in nature to those previously identified at Millstone Units 1 and 2, the two other Millstone Station nuclear generating units, which had been taken out of service in November of 1995 and February of 1996, respectively, and are owned by operating subsidiaries of NU and are also operated by the NU service company subsidiary that operates Millstone Unit 3; that the NRC had concluded that the corrective action program at Millstone Station was not currently effective in resolving identified deficiencies; that none of the generating units at Millstone Station may be restarted until the effectiveness of a corrective action program is demonstrated; and that Millstone Station had been placed on the NRC's "watch list" as a Category 3 facility. The NRC deems Category 3 plants as having significant weaknesses that warrant maintaining the plant in shutdown condition until it is demonstrated that adequate programs have been established and implemented to ensure substantial improvement. In October of 1996, the NRC announced that an independent NRC review had concluded that the work environment and management failures were the source of a high volume of employee concerns and allegations related to safety of plant operations and harassment and intimidation of employees at Millstone Station. Concurrently, the NRC issued an order directing NU to devise and implement a compliance plan for handling safety concerns raised by Millstone Station employees, and for assuring an environment free from retaliation and discrimination, and ordering NU to contract for an independent third party to oversee its corrective action program for the employee concerns program. NU is engaged in an extensive effort to address and correct all of the above-described problems at Millstone Station and to develop a comprehensive plan for returning each of the Millstone Station nuclear generating units to service. Although UI's management anticipates that all of the above-described problems with respect to Millstone Unit 3 will be resolved, UI cannot, at this time, predict how long it will take to resolve them, or when the NRC will allow Millstone Unit 3 to return to service. While Millstone Unit 3 is out of service, UI is incurring incremental replacement power costs estimated at approximately $500,000 per month, and experiencing an adverse impact on net earnings per share of approximately $.02 per month. In addition to these costs of replacement power, substantial incremental direct costs are being incurred to address the above-described problems with respect to Millstone Unit 3, and the Company may be responsible for its 3.685% joint ownership share of these costs. UI and the other nine non-NU owners of Millstone Unit 3 have been paying their monthly shares of the costs of the unit, but have reserved their rights to contest whether one or more of the NU service company subsidiary that is the operator of Millstone Unit 3 and two operating NU subsidiary electric utility companies that are the majority joint owners of Millstone Unit 3 are responsible for the additional costs that the other joint owners have experienced as a result of the shutdown of Millstone Unit 3. On August 7, 1997, the Company and the other nine minority, non-NU joint owners of Millstone Unit 3 filed lawsuits against NU and its trustees, as well as a demand for arbitration against The Connecticut Light and Power Company and Western Massachusetts Electric Company, the operating electric utility subsidiaries of NU that are the majority joint owners of the unit and have contracted with the minority joint owners to operate it. The ten non-NU joint owners, who together own about 19.5% of the unit, claim that NU and its subsidiaries failed to comply with NRC regulations, failed to operate - 22 -
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Millstone Station in accordance with good utility operating practice and concealed their failures from the non-operating joint owners and the NRC. The arbitration and lawsuits seek to recover costs of purchasing replacement power and increased operation and maintenance costs resulting from the shutdown of Millstone Unit 3. The Connecticut Yankee Unit commenced commercial operation in January of 1968, pursuant to a 40-year operating license issued by the NRC. It is owned, through ownership of Connecticut Yankee's common stock, by ten New England electric utilities, including the Company, and is operated by another service company subsidiary of NU. Prior to July 23, 1996, when the Connecticut Yankee Unit was taken out of service following an engineering evaluation that determined that safety-related air cooling system pipes could crack if the plant should lose its outside source of electric power, the Connecticut Yankee Unit had operated at a lifetime capacity factor of 75.6%. Prior to and following its removal from service in July of 1996, NRC inspections of the Connecticut Yankee Unit revealed issues that were similar to those previously identified at Millstone Station and identified a number of significant deficiencies in the engineering calculations and analyses that were relied upon to ensure the adequacy of the design of key safety systems at the unit. Pending a resolution of these issues, an economic study by the owners, comparing the costs of continuing to operate the Connecticut Yankee Unit over the remaining period of its operating license, which expires in 2007, to the costs of shutting down the unit permanently and incurring replacement power costs for the same period, resulted in a decision, on December 4, 1996, by the Board of Directors of Connecticut Yankee to retire the Connecticut Yankee Unit from commercial operation. The economic study did not consider the costs of addressing the issues and concerns raised by the NRC. If these costs had been considered, the economic study would have been more negative concerning the continued operation of the unit. At December 31, 1997, UI's equity investment in Connecticut Yankee was approximately $10.5 million. The estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in the Connecticut Yankee Unit is approximately $606 million. The Company's estimate of its remaining share of costs, including decommissioning, less return of investment (approximately $10.5 million) and return on investment (approximately $6.3 million), is approximately $40.8 million. This estimate, which is subject to ongoing review and revision, has been recorded by the Company as a regulatory asset and an obligation on the Consolidated Balance Sheet. The power purchase contract under which UI has purchased its 9.5% entitlement to the unit's power output will permit Connecticut Yankee to recover UI's share of these costs from UI. Connecticut Yankee has filed revised decommissioning cost estimates and amendments to the power contracts with its owners, including UI, with the FERC. Based on regulatory precedent, Connecticut Yankee believes it will continue to collect from its power purchasers its decommissioning costs, the owners' unrecovered investments in Connecticut Yankee and other costs associated with the permanent shutdown of the Connecticut Yankee Unit. UI expects that it will continue to be allowed to recover all FERC-approved costs from its customers through retail rates. GENERAL CONSIDERATIONS Seabrook Unit 1, Millstone Unit 3 and the Connecticut Yankee Unit are each subject to the licensing requirements and jurisdiction of the NRC under the Atomic Energy Act of 1954, as amended, and to a variety of other state and federal requirements. The NRC regularly conducts generic reviews of numerous technical issues, ranging from seismic design to education and fitness for duty requirements for licensed plant operators. The outcome of reviews that are currently pending, and the ways in which the nuclear generating units in which UI has interests may be affected by these reviews, cannot be determined; and the cost of complying with any new requirements that might result from the reviews cannot be estimated. However, such costs could be substantial. Additional capital expenditures and increased operating costs for nuclear generating units may result from modifications of these facilities or their operating procedures required by the NRC, or from actions taken by other joint owners or companies having entitlements in the units. Some equipment modifications have required and may in the future require shutdowns or deratings of generating units that would not otherwise be necessary and that result in additional costs for replacement power. The amounts of additional capital expenditures, increased operating costs and replacement power costs cannot now be predicted, but they have been and may in the future be substantial. - 23 -
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Public controversy concerning nuclear power could also adversely affect Seabrook Unit 1 and Millstone Unit 3. Proposals to force the premature shutdown of nuclear plants in other New England states have in the past received serious attention, and the licensing of Seabrook Unit 1 was a regional issue. A renewal of the controversy could be expected to increase the costs of operating the nuclear generating units in which UI has interests; and it is possible that one or the other of the units could be shut down prematurely, resulting in increased fuel and/or replacement power costs, earlier funding of costs associated with decommissioning the unit and acceleration of depreciation expense, which could have an adverse impact on the Company's financial condition and/or results of operations. INSURANCE REQUIREMENTS The Price-Anderson Act, currently extended through August 1, 2002, limits public liability resulting from a single incident at a nuclear power plant. The first $200 million of liability coverage is provided by purchasing the maximum amount of commercially available insurance. Additional liability coverage will be provided by an assessment of up to $75.5 million per incident, levied on each of the nuclear units licensed to operate in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs resulting from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5% of $75.5 million, or $3.775 million. The maximum assessment is adjusted at least every five years to reflect the impact of inflation. With respect to each of the three nuclear generating units in which the Company has an interest, the Company will be obligated to pay its ownership and/or leasehold share of any statutory assessment resulting from a nuclear incident at any nuclear generating unit. Based on its interests in these nuclear generating units, the Company estimates its maximum liability would be $23.2 million per incident. However, any assessment would be limited to $3.1 million per incident per year. The NRC requires each nuclear generating unit to obtain property insurance coverage in a minimum amount of $1.06 billion and to establish a system of prioritized use of the insurance proceeds in the event of a nuclear incident. The system requires that the first $1.06 billion of insurance proceeds be used to stabilize the nuclear reactor to prevent any significant risk to public health and safety and then for decontamination and cleanup operations. Only following completion of these tasks would the balance, if any, of the segregated insurance proceeds become available to the unit's owners. For each of the three nuclear generating units in which the Company has an interest, the Company is required to pay its ownership and/or leasehold share of the cost of purchasing such insurance. Although each of these units has purchased $2.75 billion of property insurance coverage, representing the limits of coverage currently available from conventional nuclear insurance pools, the cost of a nuclear incident could exceed available insurance proceeds. Under those circumstances, the nuclear insurance pools that provide this coverage may levy assessments against the insured owner companies if pool losses exceed the accumulated funds available to the pool. The maximum potential assessments against the Company with respect to losses occurring during current policy years are approximately $5.0 million. WASTE DISPOSAL AND DECOMMISSIONING Costs associated with nuclear plant operations include amounts for disposal of nuclear wastes, including spent fuel, and for the ultimate decommissioning of the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department of Energy (DOE) is required to design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel. The Act requires the DOE to provide, beginning in 1998, for the disposal of spent nuclear fuel and high level radioactive waste from commercial nuclear plants through contracts with the owners and generators of such waste; and the DOE has established disposal fees that are being paid to the federal government by electric utilities owning or operating nuclear generating units. In return for payment of the prescribed fees, the federal government was required to take title to and dispose of the utilities' high level wastes and spent nuclear fuel beginning no later than January 1998. However, the DOE has announced that its first high level waste repository will not be in operation earlier than 2010 and possibly not earlier than 2013, notwithstanding the DOE's statutory and contractual responsibility to begin disposal of high-level radioactive waste and spent fuel beginning not later than January 31, 1998. - 24 -
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The DOE also announced that, absent a repository, the DOE had no statutory obligation to begin accepting high level wastes and spent nuclear fuel for disposal by January 31, 1998; and the DOE did not begin accepting such wastes and fuel by the date. Numerous utilities and state governments have obtained a judicial determination that the DOE had and has a statutory and contractual responsibility to take title to and dispose of high level wastes and spent nuclear fuel commencing not later than January 31, 1998, and that the contracts between the DOE and the plant owners and generators of such wastes and fuel will provide a potentially adequate remedy for the latter in the event of a breach of the contracts. The DOE is contesting these judicial declarations; and it is unclear at this time whether the United States Congress will enact legislation to address high level wastes/spent fuel disposal issues. Until the federal government begins receiving such materials, nuclear generating units will need to retain high level wastes and spent nuclear fuel on-site or make other provisions for their storage. Storage facilities for the Connecticut Yankee Unit are deemed adequate, and storage facilities for Millstone Unit 3 are expected to be adequate for the projected life of the unit. Storage facilities for Seabrook Unit 1 are expected to be adequate until at least 2010. Fuel consolidation and compaction technologies are being considered for Seabrook Unit 1 and may provide adequate storage capability for the projected life of the unit. In addition, other licensed technologies, such as dry storage casks, may satisfy spent nuclear fuel storage requirements. Disposal costs for low-level radioactive wastes (LLW) that result from operation or decommissioning of nuclear generating units have increased significantly in recent years and may continue to rise. The cost increases are a function of increased packaging and transportation costs, and higher fees and surcharges imposed by the disposal facilities. Currently, the Chem Nuclear LLW facility at Barnwell, South Carolina, is open to the Connecticut Yankee Unit, Millstone Unit 3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW facility at Clive, Utah, is also open to these generating units for portions of their LLW. All three units have contracts in place for LLW disposal at these disposal facilities. Because access to LLW disposal may be lost at any time, Millstone Unit 3 and Seabrook Unit 1 have storage plans that will allow on-site retention of LLW for at least five years in the event that disposal is interrupted. The Connecticut Yankee Unit, which has been retired from commercial operation, has a similar storage program, although disposal of its LLW will take place in connection with its decommissioning. The Company cannot predict whether or when a LLW disposal site will be designated in Connecticut. The State of New Hampshire has not met deadlines for compliance with the Low-Level Radioactive Waste Policy Act and has stated that the state is unsuitable for a LLW disposal facility. Both Connecticut and New Hampshire are also pursuing other options for out-of-state disposal of LLW. NRC licensing requirements and restrictions are also applicable to the decommissioning of nuclear generating units at the end of their service lives, and the NRC has adopted comprehensive regulations concerning decommissioning planning, timing, funding and environmental reviews. UI and the other owners of the nuclear generating units in which UI has interests estimate decommissioning costs for the units and attempt to recover sufficient amounts through their allowed electric rates, together with earnings on the investment of funds so recovered, to cover expected decommissioning costs. Changes in NRC requirements or technology, as well as inflation, can increase estimated decommissioning costs. New Hampshire has enacted a law requiring the creation of a government-managed fund to finance the decommissioning of nuclear generating units in that state. The New Hampshire Nuclear Decommissioning Financing Committee (NDFC) has established $473 million (in 1998 dollars) as the decommissioning cost estimate for Seabrook Unit 1, of which the Company's share would be approximately $83 million. This estimate assumes the prompt removal and dismantling of the unit at the end of its estimated 36-year energy producing life. Monthly decommissioning payments are being made to the state-managed decommissioning trust fund. UI's share of the decommissioning payments made during 1997 was $1.9 million. UI's share of the fund at December 31, 1997 was approximately $12.4 million. - 25 -
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Connecticut has enacted a law requiring the operators of nuclear generating units to file periodically with the DPUC their plans for financing the decommissioning of the units in that state. The current decommissioning cost estimate for Millstone Unit 3 is $557 million (in 1998 dollars), of which the Company's share would be approximately $21 million. This estimate assumes the prompt removal and dismantling of the unit at the end of its estimated 40-year energy producing life. Monthly decommissioning payments, based on these cost estimates, are being made to a decommissioning trust fund managed by Northeast Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made during 1997 was $487,000. UI's share of the fund at December 31, 1997 was approximately $5.1 million. The decommissioning trust fund for the Connecticut Yankee Unit is also managed by NU. For the Company's 9.5% equity ownership in Connecticut Yankee, decommissioning costs of $2.1 million were funded by UI during 1997, and UI's share of the fund at December 31, 1997 was $24.9 million. The current decommissioning cost estimate for the Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit commencing in 1997, is $456 million, of which UI's share would be $43 million. The Financial Accounting Standards Board (FASB) has issued an exposure draft related to the accounting for the closure and removal costs of long-lived assets, including nuclear plant decommissioning. If the proposed accounting standard were adopted, it may result in higher annual provisions for decommissioning to be recognized earlier in the operating life of nuclear units and an accelerated recognition of the decommissioning obligation. The FASB will be deliberating this issue, and the resulting final pronouncement could be different from that proposed in the exposure draft. Item 3. Legal Proceedings. On November 2, 1993, the Company received "updated" personal property tax bills from the City of New Haven (the City) for the tax year 1991-1992, aggregating $6.6 million, based on an audit by the City's tax assessor. On May 7, 1994, the Company received a "Certificate of Correction....to correct a clerical omission or mistake" from the City's tax assessor relative to the assessed value of the Company's personal property for the tax year 1994-1995, which certificate purports to increase said assessed value by approximately 53% above the tax assessor's valuation at February 28, 1994, generating tax claims of approximately $3.5 million. On March 1, 1995, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1995-1996, which notices purport to increase said assessed value by approximately 48% over the valuation declared by the Company, generating tax claims of approximately $3.5 million. On May 11, 1995, the Company received notices of assessment changes relative to the assessed values of the Company's personal property for the tax years 1992-1993 and 1993-1994, which notices purport to increase said assessed values by approximately 45% and 49%, respectively, over the valuations declared by the Company, generating tax claims of approximately $4.1 million and $3.5 million, respectively. On March 8, 1996, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1996-1997, which notices purport to increase said assessed value by approximately 57% over the valuations declared by the Company and are expected to generate tax claims of approximately $3.8 million. On March 7, 1997, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1997-1998, which notices purport to increase said assessed value by approximately 54% over the valuations declared by the Company and are expected to generate tax claims of approximately $3.7 million. The Company is vigorously contesting each of these actions by the City's tax assessor. In January 1996, the Connecticut Superior Court granted the Company's motion for summary judgment against the City relative to the earliest tax year at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had no statutory authority to revalue personal property listed and valued on the Company's tax list for the tax year 1991-1992. This Superior Court decision, which would also have been applicable to and defeated the assessor's valuation increases for the two subsequent tax years, 1992-1993 and 1993-1994, was appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed the Superior Court's decisions in this and two other companion cases involving other taxpayers, ruling that the tax assessor had a three-year period in which to audit and revalue personal property listed and valued on the Company's tax list for the tax year 1991-1992. It is currently anticipated that all of the pending cases for all of the tax years in dispute will now be scheduled for trial in the Superior Court relative to the Company's claim that the tax assessor's increases in personal property tax assessments for the three earliest years were unlawful for other reasons and relative to the vigorously contested issue, for all of the tax years, as to the reasonableness of the tax assessor's valuation method, both as to amount and methodology. It is the present opinion of the Company that the - 26 -
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ultimate outcome of this dispute will not have a significant impact on the long-term financial position of the Company. The Company would seek permission from the DPUC to recover from its retail customers the expense of any adverse court decision or settlement. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the fiscal year ended December 31, 1997. - 27 -
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EXECUTIVE OFFICERS OF THE COMPANY The names and ages of all executive officers of the Company and all such persons chosen to become executive officers, all positions and offices with the Company held by each such person, and the period during which he or she has served as an officer in the office indicated, are as follows: [Enlarge/Download Table] NAME AGE POSITION EFFECTIVE DATE ---- --- -------- -------------- Richard J. Grossi 62 Chairman of the Board of Directors May 1, 1991 and Chief Executive Officer Robert L. Fiscus 60 Vice Chairman of the Board of Directors and Chief Financial Officer February 23, 1998 Nathaniel D. Woodson 56 President February 23, 1998 James F. Crowe 55 Group Vice President Power Supply Services October 1, 1996 Albert N. Henricksen 56 Group Vice President Support Services October 1, 1996 Anthony J. Vallillo 49 Group Vice President Client Services October 1, 1996 Rita L. Bowlby 59 Vice President-Corporate Affairs February 1, 1993 Stephen F. Goldschmidt 52 Vice President Planning and Information Resources October 1, 1996 E. Jon Majkowski 55 Vice President/President Subsidiaries (URI, PPI & TEI) October 1, 1996 James L. Benjamin 56 Controller January 1, 1981 Kurt D. Mohlman 49 Treasurer and Secretary January 1, 1994 Charles J. Pepe 49 Assistant Treasurer and Assistant Secretary January 1, 1994 There is no family relationship between any director, executive officer, or person nominated or chosen to become a director or executive officer of the Company. All executive officers of the Company hold office during the pleasure of the Company's Board of Directors. Messrs. Grossi, Fiscus, Crowe, Henricksen, Vallillo, Goldschmidt, Benjamin, Mohlman, Pepe and Ms. Bowlby have entered into employment agreements with the Company. There is no arrangement or understanding between any executive officer of the Company and any other person pursuant to which such officer was selected as an officer. A brief account of the business experience during the past five years of each executive officer of the Company is as follows: RICHARD J. GROSSI. Mr. Grossi has served as Chairman of the Board of Directors and Chief Executive Officer during the five-year period. ROBERT L. FISCUS. Mr. Fiscus served as President and Chief Financial Officer during the period January 1, 1993 to February 23, 1998. He has served as Vice Chairman of the Board of Directors and Chief Financial Officer since February 23, 1998. NATHANIEL D. WOODSON. Mr. Woodson served as Vice President and General Manager of the Energy Systems Business Unit of Westinghouse Electric Corporation during the period January 1, 1993 to April 30, 1996. He has served as President of the Company since February 23, 1998. JAMES F. CROWE. Mr. Crowe served as Executive Vice President during the period January 1, 1993 to January 1, 1994, and as Executive Vice President and Chief Customer Officer from January 1, 1994 to October 1, 1996. He has served as Group Vice President Power Supply Services since October 1, 1996. ALBERT N. HENRICKSEN. Mr. Henricksen served as Vice President-Human and Environmental Resources during the period January 1, 1993 to January 1, 1994, and as Vice President-Administration from January 1, 1994 to October 1, 1996. He has served as Group Vice President Support Services since October 1, 1996. - 28 -
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ANTHONY J. VALLILLO. Mr. Vallillo served as Vice President-Marketing during the period January 1, 1993 to October 1, 1996. He has served as Group Vice President Client Services since October 1, 1996. RITA L. BOWLBY. Ms. Bowlby has served as Vice President-Corporate Affairs during the five-year period. STEPHEN F. GOLDSCHMIDT. Mr. Goldschmidt served as Vice President-Planning during the period January 1, 1993 to January 1, 1994, and as Vice President-Information Resources from January 1, 1994 to October 1, 1996. He has served as Vice President Planning and Information Resources since October 1, 1996. E. JON MAJKOWSKI. Mr. Majkowski served as Vice President/President-UI Subsidiaries during the period January 1, 1993 to October 1 1996. He has served as Vice President/President Subsidiaries (URI, PPI & TEI) since October 1, 1996. JAMES L. BENJAMIN. Mr. Benjamin has served as Controller of the Company during the five-year period. KURT D. MOHLMAN. Mr. Mohlman served as Director of Financial Planning and Investor Relations during the period January 1, 1993 to January 1, 1994. He has served as Treasurer and Secretary of the Company since January 1, 1994. CHARLES J. PEPE. Mr. Pepe served as Director of Financing during the period January 1, 1993 to January 1, 1994. He has served as Assistant Treasurer and Assistant Secretary of the Company since January 1, 1994. PART II Item 5. Market for the Company's Common Equity and Related Stockholder Matters. UI's Common Stock is traded on the New York Stock Exchange, where the high and low sale prices during 1997 and 1996 were as follows: 1997 SALE PRICE 1996 SALE PRICE --------------- --------------- HIGH LOW HIGH LOW ---- --- ---- --- First Quarter 32 5/8 24 1/2 39 3/4 36 1/4 Second Quarter 30 7/8 24 1/2 38 35 3/4 Third Quarter 37 31 1/2 37 1/2 33 7/8 Fourth Quarter 45 15/16 37 35 31 3/8 UI has paid quarterly dividends on its Common Stock since 1900. The quarterly dividends declared in 1996 and 1997 were at a rate of 72 cents per share. The indenture under which $200 million principal amount of Notes are issued places limitations on the payment of cash dividends on common stock and on the purchase or redemption of common stock. Retained earnings in the amount of $104.1 million were free from such limitations at December 31, 1997. As of December 31, 1997, there were 16,057 Common Stock shareowners of record. - 29 -
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[Enlarge/Download Table] ITEM 6. SELECTED FINANCIAL DATA 1997 1996 1995 ===================================================================================================================== FINANCIAL RESULTS OF OPERATION ($000'S) Sales of electricity Retail Residential $259,842 $265,562 $260,694 Commercial 248,984 263,609 259,715 Industrial 102,967 108,825 106,963 Other 11,778 11,880 11,736 ------------- -------------- ------------- Total Retail 623,571 649,876 639,108 Wholesale (1) 82,871 72,844 48,232 Other operating revenues 3,825 3,300 3,109 ------------- -------------- ------------- Total operating revenues 710,267 726,020 690,449 ------------- -------------- ------------- Fuel and interchange energy -net Retail -own load 109,542 95,359 96,538 Wholesale 73,124 65,158 41,631 Capacity purchased-net 39,976 46,830 47,420 Depreciation 74,618 (3) 65,921 61,426 Other amortization, principally deferred return and cancelled plant 13,758 13,758 13,758 Other operating expenses, excluding tax expense 200,803 219,630 (5) 183,749 Gross earnings tax 23,618 26,757 27,379 Other non-income taxes 28,922 30,382 31,564 ------------- -------------- ------------- Total operating expenses, excluding income taxes 564,361 563,795 503,465 ------------- -------------- ------------- Deferred return - Seabrook Unit 1 0 0 0 AFUDC 1,575 2,375 2,762 Other non-operating income(loss) 4,186 (7,166) (4,272) Interest expense Long-term debt - net 56,158 65,046 63,431 Other 6,068 4,721 13,140 ------------- -------------- ------------- Total 62,226 69,767 76,571 ------------- -------------- ------------- Minority interest in preferred securities 4,813 4,813 3,583 Income tax expense Operating income tax 41,333 (4) 53,090 59,828 Non-operating income tax (2,496) (9,332) (4,901) ------------- -------------- ------------- Total 38,837 43,758 54,927 ------------- -------------- ------------- Income(loss) before cumulative effect of accounting change 45,791 39,096 50,393 Cumulative effect of change in accounting - net of tax 0 0 0 ------------- -------------- ------------- Net income (loss) 45,791 39,096 (6) 50,393 Discount on preferred stock redemption (48) (1,840) (2,183) Preferred and preference stock dividends 205 330 1,329 ------------- -------------- ------------- Income (loss) applicable to common stock $45,634 $40,606 $51,247 --------------------------------------------------------------------------------------------------------------------- Operating income $104,573 $109,135 $127,156 ===================================================================================================================== FINANCIAL CONDITION ($000'S) Plant in service-net $1,222,174 $1,258,306 $1,277,910 Construction work in progress 25,448 40,998 41,817 Plant-related regulatory asset 0 0 0 Other property and investments 58,441 49,091 53,355 Current assets 165,027 163,350 137,277 Deferred charges and regulatory assets 360,635 449,150 475,258 ------------- -------------- ------------- Total Assets $1,831,725 $1,960,895 $1,985,617 --------------------------------------------------------------------------------------------------------------------- Common stock equity $438,963 $440,016 $439,981 Preferred, preference stock and preferred securities 54,351 54,461 60,539 Long-term debt excluding current portion 644,670 759,680 845,684 Noncurrent liabilities (7) 119,868 138,816 65,747 Current portion of long-term debt 100,000 69,900 40,800 Notes payable 37,751 10,965 0 Other current liabilities (7) 130,993 129,007 102,336 Deferred income tax liabilities and other 305,129 358,050 430,530 ------------- -------------- ------------- Total Capitalization and Liabilities $1,831,725 $1,960,895 $1,985,617 ===================================================================================================================== (1) Operating Revenues, for years prior to 1992, include wholesale power exchange contract sales that were reclassified from Fuel and Capacity expenses in accordance with Federal Energy Regulatory Commission requirements. (2) Includes reclassification of certain Commercial and Industrial customers. (3) Includes the effect of charges of $6.4 million, before-tax, for additional amortization of conservation & load management costs. (4) Includes the effect of credits of $6.7 million, before-tax, to provide tax provision for fossil generation decommissioning. (5) Includes the effect of charges of $23.0 million, before-tax, associated with voluntary early retirement programs. (6) Includes the effect of charges of $13.4 million, after-tax,associated with voluntary early retirement programs. - 30 -
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[Enlarge/Download Table] 1994 1993 1992 1991 1990 1989 1988 ============================================================================================================================ $252,386 $238,185 $226,455 $226,751 $211,891 $205,183 $200,170 250,771 (2) 256,559 253,456 (2) 255,782 234,704 219,852 208,801 104,242 (2) 97,466 97,010 (2) 91,895 94,526 92,855 96,665 11,469 11,349 11,065 10,886 10,536 9,943 9,732 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 618,868 603,559 587,986 585,314 551,657 527,833 515,368 34,927 45,931 75,484 84,236 85,657 77,925 63,263 2,953 3,533 3,855 3,821 3,332 3,348 3,570 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 656,748 653,023 667,325 673,371 640,646 609,106 582,201 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 99,589 98,694 108,084 123,010 119,285 128,739 121,425 27,765 39,356 55,169 61,858 69,117 62,681 53,837 44,769 47,424 43,560 44,668 42,827 50,234 35,465 58,165 56,287 50,706 48,181 36,526 35,618 24,069 1,172 1,780 10,415 10,415 4,173 10,415 10,415 193,098 203,427 (8) 183,426 178,912 176,419 144,867 133,407 27,403 27,955 27,362 27,223 25,595 24,506 23,948 32,458 29,977 31,869 28,673 24,648 20,294 21,695 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 484,419 504,900 510,591 522,940 498,590 477,354 424,261 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 0 7,497 15,959 17,970 21,503 0 0 3,463 4,067 3,232 5,190 3,443 65,443 75,656 (1,907) 71 18,545 2,697 22,654 (219,742) (23,369) 73,772 80,030 88,666 90,296 94,056 91,126 90,022 10,301 12,260 12,882 9,847 15,468 22,849 12,069 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 84,073 92,290 101,548 100,143 109,524 113,975 102,091 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 0 0 0 0 0 0 0 44,937 33,309 48,712 47,231 43,493 37,963 44,045 (3,214) (6,322) (12,558) (19,299) (17,409) (101,135) (14,548) --------------- -------------- -------------- ------------- -------------- -------------- -------------- 41,723 26,987 36,154 27,932 26,084 (63,172) 29,497 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 48,089 40,481 56,768 48,213 54,048 (73,350) 78,639 (1,294) 0 0 7,337 0 0 0 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 46,795 40,481 (9) 56,768 55,550 54,048 (73,350) 78,639 0 0 0 0 0 0 0 3,323 4,318 4,338 4,530 4,751 8,233 11,348 --------------- -------------- -------------- ------------- -------------- -------------- -------------- $43,472 $36,163 $52,430 $51,020 $49,297 ($81,583) $67,291 ---------------------------------------------------------------------------------------------------------------------------- $127,392 $114,814 $108,022 $103,200 $98,563 $93,789 $113,895 ============================================================================================================================ $1,268,145 $1,243,426 $1,224,058 $1,219,871 $1,209,173 $562,473 $560,930 57,669 77,395 59,809 54,771 50,257 675,831 812,246 0 0 0 0 0 81,768 88,339 53,267 58,096 65,320 79,009 90,006 91,648 83,860 157,309 187,981 247,954 164,839 161,066 170,823 166,270 538,601 567,394 556,493 554,365 553,986 605,696 653,418 --------------- -------------- -------------- ------------- -------------- -------------- -------------- $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063 ---------------------------------------------------------------------------------------------------------------------------- $428,028 $423,324 $422,746 $401,771 $379,812 $362,584 $473,674 44,700 60,945 60,945 62,640 69,700 70,000 104,000 708,340 875,268 893,457 909,998 899,993 868,884 862,287 59,458 62,666 44,567 110,217 110,850 117,200 119,165 193,133 143,333 92,833 37,500 41,667 18,667 3,667 67,000 0 84,099 13,000 15,000 45,000 0 122,084 117,343 114,757 114,280 138,173 133,459 115,043 452,248 451,413 440,230 423,449 409,293 572,445 687,227 --------------- -------------- -------------- ------------- -------------- -------------- -------------- $2,074,991 $2,134,292 $2,153,634 $2,072,855 $2,064,488 $2,188,239 $2,365,063 ============================================================================================================================ (7) Amounts for years prior to 1996 were reclassified in 1996. (8) Includes the effect of a reorganization charge of $13.6 million, before-tax, associated with a voluntary early retirement program. (9) Includes the effect of a reorganization charge of $7.8 million, after-tax. - 31 -
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[Enlarge/Download Table] ITEM 6. SELECTED FINANCIAL DATA (CONTINUED) 1997 1996 1995 ===================================================================================================================== COMMON STOCK DATA Average number of shares outstanding 13,975,802 14,100,806 14,089,835 Number of shares outstanding at year-end 13,907,824 14,101,291 14,100,091 Earnings(loss) per share (average) - basic $3.27 $2.88 $3.64 Earnings(loss) per share (average) - diluted $3.26 $2.87 $3.63 Recurring earnings(loss) per share (average) (1) $3.11 $3.94 $3.61 Book value per share $31.56 $31.20 $31.20 Average return on equity Total 10.45% 9.20% 11.84% Utility 11.54% 11.51% 13.04% Dividends declared per share $2.88 $2.88 $2.82 Market Price: High $45.9375 $39.750 $38.500 Low $24.5000 $31.375 $29.500 Year-end $45.9375 $31.375 $37.375 ===================================================================================================================== Net cash provided by operating activities, less dividends ($000's) $127,807 $103,943 $120,033 Capital expenditures, excluding AFUDC $33,436 $47,174 $59,363 ===================================================================================================================== OTHER FINANCIAL AND STATISTICAL DATA Sales by class (MWh's) Residential 1,903,096 1,891,988 1,890,575 Commercial 2,253,488 2,258,501 2,273,965 Industrial 1,170,815 1,141,109 1,126,458 Other 48,717 48,291 48,435 ------------- -------------- ------------- Total 5,376,116 5,339,889 5,339,433 ------------- -------------- ------------- Number of retail customers by class (average) Residential 280,283 279,024 278,326 Commercial 29,228 28,666 28,550 Industrial 1,697 1,652 1,599 Other 1,163 1,141 1,122 ------------- -------------- ------------- Total 312,371 310,483 309,597 ------------- -------------- ------------- Revenue per kilowatt hour by class (cents) Residential 13.65 14.04 13.79 Commercial 11.05 11.67 11.42 Industrial 8.79 9.54 9.50 Average large industrial customers time of use rate (cents) 8.12 8.26 8.53 System requirements (MWh) 5,631,296 5,640,957 5,647,690 Peak load - kilowatts 1,173,160 1,044,620 1,156,740 Generating capability- peak(kilowatts) 1,356,100 1,522,350 1,434,102 Load factor 54.80% 61.64% 55.74% Fuel generation mix percentages Coal 44 38 37 Oil 15 8 7 Nuclear 25 37 37 Cogeneration 9 9 9 Gas 2 3 5 Hydro 5 5 5 --------------------------------------------------------------------------------------------------------------------- Revenues - retail sales ($000's) Base $621,874 $642,106 $637,219 Fuel adjustment clause 1,697 7,770 1,889 Sales provision adjustment 0 0 0 ------------- -------------- ------------- Total $623,571 $649,876 $639,108 ------------- -------------- ------------- Revenues - retail sales per kWh (cents) Base 11.57 12.02 11.93 Fuel adjustment clause 0.03 0.15 0.04 Sales provision adjustment 0.00 0.00 0.00 ------------- -------------- ------------- Total 11.60 12.17 11.97 ------------- -------------- ------------- Fuel and energy cost per kWh (cents) 1.95 1.69 1.71 Fossil 2.39 2.41 2.22 Nuclear 0.61 0.46 0.85 --------------------------------------------------------------------------------------------------------------------- Number of employees at year-end 1,175 1,287 1,358 Total payroll($000'S) $68,640 $69,276 $72,984 ===================================================================================================================== (1) Recurring earnings(loss) per share (average) is not a generally accepted accounting principle measurement. Management provides this measurement for informational purposes only. (2) Includes reclassification of certain Commercial and Industrial customers. - 32 -
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[Enlarge/Download Table] 1994 1993 1992 1991 1990 1989 1988 ============================================================================================================================ 14,085,452 14,063,854 13,941,150 13,899,906 13,887,748 13,887,748 13,887,748 14,086,691 14,083,291 14,033,148 13,932,348 13,887,748 13,887,748 13,887,748 $3.09 $2.57 $3.76 $3.67 $3.55 ($5.87) $4.85 $3.08 $2.56 $3.74 $3.66 $3.55 ($5.87) $4.85 $3.28 $3.13 $3.17 $2.90 $3.55 ($5.87) $4.85 $30.39 $30.06 $30.12 $28.84 $27.35 $26.11 $34.11 10.19% 8.45% 12.67% 13.01% 13.39% -18.88% 14.75% 12.50% 10.97% 14.46% 13.39% 13.97% 20.21% 32.91% $2.76 $2.66 $2.56 $2.44 $2.32 $2.32 $2.32 $39.500 $45.875 $42.000 $39.125 $34.125 $34.250 $27.500 $29.000 $38.500 $34.125 $30.000 $26.875 $24.750 $19.125 $29.500 $40.250 $41.500 $39.000 $31.125 $34.250 $26.875 ============================================================================================================================ $94,807 $104,547 $109,020 $73,865 $39,189 $31,437 $40,607 $63,044 $94,743 $66,390 $63,157 $64,018 $77,041 $83,735 ============================================================================================================================ 1,892,955 1,844,041 1,799,456 1,851,447 1,826,700 1,883,363 1,870,318 2,285,942 (2) 2,359,023 2,303,216 (2) 2,347,757 2,259,340 2,254,099 2,174,200 1,135,831 (2) 1,036,547 997,168 (2) 980,071 1,060,751 1,109,119 1,186,336 48,718 50,715 52,984 55,118 58,013 60,427 61,303 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 5,363,446 5,290,326 5,152,824 5,234,393 5,204,804 5,307,008 5,292,157 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 275,441 273,752 273,936 274,064 275,637 276,385 274,884 28,394 (2) 28,968 28,848 (2) 29,768 29,808 29,526 28,826 1,538 (2) 959 1,017 (2) 268 319 347 367 1,127 1,175 1,358 1,361 1,352 1,316 1,267 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 306,500 304,854 305,159 305,461 307,116 307,574 305,344 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 13.33 12.92 12.58 12.25 11.60 10.89 10.70 10.97 10.88 11.00 10.89 10.39 9.75 9.60 9.18 9.40 9.73 9.38 8.91 8.37 8.15 8.69 8.89 8.84 8.64 8.06 7.58 7.14 5,652,657 5,630,581 5,475,664 5,541,477 5,501,495 5,603,502 5,581,897 1,130,780 1,114,900 1,034,440 1,145,820 1,054,600 1,094,400 1,132,100 1,462,290 1,515,420 1,402,800 1,474,190 1,449,600 1,289,800 1,271,500 57.07% 57.65% 60.26% 55.21% 59.55% 58.45% 56.13% 35 31 34 34 43 39 37 14 16 17 21 24 37 41 32 38 35 29 20 11 11 9 8 8 9 9 9 7 4 1 1 4 3 3 0 6 6 5 3 1 1 4 ---------------------------------------------------------------------------------------------------------------------------- $619,097 $605,887 $608,176 $607,997 $589,346 $577,611 $574,422 (229) (2,328) (41,221) (37,497) (45,900) (49,778) (59,054) 0 0 21,031 14,814 8,211 0 0 --------------- -------------- -------------- ------------- -------------- -------------- -------------- $618,868 $603,559 $587,986 $585,314 $551,657 $527,833 $515,368 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 11.54 11.45 11.80 11.62 11.32 10.88 10.85 0.00 (0.04) (0.80) (0.72) (0.88) (0.93) (1.11) 0.00 0.00 0.41 0.28 0.16 0.00 0.00 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 11.54 11.41 11.41 11.18 10.60 9.95 9.74 --------------- -------------- -------------- ------------- -------------- -------------- -------------- 1.76 1.75 2.43 2.67 2.63 2.78 2.53 2.14 2.08 2.98 3.11 2.89 2.98 2.74 0.94 1.23 1.42 1.62 1.55 0.89 0.87 ---------------------------------------------------------------------------------------------------------------------------- 1,377 1,490 1,554 1,571 1,587 1,627 1,620 $75,441 $75,305 $74,052 $71,888 $69,237 $65,175 $62,387 ============================================================================================================================ - 33 -
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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 retail and wholesale sales and the Company's ability to control expenses. The two primary factors that affect sales volume are economic conditions and weather. Annual growth in total operation and maintenance expense, excluding one-time items and cogeneration capacity purchases, has averaged less than 1.5% during the past 5 years. The Company hopes to continue to restrict this average to less than the rate of inflation in future years (see "Looking Forward"). The Company's financial status and financing capability will continue to be sensitive to many other factors, including conditions in the securities markets, economic conditions, interest rates, the level of the Company's income and cash flow, and legislative and regulatory developments, including the cost of compliance with increasingly stringent environmental legislation and regulations and competition within the electric utility industry. A major factor affecting the Company's earnings prospects will be the success of the Company's efforts to implement the regulatory framework ordered by the DPUC at the end of 1996. On December 31, 1996, the DPUC completed a financial and operational review of the Company and ordered a five-year incentive regulation plan for the years 1997-2001. The DPUC did not change the existing retail base rates charged to customers; but its order increased amortization of the Company's conservation and load management program investments during 1997-1998, and accelerated the recovery of unspecified regulatory assets during 1999-2001 if the Company's common stock equity return on utility investment exceeds 10.5% after recording the increased conservation and load management amortization. The order also reduced the level of conservation adjustment mechanism revenues in retail prices, provided a reduction in customer prices through a surcredit in each of the five plan years, and accepted the Company's proposal to modify the operation of the fossil fuel clause mechanism. The Company's authorized return on utility common stock equity was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are to be utilized one-third for customer price reductions, one-third to increase amortization of regulatory assets, and one-third retained as earnings. As a result of the DPUC's order, customer prices were required to be reduced, on average, by 3% in 1997 compared to 1996. Retail revenues actually decreased by approximately $30 million, or 4.6%, in 1997 due to customer price reductions. Also as a result of the order, customer prices are required to be reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996. By its terms, the DPUC's 1996 order should be reopened in 1998 to determine the regulatory assets to be subjected to accelerated recovery in 1999, 2000 and 2001. Federal legislation has fostered competition in the wholesale electric power market, as has a FERC rulemaking requiring electric utilities to furnish transmission service to all buyers and sellers in the marketplace. In its rulemaking, the FERC stated that state regulatory commissions should address the issue of recovery by electric utilities of the costs of existing facilities that, on account of "retail access", become unrecoverable by the utilities through the regulated rates charged to their service territory customers. The legislatures and regulatory commissions in several states have considered or are considering "retail access". This, in general terms, means the transmission by an electric utility of energy produced by another entity over the utility's transmission and distribution system to a retail customer in the utility's own service territory. A retail access requirement has the effect of permitting retail customers to purchase electric capacity and energy, at the election of such customers, from the electric utility in whose service area they are located or from any other electric utility, independent power producer or power marketer. The costs of existing facilities that become unrecoverable by the service area electric utility on account of the loss of sales to these customers are said to be "stranded costs". In 1995, the Connecticut Legislature established a task force to review these issues and to make recommendations on electric industry restructuring within Connecticut. The task force concluded its work in December 1996 and issued a report and related recommendations. In its 1997 session, the Connecticut legislature drafted, but failed to bring to a - 34 -
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vote, comprehensive legislation that would have introduced retail access in Connecticut over a period of several years, with a provision for the recovery of stranded costs by service area utilities. The legislature is currently considering legislation of this same sort in its 1998 session. Among many other factors, decisions and actions concerning retail access in other states could impact the timing and form of this legislation. Although the Company is unable to predict the future effects of competitive forces in the electric utility industry, competition could result in a change in the regulatory structure of the industry, and costs that have traditionally been recoverable through the ratemaking process may not be recoverable in the future. This effect could have a material impact on the financial condition and/or results of operations of the Company. Currently, the Company's electric service rates are subject to regulation and are based on the Company's costs. Therefore, the Company, and most regulated utilities, are subject to certain accounting standards (Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71)) that are not applicable to other businesses in general. These accounting rules allow regulated utilities, where appropriate, to defer the income statement impact of certain costs that are expected to be recovered in future regulated service rates and to establish regulatory assets on balance sheets for such costs. The effects of competition or a change in the cost-based regulatory structure could cause the operations of the Company, or a portion of its assets or operations, to cease meeting the criteria for application of these accounting rules. While the Company expects to continue to meet these criteria in the foreseeable future, if the Company, or a portion of its assets or operations, were to cease meeting these criteria, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs are not recoverable in that portion of the business that continues to meet the criteria for the application of SFAS No. 71. If this change in accounting were to occur, it would have a material adverse effect on the Company's earnings and retained earnings in that year and could have a material adverse effect on the Company's ongoing financial condition as well. LIQUIDITY AND CAPITAL RESOURCES The Company's capital requirements are presently projected as follows: [Enlarge/Download Table] 1998 1999 2000 2001 2002 ---- ---- ---- ---- ---- (millions) Cash on Hand - Beginning of Year $ 32.0 $10.4 $ - $ - $ - Internally Generated Funds less Dividends 118.5 108.0 109.3 97.0 68.6 ----- ----- ----- ---- ---- Subtotal 150.5 118.4 109.3 97.0 68.6 Less: Capital Expenditures 35.9 32.7 39.6 31.1 30.7 ----- ----- ----- ---- ---- Cash Available to pay Debt Maturities and Redemptions 114.6 85.7 69.7 65.9 37.9 Less: Maturities and Mandatory Redemptions 104.2 103.4 150.4 75.3 0.3 ----- ----- ----- ---- ---- External Financing Requirements (Surplus) $(10.4) $ 17.7 $ 80.7 $ 9.4 $(37.6) ===== ===== ===== ==== ===== Note: Internally Generated Funds less Dividends, Capital Expenditures and External Financing Requirements are estimates based on current earnings and cash flow projections and are subject to change due to future events and conditions that may be substantially different from those used in developing the projections. - 35 -
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All of the Company's capital requirements that exceed available cash will have to be provided by external financing. Although the Company has no commitment to provide such financing from any source of funds, other than a $75 million revolving credit agreement with a group of banks, described below, the Company expects to be able to satisfy its external financing needs by issuing additional short-term and long-term debt, and by issuing preferred stock or common stock, if necessary. The continued availability of these methods of financing will be dependent on many factors, including conditions in the securities markets, economic conditions, and the level of the Company's income and cash flow. On December 30, 1996, the Company transferred $51.3 million to a trustee under an escrow agreement. The funds, which were invested in Treasury Notes, were used to pay $50 million principal amount of 7% Notes that matured on January 15, 1997 plus accrued interest. In February 1997, the Company purchased at a discount on the open market, and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock. The shares, having a par value of $40,300, were purchased for $21,271, creating a net gain of $19,029. On February 15, 1997, the Company repaid $10.8 million principal amount of maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of $185,328, the remaining $21.6 million outstanding principal amount of 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a wholly-owned subsidiary of the Company that was merged with and into the Company in September 1994. On July 30, 1997, the Company borrowed $98.5 million from the Business Finance Authority of the State of New Hampshire (BFA), representing the proceeds from the issuance by the BFA of $98.5 million principal amount of tax-exempt Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated, under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs' bondholders such amounts as will pay, when due, the principal of and the premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and their interest rate is adjusted periodically to reflect prevailing market conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75% at December 31, 1997. The Company has used the proceeds of this $98.5 million borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987 Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990 Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of tax-exempt bonds on which the Company also had a payment obligation to a trustee for the bondholders. Expenses associated with this transaction, including redemption premiums totaling $2,055,000 and other expenses of approximately $1,500,000, were paid by the Company. In August 1997, the Company purchased at a discount on the open market, and canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and 200 shares of its $100 par value 4.64%, Series C preferred stock. These shares, having a par value of $70,000, were purchased for $41,100, creating a net gain of $28,900. On November 12, 1997, the Company refinanced the secured lease obligation bonds that were issued in 1990 in connection with the sale and leaseback by the Company of a portion of its ownership share in Seabrook Unit 1. All of the outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook Lease Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of 10.24% Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were redeemed. The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds were $1,884,549 and $8,589,901, respectively. The Bonds were refunded with the proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds"), the principal of which will be payable from time to time in installments. Transaction expenses totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from the proceeds of the 7.83% Bonds and will be repaid as part of the Company's Lease payments over the remaining term of the Lease. The remainder of the redemption premiums ($2,334,472) and transaction expenses were paid by the Company and will be amortized over the remainder of the Lease term. The transaction reduces the interest rate on the leaseback arrangement, which is treated as long-term debt on the Company's Consolidated Balance Sheet, from 8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76% Bonds and $49,850,000 principal amount of the 10.24% Bonds. - 36 -
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The Company used the proceeds from the redemption of these bonds ($70,662,688, including redemption premiums totaling $3,815,688), plus available funds and short-term borrowings, to purchase $101,388,000 principal amount of the 7.83% Bonds. The Company intends to hold the 7.83% Bonds until maturity and has recognized the investment as an offset to long-term debt on its Consolidated Balance Sheet. On January 13, 1998, the Company issued and sold $100 million principal amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which were issued at a discount, is 6.30%; and the Notes will mature on December 15, 2002. The proceeds from the sale of the Notes were used to repay $100 million principal amount of 7 3/8% Notes, which matured on January 15, 1998. The Company has a revolving credit agreement with a group of banks, which currently extends to December 9, 1998. The borrowing limit of this facility is $75 million. The facility permits the Company to borrow funds at a fluctuating interest rate determined by the prime lending market in New York, and also permits the Company to borrow money for fixed periods of time specified by the Company at fixed interest rates determined by the Eurodollar interbank market in London, or by bidding, at the Company's option. If a material adverse change in the business, operations, affairs, assets or condition, financial or otherwise, or prospects of the Company and its subsidiaries, on a consolidated basis, should occur, the banks may decline to lend additional money to the Company under this revolving credit agreement, although borrowings outstanding at the time of such an occurrence would not then become due and payable. As of December 31, 1997, the Company had $30 million of short-term borrowings outstanding under this facility. In addition, as of December 31, 1997, one of the Company's subsidiaries, American Payment Systems, Inc., had borrowings of $7.8 million outstanding under a bank line of credit agreement. At December 31, 1997, the Company had $32.0 million of cash and temporary cash investments, an increase of $25.6 million from the balance at December 31, 1996. The components of this increase, which are detailed in the Consolidated Statement of Cash Flows, are summarized as follows: (Millions) -------- Balance, December 31, 1996 $ 6.4 ----- Net cash provided by operating activities 168.4 Net cash provided by (used in) financing activities: - Financing activities, excluding dividend payments (34.2) - Dividend payments (40.6) Net cash used in investing activities, excluding investment in plant (34.6) Cash invested in plant, including nuclear fuel (33.4) ---- Net Change in Cash 25.6 ---- Balance, December 31, 1997 $32.0 ==== The Company's long-term debt instruments do not limit the amount of short-term debt that the Company may issue. The Company's revolving credit agreement described above requires it to maintain an available earnings/interest charges ratio of not less than 1.5:1.0 for each 12-month period ending on the last day of each calendar quarter. For the 12-month period ended December 31, 1997 this coverage ratio was 3.23:1.0. SUBSIDIARY OPERATIONS UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that serves as the parent corporation for several unregulated businesses, each of which is incorporated separately to participate in business ventures that will - 37 -
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complement and enhance UI's electric utility business and serve the interests of the Company and its shareholders and customers. URI has four wholly-owned subsidiaries. The largest URI subsidiary, American Payment Systems, Inc., manages a national network of agents for the processing of bill payments made by customers of other utilities. Another subsidiary of URI, Thermal Energies, Inc., is participating in the development of district heating and cooling facilities in the downtown New Haven area, including the energy center for an office tower and participation as a 52% partner in the energy center for a city hall and office tower complex. A third URI subsidiary, Precision Power, Inc., provides power-related equipment and services to the owners of commercial buildings and industrial facilities. URI's fourth subsidiary, United Bridgeport Energy, Inc., is participating in a merchant wholesale electric generating facility being constructed on land leased from UI at its Bridgeport Harbor Station generating plant. The after-tax impact of the subsidiaries on the consolidated financial statements of the Company is as follows: ASSETS NET INCOME (LOSS) EARNINGS AT DEC. 31 (000'S) PER SHARE (000'S) ---------------- --------- ---------- (Basic & Diluted) 1997 $(542) $(0.04) $27,873 1996 (5,237) (0.37) 36,385 1995 (2,640) (0.19) 16,323 In 1996, the Company made provisions for losses of $2.6 million (after-tax) associated with agent collections and miscellaneous other items at its American Payment Systems, Inc. subsidiary. RESULTS OF OPERATIONS 1997 VS. 1996 ------------- Earnings for the year 1997 were $45.6 million, or $3.27 basic earnings per share, up $5.0 million, or $.39 per share, from 1996. Earnings from operations, which exclude one-time items and accelerated amortization of costs attributable to one-time items, decreased by $12.2 million, or $.83 per share, in 1997 compared to 1996. The most significant one-time item recorded in 1997 was a gain from an income tax expense reduction of $6.7 million in the second quarter, or $.48 per share, which makes provision for the cumulative deferred tax benefits associated with the future decommissioning of fossil-fueled generating plants. By order of the Connecticut Department of Public Utility Control (DPUC), the Company was required to accelerate the amortization of regulatory assets by as much as $6.4 million ($4.1 million after-tax), or $.30 per share, provided that the 1997 return on utility common stock equity would exceed 10.5 percent for the year. As a result of the tax benefit, the full $6.4 million was charged in the second quarter of 1997. SEE THE LOOKING FORWARD SECTION FOR MORE INFORMATION ON THE DPUC ORDER. Additional 1997 one-time items include a $.05 per share gain related to subleasing office space, a gain of $2.5 million ($1.5 million after-tax), or $.11 per share, related to forgone benefits associated with the 1996 voluntary retirement and separation programs, and a charge of $4.3 million ($2.5 million after-tax), or $.18 per share, for terminating a consulting contract. The one-time items recorded in 1996, which amounted to a net loss of $1.06 per share were: charges of $23.0 million ($13.4 million after-tax), or $.95 per share, from early retirement and voluntary severance programs, a charge of $1.4 million ($0.8 million after-tax), or $.06 per share, for the cumulative loss on an office space sublease, a charge of $2.6 million (after-tax), or $.18 per share, related to subsidiary operations, and a gain of $1.8 million (after-tax), or $.13 per share, from the repurchase of preferred stock at a discount to par value. Retail operating revenues decreased by about $26.3 million in 1997 compared to 1996: - 38 -
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. Results for 1997 reflect an ADJUSTMENT TO RETAIL KILOWATT-HOUR SALES AND REVENUE, made in the fourth quarter of 1997, to reverse prior period overestimates of transmission losses. The adjustment added 25 million kilowatt-hours, a 0.5 percent increase compared to 1996 kilowatt-hour sales, and $2.7 million of revenues. . An additional retail kilowatt-hour sales increase of 0.2% from the prior year increased retail revenues by $1.6 million and sales margin (revenue less fuel expense and revenue-based taxes) by $1.1 million. The Company believes that weather factors had a negative impact on retail kilowatt-hour sales of about 0.5 percent. There was one less day in 1997 (1996 was a leap year), which decreased retail kilowatt-hour sales by 0.3 percent. This would indicate that "real" (i.e. not attributable to abnormal weather or the leap year day in 1996) kilowatt-hour sales increased by about 1.0-1.5 percent for the year. . Reductions in customer bills, as agreed to by the Company and the DPUC in December 1996, decreased retail revenues by about $23.0 million, including suspension of the fossil fuel adjustment clause (FAC) mechanism that reduced revenues by $6.0 million. This was a somewhat greater decrease than expected, principally because of a decrease in conservation spending. Other reductions in customer bills, due to rate mix, contract pricing and other pass-through reductions, amounted to $7.6 million. Wholesale "capacity" revenues increased $2.1 million in 1997 compared to 1996. Wholesale "energy" revenues, which increased during 1997 compared to 1996 as a result of nuclear generating unit outages in the region, are a direct offset to wholesale energy expense and do not contribute to sales margin. Retail fuel and energy expenses increased by $14.2 million in 1997 compared to 1996. These expenses increased by $12.6 million due to the need for more expensive energy to replace generation by nuclear generating units: for the Connecticut Yankee unit, which ran at nearly full capacity in the first six and one-half months of 1996, for Millstone Unit 3, which ran at nearly full capacity in the first quarter of 1996, for an unplanned eight-day extension of a Seabrook unit refueling outage in the second quarter of 1997 that increased the Company's replacement generation cost by about $0.7 million, and for an unplanned Seabrook unit outage that began on December 5, 1997. The Seabrook unit was returned to service from the last outage on January 17, 1998. Millstone Unit 3 was taken out of service on March 30, 1996 and Connecticut Yankee was taken out of service on July 23, 1996. For more on the status of the Connecticut Yankee and Millstone Unit 3 units, see the LOOKING FORWARD section. Retail fuel and energy expenses also increased by about $1.6 million in 1997 compared to 1996, due to higher fossil fuel prices. By order of the DPUC, these costs are not passed on to customers through the FAC. Operating expenses for operations, maintenance and purchased capacity charges decreased by $1.7 million, excluding the impact of one-time items, in 1997 compared to 1996: . Purchased capacity expense decreased $6.9 million, due to declining costs from the retired Connecticut Yankee nuclear generating unit, and also due to slightly lower cogeneration costs. . Operation and maintenance expense increased by $5.1 million. General, refueling and unscheduled outage expenses at the Seabrook nuclear generating unit increased about $2.9 million, and general expenses at the Millstone 3 nuclear generating unit increased $4.8 million. Expenses associated with the Company's re-engineering efforts increased by a net $1.0 million. Other general expenses increased by about $2.9 million. These increases were partly offset by a $4.6 million reduction in pension expense due to investment performance and changes in actuarial assumptions and methodologies, and health benefit reductions of $1.9 million. The increase at Millstone Unit 3 was partly offset by the reversal of a portion of a 1996 provision in "Other income (deductions)". Depreciation expense, excluding the impact of one-time items, increased by $2.3 million in 1997 compared to 1996. Income taxes, exclusive of the effects of one-time items, changed based on changes in taxable income and tax rates. - 39 -
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Other net income increased by $4.6 million in 1997 compared to 1996 due to an improvement in earnings (reduction in losses) from unregulated subsidiaries. The Company's largest unregulated subsidiary, American Payment Systems, earned about $101,000 ($47,000 after-tax) in 1997, an improvement of $3.8 million ($2.2 million after-tax) over 1996 losses, excluding one-time items, of about $3.7 million ($2.1 million after-tax). Other UI subsidiaries lost $1.0 million ($0.6 million after-tax) compared to a loss of $0.8 million in 1996. The remainder of the improvement in other net income was due to an increase of $0.8 million in interest income. Interest charges continued their significant decline, decreasing by $7.5 million, or 11 percent, in 1997 compared to 1996 as a result of the Company's refinancing program and strong cash flow. Also, total preferred dividends (net-of-tax) decreased slightly in 1997 compared to 1996 as a result of purchases of preferred stock by the Company in 1996. 1996 VS. 1995 ------------- Earnings for the year 1996 were $40.6 million, or $2.88 basic earnings per share, down $10.6 million, or $.76 per share, from 1995. Earnings from operations, which exclude one-time items, were $55.6 million, or $3.94 per share for 1996, up $4.9 million, or $.33 per share, from 1995. The one-time items recorded in 1996, that totaled to a charge of $1.06 per share, were: a gain of $1.8 million (after-tax), or $.13 per share, from the purchase of preferred stock by the Company at a discount to par value, charges of $23.0 million ($13.4 million after-tax), or $.95 per share, reflecting the estimated costs of early retirements and voluntary separations as part of the Company's on-going organization review and cost reduction program, a charge of $1.4 million ($0.8 million after-tax), or $.06 per share, for the cumulative loss on an office space sublease, and a charge of $2.6 million (after-tax), or $.18 per share, that the Company was required to make provisions for losses associated with agent collections and miscellaneous other items at its American Payment Systems, Inc. subsidiary. The one-time items recorded in 1995, that totaled to a gain of $.03 per share, were: a charge of $.12 per share, taken in the third quarter of 1995, to reflect the effects of legislated future state income tax rate reductions that reduced future tax benefits on plant previously written off, and gains of $.15 per share from the purchase of preferred stock by the Company at a discount to par value. Retail operating revenues increased by about $10.8 million in 1996 compared to 1995: . Retail kilowatt-hour sales for 1996 were virtually unchanged from 1995. The Company's calculation of the impact of weather on kilowatt-hour sales indicates that sales decreased by about 1.3% in 1996 compared to 1995 due to weather factors. Weather was deemed to be more severe than normal in 1995, particularly in the summer months, and milder than normal in 1996, particularly in the summer months. Retail kilowatt-hour sales also increased by 0.3% due to the leap year day in 1996. This indicates that there was a "real" (i.e. not attributable to abnormal weather or leap year) kilowatt-hour sales increase of about 1.0% in 1996 compared to 1995. Because sales were lower in the summer months when rates are generally higher, retail revenues decreased by $0.7 million. . Other factors increased retail revenues by $11.5 million: $6.4 million from the recovery, through the Conservation Adjustment Mechanism, of previously recorded and projected conservation program costs mandated by the Department of Public Utility Control (DPUC), partially offset by competitive pricing and other price reduction mechanisms, and a net $5.1 million increase from "pass through" charges for certain expense changes including increases in fuel costs. Wholesale "capacity" revenues increased by $1.1 million in 1996 compared to 1995. Wholesale "energy" revenues are a direct offset to wholesale energy expense and do not contribute to sales margin (revenue less fuel expense and revenue-based taxes). These energy revenues, as well as the associated fuel expense, increased during 1996 compared to 1995. - 40 -
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Retail fuel and energy expenses decreased by $1.2 million in 1996 compared to 1995. A decrease of $9.0 million was due to lower nuclear fuel prices, primarily at the Seabrook nuclear generating unit. Higher kilowatt-hour generation at the Seabrook nuclear generating unit, that had a refueling outage in 1995, reduced fuel and energy expenses by $1.9 million, while lower kilowatt-hour generation, due to the shutdowns at the Connecticut Yankee and Millstone Unit 3 nuclear generating units, increased fuel and energy expense by $5.3 million. For more on the status of the operation of these units, see the LOOKING FORWARD section. Other fuel and energy expenses increased by $4.4 million, primarily from increases in "pass through" charges, including fossil fuel costs. Operating expenses for operations, maintenance and purchased capacity charges increased by $10.9 million in 1996 compared to 1995: . Purchased capacity expense was $0.6 million lower. . Operation and maintenance expense increased by $11.5 million. Expenses associated with the Company's re-engineering efforts increased by a net $2.0 million. Expenses increased by $1.5 million at the Millstone Unit 3 nuclear generating unit, by $4.9 million for overhauls at the Company's fossil fuel generating units, by $1.0 million for a major dredging project at one of the generating stations, by $1.3 million from the expensing of previously capitalized costs associated with software purchases and development, and by $4.0 million in general. Expenses at the Seabrook nuclear generating unit decreased by $3.2 million absent the refueling outage that occurred in the fourth quarter of 1995. Other operating expenses increased in 1996 compared to 1995, from higher depreciation expense and income taxes (excluding the income tax effects of one-time items). Other net income increased in 1996 compared to 1995 primarily because of the absence of expenses, associated with canceled construction projects, which were recorded in 1995. Interest charges continued their significant decline, decreasing by $6.8 million in 1996 compared to 1995 as a result of the Company's refinancing program and strong cash flow. The Company was successful in purchasing $67 million of the approximately $200 million outstanding Seabrook Lease Obligation Bonds, to hold in its own account, using proceeds from a lower cost bank term loan. The interest income that the Company receives from its $67 million investment in these bonds appears on the income statement as a credit to interest expense and partially offsets the interest expense incurred on the Seabrook lease obligation. Also, total preferred dividends (net-of-tax) decreased slightly in 1996 compared to 1995 as a result of the purchases of preferred stock by the Company. LOOKING FORWARD (THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.) Five-year rate plan ------------------- On December 31, 1996, the DPUC issued an order (the Order) that implemented a 5-year regulatory framework that would reduce the Company's retail prices and accelerate the recovery of certain "regulatory" assets beginning with deferred conservation costs. The Order's schedule of price reductions and accelerated amortizations was based on a DPUC pro forma financial analysis that anticipated the Company would be able to implement such changes and earn an allowed return on common stock equity invested in utility assets of 11.5% over the period 1997 to 2001. The Order established a set formula to share any income that would produce a return above the 11.5% level: one-third would be applied to customer bill reductions, one-third would be applied to additional amortization of regulatory assets, and one-third would be retained by shareowners. - 41 -
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It should be noted that, although the Order was for the five-year period 1997-2001 and the Company agreed that it would begin to implement the multi-year plan, it did not agree to commit to the five-year period. In addition, the DPUC, in the Order, acknowledged that the Order could be revisited in the light of any new legislation. The Connecticut legislature did not pass an electric utility restructuring bill in the 1997 legislative session, but such legislation has been reintroduced in 1998. 1998 Earnings ------------- The Company's income from its utility business is greatly affected by: retail sales that fluctuate with weather conditions and economic activity, fossil fuel prices, nuclear generating unit availability and operating costs, and interest rates. These are all items over which the Company has little control, although the Company engages in economic development activities to increase sales, and hedges its exposure to volatile fuel costs and interest rates. The Company's revenues are principally dependent on the level of retail sales. The two primary factors that affect retail sales volume are economic conditions and weather. The Company estimates that mild 1997 weather reduced retail kilowatt-hour sales by about 0.5 percent for the year. Because much of the mild weather occurred in the summer months, when prices are higher than average, the revenue impact was exacerbated. It is estimated that mild weather may have reduced revenues by as much as $5.2 million for the year, and sales margin (revenue less fuel expense and revenue-based taxes) by as much as $4.2 million. Weather corrected retail sales for 1997 were probably in the 5,375-5,420 gigawatt-hour range. On this basis, the Company experienced about 1-1.5 percent of "real" sales growth in 1997 (i.e. exclusive of weather and leap year factors) over "normal" 1996 sales, with almost all of the growth occurring in the last half of the year. A similar level of growth in 1998 compared to 1997 from all customer groups would add about $6-$8 million to sales margin. Reductions in revenues could occur for several reasons. The Company has dealt with the potential loss of customers as a result of self-generation, relocation or discontinuation of operations by successfully negotiating 62 multi-year contracts with major customers. Such a contract has been signed with Yale University, the Company's largest customer, which is constructing a cogeneration unit that will produce approximately one half of its annual electricity requirements (about 1.5 percent of the Company's total 1997 retail sales) commencing sometime in early 1998. While providing cost reduction and price stability for customers and helping the Company maintain its customer base for the long term, these contracts are expected to cause future reductions in retail revenues. They reduced retail revenues by about $3 million in 1997 compared to 1996, but are not expected to approach that level of change in 1998. Additionally, rate migration (customers switching to rates that are more favorable because of usage patterns) reduced retail revenues by about $3 million in 1997 compared to 1996; but the impact of rate migration on revenues in 1998 compared to 1997 is expected to be less than $1 million. Also, as part of the Order, the operation of the Company's long-standing fossil fuel adjustment clause (FAC) mechanism that allowed for recovery in retail rates of changes in fossil fuel costs was suspended within a broad range of fuel prices. FAC revenues will decline by about $2 million in 1998, to zero, compared to 1997, due to this suspension of the FAC. To summarize, assuming 1997 rates of "real" growth and the expected loss of sales due to Yale University cogeneration, little change in retail kilowatt-hour sales is expected in 1998 compared to 1997. Retail revenues should decline by several million dollars or more if the Company is in the "sharing" range above an 11.5% return on common stock equity. The overall average retail price anticipated for 1998 is about 11.6 cents per kilowatt-hour, almost 5 percent below the 1996 peak level. Wholesale capacity prices strengthened in short-term markets during 1997, due to outages of regional nuclear generating plants and changes in the New England Power Pool (NEPOOL) capability responsibility requirements for its participants. Wholesale capacity and transmission sales revenues increased $2.1 million in 1997 compared to 1996. The strength of these markets for 1998 will depend on the timing of the return to service of the nuclear units at Millstone Station, on the addition of new generation sources, and on how the capacity and energy markets perform under the new NEPOOL open competition system, designed to meet Federal Energy Regulatory Commission (FERC) open access orders, when it is implemented. Implementation of this system is currently - 42 -
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expected in mid-1998; but this date is subject to NEPOOL information system development and testing and further orders from the FERC. No significant sales margin improvement is expected from wholesale capacity sales. Wholesale energy revenues should remain similar to wholesale energy expense and not contribute significantly to sales margin. Another major factor affecting the Company's 1998 earnings prospects will be the Company's ability to control operating expenses. The Company offered voluntary early retirement programs and a voluntary severance program to union, nonunion and management employees in 1996. A portion of the resulting personnel cost savings occurred in 1996 and 1997, but the majority of the savings will be realized in 1998. Savings of $6 million from personnel reductions are estimated. The Company is expecting other significant expense declines in 1998 compared to 1997 from a number of sources. From the nuclear generating units, it is expected that operation and maintenance expenses associated with the Seabrook and Connecticut Yankee units should decline by a total of about $9 million. The Seabrook unit should have no refueling outage in 1998 and, if it operates at an assumed 95% availability (it was available virtually 100% between outages in 1997), net fuel expense should decline by about $2 million. Millstone Unit 3 was taken out of service on March 30, 1996, and will remain shut down pending a comprehensive Nuclear Regulatory Commission (NRC) inquiry into the conformity of the unit and its operations with all applicable NRC regulations and standards. The Company anticipates that, once NRC deficiencies are corrected and Unit 3 is returned to service, operating costs should ramp down to more normal levels for an efficient and safe nuclear unit of this class. Also, if Millstone Unit 3 returns to service, net fuel expense should decline by $400,000 per month for every month of operation, net of the replacement fuel provision of about $100,000 per month...up to $3.6 million for the year, if full power is reached by May 1, 1998. Pension and health benefit expenses, excluding one-time items, are expected to decrease by about $2.5 million in 1998 compared to 1997. NEPOOL expenses are expected to increase by about $1.0 million, and information system expenses associated with the "year 2000 issue" are expected to increase by $2.0 million. Other operation and maintenance expenses may increase or decrease by amounts that cannot be predicted at this time. Interest costs are expected to continue to decline by about $10 million in 1998, reaching a level of about $52 million, a level that was last experienced in 1984. This interest cost reduction is largely a result of 1997 debt refinancings and debt paydown (long-term debt was reduced by $85 million in 1997) and an expected 1998 debt paydown of more than $70 million. Other factors should increase costs. Other operation and maintenance expense should increase in 1998, compared to 1997, by about $6 million, reflecting increased fossil-fueled generating unit scheduled maintenance and provisions for future outages. Base depreciation, excluding accelerated amortization, should increase about $2.0 million; and accelerated amortization per the DPUC Order will increase by about $7 million. Other operating expenses will have some increases and some decreases that should more or less offset one another. In summary, the Company expects substantial net expense reductions that should more than compensate for the loss of one-time items realized in 1997, cover the increase in accelerated conservation and load management amortization, and allow utility earnings to increase above an 11.5% return on common stock equity into the "sharing" range of the DPUC Order. The 11.5% return level would produce utility earnings of about $3.40-$3.45 per share, while "shared" earnings should add an additional $.05-$.10 per share. Non-utility earnings should increase by about $.05-$.10 per share in 1998 compared to 1997, primarily from an anticipated improvement in the earnings of American Payment Systems, Inc. The other subsidiaries are expected to break even in 1998. The Company expects that 1998 quarterly earnings from operations will follow a pattern similar to that of 1997 on a weather-normalized basis. Although the current $2.88 indicated annual common stock dividend level for 1997 represented a payout of 88% of total 1997 earnings, the Company's cash flow remains, and is expected to remain, very strong. Net cash - 43 -
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provided by operating activities was $168 million in 1997, over 4 times the common stock dividend payout, one of the highest such "coverage" levels in the utility industry. The DPUC Order will limit earnings from utility operations such that further dividend increases may have to be delayed for several years. However, the Order should allow the Company to recover regulatory assets more rapidly, help it prepare for competition in the electric utility industry, and help maintain cash flow at its excellent current level through the end of the decade. If the Company is able to grow income and earnings in 1998 to the extent indicated above, the common stock dividend payout ratio at the current indicated annual dividend rate would be reduced to approximately 80%. Longer Term ----------- On June 30, 1997, the Company's unionized employees accepted a new five-year agreement, amending and extending the existing agreement that was scheduled to remain in effect through May 15, 1998. The new agreement provides for, among other things, 2% annual wage increases beginning in May 1998, and annual lump sum bonuses of 2.5% of base annual straight time wages (not cumulative). These provisions will restrict the growth of the Company's bargaining unit base wage expense to about $500,000 per year. The agreement also provides for job security for longer-term bargaining unit employees, and will allow the Company some flexibility in adjusting work methods, as part of its ongoing process re-engineering efforts. Connecticut Yankee expenses are expected to continue to decline by substantial amounts before leveling out at about $6 million per year after 1999, compared to $11.8 million in 1997, until decommissioning is complete. However, the ability of the Company to recover its ownership share of future costs associated with the retirement of the Connecticut Yankee unit will be dependent upon the outcome of pending regulatory filings with the Federal Energy Regulatory Commission. On August 7, 1997, the Company and the other nine minority joint owners of Millstone Unit 3 that are not subsidiaries of Northeast Utilities (NU) filed lawsuits against NU and its trustees, as well as a demand for arbitration against The Connecticut Light and Power Company and Western Massachusetts Electric Company, the operating electric utility subsidiaries of NU that are the majority joint owners of the unit and have contracted with the minority joint owners to operate it. The ten non-NU joint owners, who together own about 19.5% of the unit, claim that NU and its subsidiaries failed to comply with NRC regulations, failed to operate Millstone Station in accordance with good utility operating practice and concealed their failures from the non-operating joint owners and the NRC. The arbitration and lawsuits seek to recover costs of purchasing replacement power and increased operation and maintenance costs resulting from the shutdown of Millstone Unit 3. The Company's planning and operations functions, and its cash flow, are dependent on the timely flow of electronic data to and from its customers, suppliers and other electric utility system managers and operators. In order to assure that this data flow will not be disturbed by the problems emanating from the fact that many existing computer programs were designed without considering the impact of the year 2000 and use only two digits to identify the year in the date field of the programs (the Year 2000 Issue), the Company initiated in mid-1997, and is pursuing, an aggressive program to identify and correct all deficiencies in its computer systems and in the computer systems of the critical suppliers and other persons with whom data must be exchanged. A complete inventory and assessment of the Company's computer system applications, hardware, software and embedded technologies has been completed, and recommended solutions to all identified risks and exposures have been generated. A remediation, retirement, renovation and testing program has commenced. Necessary upgrades to mainframe hardware and software are expected to be completed and tested during 1998, and a parallel program with respect to desktop hardware and software is currently projected to be completed and tested by March 31, 1999. Request for documented compliance information have been sent to all critical suppliers, data sharers and facility building owners and, as responses are received, appropriate solutions and testing programs are being developed and executed. The Company believes that the successful implementation of this program, which is currently estimated to cost approximately $2.6 million, will preclude any significant adverse impact of the Year 2000 Issue on its operations and financial condition. - 44 -
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. [Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (THOUSANDS EXCEPT PER SHARE AMOUNTS) 1997 1996 1995 ---- ---- ---- OPERATING REVENUES (NOTE G) $710,267 $726,020 $690,449 ------------- ------------ ------------ OPERATING EXPENSES Operation Fuel and energy 182,666 160,517 138,169 Capacity purchased 39,976 46,830 47,420 Early retirement program charges - 23,033 - Other 158,600 158,945 147,660 Maintenance 42,203 37,652 36,089 Depreciation 74,618 65,921 61,426 Amortization of cancelled nuclear project and deferred return (Note D and J) 13,758 13,758 13,758 Income taxes (Note A and F) 41,333 53,090 59,828 Other taxes (Note G) 52,540 57,139 58,943 ------------- ------------ ------------ Total 605,694 616,885 563,293 ------------- ------------ ------------ OPERATING INCOME 104,573 109,135 127,156 ------------- ------------ ------------ OTHER INCOME AND (DEDUCTIONS) Allowance for equity funds used during construction 336 940 390 Other-net (Note G) 4,186 (7,166) (4,272) Non-operating income taxes 2,496 9,332 4,901 ------------- ------------ ------------ Total 7,018 3,106 1,019 ------------- ------------ ------------ INCOME BEFORE INTEREST CHARGES 111,591 112,241 128,175 ------------- ------------ ------------ INTEREST CHARGES Interest on long-term debt 63,063 66,305 63,431 Interest on Seabrook obligation bonds owned by the company (6,905) (1,259) - Other interest (Note G) 3,280 2,092 9,002 Allowance for borrowed funds used during construction (1,239) (1,435) (2,372) ------------- ------------ ------------ 58,199 65,703 70,061 Amortization of debt expense and redemption premiums 2,788 2,629 4,138 ------------- ------------ ------------ Net Interest Charges 60,987 68,332 74,199 ------------- ------------ ------------ MINORITY INTEREST IN PREFERRED SECURITIES 4,813 4,813 3,583 ------------- ------------ ------------ NET INCOME 45,791 39,096 50,393 Discount on preferred stock redemptions (48) (1,840) (2,183) Dividends on preferred stock 205 330 1,329 ------------- ------------ ------------ INCOME APPLICABLE TO COMMON STOCK $45,634 $40,606 $51,247 ============= ============ ============ AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 13,976 14,101 14,090 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 13,992 14,131 14,108 EARNINGS PER SHARE OF COMMON STOCK - BASIC $3.27 $2.88 $3.64 ============= ============ ============ EARNINGS PER SHARE OF COMMON STOCK - DILUTED $3.26 $2.87 $3.63 ============= ============ ============ CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $2.88 $2.88 $2.82 The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements. - 45 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (THOUSANDS OF DOLLARS) 1997 1996 1995 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $45,791 $39,096 $50,393 ------------ ------------ ------------ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 79,487 70,363 66,958 Deferred income taxes 7,986 (2,276) 27,495 Deferred investment tax credits - net (762) (762) (762) Amortization of nuclear fuel 5,799 5,690 13,571 Allowance for funds used during construction (1,575) (2,375) (2,762) Amortization of deferred return 12,586 12,586 12,586 Early retirement costs accrued - 23,033 - Changes in: Accounts receivable - net 16,944 (23,555) 9,489 Fuel, materials and supplies 2,863 239 69 Prepayments 211 (557) 9,256 Accounts payable 641 22,657 2,555 Interest accrued (3,569) (671) (6,420) Taxes accrued 3,663 (4,794) (11,310) Other assets and liabilities (1,644) 6,078 (9,627) ------------ ------------ ------------ Total Adjustments 122,630 105,656 111,098 ------------ ------------ ------------ NET CASH PROVIDED BY OPERATING ACTIVITIES 168,421 144,752 161,491 ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Common stock (6,432) 40 440 Long-term debt 98,500 82,500 150,000 Preferred securities of subsidiary - - 50,000 Notes payable 26,786 10,965 (67,000) Securities redeemed and retired: Preferred stock (110) (6,078) (34,161) Long-term debt (151,199) (72,895) (165,103) Discount on preferred stock redemption 48 1,840 2,183 Expenses of issues (1,500) (442) (2,222) Lease obligations (315) (291) (1,169) Dividends Preferred stock (206) (410) (1,944) Common stock (40,408) (40,399) (39,514) ------------ ------------ ------------ NET CASH USED IN FINANCING ACTIVITIES (74,836) (25,170) (108,490) ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Plant expenditures, including nuclear fuel (33,436) (47,174) (59,363) Investment in Seabrook obligation bonds (34,541) (71,084) - ------------ ------------ ------------ NET CASH USED IN INVESTING ACTIVITIES (67,977) (118,258) (59,363) ------------ ------------ ------------ CASH AND TEMPORARY CASH INVESTMENTS: NET CHANGE FOR THE PERIOD 25,608 1,324 (6,362) BALANCE AT BEGINNING OF PERIOD 6,394 5,070 11,432 ------------ ------------ ------------ BALANCE AT END OF PERIOD $32,002 $6,394 $5,070 ============ ============ ============ CASH PAID DURING THE PERIOD FOR: Interest (net of amount capitalized) $59,441 $69,669 $76,271 ============ ============ ============ Income taxes $26,773 $51,415 $32,100 ============ ============ ============ The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements. - 46 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEET DECEMBER 31, 1997, 1996 AND 1995 ASSETS (Thousands of Dollars) 1997 1996 1995 ---- ---- ---- Utility Plant at Original Cost In service $1,867,145 $1,843,952 $1,809,925 Less, accumulated provision for depreciation 644,971 585,646 532,015 -------------- -------------- --------------- 1,222,174 1,258,306 1,277,910 Construction work in progress 25,448 40,998 41,817 Nuclear fuel 25,990 23,010 25,967 -------------- -------------- --------------- Net Utility Plant 1,273,612 1,322,314 1,345,694 -------------- -------------- --------------- Other Property and Investments 32,451 26,081 27,388 -------------- -------------- --------------- Current Assets Cash and temporary cash investments 32,002 6,394 5,070 Accounts receivable Customers, less allowance for doubtful accounts of $1,800, $2,300 and $6,300 57,231 63,722 63,987 Other 27,914 38,367 14,547 Accrued utility revenues 25,269 29,139 28,318 Fuel, materials and supplies, at average cost 19,147 22,010 22,249 Prepayments 3,397 3,608 3,051 Other 67 110 55 -------------- -------------- --------------- Total 165,027 163,350 137,277 -------------- -------------- --------------- Deferred Charges Unamortized debt issuance expenses 6,611 6,580 7,577 Other 5,727 1,485 2,377 -------------- -------------- --------------- Total 12,338 8,065 9,954 -------------- -------------- --------------- Regulatory Assets (future amounts due from customers through the ratemaking process) Income taxes due principally to book-tax differences (Note A) 228,992 289,672 358,168 Connecticut Yankee 51,313 64,851 - Deferred return - Seabrook Unit 1 25,171 37,757 50,343 Unamortized redemption costs 23,027 25,063 22,244 Unamortized cancelled nuclear project 12,125 13,297 24,620 Uranium enrichment decommissioning costs 1,312 1,377 1,505 Other 6,357 9,068 8,424 -------------- -------------- --------------- Total 348,297 441,085 465,304 -------------- -------------- --------------- $1,831,725 $1,960,895 $1,985,617 ============== ============== =============== The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements. - 47 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEET December 31, 1997, 1996 and 1995 CAPITALIZATION AND LIABILITIES (Thousands of Dollars) 1997 1996 1995 ---- ---- ---- Capitalization (Note B) Common stock equity Common stock $288,730 $284,579 $284,542 Paid-in capital 1,349 772 769 Capital stock expense (2,182) (2,182) (2,207) Unearned employee stock ownership plan equity (11,160) - - Retained earnings 162,226 156,847 156,877 -------------- -------------- --------------- 438,963 440,016 439,981 Preferred stock 4,351 4,461 10,539 Minority interest in preferred securities 50,000 50,000 50,000 Long-term debt Long-term debt 746,058 826,527 845,684 Investment in Seabrook obligation bonds (101,388) (66,847) - -------------- -------------- --------------- Net long-term debt 644,670 759,680 845,684 Total 1,137,984 1,254,157 1,346,204 -------------- -------------- --------------- Noncurrent Liabilities Connecticut Yankee contract obligation 40,821 54,752 - Pensions accrued (Note H) 39,149 49,205 33,832 Nuclear decommissioning obligation 17,538 12,851 10,317 Obligations under capital leases 16,853 17,193 17,508 Other 5,507 4,815 4,090 -------------- -------------- --------------- Total 119,868 138,816 65,747 -------------- -------------- --------------- Current Liabilities Current portion of long-term debt 100,000 69,900 40,800 Notes payable 37,751 10,965 - Accounts payable 68,699 68,058 45,401 Dividends payable 10,051 10,205 10,072 Taxes accrued 4,166 503 5,297 Interest accrued 10,266 13,835 14,506 Obligations under capital leases 340 315 291 Other accrued liabilities 37,471 36,091 26,769 -------------- -------------- --------------- Total 268,744 209,872 143,136 -------------- -------------- --------------- Customers' Advances for Construction 1,878 1,888 2,655 -------------- -------------- --------------- Regulatory Liabilitie (future amounts owed to customers through the ratemaking process) Accumulated deferred investment tax credits 16,385 17,147 17,909 Other 2,356 1,811 1,990 -------------- -------------- --------------- Total 18,741 18,958 19,899 -------------- -------------- --------------- Deferred Income Taxes (future tax liabilities owed to taxing authorities) 284,510 337,204 407,976 Commitments and Contingencies (Note L) -------------- -------------- --------------- $1,831,725 $1,960,895 $1,985,617 ============== ============== =============== The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements. - 48 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY CONSOLIDATED STATEMENT OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (THOUSANDS OF DOLLARS) 1997 1996 1995 ---- ---- ---- BALANCE, JANUARY 1 $156,847 $156,877 $145,559 Net income 45,791 39,096 50,393 Adjustments associated with repurchase of preferred stock 48 1,815 1,988 ------------- ------------- ------------- Total 202,686 197,788 197,940 ------------- ------------- ------------- Deduct Cash Dividends Declared Preferred stock 205 330 1,329 Common stock 40,255 40,611 39,734 ------------- ------------- ------------- Total 40,460 40,941 41,063 ------------- ------------- ------------- BALANCE, DECEMBER 31 $162,226 $156,847 $156,877 ============= ============= ============= The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements. - 49 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The United Illuminating Company (UI or the Company) is an operating electric public utility company, engaged principally in the production, purchase, transmission, distribution and sale of electricity for residential, commercial and industrial purposes in a service area of about 335 square miles in the southwestern part of the State of Connecticut. The service area, largely urban and suburban in character, includes the principal cities of Bridgeport (population 137,000) and New Haven (population 124,000) and their surrounding areas. Situated in the service area are retail trade and service centers, as well as large and small industries producing a wide variety of products, including helicopters and other transportation equipment, electrical equipment, chemicals and pharmaceuticals. In addition, the Company has created, and owns, unregulated subsidiaries. The Board of Directors of the Company has authorized the investment of a maximum of $27 million in the unregulated subsidiaries, and, at December 31, 1997, $27 million had been invested. A wholly-owned subsidiary, United Resources, Inc., serves as the parent corporation to American Payment Systems, Inc., (APS) which manages a national network of agents for the processing of bill payments made by customers of other utilities. (A) STATEMENT OF ACCOUNTING POLICIES ACCOUNTING RECORDS The accounting records are maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and the Connecticut Department of Public Utility Control (DPUC). USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, United Resources Inc. Intercompany accounts and transactions have been eliminated in consolidation. REGULATORY ACCOUNTING The consolidated financial statements of the Company are in conformity with generally accepted accounting principles and with accounting for regulated electric utilities prescribed by the Federal Energy Regulatory Commission (FERC) and the Connecticut Department of Public Utility Control (DPUC). Generally accepted accounting principles for regulated entities allow the Company to give accounting recognition to the actions of regulatory authorities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". In accordance with SFAS No. 71, the Company has deferred recognition of costs (a regulatory asset) or has recognized obligations (a regulatory liability) if it is probable that such costs will be recovered or obligations relieved in the future through the ratemaking process. In addition to the Regulatory Assets and Liabilities separately identified on the Consolidated Balance Sheet, there are other regulatory assets and liabilities such as conservation and load management costs and certain deferred tax liabilities. The Company also has obligations under long-term power contracts, the recovery of which is subject to regulation. - 50 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The effects of competition could cause the operations of the Company, or a portion of its assets or operations, to cease meeting the criteria for application of these accounting rules. While the Company expects to continue to meet these criteria in the foreseeable future, if the Company, or a portion of its assets or operations, were to cease meeting these criteria, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met. If this change in accounting were to occur, it could have a material adverse effect on the Company's earnings and retained earnings in that year and could have a material adverse effect on the Company's ongoing financial condition as well. See Note (C), Rate-Related Regulatory Proceedings. RECLASSIFICATION OF PREVIOUSLY REPORTED AMOUNTS Certain amounts previously reported have been reclassified to conform with current year presentations. UTILITY PLANT The cost of additions to utility plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The cost of current repairs and minor replacements is charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of and the cost of removal, less salvage, are charged to the accumulated provision for depreciation. The Company's utility plant in service as of December 31, 1997, 1996 and 1995 was comprised as follows: 1997 1996 1995 ---- ---- ---- (000's) Production $1,131,285 $1,124,113 $1,122,001 Transmission 161,288 160,970 158,373 Distribution 401,426 387,825 375,962 General 52,776 47,889 45,924 Future use plant 30,594 32,751 32,762 Other 89,776 90,404 74,903 --------- --------- --------- $1,867,145 $1,843,952 $1,809,925 ========= ========= ========= ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION In accordance with the applicable regulatory systems of accounts, the Company capitalizes AFUDC, which represents the approximate cost of debt and equity capital devoted to plant under construction. In accordance with FERC prescribed accounting, the portion of the allowance applicable to borrowed funds is presented in the Consolidated Statement of Income as a reduction of interest charges, while the portion of the allowance applicable to equity funds is presented as other income. Although the allowance does not represent current cash income, it has historically been recoverable under the ratemaking process over the service lives of the related properties. The Company compounds the allowance applicable to major construction projects semi-annually. Weighted average AFUDC rates in effect for 1997, 1996 and 1995 were 7.5%, 9.0% and 8.0%, respectively. DEPRECIATION Provisions for depreciation on utility plant for book purposes are computed on a straight-line basis, using estimated service lives determined by independent engineers. One-half year's depreciation is taken in the year of addition and disposition of utility plant, except in the case of major operating units on which depreciation commences in the month - 51 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) they are placed in service and ceases in the month they are removed from service. The aggregate annual provisions for depreciation for the years 1997, 1996 and 1995 were equivalent to approximately 3.15%, 3.12% and 3.07%, respectively, of the original cost of depreciable property. INCOME TAXES In accordance with Statement of Financial Accounting Standards (SFAS) No. 109 "Accounting for Income Taxes", the Company has provided deferred taxes for all temporary book-tax differences using the liability method. The liability method requires that deferred tax balances be adjusted to reflect enacted future tax rates that are anticipated to be in effect when the temporary differences reverse. In accordance with generally accepted accounting principles for regulated industries, the Company has established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. For ratemaking purposes, the Company normalizes all investment tax credits (ITC) related to recoverable plant investments except for the ITC related to Seabrook Unit 1, which was taken into income in accordance with provisions of a 1990 DPUC retail rate decision. ACCRUED UTILITY REVENUES The estimated amount of utility revenues (less related expenses and applicable taxes) for service rendered but not billed is accrued at the end of each accounting period. CASH AND TEMPORARY CASH INVESTMENTS For cash flow purposes, the Company considers all highly liquid debt instruments with a maturity of three months or less at the date of purchase to be cash and temporary cash investments. The Company records outstanding checks as accounts payable until the checks have been honored by the banks. The Company is required to maintain an operating deposit with the project disbursing agent related to its 17.5% ownership interest in Seabrook Unit 1. This operating deposit, which is the equivalent to one and one half months of the funding requirement for operating expenses, is restricted for use and amounted to $2.3 million, $3.4 million and $3.9 million, at December 31, 1997, 1996 and 1995, respectively. INVESTMENTS The Company's investment in the Connecticut Yankee Atomic Power Company, a nuclear generating company in which the Company has a 9 1/2% stock interest, is accounted for on an equity basis. This investment amounted to $10.5 million, $10.1 million and $9.6 million at December 31, 1997, 1996 and 1995, respectively, and is included on the Consolidated Balance Sheet in "Other Property and Investments" at December 31, 1995 and as a regulatory asset at December 31, 1997 and 1996. See Note (L), Commitments and Contingencies - Other Commitments and Contingencies - Connecticut Yankee. FOSSIL FUEL COSTS Historically, the amount of fossil fuel costs that cannot be reflected currently in customers' bills pursuant to the fossil fuel adjustment clause in the Company's rates has been deferred at the end of each accounting period. Since adoption of the deferred accounting procedure in 1974, rate decisions by the DPUC and its predecessors have consistently made specific provision for amortization and ratemaking treatment of the Company's existing deferred fossil fuel cost balances. As a result of a December 1996 DPUC decision, the Company has suspended this deferred - 52 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) accounting procedure unless the average fossil fuel oil prices increase or decrease outside a certain bandwidth prescribed in the decision. INTEREST RATE AND FUEL PRICE MANAGEMENT The Company utilizes interest rate and fuel oil price management instruments to manage interest rate and fuel oil price risk. Interest rate swap agreements have been entered into that effectively convert the interest rates on $225 million of variable rate term loan borrowings to fixed rate borrowings. Amounts receivable or payable under these swap agreements are accrued and charged to interest expense. The Company enters into basic fuel oil price management instruments to help minimize fuel oil price risk by fixing the future price for fuel oil used for generation. Amounts receivable or payable under these instruments are recognized in income when realized. As of December 31, 1997, the Company had entered into swap agreements for 1998 for 795,000 barrels of fuel oil at a weighted average price of $16.33 per barrel and had call options for 590,000 barrels of fuel oil at a weighted average price of $18.45 per barrel. RESEARCH AND DEVELOPMENT COSTS Research and development costs, including environmental studies, are capitalized if related to specific construction projects and depreciated over the lives of the related assets. Other research and development costs are charged to expense as incurred. PENSION AND OTHER POSTEMPLOYMENT BENEFITS The Company accounts for normal pension plan costs in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 87, "Employers' Accounting for Pensions", and for supplemental retirement plan costs and supplemental early retirement plan costs in accordance with the provisions of SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". The Company accounts for other postemployment benefits, consisting principally of health and life insurance, under the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", which requires, among other things, that the liability for such benefits be accrued over the employment period that encompasses eligibility to receive such benefits. The annual incremental cost of this accrual has been allowed in retail rates in accordance with a 1992 rate decision of the DPUC. URANIUM ENRICHMENT OBLIGATION Under the Energy Policy Act of 1992 (Energy Act), the Company will be assessed for its proportionate share of the costs of the decontamination and decommissioning of uranium enrichment facilities operated by the Department of Energy. The Energy Act imposes an overall cap of $2.25 billion on the obligation assessed to the nuclear utility industry and limits the annual assessment to $150 million each year over a 15-year period. At December 31, 1997, the Company's unfunded share of the obligation, based on its ownership interest in Seabrook Unit 1 and Millstone Unit 3, was approximately $1.2 million. Effective January 1, 1993, the Company was allowed to recover these assessments in rates as a component of fuel expense. Accordingly, the Company has recognized these costs as a regulatory asset on its Consolidated Balance Sheet. - 53 -
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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 $2,571,000, $2,130,000 and $1,882,000 during 1997, 1996 and 1995 into the decommissioning trust funds for Seabrook Unit 1 and Millstone Unit 3. At December 31, 1997, the Company's shares of the trust fund balances, which included accumulated earnings on the funds, were $12.4 million and $5.1 million for Seabrook Unit 1 and Millstone Unit 3, respectively. These fund balances are included in "Other Property and Investments" and the accrued decommissioning obligation is included in "Noncurrent Liabilities" on the Company's Consolidated Balance Sheet. IMPAIRMENT OF LONG-LIVED ASSETS Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of" requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition. This standard also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining allowable costs. Under this standard, the probability of recovery and the recognition of regulatory assets under the criteria of SFAS No. 71 must be assessed on an ongoing basis. The Company does not have any assets that are impaired under this standard. APS REVENUES AND AGENT COLLECTIONS APS recognized revenue of $31.7 million, $19.2 million and $6.8 million for the years 1997, 1996 and 1995, respectively, based on established fees per payment transaction processed. Cash associated with customer payments are the property of other utilities and have not been reflected in UI's consolidated financial statements. EARNINGS PER SHARE In February 1997, the Financial Accounting Standards Board issued SFAS No. 128, "Earnings per Share". This statement, which is effective for financial statements issued for periods ending after December 15, 1997, including interim periods, establishes simplified standards for computing and presenting earnings per share (EPS). It requires dual presentation of basic and diluted EPS on the face of the income statement for entities with complex capital structures and disclosure of the calculation of each EPS amount. - 54 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share calculations for the years 1997, 1996 and 1995: [Enlarge/Download Table] (In thousands except per share amounts) Income Applicable to Average Number of Common Stock Shares Outstanding Earnings (Numerator) (Denominator) per Share ----------- ------------- --------- 1997 ---- Basic earnings per share $45,634 13,976 $3.27 Effect of dilutive stock options - 16 (.01) ------ ------ ---- Diluted earnings per share $45,634 13,992 $3.26 ====== ====== ==== 1996 ---- Basic earnings per share $40,606 14,101 $2.88 Effect of dilutive stock options - 30 (.01) ------ ------ ---- Diluted earnings per share $40,606 14,131 $2.87 ====== ====== ==== 1995 ---- Basic earnings per share $51,247 14,090 $3.64 Effect of dilutive stock options - 18 (.01) ------ ------ ---- Diluted earnings per share $51,247 14,108 $3.63 ====== ====== ==== STOCK-BASED COMPENSATION The Company accounts for employee stock-based compensation in accordance with Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation". This statement establishes financial accounting and reporting standards for stock-based employee compensation plans, such as stock purchase plans, stock options, restricted stock, and stock appreciation rights. The statement defines the methods of determining the fair value of stock-based compensation and requires the recognition of compensation expense for book purposes. However, the statement allows entities to continue to measure compensation expense in accordance with the prior authoritative literature, APB No. 25, "Accounting for Stock Issued to Employees", but requires that pro forma net income and earnings per share be disclosed for each year for which an income statement is presented as if SFAS No. 123 had been applied. The accounting requirements of this statement are effective for transactions entered into after 1995. However, pro forma disclosures must include the effects of all awards granted after January 1, 1995. As of December 31, 1997, there were no options granted to which this statement would apply. The Company has not elected to adopt the expense recognition provisions of SFAS No. 123. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information". This statement, which is effective for financial statements issued for fiscal years beginning after December 15, 1997, requires entities to disclose specific financial and descriptive information about its reportable operating segments. Reportable operating segments are components of an entity about which separate financial information is available that is regularly used when evaluating segment performance and determining the allocation of resources. The Company currently does not have separate reportable segments to which this standard would apply. - 55 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (B) CAPITALIZATION December 31, --------------------------------------------------------------------------------------- 1997 1996 1995 Shares Shares Shares Outstanding $(000's) Outstanding $(000's) Outstanding $(000's) -------------- ------------ -------------- ------------ -------------- ------------ COMMON STOCK EQUITY Common stock, no par value, at December 31(a) 13,907,824 $288,730 14,101,291 $284,579 14,100,091 $284,542 Shares authorized 1995 30,000,000 1996 30,000,000 1997 30,000,000 Paid-in capital 1,349 772 769 Capital stock expense (2,182) (2,182) (2,207) Unearned employee stock ownership plan equity (11,160) - - Retained earnings (b) 162,226 156,847 156,877 ------------ ------------ ------------ Total common stock equity 438,963 440,016 439,981 ------------ ------------ ------------ PREFERRED AND PREFERENCE STOCK (C) Cumulative preferred stock, $100 par value, shares authorized at December 31, 1995 1,180,394 1996 1,119,612 1997 1,119,612 Preferred stock issues: 4.35% Series A 10,894 11,297 21,247 4.72% Series B 17,158 17,658 30,490 4.64% Series C 12,745 12,945 12,945 5 5/8% Series D 2,712 2,712 40,712 -------------- -------------- -------------- 43,509 4,351 44,612 4,461 105,394 10,539 -------------- ------------ -------------- ------------ -------------- ------------ Cumulative preferred stock, $25 par value: 2,400,000 shares authorized Preferred stock issues - - - - - - Cumulative preference stock, $25 par value: 5,000,000 shares authorized Preference stock issues - - - - - - ------------ ------------ ------------ Total preferred stock not subject to mandatory redemption 4,351 4,461 10,539 ------------ ------------ ------------ MINORITY INTEREST IN PREFERRED SECURITIES (D) 50,000 50,000 50,000 ------------ ------------ ------------ - 56 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) December 31, ------------------------------------------------- 1997 1996 1995 $(000's) $(000's) $(000's) ------------- ------------- -------------- LONG-TERM DEBT (E) First Mortgage Bonds: 9.44%, Series B - $32,400 $43,200 Other Long-term Debt Pollution Control Revenue Bonds: 9 1/2%, 1986 Series, due June 1, 2016 - - 7,500 Variable rate, 1996 Series, due June 26, 2026 7,500 7,500 - 9 3/8%, 1987 Series, due July 1, 2012 - 25,000 25,000 10 3/4%, 1987 Series, due November 1, 2012 - 43,500 43,500 8%, 1989 Series A, due December 1, 2014 25,000 25,000 25,000 5 7/8%, 1993 Series, due October 1, 2033 64,460 64,460 64,460 Solid Waste Disposal Revenue Bonds: Adjustable rate 1990 Series A, due September 1, 2015 - 30,000 30,000 Pollution Control Refunding Revenue Bonds: Variable rate, 1997 Series, due July 30, 2027 98,500 - - Notes: 7.00%, 1992 Series E, due January 15, 1997 - - 50,000 7 3/8%, 1992 Series G, due January 15, 1998 100,000 100,000 100,000 6.20%, 1993 Series H, due January 15, 1999 100,000 100,000 100,000 Term Loans: 6.95%, due August 29, 2000 50,000 50,000 50,000 6.47%, due September 6, 2000 50,000 50,000 50,000 6.4375%, due September 6, 2000 50,000 50,000 50,000 6.675%, due October 25, 2001 25,000 25,000 - 7.005% due October 25, 2001 50,000 50,000 - Obligation under the Seabrook Unit 1 sale/leaseback agreement 225,601 243,660 248,030 ------------- ------------- -------------- 846,061 896,520 886,690 Unamortized debt discount less premium (3) (93) (206) ------------- ------------- -------------- Total long-term debt 846,058 896,427 886,484 Less: Current portion included in Current Liabilities (e) 100,000 69,900 40,800 Investment-Seabrook Lease Obligation Bonds 101,388 66,847 - ------------- ------------- -------------- Total long-term debt included in Capitalization 644,670 759,680 845,684 ------------- ------------- -------------- TOTAL CAPITALIZATION $1,137,984 $1,254,157 $1,346,204 ============= ============= ============== - 57 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (A) COMMON STOCK The Company had 14,236,124 shares of its common stock, no par value, outstanding at December 31, 1997, of which 328,300 shares were unallocated shares held by the Company's Employee Stock Ownership Plan ("ESOP") and not recognized as outstanding for accounting purposes. The Company issued 134,833 shares of common stock in 1997, 1,200 shares of common stock in 1996 and 13,400 shares of common stock in 1995, pursuant to a stock option plan. In 1990, the Company's Board of Directors and the shareowners approved a stock option plan for officers and key employees of the Company. The plan provides for the awarding of options to purchase up to 750,000 shares of the Company's common stock over periods from one to ten years following the dates when the options are granted. The Connecticut Department of Public Utility Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to this plan. The exercise price of each option cannot be less than the market value of the stock on the date of the grant. Options to purchase 17,799 shares of stock at an exercise price of $30 per share, 54,500 shares of stock at an exercise price of $30.75 per share, 4,000 shares of stock at an exercise price of $35.625 per share, 33,799 shares of stock at an exercise price of $39.5625 per share, and 5,000 shares of stock at an exercise price of $42.375 per share have been granted by the Board of Directors and remained outstanding at December 31, 1997. The Company has entered into an arrangement under which it loaned $11.5 million to The United Illuminating Company ESOP. The trustee for the ESOP used the funds to purchase shares of the Company's common stock in open market transactions. The shares will be allocated to employees' ESOP accounts, as the loan is repaid, to cover a portion of the Company's required ESOP contributions. The loan will be repaid by the ESOP over a twelve-year period, using the Company contributions and dividends paid on the unallocated shares of the stock held by the ESOP. As of December 31, 1997, 328,300 shares, with a fair market value of $15.1 million, had been purchased by the ESOP and had not been committed to be released or allocated to ESOP participants. (B) RETAINED EARNINGS RESTRICTION The indenture under which $200 million principal amount of Notes are issued places limitations on the payment of cash dividends on common stock and on the purchase or redemption of common stock. Retained earnings in the amount of $104.1 million were free from such limitations at December 31, 1997. (C) PREFERRED AND PREFERENCE STOCK The par value of each of these issues was credited to the appropriate stock account and expenses related to these issues were charged to capital stock expense. In February 1997, the Company purchased at a discount on the open market, and canceled, 403 shares of its $100 par value 4.35%, Series A preferred stock. The shares, having a par value of $40,300, were purchased for $21,271, creating a net gain of $19,029. In August 1997, the Company purchased at a discount on the open market, and canceled, 500 shares of its $100 par value 4.72%, Series B preferred stock and 200 shares of its $100 par value 4.64%, Series C preferred stock. These shares, having a par value of $70,000, were purchased for $41,100, creating a net gain of $28,900. Shares of preferred stock have preferential dividend and liquidation rights over shares of common stock. Preferred shareholders are not entitled to general voting rights. However, if any preferred dividends are in arrears for six or more - 58 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) quarters, or if certain other events of default occurs, preferred shareholders are entitled to elect a majority of the Board of Directors until all preferred dividend arrears are paid and any event of default is terminated. Preference stock is a form of stock that is junior to preferred stock but senior to common stock. It is not subject to the earnings coverage requirements or minimum capital and surplus requirements governing the issuance of preferred stock. There were no shares of preference stock outstanding at December 31, 1997. (D) PREFERRED CAPITAL SECURITIES United Capital Funding Partnership L.P. ("United Capital") is a special purpose limited partnership in which the Company owns all of the general partner interests. United Capital has $50 million of its monthly income 9 5/8% Preferred Capital Securities, Series A, ("Preferred Capital Securities") outstanding, representing limited partnership interests in United Capital. United Capital loaned the proceeds of the issuance and sale of the Preferred Capital Securities to the Company in return for the Company's 9 5/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025. United Capital and the Company have registered an additional $50 million of Capital Securities and/or Subordinated Debentures for sale to the public from time to time, in one or more series, under the Securities Act of 1933. (E) LONG-TERM DEBT The expenses to issue long-term debt are deferred and amortized over the life of the respective debt issue. On December 30, 1996, the Company transferred $51.3 million to a trustee under an escrow agreement. The funds, which were invested in Treasury Notes, were used to pay $50 million principal amount of 7% Notes that matured on January 15, 1997 plus accrued interest. On February 15, 1997, the Company repaid $10.8 million principal amount of maturing 9.44% First Mortgage Bonds, Series B, and redeemed, at a premium of $185,328, the remaining $21.6 million outstanding principal amount of 9.44% First Mortgage Bonds, Series B, issued by Bridgeport Electric Company, a wholly-owned subsidiary of the Company that was merged with and into the Company in September 1994. On July 30, 1997, the Company borrowed $98.5 million from the Business Finance Authority of the State of New Hampshire (BFA), representing the proceeds from the issuance by the BFA of $98.5 million principal amount of tax-exempt Pollution Control Refunding Revenue Bonds (PCRRBs). The Company is obligated, under its borrowing agreement with the BFA, to pay to a trustee for the PCRRBs' bondholders such amounts as will pay, when due, the principal of and the premium, if any, and interest on the PCRRBs. The PCRRBs will mature in 2027, and their interest rate is adjusted periodically to reflect prevailing market conditions. The PCRRBs' interest rate, which is being adjusted weekly, was 3.75% at December 31, 1997. The Company has used the proceeds of this $98.5 million borrowing to cause the redemption and repayment of $25 million of 9 3/8%, 1987 Series A, Pollution Control Revenue Bonds, $43.5 million of 10 3/4%, 1987 Series B, Pollution Control Revenue Bonds, and $30 million of Adjustable Rate, 1990 Series A, Solid Waste Disposal Revenue Bonds, three outstanding series of tax-exempt bonds on which the Company also had a payment obligation to a trustee for the bondholders. Expenses associated with this transaction, including redemption premiums totaling $2,055,000 and other expenses of approximately $1,500,000, were paid by the Company. On November 12, 1997, the Company refinanced the secured lease obligation bonds that were issued in 1990 in connection with the sale and leaseback by the Company of a portion of its ownership share in Seabrook Unit 1. All - 59 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) of the outstanding $69,593,000 principal amount of 9.76% Series 2006 Seabrook Lease Obligation Bonds (the "9.76% Bonds") and $129,055,000 principal amount of 10.24% Series 2020 Seabrook Lease Obligation Bonds (the "10.24% Bonds") were redeemed. The redemption premiums paid on the 9.76% Bonds and the 10.24% Bonds were $1,884,549 and $8,589,901, respectively. The Bonds were refunded with the proceeds from the issuance of $203,088,000 principal amount of 7.83% Seabrook Lease Obligation Bonds due January 2, 2019 (the "7.83% Bonds") the principal of which will be payable from time to time in installments. Transaction expenses totaling $1,530,022 and redemption premiums totaling $8,139,978 were paid from the proceeds of the 7.83% Bonds and will be repaid as part of the Company's Lease payments over the remaining term of the Lease. The remainder of the redemption premiums ($2,334,472) and transaction expenses were paid by the Company and will be amortized over the remainder of the Lease term. The transaction reduces the interest rate on the leaseback arrangement, which is treated as long-term debt on the Company's Consolidated Balance Sheet, from 8.45% to 7.56%. The Company owned $16,997,000 principal amount of the 9.76% Bonds and $49,850,000 principal amount of the 10.24% Bonds. The Company used the proceeds from the redemption of these bonds ($70,662,688, including redemption premiums totaling $3,815,688), plus available funds and short-term borrowings, to purchase $101,388,000 principal amount of the 7.83% Bonds. The Company intends to hold the 7.83% Bonds until maturity and has recognized the investment as an offset to long-term debt on its Consolidated Balance Sheet. On January 13, 1998, the Company issued and sold $100 million principal amount of 6.25% four-year and eleven month Notes. The yield on the Notes, which were issued at a discount, is 6.30%; and the Notes will mature on December 15, 2002. The proceeds from the sale of the Notes were used to repay $100 million principal amount of 7 3/8% Notes, which matured on January 15, 1998. - 60 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Maturities and mandatory redemptions/repayments are set forth below: [Download Table] 1998 1999 2000 2001 2002 ---- ---- ---- ---- ---- (000's) Maturities $100,000 $100,000 $150,000 $75,000 $ - Mandatory redemptions/repayments (1) 4,194 3,410 430 333 338 ------- ------- ------- ------ --- Maturities, Mandatory and Optional redemptions/repayments $104,194 $103,410 $150,430 $75,333 $338 ======= ======= ======= ====== === (1) Principal component of Seabrook lease obligation, net of principal repayment of Seabrook Lease Obligation Bonds held as an investment. As of December 31, 1997, the Company had $200 million principal amount of Notes for sale to the public from time to time, in one or more series, registered under the Securities Act of 1933. On January 13, 1998, the Company issued and sold $100 million principal amount of these Notes. (C) RATE-RELATED REGULATORY PROCEEDINGS Utilities are entitled by Connecticut law to charge retail rates that are determined by the DPUC to be sufficient to allow them to cover their operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting the public interest. However, a company may earn up to 1% above its DPUC-authorized return on equity for six consecutive months before a mandatory review is required by the DPUC. A Connecticut statute requires the DPUC to review and investigate the financial and operating records of each electric utility company, at intervals of not more than four years, to determine whether the company's rates comply with statutory standards. On December 31, 1996, the DPUC completed a financial and operational review of the Company and ordered a five-year incentive regulation plan for the years 1997-2001. The DPUC did not change the existing retail base rates charged to customers; but its order increased amortization of the Company's conservation and load management program investments during 1997-1998, and accelerated the recovery of unspecified regulatory assets during 1999-2001 if the Company's common stock equity return on utility investment exceeds 10.5% after recording the increased conservation and load management amortization. The order also reduced the level of conservation adjustment mechanism revenues in retail prices, provided a reduction in customer prices through a surcredit in each of the five plan years, and accepted the Company's proposal to modify the operation of the fossil fuel clause mechanism. The Company's authorized return on utility common stock equity was reduced from 12.4% to 11.5%. Earnings above 11.5%, on an annual basis, are to be utilized one-third for customer price reductions, one-third to increase amortization of regulatory assets, and one-third retained as earnings. A reopening of this docket will be requested by the Company in 1998 to determine the regulatory assets to be subjected to accelerated recovery in 1999, 2000 and 2001. In its 1997 session, the Connecticut legislature drafted, but failed to bring to a vote, comprehensive legislation that would have introduced retail access in Connecticut over a period of several years, with a provision for the recovery of stranded costs by service area utilities. The legislature is currently considering legislation of this same sort in its 1998 session. Among many other factors, decisions and actions concerning retail access in other states could impact the timing and form of this legislation. Since January 1971, UI has had a fossil fuel adjustment clause (FCA) in virtually all of its retail rates. As a result of the DPUC Order described above, the Company's FCA has been modified so that the clause will not be implemented - 61 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) unless the monthly average price for fuel oil increases above $28 per barrel or decreases below $10 per barrel for six consecutive months. (D) ACCOUNTING FOR PHASE-IN PLAN The Company phased into rate base its allowable investment in Seabrook Unit 1, amounting to $640 million, during the period January 1, 1990 to January 1, 1994. In conjunction with this phase-in plan, the Company was allowed to record a deferred return on the portion of allowable investment excluded from rate base during the phase-in period. Accordingly, the Company is amortizing the net-of-tax accumulated deferred return of $62.9 million over a five-year period that commenced January 1, 1995. (E) SHORT-TERM CREDIT ARRANGEMENTS The Company has a revolving credit agreement with a group of banks that currently extends to December 9, 1998. The borrowing limit of this facility is $75 million. The facility permits the Company to borrow funds at a fluctuating interest rate determined by the prime lending market in New York, and also permits the Company to borrow money for fixed periods of time specified by the Company at fixed interest rates determined by the Eurodollar interbank market in London, or by bidding, at the Company's option. If a material adverse change in the business, operations, affairs, assets or condition, financial or otherwise, or prospects of the Company and its subsidiaries, on a consolidated basis, should occur, the banks may decline to lend additional money to the Company under this revolving credit agreement, although borrowings outstanding at the time of such an occurrence would not then become due and payable. As of December 31, 1997, the Company had $30 million of short-term borrowings outstanding under this facility. In addition, as of December 31, 1997, one of the Company's subsidiaries, American Payment Systems, Inc., had borrowings of $7.8 million outstanding under a bank line of credit agreement. The Company's long-term debt instruments do not limit the amount of short-term debt that the Company may issue. The Company's revolving credit agreement described above requires it to maintain an available earnings/interest charges ratio of not less than 1.5:1.0 for each 12-month period ending on the last day of each calendar quarter. For the 12-month period ended December 31, 1997, this coverage ratio was 3.23:1.0. - 62 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Information with respect to short-term borrowings under the Company's revolving credit agreement is as follows: [Enlarge/Download Table] 1997 1996 1995 ---- ---- ---- (000's) Maximum aggregate principal amount of short-term borrowings outstanding at any month-end $50,000 $30,000 $195,000 Average aggregate short-term borrowings outstanding during the year* $41,441 $15,380 $117,980 Weighted average interest rate* 5.9% 5.7% 6.5% Principal amounts outstanding at year-end $30,000 $0 $0 Annualized interest rate on principal amounts outstanding at year-end 6.2% N/A N/A *Average short-term borrowings represent the sum of daily borrowings outstanding, weighted for the number of days outstanding and divided by the number of days in the period. The weighted average interest rate is determined by dividing interest expense by the amount of average borrowings. Commitment fees of approximately $114,000, $130,000 and $426,500 paid during 1997, 1996 and 1995, respectively, are excluded from the calculation of the weighted average interest rate. - 63 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (F) INCOME TAXES 1997 1996 1995 ----- ----- ---- Income tax expense consists of: (000's) Income tax provisions: Current Federal $23,940 $35,398 $18,031 State 7,673 11,398 10,163 ----------- ------------ ------------ Total current 31,613 46,796 28,194 ----------- ------------ ------------ Deferred Federal 7,008 616 24,682 State 978 (2,892) 2,813 ----------- ------------ ------------ Total deferred 7,986 (2,276) 27,495 ----------- ------------ ------------ Investment tax credits (762) (762) (762) ----------- ------------ ------------ Total income tax expense $38,837 $43,758 $54,927 =========== ============ ============ Income tax components charged as follows: Operating expenses $41,333 $53,090 $59,828 Other income and deductions - net (2,496) (9,332) (4,901) ----------- ------------ ------------ Total income tax expense $38,837 $43,758 $54,927 =========== ============ ============ The following table details the components of the deferred income taxes: Tax depreciation on unrecoverable plant investment $8,089 $5,745 $8,889 Fossil plants decommissioning reserve (7,286) - - Conservation & load management (5,768) (367) 804 Accelerated depreciation 5,681 5,617 9,410 Pension benefits 4,911 (9,066) (1,460) Seabrook sale/leaseback transaction 2,664 (598) (397) Deferred fossil fuel costs (686) 755 (122) Cancelled nuclear project (467) (4,729) (467) Unit overhaul and replacement power costs 212 (1,491) - Alternative minimum tax - - 11,404 Other - net 636 1,858 (566) ----------- ------------ ------------ Deferred income taxes - net $7,986 ($2,276) $27,495 =========== ============ ============ - 64 -
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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: [Enlarge/Download Table] 1997 1996 1995 ---- ---- ---- Pre-Tax Tax Pre-Tax Tax Pre-Tax Tax ------- --- ------- --- ------- --- (000's) Computed tax at federal statutory rate $29,619 $28,999 $36,862 Increases (reductions) resulting from: Deferred return-Seabrook Unit 1 12,586 4,405 12,586 4,405 12,586 4,405 ITC taken into income (762) (762) (762) (762) (762) (762) Allowance for equity funds used during construction (336) (118) (940) (329) (390) (136) Fossil plant decommissioning reserve (15,591) (5,457) - - - - Book depreciation in excess of non-normalized tax depreciation 23,926 8,374 22,703 7,946 21,586 7,555 State income taxes, net of federal income tax benefits 8,651 5,622 8,506 5,529 12,976 8,434 Other items - net (8,134) (2,846) (5,797) (2,030) (4,090) (1,431) ------ ------ ------ Total income tax expense $38,837 $43,758 $54,927 ====== ====== ====== Book income before income taxes $84,628 $82,854 $105,320 ====== ====== ======= Effective income tax rates 45.9% 52.8% 52.1% ===== ===== ===== At December 31, 1997 the Company had deferred tax liabilities for taxable temporary differences of $400 million and deferred tax assets for deductible temporary differences of $115 million, resulting in a net deferred tax liability of $285 million. Significant components of deferred tax liabilities and assets were as follows: tax liabilities on book/tax plant basis differences and on the cumulative amount of income taxes on temporary differences previously flowed through to ratepayers, $237 million; tax liabilities on normalization of book/tax depreciation timing differences, $122 million and tax assets on the disallowance of plant costs, $47 million. - 65 -
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[Enlarge/Download Table] THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (G) SUPPLEMENTARY INFORMATION 1997 1996 1995 ----- ----- ---- (000'S) OPERATING REVENUES ------------------ Retail $623,571 $649,876 $639,108 Wholesale - capacity 9,747 7,686 6,601 - energy 73,124 65,158 41,631 Other 3,825 3,300 3,109 ------------- ------------- -------------- Total Operating Revenues $710,267 $726,020 $690,449 ============= ============= ============== SALES BY CLASS(MWH'S) - UNAUDITED --------------------------------- Retail Residential 1,903,096 1,891,988 1,890,575 Commercial 2,253,488 2,258,501 2,273,965 Industrial 1,170,815 1,141,109 1,126,458 Other 48,717 48,291 48,435 ------------- ------------- -------------- 5,376,116 5,339,889 5,339,433 Wholesale 2,700,393 2,260,423 1,708,837 ------------- ------------- -------------- Total Sales by Class 8,076,509 7,600,312 7,048,270 ============= ============= ============== OTHER TAXES ----------- Charged to: Operating: State gross earnings $23,618 $26,757 $27,379 Local real estate and personal property 22,974 24,854 25,761 Payroll taxes 5,948 5,528 5,800 Other - - 3 ------------- ------------- -------------- 52,540 57,139 58,943 Nonoperating and other accounts 459 628 527 ------------- ------------- -------------- Total Other Taxes $52,999 $57,767 $59,470 ============= ============= ============== OTHER INCOME AND (DEDUCTIONS) - NET ----------------------------------- Interest income $2,317 $1,505 $2,624 Equity earnings from Connecticut Yankee 1,343 1,225 1,440 Loss from subsidiary companies (814) (8,422) (4,898) Engineering study costs - - (849) Miscellaneous other income and (deductions) - net 1,340 (1,474) (2,589) ------------- ------------- -------------- Total Other Income and (Deductions) - net $4,186 ($7,166) ($4,272) ============= ============= ============== OTHER INTEREST CHARGES ---------------------- Notes Payable $2,462 $882 $7,660 Other 818 1,210 1,342 ------------- ------------- -------------- Total Other Interest Charges $3,280 $2,092 $9,002 ============= ============= ============== - 66 -
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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 1997, 1996 and 1995 were ($4,626,000), $18,403,000 and $3,842,000, respectively. The Company's funding policy for the qualified plan is to make annual contributions that satisfy the minimum funding requirements of ERISA but that do not exceed the maximum deductible limits of the Internal Revenue Code. These amounts are determined each year as a result of an actuarial valuation of the plan. In accordance with this policy, no pension fund contributions were made in 1995. In 1996, the Company contributed $2.8 million for 1995 funding requirements. In 1997, the Company contributed $2.7 million for 1996 funding requirements and $2.5 million for 1997 funding requirements. During 1996, the Company established a supplemental retirement benefit trust and through this trust purchased life insurance policies on the officers of the Company to fund the future liability under the supplemental plan. The cash surrender value of these policies is shown as an investment on the Company's Consolidated Balance Sheet. The qualified plan's irrevocable trust fund consists principally of equity and fixed-income securities and real estate investments in approximately the following percentages at December 31, 1997: PERCENTAGE OF ASSET CATEGORY TOTAL FUND -------------- ------------- Equity Securities 72.8% Fixed-income Securities 24.2% Real Estate 3.0% 1997 1996 ---- ---- (000's) The components of net pension costs were as follows: Service cost of benefits earned during the period $ 3,791 $ 4,456 Interest cost on projected benefit obligation 17,565 15,882 Actual return on plan assets (43,225) (24,167) Net amortization and deferral 19,967 6,336 ------ ------ Net pension cost $ (1,902)** $ 2,507* ===== ====== * In addition, a cost of $15,896,000 was recognized under SFAS No. 88 as a result of special termination benefits provided under the Pension Plan. ** In addition, a credit of $2,724,000 was recognized under SFAS No. 88 as a curtailment gain resulting from a 1996 voluntary early retirement program. Assumptions used to determine pension costs were: Discount rate 7.75% 7.25% Average wage increase 4.50% 4.50% Return on plan assets 11.00% 9.00% - 67 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) [Enlarge/Download Table] DECEMBER 31, 1997 DECEMBER 31, 1996 ----------------- ----------------- QUALIFIED NON-QUALIFIED QUALIFIED NON-QUALIFIED PLAN PLANS PLAN PLANS ---- ----- ---- ----- (000's) The funded status and amounts recognized in the balance sheet are as follows: Actuarial present value of benefit obligations: Vested benefit obligation $184,055 $4,716 $165,919 $4,512 ======= ===== ======= ===== Accumulated benefit obligation $192,556 $4,720 $174,253 $4,512 ======= ===== ======= ===== Reconciliation of accrued pension liability: Projected benefit obligation $254,192 $5,353 $227,631 $5,152 Less fair value of plan assets (243,739) - 208,863 - ------- ----- ------- ----- Projected benefit greater than plan assets 10,453 5,353 18,768 5,152 Unrecognized prior service cost (4,217) (68) (5,078) (81) Unrecognized net gain (loss) from past experience 19,272 (13) 21,038 (28) Unrecognized net asset (obligation) at date of initial application 8,446 (77) 9,554 (120) ------- ----- ------- ----- Accrued pension liability $ 33,954 $5,195 $ 44,282 $4,923 ======= ===== ======= ===== Assumptions used in estimating benefit obligations: Discount rate 7.25% 7.25% 7.75% 7.75% Average wage increase 4.50% 4.50% 4.50% 4.50% In addition to providing pension benefits, the Company also provides other postretirement benefits (OPEB), consisting principally of health care and life insurance benefits, for retired employees and their dependents. Employees with 25 years of service are eligible for full benefits, while employees with less than 25 years of service but greater than 15 years of service are entitled to partial benefits. Years of service prior to age 35 are not included in determining the number of years of service. For funding purposes, the Company established a Voluntary Employees' Benefit Association Trust (VEBA) to fund OPEB for union employees who retire on or after January 1, 1994. Approximately 46% of the Company's employees are represented by Local 470-1, Utility Workers Union of America, AFL-CIO, for collective bargaining purposes. The Company established a 401(h) account in connection with the qualified pension plan to fund OPEB for non-union employees who retire on or after January 1, 1994. The funding policy assumes contributions to these trust funds to be the total OPEB expense calculated under SFAS No. 106, adjusted to reflect a share of amounts expensed as a result of voluntary early retirement programs minus pay-as-you-go benefit payments for pre-January 1, 1994 retirees, allocated in a manner that minimizes current income tax liability, without exceeding maximum tax deductible limits. In accordance with this policy, the Company contributed approximately $3.1 million, $3.8 million and $0 to the union VEBA in 1995, 1996 and 1997, respectively. The Company contributed $0, $0.9 million and $1.7 million to the 401(h) account in 1995, 1996 and 1997, respectively. Plan assets for both the union VEBA and 401(h) account consist primarily of equity and fixed-income securities. - 68 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The components of the net cost of OPEB were as follows: 1997 1996 ---- ---- (000's) Service cost $ 925 $1,379 Interest cost 2,434 2,524 Actual return on plan assets (3,836) (1,838) Amortizations and deferrals - net 3,527 2,359 ----- ----- Net Cost of Postretirement Benefit $3,050** $4,424* ===== ===== * In addition, a cost of $4,126,000 was recognized as a result of special termination programs. ** Includes a credit of $186,000 recognized under SFAS No. 88 as a curtailment gain resulting from a 1996 voluntary early retirement program. Assumptions used to determine OPEB costs were: Discount rate 7.75% 7.25% Health Care Cost Trend Rate 5.50% 5.50% Return on plan assets 11.00% 8.50% A one percentage point increase in the assumed health care cost trend rate would have increased the aggregate service cost and interest cost components of the 1997 net cost of periodic postretirement benefit by approximately $400,000 and would increase the accumulated postretirement benefit obligation for health care benefits by approximately $3,000,000. The following table reconciles the funded status of the plan with the amount recognized in the Consolidated Balance Sheet as of December 31, 1997 and 1996: 1997 1996 ---- ---- (000's) Accumulated Postretirement Benefit Obligation: Retirees and dependents $22,847 $22,614 Fully eligible active plan participants 299 929 Other active plan participants 11,966 12,677 ------ ------ Total Accumulated Postretirement Benefit Obligation 35,112 36,220 Plan assets at fair value 21,168 16,720 ------ ------ Accumulated Postretirement Benefit Obligation in Excess of Plan Assets 13,944 19,500 Unrecognized net gain (loss) 6,380 2,731 Unamortized transition obligation (17,537) (19,443) ------ ------ Accrued Postretirement Benefit Obligation $ 2,787 $ 2,788 ====== ====== The weighted average discount rates used to measure the accumulated postretirement benefit obligation at December 31, 1997 and 1996 were 7.25% and 7.75%, respectively. The Company has an Employee Savings Plan (401(k) Plan) in which substantially all employees are eligible to participate. The 401(k) Plan enables employees to defer receipt of up to 15% of their compensation and to invest such - 69 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) funds in a number of investment alternatives. The Company makes matching contributions in the form of Company common stock for each employee. During 1995 and the first five months of 1996, the matching contributions were made into the 401(k) Plan. Beginning in June 1996, the matching contributions were made into the Employee Stock Ownership Plan (ESOP). The Company's matching contributions to the 401(k) Plan during 1995 and the first five months of 1996 were $1.6 million and $0.8 million, respectively. In June 1996, all shares of the Company's common stock in the 401(k) Plan were transferred to the ESOP. The Company has an ESOP for substantially all its employees. In June 1996, the Company began making matching contributions to the ESOP based on each employee's salary deferrals in the 401(k) Plan. The matching contribution currently equals fifty cents for each dollar of the employee's compensation deferred, but is not more than three and three-eighths percent of the employee's annual salary. The Company's matching contributions to the ESOP during the period June 1996 - December 1996 and the year 1997 were $0.8 million and $1.7 million, respectively. The Company pays dividends on the shares of stock in the ESOP to the participant and the Company receives a tax deduction on the dividends paid. The participant is given the option of reinvesting the dividends into the ESOP, as an after-tax contribution. The Company also makes an annual contribution to the ESOP equal to 25% of the dividends paid to each participant. The Company's annual contributions during 1997, 1996 and 1995 were $417,000, $324,000 and $192,000, respectively. (I) JOINTLY OWNED PLANT At December 31, 1997, the Company had the following interests in jointly owned plants: OWNERSHIP/ LEASEHOLD PLANT IN ACCUMULATED SHARE SERVICE DEPRECIATION --------- -------- ------------ (Millions) Seabrook Unit 1 17.5 % $650 $131 Millstone Unit 3 3.685 135 59 New Haven Harbor Station 93.7 143 74 The Company's share of the operating costs of jointly owned plants is included in the appropriate expense captions in the Consolidated Statement of Income. (J) UNAMORTIZED CANCELLED NUCLEAR PROJECT From December 1984 through December 1992, the Company had been recovering its investment in Seabrook Unit 2, a partially constructed nuclear generating unit that was cancelled in 1984, over a regulatory approved ten-year period without a return on its unamortized investment. In the Company's 1992 rate decision, the DPUC adopted a proposal by the Company to write off its remaining investment in Seabrook Unit 2, beginning January 1, 1993, over a 24-year period, corresponding with the flowback of certain Connecticut Corporation Business Tax (CCBT) credits. Such decision will allow the Company to retain the Seabrook Unit 2/CCBT amounts for ratemaking purposes, with the accumulated CCBT credits not deducted from rate base during the 24-year period of amortization in recognition of a longer period of time for amortization of the Seabrook Unit 2 balance. As a result of reducing its remaining unamortized investment in Seabrook Unit 2 with proceeds from the sale of certain Seabrook Unit 2 equipment, the Company expects to completely amortize its unamortized investment in the year 2008. - 70 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS The Company has a Fossil Fuel Supply Agreement with a financial institution providing for financing up to $37.5 million of fossil fuel purchases. Under this agreement, the financing entity may acquire and/or store natural gas, coal and fuel oil for sale to the Company, and the Company may purchase these fossil fuels from the financing entity at a price for each type of fuel that reimburses the financing entity for the direct costs it has incurred in purchasing and storing the fuel, plus a charge for maintaining an inventory of the fuel determined by reference to the fluctuating interest rate on thirty-day, dealer-placed commercial paper in New York. The Company is obligated to insure the fuel inventories and to indemnify the financing entity against all liabilities, taxes and other expenses incurred as a result of its ownership, storage and sale of fossil fuel to the Company. This agreement currently extends to March 1999. At December 31, 1997, approximately $28.1 million of fossil fuel purchases were being financed under this agreement. The Company also has lease arrangements for data processing equipment, office equipment, vehicles and office space, including the lease of a distribution service facility, which is recognized as a capital lease. The gross amount of assets recorded under capital leases and the related obligations of those leases as of December 31, 1997 are recorded on the balance sheet. Future minimum lease payments under capital leases, excluding the Seabrook sale/leaseback transaction, which is being treated as a long-term financing, are estimated to be as follows: (000's) 1998 $ 1,715 1999 1,696 2000 1,696 2001 1,696 2002 1,696 After 2002 17,695 ------ Total minimum capital lease payments 26,194 Less: Amount representing interest 9,001 ------ Present value of minimum capital lease payments $17,193 ====== Capitalization of leases has no impact on income, since the sum of the amortization of a leased asset and the interest on the lease obligation equals the rental expense allowed for ratemaking purposes. Operating leases, which are charged to operating expense, consist principally of a large number of small, relatively short-term, renewable agreements for a wide variety of equipment. In addition, the Company has an operating lease for its corporate headquarters. Future minimum lease payments under this lease are estimated to be as follows: (000's) 1998 $ 6,125 1999 6,426 2000 6,524 2001 6,837 2002 8,168 2003-2012 100,334 ------- Total $134,414 ======= - 71 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Rental payments charged to operating expenses in 1997, 1996 and 1995, including rental payments for its corporate headquarters, were $12.2 million, $12.8 million and $11.5 million, respectively. (L) COMMITMENTS AND CONTINGENCIES CAPITAL EXPENDITURE PROGRAM The Company's continuing capital expenditure program is presently estimated at approximately $170.0 million, excluding AFUDC, for 1998 through 2002. NUCLEAR INSURANCE CONTINGENCIES The Price-Anderson Act, currently extended through August 1, 2002, limits public liability resulting from a single incident at a nuclear power plant. The first $200 million of liability coverage is provided by purchasing the maximum amount of commercially available insurance. Additional liability coverage will be provided by an assessment of up to $75.5 million per incident, levied on each of the nuclear units licensed to operate in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs resulting from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5% of $75.5 million, or $3.775 million. The maximum assessment is adjusted at least every five years to reflect the impact of inflation. With respect to each of the three nuclear generating units in which the Company has an interest, the Company will be obligated to pay its ownership and/or leasehold share of any statutory assessment resulting from a nuclear incident at any nuclear generating unit. Based on its interests in these nuclear generating units, the Company estimates its maximum liability would be $23.2 million per incident. However, any assessment would be limited to $3.1 million per incident per year. The NRC requires each nuclear generating unit to obtain property insurance coverage in a minimum amount of $1.06 billion and to establish a system of prioritized use of the insurance proceeds in the event of a nuclear incident. The system requires that the first $1.06 billion of insurance proceeds be used to stabilize the nuclear reactor to prevent any significant risk to public health and safety and then for decontamination and cleanup operations. Only following completion of these tasks would the balance, if any, of the segregated insurance proceeds become available to the unit's owners. For each of the three nuclear generating units in which the Company has an interest, the Company is required to pay its ownership and/or leasehold share of the cost of purchasing such insurance. Although each of these units has purchased $2.75 billion of property insurance coverage, representing the limits of coverage currently available from conventional nuclear insurance pools, the cost of a nuclear incident could exceed available insurance proceeds. Under those circumstances, the nuclear insurance pools that provide this coverage may levy assessments against the insured owner companies if pool losses exceed the accumulated funds available to the pool. The maximum potential assessments against the Company with respect to losses occurring during current policy years are approximately $5.0 million. OTHER COMMITMENTS AND CONTINGENCIES CONNECTICUT YANKEE On December 4, 1996, the Board of Directors of the Connecticut Yankee Atomic Power Company (Connecticut Yankee) voted unanimously to retire the Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial operation. The Company has a 9.5% stock ownership share in Connecticut Yankee and had relied on the Connecticut Yankee Unit for approximately 3.7% of the Company's 1995 total generating resources. The power purchase contract under which the Company has purchased its 9.5% entitlement to the Connecticut Yankee Unit's power output permits Connecticut Yankee to recover 9.5% of all of its costs from UI. Connecticut Yankee has filed - 72 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) revised decommissioning cost estimates and amendments to the power contracts with its owners with the Federal Energy Regulatory Commission (FERC). The estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in the Connecticut Yankee Unit is approximately $606 million at December 31, 1997. Based on regulatory precedent, Connecticut Yankee believes it will continue to collect from its owners its decommissioning costs, the unrecovered investment in the Connecticut Yankee Unit and other costs associated with the permanent shutdown of the Connecticut Yankee Unit. UI expects that it will continue to be allowed to recover all FERC-approved costs from its customers through retail rates. The Company's estimate of its remaining share of costs, including decommissioning, less return of investment (approximately $10.5 million) and return on investment (approximately $6.3 million) at December 31, 1997, is approximately $40.8 million. This estimate, which is subject to ongoing review and revision, has been recorded by the Company as a regulatory asset and an obligation on the Consolidated Balance Sheet. HYDRO-QUEBEC The Company is a participant in the Hydro-Quebec transmission intertie facility linking New England and Quebec, Canada. Phase I of this facility, which became operational in 1986 and in which the Company has a 5.75% participating share, has a 690 megawatt equivalent capacity value; and Phase II, in which the Company has a 5.45% participating share, increased the equivalent capacity value of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A ten-year Firm Energy Contract, which provides for the sale of 7 million megawatt-hours per year by Hydro-Quebec to the New England participants in the Phase II facility, became effective on July 1, 1991. Additionally, the Company is obligated to furnish a guarantee for its participating share of the debt financing for the Phase II facility. As of December 31, 1997, the Company's guarantee liability for this debt was approximately $7.4 million. PROPERTY TAXES On November 2, 1993, the Company received "updated" personal property tax bills from the City of New Haven (the City) for the tax year 1991-1992, aggregating $6.6 million, based on an audit by the City's tax assessor. On May 7, 1994, the Company received a "Certificate of Correction....to correct a clerical omission or mistake" from the City's tax assessor relative to the assessed value of the Company's personal property for the tax year 1994-1995, which certificate purports to increase said assessed value by approximately 53% above the tax assessor's valuation at February 28, 1994, generating tax claims of approximately $3.5 million. On March 1, 1995, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1995-1996, which notices purport to increase said assessed value by approximately 48% over the valuation declared by the Company, generating tax claims of approximately $3.5 million. On May 11, 1995, the Company received notices of assessment changes relative to the assessed values of the Company's personal property for the tax years 1992-1993 and 1993-1994, which notices purport to increase said assessed values by approximately 45% and 49%, respectively, over the valuations declared by the Company, generating tax claims of approximately $4.1 million and $3.5 million, respectively. On March 8, 1996, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1996-1997, which notices purport to increase said assessed value by approximately 57% over the valuations declared by the Company and are expected to generate tax claims of approximately $3.8 million. On March 7, 1997, the Company received notices of assessment changes relative to the assessed value of the Company's personal property for the tax year 1997-1998, which notices purport to increase said assessed value by approximately 54% over the valuations declared by the Company and are expected to generate tax claims of approximately $3.7 million. The Company is vigorously contesting each of these actions by the City's tax assessor. In January 1996, the Connecticut Superior Court granted the Company's motion for summary judgment against the City relative to the earliest tax year at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had no statutory authority to revalue personal property listed and valued on the Company's tax list for the tax year 1991-1992. This Superior Court decision, which would also have been applicable to and defeated the assessor's valuation increases for - 73 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) the two subsequent tax years, 1992-1993 and 1993-1994, was appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed the Superior Court's decisions in this and two other companion cases involving other taxpayers, ruling that the tax assessor had a three-year period in which to audit and revalue personal property listed and valued on the Company's tax list for the tax year 1991-1992. It is currently anticipated that all of the pending cases for all of the tax years in dispute will now be scheduled for trial in the Superior Court relative to the Company's claim that the tax assessor's increases in personal property tax assessments for the three earliest years were unlawful for other reasons and relative to the vigorously contested issue, for all of the tax years, as to the reasonableness of the tax assessor's valuation method, both as to amount and methodology. It is the present opinion of the Company that the ultimate outcome of this dispute will not have a significant impact on the long-term financial position of the Company. The Company would seek permission from the DPUC to recover from its retail customers the expense of any adverse court decision or settlement. ENVIRONMENTAL CONCERNS In complying with existing environmental statutes and regulations and further developments in areas of environmental concern, including legislation and studies in the fields of water and air quality (particularly "air toxics" and "global warming"), hazardous waste handling and disposal, toxic substances, and electric and magnetic fields, the Company may incur substantial capital expenditures for equipment modifications and additions, monitoring equipment and recording devices, and it may incur additional operating expenses. Litigation expenditures may also increase as a result of scientific investigations, and speculation and debate, concerning the possibility of harmful health effects of electric and magnetic fields. The total amount of these expenditures is not now determinable. SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS The Company has estimated that the total cost of decontaminating and demolishing its Steel Point Station and completing requisite environmental remediation of the site will be approximately $11.3 million, of which approximately $8.3 million had been incurred as of December 31, 1997, and that the value of the property following remediation will not exceed $6.0 million. As a result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the Company has been recovering through retail rates $1.075 million of the remediation costs per year. The remediation costs, property value and recovery from customers will be subject to true-up in the Company's next retail rate proceeding based on actual remediation costs and actual gain on the Company's disposition of the property. The Company is presently remediating an area of PCB contamination at its English Station generating site, including repair and/or replacement of approximately 560 linear feet of sheet piling. The total cost of the remediation and sheet piling repair is presently estimated at $3.5 million, and the Company plans to repair/replace a major portion of the remaining sheet piling at this location at an estimated cost of $6 million. (M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING Costs associated with nuclear plant operations include amounts for disposal of nuclear wastes, including spent fuel, and for the ultimate decommissioning of the plants. Under the Nuclear Waste Policy Act of 1982, the federal Department of Energy (DOE) is required to design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel. The Act requires the DOE to provide, beginning in 1998, for the disposal of spent nuclear fuel and high level radioactive waste from commercial nuclear plants through contracts with the owners and generators of such waste; and the DOE has established disposal fees that are being paid to the federal government by electric utilities owning or operating nuclear generating units. In return for payment of the prescribed fees, the federal government was required to take title to and dispose of the utilities' high level wastes and spent nuclear fuel beginning no later than January 1998. However, the DOE has announced that its first high level waste repository will - 74 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) not be in operation earlier than 2010 and possibly not earlier than 2013, notwithstanding the DOE's statutory and contractual responsibility to begin disposal of high-level radioactive waste and spent fuel beginning not later than January 31, 1998. The DOE also announced that, absent a repository, the DOE has no statutory obligation to begin taking high level wastes and spent nuclear fuel for disposal by January 1998. However, numerous utilities and states have obtained a judicial declaration that the DOE has a statutory responsibility to take title to and dispose of high level wastes and spent nuclear fuel beginning in January 1998, and that the contracts between the DOE and the plant owners and generators of such waste will provide a potentially adequate remedy for the latter if the DOE fails to fulfill its contractual obligations by that date. The DOE is contesting these judicial declarations; and it is unclear at this time whether the United States Congress will enact legislation to address spent fuel/high level waste disposal issues. Until the federal government begins receiving such materials, nuclear generating units will need to retain high level wastes and spent nuclear fuel on-site or make other provisions for their storage. Storage facilities for the Connecticut Yankee Unit are deemed adequate, and storage facilities for Millstone Unit 3 are expected to be adequate for the projected life of the unit. Storage facilities for Seabrook Unit 1 are expected to be adequate until at least 2010. Fuel consolidation and compaction technologies are being considered for Seabrook Unit 1 and may provide adequate storage capability for the projected life of the unit. In addition, other licensed technologies, such as dry storage casks, may satisfy spent nuclear fuel storage requirements. Disposal costs for low-level radioactive wastes (LLW) that result from operation or decommissioning of nuclear generating units have increased significantly in recent years and may continue to rise. The cost increases are a function of increased packaging and transportation costs, and higher fees and surcharges imposed by the disposal facilities. Currently, the Chem Nuclear LLW facility at Barnwell, South Carolina, is open to the Connecticut Yankee Unit, Millstone Unit 3, and Seabrook Unit 1 for disposal of LLW. The Envirocare LLW facility at Clive, Utah, is also open to these generating units for portions of their LLW. All three units have contracts in place for LLW disposal at these disposal facilities. Because access to LLW disposal may be lost at any time, Millstone Unit 3 and Seabrook Unit 1 have storage plans that will allow on-site retention of LLW for at least five years in the event that disposal is interrupted. The Connecticut Yankee Unit, which has been retired from commercial operation, has a similar storage program, although disposal of its LLW will take place in connection with its decommissioning. The Company cannot predict whether or when a LLW disposal site will be designated in Connecticut. The State of New Hampshire has not met deadlines for compliance with the Low-Level Radioactive Waste Policy Act and has stated that the state is unsuitable for a LLW disposal facility. Both Connecticut and New Hampshire are also pursuing other options for out-of-state disposal of LLW. NRC licensing requirements and restrictions are also applicable to the decommissioning of nuclear generating units at the end of their service lives, and the NRC has adopted comprehensive regulations concerning decommissioning planning, timing, funding and environmental reviews. UI and the other owners of the nuclear generating units in which UI has interests estimate decommissioning costs for the units and attempt to recover sufficient amounts through their allowed electric rates, together with earnings on the investment of funds so recovered, to cover expected decommissioning costs. Changes in NRC requirements or technology, as well as inflation, can increase estimated decommissioning costs. New Hampshire has enacted a law requiring the creation of a government-managed fund to finance the decommissioning of nuclear generating units in that state. The New Hampshire Nuclear Decommissioning Financing Committee (NDFC) has established $473 million (in 1998 dollars) as the decommissioning cost estimate for Seabrook - 75 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Unit 1, of which the Company's share would be approximately $83 million. This estimate assumes the prompt removal and dismantling of the unit at the end of its estimated 36-year energy producing life. Monthly decommissioning payments are being made to the state-managed decommissioning trust fund. UI's share of the decommissioning payments made during 1997 was $1.9 million. UI's share of the fund at December 31, 1997 was approximately $12.4 million. Connecticut has enacted a law requiring the operators of nuclear generating units to file periodically with the DPUC their plans for financing the decommissioning of the units in that state. The current decommissioning cost estimate for Millstone Unit 3 is $557 million (in 1998 dollars), of which the Company's share would be approximately $21 million. This estimate assumes the prompt removal and dismantling of the unit at the end of its estimated 40-year energy producing life. Monthly decommissioning payments, based on these cost estimates, are being made to a decommissioning trust fund managed by Northeast Utilities (NU). UI's share of the Millstone Unit 3 decommissioning payments made during 1997 was $487,000. UI's share of the fund at December 31, 1997 was approximately $5.1 million. The decommissioning trust fund for the Connecticut Yankee Unit is also managed by NU. For the Company's 9.5% equity ownership in Connecticut Yankee, decommissioning costs of $2.1 million were funded by UI during 1997, and UI's share of the fund at December 31, 1997 was $24.9 million. The current decommissioning cost estimate for the Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit commencing in 1997, is $456 million, of which UI's share would be $43 million. The Financial Accounting Standards Board (FASB) has issued an exposure draft related to the accounting for the closure and removal costs of long-lived assets, including nuclear plant decommissioning. If the proposed accounting standard were adopted, it may result in higher annual provisions for decommissioning to be recognized earlier in the operating life of nuclear units and an accelerated recognition of the decommissioning obligation. The FASB will be deliberating this issue, and the resulting final pronouncement could be different from that proposed in the exposure draft. - 76 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (O) FAIR VALUE OF FINANCIAL INSTRUMENTS (1) The estimated fair values of the Company's financial instruments are as follows: 1997 1996 ---- ---- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- (000's) (000's) Cash and temporary cash investments $32,002 $32,002 $ 6,394 $ 6,394 Long-term debt (2)(3)(4) $620,457 $624,192 $652,767 $655,582 (1) Equity investments were not valued because they were not considered to be material. (2) Excludes the obligation under the Seabrook Unit 1 sale/leaseback agreement. (3) The fair market value of the Company's long-term debt is estimated by brokers based on market conditions at December 31, 1997 and 1996, respectively. (4) See Note (B), Capitalization - Long-Term Debt. - 77 -
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THE UNITED ILLUMINATING COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (P) QUARTERLY FINANCIAL DATA (UNAUDITED) Selected quarterly financial data for 1997 and 1996 are set forth below: [Download Table] OPERATING OPERATING NET EARNINGS PER SHARE OF QUARTER REVENUES INCOME INCOME COMMON STOCK(1) ------- --------- --------- ------ --------------------- (000's) (000's) (000's) Basic Diluted ----- ------- 1997 First $180,325 $22,150 $7,710 $ .54 $.54 Second(2)(3) 163,774 22,692 8,542 .61 .61 Third 196,563 38,351 23,402 1.68 1.68 Fourth 169,605 21,380 6,137 .44 .44 1996 First(4) $170,860 $29,042 $11,721 $ .82 $ .82 Second(4)(5) 168,790 25,871 8,883 .75 .75 Third(4) 209,167 34,466 17,904 1.27 1.26 Fourth(6) 177,203 19,756 588 .04 .04 ------------------ (1) Based on weighted average number of shares outstanding each quarter. (2) Operating income, net income and earnings per share for the second quarter of 1997 included an after-tax credit of $6.7 million, or $.48 per share, to provide for the cumulative tax benefits associated with future fossil generation decommissioning. (3) Operating income, net income and earnings per share for the second quarter of 1997 included an after-tax charge of $4.1 million, or $.30 per share, to record additional amortization of conservation and load management costs. (4) Operating income, net income and earnings per share for the first, second and third quarters of 1996 included after-tax charges of $4.2 million, or $.30 per share, $0.5 million, or $.03 per share and $8.7 million, or $.62 per share, respectively, for early retirement and voluntary separation programs. (5) Operating income, net income and earnings per share for the second quarter of 1996 included an after-tax charge of $0.8 million, or $.06 per share, for the cumulative loss on an office space sublease. (6) Net income and earnings per share for the fourth quarter of 1996 included an after-tax charge of $2.6 million, or $.18 per share, for losses associated with the Company's unregulated subsidiaries. - 78 -
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REPORT OF INDEPENDENT ACCOUNTANTS January 26, 1998 To the Shareowners and Board of Directors of The United Illuminating Company In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, of cash flows and of retained earnings present fairly, in all material respects, the consolidated financial position of The United Illuminating Company and its subsidiaries at December 31, 1997 and 1996, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ Price Waterhouse LLP - 79 -
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REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE January 26, 1998 To the Board of Directors of The United Illuminating Company Our audits of the consolidated financial statements referred to in our report dated January 26, 1998 appearing on page 79 of the 1997 Annual Report on Form 10-K also included an audit of the Financial Statement Schedule on page S-1 of this Form 10-K. In our opinion, this Financial Statement Schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. /s/ Price Waterhouse LLP - 80 -
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[Letterhead of Coopers & Lybrand] REPORT OF INDEPENDENT ACCOUNTANTS --------------------------------- To the Shareowners and Directors of The United Illuminating Company: We have audited the consolidated balance sheet of The United Illuminating Company as of December 31, 1995, and the related consolidated statements of income, retained earnings and cash flows for the year then ended and the consolidated financial statement schedule for the year ended December 31, 1995 (page S-1). These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The United Illuminating Company as of December 31, 1995, and the consolidated results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. /s/ Coopers & Lybrand L.L.P. Hartford, Connecticut January 29, 1996 - 81 -
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures. Previously reported. See Current Report (Form 8-K, dated December 15, 1995 (amended January 2, 1996 and January 18, 1996)). PART III Item 10. Directors and Executive Officers of the Company. The information appearing under the captions "NOMINEES FOR ELECTION AS DIRECTORS" AND "SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE" in the Company's definitive Proxy Statement, dated March 27, 1998 for the Annual Meeting of the Shareholders to be held on May 20, 1998, which Proxy Statement will be filed with the Securities and Exchange Commission on or about March 27, 1998, is incorporated by reference in partial answer to this item. See also "EXECUTIVE OFFICERS OF THE COMPANY", following Part I, Item 4 herein. Item 11. Executive Compensation. The information appearing under the captions "EXECUTIVE COMPENSATION," "STOCK OPTION EXERCISES IN 1997 AND YEAR-END OPTION VALUES," "RETIREMENT PLANS," "BOARD OF DIRECTORS COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE REPORT ON EXECUTIVE COMPENSATION," "COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION," "DIRECTOR COMPENSATION" and "SHAREOWNER RETURN PRESENTATION" in the Company's definitive Proxy Statement, dated March 27, 1998, for the Annual Meeting of the Shareholders to be held on May 20, 1998, which Proxy Statement will be filed with the Securities and Exchange Commission on or about March 27, 1998, is incorporated by reference in answer to this item. Item 12. Security Ownership of Certain Beneficial Owners and Management. The information appearing under the captions "PRINCIPAL SHAREOWNERS" and "STOCK OWNERSHIP OF DIRECTORS AND OFFICERS" in the Company's definitive Proxy Statement, dated March 27, 1998 for the Annual Meeting of the Shareholders to be held on May 20, 1998, which Proxy Statement will be filed with the Securities and Exchange Commission on or about March 27, 1998, is incorporated by reference in answer to this item. Item 13. Certain Relationships and Related Transactions. Since January 1, 1997, there has been no transaction, relationship or indebtedness of the kinds described in Item 404 of Regulation S-K. - 82 -
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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, 1997, 1996 and 1995 Consolidated statement of cash flows for the years ended December 31, 1997, 1996 and 1995 Consolidated balance sheet, December 31, 1997, 1996 and 1995 Consolidated statement of retained earnings for the years ended December 31, 1997, 1996 and 1995 Notes to consolidated financial statements Reports of independent accountants Financial Statement Schedule (see S-1) Schedule II - Valuation and qualifying accounts for the years ended December 31, 1997, 1996 and 1995. - 83 -
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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 Registration Statement No. 2-60849, effective July 24, 1978. (6) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1996. (7) Filed with Registration Statement No. 33-40169, effective August 12, 1991. (8) Filed with Registration Statement No. 33-35465, effective August 1, 1990. (9) Filed with Amendment No. 1 to Registration Statement No. 33-55461, effective October 31, 1994. (10) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31, 1995. (11) Filed with Registration Statement No. 2-57275, effective October 19, 1976. (12) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1995. (13) Filed with Registration Statement No. 2-66518, effective February 25, 1980. (14) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1991. (15) Filed with Registration Statement No. 2-49669, effective December 11, 1973. (16) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1993. (17) Filed with Registration Statement No. 2-54876, effective November 19, 1975. (18) Filed with Registration Statement No. 2-52657, effective February 6, 1975. (19) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended June 30, 1997. (20) Filed with Annual Report (Form 10-K) for fiscal year ended December 31, 1992. (21) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended September 30, 1997. (22) Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31, 1994. (23) Filed March 29, 1996, with proxy material for the Annual Meeting of the Shareowners. - 84 -
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The exhibit number in the statement or report referenced is set forth in the parenthesis following the description of the exhibit. Those of the following exhibits not so identified are filed herewith. [Enlarge/Download Table] Exhibit Table Exhibit Reference Item No. No. No. Description ------- ------- --------- ----------- (3) 3.1a (1) Copy of Restated Certificate of Incorporation of The United Illuminating Company, dated January 23, 1995. (Exhibit 3.1) (3) 3.1b (2) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated August 4, 1995. (Exhibit 3.1b) (3) 3.1c (3) Copy of Certificate Amending Certificate of Incorporation by Action of Board of Directors, dated July 16, 1996. (Exhibit 3.1c) (3) 3.1d (4) Copy of Certificate Amending Certificate of Incorporation By Action of Board of Directors, dated December 11, 1996. (Exhibit 3.1d) (3) 3.2a (5) Copy of Bylaws of The United Illuminating Company. (Exhibit 2.3) (3) 3.2b (6) Copy of Article II, Section 2, of Bylaws of The United Illuminating Company, as amended March 26, 1990, amending Exhibit 3.2a. (Exhibit 3.2b) (3) 3.2c (6) Copy of Article V, Section 1, of Bylaws of The United Illuminating Company, as amended April 22, 1991, amending Exhibit 3.2a. (Exhibit 3.2c) (4) 4.1 (7) Copy of Indenture, dated as of August 1, 1991, from The United Illuminating Company to The Bank of New York, Trustee. (Exhibit 4) (4),(10) 4.2 (8) Copy of Participation Agreement, dated as of August 1, 1990, among Financial Leasing Corporation, Meridian Trust Company, The Bank of New York and The United Illuminating Company. (Exhibits 4(a) through 4(h), inclusive, Amendment Nos. 1 and 2). (4) 4.3a (9) Copy of form of Amended and Restated Agreement of Limited Partnership of United Capital Funding Partnership L.P. (Exhibit 4(c)) (4) 4.3b (10) Copy of Action of The United Illuminating Company, as General Partner of United Capital Funding Partnership L.P., relating to the 9 5/8% Preferred Capital Securities, Series A, of United Capital Funding Partnership L.P. (Exhibit 4(b)) (4) 4.3c (9) Copy of form of Indenture, dated as of April 1, 1995, from The United Illuminating Company to The Bank of New York, as Trustee. (Exhibit 4(e)) (4) 4.3d (10) Copy of First Supplemental Indenture, dated as of April 1, 1995, between The United Illuminating Company and The Bank of New York, Trustee, supplementing Exhibit 4.3c. (Exhibit 4(d)) (4) 4.3e (9) Copy of form of Payment and Guarantee Agreement of The United Illuminating Company, dated as of April 1, 1995. (Exhibit 4(j)) (10) 10.1 (11) Copy of Stockholder Agreement, dated as of July 1, 1964, among the various stockholders of Connecticut Yankee Atomic Power Company, including The United Illuminating Company. (Exhibit 5.1-1) (10) 10.2a (11) Copy of Power Contract, dated as of July 1, 1964, between Connecticut Yankee Atomic Power Company and The United Illuminating Company. (Exhibit 5.1-2) (10) 10.2b (12) Copy of Additional Power Contract, dated as of April 30, 1984, between Connecticut Yankee Atomic Power Company and The United Illuminating Company. (10) 10.2c (6) Copy of 1987 Supplementary Power Contract, dated as of April 1, 1987, supplementing Exhibits 10.2a and 10.2b. (Exhibit 10.2c) (10) 10.2d (6) Copy of 1996 Amendatory Agreement, dated as of December 4, 1996, amending Exhibits 10.2b and 10.2c. (Exhibit 10.2d) - 85 -
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[Enlarge/Download Table] Exhibit Table Exhibit Reference Item No. No. No. Description ------- ------- --------- ----------- (10) 10.2e (6) Copy of First Supplement to 1996 Amendatory Agreement, dated as of February 10, 1997, supplementing Exhibit 10.2d. (Exhibit 10.2e) (10) 10.3 (11) Copy of Capital Funds Agreement, dated as of September 1, 1964, between Connecticut Yankee Atomic Power Company and The United Illuminating Company. (Exhibit 5.1-3) (10) 10.4a (11) Copy of Connecticut Yankee Transmission Agreement, dated as of October 1, 1964, among the various stockholders of Connecticut Yankee Atomic Power Company, including The United Illuminating Company. (Exhibit 5.1-4) (10) 10.4b (13) Copy of Agreement Amending and Revising Connecticut Yankee Transmission Agreement, dated as of July 1, 1979, amending Exhibit 10.4a. (Exhibit 5.1-7) (10) 10.5 (5) Copy of Capital Contributions Agreement, dated October 16, 1967, between The United Illuminating Company and Connecticut Yankee Atomic Power Company. (Exhibit 5.1-5) (10) 10.6a (14) Copy of NEPOOL Power Pool Agreement, dated as of September 1, 1971, as amended to November 1, 1988. (Exhibit 10.6a) (10) 10.6b (15) Copy of Agreement Setting Out Supplemental NEPOOL Understandings, dated as of April 2, 1973. (Exhibit 5.7-10) (10) 10.6c (14) Copy of Amendment to NEPOOL Power Pool Agreement, dated as of March 15, 1989, amending Exhibit 10.6a. (Exhibit 10.6c) (10) 10.6d (14) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of October 1, 1990, amending Exhibit 10.6a. (Exhibit 10.6d) (10) 10.6e (16) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of September 15, 1992, amending Exhibit 10.6a. (Exhibit 10.6e) (10) 10.6f (16) Copy of Agreement Amending NEPOOL Power Pool Agreement, dated as of June 1, 1993, amending Exhibit 10.6a. (Exhibit 10.6f) (10) 10.7a (14) Copy of Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, dated May 1, 1973, as amended to February 1, 1990. (Exhibit 10.7a) (10) 10.7b (17) Copy of Transmission Support Agreement, dated as of May 1, 1973, among the Seabrook Companies. (Exhibit 5.9-2) (10) 10.7c (6) Copy of Twenty-third Amendment to Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, dated as of November 1, 1990, amending Exhibit 10.7a. (Exhibit 10.7c) (10) 10.8a (13) Copy of Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of September 1, 1973, among The Connecticut Light and Power Company, The Hartford Electric Light Company, Western Massachusetts Electric Company, New England Power Company, The United Illuminating Company, Public Service Company of New Hampshire, Central Vermont Public Service Company, Montaup Electric Company and Fitchburg Gas and Electric Light Company, relating to a nuclear fueled generating unit in Connecticut. (Exhibit 5.8-1) (10) 10.8b (18) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of August 1, 1974, amending Exhibit 10.8a. (Exhibit 5.9-2) (10) 10.8c (11) Copy of Amendment to Sharing Agreement - 1979 Connecticut Nuclear Unit, dated as of December 15, 1975, amending Exhibit 10.8a. (Exhibit 5.8-4, Post-effective Amendment No. 2) (10) 10.9a (5) Copy of Transmission Line Agreement, dated January 13, 1966, between the Trustees of the Property of The New York, New Haven and Hartford Railroad Company and The United Illuminating Company. (Exhibit 5.4) - 86 -
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[Enlarge/Download Table] Exhibit Table Exhibit Reference Item No. No. No. Description ------- ------- --------- ----------- (10) 10.9b (14) Notice, dated April 24, 1978, of The United Illuminating Company's intention to extend term of Transmission Line Agreement dated January 13, 1966, Exhibit 10.9a. (Exhibit 10.9b) (10) 10.9c (14) Copy of Letter Agreement, dated March 28, 1985, between The United Illuminating Company and National Railroad Passenger Corporation, supplementing and modifying Exhibit 10.9a. (Exhibit 10.9c) (10) 10.9d (19) Copy of Notice, dated April 22, 1997, of The United Illuminating Company's intention to extend term of Transmission Line Agreement, Exhibit 10.9a, as supplemented and modified by Exhibit 10.9c. (Exhibit 10.9d) (10) 10.10 Copy of Agreement, effective May 16, 1997, between The United Illuminating Company and Local 470-1, Utility Workers Union of America, AFL-CIO. (10) 10.11 (20) Copy of Coal Sales Agreement, dated as of August 1, 1992, between Pittston Coal Sales Corp. and The United Illuminating Company. (Confidential treatment requested) (Exhibit 10.13) (10) 10.12 (6) Copy of Fossil Fuel Supply Agreement between BLC Corporation and The United Illuminating Company, dated as of July 1, 1991. (Exhibit 10.13) (10) 10.13* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The United Illuminating Company and Richard J. Grossi. (Exhibit 10.22) (10) 10.14* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The United Illuminating Company and Robert L. Fiscus. (Exhibit 10.23) (10) 10.15* (21) Copy of Amended and Restated Employment Agreement, effective as of March 1, 1997, between The United Illuminating Company and James F. Crowe. (Exhibit 10.24) (10) 10.16* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Albert N. Henricksen. (Exhibit 10.25) (10) 10.17* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Anthony J. Vallillo. (Exhibit 10.26) (10) 10.18* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Rita L. Bowlby. (Exhibit 10.27) (10) 10.19* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Stephen F. Goldschmidt. (Exhibit 10.28) ` (10) 10.20* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and James L. Benjamin. (Exhibit 10.29) (10) 10.21* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Kurt D. Mohlman. (Exhibit 10.30) (10) 10.22* (21) Copy of Employment Agreement, dated as of March 1, 1997, between The United Illuminating Company and Charles J. Pepe. (Exhibit 10.31) (10) 10.23* (14) Copy of Executive Incentive Compensation Program of The United Illuminating Company. (Exhibit 10.24) (10) 10.24* (12) Copy of The United Illuminating Company 1990 Stock Option Plan, as amended on December 20, 1993, January 24, 1994 and August 22, 1994. (10) 10.25* (22) Copy of The United Illuminating Company Dividend Equivalent Program. (Exhibit 10.20) (10) 10.26* (23) Copy of Directors' Deferred Compensation Plan of The United Illuminating Company. (10) 10.27* (3) Copy of The United Illuminating Company 1996 Long Term Incentive Program. (Exhibit 10.21*) - 87 -
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[Enlarge/Download Table] Exhibit Table Exhibit Reference Item No. No. No. Description ------- ------- --------- ----------- (12),(99) 12 Statement Showing Computation of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (Twelve Months Ended December 31, 1997, 1996, 1995, 1994 and 1993). (21) 21 List of subsidiaries of The United Illuminating Company. (27) 27 Financial Data Schedule (28) 28.1 (20) Copies of significant rate schedules of The United Illuminating Company. (Exhibit 28.1) ------------------------ *Management contract or compensatory plan or arrangement. - 88 -
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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 - 89 -
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CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Prospectuses constituting part of the Registration Statements on Form S-3 (No. 33-50221, No. 33-50445, No. 33-55461 and No. 33-64003) of our reports dated January 26, 1998 appearing on page 79 and page 80 of The United Illuminating Company's Annual Report on Form 10-K for the year ended December 31, 1997. /s/ Price Waterhouse LLP New York, New York March 3, 1998 - 90 -
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[Letterhead of Coopers & Lybrand] CONSENT OF INDEPENDENT ACCOUNTANTS ---------------------------------- We consent to the incorporation by reference in the Post Effective Amendment No. 1 to the Registration Statement of The United Illuminating Company on Form S-3 (File No. 33-50221) and the Registration Statements on Form S-3 (File No. 33-50445, File No. 33-55461 and File No. 33-64003), of our report, dated January 29, 1996, on our audit of the consolidated financial statements and financial statement schedule of The United Illuminating Company as of December 31, 1995 and for the year then ended, which report is included in this Annual Report on Form 10-K. /s/ Coopers & Lybrand L.L.P. Hartford, Connecticut March 2, 1998 - 91 -
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SIGNATURES Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE UNITED ILLUMINATING COMPANY By /s/ Richard J. Grossi -------------------------------- Richard J. Grossi Chairman of the Board of Directors and Chief Executive Officer DATE: MARCH 3, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. [Download Table] SIGNATURE TITLE DATE --------- ----- ---- Director, Chairman of the Board of Directors and /s/ Richard J. Grossi Chief Executive Officer March 3, 1998 ------------------------------ (Richard J. Grossi) (Principal Executive Officer) Director, Vice Chairman and /s/ Robert L. Fiscus Chief Financial Officer March 3, 1998 ------------------------------ (Robert L. Fiscus) (Principal Financial and Accounting Officer) /s/ John F. Croweak Director March 3, 1998 ------------------------------ (John F. Croweak) /s/ F. Patrick McFadden, Jr. Director March 3, 1998 ------------------------------ (F. Patrick McFadden, Jr.) /s/ J. Hugh Devlin Director March 3, 1998 ------------------------------ (J. Hugh Devlin) /s/ Betsy Henley-Cohn Director March 3, 1998 ------------------------------ (Betsy Henley-Cohn) /s/Frank R. O'Keefe, Jr. Director March 3, 1998 ------------------------------ (Frank R. O'Keefe, Jr.) /s/ James A. Thomas Director March 3, 1998 ------------------------------ (James A. Thomas) /s/ David E.A. Carson Director March 3, 1998 ------------------------------ (David E.A. Carson) /s/ John L. Lahey Director March 3, 1998 ------------------------------ (John L. Lahey) /s/ Marc C. Breslawsky Director March 3, 1998 ------------------------------ (Marc C. Breslawsky) /s/ Thelma R. Albright Director March 3, 1998 ------------------------------ (Thelma R. Albright) - 92 -
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[Enlarge/Download Table] SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS THE UNITED ILLUMINATING COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (Thousands of Dollars) COL. A COL. B COL. C COL. D COL. E ------ ------ ------ ------ ------ ADDITIONS ------------------------------- BALANCE AT CHARGED TO CHARGED BALANCE AT BEGINNING COSTS AND TO OTHER END OF CLASSIFICATION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD -------------- ---------- ---------- -------- ---------- ---------- RESERVE DEDUCTION FROM ASSET TO WHICH IT APPLIES: Reserve for uncollectible accounts: 1997 $2,300 $6,407 - $6,907 (A) $1,800 1996 $6,300 $9,854 - $13,854 (A) $2,300 1995 $4,900 $9,383 - $7,983 (A) $6,300 ------------------------------------ NOTE: (A) Accounts written off, less recoveries. S-1

Dates Referenced Herein   and   Documents Incorporated By Reference

Referenced-On Page
This 10-K Filing   Date First   Last      Other Filings
1/1/9219
1/31/922774
8/1/9288
9/15/9287
12/31/9285
1/1/931675
2/1/9329
6/1/9387
11/2/932774
12/20/9388
12/31/93858910-K, U-3A-2, U-3A-2/A
1/1/941969
1/24/9488
2/28/942774
3/31/948510-Q
5/7/942774
8/22/9488
10/31/9485
12/31/948910-K
1/1/955663
1/23/9586
3/1/952774
3/31/958510-Q
4/1/9586
4/3/951
5/11/95277410-Q
8/4/9586
9/30/958510-Q
12/15/95838-K
12/31/95469410-K, 10-K/A
1/2/96838-K/A
1/18/96838-K/A
1/29/968292
3/8/962774
3/29/9685DEF 14A
3/30/962344
4/30/9629
6/30/968510-Q
7/16/9686
7/23/962440
10/1/962930
12/4/962386
12/11/9686
12/30/961060
12/31/9699410-K, 10-K/A
1/1/9783
1/15/971060
2/10/9787
2/15/971060
3/1/9788
3/7/972774
3/31/978510-Q
4/11/972775
4/22/9788
5/16/9788
6/30/97178510-Q
7/18/9715
7/30/971160
8/7/972345
9/30/978510-Q
11/7/9715
11/12/97116010-Q
12/5/9740
12/15/975556SC 13D/A
12/30/9715
For The Period Ended12/31/97194
1/13/981162
1/15/981161
1/17/9840
1/26/988091
1/31/98176
2/2/981
2/23/9829
3/2/9892
Filed On / Filed As Of3/3/989193
3/27/98183DEF 14A
3/31/981310-Q
5/1/9844
5/15/981745
5/20/981838-K, DEF 14A, PRE 14A
7/1/981519
12/9/981163
3/31/99184510-Q, 10-Q/A
12/31/0013
8/1/022573
12/15/021161
7/31/0713
7/1/1258
11/1/1258
9/1/1558
6/1/1658
1/2/191161
 
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