-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, L/Emh+rpdsmtREbf3M6VJh9+xz3MO8wlZyx3hkOfwuM7SmQ6p1Iaf8F2zaGpsII8 UoEZ9p3WlAHyQjhzuWZrjA== 0000013372-96-000004.txt : 19960401 0000013372-96-000004.hdr.sgml : 19960401 ACCESSION NUMBER: 0000013372-96-000004 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960329 SROS: BSE SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BOSTON EDISON CO CENTRAL INDEX KEY: 0000013372 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041278810 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02301 FILM NUMBER: 96541377 BUSINESS ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: ROOM P 344 CITY: BOSTON STATE: MA ZIP: 02199 BUSINESS PHONE: 6174242000 MAIL ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: ROOM P 344 CITY: BOSTON STATE: MA ZIP: 02199 10-K 1 BOSTON EDISON COMPANY 1995 FORM 10-K 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, 1995 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 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter) Massachusetts 04-1278810 - ------------------------------------------- ------------------------ (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 800 Boylston Street, Boston, Massachusetts 02199 - ------------------------------------------- ------------------------ (Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000 ------------ Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange Title of each class on which registered ------------------- --------------------- Common stock, par value $1 per share New York Stock Exchange Boston Stock Exchange Cumulative preferred stock: 7.75% Series, par value $100 per share New York Stock Exchange (represented by depositary shares-each represents one-fourth interest in par value) 8.25% Series, par value $100 per share New York Stock Exchange (represented by depositary shares-each represents one-fourth interest in par value)
Securities registered pursuant to Section 12(g) of the Act: None 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. [ ] 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 --- --- The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 29, 1996 computed by reference to the last reported sale price of the common stock, $1 par value, of the registrant of the New York Stock Exchange composite tape on that date: $1,328,730,345. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class Outstanding at February 29, 1996 -------------------------- -------------------------------- Common Stock, $1 par value 48,098,836 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document ---- -------- III Portions of definitive proxy statement dated March 28, 1996 for Annual Meeting of Stockholders to be held May 8, 1996.
1 Boston Edison Company - -------------------------------------------------------------------------- Form 10-K Annual Report - -------------------------------------------------------------------------- December 31, 1995 - --------------------------------------------------------------------------
Part I Page - -------------------------------------------------------------------------- Item 1. Business 2 Item 2. Properties and Power Supply 9 Item 3. Legal Proceedings 11 Item 4. Submission of Matters to a Vote of Security Holders 12 Part II - -------------------------------------------------------------------------- Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 16 Item 6. Selected Financial Data 17 Item 7. Management's Discussion and Analysis 18 Item 8. Financial Statements and Supplementary Financial Information 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 52 Part III - -------------------------------------------------------------------------- Item 10. Directors and Executive Officers of the Registrant 53 Item 11. Executive Compensation 53 Item 12. Security Ownership of Certain Beneficial Owners and Management 54 Item 13. Certain Relationships and Related Transactions 54 Part IV - -------------------------------------------------------------------------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 55
2 Part I ------ Item 1. Business - ----------------- (a) General Development of Business - ----------------------------------- Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law. The Company operates in the energy and energy services business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. The Company has an unregulated subsidiary, Boston Energy Technology Group (BETG), in which it has authority from the Massachusetts Department of Public Utilities (DPU) to invest up to $45 million. This wholly owned subsidiary engages primarily in energy conservation services and the production of water treatment systems. In 1996 BETG entered into a joint venture to build a series of ice-based cooling systems. BETG's investment in this joint venture, Northwind Boston, is not material. The Company does not currently have a substantial investment in BETG and does not expect the subsidiary to significantly impact the results of operations in the next several years. (b) Financial Information about Industry Segments - ------------------------------------------------- The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable. (c) Narrative Description of Business - ------------------------------------- Principal Products and Services The Company supplies electricity at retail to an area of 590 square miles, including the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 1995 the Company served an average of 654,000 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues by class for the last three years consisted of the following:
1995 1994 1993 - --------------------------------------------------------------------------- Retail electric revenues: Commercial 50% 50% 49% Residential 28% 28% 28% Industrial 9% 9% 10% Other 2% 2% 1% Wholesale and contract revenues 11% 11% 12% ===========================================================================
3 Sources and Availability of Fuel The Company owns two stations whose generating units have the ability to burn oil, natural gas or both, one nuclear power station and ten combustion turbine generators. Refer also to the Company-Owned Facilities section of Item 2. The Company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:
Percentage of Company Average Cost of Fuel Generation by Source (%) ($ per Million BTU) -------------------------------- -------------------------------- 1995 1994 1993 1992 1991 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------ Oil 17.5 27.8 31.3 33.7 42.8 2.66 2.35 2.38 2.40 2.60 Gas 39.9 31.6 24.3 25.7 24.9 2.20 2.28 2.67 2.55 2.08 Nuclear 42.6 40.6 44.4 40.6 32.3 0.43 0.50 0.51 0.52 0.56 ==============================================================================
The majority of the Company's residual oil purchases consists of imported oil acquired primarily from international suppliers. The Company has contracts with major oil companies that can supply most of its estimated requirements, assuming no major disruptions in oil producing regions. Within contract provisions, the Company has the ability to purchase significant amounts of oil in the spot market when it is economical to do so. A portion of the Company's natural gas is supplied on an interruptible basis by contract. These contracts permit interruptions in deliveries by the supplier when natural gas pipeline capacity is unavailable. The Company is currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances, as part of a 1991 consent order with the Massachusetts Department of Environmental Protection (DEP). The Company has arrangements for a firm supply of natural gas to run the station at a minimum level and is developing a least-cost plan for operating beyond this minimum level which principally utilizes interruptible gas supplies or short-term capacity purchases. In order to obtain nuclear fuel for use at Pilgrim Station, the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 1998, 2000, 1998 and 2012, respectively. Franchises Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for the Company's electric transmission and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the action of these authorities is subject to appeal to the DPU. The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature. 4 Seasonal Nature of Business The Company's kWh sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. In addition, the Company bills higher base rates to commercial and industrial customers during the billing months of June through September as mandated by the DPU. Accordingly, greater than half of the Company's annual earnings typically occurs in the third quarter. Refer also to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8. Working Capital Practices The Company has no special practices with respect to working capital that would be considered unusual for the electric utility industry or significant for the understanding of the Company's business. Customer Dependence No material portion of the Company's business is dependent upon one or a few customers. Government Contracts No material portion of the Company's business is subject to renegotiation or termination of government contracts or subcontracts. Competitive Conditions The Company is operating in an increasingly competitive environment. Competitive pressures on the electric utility industry have increased due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels and changes in customer expectations. The trend is toward promotion of increased competition through modified regulation of the industry. To date the effects of competition have been most prominent in the wholesale electric market. In response to increased competition from other electric utilities and nonutility generators to sell electricity for resale, the Company secured long-term power supply agreements with its six wholesale customers that set rates through 2002 and beyond. As discussed in the Competition section of Item 7, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) in March 1995 addressing open transmission access and recovery of previously incurred costs. The provisions in the NOPR provide a framework for significant changes in the electric utility industry. Direct competition with other electric utilities and other energy suppliers for retail electricity sales is still subject to certain limitations. The Company and other Massachusetts electric utilities are currently protected in several ways by the DPU and municipal statutes against other utilities offering service to retail customers in their service areas. Another electric utility may not extend its service area to include municipalities other than those named in its agreement of association or charter without DPU authorization granted after notice and public hearing. Also, another company may not obtain an initial location for its lines in a municipality served by the Company without the approval of municipal authorities, subject to the right of appeal to the DPU. Additionally, a municipality may not engage in the electric utility business without complying with statutes requiring 5 specific city or town approval and the purchase of Company property within municipality limits. Despite the limitations on direct competition, the Company has been experiencing some forms of increased competition in the retail electric market. Competition currently exists with alternative fuel suppliers as customers are able to substitute natural gas, steam or oil for electricity for heating or cooling purposes. In addition, current legislation allows industrial and large commercial customers to own and operate their own electric generating units. Large facilities may also factor the cost of electricity into their decisions to relocate to new service territories. Electric utilities are thus under increasing pressure to discount rates. In August 1995 the DPU issued an order on restructuring of the electric utility industry. The order provides for Massachusetts-based electric utilities to restructure their operations to encourage more competition for customers. Refer to the Competition section of Item 7 for a discussion of the DPU order and the Company's involvement in the restructuring proceedings. In addition to its involvement in the DPU's restructuring proceedings, the Company is actively responding to the current and anticipated changes in the industry in several ways. In 1995 the Company reorganized into separate business units and reduced its workforce in order to strengthen its competitiveness as discussed in Note F to the Consolidated Financial Statements. It also continued to develop customer alliances and provided economic development rates to some customers. In addition, the Company currently has a special lower rate available for a small number of large manufacturing customers on a limited basis and recently implemented a one-year pilot program that uses a competitive market index to set electric rates for a limited number of customers. These actions all signify the Company's commitment to be a competitively priced, reliable provider of energy. Research Activities The Company actively participates in several industry sponsored research activities. Related expenditures, included in other operations and maintenance expense on the consolidated income statement in Item 8, were not material in 1995. Environmental Matters The Company is subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards can require modification of existing facilities or curtailment or termination of operations at these facilities, delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. The Company's environmental-related capital expenditures for the years 1996 through 2000 are currently expected to total $17 million, including $4.5 million in 1996 and $3.5 million in 1997. Additional expenditures could be required as changes in environmental requirements occur. The Company is required by the DEP to clean up approximately 40 properties that it owns or operates in which hazardous materials were previously spilled 6 or released. In addition, the Company has exposure to potential joint and several liability for the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Litigation or negotiations among the parties and with regulatory authorities is in process concerning the scope and cost of cleanup and the sharing of costs among the potentially responsible parties for several of these sites. The Company's potential hazardous waste liabilities are described further in the Environmental section of Item 7. Spent nuclear fuel and low-level radioactive waste (LLW) result from the operations of Pilgrim Station. Uncertainties continue to exist regarding the ultimate disposal of both the spent nuclear fuel and LLW. Refer to Note E to the Consolidated Financial Statements in Item 8 for further discussion regarding spent nuclear fuel and LLW disposal. As a facility which treats and stores hazardous wastes, Pilgrim Station is required to be licensed by the United States Environmental Protection Agency (EPA). Pilgrim has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive. The Company is subject to regulation by the EPA and the DEP relative to emissions from its fossil fuel-fired generating units under federal and Massachusetts clean air laws, including the 1990 Clean Air Act Amendments. These regulations require the installation of various emissions controls and, in certain cases, the use of low sulfur content fuels. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section of Item 7. The Company is also subject to regulation by the EPA and the DEP with respect to discharges of effluent from its generating stations into receiving waters. The federal Clean Water Act and the Massachusetts Clean Waters Act require the Company to receive permits that limit discharges in accordance with applicable water quality standards and are subject to renewal. The Company has the required discharge permits for each of its electric generating stations. Public concern continues regarding electromagnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. These concerns include the possibility of adverse health effects as well as perceived effects on property values. Refer to the Environmental section of Item 7 for a discussion of the EMF issue. Number of Employees The Company had 3,518 full-time and 26 part-time utility employees as of January 1, 1996, 2,342 of which are represented by two locals of the Utility Workers Union of America, AFL-CIO. The locals' labor contracts are effective through 2000. BETG had 46 full-time employees. (d) Financial Information about Foreign and Domestic Operations and Export - -------------------------------------------------------------------------- Sales - ----- Refer to Principal Products and Services of this item for information regarding the geographical area served by the Company and revenues by class for the last three years. 7 (e) Additional Information - -------------------------- Regulation The Company and its wholly owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the DPU, whose jurisdiction includes supervision over retail rates for electricity, financing, investing and accounting. In addition, the FERC has jurisdiction over various phases of the Company's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of that power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation. The Company is required to submit to the DPU annual performance standards applicable to its generating units and other units from which the Company purchases power through long-term contracts. Under this generating unit performance program, the Company provides quarterly progress reports to the DPU. The DPU has the right to reduce subsequent fuel and purchased power billings if it finds that the Company has been unreasonable or imprudent in the operation of its generating units or in the procurement of fuel. The Company has not yet received orders from the DPU for the performance years ended October 1994 and October 1995. The Company believes that its current provision for refunds is sufficient to cover potential refunds. The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which was issued in 1972 and expires in 2012. Continuing NRC review of existing regulations and certain operating occurrences at other nuclear plants have periodically resulted in the imposition of additional requirements for all domestic nuclear plants, including Pilgrim Station. NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties. In addition, the Company could undertake certain actions regarding Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations, a voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants. Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests for various kinds of federal, state and local legislative or regulatory action, direct voter initiatives or referenda or litigation. The Company cannot predict the extent, cost or timing of any modifications to Pilgrim Station which could be necessary in the future as a result of additional regulatory or other requirements, nor can it determine the effect of such future requirements on the continued operation of Pilgrim Station. The Company continues to evaluate the operation of the station from the standpoint of safety, reliability and economics and believes that such continued operation is in the best interests of the Company and its customers. The Company also owns 9.5% of the common stock of Connecticut Yankee Atomic Power Company, which owns a nuclear generating unit. Northeast Utilities, the majority owner of Connecticut Yankee, operates the unit. In March 1996 the 8 NRC ordered Northeast Utilities to submit a plan within 30 days verifying operational compliance with licensing documentation at the Connecticut Yankee unit and another unit owned and operated by Northeast Utilities, or risk having the plants shut down. This order follows noncompliances discovered at two of Northeast Utilities' other nuclear units. The Company is unable to determine at this time what the results of the NRC order will be on the operations of the Connecticut Yankee unit, or what the impact would be on the Company if the unit were to be shut down. Capital Expenditures and Financings The Company's most recent estimates of capital expenditures, allowance for funds used during construction (AFUDC), long-term debt maturities and sinking fund requirements for the years 1996 through 2000 are as follows:
(in thousands) 1996 1997 1998 1999 2000 - ----------------------------------------------------------------------------- Plant expenditures $160,000 $140,000 $130,000 $120,000 $110,000 Nuclear fuel expenditures 48,000 0 27,000 13,000 29,000 AFUDC (1) 2,000 2,000 2,000 2,000 2,000 Long-term debt 101,600 101,600 101,600 1,600 166,600 Preferred stock sinking fund 2,000 2,000 2,000 2,000 2,000 ============================================================================= (1) Excludes AFUDC on nuclear fuel.
The Company conducts a continuing review of its capital expenditure and financing programs. These programs and, therefore, the estimates shown above are subject to revision due to changes in regulatory requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. Plant expenditures in 1995 were $181 million and consisted primarily of additions to the Company's transmission and distribution systems and nuclear generation facility. Significant projects included spending of $20 million for the replacement of the main turbine rotors at Pilgrim Station and $17 million for the replacement of electric system property. In 1994 the DPU approved the Company's financing plan to issue up to $500 million of securities through 1996 using the proceeds to refinance short and long-term securities and for capital expenditures. Refer to Notes J and K to the Consolidated Financial Statements in Item 8 for specific information relating to the Company's financing activities. 9 Item 2. Properties and Power Supply - ------------------------------------ Company-Owned Facilities The Company's total electric generation capacity consisted of the following:
Year Unit Location Capacity(a) Type Installed - ----------------------------------------------------------------------------- Pilgrim Nuclear Plymouth, Mass. 669 Nuclear 1972 Power Station New Boston Station South Boston, Mass. 760 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, Mass. Units 4-5-6 399 Fossil 1957-1961 Unit 7 592 Fossil 1975 Combustion turbine 14 Fossil 1969 generator Combustion turbine Various 284 Fossil 1966-1971 generators (nine) ============================================================================= (a) In MW based on winter capability audit results.
All of the Company's steam fossil fuel-fired generating units are located at tide water and have access to fuel oil storage and/or natural gas or oil pipelines from nearby suppliers. The Company also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil- fired unit located in Yarmouth, Maine, began operations in 1978 and is operated by Central Maine Power Company. Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and non-utilities and its participation in the New England Power Pool as further described in this item. The Company's significant items of property consist of electric generating stations, substations and service centers, and are generally located on Company-owned land. The Company's high-tension transmission lines are generally located on land either owned by the Company or subject to easements in its favor. The Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by municipal and other state authorities. As of December 31, 1995, the Company's transmission system consisted of 362 miles of overhead circuits operating at 115, 230 and 345 kV and 156 miles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 46 transmission or combined transmission and distribution substations with transformer capacity of 10,612 megavolt amperes (MVA), 69 distribution substations with transformer capacity of 1,143 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 237 customers' substations. The overhead and underground distribution systems cover 4,652 and 892 miles of streets, respectively. HEEC, the Company's regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts. 10 The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company plans for the construction of certain new generation or transmission facilities based upon findings that such facilities are consistent with state public health, environmental protection and resource use and development policies. The Company currently has one proceeding before the EFSB, which concerns proposed transmission and station facilities in Hopkinton and Milford, Massachusetts. Long-Term Power Contracts Refer to Note O to the Consolidated Financial Statements in Item 8 for further information regarding the following contracts. The Company also has short- term agreements with several other utilities for varying periods for purchases of system and unit power, for sales of Company system and unit power and for transmission services. Utility Purchase Contracts: - -------------------------- The Company has a long-term contract with a subsidiary of Commonwealth Energy System in which it receives 25% of the output of an oil-fired electric generating unit. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return on investment. The Company has two long-term purchased power contracts with the Massachusetts Bay Transportation Authority (MBTA) for the availability of two of the MBTA's jet turbines. The MBTA retains the right to utilize the jets for its own emergency use and for testing purposes while the Company retains New England Power Pool credit for their capacity and output. The Company has a contract to purchase 9.5% of Connecticut Yankee's nuclear generating unit's output and is obligated to pay Connecticut Yankee 9.5% of its fixed and operating costs plus an annual return on investment. Non-Utility Generator Purchase Contracts: - ---------------------------------------- The Company currently purchases 533 MW of capacity and associated energy from non-utility generators. These purchases are from Ocean State Power, Northeast Energy Associates, L'Energia and MassPower. The Company also purchases power from two small hydro-electric facilities. Sales Contracts: - --------------- The Company has agreements with Commonwealth Electric Company, a subsidiary of Commonwealth Energy System, and with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, under which Commonwealth and Montaup each purchase 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and operating costs plus an annual return on investment. Commonwealth and Montaup have also agreed to indemnify the Company to the extent of 11% each of all losses, liability or damage not covered by insurance resulting from the operation, condemnation, shutdown or retirement of the unit. In addition, the Company has similar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station. 11 New England Power Pool The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities and other electricity suppliers in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To obtain maximum benefits of power pooling, the electric facilities of all member companies are operated by NEPOOL as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest cost generation and transmission equipment available at any given time. This operation is the responsibility of NEPOOL's central dispatch center, the New England Power Exchange (NEPEX). As a result of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of the other members. The dispatching of Company-owned generating facilities by NEPEX may be affected by minimally increasing energy requirements and any additions to New England generation capacity. The table below sets forth certain information as of the date of the Company's 1995-1996 winter and 1995 summer peak loads: December 11, 1995 August 16, 1995 (winter 1995-96) (summer 1995) - ------------------------------------------------------------------------ NEPEX utilities installed capacity: Seasonal maximum rating 27,187 MW 25,637 MW Seasonal normal rating 26,839 MW 25,353 MW NEPEX peak load 19,167 MW 20,486 MW Company territory peak load 2,458 MW 2,785 MW ========================================================================
The Company's net capacity was 3,667 MW at its winter peak and 3,445 MW at its summer peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,341 MW and 3,306 MW, respectively. NEPOOL participants have two agreements with Hydro-Quebec of Canada for hydro- electric power. The first agreement, Phase I, provides up to three million MWH of hydro-electric power to NEPOOL annually through 1997. The second agreement, Phase II, is a firm contract that provides seven million MWH of hydro-electric power annually through 2001. The price of the Phase II energy is based on the average cost of fossil fuel in New England for the previous year. The contract price is 80% of that average through 1996 and will be 95% of that average in 1997-2001. The Company receives capacity credit through NEPOOL for approximately 11% of the generation equivalent of the total Hydro- Quebec interconnection. The Company has an approximately 11% equity ownership interest in the two companies which own and operate the Phase II transmission facilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 1995, the Company's portion of these guarantees was approximately $19 million. Item 3. Legal Proceedings - -------------------------- In 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts (US District Court) alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by the Company's 1988 reduction in force. Legal counsel continues to vigorously defend this case. The 12 Company has also been named as a party in a lawsuit filed in both the US District Court and the Massachusetts Norfolk Superior Court by Subaru of New England, Inc. and Subaru Distributors Corporation in 1992. The plaintiffs are claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. The Company believes that it has a strong defense in this case. It is also involved in certain other legal matters. The Company is unable to fully determine a range of reasonably possible litigation costs in excess of amounts previously accrued, although based on the information currently available, it does not expect that any such additional costs will have a material impact on its financial condition. However, additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. Also refer to the Environmental section in Item 7 for a discussion of legal issues involving hazardous waste sites. Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------ There were no matters submitted to a vote of security holders during the fourth quarter of 1995. 13 Executive Officers of the Registrant - ------------------------------------ The names, ages, positions and business experience during the last five years of all the executive officers of Boston Edison Company and its subsidiaries as of March 1, 1996 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding between any Company officer and another person pursuant to which the officer was elected. Officers of the Company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until their respective successors are chosen and qualified.
Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Thomas J. May, 48 Chairman of the Board, President Chairman of the Board, President and Chief Executive Officer (since and Chief Executive Officer 1995), Chairman of the Board and Chief Executive Officer (1994- 1995), President and Chief Operating Officer (1993-1994) and Executive Vice President (1990- 1993); Director (since 1991) Chairman of the Board and Chief Executive Officer and Director, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp. and Ener-G-Vision, Inc.; Chairman of the Board and Director, REZ-TEK International Corp. and Coneco Corp. E. Thomas Boulette, 53 Senior Vice President - Nuclear Senior Vice President - Nuclear (since 1993), Vice President - Nuclear Operations and Station Director (1992-1993) and Vice President - Operations (1989- 1992) of Maine Yankee Atomic Power Company L. Carl Gustin, 52 Senior Vice President - Corporate Senior Vice President - Corporate Relations (since 1995), Senior Relations Vice President - Marketing & Corporate Relations (1989-1995) John J. Higgins, Jr., 63 Senior Vice President - Human Senior Vice President - Human Resources (since 1990) Resources
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Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Douglas S. Horan, 46 Senior Vice President and General Senior Vice President and Counsel (since 1995), Vice General Counsel President and General Counsel (1994-1995), Deputy General Counsel (1991-1994) and Associate General Counsel (1986-1991) Director and General Counsel, Harbor Electric Energy Company; Director, Boston Energy Technology Group James J. Judge, 40 Senior Vice President and Senior Vice President and Treasurer (since 1995), Assistant Treasurer Treasurer (1989-1995) and Director - Corporate Planning (1993-1995) Senior Vice President, Treasurer and Director, Harbor Electric Energy Company and Boston Energy Technology Group; Director, Ener-G-Vision, Inc., TravElectric Services Corp. and REZ-TEK International Corp. Ronald A. Ledgett, 57 Senior Vice President - Fossil Senior Vice President - Fossil (since 1995), Senior Vice President - Power Delivery (1991- 1995) and Director, Special Projects (1989-1991) Alison Alden, 47 Vice President - Sales & Service Vice President - Sales & Service (since 1993) and Director - Organization Development (1990- 1993) Director, Harbor Electric Energy Company, Boston Energy Technology Group and Coneco Corp. Robert A. Ruscitto, 51 Vice President - Field Service and Vice President - Field Service Electric Delivery (since 1995), and Electric Delivery Vice President - Electric Customer Service (1994-1995), General Manager, Electric Customer Service (1992-1994) and Manager, Metropolitan Transmission & Distribution Department (1990-1992)
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Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Robert J. Weafer, Jr., 49 Vice President - Finance, Vice President - Finance, Controller and Chief Accounting Controller and Chief Officer (since 1991), Controller Accounting Officer (1988-1991) and Chief Accounting Officer (1983-1991) Theodora S. Convisser, 48 Clerk of the Corporation (since Clerk of the Corporation 1986) and Assistant General Counsel (since 1984) Clerk, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Ener-G-Vision, Inc., REZ-TEK International Corp. and Coneco Corp.
16 Part II ------- Item 5. Market for the Registrant's Common Stock and Related Stockholder - ------------------------------------------------------------------------- Matters - ------- (a) Market Information - ---------------------- The Company's common stock is listed on the New York and Boston Stock Exchanges. Following are the reported high and low sales prices of the Company's common stock on the New York Stock Exchange as reported daily in the Wall Street Journal for each of the quarters in 1995 and 1994:
1995 1994 - ------------------------------------------------------------------------------ High Low High Low - ------------------------------------------------------------------------------ First quarter $25 1/2 $23 1/8 $29 7/8 $26 Second quarter 27 23 3/8 29 1/8 25 1/4 Third quarter 27 1/2 24 1/2 27 5/8 22 3/4 Fourth quarter 29 1/2 26 3/4 24 1/4 21 1/2 ==============================================================================
(b) Holders - ----------- As of December 31, 1995, the Company had 38,205 holders of record of its common stock. (c) Dividends - ------------- Following are the dividends declared per share of common stock for each of the quarters in 1995 and 1994:
1995 1994 - --------------------------------------------------------------------- First quarter $0.455 $0.440 Second quarter 0.455 0.440 Third quarter 0.455 0.440 Fourth quarter 0.470 0.455 =====================================================================
(d) Other Information - --------------------- Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements for the year ended December 31, 1995: Ratio of earnings to fixed charges 2.38 Ratio of earnings to fixed charges and preferred stock dividend requirements 2.00
17 Item 6. Selected Financial Data - -------------------------------- The following table summarizes five years of selected consolidated financial data of the Company (in thousands, except per share data).
1995 1994 1993 1992 1991 - --------------------------------------------------------------------------- Operating revenues $1,628,503 $1,544,735 $1,482,159 $1,411,753 $1,354,501 Net income 112,310 125,022 118,218 107,298 94,670 Earnings per common share 2.52(a) 2.41 2.28 2.10 1.96 Total assets 3,643,849 3,616,576 3,476,601 3,294,212 3,098,742 Long-term debt 1,160,223 1,136,617 1,272,497 1,091,073 1,136,765 Redeemable preferred/ preference stock 217,000 219,000 221,000 221,000 221,333 Cash dividends declared per common share 1.835 1.775 1.715 1.655 1.595 =========================================================================== (a) Excludes $0.44 per share restructuring charge. Certain reclassifications were made to the data reported in prior years to conform with the method of presentation used in 1995.
18 Item 7. Management's Discussion and Analysis - --------------------------------------------- Rate Regulation The rates we charge our retail customers are regulated by our state regulators, the Massachusetts Department of Public Utilities (DPU). In 1992 the DPU approved a three-year settlement agreement effective November 1992. This agreement provided us with retail rate increases, allowed for the recovery of demand side management (DSM) conservation program costs, specified certain accounting adjustments and clarified the timing and recognition of certain expenses. The agreement also set a limit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any penalties or rewards from performance incentives. The retail rate increases consisted of two annual base rate increases of $29 million effective November 1993 and November 1994 and an annual performance adjustment charge effective November 1992 through October 2000. The performance adjustment charge varies annually based on the performance of Pilgrim Nuclear Power Station. This charge is further described in the Electric Sales and Revenues section. In addition to the retail rate increases, our results of operations were affected by the recovery of DSM program costs, accounting adjustments and the timing and recognition of certain expenses as further described in the following Results of Operations section. We did not make a base rate filing upon the expiration of the 1992 settlement agreement, therefore base rates currently remain in effect at their 1995 levels. In February 1996 we filed an industry restructuring plan with the DPU in response to its August 1995 order on restructuring the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in an unbundling of our currently integrated monopoly business into a separate competitive electric production business and a regulated electric distribution business. Refer to Outlook for the Future for further information regarding the restructuring of the electric utility industry in Massachusetts. Results of Operations 1995 versus 1994 Earnings per common share were $2.08 in 1995 and $2.41 in 1994. Earnings in 1995 reflect a one-time charge of $34 million ($20.7 million net of tax, or $0.44 per share) associated with our corporate restructuring. The charge reflects the costs of early retirement and severance programs implemented as part of our organizational streamlining and reorganization into business units. Excluding the one-time charge, earnings per common share were $2.52 in 1995, an increase of 4.6% over 1994. This increase is due to the $29 million annual retail base rate increase effective November 1994, the ending of amortization of deferred cancelled nuclear costs in 1994, a 1.2% increase in retail kWh sales and lower revenue reserve provisions. These positive impacts were partially offset by higher income tax, property tax, nuclear outage amortization and employee benefit expenses, and an award received on an eminent domain case in 1994. 19 Operating revenues Operating revenues increased 5.4% over 1994 as follows:
(in thousands) - ------------------------------------------------------ Retail electric revenues $59,419 Demand side management revenues 8,783 Wholesale and other revenues 11,126 Short-term sales revenues 4,440 - ------------------------------------------------------ Increase in operating revenues $83,768 ======================================================
Retail electric revenues increased $59 million. Approximately $28 million of the increased revenues was due to the November 1994 base rate increase and approximately $11 million was due to the increase in retail kWh sales. Fuel and purchased power revenues increased $11 million as a result of the timing effect of fuel and purchased power cost recovery. However, these higher revenues are offset by higher fuel and purchased power expenses and have no net effect on earnings. Performance revenues, which vary annually based on the operating performance of Pilgrim Station, increased $9 million primarily due to a higher performance rate effective in 1995 and a 17% increase in generation. A new annual conservation charge for recovery of demand side management program costs was implemented in February 1995. Under this charge all 1995 program costs were recovered in 1995. This resulted in higher DSM revenues and expenses than in prior years when certain program costs were capitalized for recovery over six years. The net increase in wholesale and other revenues is primarily due to a $10 million decrease in revenue reserve provisions, which are primarily related to wholesale customer contract issues. The increase in short-term sales revenues is due to higher short-term sales resulting from higher generating availability in 1995. Revenues from short- term sales serve to reduce fuel and purchased power billings to retail customers and therefore have no net effect on earnings. Operating expenses Total fuel and purchased power expenses increased $22 million primarily due to the timing effect of fuel and purchased power cost collection. Excluding the timing effect, fuel expense increased 5% due to an 8% increase in fossil station generation while purchased power expense was unchanged. Fuel and purchased power expenses are substantially all recoverable through fuel and purchased power revenues. Other operations and maintenance expense increased 0.9% over 1994. Employee benefit expenses increased primarily due to higher postretirement benefit expenses recorded in accordance with the 1992 settlement agreement. We also incurred higher administrative costs in positioning the company for changes in the industry, which were offset by lower operating costs in the electric delivery business. Electric generation costs increased only 1% in 1995, primarily due to a refueling and maintenance outage at Pilgrim Station. The $34 million one-time restructuring charge was incurred over the third and fourth quarters of 1995 as a result of our corporate reorganization announced in July 1995. As part of the reorganization 330 employees elected to retire under enhanced retirement programs and 149 employees whose positions were eliminated became eligible for benefits under a special severance program. 20 See Note F to the Consolidated Financial Statements for additional information. We expect to achieve ongoing savings as a result of the restructuring, with a payback period of approximately one year. Depreciation and amortization expense increased due to a higher average depreciable plant balance. In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. In the third quarter of 1995 we changed the amortization period of deferred nuclear outage costs to two years from five years as discussed in Note B to the Consolidated Financial Statements. The remaining $9 million of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 was written off. Approximately $15 million of deferred costs from the 1995 refueling outage is being amortized over two years. The increase in demand side management programs expense is related to the increase in DSM revenues. Beginning with the annual conservation charge implemented in February 1995, DSM costs are recovered and expensed primarily in the year incurred. The 1995 expense includes $31 million of 1995 program costs and $14 million of amortization of costs capitalized in 1992 through 1994. Property and other taxes increased primarily due to higher Boston property taxes resulting from capital additions. Our effective annual income tax rate for 1995 was 37.1% vs. 31.4% for 1994. The higher rate is the result of a $10 million adjustment to deferred income taxes made in 1994 in accordance with the 1992 settlement agreement. Other income The net decrease in other income is primarily due to a $5.7 million gain recognized in 1994 from a court ruling on a 1989 eminent domain taking of certain of our property. Interest charges Interest charges on long-term debt increased due to a $125 million debentures issuance in May 1995, partially offset by interest savings from first mortgage bond and debenture redemptions in 1994. Other interest charges increased slightly due to higher short-term interest rates partially offset by a lower average short-term debt level. Allowance for borrowed funds used during construction (AFUDC), which represents the financing costs of construction, decreased due to a lower construction work in progress balance and shorter construction periods, partially offset by a higher AFUDC rate related to the higher short-term interest rates. 1994 versus 1993 Earnings per common share were $2.41 in 1994 and $2.28 in 1993. The increase in earnings was primarily the result of the expiration of a long-term purchased power contract in October 1993, a $29 million annual retail base rate increase effective November 1993, a 2.0% increase in retail kWh sales and an award relating to an eminent domain case. These positive changes were partially offset by higher operations and maintenance, depreciation and amortization and income tax expenses. 21 Operating revenues Operating revenues increased 4.2% over 1993 as follows:
(in thousands) - ------------------------------------------------------ Retail electric revenues $62,945 Demand side management revenues 5,056 Wholesale and other revenues (6,644) Short-term sales revenues 1,219 - ------------------------------------------------------ Increase in operating revenues $62,576 ======================================================
Retail electric revenues increased $63 million. The November 1993 and 1994 base rate increases resulted in $29 million of the increased revenues, and approximately $6 million was due to the 2% increase in retail kWh sales. Fuel and purchased power revenues increased $28 million primarily due to the recovery of certain new purchased power expenses. In accordance with the 1992 settlement agreement, specific revenues related to the purchased power contract that expired in October 1993 were not affected. Wholesale and other revenues decreased primarily due to an $8.5 million increase in revenue reserve provisions in 1994 related to certain wholesale customer contract issues. Operating expenses Total fuel and purchased power expenses decreased $27 million. Fuel expense decreased partly due to lower fossil fuel prices and a 12% decrease in nuclear output. Purchased power expense reflects lower costs associated with the long-term contract that expired in October 1993, partially offset by the costs of new contracts. The timing effect of fuel and purchased power cost collection also contributed to the decrease in fuel and purchased power expenses. Other operations and maintenance expense increased 7.4% primarily due to higher employee benefit expenses. Pension expense increased $20 million due to a higher contribution made to the pension plan for the year. In accordance with the 1992 settlement agreement, we recorded pension expense in the amount of the contribution to the plan. Depreciation and amortization expense increased primarily due to a higher depreciable plant balance. In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. In accordance with the 1992 settlement agreement we did not expense any of these costs in 1993. Amortization of deferred nuclear outage costs in 1994 and 1993 consists of amounts related to the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we deferred approximately $14 million of refueling outage costs. We began to amortize these costs in June 1993 over five years as approved in the 1992 settlement agreement. The $2 million decrease in demand side management programs expense was due to the timing of recovery of program costs. DSM expense includes some program costs recovered over twelve months and other program costs recovered over six years. The 1994 expense consists of $22 million of costs primarily related to 1994 expenditures and $13 million of costs capitalized in 1992 through 1994. 22 Municipal property and other taxes increased primarily as a result of higher Boston property taxes due to a tax rate increase and capital additions. Our effective annual income tax rate for 1994 was 31.4% vs. 23.4% for 1993. Both rates were reduced from the statutory rate by adjustments to deferred income taxes of $10 million in 1994 and $20 million in 1993 made in accordance with the 1992 settlement agreement. Other income In November 1994 a court ruling became effective providing us with an additional $5.7 million gain on a 1989 eminent domain taking of certain of our property. Interest charges Total interest charges did not change significantly. Interest charges on long-term debt decreased due to the first mortgage bond and debenture redemptions in 1994 and the significant first mortgage bond refinancing in 1993 at lower interest rates. This decrease was partially offset by higher amortization of redemption premiums. Other interest charges increased due to higher short-term interest rates partially offset by a lower average short- term debt level. AFUDC increased as a result of a higher AFUDC rate related to the higher short-term interest rates. Electric Sales and Revenues Electric sales Retail kWh sales increased 1.2% in 1995 primarily due to the positive effects of a stronger economy on commercial customers. This sector represents approximately 50% of our electric operating revenues. Demand side management conservation programs are designed to assist customers in reducing electricity use and, therefore, result in lower growth in electricity sales. We receive approval from our state regulators for DSM spending levels and recovery amounts through an annual conservation charge. Through 1994 we collected from customers certain DSM program costs primarily in the year incurred and other DSM program costs over a six-year period. In 1995 a new annual conservation charge was implemented under which all 1995 program costs were recovered in 1995. We are also provided with incentives and recovery of lost revenues based on the actual reduction in customer electricity usage from these programs and a return on the costs that we are recovering over six years. Electric revenues As discussed in the Rate Regulation section, our 1992 settlement agreement provided us with two annual retail base rate increases of $29 million effective in 1993 and 1994 and an eight-year annual performance adjustment charge. We did not make a base rate filing upon the expiration of the settlement agreement in 1995, therefore base rates currently remain in effect at their 1995 levels. Due to our continued commitment to controlling costs and increasing operating efficiencies, maintaining these rate levels in our current regulatory environment is not expected to significantly affect our financial condition or results of operations. The annual performance adjustment charge provides us with opportunities to improve our financial results. The most significant potential impact of this 23 performance incentive is based on Pilgrim Station's annual capacity factor. An annual capacity factor between 60% and 68% would provide us with approximately $51 million of revenues in the performance year ended October 1996. For each percentage point increase in capacity factor above 68%, annual revenues will increase by approximately $750,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease by approximately $840,000. Pilgrim's capacity factor for the performance year ending October 1996 is currently expected to be approximately 91%, an increase from the 67% capacity factor achieved in the performance year ended October 1995. There are no major outages scheduled for the current performance year. Pilgrim was out of service in November 1994 and for a 73- day refueling and maintenance outage in 1995. We earned approximately $49 million in revenues related to Pilgrim's capacity factor in the performance year ended October 31, 1995. Pilgrim Station was shut down for three months in 1994 due to a non-nuclear problem with its electrical generator. Regularly scheduled maintenance work was also performed during the shutdown. The power needs usually met by the station were met by other generating plants or purchased from other suppliers as necessary. We do not believe that the generator damage resulted from actions within our control. Our recovery of the incremental purchased power costs during the outage through fuel and purchased power revenues, however, is subject to review by the DPU under a generating unit performance program. Liquidity We meet our capital expenditure cash requirements primarily with internally generated funds. These funds provided for 95%, 98% and 77% of our plant and nuclear fuel expenditures in 1995, 1994 and 1993, respectively. Our current estimate of plant expenditures for 1996 is $160 million. These expenditures will be used primarily to maintain and improve existing transmission and distribution facilities. We expect plant expenditures to remain level or decline slightly from the 1996 amount in the four years thereafter. In addition to capital expenditures we have long-term debt and preferred stock payment requirements of $103.6 million per year in 1996 through 1998, $3.6 million in 1999 and $168.6 million in 2000. External financings continue to be necessary to supplement our internally generated funds, primarily through the issuance of short-term commercial paper and bank borrowings. We currently have authority from our federal regulators, the Federal Energy Regulatory Commission (FERC), to issue up to $350 million of short-term debt. We have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At December 31, 1995, we had $126 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1994 the DPU approved our financing plan to issue up to $500 million of securities through 1996 using the proceeds to refinance short and long-term securities and for capital expenditures. Refer to Notes J and K to the Consolidated Financial Statements for specific information relating to our recent financing activities. Outlook for the Future Competition Competitive pressures on the electric utility industry have increased due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels and changes in customer expectations. The trend is 24 toward promotion of increased competition through modified regulation of the industry. To date the effects of competition have been most prominent in the wholesale electric market. In response to increased competition from other electric utilities and nonutility generators to sell electricity for resale, we secured long-term power supply agreements with our six wholesale customers that set rates through 2002 and beyond. In 1995, our largest retail customer, the Massachusetts Port Authority (Massport), issued a request for proposals for a wholesale supplier of electricity. We successfully retained Massport as a customer through a ten-year wholesale power supply agreement effective November 1995. We are awaiting approval of this agreement from the FERC. In March 1995 the FERC issued a Notice of Proposed Rulemaking (NOPR) addressing open transmission access and recovery of previously incurred costs. If approved, the NOPR would require all utilities with transmission systems to file open access tariffs at the FERC, to provide service under those tariffs to transmission customers comparable to service provided to their electric energy customers and to take service under the tariffs for wholesale purchases and sales. The NOPR also supports the full recovery of legitimate and verifiable costs previously incurred under federal and state regulation. The provisions in the NOPR provide a framework for significant changes in the electric utility industry. We have also been experiencing increased competition in the retail electric market. Competition currently exists with alternative fuel suppliers as customers are able to substitute natural gas, steam or oil for electricity for heating or cooling purposes. In addition, industrial and large commercial customers may pursue options to generate their own electric power or factor the cost of electricity into their decisions to relocate to new service territories. Electric utilities are thus under increasing pressure from these customers to discount rates. In August 1995 the DPU issued an order on restructuring of the electric utility industry. The order provides for Massachusetts-based electric utilities to restructure their operations to encourage more competition for customers. It also includes the following principles for a restructured electric industry: - provide the broadest possible customer choice - provide all customers with an opportunity to share in the benefits of increased competition - ensure full and fair competition in generation markets - functionally separate generation, transmission and distribution services - provide universal service - support and further the goals of environmental regulation - rely on incentive regulation where a fully competitive market cannot exist, or does not yet exist The DPU order also set the following principles to guide the transition from a regulated to a competitive industry structure: - honor existing commitments - unbundle rates for generation, transmission and distribution - reduce rates in the near term - maintain demand side management programs - ensure an orderly and quick transition that minimizes customer confusion The order provides a reasonable opportunity for the recovery of net, nonmitigatable potentially strandable costs (strandable costs), over a period 25 of up to ten years. These costs include investments in plant that might not be recoverable in a competitive market, liabilities for future decommissioning of nuclear plants, the amounts by which certain purchase power contracts exceed the competitive price for generation, and prudently incurred regulatory assets. We are looking at possibilities for mitigating our potentially strandable costs, including potential revisions to depreciation and amortization periods. The order establishes only general principles for the transition to a competitive market and does not establish a particular model for the new industry structure. Each of the Massachusetts-based electric utilities is required to develop a plan for moving toward competition consistent with the DPU's order and encouraged to negotiate with all interested parties while doing so. We were one of three companies required to file a restructuring plan in February 1996. Our plan is consistent with the general principles outlined in the order, including unbundled rates for generation, transmission and distribution. It provides for and is based upon full recovery of strandable costs through a nonbypassable access charge. This charge is to be paid by customers as a condition of receiving service over our distribution system, which remains a monopoly function. We expect to enter into negotiations with intervening parties that will result in new rates and performance incentives to be implemented in the new industry structure. In addition to our involvement in the DPU's restructuring proceedings, we are actively responding to the current and anticipated changes in the industry in several ways. In 1995 we reorganized the company into separate business units in order to strengthen our competitiveness. These business units, Customer, Generating-Fossil, Generating-Nuclear and Corporate Services, were designed to sharpen management focus along our significant lines of operation while maintaining company-wide strategic goals. As a result of enhanced retirement programs and a special severance program offered during this corporate restructuring, we reduced our workforce by 12%. We expect to achieve ongoing savings as a result of the restructuring, with a payback period of approximately one year. We also continued to develop customer alliances and provided economic development rates to some customers. In addition, we currently have a special lower rate available for a small number of large manufacturing customers on a limited basis and we recently implemented a one- year pilot program that uses a competitive market index to set electric rates for a limited number of customers. These actions all signify our commitment to be a competitively priced, reliable provider of energy. We do not expect the economic development rates, the lower manufacturing customer rates or the pilot program to have a significant impact on our financial condition or results of operations. In the rate-regulated environment based on cost recovery that we have traditionally operated in, we are subject to certain accounting standards that are not applicable to other businesses and industries. The standards allow us to record certain costs as regulatory assets instead of as expenses when incurred when we expect to receive future rate recovery of the costs. We believe that we currently meet the criteria of these standards. In addition to the specifically identified regulatory assets on our consolidated balance sheets, there may be differences in the carrying value of our net utility plant compared to what the amount would have been if we were not subject to rate regulation. These potential differences would be due to differing plant depreciable lives for regulatory and non-regulatory accounting standards. We have not yet fully determined to what extent such differences may exist. The effects of competition and modified regulation could, in the near term, cause us to no longer meet the criteria for application of the regulatory accounting standards for some of our operations. Should this occur we would have to take a noncash write-off of our affected regulatory assets and adjust our affected 26 plant balances if necessary by recording an addition to depreciation expense at that time. However, the DPU order on industry restructuring provides a reasonable opportunity for recovery of these previously incurred costs, which are also provided for in our related plan. We expect to recover all strandable costs through our distribution system, which we expect will remain rate-regulated, and therefore will continue to meet the criteria of these accounting standards. If it does not continue to be likely that we will recover all our regulatory assets and generating plant costs as our restructuring plan is ultimately finalized, we would have to write off such portions that are no longer probable of recovery in accordance with Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. See Note M to the Consolidated Financial Statements for information on this new accounting standard. The nonrecovery of specifically identified and other embedded regulatory assets or plant costs could have a material impact on our results of operations and financial condition. Resource regulation In this period of transition in the electric utility industry we remain subject to current regulatory requirements. The DPU requires utilities to purchase power from qualifying nonutility generators at prices set through a bidding process. In a continuation of a dispute which originated in 1991, the DPU is currently investigating whether we should again be ordered to negotiate a contract to purchase power from an independent power producer, JMC Altresco, Inc. We have consistently opposed this order since we do not believe we need any new power for several years and the proposed contract would impose excessive costs on our customers. In 1995 we filed a motion to dismiss the matter, which is pending. We also filed testimony comparing the cost of Altresco to projected market costs and hearings are currently ongoing. In a separate but related matter, we appealed the Massachusetts Energy Facilities Siting Board's (EFSB) approval of construction of Altresco's proposed generating station based partly on the EFSB's failure to consider market information and forecasts. We also currently remain subject to the DPU's integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs with all other supplies of energy. As a result of our 1994 IRM filing, the DPU found that we did not have a need for additional generating capacity through 2001 and therefore were not required to issue a competitive request for proposals for new generating capacity. Required updates to our IRM filing have been postponed due to the current industry restructuring proceedings ongoing at the DPU. Nonutility business We have an unregulated subsidiary, Boston Energy Technology Group (BETG), in which we have authority from the DPU to invest up to $45 million. This wholly owned subsidiary engages primarily in energy conservation services and the production of water treatment systems. In 1996 BETG entered into a joint venture to build a series of ice-based cooling systems as an alternative to costly chemical systems. BETG's investment in this joint venture, Northwind Boston, is not material. We do not currently have a substantial investment in BETG and do not anticipate it significantly impacting our results of operations in the next several years. 27 Other Matters Environmental We are subject to numerous federal, state and local standards with respect to waste disposal, air and water quality and other environmental considerations. These standards can require that we modify our existing facilities or incur increased operating costs. We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability. Through December 31, 1995, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any such additional costs to have a material impact on our financial condition. However, additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. Uncertainties continue to exist with respect to the disposal of both spent nuclear fuel and low-level radioactive waste (LLW) resulting from the operation of Pilgrim Station. The United States Department of Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel; however, there are uncertainties regarding the DOE's schedule of acceptance of spent fuel for disposal. In 1995 we regained access to the LLW disposal facility located in Barnwell, South Carolina. Refer to Note E to the Consolidated Financial Statements for further discussion regarding spent nuclear fuel and LLW disposal. As part of a 1991 DEP consent order, we are currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances. The station has the ability to burn natural gas, oil or both. We have arrangements for a firm supply of natural gas to run the station at a minimum level and are developing a least-cost plan for operating beyond this minimum level which principally utilizes interruptible gas supplies or short- term capacity purchases. The 1990 Clean Air Act Amendments require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel-fired generating units. The reduction will be accomplished by restricting sulfur dioxide emissions through a market-based system of allowances. We currently have allowances that are in excess of our needs and which may be marketable. Any gain from the sale of these allowances may be subject to future regulatory treatment. Other provisions of the 1990 Clean Air Act Amendments involve limitations on emissions of nitrogen oxides from existing generating units. Combustion system modifications made to New Boston and Mystic Stations, including the installation of low nitrogen oxides burners at New Boston, have 28 allowed the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain DEP air quality modeling studies currently in progress, additional emission reductions may also be required by 1999 or years thereafter. The extent of any additional emission restrictions and the cost of any further modifications is uncertain at this time. Public concern continues regarding electromagnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Such concerns have included the possibility of adverse health effects caused by EMF as well as perceived effects on property values. Some scientific reviews conducted to date have suggested associations between EMF and potential health effects, while other studies have not substantiated such associations. We support further research into the subject and are participating in the funding of industry-sponsored studies. We are aware that public concern regarding EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities in proceedings before regulators or in requests for legislation or regulatory standards concerning EMF levels. We have addressed issues relative to EMF in various legal and regulatory proceedings and in discussions with customers and other concerned persons; however, to date we have not been significantly affected by these developments. We continue to closely monitor all aspects of the EMF issue. Litigation In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. We have also been named as a party in a lawsuit by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs are claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. We believe that we have a strong defense in this case. We are also involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts previously accrued, although based on the information currently available, we do not expect that any such additional costs will have a material impact on our financial condition. However, additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. New accounting pronouncement Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, is effective in 1996. This statement establishes accounting standards for recognizing and measuring asset impairment losses. Refer to Note M to the Consolidated Financial Statements for more information regarding this statement and its potential effects. Safe harbor cautionary statement We occasionally make forward-looking statements such as forecasts and projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements. Actual results could potentially differ materially from these statements. Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved. 29 The above sections include certain forward-looking statements about the effects of the industry restructuring process and our related plan, operating results, Pilgrim Station's performance and environmental and legal issues. The effects of the industry restructuring process currently underway at the DPU and our related plan could differ from our expectations. This could occur as regulatory decisions and negotiated settlements between utilities and intervenors are finalized during the restructuring process. In addition, the development of a competitive electric generation market and the impacts of actual electric supply and demand in New England may affect the ultimate results of the industry restructuring and our plan. The impacts of our continued cost control procedures on our operating results could differ from our expectations. The effects of changes in economic conditions, tax rates, interest rates, technology and the prices and availability of operating supplies could materially affect our projected operating results. Pilgrim Station's performance could differ from our expectations. The station's capacity factor could be impacted by changes in regulations or by unplanned outages resulting from certain operating conditions. The impacts of various environmental and legal issues could differ from our expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect our estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect our estimated litigation costs. 30 Item 8. Financial Statements and Supplementary Financial Information - --------------------------------------------------------------------- Consolidated Statements of Income
years ended December 31, (in thousands, except earnings per share) 1995 1994 1993 - --------------------------------------------------------------------------- Operating revenues $1,628,503 $1,544,735 $1,482,159 - --------------------------------------------------------------------------- Operating expenses: Fuel 170,337 156,951 170,799 Purchased power 365,469 356,874 370,049 Other operations and maintenance 439,263 435,824 405,609 Restructuring costs 34,000 0 0 Depreciation and amortization 153,339 148,845 137,710 Amortization of deferred cost of cancelled nuclear unit 0 19,791 0 Amortization of deferred nuclear outage costs 18,933 7,721 6,546 Demand side management programs 45,125 35,438 37,504 Taxes - property and other 106,361 100,015 93,102 Income taxes 68,276 54,798 35,143 - --------------------------------------------------------------------------- Total operating expenses 1,401,103 1,316,257 1,256,462 - --------------------------------------------------------------------------- Operating income 227,400 228,478 225,697 Other income (expense), net (575) 3,979 211 - --------------------------------------------------------------------------- Operating and other income 226,825 232,457 225,908 - --------------------------------------------------------------------------- Interest charges: Long-term debt 106,640 102,570 104,375 Other 12,642 12,343 9,778 Allowance for borrowed funds used during construction (4,767) (7,478) (6,463) - --------------------------------------------------------------------------- Total interest charges 114,515 107,435 107,690 - --------------------------------------------------------------------------- Net income 112,310 125,022 118,218 Preferred dividends provided 15,571 15,765 15,705 - --------------------------------------------------------------------------- Balance available for common stock $ 96,739 $ 109,257 $ 102,513 =========================================================================== Weighted average common shares outstanding 46,592 45,338 44,959 Earnings per share of common stock $ 2.08 $ 2.41 $ 2.28 ===========================================================================
Consolidated Statements of Retained Earnings
years ended December 31, (in thousands) 1995 1994 1993 - --------------------------------------------------------------------------- Balance at beginning of year $ 247,004 $ 218,292 $ 192,948 Net income 112,310 125,022 118,218 - --------------------------------------------------------------------------- Subtotal 359,314 343,314 311,166 - --------------------------------------------------------------------------- Cash dividends declared: Preferred stock 15,571 15,765 15,705 Common stock 86,399 80,545 77,169 - --------------------------------------------------------------------------- Subtotal 101,970 96,310 92,874 - --------------------------------------------------------------------------- Balance at end of year $ 257,344 $ 247,004 $ 218,292 ===========================================================================
The accompanying notes are an integral part of the consolidated financial statements. 31 Consolidated Balance Sheets
December 31, (in thousands) 1995 1994 - ------------------------------------------------------------------------------ Assets Utility plant in service, at original cost $4,315,422 $4,074,810 Less: accumulated depreciation 1,439,996 $2,875,426 1,344,452 $2,730,358 - ------------------------------------------------------------------------------ Nuclear fuel 302,594 291,836 Less: accumulated amortization 251,951 50,643 236,239 55,597 - ------------------------------------------------------------------------------ Construction work in progress 29,573 144,048 - ------------------------------------------------------------------------------ Net utility plant 2,955,642 2,930,003 Investments in electric companies, at equity 23,620 24,678 Nuclear decommissioning trust 102,894 82,831 Current assets: Cash and cash equivalents 5,841 6,822 Accounts receivable 219,114 189,361 Accrued unbilled revenues 37,113 32,240 Fuel, materials and supplies, at average cost 59,631 71,560 Prepaid expenses and other 23,607 345,306 26,693 326,676 - ------------------------------------------------------------------------------ Deferred debits: Regulatory assets 156,774 198,148 Intangible asset - pension 27,386 22,849 Other 32,227 216,387 31,391 252,388 - ------------------------------------------------------------------------------ Total assets $3,643,849 $3,616,576 ============================================================================== Capitalization and Liabilities Common stock equity $ 989,438 $ 915,747 Cumulative preferred stock: Nonmandatory redeemable series 123,000 123,000 Mandatory redeemable series 92,000 94,000 Long-term debt 1,160,223 1,136,617 Current liabilities: Long-term debt/preferred stock due within one year $ 102,667 $ 102,250 Notes payable 126,441 214,786 Accounts payable 133,474 130,496 Accrued interest 25,113 24,464 Dividends payable 25,351 23,533 Pension benefits 32,602 31,908 Other 105,442 551,090 85,204 612,641 - ------------------------------------------------------------------------------ Deferred credits: Power contracts 21,396 40,277 Accumulated deferred income taxes 497,282 515,454 Accumulated deferred investment tax credits 62,970 67,048 Nuclear decommissioning reserve 113,288 92,404 Other 33,162 728,098 19,388 734,571 - ------------------------------------------------------------------------------ Commitments and contingencies - - - ------------------------------------------------------------------------------ Total capitalization and liabilities $3,643,849 $3,616,576 ==============================================================================
The accompanying notes are an integral part of the consolidated financial statements. 32 Consolidated Statements of Cash Flows
years ended December 31, (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Operating activities: Net income $112,310 $125,022 $118,218 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 148,630 142,932 130,074 Amortization of nuclear fuel 19,029 18,810 21,816 Amortization of deferred cost of cancelled nuclear unit, net 0 19,067 0 Amortization of deferred nuclear outage costs 18,933 7,721 6,546 Other amortization 15,702 14,692 10,158 Deferred income taxes (21,115) (4,184) 10,303 Investment tax credits (4,078) (4,092) (4,073) Allowance for borrowed funds used during construction (4,767) (7,478) (6,463) Net changes in: Accounts receivable and accrued unbilled revenues (34,626) (20,701) 13,206 Fuel, materials and supplies 7,202 3,093 9,722 Accounts payable 2,978 23,196 (18,916) Other current assets and liabilities 26,485 35,217 25,660 Other, net 23,975 14,847 (20,437) - ----------------------------------------------------------------------------- Net cash provided by operating activities 310,658 368,142 295,814 - ----------------------------------------------------------------------------- Investing activities: Plant expenditures (excluding AFUDC) (180,822) (198,771) (246,774) Nuclear fuel expenditures (13,621) (21,934) (6,491) Capitalized demand side management expenditures 0 (37,007) (37,156) Sale of plant assets, net 3,018 15,972 0 Nuclear decommissioning trust investments (20,063) (16,771) (15,189) Electric company investments 1,058 (386) 1,106 - ----------------------------------------------------------------------------- Net cash used by investing activities (210,430) (258,897) (304,504) - ----------------------------------------------------------------------------- Financing activities: Issuances: Common stock 64,888 10,634 10,855 Preferred stock 0 0 40,000 Long-term debt 125,000 15,000 815,000 Redemptions: Preferred stock (2,000) (2,000) (40,000) Long-term debt (100,600) (50,000) (648,625) Net change in notes payable (88,345) 10,635 (71,349) Dividends paid (100,152) (95,460) (92,370) - ----------------------------------------------------------------------------- Net cash provided (used) by financing activities (101,209) (111,191) 13,511 - ----------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents (981) (1,946) 4,821 Cash and cash equivalents at the beginning of the year 6,822 8,768 3,947 - ----------------------------------------------------------------------------- Cash and cash equivalents at the end of the year $ 5,841 $ 6,822 $ 8,768 ============================================================================= Cash paid during the year for: Interest, net of amounts capitalized $113,945 $108,462 $103,720 Income taxes $ 96,180 $ 46,074 $ 30,305
The accompanying notes are an integral part of the consolidated financial statements. 33 Notes to Consolidated Financial Statements Note A. Nature of Operations We are an investor-owned regulated public utility operating in the energy and energy services business. This includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. A portion of our generation is produced by a nuclear unit, Pilgrim Station. We supply electricity at retail to an area of 590 square miles, including the City of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues were 89% retail and 11% wholesale in 1995. Note B. Significant Accounting Policies 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company and Boston Energy Technology Group. All significant intercompany transactions have been eliminated. Certain prior period amounts on the financial statements were reclassified to conform with the current presentation. We follow accounting policies prescribed by our federal and state regulators, the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Public Utilities (DPU). We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company we are subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures 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 these estimates. 2. Revenues We record revenues for electricity used by our customers but not yet billed at the end of each accounting period. 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and some purchased power costs to be billed to customers using a forecasted rate. The difference between actual and estimated costs is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel. 34 4. Depreciation and Nuclear Fuel Amortization Our physical property was depreciated on a straight-line basis in 1995, 1994 and 1993 at composite rates of 3.10%, 3.11% and 3.09% per year, respectively, based on estimated useful lives of the various classes of property. The cost of decommissioning Pilgrim Station is excluded from these depreciation rates. When property units are retired, their cost, net of salvage value, is charged to accumulated depreciation. The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates. 5. Amortization of Deferred Nuclear Outage Costs We defer the incremental costs associated with nuclear refueling outages and amortize them over future periods. In 1995 we changed the amortization period to two years from five years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station. The change from the prior five-year amortization period approved in the 1992 settlement agreement was made following the DPU's August 1995 order on electric industry restructuring, which is discussed further in the Outlook for the Future section of Management's Discussion and Analysis. This order requires utilities to mitigate potentially strandable costs by available and reasonable means. The prior regulatory treatment of recovery over a five year period resulted in a significant lag between the expenditure and recovery of outage costs. We decided not to request recovery of the buildup of costs resulting from this regulatory lag. Accordingly, the remaining $9 million of deferred costs allocable to retail customers for refueling outages performed in 1991 and 1993 was written off. Approximately $15 million of deferred costs from the 1995 refueling outage is being amortized over two years. 6. Amortization of Discounts and Redemption Premiums on Debt We expense discounts, redemption premiums and related costs associated with issuances or redemptions of long-term debt or the refinancing of existing debt over the life of the debt or the replacement debt subject to regulatory approval. 7. Allowance for Funds Used During Construction (AFUDC) AFUDC represents the estimated costs to finance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1995, 1994 and 1993 were 6.35%, 4.45% and 3.62%, respectively, and represented only the cost of short-term debt. 8. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of three months or less when purchased. Outstanding checks are included in cash and accounts payable until presented for payment. 35 9. Allowance for Doubtful Accounts Our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance. 10. Regulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with agreements with the DPU. These costs are to be expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. No return on investment was earned on the regulatory assets. Regulatory assets consisted of the following:
December 31, 1995 1994 - ------------------------------------------------------------------ Redemption premiums $ 44,709 $52,859 Income taxes, net 46,121 44,745 Power contracts 21,396 40,277 Pension and postretirement costs 13,811 22,761 Nuclear outage costs 13,471 17,804 Other 17,266 19,702 - ------------------------------------------------------------------ $156,774 $198,148 ==================================================================
Note C. Rate Regulation In 1992 the DPU approved a three-year settlement agreement relating to our rate case proceedings. The agreement provided for retail rate increases, accounting adjustments and demand side management program expenditures; clarified the timing and recognition of certain expenses and set limits on our rate of return on common equity through 1995. In February 1996 we filed an industry restructuring plan with the DPU in response to its August 1995 order on restructuring the electric utility industry. This plan is expected to lead to negotiations with intervening parties that will result in new rates and performance incentives to be implemented in a new industry structure with a competitive generation market and incentive-regulated transmission and distribution systems. Refer to Management's Discussion and Analysis for further information regarding the restructuring of the electric utility industry in Massachusetts and our proposed plan. State regulatory proceedings do not affect our contract or wholesale power rates, which are regulated by the FERC. Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), which requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory assets of $46.1 million and $44.7 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1995, and December 31, 1994, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes. 36 Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 1995 1994 - ------------------------------------------------------------------------------ Deferred tax liabilities: Plant-related $521,280 $511,572 Other 95,148 105,786 - ------------------------------------------------------------------------------ 616,428 617,358 - ------------------------------------------------------------------------------ Deferred tax assets: Plant-related 12,590 13,216 Investment tax credits 40,632 43,273 Alternative minimum tax 0 1,332 Other 65,924 44,083 - ------------------------------------------------------------------------------ 119,146 101,904 - ------------------------------------------------------------------------------ Net accumulated deferred income taxes $497,282 $515,454 ==============================================================================
No valuation allowances for deferred tax assets are deemed necessary. Components of income tax expense were as follows:
years ended December 31, (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Current income tax expense $93,469 $63,358 $28,913 Deferred tax expense (21,115) (4,468) 10,303 Investment tax credits (4,078) (4,092) (4,073) - ----------------------------------------------------------------------------- Income taxes charged to operations 68,276 54,798 35,143 - ----------------------------------------------------------------------------- Taxes on other income: Current (1,729) 2,550 1,205 Deferred 0 284 0 - ----------------------------------------------------------------------------- (1,729) 2,834 1,205 - ----------------------------------------------------------------------------- Total income tax expense $66,547 $57,632 $36,348 =============================================================================
The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
1995 1994 1993 - ----------------------------------------------------------------------------- Statutory tax rate 35.0% 35.0% 35.0% State income tax, net of federal income tax benefit 4.3 4.3 4.2 Investment tax credits (2.3) (2.3) (2.6) Municipal property tax adjustment - - (0.6) Reversal of deferred taxes - settlement agreement - (5.5) (13.0) Other 0.1 (0.1) 0.4 - ----------------------------------------------------------------------------- Effective tax rate 37.1% 31.4% 23.4% =============================================================================
Note E. Nuclear Decommissioning and Nuclear Waste Disposal 1. Nuclear Decommissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We are currently expensing an estimate of the decommissioning costs over Pilgrim's expected service life. The 1995 expense of approximately $14 million is included in depreciation expense on the consolidated income statement. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the "green field" method, which provides for the plant site to be completely restored to its original state. The cost estimate, which involves many uncertainties, was incorporated in our 37 1992 retail settlement agreement. We receive recovery of the annual expense from charges to our retail customers and from other utility companies and municipalities which purchase a contracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted so that they may only be used for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning fund balance and nuclear decommissioning reserve, thus reducing the amount to be collected from customers. The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact of long-term spent fuel storage options resulting from delays in the United States Department of Energy (DOE) spent fuel removal program. (See part 2 below for a discussion of spent fuel removal.) The partial update indicates an estimated decommissioning cost of $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. No further update is currently available; however, we will continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate. In February 1996 the Financial Accounting Standards Board (FASB) issued proposed new rules for accounting for liabilities related to closure and removal of long-lived assets, which includes decommissioning. If these draft rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to nuclear plant. The plant addition would be depreciated over Pilgrim's expected service life. The liability would be measured based on the present value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for decommissioning. If it is not probable that we could recover these costs from customers, we would have to charge the cumulative effect of the difference to income instead of recording a regulatory asset. In addition, trust fund earnings would be reported on the income statement. 2. Spent Nuclear Fuel The spent fuel storage facility at Pilgrim Station provides storage capacity through approximately 2003. We have a license amendment from the Nuclear Regulatory Commission to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the DPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies. It is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. The DOE is conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political opposition and the DOE has publicly stated that it may be unable to construct such a repository in a timely manner. In 1994 we and other interested parties filed petitions in the U.S. Court of 38 Appeals for the D.C. Circuit seeking declaratory rulings that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. The DOE has sought to dismiss those petitions and a court ruling is awaited. It is unknown at this time whether and on what schedule the DOE will eventually construct a spent fuel repository and what the effect on us will be of any delays in such construction. 3. Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us. Legislation has been enacted in Massachusetts establishing a regulatory process for managing the state's LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agreement with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management procedure, we will continue to monitor the situation and investigate other available options. 4. Other Nuclear Units We are an investor in and customer of two other domestic nuclear units. Both of these units receive, through the rates charged to their customers, an amount to cover the estimated costs to dispose of their spent nuclear fuel and to decommission the units at the end of their useful lives. Note F. Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement programs and implemented a special severance program to reduce employee staffing levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million net of tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 million for the severance program. The enhanced retirement programs were offered to all employees at least 55 years old, with different years of service requirements for management and union employees. The programs provided for supplemental salary payments and waivers of the early retirement pension reduction and the medical and life insurance benefits years of service requirement. The special severance program was provided for all employees whose positions were eliminated in the reorganization, who were all management and administrative support personnel. Severance benefits provided were salary payments, medical insurance and outplacement services. The retirement programs' pension and medical and life insurance benefits, totalling $16 million, will be paid from pension and employee benefit trusts. The liabilities to the trusts are included on the consolidated balance sheet at December 31, 1995, in pension benefits and other current liabilities. All other benefits are being paid from general corporate funds. As of December 31, 1995, $10 million had been paid and $8 million remained in other current liabilities. 39 Note G. Pensions and Other Postretirement Benefits 1. Pensions We have a defined benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market funds, insurance contracts and real estate funds. We also have a supplemental pension plan for certain management employees. Benefits under this plan are based on final compensation upon retirement. The plan is not funded. The plan's cost and benefit obligation amounts are included in the following pension information for 1995. Amounts related to the plan prior to 1995 were not material to our total pension costs and obligations. Net pension cost consisted of the following components:
years ended December 31, (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Current service cost - benefits earned $11,339 $15,057 $ 11,734 Interest cost on projected benefit obligation 31,789 33,961 33,181 Actual net loss/(return) on plan assets (72,192) 214 (44,470) Net amortization and deferral 49,557 (32,169) 8,528 - ----------------------------------------------------------------------------- Net pension cost (a) $20,493 $17,063 $ 8,973 ============================================================================= (a) In accordance with our 1992 settlement agreement we deferred the difference in the net pension cost of the retirement plan and its annual funding amount. Net deferred costs amounted to ($1.2) million and $6.5 million at December 31, 1995 and 1994, respectively. Total net pension costs recorded as expense in 1995, 1994 and 1993 were $28 million, $25 million and $5 million, respectively.
We used the following assumptions for calculating pension cost:
1995 1994 1993 - ----------------------------------------------------------------------------- Discount rate 8.25% 7.00% 8.25% Expected long-term rate of return on assets 10.00% 10.00% 10.00% Compensation increase rate 3.90% 4.50% 4.50% - -----------------------------------------------------------------------------
40 The pension plans' funded status was as follows:
December 31, (in thousands) 1995 1994 - ----------------------------------------------------------------------------- Actuarial present value of benefit obligations: Accumulated benefit obligation, including vested benefits of $386,020 and $305,632 (b) $401,329 $321,072 ============================================================================= Plan assets at fair value $358,572 $289,164 Projected obligation for service rendered to date (487,702) (387,910) - ----------------------------------------------------------------------------- Projected benefit obligation in excess of plan assets (129,130) (98,746) Unrecognized prior service cost 22,506 13,328 Unrecognized net loss 83,187 67,361 Unrecognized net obligation 8,064 8,998 Minimum liability adjustment (c) (27,386) (22,849) - ----------------------------------------------------------------------------- Net pension liability (d) $(42,759) $(31,908) ============================================================================= (b) The accumulated benefit obligation at December 31, 1995, includes $13.5 million related to the enhanced retirement programs offered in 1995 as discussed in Note F. (c) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SFAS 87), requires the recognition of an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SFAS 87 we recorded additional minimum liabilities and corresponding intangible assets of $27 million and $23 million on our consolidated balance sheets at December 31, 1995 and 1994, respectively. (d) Net pension liability included on the consolidated balance sheets in current liabilities is $33 million and $32 million, and in deferred credits is $10 million and $0 at December 31, 1995 and 1994, respectively.
We used the following assumptions for calculating the plans' year-end funded status:
1995 1994 - ----------------------------------------------------------------------------- Discount rate 7.25% 8.25% Compensation increase rate 3.90% 3.90% - -----------------------------------------------------------------------------
We also provide defined contribution 401(k) plans for substantially all our employees. We match a percentage of employees' voluntary contributions to the plans, which amounted to $9 million in 1995, $8 million in 1994 and $7 million in 1993. 2. Other Postretirement Benefits In addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). Our 1992 settlement agreement provides us with a five-year expense phase-in of the PBOP costs incurred under SFAS 106 and allows us to defer any costs in excess of the phase-in amounts to the extent that we fund an external trust. Our funding policy is to contribute 100% of 41 postretirement benefits costs to external trusts. Accordingly, we recorded expenses of $23 million in 1995, $17 million in 1994 and $15 million in 1993, reflecting the amount of current cost recovery from customers. Net deferred costs amounted to $15 million and $16 million at December 31, 1995 and 1994, respectively. Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Current service cost - benefits earned $ 3,408 $ 4,978 $ 4,351 Interest cost on accumulated benefit obligation 13,521 13,632 14,286 Actual return on plan assets (7,151) (187) 0 Amortization of transition obligation 9,151 9,151 9,151 Net amortization and deferral 3,017 (2,581) 0 - ----------------------------------------------------------------------------- Net postretirement benefits cost $21,946 $24,993 $27,788 =============================================================================
We used the following assumptions for calculating postretirement benefits cost:
1995 1994 1993 - ----------------------------------------------------------------------------- Discount rate 8.25% 7.00% 8.00% Expected long-term rate of return on assets 9.00% 9.00% 9.00% Health care cost trend rate 7.00% 9.00% 12.50% - -----------------------------------------------------------------------------
The health care cost trend rate is assumed to decrease by one percent in 1996 and 1997 and to remain at 5% in years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. A one percent increase in the assumed health care cost trend rate would increase the total service and interest cost components by 8% and would increase the accumulated benefit obligation at December 31, 1995, by 7.5%. The postretirement benefits program's funded status was as follows:
December 31, (in thousands) 1995 1994 - ----------------------------------------------------------------------------- Trust assets at fair value $ 51,064 $ 33,300 Accumulated obligation for service rendered to date from: Retirees $(110,877) $(93,960) Active employees eligible to retire (31,980) (31,159) Active employees not eligible to retire (53,514) (196,371) (51,545) (176,664) - ----------------------------------------------------------------------------- Accumulated benefit obligation in excess of trust assets (145,307) (143,364) Unrecognized prior service cost (17,889) (19,502) Unrecognized net (gain)/loss 5,612 (1,849) Unrecognized transition obligation 155,564 164,715 - ----------------------------------------------------------------------------- Net postretirement benefits liability $ (2,020) $ 0 =============================================================================
The net postretirement benefits liability at December 31, 1995, represents the additional PBOP obligation from the enhanced retirement programs offered in 1995 (see Note F). This additional amount was not funded as part of the 1995 PBOP cost. The weighted average discount rates used to measure the accumulated benefit obligation were 7.25% in 1995 and 8.25% in 1994. The trust assets consist of equities, bonds and money market funds. 42 Note H. Eminent Domain Taking In November 1994 a Norfolk Superior Court ruling against the Massachusetts Metropolitan District Commission (MDC) became effective, providing us with an additional $5.7 million gain on an eminent domain land-taking case. We had filed suit against the MDC in 1992 related to the eminent domain taking of certain of our property in 1989. Note I. Cancelled Nuclear Unit In 1982 we began expensing the cost of our cancelled Pilgrim 2 nuclear unit over approximately eleven and one-half years in accordance with an order received from the DPU. We did not expense any of these costs in 1993. The remaining balance of $19 million was fully expensed in 1994 as allowed by our 1992 settlement agreement. 43 Note J. Capital Stock
December 31, (dollars in thousands, except per share amounts) 1995 1994 1993 - ------------------------------------------------------------------------------ Common stock equity: Common stock, par value $1 per share, 100,000,000 shares authorized; 48,003,178, 45,535,477 and 45,129,227 shares issued and outstanding: $ 48,003 $ 45,535 $ 45,129 Premium on common stock 683,686 622,803 612,653 Retained earnings 257,344 247,004 218,292 Surplus invested in plant 405 405 405 - ------------------------------------------------------------------------------ Total common stock equity $989,438 $915,747 $876,479 ==============================================================================
Cumulative preferred stock: Par value $100 per share, 2,890,000 shares authorized; issued and outstanding: Nonmandatory redeemable series:
Current Shares Redemption Series Outstanding Price/Share - ------------------------------------------------------------------------------ 4.25% 180,000 $103.625 $ 18,000 $ 18,000 $ 18,000 4.78% 250,000 $102.800 25,000 25,000 25,000 7.75% 400,000 - 40,000 40,000 40,000 8.25% 400,000 - 40,000 40,000 40,000 - ------------------------------------------------------------------------------ Total nonmandatory redeemable series $123,000 $123,000 $123,000 ==============================================================================
Mandatory redeemable series:
Current Shares Redemption Series Outstanding Price/Share - ------------------------------------------------------------------------------ 7.27% 440,000 $103.390 $ 44,000 $ 46,000 $ 48,000 8.00% 500,000 - 50,000 50,000 50,000 - ------------------------------------------------------------------------------ Total mandatory redeemable series 94,000 96,000 98,000 Less: due within one year 2,000 2,000 2,000 - ------------------------------------------------------------------------------ Total mandatory redeemable series, net $ 92,000 $ 94,000 $ 96,000 ==============================================================================
Dividends Declared per Share Common stock $ 1.835 $ 1.775 $ 1.715 Preferred stock: 4.25% series $ 4.250 $ 4.250 $ 4.253 4.78% series 4.780 4.780 4.785 7.27% series 7.270 7.270 7.270 7.75% series 7.750 7.750 5.707 8.00% series 8.000 8.000 8.000 8.25% series 8.250 8.250 8.250 8.88% series 0 0 2.220
44 1. Common Stock Common stock issuances in 1993 through 1995 were as follows:
Number Total Premium on (in thousands) of Shares Par Value Common Stock - ------------------------------------------------------------------------------ Balance December 31, 1992 44,763 $44,763 $602,196 Dividend reinvestment plan 366 366 10,457 - ------------------------------------------------------------------------------ Balance December 31, 1993 45,129 45,129 612,653 Dividend reinvestment plan 406 406 10,150 - ------------------------------------------------------------------------------ Balance December 31, 1994 45,535 45,535 622,803 Dividend reinvestment plan (a) 468 468 11,404 New issuances (b) 2,000 2,000 49,479 - ------------------------------------------------------------------------------ Balance December 31, 1995 48,003 $48,003 $683,686 ============================================================================== (a) At December 31, 1995, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 1,941,219 shares. (b) We used the net proceeds of the 1995 common stock issuances to reduce short-term debt.
2. Cumulative Nonmandatory Redeemable Preferred Stock In 1993 we issued 400,000 shares of 7.75% cumulative nonmandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in May 1998. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulative nonmandatory redeemable preferred stock. 3. Cumulative Mandatory Redeemable Preferred Stock The 440,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $103.390. The redemption price declines annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each May to redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends. We are not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share, plus accrued dividends. 45 Note K. Indebtedness
December 31, (in thousands) 1995 1994 - ------------------------------------------------------------------------------ Long-term debt: Debentures: 8.875%, due December 1995 $ 0 $ 100,000 5.125%, due March 1996 100,000 100,000 5.700%, due March 1997 100,000 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 0 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 - ------------------------------------------------------------------------------ Total debentures 1,215,000 1,190,000 Less: due within one year 100,000 100,000 - ------------------------------------------------------------------------------ Net long-term debentures 1,115,000 1,090,000 - ------------------------------------------------------------------------------ Sewage facility revenue bonds 35,700 36,300 Less: due within one year 1,600 600 Less: funds held by trustee 3,877 4,083 - ------------------------------------------------------------------------------ Net long-term sewage facility revenue bonds 30,223 31,617 - ------------------------------------------------------------------------------ Massachusetts Industrial Finance Agency bonds: 5.750%, due February 2014 15,000 15,000 - ------------------------------------------------------------------------------ Total long-term debt $1,160,223 $1,136,617 ============================================================================== Short-term debt: Notes payable: Bank loans $ 75,941 $ 80,786 Commercial paper 50,500 134,000 - ------------------------------------------------------------------------------ Total notes payable $ 126,441 $ 214,786 ==============================================================================
1. Long-Term Debt In 1994 the Massachusetts Industrial Finance Agency, on our behalf, issued $15 million of 5.75% tax-exempt unsecured bonds due in 2014. The bonds are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006. The proceeds from this issuance together with sufficient other funds were used to fully redeem the Series U first mortgage bonds. In 1994 we redeemed at par the $25 million of variable rate Series S first mortgage bonds. As a result of the redemption of all outstanding first mortgage bonds, the Indenture of Trust and First Mortgage that had mortgaged substantially all our property since 1940 was terminated in November 1994. In May 1995 we issued $125 million of 7.80% debentures due in 2010. We used the net proceeds from this issuance to reduce short-term debt. The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable 46 in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity. There is no sinking fund requirement for any series of our debentures. Sewage facility revenue bonds were issued by Harbor Electric Energy Company (HEEC), a wholly owned subsidiary. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In May 1995 $0.6 million was redeemed as scheduled. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million. The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2000 are $101.6 million per year in 1996 through 1998, $1.6 million in 1999 and $166.6 million in 2000. 2. Short-Term Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have authority to issue up to $350 million of short-term debt. We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. Information regarding our short-term borrowings, comprised of bank loans and commercial paper, is as follows:
(dollars in thousands) 1995 1994 1993 - ----------------------------------------------------------------------------- Maximum short-term borrowings $327,769 $268,100 $320,000 Weighted average amount outstanding $165,720 $214,640 $220,149 Weighted average interest rates excluding commitment fees 6.2% 4.5% 3.4% - -----------------------------------------------------------------------------
Note L. Fair Value of Securities The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value: Nuclear decommissioning trust: The cost of $102.9 million approximates fair value based on quoted market prices of securities held. Cash and cash equivalents: The carrying amount of $5.8 million approximates fair value due to the short-term nature of these securities. 47 Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt: The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 1995, are as follows:
Carrying Fair (in thousands) Amount Value - ------------------------------------------------------------------------------ Mandatory redeemable cumulative preferred stock $ 94,000 $ 98,005 Sewage facility revenue bonds 35,700 38,446 Unsecured debt 1,230,000 1,276,213 - ------------------------------------------------------------------------------
Note M. New Accounting Pronouncement In 1995 the FASB issued Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of (SFAS 121), effective in 1996. This statement clarifies when and how to recognize asset impairments. In addition, SFAS 121 requires that all regulatory assets, which must have a high probability of recovery to be initially established, continue to meet that high probability standard or be written off. However, if written off, a regulatory asset can be restored if it regains a high probability of recovery. The impact of this standard on our plant and regulatory assets will be determined by regulatory changes implemented by the DPU and FERC. Based on the transition principles of the DPU's order on industry restructuring and our related plan, which are discussed in the Outlook for the Future section of Management's Discussion and Analysis, we do not expect SFAS 121 to have an adverse impact on our financial position or results of operations in the near term. Our conclusion may change as the actual shape of restructuring of the industry in Massachusetts develops. If recovery of our plant and regulatory assets is not provided, SFAS 121 could require a write-down of these assets. Note N. Commitments and Contingencies 1. Contractual Commitments At December 31, 1995, we had estimated contractual obligations for plant and equipment of approximately $35 million. We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1995 are as follows:
(in thousands) - ------------------------------------------------------ 1996 $ 24,908 1997 22,109 1998 19,002 1999 17,408 2000 16,656 Years thereafter 108,417 - ------------------------------------------------------ Total $208,500 ======================================================
We will capitalize a portion of these lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $24.5 million in 1995, $28.6 million in 1994 and $29.8 million in 1993, net of capitalized expenses of $2.7 million in 1995, $2.4 million in 1994 and $5.2 million in 1993. 48 We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply New Boston Station with natural gas. The fixed and determinable portions of the obligations are $16.1 million in 1996, 1997 and 1998, $24.8 million in 1999 and $13.8 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $13.9 million in 1995, and $6.5 million in 1994 and 1993. 2. Hydro-Quebec We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included on our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria and are compensated accordingly. At December 31, 1995, our portion of these guarantees was approximately $19 million. 3. Yankee Atomic Electric Company We have a 9.5% stock investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the Board of Directors of Yankee Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and decommission the facility. We relied on Yankee Atomic for less than one percent of our system capacity under a long-term purchased power contract. Yankee Atomic received approval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $21 million as of December 31, 1995. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement. 4. Nuclear Insurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately $8.3 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 110 units licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional five percent of the maximum retrospective assessment. We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is $15 million under both 49 the replacement power and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses are in excess of the total funds available to NEIL. While additional assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in any such assessment. 5. Litigation In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. We have also been named as a party in a lawsuit by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs are claiming certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from New Boston Station. We believe that we have a strong defense in this case. We are also involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts previously accrued, although based on the information currently available, we do not expect that any such additional costs will have a material impact on our financial condition. However, additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. 6. Hazardous Waste We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability. Through December 31, 1995, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any such additional costs to have a material impact on our financial condition. However, additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. 50 Note O. Long-Term Power Contracts 1. Long-Term Contracts for the Purchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of the generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidated income statements. Information relating to these contracts as of December 31, 1995, is as follows:
proportionate share (in thousands) - ------------------------------------------------------------------------------ Units of 1995 1995 Interest Debt Contract Capacity Minimum Portion of Outstanding Expiration Purchased(a) Debt Minimum Through Cont. Generating Unit Date % MW Service Debt Service Exp. Date - ------------------------------------------------------------------------------ Canal Unit 1 2001 25.0 139 $ 1,122 $ 349 $ 3,400 Mass. Bay Trans- portation Authority - 1 2005 100.0 34 (b) (b) (b) Connecticut Yankee Atomic 2007 9.5 55 2,646 1,786 13,857 Ocean State Power - Unit 1 2010 23.5 67 4,819 3,318 20,749 Ocean State Power - Unit 2 2011 23.5 66 4,090 3,049 17,228 Northeast Energy Associates (c) (c) 219 (c) (c) (c) L'Energia 2013 73.0 64 (d) (d) (d) MassPower (e) 2013 44.3 117 12,217 7,662 81,983 Mass. Bay Trans- portation Authority - 2 2019 100.0 34 (f) (f) (f) - ------------------------------------------------------------------------------ Total 795 $24,894 $16,164 $137,217 ============================================================================== (a) The Northeast Energy Associates contract represents 5.9% of our total system generation capability. The remaining units listed above represent 15.6% in total. (b) We are required to pay the greater of $22.00 per kilowatt-year or 90% of the New England Power Pool capability responsibility adjustment charge up to $63.00 per kilowatt-year times the qualified capacity (currently rated at 34MW), plus incremental operating, maintenance and fuel costs. The total charges for this contract in 1995 were approximately $2 million. (c) We purchase approximately 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for this energy based on a price per kWh actually received. We do not pay a proportionate share of the unit's capital and fixed operating costs. The total charges for these contracts in 1995 were approximately $127 million. (d) We pay for this energy based on a price per kWh actually received. The total charges under this contract for 1995 were approximately $25 million. 51 (e) Payments for this contract are based on a stipulated price per MW rating of the unit subject to the unit maintaining a twelve-month average availability of at least 90%. Payments are adjusted proportionately if the twelve-month average is below 90%. If the twelve-month average is less than 10%, no payment is required. Total charges for this contract in 1995 were approximately $49 million. (f) The second Massachusetts Bay Transportation Authority contract started in June 1995. Capacity payments under this contract do not begin until 2003. At that time we will be required to pay $84.57 per kilowatt-year times the qualified capacity plus incremental operating maintenance and fuel costs.
Our total fixed and variable costs for these contracts in 1995, 1994 and 1993 were approximately $283 million, $286 million and $225 million, respectively. Our minimum fixed payments under these contracts for the years after 1995 are as follows:
(in thousands) - ------------------------------------------------------ 1996 $ 106,649 1997 103,682 1998 105,778 1999 105,258 2000 103,676 Years thereafter 1,187,672 - ------------------------------------------------------ Total $1,712,715 ====================================================== Total present value $ 883,409 ======================================================
2. Long-Term Power Sales In addition to wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts. Information relating to these contracts is as follows:
Contract Expiration Units of Capacity Sold Contract Customer Date % MW - ------------------------------------------------------------------------------ Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 Various municipalities 2000(a) 3.7 25.0 - ------------------------------------------------------------------------------ Total 25.7 172.4 ============================================================================== (a) Subject to certain adjustments.
Under these contracts, the utilities pay their proportional share of the costs of operating Pilgrim Station and associated transmission facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decommissioning and a return on capital. 52 Selected Consolidated Quarterly Financial Data (Unaudited) (in thousands, except earnings per share)
Balance Available Earnings Operating Operating Net for Common Per Average Revenues Income Income Stock Common Share(a) - -------------------------------------------------------------------------- 1995 - ---- First quarter $379,678 $ 47,610 $20,202 $16,300 $0.36 Second quarter 380,828 55,683 26,137 22,247 0.48 Third quarter 498,554 102,695(b) 72,368 (b) 68,478 (b) 1.46 (b) Fourth quarter 369,443 21,412(b) (6,397)(b) (10,286)(b) (0.21)(b) 1994 - ---- First quarter $376,935 $ 45,891 $19,812 $15,850 $0.35 Second quarter 368,245 50,812 23,982 20,031 0.44 Third quarter 448,179 96,880 70,182 66,256 1.46 Fourth quarter 351,376 34,895 11,046 7,120 0.16 (a) Based on the weighted average number of common shares outstanding during the quarter. (b) As discussed in Note F to the Consolidated Financial Statements, we incurred a $34 million pre-tax charge related to our corporate restructuring over the third and fourth quarters of 1995. Amounts excluding the restructuring charge are as follows:
Balance Available Earnings Operating Net for Common Per Average Income Income Stock Common Share - -------------------------------------------------------------------------- Third quarter $107,779 $77,452 $73,562 $1.57 Fourth quarter 36,991 9,182 5,293 0.11
Certain reclassifications were made to the data reported in prior periods to conform with the current method of presentation. Item 9. Changes in and Disagreements with Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure - -------------------- Not applicable. 53 Part III -------- Item 10. Directors and Executive Officers of the Registrant - ------------------------------------------------------------ (a) Identification of Directors - --------------------------------- See "Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference. (b) Identification of Executive Officers - ----------------------------------------- The information required by this item is included at the end of Part I of this Form 10-K under the caption Executive Officers of the Registrant. (c) Identification of Certain Significant Employees - ---------------------------------------------------- Not applicable. (d) Family Relationships - ------------------------- Not applicable. (e) Business Experience - ------------------------ For information relating to the business experience during the past five years and other directorships (of companies subject to certain SEC requirements) held by each person nominated to be a director, see "Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference. For information relating to the business experience during the past five years of each person who is an executive officer, see Executive Officers of the Registrant in this Form 10-K. (f) Involvement in Certain Legal Proceedings - --------------------------------------------- Not applicable. (g) Promoters and Control Persons - ---------------------------------- Not applicable. Item 11. Executive Compensation - -------------------------------- See "Director and Executive Compensation" on pages 6 through 12 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference 54 Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------ (a) Security Ownership of Certain Beneficial Owners - ---------------------------------------------------- To the knowledge of management, no person owns beneficially more than five percent of the outstanding voting securities of the Company. (b) Security Ownership of Management - ------------------------------------- See "Stock Ownership by Directors and Executive Officers" on page 5 of the definitive proxy statement dated March 28, 1996, incorporated herein by reference. (c) Changes in Control - ----------------------- Not applicable. Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Not applicable. 55 Part IV ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - ------------------------------------------------------------------------- (a) The following documents are filed as part of this Form 10-K:
Page ---- Consolidated Statements of Income for the three years ended December 31, 1995, 1994 and 1993 30 Consolidated Statements of Retained Earnings for the three years ended December 31, 1995, 1994 and 1993 30 Consolidated Balance Sheets as of December 31, 1995 and 1994 31 Consolidated Statements of Cash Flows for the three years ended December 31, 1995, 1994 and 1993 32 Notes to Consolidated Financial Statements 33 Selected Consolidated Quarterly Financial Data (Unaudited) 52 Report of Independent Accountants 66
No financial statement schedules are prepared as they are either not required or not applicable. 56
Exhibit SEC Docket ------- ---------- Exhibit 3 Articles of Incorporation and By-Laws - --------- ------------------------------------- Incorporated herein by reference: 3.1 Restated Articles of Organization 3.1 1-2301 Form 10-Q for the quarter ended June 30, 1994 3.2 Boston Edison Company Bylaws 3.1 1-2301 April 19, 1977, as amended Form 10-Q January 22, 1987, January 28, 1988, for the May 24, 1988 and November 22, 1989 quarter ended June 30, 1990 Exhibit 4 Instruments Defining the Rights of - --------- ---------------------------------- Security Holders, Including Indentures -------------------------------------- Incorporated herein by reference: 4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301 dated September 1, 1988, between Form 10-Q Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 4.1.1 First Supplemental Indenture 4.1 1-2301 dated June 1, 1990 to Form 8-K Indenture dated September 1, 1988 dated with Bank of Montreal Trust Company - June 28, 1990 9 7/8% debentures due June 1, 2020 4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301 the City of Boston, Massachusetts Form 10-K (acting by and through its Industrial for the Development Financing Authority) and year ended Harbor Electric Energy Company and December 31, Shawmut Bank, N.A., as Trustee, dated 1991 November 1, 1991 4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 5, 1991 re for the 9 3/8% debentures due August 15, 2021 year ended December 31, 1991
57
Exhibit SEC Docket ------- ---------- 4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K for the year ended December 31, 1992 4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301 Board of Directors of Boston Edison Form 10-K Company taken September 10, 1992 re for the 8 1/4% debentures due September 15, 2022 year ended December 31, 1992 4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301 Board of Directors of Boston Edison Form 10-K Company taken January 27, 1993 re for the 6.80% debentures due February 1, 2000 year ended December 31, 1992 4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken March 5,1993 re for the 5 1/8% debentures due March 15, 1996, year ended 5.70% debentures due March 15, 1997, December 31, 5.95% debentures due March 15, 1998, 1992 6.80% debentures due March 15, 2003, 7.80% debentures due March 15, 2023 4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 18, 1993 re for the 6.05% debentures due August 15, 2000 year ended December 31, 1993 Filed herewith: 4.1.9 Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010
58
Exhibit SEC Docket ------- ---------- 4.1.10 First Amendment to Revolving Credit Agreement The Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long-term debt whose authorization does not exceed 10% of the Company's total assets. Exhibit 10 Material Contracts - ---------- ------------------ Incorporated herein by reference: 10.1 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, May Form 10-Q 1986 for the quarter ended June 30, 1986 10.1.1 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May Form 10-K 1986, with modifications for the year ended December 31, 1991 10.2 Executive Annual Incentive 10.5 1-2301 Compensation Plan Form 10-K for the year ended December 31, 1988 10.3 1991 Director Stock Plan 10.1 1-2301 Form 10-Q for the quarter ended March 31, 1991 10.4 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 1, 1990 Form 10-K for the year ended December 31, 1992
59
Exhibit SEC Docket ------- ---------- 10.5 Deferred Compensation Trust 10.10 1-2301 between Boston Edison Company Form 10-K and State Street Bank and for the Trust Company dated year ended February 2, 1993 December 31, 1992 10.5.1 Amendment No. 1 to Deferred 10.5.1 1-2301 Compensation Trust dated Form 10-K March 31, 1994 for the year ended December 31, 1994 10.6 Directors Retirement Benefit 10.8.1 1-2301 (1993 Plan) Form 10-K for the year ended December 31, 1993 10.7 Description of Supplemental Fee 10.7 1-2301 Arrangement for Certain Directors Form 10-K for the year ended December 31, 1994 10.8 Performance Share Plan, Amendment 10.8 1-2301 and Restatement dated October 24, 1994 Form 10-K for the year ended December 31, 1994 10.9 Boston Edison Company Deferred 10.9 1-2301 Compensation Plan, Amendment and Form 10-K Restatement dated January 31, 1995 for the year ended December 31, 1994 10.10 Employment Agreement applicable to 10.10 1-2301 Ronald A. Ledgett dated April 30, 1987 Form 10-K for the year ended December 31, 1994
60
Exhibit SEC Docket ------- ---------- Exhibit 12 Statement re Computation of Ratios - ---------- ---------------------------------- Filed herewith: 12.1 Computation of Ratio of Earnings to Fixed Charges for the Year Ended December 31, 1995 12.2 Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year Ended December 31, 1995 Exhibit 21 Subsidiaries of the Registrant - ---------- ------------------------------ 21.1 Harbor Electric Energy Company (incorporated in Massachusetts), a wholly owned subsidiary of Boston Edison Company 21.2 Boston Energy Technology Group, Inc. (incorporated in Massachusetts), a wholly owned subsidiary of Boston Edison Company 21.3 Ener-G-Vision, Inc. (incorporated in Massachusetts), a wholly owned subsidiary of Boston Energy Technology Group, Inc. 21.4 TravElectric Services Corporation (incorporated in Massachusetts), a wholly owned subsidiary of Boston Energy Technology Group, Inc. 21.5 REZ-TEK International Corporation (incorporated in Massachusetts), a majority owned subsidiary of Boston Energy Technology Group, Inc. 21.6 Coneco Corporation (incorporated in Massachusetts), a majority owned subsidiary of Boston Energy Technology Group, Inc.
61
Exhibit SEC Docket ------- ---------- Exhibit 23 Consent of Independent Accountants - ---------- ---------------------------------- Filed herewith: 23.1 Consent of Independent Accountants to incorporate by reference their opinion included with this Form 10-K in the Form S-3 Registration Statements filed by the Company on September 14, 1990 (File No. 33-36824), February 3, 1993 (File No. 33-57840), May 31, 1995 (File No. 33-59693) and in the Form S-8 Registration Statements filed by the Company on October 10, 1985 (File No. 33-00810), July 28, 1986 (File No. 33-7558), December 31, 1990 (File No. 33-38434), June 5, 1992 (33-48424 and 33-48425), March 17, 1993 (33-59662 and 33-59682) and April 6, 1995 (33-58457) Exhibit 27 Financial Data Schedule - ---------- ----------------------- Filed herewith: 27.1 Schedule UT Exhibit 99 Additional Exhibits - ---------- ------------------- Incorporated herein by reference: 99.1 DPU Settlement Agreement with 28.1 1-2301 Boston Edison Company dated Form 8-K October 3, 1989 dated October 3, 1989 99.2 Settlement Agreement between Boston 28.1 1-2301 Edison Company and Commonwealth Form 8-K Electric Company, Montaup Electric dated Company and the Municipal December 21, Light Department of the Town of 1989 Reading, Massachusetts, dated January 5, 1990 99.3 Pilgrim Outage Case Settlement between 28.2 1-2301 Boston Edison Company and Reading Form 8-K Municipal Light Department regarding dated Contract Demand Rate, dated December December 21, 21, 1989 1989
62
Exhibit SEC Docket ------- ---------- 99.4 Settlement Agreement Between Boston 28.2 1-2301 Edison Company and City of Holyoke Form 10-Q Gas and Electric Department et. al., for the dated April 26, 1990 quarter ended March 31, 1990 99.5 Information required by SEC Form 1-2301 11-K for certain Company employee Form 10-K/A benefit plans for the years ended Amendments to December 31, 1994, 1993 and 1992 Form 10-K for the years ended December 31, 1994 and 1993 and Form 8 Amendment to Form 10-K for the year ended December 31, 1992 dated June 29, 1995, June 30, 1994 and June 29, 1993, respectively 99.6 DPU Settlement Agreement with 28.2 1-2301 Boston Edison Company, dated Form 10-Q October 23, 1992 for the quarter ended September 30, 1992
63 (b) Reports on Form 8-K: There were no Form 8-K's filed during the fourth quarter of 1995. 64 SIGNATURES ---------- Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BOSTON EDISON COMPANY By: /s/ James J. Judge --------------------------------------- James J. Judge Senior Vice President and Treasurer (Principal Financial Officer) Date: March 28, 1996 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 indicated on the 28th day of March 1996. /s/ Thomas J. May Chairman of the Board, President - ------------------------------------- and Chief Executive Officer Thomas J. May /s/ Robert J. Weafer, Jr. Vice President - Finance, - ------------------------------------- Controller and Chief Accounting Robert J. Weafer, Jr. Officer /s/ William F. Connell Director - ------------------------------------- William F. Connell /s/ Gary L. Countryman Director - ------------------------------------- Gary L. Countryman /s/ Thomas G. Dignan, Jr. Director - ------------------------------------- Thomas G. Dignan, Jr. /s/ Charles K. Gifford Director - ------------------------------------- Charles K. Gifford /s/ Nelson S. Gifford Director - ------------------------------------- Nelson S. Gifford /s/ Kenneth I. Guscott Director - ------------------------------------- Kenneth I. Guscott 65 /s/ Matina S. Horner Director - ------------------------------------- Matina S. Horner /s/ Sherry H. Penney Director - ------------------------------------- Sherry H. Penney /s/ Herbert Roth, Jr. Director - ------------------------------------- Herbert Roth, Jr. - ------------------------------------- Director Stephen J. Sweeney - ------------------------------------- Director Paul E. Tsongas
66 Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company: We have audited the consolidated financial statements of Boston Edison Company and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K. These consolidated 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 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 audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1995 and 1994, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. COOPERS & LYBRAND L.L.P. Boston, Massachusetts January 25, 1996 EX-4.1.9 2 VOTES OF THE PRICING COMMITTEE OF THE BOARD OF DIRECTORS Exhibit 4.1.9 PRICING COMMITTEE MEETING ------------------------- BOSTON, MAY 10, 1995 A meeting of the Pricing Committee of the Board of Directors of Boston Edison Company was held at the Executive Offices of the Company, 800 Boylston Street, Boston, Massachusetts, on Wednesday, May 10, 1995, at twelve o'clock noon, local time, the Chairman presiding. Present: Mr. May - and present and participating by telephone communications equipment, by means of which all persons participating in the meeting could hear each other at the same time, Mr. N. Gifford and Drs. Horner and Penney - and, by invitation, Mr. Alpert and Ms. O'Neil. Absent: Mr. Davis. Messrs. May and Alpert presented management's proposal to issue $125 million of debentures. The directors discussed the matters presented. On motion duly made and seconded, it was VOTED: That, pursuant to votes of the Board of Directors adopted January 28, 1993, the Company issue and sell $125,000,000 aggregate principal amount of unsecured debentures to be issued under and in accordance with the provisions of Article Three of the Indenture dated September 1, 1988 between the Company and Bank of Montreal Trust Company, as Trustee (the "Trustee") as amended and supplemented as of the date hereof (the "Indenture"). VOTED: That said series of debentures be established as a separate series of securities in accordance with and pursuant to the Indenture, to be entitled as follows: the 7.80% Debentures due May 15, 2010 (the "Debentures"). VOTED: That the Debentures be issued with the following terms: Maturity Date: May 15, 2010 Interest Rate: 7.80% Interest Payment Date: May 15 and November 15 of each year commencing November 15, 1995. Price to the Public: $124,835,000; 99.868% Proceeds to the Company: $123,897,500; 99.118% Redemption Provisions: No call.
VOTED: That the form of the Debentures presented to the Pricing Committee and attached to these votes as Exhibit A is hereby established, adopted and approved with such changes, insertions and omissions as are required or permitted by the Indenture and these votes and that such form shall be filed with the minutes of this meeting; and that the chairman, president, any senior vice president, the treasurer or any assistant treasurer of the Company be, and each of them acting singly is, hereby authorized to complete the form of Debenture as provided for in these votes, the completion of such Debentures to be conclusive evidence that the same has been approved by the Company. VOTED: That the form of Purchase Agreement presented to the Pricing Committee relating to the Debentures is hereby approved and that the chairman, president, any senior vice president, the treasurer and any assistant treasurer be, and each acting singly is, hereby authorized, in the name and on behalf of the Company, to execute with and deliver to Goldman, Sachs & Co., Merrill Lynch & Co. and Salomon Brothers Inc a Purchase Agreement relating to the Debentures with such changes, insertions and omissions as the officer or officers executing the same may approve, such execution and delivery to be conclusive evidence of the authorization and approval thereof by the Company. VOTED: That Bank of Montreal Trust Company is hereby designated as the transfer agent, registrar and paying agent for the Debentures and that the Trustee and such transfer agent, registrar and paying agent shall be entitled to the estate, powers, rights, authorities, benefits, privileges and immunities set forth in the Indenture; and that such resolutions, if any, as are customarily requested by the Trustee and each such transfer agent, registrar and paying agent with respect to its authority are hereby adopted and shall be filed with the minutes of this meeting. VOTED: That the chairman, president, any senior vice president, the treasurer or any assistant treasurer be, and each of them is, hereby authorized to file with the Trustees a certificate setting forth the form and terms of the Debentures as established by and pursuant to these votes and the written order for the certification and delivery to the purchasers at the time and in the manner specified in the Purchase Agreement for the Debentures; and that the officers of the Company be, and each of them acting singly is, hereby authorized to take such further action and execute such certificates, instruments and other documents as in the judgment of such officers or officer will comply with the provisions of the Indenture and the Purchase Agreement and to issue and deliver the Debentures in accordance therewith. VOTED: That the treasurer or any assistant treasurer be, and each of them acting singly is, hereby authorized and directed to apply the proceeds from the issue and sale of the Debentures to repay obligations incurred under bank lines of credit and commercial paper for capital expenditures for extensions, additions and improvements to the Company's plant and property and for working capital purposes. VOTED: That the officers of the Company are, and each acting singly is, hereby authorized to execute and deliver such other documents and take such further actions in the name of the Company as the officers or officer so acting shall deem advisable to implement the foregoing votes, such execution and delivery or the taking of any such action to be conclusive evidence of its authorization by the Company. No further business being presented, on motion duly made and seconded, the meeting dissolved at fifteen minutes past twelve o'clock p.m., local time. A true record. Attest: By: /s/ Theadora S. Convisser ------------------------------------- Clerk EX-4.1.10 3 FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT Exhibit 4.1.10 FIRST AMENDMENT TO REVOLVING CREDIT AGREEMENT This FIRST AMENDMENT, dated as of May 19, 1995, by and among (a) Boston Edison Company (the "Borrower"), a Massachusetts corporation, (b) each of the Banks named on the signature pages hereof (collectively, the "Banks"), (c) The First National Bank of Boston and Citibank, N.A., as co-agents (collectively, the "Agents") and (d) The First National Bank of Boston as administrative agent (the "Administrative Agent"). WHEREAS, the Borrower, the Banks, the Agents and the Co-Agents are parties to that certain Revolving Credit Agreement dated as of February 12, 1993, as in effect on the date hereof (the "Credit Agreement"); and WHEREAS, the Borrower has requested and the Banks have agreed, subject to the terms and conditions set forth herein, to modify certain provisions of the Credit Agreement: NOW, THEREFORE, the Borrower, the Banks, the Agents and the Administrative Agent hereby covenant and agree as follows: 1. Defined Terms. Capitalized terms which are used herein without ------------- definition and which are defined in the Credit Agreement shall have the same meanings herein as in the Credit Agreement. 2. Amendment to Section 1 - Definitions. Section 1 of the Credit ------------------------------------ Agreement is hereby amended as follows: (a) The definition of "Balance Sheet Date" is hereby amended by substituting "December 31, 1994" for "September 20, 1992" therein. (b) The definition of "Commitment Fee Rate" is hereby deleted; (c) The definition of "DPU Approval" is hereby amended and restated in its entirety as follows: DPU Approval. An appropriate order of the DPU authorizing the ------------ incurrence of indebtedness (i) after December 31, 1996 (for purposes of satisfying the Extension Conditions) or (ii) after the DPU Final Incurrence Date, in each case payable more than one year after the date of incurrence, such order to contain no condition inconsistent with the provisions hereof or reasonably unacceptable to the Majority Banks. (d) The definition of "Extension Conditions" is hereby amended by substituting the date "December 31, 1996" for the date "December 31, 1994" therein; (e) The definition of "Extension Date" is hereby amended by substituting the date "December 31, 1996" for the date "December 31, 1994" therein; (f) The definition of "FERC Approval" is hereby amended and restated in its entirety to read as follows: FERC Approval. The order of the FERC dated June 27, 1994 ------------- authorizing the Borrower to incur, on or before December 31, 1996, short-term indebtedness with a final maturity date not later than December 31, 1997. (g) The definition of "Interest Period" is hereby amended by deleting the second sentence thereof in its entirety and inserting the following sentence therefor: The Interest Period for each Loan, as so determined, shall be (a) with respect to Alternate Base Rate Loans any period ending on or prior to the Termination Date, (b) with respect to Eurodollar Rate Loans, one, two, three or six months and (c) up to 270 days with respect to Competitive Bid Rate Loans. (h) The definition of "Termination Date" is hereby amended and restated in its entirety to read as follows: Termination Date. May 15, 1999; provided that if all of the ---------------- -------- Extension Conditions have not been complied with on or prior to December 31, 1996, the Termination Date shall be December 30, 1997; provided, further, that if the Extension Conditions have been -------- ------- complied with but the DPU Approval delivered to satisfy the Extension Conditions provides for a DPU Final Incurrence Date prior to May 15, 1999, the Termination Date shall be the earlier to occur of the date which is 364 days following the DPU Final Incurrence Date specified in such DPU Approval or May 15, 1999; provided, -------- further, that if the Second Extension Conditions have been complied ------- with but the DPU Approval delivered to satisfy the Second Extension Conditions provides for a Second DPU Final Incurrence Date prior to May 15, 1999, the Termination Date shall be the earlier to occur of the date which is 364 days following the Second DPU Final Incurrence Date specified in such DPU Approval or May 15, 1999. Notwithstanding the foregoing, the Termination Date shall be May 15, 1999 with respect to any outstanding Loans incurred pursuant to a DPU Approval authorizing such Loans. (i) Section 1 of the Credit Agreement is hereby amended by inserting the following new definitions in appropriate alphabetical order: DPU Final Incurrence Date. The date specified in the DPU Approval --- ----- ---------- ---- delivered for purposes of satisfying the Extension Conditions as the last date upon which the Borrower may incur indebtedness pursuant to such order. Facility Fee Rate. For each day that the First Mortgage Bonds have -------- --- ---- a rating equal to or higher than BBB by Standard & Poor's Corporation and Baa2 by Moody's Investors Service, Inc. the Facility Fee Rate shall equal 0.1875% per annum provided, that in the event -------- there are no First Mortgage Bonds outstanding, the condition specified herein shall be deemed to be met if the Borrower has outstanding debentures or other unsecured debt having a rating equal to or higher than BBB- by Standard & Poor's Corporation and Baa3 by Moody's Investor Service, Inc. For each day that the condition specified in the preceding sentence is not satisfied, the Facility Fee Rate shall equal 0.2875% per annum. In the event that the First Mortgage Bonds or unsecured debt of the Borrower, as applicable, is not rated by one of Standard & Poor's Corporation or Moody's Investor Service, Inc., the condition specified herein shall be deemed to be met if the applicable rating from the other such rating company is achieved and the First Mortgage Bonds have a rating of BBB or higher from Duff & Phelps Corporation, or, if the First Mortgage Bonds are not then outstanding, the Borrower's unsecured debt has a rating of BBB- or higher from Duff & Phelps Corporation. Second DPU Final Incurrence Date. The date specified in the DPU ------ --- ----- ---------- ---- Approval delivered for purposes for satisfying the Second Extension Conditions as the last date upon which the Borrower may incur indebtedness pursuant to such order. Second Extension Conditions. (1) The Banks shall have received on ------ --------- ---------- or prior to the Second Extension Date, copies of the DPU Approval authorizing the Borrower to incur long-term indebtedness after the DPU Final Incurrence Date, which approval or order shall not have been rescinded or stayed or materially adversely modified, or the right of the Borrower to incur indebtedness thereunder restrained by the DPU or by any court of competent jurisdiction or other regulatory agency with appropriate jurisdiction and all applicable appeal periods with respect to such approval or order shall have expired and (2) Ropes & Gray, Borrower's counsel shall have delivered to the Administrative Agent a legal opinion dated the Second Extension Date, addressed to the Banks and reasonably satisfactory to the Majority Banks to the effect that the incurrence by, or existence of, indebtedness of the Borrower under this Agreement after the DPU Final Incurrence Date has been duly approved to the extent required by law and all applicable regulations by such approval or order which remains in full force and effect and no further authorization, order or approval or other action by, and no notice to or filing with any governmental authority or regulatory body is required for the incurrence of such indebtedness pursuant hereto; and (3) the representations and warranties of the Borrower contained in Section 4 are true and complete in all material respects on and as of the Second Extension Date. Second Extension Date. A date selected by the Borrower on or prior ------ --------- ---- to the DPU Final Incurrence Date on which the Second Extension Conditions shall have been satisfied. 3. Amendment to Section 2.3 - Commitment Fee. Section 2.3 of the --------- -- ------- --- Credit Agreement is hereby amended by (i) substituting in the heading thereof the phrase "Facility Fee" for the phrase "Commitment Fee" and (ii) deleting the text thereof in its entirety and substituting the following text therefor: The Borrower agrees to pay to the Administrative Agent for the accounts of the Banks in accordance with their respective Commitment Percentages a facility fee calculated daily at the Facility Fee Rate on the amount of the Total Commitment in effect on such day. The facility fee shall accrue from April 1, 1995 through the Termination Date and be payable quarterly in arrears on the last day of each March, June, September and December for the fiscal quarter (or portion thereof) then ended, with the first such payment on June 30, 1995 and with a final payment on the Termination Date (or the date of termination in full of the Commitments, if earlier). 4. Amendment to Section 2.4 - Extension of Commitment. Section 2.4 of --------- -- ------- --- --------- -- ---------- the Credit Agreement is hereby amended by (i) substituting the phrase "facility fee" for the phrase "commitment fee" in the penultimate sentence of paragraph (a) thereof and (ii) deleting paragraph (c) thereof in its entirety. 5. Amendment to Section 2.6 - Interest Period. Section 2.6 of the --------- -- ------- --- -------- ------ Credit is hereby amended as follows: (a) Section 2.6(a) is amended by deleting clause (ii) thereof in its entirety and substituting the following therefor: (ii) on or prior to May 15, 1998 for the Eurodollar Loans, at a rate per annum equal to the sum of (A) the Euro Rate plus (B) ---- 0.4125%; and (iii) after May 15, 1998 for Eurodollar Loans, at a rate per annum equal to the sum of (A) the Euro Rate plus (B) 0.600%; and ---- (b) Section 2.6(b) is hereby amended by deleting clause (ii) thereof in its entirety and substituting the following therefor: (ii) on or prior to May 15, 1998 for Eurodollar Loans, at a rate per annum equal to the sum of (A) the Euro Rate plus (B) ---- 0.5375%; and (iii) after May 15, 1998 for Eurodollar Loans, at a rate per annum equal to the sum of (A) the Euro Rate plus (B) 0.725%; and ---- 6. Amendment to Section 3.1 - Funds for Payments. Section 3.1 of the --------- -- ------- --- ----- --- -------- Credit Agreement is hereby amended by substituting the phrase "facility fee" for the phrase "commitment fee" in the first sentence thereof. 7. Amendment to Section 3.2 - Computations. Section 3.2 of the Credit --------- -- ------- --- ------------ Agreement is hereby amended by substituting the phrase "facility fee" for the phrase "commitment fee" in the first sentence thereof. 8. Amendment to Section 4.2 - Government Approvals. Section 4.2 of the --------- -- ------- --- ---------- --------- Credit Agreement is hereby amended and restated in its entirety as follows: Except for (i) obtaining DPU approval authorizing the incurring of indebtedness after December 31, 1996 (or such later date as shall be specified therefor in the DPU Approval) pursuant to this Agreement payable more than one year after the date of incurrence thereof and (ii) obtaining approval of the Federal Energy Regulatory Commission ("FERC") authorizing the incurring of short-term indebtedness pursuant to this Agreement after December 31, 1996 (or such later date as shall be specified therefor in any extension of the FERC Approval), the execution, delivery and performance by the Borrower of this Agreement and the notes and the transactions contemplated hereby and thereby do not require the approval or consent of, or filing with, any governmental agency or authority other than those already obtained or made and in full force and effect. 9. Amendment to Section 4.3 - Financial Statements. Section 4.3 of the --------- -- ------- --- --------- ---------- Credit Agreement is hereby amended by substituting the date "December 31, 1994" for the date "December 31, 1991" therein and by deleting the second sentence thereof. 10. Amendment to Section 4.6 - Litigation. Section 4.6 of the Credit --------- -- ------- --- ---------- Agreement is hereby amended by substituting the date "December 31, 1994" for the date "December 31, 1991" therein. 11. Amendment to Section 4.7 - Compliance with Other Instruments, Laws, --------- -- ------- --- ---------- ---- ----- ------------ ----- Etc. Section 4.7 of the Credit Agreement is hereby amended by substituting - ---- the date "December 31, 1994" for the date "December 31, 1991" therein. 12. Amendment to Section 5.1 - Punctual Payment. Section 5.1 of the --------- -- ------- --- -------- ------- Credit Agreement is hereby amended by substituting the phrase "facility fee" for the phrase "commitment fee" in the second sentence thereof. 13. Amendment to Section 5.8 - Compliance with Laws, Contracts, --------- -- ------- --- ---------- ---- ----- ---------- Licenses, and Permits. Section 5.8 of the Credit Agreement is hereby - --------- --- ------- amended by substituting the date December 31, 1994" for the date "December 31, 1991" therein. 14. Amendment to Section 7.2 - All Borrowings. Section 7.2 of the --------- -- ------- --- --- ---------- Credit Agreement is hereby amended by inserting the following paragraph (d) at the end thereof: (d) Certificate of Capacity. The Borrower shall have delivered to ----------- -- -------- the Administrative Agent an Officers' Certificate certifying that the Borrower has capacity to incur additional indebtedness in the amount of the Loan then being requested pursuant to the terms of (i) if the earliest possible Termination Date applicable to such Loan is 365 days or more after the Drawdown Date for such Loan, the then applicable order of the DPU authorizing the Borrower to incur long- term indebtedness and (ii) if earliest possible Termination Date applicable to such Loan is less than 365 days after the Drawdown Date for such Loan, the then applicable order of FERC authorizing the Borrower to incur short-term indebtedness. 15. Amendment to Section 7.3 - Borrowings After December 31, 1996. --------- -- ------- --- ---------- ----- -------- --- ---- Section 7.3 of the Credit Agreement is hereby amended and restated in its entirety as follows: 7.3 Borrowings After December 31, 1996. (i) In the case of each ---------- ----- -------- --- ---- Loan made after December 31, 1996 and prior to the Extension Date, the Borrower shall have received an extension of the FERC Approval authorizing the Borrower to incur indebtedness on the Drawdown Date for such Loan, (ii) if the Extension Conditions shall have been satisfied, in the case of each Loan made after the DPU Final Incurrence Date but prior the Second Extension Date, the Borrower shall have received an extension of the FERC Approval authorizing the Borrower to incur indebtedness on the Drawdown Date for such Loan, (iii) if the Second Extension Conditions shall have been satisfied, in the case of each Loan made after the Second DPU Final Incurrence Date, the Borrower shall have received an extension of the FERC Approval authorizing the Borrower to incur indebtedness on the Drawdown Date for such Loan, and (iv) notwithstanding the foregoing , in the case of each Loan made after May 15, 1998, the Borrower shall have received an extension of the FERC Approval authorizing the Borrower to incur short-term indebtedness on the Drawdown Date for such Loan, and, in the case of each clause (i), (ii), (iii) and (iv), the Borrower shall have delivered a copy of the applicable FERC Approval to the Administrative Agent, or shall have delivered to the Administrative Agent an opinion of Ropes & Gray, Borrower's counsel, that such approval is not required. 16. Amendment to Section 8 - Events of Default. Section 8(b) of the --------- -- ------- - ------ -- ------- Credit Agreement is hereby amended by substituting the phrase "facility fee" for the phrase "commitment fee" therein. 17. Amendment to Section 18 - Consents, Amendments, Waivers, Etc. --------- -- ------- -- --------- ----------- -------- ---- Section 18 of the Credit Agreement is hereby amended by substituting the phrase "facility fee" for the phrase "commitment fee" in the second sentence thereof. 18. Amendment to Notices. Notwithstanding anything to the contrary set --------- -- ------- forth in 15(d) of the Credit Agreement, the address for notices to each of State Street Bank & Trust Company and Shawmut Bank, N.A., shall be that address set forth for each such Bank in the signature pages hereof, or such other address for notice as such Bank shall have last furnished in writing to the Person giving such notice. 19. Conditions to Effectiveness. This Amendment shall become effective ---------- -- ------------- upon satisfaction of the following conditions: (a) the execution of this Amendment by the Company, the Agents and the Banks; and (b) the delivery to the Banks from Messrs. Ropes & Gray, counsel to the Borrower, a favorable legal opinion, dated as of the date hereof, addressed to the Banks and substantially in the form of Exhibit A hereto. ------- - 20. No Other Amendments. Except as expressly provided in this -- ----- ---------- Amendment, all of the terms and conditions of the Credit Agreement remain unchanged, and the terms and conditions of the Credit Agreement as amended hereby remain in full force and effect. 21. Execution in Counterparts. This Amendment may be executed in any --------- -- ------------ number of counterparts and by each party on a separate counterpart, each of which when so executed and delivered shall be an original, but all of which together shall constitute one instrument. In proving this Amendment, it shall not be necessary to produce or account for more than one such counterpart signed by the party against whom enforcement is sought. 22. Miscellaneous. This Amendment shall be deemed to be a contract ------------- under seal under the laws of The Commonwealth of Massachusetts and shall for all purposes be construed in accordance with and governed by the laws of The Commonwealth of Massachusetts. The captions in this Amendment are for convenience of reference only and shall not define or limit the provisions hereof. IN WITNESS WHEREOF, the parties have executed this Amendment as of the date first above written. BOSTON EDISON COMPANY By: /s/ Marc S. Alpert ------------------------------------- Title: Vice President and Treasurer THE FIRST NATIONAL BANK OF BOSTON as Co-Agent and Administrative Agent By: /s/ Michael Kane ------------------------------------- Title: Managing Director THE FIRST NATIONAL BANK OF BOSTON By: /s/ Michael Kane ------------------------------------- Title: Managing Director CITIBANK, N.A. as Co-Agent By: /s/ Paul J. Addison ------------------------------------- Title: Attorney In Fact CITIBANK, N.A. By: /s/ Paul J. Addison ------------------------------------- Title: Attorney In Fact THE FIRST NATIONAL BANK OF CHICAGO By: /s/ Ronald L. Coleman ------------------------------------- Title: Vice President FLEET BANK OF MASSACHUSETTS, N.A. By: /s/ Michael W. Borsey ------------------------------------- Title: Vice President BANK OF MONTREAL By: /s/ John L. Smith ------------------------------------- Title: Director THE BANK OF NOVA SCOTIA By: /s/ Michael R. Bradley ------------------------------------- Title: Authorized Signatory SWISS BANK CORPORATION By: /s/ Darryl M. Monasebian ------------------------------------- Title: Associate Director Merchant Banking By: /s/ John A. McCall ------------------------------------- Title: Associate Director THE BANK OF NEW YORK By: /s/ John W. Hall ------------------------------------- Title: Vice President SHAWMUT BANK, N.A. By: /s/ John P. Rafferty ------------------------------------- Title: Director One Federal Street, OF-0308 Boston, Massachusetts 02211 Attention: John P. Rafferty, Director STATE STREET BANK & TRUST COMPANY By: /s/ Lise Anne Boutiette ------------------------------------- Title: Vice President 225 Federal Street Boston, Massachusetts 02110 Attention: Lise Boutiette, Vice President EX-12.1 4 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12.1 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges Year ended December 31, 1995 (in thousands) Net income from continuing operations $112,310 Income taxes 66,547 Fixed charges 129,576 -------- Total $308,433 ======== Interest expense $119,282 Interest component of rentals 10,294 -------- Total $129,576 ======== Ratio of earnings to fixed charges 2.38 ====
EX-12.2 5 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12.2 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements Year ended December 31, 1995 (in thousands) Net income from continuing operations $112,310 Income taxes 66,547 Fixed charges 129,576 -------- Total $308,433 ======== Interest expense $119,282 Interest component of rentals 10,294 -------- Subtotal $129,576 -------- Preferred stock dividend requirements 24,755 -------- Total $154,331 ======== Ratio of earnings to fixed charges and preferred stock dividend requirements 2.00 ====
EX-23.1 6 CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Boston Edison Company on Form S-3 (File Nos. 33-36824, 33-57840 and 33-59693) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424, 33-48425, 33-59662, 33-59682 and 33-58457) of our report dated January 25, 1996 on our audits of the consolidated financial statements of Boston Edison Company as of December 31, 1995 and 1994 and for each of the three years in the period ended December 31, 1995, which report is included in this Annual Report on Form 10-K. By: /s/ Coopers & Lybrand, L.L.P. ------------------------------------- Coopers & Lybrand, L.L.P. Boston, Massachusetts March 28, 1996 EX-27 7 FINANCIAL DATA SCHEDULE
UT 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 2,955,642 126,514 345,306 216,387 0 3,643,849 48,003 683,686 257,749 989,438 92,000 123,000 1,160,223 75,941 0 50,500 100,667 2,000 0 0 1,050,080 3,643,849 1,628,503 68,276 1,332,827 1,401,103 227,400 (575) 226,825 114,515 112,310 15,571 96,739 86,399 3,481 310,658 2.08 0
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