-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, K2qIGygNSXOi0kFWeRU7raHXzTfv6m+dfNK6fSLfhzfJz23oXn2yfvKw1NAHgcsI +CgMyZ9yGbMNY6X4xPF08Q== 0000950135-94-000231.txt : 19940404 0000950135-94-000231.hdr.sgml : 19940404 ACCESSION NUMBER: 0000950135-94-000231 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BOSTON EDISON CO CENTRAL INDEX KEY: 0000013372 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 041278810 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-02301 FILM NUMBER: 94519774 BUSINESS ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: ROOM P-344 CITY: BOSTON STATE: MA ZIP: 02199 BUSINESS PHONE: 6174242000 10-K 1 BOSTON EDISON FORM 10-K 1 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, 1993 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. [X] 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 28, 1994 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: $1,220,739,336. 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 28, 1994 -------------------------- -------------------------------- Common Stock, $1 par value 45,212,568 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document - ---- -------- III Portions of definitive Proxy Statement dated March 17, 1994 for Annual Meeting of Stockholders to be held April 22, 1994.
Exhibit list appears on page 51. 2 Boston Edison Company - ------------------------------------------------------------------------------- Form 10-K Annual Report - ------------------------------------------------------------------------------- December 31, 1993 - -------------------------------------------------------------------------------
Part I Page - ------------------------------------------------------------------------------- Item 1. Business 2 Item 2. Properties and Power Supply 10 Item 3. Legal Proceedings 13 Item 4. Submission of Matters to a Vote of Security Holders 13 Part II - ------------------------------------------------------------------------------- Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 17 Item 6. Selected Financial Data 18 Item 7. Management's Discussion and Analysis 19 Item 8. Financial Statements and Supplementary Financial Information 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 48 Part III - ------------------------------------------------------------------------------- Item 10. Directors and Executive Officers of the Registrant 48 Item 11. Executive Compensation 48 Item 12. Security Ownership of Certain Beneficial Owners and Management 49 Item 13. Certain Relationships and Related Transactions 49 Part IV - ------------------------------------------------------------------------------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 50
1 3 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 demand side management (DSM) programs. In 1993 the Company established an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from the Massachusetts Department of Public Utilities (DPU). The Company was granted authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management, electric transportation and electric generation and distribution activities through its wholly-owned subsidiaries Ener-G-Vision, Inc. and TravElectric Services Corporation. In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc. The new entity, REZ-TEK International Corporation, will continue the business of manufacturing ozone water treatment systems. 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 approximately 590 square miles encompassing 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 1993 the Company served an average of approximately 651,000 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Revenues by class for the last three years are as follows:
1993 1992 1991 - ---------------------------------------------------------------- Retail electric revenues: Commercial 49% 47% 47% Residential 27% 26% 26% Industrial 10% 10% 10% Other 2% 4% 5% Wholesale and contract revenues 12% 13% 12% ================================================================
2 4 Sources and Availability of Fuel The Company's generating units, other than Pilgrim Nuclear Power Station, are fueled by oil, natural gas or both. The Company's generation by type of fuel and the cost of fuel for each of the last five years are as follows:
Percentage of Company Average Cost (Dollars per Million) Generation by Source (%) of BTU's on a Burned Basis ($) ------------------------- ------------------------------- 1993 1992 1991 1990 1989 1993 1992 1991 1990 1989 - ------------------------------------------------------------------ Oil 31.3 33.7 42.8 33.6 53.7 2.38 2.40 2.60 2.76 2.67 Gas 24.3 25.7 24.9 33.3 31.7 2.67 2.55 2.08 2.35 2.34 Nuclear 44.4 40.6 32.3 33.1 14.6 0.51 0.52 0.56 0.59 0.57 ==================================================================
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. Most of the Company's natural gas is supplied on an interruptible basis whereby a contract permits interruptions in deliveries by the supplier when natural gas pipeline capacity is unavailable. Deliveries of natural gas to the Company's generating units from suppliers may also be dependent on the availability of pipeline capacity to the New England region and competitive forces prevailing in the pipeline industry. Beginning in April 1995 the Company will be required to operate New Boston Station using exclusively natural gas as fuel, except in certain emergency circumstances, as part of a 1991 consent order from the Massachusetts Department of Environmental Protection (DEP). The Company has arrangements for a nine month supply of natural gas to the station until April 1995 and is currently in the process of negotiating with suppliers and transporters concerning the economics and availability of natural gas to the station on a year-round basis after that time. Year-round gas supplies are currently not available to the station and, as a result, the outcome of the Company's negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain. 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 that will individually allow operation of Pilgrim Station through 1998, 2000, 2001 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 3 5 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 locations are unlimited in time, but their rights are not vested and are subject to the action of these authorities and the legislature. Seasonal Nature of Business The Company's kWh sales and revenues have historically been less in the spring and fall than during winter and summer 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, a significant portion of annual earnings occurs in the Company's third quarter. See 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 experiencing a substantial increase in competition from other electric utilities and non-utility generators to sell electricity for resale. In response to the current environment the Company has secured long-term power supply agreements with its four current wholesale customers which set rates principally through the year 2002. The Company also obtained a new wholesale customer for which it will provide up to 30 megawatts (MW) of contract demand power for ten years beginning November 1994. The DPU has created an 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. The Company submitted a draft IRM filing in March 1994 that covers the period 1994 through 2004. In this filing the Company concluded that adequate resources exist to meet customer needs for continued reliable, low cost power through the period without procurement of any new generation resources. The IRM process requires a settlement period in which intervenors and other interested parties have the opportunity to review, comment and request information on the draft filing. Any settlements reached will be reflected in the Company's final IRM filing to be submitted in July 1994. Any remaining issues will be litigated at the DPU through formal proceedings. 4 6 Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. The Company and other Massachusetts electric utilities are 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 specific city or town approval and the purchase of Company property within municipality limits. However, the Company is currently experiencing some forms of competition in the retail electric market. Current legislation allows industrial and large commercial customers to own and operate their own electric generating units. Retail customers may also substitute natural gas or oil for electricity as fuel for heating and cooling purposes. The Company is responding to the current and anticipated competitive pressures with a commitment to cost control and increased operating efficiencies without sacrificing quality of service or profitability. Research Activities The Company actively participates in several industry-sponsored research activities. These expenditures, included in other operations and maintenance expense on the consolidated income statements in Item 8, were not material in 1993. Environmental Matters The Company is subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require modification of existing facilities or curtailment or termination of operations at facilities, delay construction of new facilities or 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 capital expenditures for environmental purposes during the five years 1989 through 1993 were approximately $125 million. Environmental-related capital expenditures for the years 1994 through 1998 are currently expected to approximate $43 million, including $17 million in 1994 and $9 million in 1995. These amounts exclude costs associated with asbestos removal which were approximately $11 million during the five years 1989 through 1993 and are currently expected to be approximately $10 million for the years 1994 through 1998. The 1994 expected capital expenditures for environmental purposes include costs to complete modifications at New Boston Station in order to improve air quality and reduce emissions of nitrogen oxides, as discussed in the Environmental section of Other Matters in Item 7, and to install air monitoring systems at other Company generating units. 5 7 Substantial additional expenditures could be required as changes in environmental requirements occur. The Company is subject to regulation by the United States Environmental Protection Agency (EPA) and the Massachusetts Department of Environmental Protection (DEP) with respect to discharges of effluent from the Company's 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 every five years. The Company has received discharge permits as required by the EPA and the DEP for each of its electric generating stations. The Company is also subject to EPA and DEP regulation relative to emissions from its fossil-fired generating units pursuant to Federal and Massachusetts clean air laws, including the 1990 Clean Air Act Amendments. These regulations require the installation of various emissions controls and the use of low sulfur content fuels in certain cases. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section in Item 7. The Company is subject to various federal, state and local laws and regulations pertaining to the generation, treatment, transportation, storage and disposal of certain hazardous substances and to the cleanup of locations where such substances have either been disposed of or spilled. One of the requirements of these laws and regulations is that certain facilities which treat, store or dispose of hazardous wastes must be licensed. The only facility owned by the Company which requires such a license is Pilgrim Station. Currently Pilgrim Station has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive. The Company has exposure to potential joint and several liability for the cleanup of sites where hazardous wastes may have been spilled or disposed of in the past. The Company has been notified of such potential liability for approximately twelve sites, most of which involve numerous parties. Complex 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 also faces additional exposure for the cleanup of Company-owned or operated sites due to state regulations revised in 1993. The potential hazardous waste liabilities are further described in the Environmental section of Item 7. The Company currently disposes of low-level radioactive waste (LLW) generated at Pilgrim Station through arrangements with licensed disposal facilities located in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, the Company's continued access to such disposal facilities has become severely limited and significantly increased in cost. See Note D to the consolidated financial statements in Item 8 for further discussion regarding LLW disposal. The Company's existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. A request for a license amendment to allow modification of the storage facility 6 8 to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012 is pending before the Nuclear Regulatory Commission (NRC). The Company expects approval of the request in 1994. At that time the Company will initially modify the facility to provide spent fuel storage capacity through approximately 2003. In addition, the United States Department of Energy (DOE), which is ultimately responsible for the disposal of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982, is currently 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 litigation and the DOE has publicly stated that it may be unable to construct such a repository in a timely manner. The Company is unable to predict whether and on what schedule the DOE will eventually construct a repository and what the effect will be on the Company. Published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. This topic is discussed more fully in the Environmental section of Item 7. Number of Employees The Company had 4,404 full-time and 14 part-time employees as of the end of 1993, 2,775 of which are represented by two locals of the Utility Workers Union of America, AFL-CIO. The current four-year labor contract in effect with the locals is scheduled to expire in May 1994. Labor contract negotiations began in early February 1994 and the Company anticipates favorable resolution of these negotiations. (d) Financial Information about Foreign and Domestic Operations - --------------------------------------------------------------- and Export Sales - ---------------- See Principal Products and Services for information regarding the geographical area served by the Company and revenues by class for the last three years. (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 Federal Energy Regulatory Commission (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 such 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. Recent requirements imposed on the Company by the DPU are discussed under Competitive Conditions of this item and Non-Utility Generator Purchase Contracts in Item 2. 7 9 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 under long-term contracts. The Company provides quarterly generating unit performance progress reports to the DPU. The DPU has the right to reduce subsequent fuel clause 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. In 1993 the Company received a generating unit performance order from the DPU for the performance period November 1990 through October 1991. The order required the Company to make refunds to its customers due to its not meeting certain performance standards. A subsequent order was received from the DPU in February 1994 for the performance period November 1991 through October 1992. The Company is currently assessing the potential customer refunds associated with missed performance goals. The Company has not yet received an order from the DPU for the performance period November 1992 through October 1993. The Company believes that its current provision for refunds will be sufficient to cover all potential refunds. The 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 may result in the issuance of notices of violation. These notices may be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties. In addition, the Company might undertake certain actions in regard to Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations (INPO), 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 might be required 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. 8 10 Capital Expenditures and Financings The Company's most recent estimate of capital expenditures, allowance for funds used during construction (AFUDC), long-term debt maturities and sinking fund requirements for the years 1994 through 1998 are as follows:
(in thousands) 1994 1995 1996 1997 1998 - -------------------------------------------------------------------- Capital expenditures (1) $201,000 $206,000 $184,000 $181,000 $172,000 AFUDC (2) 6,000 4,000 4,000 5,000 5,000 Long-term debt - 100,600 101,600 101,600 101,600 Preferred stock sinking fund 2,000 2,000 2,000 2,000 2,000 ==================================================================== (1) Excludes estimated nuclear fuel expenditures of $19,000, $9,000, $23,000, $12,000 and $25,000, respectively and capitalized DSM expenditures. (2) Excludes estimated AFUDC on nuclear fuel of approximately $1,000 per year. The estimated AFUDC rate varies from 4.0% to 6.5%.
The Company conducts a continuing review of its capital expenditure and financing programs. These programs and the estimates shown above are therefore subject to revision due to changes in environmental standards, regulatory requirements, availability and cost of capital, interest rates and other assumptions. In addition, depending upon the outcome of certain air quality modeling studies, the Company may be required to make additional expenditures by 1999 in order to comply with the provisions of the 1990 Clean Air Act Amendments. The extent of any additional expenditures is uncertain at this time. Capital expenditures in 1993 were approximately $247 million and consisted primarily of additions to the Company's transmission and distribution systems and fossil and nuclear generation facilities. Significant projects included spending for transmission and distribution of approximately $13 million for the replacement of electric system property, $9 million for a new substation and $7 million for a new energy control system. Capital spending for fossil generation facilities included approximately $24 million for environmental modifications at New Boston Station as described in the Environmental section of Other Matters in Item 7. Expenditures in 1993 for Pilgrim Station included approximately $32 million to improve efficiencies and meet regulatory requirements and $8 million for a new administrative building. Funds generated internally represented approximately 74%, 90% and 89% of capital expenditures in 1993, 1992 and 1991, respectively. It is expected that a significant portion of future capital expenditures will be funded internally. The Company intends to continue spending significant amounts on its DSM programs. The Company spent approximately $53 million on these programs in 1993, of which $37 million was capitalized and is being collected from customers over six years in accordance with the Company's 1992 settlement agreement. See the Liquidity and Outlook for the Future sections in Item 7 for further discussion regarding the Company's DSM programs. 9 11 In 1993 the DPU approved a financing plan allowing the Company to issue up to $1.1 billion in securities through 1994 and to use the proceeds to refinance long-term securities and short-term debt. See Note F to the consolidated financial statements in Item 8 for specific information relating to the Company's financing activities. Item 2. Properties and Power Supply - ------------------------------------ Company-Owned Facilities The Company's total installed electric generation capacity as of December 31, 1993 is as follows:
Installed Capacity Year Unit Location (MW) Type Installed - ------------------------------------------------------------------------- Pilgrim Nuclear Plymouth, MA 678 Nuclear 1972 Power Station New Boston Station South Boston, MA 718 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, MA Units 4-5-6 469 Fossil 1957-1961 Unit 7 617 Fossil 1975 Combustion turbine Various 239 Fossil 1966-1971 generators (ten) =========================================================================
All of the Company's steam fossil fuel-fired electric 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 is also a 5.888% joint owner in 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. As of December 31, 1993 the Company's transmission system was comprised of approximately 362 miles of overhead circuits operating at 115,000, 230,000 and 345,000 volts and approximately 155 miles of underground circuits operating at 115,000 and 345,000 volts. The substations supported by these lines consist of 42 transmission or combined transmission and distribution substations with transformer capacity of 10,025 megavolt amperes (MVA), 71 distribution substations with transformer capacity of 1,238 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 231 customers' substations. The overhead distribution system covers approximately 4,652 miles of streets and the underground distribution system extends through approximately 892 miles of streets. HEEC, the Company's regulated subsidiary, has a distribution system that consists 10 12 principally of a 4.09 mile 115Kv submarine distribution line and a temporary substation which is located on Deer Island in Boston, Massachusetts. The Company's significant items of property consist of electric generating stations, substations and certain service centers and are generally located on Company-owned land, with certain exceptions as set forth in the Company's First Mortgage Bond Indenture and its supplements. 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 local or state authorities. 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 no proceedings before the EFSB. Long-Term Power Contracts Refer to Note K 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 contract with a subsidiary of Commonwealth Energy System and two other utilities in which the participants are sharing in equal amounts the output of an oil-fired electric generation plant. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return over a period of approximately 33 years for its proportionate share of generation. The Company has two long-term purchased power contracts with the Massachusetts Bay Transit 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 but the Company retains New England Power Pool credit for their capacity and output. The Company owns 9.5% of the common stock of Connecticut Yankee Atomic Power Company, which operates a nuclear generating unit. The Company is entitled to receive 9.5% of the 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 approximately 500 MW of capacity and associated energy from non-utility generators. A majority of these purchases are from Ocean State Power and Northeast Energy Associates. In 1993 the L'Energia facility located in Lowell, Massachusetts was declared commercial and the Company began purchasing electricity from this unit under a twenty-year agreement. In addition, the Company is purchasing power from two 11 13 small hydro facilities, and began purchasing capacity and energy from the MassPower facility located in Springfield, Massachusetts in January 1994. In June 1993 the DPU ordered the Company to purchase 132 MW of power from Altresco Lynn, LP, an independent power producer, starting as early as 1995. The Company opposes this order since it does not believe it needs any new power for several years. In July 1993 the Company asked the Massachusetts Supreme Judicial Court to reverse the order. The Court has not yet ruled on the Company's request. The Company has supported an appeal filed by other interested parties of the Energy Facilities Siting Board's conditional approval of Altresco Lynn's project. In February 1994 Altresco Lynn alleged that the Company's actions in opposing the project were improper and that it may seek to hold the Company responsible for any resulting damages. Sales Contracts: - ---------------- The Company has agreements with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, and with Commonwealth Electric Company, a subsidiary of Commonwealth Energy System, under which Montaup and Commonwealth 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. Montaup and Commonwealth have also agreed to indemnify the Company to the extent of 11% each of all loss, 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. New England Power Pool The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To assume 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 generating 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 table below sets forth certain information as of the date of the Company's 1993 summer and 1993-1994 winter peak loads:
January 19, 1994 July 7, 1993 (Winter 1993-94) (Summer 1993) - ------------------------------------------------------------------------ NEPEX utilities installed capacity: Seasonal maximum rating 25,529 MW 24,368 MW Seasonal normal rating 25,232 MW 24,160 MW NEPEX peak load (estimate) 19,422 MW 19,570 MW Company territory peak load 2,474 MW 2,662 MW ========================================================================
12 14 The Company's net capacity was 3,663 MW at its summer peak and 3,533 MW at is winter peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,190 MW and 3,289 MW, respectively. In 1983 the NEPOOL participants signed an agreement, known as Phase I, with Hydro-Quebec of Canada to provide up to three million MWH of hydro-electric power annually to NEPOOL from 1986-1997. In 1985 a second agreement, known as Phase II, was made between NEPOOL and Hydro-Quebec to provide an additional seven million MWH of hydro-electric power annually for ten years. This agreement required expansion of the existing 690 MW Phase I interconnection. The Company and other New England electric utilities entered into an agreement to expand the interconnection with the Hydro-Quebec system of Canada to 2,000 MW. The Phase II facilities began full commercial operation up to the 2,000 MW level in July 1991. The price of this energy is based on the average cost of fossil fuel in New England for the previous year. The contract price for the first five years is 80% of that average, and for the second five years will be 95% of that average. 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 constructed the Phase II facilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants not meeting certain credit criteria. Amounts so guaranteed by the Company were approximately $22 million at December 31, 1993. As a result of the continuing additions to New England generating capacity and minimally increasing energy requirements, the dispatching of Company-owned generating facilities by NEPEX may be affected. Item 3. Legal Proceedings - -------------------------- In March 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts 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 is vigorously defending this case. Based on the information presently available, the Company does not expect that this litigation will have a material impact on the Company's financial condition. However, an unfavorable decision ordered against the Company could have a material impact on quarterly earnings. See also Item 1, Environmental Matters and Note H to the consolidated financial statements in Item 8 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 1993. 13 15 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, 1994 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 - ----------------------- ---------------------- Bernard W. Reznicek, 57 Chairman of the Board and Chief Chairman of the Board and Executive Officer (since 1993), Chief Executive Officer formerly Chairman, President and Chief Executive Officer (1992-1993), President and Chief Executive Officer (1990-1992) and President and Chief Operating Officer (1987-1990). Director (since 1987). Chairman of the Board, Chief Executive Officer and Director, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp. and Ener-G- Vision, Inc. Thomas J. May, 46 President and Chief Operating Officer President and Chief (since 1993), formerly Executive Vice Operating Officer President (1990-1993) and Senior Vice President (1987- 1990). Director (since 1991). President, Chief Operating Officer and Director, Harbor Electric Energy Company; President and Director, Boston Energy Technology Group; Director, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ-TEK International Corp.
14 16
Business Experience Name, Age and Position During Past Five Years - ---------------------- ----------------------- George W. Davis, 60 Executive Vice President (since Executive Vice President 1992), responsible for all power supply and delivery operations. Director (since 1991). Senior Vice President - Nuclear (1990- 1992). Vice President - Nuclear Administration (1989- 1990). E. Thomas Boulette, 51 Senior Vice President - Nuclear Senior Vice President - Nuclear (since 1993). Vice President - Nuclear Operations and Station Director (1992-1993). Vice President - Operations (1989- 1992) and Plant Manager (1988- 1989) of Maine Yankee Atomic Power Company. Cameron H. Daley, 48 Senior Vice President - Power Senior Vice President - Supply (since 1989). Power Supply Vice President - Power Production (1982-1989). John J. Desmond, III, 60 Senior Vice President - Legal (since Senior Vice President - Legal 1992). Vice President and General Counsel (1985-1992). L. Carl Gustin, 50 Senior Vice President - Marketing & Senior Vice President - Corporate Relations Marketing & (since 1989). Corporate Relations Vice President - Corporate Relations (1986-1989). John J. Higgins, Jr., 61 Senior Vice President - Human Resources Senior Vice President - (since 1990). Human Resources Vice President - Human Resources (1988-1990). Ronald A. Ledgett, 55 Senior Vice President - Power Senior Vice President - Power Delivery (since 1991). Delivery Director, Special Projects (1989-1991).
15 17
Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Charles E. Peters, Jr., 42 Senior Vice President - Finance Senior Vice President - Finance (since 1991). Chief Financial Officer and Senior Vice President of Genrad, Inc. (1985-1991). Vice President, Treasurer and Director, Harbor Electric Energy Company; Treasurer and Director, Boston Energy Technology Group; Director, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ-TEK International Corp. Marc S. Alpert, 49 Vice President and Treasurer (since Vice President and Treasurer 1988). Assistant Treasurer, Harbor Electric Energy Company and Boston Energy Technology Group. Robert J. Weafer, Jr., 47 Vice President, Controller and Vice President, Controller Chief Accounting Officer and Chief Accounting Officer (since 1991). Controller and Chief Accounting Officer (1988-1991). Theodora S. Convisser, 46 Clerk of the Corporation (since Clerk of the Corporation 1986). Clerk of Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Ener-G-Vision, Inc. and REZ-TEK International Corp.
16 18 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 1993 and 1992:
1993 1992 - ------------------------------------------------------------------------ High Low High Low - ------------------------------------------------------------------------ First quarter $30 1/2 $26 3/8 $24 5/8 $22 1/8 Second quarter 30 7/8 27 7/8 26 22 3/8 Third quarter 32 5/8 29 3/4 26 7/8 24 7/8 Fourth quarter 32 1/4 27 7/8 28 1/4 24 3/4 ========================================================================
(b) Holders - ----------- As of December 31, 1993, the Company had 42,392 holders of record of its common stock (actual count of record holders). (c) Dividends - ------------- Following are the dividends declared per share of common stock for each of the quarters in 1993 and 1992:
1993 1992 - ----------------------------------------------------------------------- First quarter $0.425 $0.410 Second quarter 0.425 0.410 Third quarter 0.425 0.410 Fourth quarter 0.440 0.425 =======================================================================
17 19 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).
1993 1992 1991 1990 1989 - --------------------------------------------------------------------------------------------------- Operating revenues $1,482,253 $1,411,753 $1,354,501 $1,314,440 $1,339,956 Net income/ (loss) 118,218 107,298 94,670 79,616(a) (16,135)(b) Earnings/(loss) per common share 2.28 2.10 1.96 1.60(a) (0.88)(b) Total assets 3,477,299 3,294,234 3,119,285 3,012,589 2,876,691 Long-term debt 1,272,497 1,091,073 1,136,765 1,074,025 948,839 Redeemable preferred/ preference stock 221,000 221,000 221,333 221,333 221,333 Cash dividends declared per common share 1.715 1.655 1.595 1.535 1.745 =================================================================================================== (a) Before cumulative effect of change in accounting principle ($15,824 or $0.41 per common share). (b) Includes $106,280 or $2.78 per common share loss applicable to rate and contract settlements.
18 20 Item 7. Management's Discussion and Analysis - --------------------------------------------- REGULATORY PROCEEDINGS Retail settlement agreements Effective November 1992 our state regulators, the Massachusetts Department of Public Utilities, approved a three-year settlement agreement. This agreement provides us with retail rate increases, allows for the recovery of demand side management (DSM) conservation program expenditures, specifies certain accounting adjustments and clarifies the timing and recognition of certain expenses. The agreement also sets 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 consist of a new annual performance adjustment charge effective November 1992 and two additional rate increases of $29 million effective November 1993 and November 1994. The performance adjustment charge varies annually based upon the performance of our Pilgrim Nuclear Power Station. This charge is further described in our discussion of financial condition. Our 1993 results of operations were affected by the recovery of DSM program expenditures, accounting adjustments and timing and recognition of certain expenses as further described in the following Results of Operations section. Our state regulators approved a previous three-year settlement agreement effective November 1989. That agreement also provided us with retail rate increases and specified certain accounting adjustments. The 1989 agreement primarily affected our results of operations through 1992. RESULTS OF OPERATIONS 1993 VERSUS 1992 Earnings per common share were $2.28 in 1993 and $2.10 in 1992. The increase in earnings is primarily the result of an annual rate increase effective November 1992, lower purchased power expense due to a long-term contract expiration, no amortization of deferred cancelled nuclear unit costs and lower interest expense. These positive changes were partially offset by higher operations and maintenance expense and higher income tax and property tax expenses. Operating revenues Operating revenues increased 5% over 1992 as follows: (in thousands) - ------------------------------------------------------------ Retail electric revenues $70,837 Demand side management revenues 33,601 Wholesale and other revenues (2,794) Short-term sales revenues (31,144) - ------------------------------------------------------------ Increase in operating revenues $70,500 ============================================================
19 21 Retail electric revenues increased $70.8 million. The November 1992 and 1993 rate increases resulted in $40.6 million of additional revenues in 1993. Fuel and purchased power revenues increased $29.5 million over 1992, partly due to lower revenues received from short-term power sales as discussed below. We began recovery of certain demand side management program costs, lost base revenues and incentives in August 1992. Our 1993 revenues provided $45.9 million related to 1991, 1992 and 1993 DSM programs. Our 1992 revenues of $12.3 million related primarily to 1991 programs. The decrease in wholesale and other revenues reflects an estimated provision for refunds to customers of approximately $8 million as a result of orders from our state regulators on our generating unit performance program. Lower short-term power sales revenues were a result of changes in our generation availability and the needs of short-term power purchasers. All revenues from short-term sales serve to reduce fuel and purchased power billings to retail customers and have no effect on earnings. Operating expenses Fuel expense decreased $19.5 million primarily due to a 21.5% decrease in generation, resulting from planned overhauls of our fossil plants. Interchange purchases increased due to the lower generation, resulting in a $7.5 million net increase in purchased power expense. The net increase also reflects savings of approximately $10 million from a long-term purchased power contract that expired in October 1993. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues. Other operations and maintenance expense increased 7.1% primarily due to increases in employee benefits and nuclear production expenses. Postretirement benefits expense increased by $7 million primarily as a result of the adoption of a new accounting standard and pension expense increased by $5 million; both are provided for in our 1992 settlement agreement and further explained in Note I to the consolidated financial statements. A refueling outage at Pilgrim Station in 1993 resulted in higher nuclear production expenses. Depreciation and amortization expense increased in 1993 primarily due to a higher annual decommissioning charge for Pilgrim Station effective November 1992 provided by the 1992 settlement agreement. The new charge is based on a 1991 estimate of decommissioning costs as further discussed in Note D to the consolidated financial statements. In addition, the effect of lower depreciation rates implemented in accordance with the settlement agreement was offset by the effect of a higher depreciable plant balance. In accordance with our 1992 settlement agreement we did not expense any of the $19 million of remaining deferred costs associated with the cancelled Pilgrim 2 nuclear unit in 1993. We will expense the remaining costs in 1994 and/or 1995. Amortization of deferred nuclear outage costs includes 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 20 22 these costs in June 1993 over five years are approved in the 1992 settlement agreement. The increase in demand side management programs expense is consistent with the increase in DSM revenues. DSM expense includes some costs recovered over a twelve month period and other costs recovered over six years. We began to recover previously deferred DSM expenses in August 1992. In 1993 we expensed and collected from customers approximately $30 million of deferred 1991, 1992 and 1993 program costs. Over six years we are expensing and collecting from our customers $11 million of costs capitalized in 1992 and $37 million of costs capitalized in 1993. The 1993 expense related to these capitalized costs was $7 million. Municipal property and other taxes increased in 1993 due to the absence of tax abatements. In 1992 property taxes were reduced by $10.4 million of tax abatements in accordance with our 1989 settlement agreement. Our effective annual income tax rate for 1993 was 23.4% vs. 8.7% for 1992. Both rates were significantly reduced by adjustments to deferred income taxes of $20 million in 1993 and $23 million in 1992 made in accordance with the 1992 and 1989 settlement agreements. The 1992 rate was also reduced due to tax benefits of approximately $7 million resulting from mandated payments made in accordance with the 1989 agreement. Our adoption of a new accounting standard for income taxes in 1993 did not significantly affect earnings. We expect our effective tax rate to be close to the statutory rate in 1994. Interest charges and preferred and preference dividends Total interest charges decreased $3.8 million in 1993. Interest on long-term debt decreased primarily due to the refinancing of substantially all our first mortgage bonds in 1993 at lower interest rates, partially offset by higher amortization of redemption premiums. Other interest charges decreased due to a lower short-term debt level and lower short-term interest rates. Allowance for funds used during construction (AFUDC), which represents the financing costs of construction, decreased as a result of a lower AFUDC rate related to lower short-term interest rates. Preferred and preference dividends decreased 5% due to the replacement of a preferred and a preference stock issue with less costly issues of preferred stock. 1992 VERSUS 1991 Earnings per common share were $2.10 in 1992 and $1.96 in 1991. The increase in earnings is primarily the result of a rate increase effective November 1991, incentive revenues earned from the performance of Pilgrim Station and lower income tax and interest expenses. These increases were partially offset by higher operations and maintenance and property tax expenses. We also had a one-time charge in 1992 for costs incurred for a deferred generating plant project. 21 23 Operating revenues Operating revenues increased 4.2% over 1991 as follows: (in thousands) - ------------------------------------------------------------- Retail electric revenues $27,672 Demand side management revenues 12,343 Wholesale and other revenues 1,881 Short-term sales revenues 15,356 - ------------------------------------------------------------- Increase in operating revenues $57,252 =============================================================
Retail electric revenues increased $27.7 million. We received a $25 million rate increase effective November 1991 as part of the 1989 settlement agreement. We also earned $8.2 million in incentive revenues in 1992 as a result of Pilgrim Station's capacity factor exceeding its target set in the agreement. Fuel and purchased power revenues decreased approximately $5 million due to higher purchased power costs more than offset by higher revenues received from short-term power sales as discussed below. In 1992 we began to receive revenues for the recovery of certain DSM program costs, lost base revenues and incentives. The 1992 revenues relate primarily to 1991 DSM programs. Our short-term power sales increased in 1992 as a result of our high generating unit availability and the greater power needs of other New England utilities. All revenues from short-term sales served to reduce fuel and purchased power billings to retail customers and had no effect on earnings. Operating expenses Purchased power expense increased $18 million in 1992 due to new long-term purchased power contracts. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues. Other operations and maintenance expense increased 2.3% due primarily to increases in employee benefit expenses and bad debts. Amortization of deferred nuclear outage costs in 1992 and 1991 includes amounts primarily related to the 1991 refueling outage at Pilgrim Station. In 1991 we deferred approximately $23 million of refueling outage costs. We began to expense these costs over five years in September 1991 as approved by our state regulators. Municipal property and other taxes increased 21% primarily due to a reduction in residential and commercial real estate values caused by the depressed economy. This resulted in higher tax rates applied to our personal property values. In accordance with our 1989 settlement agreement, municipal property tax expenses were reduced by tax abatements of $10.4 million in 1992 and $13.6 million in 1991. Our effective annual income tax rate for 1992 was 8.7% vs. 16.5% for 1991. Both rates were significantly reduced by adjustments to deferred income taxes of $23 million in 1992 and $13 million in 1991 made in accordance with the 1989 settlement agreement. We also received tax benefits in both years as a result of payments mandated by the agreement. 22 24 Other income and expense In 1992 we expensed $8 million of costs previously invested in the proposed Edgar Energy Park generation project. This project was deferred indefinitely as additional generating capacity is not expected to be needed for several years. Interest charges and preferred and preference dividends Total interest charges decreased 4.6% primarily due to lower interest rates on our average short-term borrowings. AFUDC decreased 12.7% due to a lower AFUDC rate related to lower short-term interest rates. Preferred and preference dividends decreased approximately $1 million primarily due to the replacement of two preference stock series with less costly issues of preferred stock. Earnings per share Net income increased 13%. However, earnings per common share for 1992 increased only 7%, reflecting an increase in the weighted average number of common shares outstanding primarily a result of our 1991 and 1992 common stock issuances. FINANCIAL CONDITION Our 1992 settlement agreement provides us with increased revenues from retail customers over the three-year period ending October 1995. Additionally, a long-term purchased power contract with annual charges of approximately $60 million expired in October 1993 with no related change in revenues. We are limited to an annual rate of return on equity during the three-year period of 11.75%, excluding any penalties or rewards from performance incentives. Our continued ability to achieve or exceed the 11.75% rate of return on equity will be primarily dependent upon our ability to control costs and to earn performance incentives from generation performance mechanisms specified in both the 1989 and 1992 settlement agreements. The most significant impact that incentives can have on our financial results is based on Pilgrim Station's annual capacity factor. Effective November 1993 an annual capacity factor between 60% and 68% will provide us with approximately $45 million of revenues through the performance adjustment charge. For each percentage point increase in capacity factor above 68%, annual revenues will increase by $670,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%) annual revenues will decrease by $770,000. Pilgrim's capacity factor for the performance year ending October 1994 is expected to be approximately 81% (assuming normal operating conditions), an increase over the 66% capacity factor achieved in the performance year ended October 1993, as no refueling outage is scheduled for 1994. We earned approximately $40 million in performance charge revenues in the performance year ended October 1993. Our fossil generation unit performance can provide an increase or decrease of up to $4 million in revenues in each performance year, however, we do not expect any revenue adjustments from this mechanism. 23 25 LIQUIDITY We meet our plant expenditure cash requirements primarily with internally generated funds. These funds (excluding payments made related to settlement agreements) provided for 74%, 90% and 89% of our plant expenditures in 1993, 1992 and 1991, respectively. Our current estimate of plant expenditures for 1994 is $233 million, including $20 million of nuclear fuel additions. These expenditures will be used primarily to maintain and improve existing transmission, distribution and generation facilities. We also estimate capitalizable DSM expenditures to be $38 million in 1994, which will be collected from customers over six years. We do not expect plant expenditures, excluding nuclear fuel and DSM, to vary significantly from the 1994 amount in the four years thereafter. We have long-term debt and preferred stock payment requirements of $2 million in 1994, $102.6 million in 1995, and $103.6 million per year in 1996 through 1998. External financings continue to be necessary to supplement our internally generated funds, primarily the issuance of short-term commercial paper and bank borrowings. We currently have authority from our federal regulators 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, 1993 we had $204.1 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1993 our state regulators approved a financing plan allowing us to issue up to $1.1 billion in securities through 1994 and to use the proceeds to refinance long-term securities and short-term debt. At December 31, 1993 we had $245 million remaining authorized to be issued under the plan which can be used to issue common stock, preferred stock and long-term debt. As a result of our refinancing activities in 1993 we expect to realize annualized savings of approximately $11.5 million. Refer to Note F to the consolidated financial statements for specific information relating to our recent financing activities. OUTLOOK FOR THE FUTURE Electricity sales A significant portion of our electricity sales are made to commercial customers rather than industrial customers. As a result our sales have been only moderately impacted by the decline in the local Massachusetts economy. Our retail sales increased 1.2% in 1993 and we anticipate only slight growth in retail sales in the near term. Implementation of DSM programs, which are designed to assist customers in reducing electricity use, will result in lower growth in electricity sales. The 1992 settlement agreement established annual DSM spending levels over $50 million through 1994. The agreement provides for collection from customers of certain costs primarily in the year incurred and others over a six-year period. 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 recover over six years. Competition As we are operating in a time of increasing competition from other electric utilities and non-utility generators to sell electricity for resale, we have secured long-term power supply agreements with our four wholesale customers. Through these 24 26 agreements our rates are set principally through the year 2002. We also obtained a new wholesale customer in 1993 for which we will provide up to 30 megawatts of contract demand power for ten years beginning November 1994. Our state regulators require utilities to purchase power from qualifying non-utility generators at prices set through a bidding process. In June 1993 our state regulators ordered us to purchase 132 megawatts of power from an independent power producer, starting as early as 1995. We oppose this order since we do not believe we need any new power for several years. In July 1993 we asked the Massachusetts Supreme Judicial Court to reverse the order. We are currently awaiting a decision from the court. In addition, our state regulators have created an 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. We will submit an IRM filing in March 1994. Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. In 1993 we announced our goal of not seeking additional rate increases, other than those provided in the 1992 settlement agreement, for our residential, commercial and industrial customers until at least the year 2000. We plan to accomplish this by controlling costs and increasing operating efficiencies without sacrificing quality of service or profitability. The announcement reflects our strong commitment to be a competitively priced reliable provider of energy. Non-utility business In 1993 we created an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from our state regulators. We have authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management activities through its wholly-owned subsidiary Ener-G-Vision, Inc. and businesses involving electric transportation and the related infrastructure through its wholly-owned subsidiary TravElectric Services Corporation. 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. In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc., a manufacturer of ozone water treatment systems. The new entity, which will be known as REZ-TEK International Corp., will continue the business of producing a system that treats cooling water used in commercial and industrial air conditioning systems in an energy efficient and environmentally sound manner. OTHER MATTERS Environmental We are subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require that we modify our existing facilities or incur increased operating costs. In 1991 we entered into a consent order with the Massachusetts Department of Environmental Protection (DEP) and other interested parties to undertake certain improvements in the emission control systems at New Boston Station. These 25 27 improvements included the replacement of four existing chimney stacks with two taller stacks in order to improve the air quality in the vicinity of the station, and the installation of low nitrogen oxides burners. The capital cost of these modifications along with other associated improvements has been approximately $78 million through 1993 with an additional $3 million expected to complete these projects in 1994. New Boston Station has the ability to burn natural gas, oil or both. As part of the DEP consent order we also agreed to operate the station using natural gas as fuel for a minimum of nine months per year beginning in April 1992. Beginning in April 1995 we will be required to operate the station fueled exclusively by natural gas, except in certain emergency circumstances. We have made arrangements for a nine month supply of natural gas to the station until April 1995 and are currently in the process of negotiating with natural gas suppliers and transporters concerning the economics and availability of natural gas to New Boston on a year-round basis after that time. Year- round gas supplies are currently not available to the station and, as a result, the outcome of our negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain. The 1990 Clean Air Act Amendments will 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 believe that we will have allowances issued to us that are in excess of our needs and which may be marketable. Any gain from the sale of these 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 the low nitrogen oxides burners at New Boston, will allow the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain air quality modeling studies, additional emission reductions may also be required by 1999. The extent of any additional reductions and the cost of any further modifications is uncertain at this time. State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the DEP. We are currently evaluating the potential costs associated with the cleanup of sites where we have been identified as the owner or operator. There are uncertainties associated with these potential 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 certain other multi-party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings. We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. Refer to Note D to the consolidated financial statements for further discussion regarding LLW disposal. In recent years a number of published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields (EMF) associated with 26 28 electric transmission and distribution facilities and appliances and wiring in buildings and homes. Some scientific reviews conducted to date by several state and federal agencies have suggested associations between EMF and such 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 before regulators, or in requests for legislation or regulatory standards concerning EMF levels. We have not been significantly affected to date by these developments and cannot predict their potential impact on us, however, we continue to closely monitor all aspects of the EMF issue. Litigation In March 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 is vigorously defending this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings. Labor negotiations We began negotiations involving our labor contracts in early February 1994. These contracts expire on May 15, 1994. We anticipate favorable resolution of these negotiations prior to that date. New accounting pronouncements We will adopt Statement of Financial Accounting Standards (SFAS) No. 112, Employers' Accounting for Postemployment Benefits, and SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, in the first quarter of 1994. Refer to Notes I and J to the consolidated financial statements for further discussion of these pronouncements. 27 29 ITEM 8. Financial Statements and Supplementary Financial Information - --------------------------------------------------------------------- Consolidated Statements of Income
years ended December 31, (in thousands, except earnings per share) 1993 1992 1991 - ---------------------------------------------------------------------------------------- Operating revenues $1,482,253 $1,411,753 $1,354,501 Operating expenses: Fuel 176,366 195,873 200,912 Purchased power 364,482 356,931 338,994 Other operations and maintenance 406,271 379,350 370,758 Depreciation and amortization 137,722 129,045 126,151 Amortization of deferred cost of cancelled nuclear unit 0 24,381 24,381 Amortization of deferred nuclear outage costs 6,546 4,901 2,443 Demand side management programs 37,504 8,221 1,674 Taxes - property and other 93,102 80,426 66,216 Income taxes 34,941 11,725 17,111 - ---------------------------------------------------------------------------------------- Total operating expenses 1,256,934 1,190,853 1,148,640 - ---------------------------------------------------------------------------------------- Operating income 225,319 220,900 205,861 Other income (expense), net 589 (2,074) 5,684 - ---------------------------------------------------------------------------------------- Operating and other income 225,908 218,826 211,545 - ---------------------------------------------------------------------------------------- Interest charges: Long-term debt 104,375 106,850 108,912 Other 9,778 12,525 16,947 Allowance for borrowed funds used during construction (6,463) (7,847) (8,984) - ---------------------------------------------------------------------------------------- Total interest charges 107,690 111,528 116,875 - ---------------------------------------------------------------------------------------- Net income 118,218 107,298 94,670 Preferred and preference dividends provided 15,705 16,550 17,611 - ---------------------------------------------------------------------------------------- Balance available for common stock $ 102,513 $ 90,748 $ 77,059 ======================================================================================== Common shares outstanding (weighted average) 44,959 43,144 39,348 Earnings per share of common stock $ 2.28 $ 2.10 $ 1.96 ========================================================================================
Consolidated Statements of Retained Earnings
years ended December 31, (in thousands) 1993 1992 1991 - ---------------------------------------------------------------------------------------- Balance at beginning of year $192,948 $174,477 $161,143 Net income 118,218 107,298 94,670 - ---------------------------------------------------------------------------------------- Subtotal 311,166 281,775 255,813 - ---------------------------------------------------------------------------------------- Cash dividends declared: Preferred stock 15,705 14,923 9,476 Preference stock 0 1,953 8,135 Common stock 77,169 71,951 63,725 - ---------------------------------------------------------------------------------------- Subtotal 92,874 88,827 81,336 - ---------------------------------------------------------------------------------------- Balance at end of year $218,292 $192,948 $174,477 ========================================================================================
The accompanying notes are an integral part of the consolidated financial statements. 28 30 Consolidated Balance Sheets
December 31, (in thousands) 1993 1992 - --------------------------------------------------------------------------------------------- Assets Property, plant and equipment, at original cost: Utility plant in service $3,904,776 $3,629,727 Less: accumulated depreciation 1,258,359 $2,646,417 1,177,294 $2,452,433 - --------------------------------------------------------------------------------------------- Nuclear fuel 273,867 270,420 Less: accumulated amortization 220,477 53,390 201,978 68,442 - --------------------------------------------------------------------------------------------- Construction work in progress 144,835 182,458 - --------------------------------------------------------------------------------------------- Total 2,844,642 2,703,333 Investments in electric companies, at equity 24,292 25,398 Nuclear decommissioning fund, at cost 66,060 50,871 Current assets: Cash and cash equivalents 8,768 3,947 Accounts receivable 171,098 185,563 Accrued unbilled revenues 29,823 28,564 Fuel, materials and supplies, at average cost 79,381 93,931 Prepaid expenses and other 9,738 298,808 6,644 318,649 - --------------------------------------------------------------------------------------------- Deferred debits: Power contracts 36,275 43,717 Cancelled nuclear unit 19,067 19,067 Nuclear outage costs 25,524 17,970 Pension and postretirement costs 24,416 10,449 Redemption premiums 59,116 40,506 Regulatory asset-income taxes, net 26,916 0 Other 52,183 243,497 64,274 195,983 - --------------------------------------------------------------------------------------------- Total assets $3,477,299 $3,294,234 ============================================================================================= Capitalization and Liabilities Common stock equity $ 876,479 $ 840,312 Cumulative preferred stock: Non-mandatory redeemable series 123,000 123,000 Mandatory redeemable series 96,000 98,000 First mortgage bonds 40,000 631,825 Sewage facility revenue bonds, net 32,497 24,248 Debentures 1,200,000 385,000 Unsecured medium-term notes 0 50,000 Current liabilities: Long-term debt/preferred stock due within one year $ 2,000 $ 6,800 Notes payable 204,151 275,500 Accounts payable 144,760 154,251 Interest accrued 25,467 21,497 Dividends payable 22,696 22,192 Other 27,336 426,410 12,482 492,722 - --------------------------------------------------------------------------------------------- Deferred credits: Power contracts 36,275 43,717 Accumulated deferred income taxes 484,796 448,720 Accumulated deferred investment tax credits 71,140 75,213 Nuclear decommissioning reserve 73,744 57,165 Other 16,958 682,913 24,312 649,127 - --------------------------------------------------------------------------------------------- Commitments and contingencies - - - --------------------------------------------------------------------------------------------- Total capitalization and liabilities $3,477,299 $3,294,234 =============================================================================================
The accompanying notes are an integral part of the consolidated financial statements. 29 31 Consolidated Statements of Cash Flows
Years ended December 31, (in thousands) 1993 1992 1991 - ------------------------------------------------------------------------------------- Cash flows from operating activities: Net income $118,218 $107,298 $ 94,670 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 130,074 123,243 121,572 Amortization of nuclear fuel 21,816 25,473 19,869 Amortization of deferred cost of cancelled nuclear unit, net 0 22,340 21,112 Other amortization 9,433 2,132 1,696 Allowance for funds used during (6,463) (7,847) (8,984) construction Deferred income taxes 10,303 17,165 24,476 Investment tax credits (4,073) (4,273) (4,290) (Deferral) amortization of nuclear outage costs, net (7,554) 4,901 (22,062) Net changes in: Accounts receivable and accrued unbilled revenues 13,206 (18,188) (3,519) Fuel, materials and supplies 9,722 (2,330) 12,716 Accounts payable (9,491) 41,899 (19,510) Rate and contract settlements (175) (31,363) (44,546) Other current assets and liabilities 16,408 (2,565) 3,079 Other, net (4,958) (13,777) (24,588) - ------------------------------------------------------------------------------------- Net cash provided by operating activities 296,466 264,108 171,691 - ------------------------------------------------------------------------------------- Cash flows provided (used) by investing activities: Plant and nuclear fuel (excluding AFUDC) (253,885) (231,025) (214,213) Capitalized demand side management costs (37,156) (11,469) 0 Decommissioning fund (15,189) (7,210) (5,896) Investments in electric companies 1,106 1,836 (1,515) - ------------------------------------------------------------------------------------- Net cash used by investing activities (305,124) (247,868) (221,624) - ------------------------------------------------------------------------------------- Cash flows provided (used) by financing activities: Issuances: Common stock 10,823 68,345 68,800 Preferred stock 40,000 40,000 50,000 Long-term debt 815,000 60,000 146,120 Redemptions: Debt retirements (648,625) (123,600) (118,600) Preferred/preference stock (40,000) (40,333) (50,000) Net change in short-term debt (71,349) 65,200 35,770 Dividends paid (92,370) (86,184) (79,545) - ------------------------------------------------------------------------------------- Net cash provided (used) by financing activities 13,479 (16,572) 52,545 - ------------------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents 4,821 (332) 2,612 Cash and cash equivalents at the beginning of the year 3,947 4,279 1,667 - ------------------------------------------------------------------------------------- Cash and cash equivalents at the end of the year $ 8,768 $ 3,947 $ 4,279 ===================================================================================== Cash paid during the year for: Interest, net of amounts capitalized $103,720 $113,076 $115,488 Income taxes $ 30,305 $ 10,095 $ 18,979
The accompanying notes are an integral part of the consolidated financial statements. 30 32 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE A. 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. We follow accounting policies prescribed by our federal and state regulators. We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The financial statements comply with generally accepted accounting principles. Certain prior period amounts on the financial statements were reclassified to conform with current presentation. 2. Revenue Recognition We record revenues for electricity used by our customers, but not yet billed, in order to more closely match revenues with expenses. 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for all fuel costs, the capacity portion of some purchased power costs and some transmission costs to be billed to customers monthly using a forecasted rate. The difference between actual and estimated costs is included in accounts receivable on our consolidated balance sheets until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel. 4. Depreciation and Nuclear Fuel Amortization Our physical property was depreciated on a straight-line basis in 1993, 1992 and 1991 at composite rates of approximately 3.09%, 3.36% and 3.41% per year, respectively, based on estimated useful lives of the various classes of property. The cost of decommissioning Pilgrim Station, our nuclear unit, is excluded from the 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 the decontamination and decommissioning of the United States enrichment facilities used in the production of nuclear fuel. These costs are recovered from our customers through fuel charges. 5. 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. AFUDC is not an item of current cash income, but payment is received for these costs from customers over the service life of the plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1993, 1992 and 1991 were 3.62%, 4.48%, and 6.85%, respectively, and represented only the cost of debt. 31 33 6. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of three months or less. 7. 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. 8. Deferred Debits Deferred debits consist primarily of costs incurred which will be collected from customers through future charges in accordance with agreements with our state regulators. These costs will be expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. A portion of these costs is currently being charged to and collected from customers. 9. Amortization of Discounts, Premiums and Redemption Premiums on Securities We expense discounts, premiums, redemption premiums and related expenses associated with issuances of securities or refinancing of existing securities in equal annual installments over the life of the replacement securities subject to regulatory approval. NOTE B. RETAIL SETTLEMENT AGREEMENTS In 1992 and 1989 our state regulators, the Massachusetts Department of Public Utilities, approved three-year settlement agreements relating to our rate case proceedings. These agreements 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. Refer to Management's Discussion and Analysis for further information related to these settlement agreements. The settlement agreements did not affect our contract or wholesale power rates charged to other utilities, which are regulated by our federal regulators, the Federal Energy Regulatory Commission. NOTE C. INCOME TAXES In the first quarter of 1993 we prospectively adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). This required us to change our methodology of accounting for income taxes from the deferred method to an asset and liability approach. The deferred method of accounting was based on the tax effects of timing differences between income for financial reporting purposes and taxable income. The asset and liability approach requires the recognition of deferred tax liabilities and assets 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 a net regulatory asset of $26.9 million and a corresponding net increase in accumulated deferred income taxes as of December 31, 1993. The regulatory asset represents the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income taxes on our consolidated balance sheet at December 31, 1993 includes $587.8 million of gross deferred income tax liabilities net of $103.0 million of gross 32 34 deferred income tax assets. We have approximately $19 million of alternative minimum tax carryforwards available at December 31, 1993. The major components of accumulated deferred income taxes are a result of differences between book and tax expenses relating to property, plant and equipment. Deferred income tax expense reflected in our consolidated income statements is incurred when certain income and expenses are reported on the tax return in different years than reported in the financial statements. Investment tax credits are included in income over the estimated useful lives of the related property. Components of income tax expense are as follows:
(in thousands) 1993 1992 1991 - ---------------------------------------------------------------------------- Excess tax depreciation over book $12,382 $9,765 $10,802 depreciation Deferred fuel expense (3,142) 2,587 56 Debt portion of allowance for funds used during construction 2,114 2,495 2,856 Massachusetts corporate franchise tax 5,089 6,134 7,140 Deferred nuclear outage expense 2,472 (1,558) 7,014 Cost of removal 3,272 6,904 4,277 Rate and contract settlements 0 10,013 10,196 Municipal property taxes (489) 3,351 3,745 Demand side management programs 3,775 2,978 2,256 Cancelled nuclear unit 0 (4,621) (8,998) Reversal of deferred taxes-settlement agreement, net (19,231) (23,000) (13,000) Adjustment of prior year income tax accrual (2,154) 4,134 2,563 Call premiums on refunded bond issues 5,821 1,029 (288) Trust contributions-postretirement benefits 3,451 0 0 Other (3,057) (3,828) (5,395) - ---------------------------------------------------------------------------- Subtotal deferred income taxes 10,303 16,383 23,224 Current income tax expense 28,711 (385) (1,823) Investment tax credits (4,073) (4,273) (4,290) - ---------------------------------------------------------------------------- Provision for income taxes 34,941 11,725 17,111 - ---------------------------------------------------------------------------- Taxes on other income: Current 1,205 (2,348) 405 Deferred 0 782 1,252 - ---------------------------------------------------------------------------- Subtotal 1,205 (1,566) 1,657 - ---------------------------------------------------------------------------- Total income tax expense $36,146 $10,159 $18,768 ============================================================================
The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate are explained below:
1993 1992 1991 - ----------------------------------------------------------------------------- Statutory tax rate 35.0% 34.0% 34.0% State income tax, net of federal income 4.2 3.9 4.1 tax benefit Investment tax credits (2.6) (3.6) (3.8) Municipal property tax adjustment (0.6) (1.6) (1.6) Adjustment of deferred taxes on cancelled nuclear unit - 2.7 - Reversal of deferred taxes-settlement (13.0) (19.6) (11.5) agreement Federal tax benefit of mandated payments from settlement agreements - (6.2) (3.3) Other 0.4 (0.9) (1.4) - ----------------------------------------------------------------------------- Effective tax rate 23.4% 8.7% 16.5% =============================================================================
33 35 NOTE D. ESTIMATED FUTURE COSTS OF DISPOSING OF SPENT NUCLEAR FUEL AND RETIRING NUCLEAR GENERATING PLANTS The existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. We have a request for a license amendment pending before the Nuclear Regulatory Commission (NRC) to allow modification of the storage facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. The NRC is reviewing our request and we expect approval in 1994. At that time we will initially modify the facility to provide spent fuel storage capacity through approximately 2003. It is the ultimate responsibility of the United States Department of Energy (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. When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. During rate proceedings we provided our regulators a 1991 study documenting a cost of $328 million to decommission the plant. The study is based on the "green field" method of decommissioning, which provides for the plant site to be completely restored to its original state. We are expensing these estimated decommissioning costs over Pilgrim's expected service life. The 1993 expense of approximately $13 million is included in depreciation expense on the consolidated income statements. We receive recovery of this expense from charges to our retail customers and from other utility companies and municipalities who 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 has been partially updated for internal planning purposes to evaluate the potential financial impact of long-term spent fuel storage options resulting from delays in DOE spent fuel removal on the estimated decommissioning cost. The partial update indicates an estimated decommissioning cost of approximately $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. 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. We are also an investor in two other domestic nuclear units. Both of these units receive through the rates charged to their customers an amount to cover the estimated cost to dispose of their spent nuclear fuel and to retire the units at the end of their useful lives. We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. We have access to the South Carolina site through July 1994, but do not presently believe that disposal site access will be provided after that date. Although legislation has been enacted in Massachusetts establishing a regulatory method for managing the state's LLW including the possible siting, licensing and construction of a LLW disposal facility within the state, it appears unlikely that such a facility will be constructed in a timely manner. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management method, we continue to monitor the situation and are investigating other available options, including the possibility of on-site storage. 34 36 NOTE E. CANCELLED NUCLEAR UNIT In May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear unit over approximately eleven and one-half years in accordance with an order received from state regulators. We did not expense any of these costs in 1993. Instead, the remaining balance of approximately $19 million at December 31, 1993 and 1992 will be expensed in 1994 and/or 1995 as approved by our state regulators in our 1992 settlement agreement. 35 37 NOTE F. CAPITAL STOCK AND INDEBTEDNESS Capital Stock
December 31, (dollars in thousands, except per share amounts) 1993 1992 1991 - ------------------------------------------------------------------------------ COMMON STOCK EQUITY: Common stock, par value $1 per share, 100,000,000 shares authorized; 45,129,227, 44,763,055 and 42,047,356 shares issued and outstanding $ 45,129 $ 44,763 $ 42,047 Premium on common stock 612,653 602,196 536,567 Retained earnings 218,292 192,948 174,477 Surplus invested in plant 405 405 405 - ------------------------------------------------------------------------------ Total common stock equity $876,479 $840,312 $753,496 ==============================================================================
CUMULATIVE PREFERRED STOCK: Par value $100 per share, 2,410,000 shares currently authorized; issued and outstanding: Non-mandatory 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 0 0 8.25% 400,000 - 40,000 40,000 0 8.88% 0 - 0 40,000 40,000 - ------------------------------------------------------------------------------ Total non-mandatory redeemable series $123,000 $123,000 $ 83,000 ==============================================================================
Mandatory redeemable series:
Current Shares Series Outstanding - ------------------------------------------------------------------------------ 7.27% 480,000 $48,000 $48,000 $ 50,000 8.00% 500,000 50,000 50,000 50,000 - ------------------------------------------------------------------------------ Total mandatory redeemable series 98,000 98,000 100,000 Less: due within one year 2,000 0 0 - ------------------------------------------------------------------------------ Total mandatory redeemable series, net $96,000 98,000 $100,000 ==============================================================================
CUMULATIVE PREFERENCE STOCK: Par value $1 per share, 8,000,000 shares authorized; none currently issued and outstanding Non-mandatory redeemable series: $1.46 series $ 0 $ 0 $ 2,675 Premium on $1.46 series 0 0 35,658 - ------------------------------------------------------------------------------ Total preference stock $ 0 $ 0 $ 38,333 ==============================================================================
Dividends Declared per Share COMMON STOCK $1.715 $1.655 $1.595 PREFERRED STOCK: 4.25% series $4.253 $4.250 $4.250 4.78% series 4.785 4.780 4.780 7.27% series 7.270 7.270 7.270 7.75% series 5.707 0 0 8.00% series 8.000 8.000 1.337 8.25% series 8.250 5.278 0 8.88% series 2.220 8.880 8.880 PREFERENCE STOCK: $1.46 series $ 0 $0.365 $1.460 Stated rate auction preference stock 0 0 6.900
36 38 Indebtedness
December 31, (dollars in thousands) 1993 1992 - ------------------------------------------------------------------------------- LONG-TERM DEBT: First mortgage bonds: Interest Series Rate Maturity - ------------------------------------------------------------------------------ I 4.750% 1995 $ 0 $ 25,000 J 6.125% 1997 0 40,000 K 6.875% 1998 0 50,000 L 9.000% 1999 0 50,000 M 9.375% 2000 0 60,000 N 8.125% 2001 0 75,000 S Variable 2002 25,000 25,000 Q 9.750% 2003 0 59,375 R 10.950% 2004 0 44,250 P 9.250% 2007 0 60,000 U 10.250% 2014 15,000 15,000 W 9.500% 2016 0 135,000 - ------------------------------------------------------------------------------ Total first mortgage bonds 40,000 638,625 Less: due within one year 0 6,800 - ------------------------------------------------------------------------------ Total first mortgage bonds, net $ 40,000 $ 631,825 ============================================================================== Sewage facility revenue bonds $ 36,300 $ 36,300 Less: funds held by trustee 3,803 12,052 - ------------------------------------------------------------------------------ Total sewage facility revenue bonds, net $ 32,497 $ 24,248 ============================================================================== Debentures: 8.875%, due 1995 $ 100,000 $100,000 5.125%, due 1996 100,000 0 5.700%, due 1997 100,000 0 5.950%, due 1998 100,000 0 6.800%, due 2000 65,000 0 6.050%, due 2000 100,000 0 6.800%, due 2003 150,000 0 9.875%, due 2020 100,000 100,000 9.375%, due 2021 125,000 125,000 8.250%, due 2022 60,000 60,000 7.800%, due 2023 200,000 0 - ------------------------------------------------------------------------------ Total debentures $1,200,000 $385,000 ============================================================================== Unsecured medium-term notes $ 0 $ 50,000 ============================================================================== SHORT-TERM DEBT: Notes payable: Bank loans $106,501 $ 162,500 Commercial paper 97,650 113,000 - ------------------------------------------------------------------------------ Total notes payable $204,151 $ 275,500 ==============================================================================
37 39 1. Common Stock Since December 31, 1990, we issued the following shares of common stock:
Number Total Premium on (in thousands) of Shares Par Value Common Stock - -------------------------------------------------------------------------------- Balance December 31, 1990 38,998 $194,993 $314,822 Dividend reinvestment plan 449 2,181 6,844 Change in par value of common stock (a) 0 (157,727) 157,727 New issue (b) 2,600 2,600 57,174 - ----------------------------------------------------------------------------- Balance December 31, 1991 42,047 42,047 536,567 Dividend reinvestment plan 416 416 9,658 New issue (c) 2,300 2,300 55,971 - ----------------------------------------------------------------------------- Balance December 31, 1992 44,763 44,763 602,196 Dividend reinvestment plan (d) 366 366 10,457 - ----------------------------------------------------------------------------- Balance December 31, 1993 45,129 $ 45,129 $612,653 =============================================================================
(a) In November 1991 our Articles of Organization were amended to increase authorized common stock from 50 million to 100 million shares and reduce the par value from $5 to $1 per common share. (b) We used the net proceeds of the 1991 common stock issuance to retire $55 million of Series X, 11% first mortgage bonds. (c) We used the net proceeds of the 1992 common stock issuance to reduce short-term debt. (d) At December 31, 1993, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 815,170 shares. 2. Cumulative Non-Mandatory Redeemable Preferred and Preference Stock In June 1992 we issued 400,000 shares of 8.25% cumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in June 1997. 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 $1.46 series cumulative non-mandatory redeemable preference stock. In May 1993 we issued 400,000 shares of 7.75% cumulative non-mandatory 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 non-mandatory redeemable preferred stock. 3. Cumulative Mandatory Redeemable Preferred Stock The 480,000 shares of our 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $104.36. The redemption price declines annually each May to par value in May 2002. In May 1993 the stock became subject to sinking fund requirements to retire 20,000 shares at $100 per share plus accrued dividends each year through May 2002. In 1992 we purchased 20,000 shares at a discount on the open market which satisfied the mandatory sinking fund requirement for May 1993. Beginning in 1993, we have the non-cumulative option each May to redeem additional shares, not to exceed 20,000, for the sinking fund at $100 per share plus accrued dividends. 38 40 We are not able to redeem any part of our 500,000 shares of $100 par value 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. 4. Long-Term Debt Substantially all our property, plant, equipment, materials and supplies are subject to lien under the terms of our Indenture of Trust and First Mortgage dated December 1, 1940, and its supplements. Currently only the outstanding Series S and U first mortgage bonds are subject to the terms of the indenture. The aggregate principal amounts of our first mortgage bonds, debentures, and sewage facility revenue bonds (including sinking fund requirements) due in 1994 and 1995 are $0 and $100.6 million, respectively, and $101.6 million per year in 1996 through 1998. Our first mortgage bonds, Series S, adjustable rate due 2002, paid interest at 9.2% per year for the period January 15, 1993 through January 14, 1994. The rate is adjusted annually and is based upon the ten-year constant maturity Treasury rate as published by the Federal Reserve Board. The interest rate for the period January 15, 1994 through January 14, 1995 is 8.2%. In September 1992 we issued $60 million of 8.25% debentures which mature in September 2022. The debentures are redeemable at prices decreasing from 103.78% of par beginning in September 2002, to 100% of par beginning in September 2012. We used the net proceeds from the sale to reduce short-term debt. In October 1992 we redeemed the remaining balance of $45 million Series X first mortgage bonds. In February 1993 we issued $65 million of 6.8% debentures due in 2000. We used the proceeds of this issue to reduce short-term debt. These debentures are not redeemable prior to maturity. In March 1993 we issued $650 million of debentures and used the proceeds to retire ten of twelve outstanding series of first mortgage bonds and reduce short-term debt. The debentures were issued in five separate series with interest rates ranging from 5.125% to 7.8% and maturing between 1996 and 2023. The 5 1/8% debentures due 1996, 5.70% due 1997, 5.95% due 1998 and 6.80% due 2003 are not redeemable prior to maturity. The 7.80% debentures due 2023 are first redeemable in March 2003 at a redemption price of 103.73%. The redemption price decreases annually each March to par value in March 2013. There is no sinking fund requirement for any series of the debentures. In August 1993 we issued $100 million of 6.05% debentures due in 2000. We used the proceeds from this sale to reduce short-term debt. These debentures are not redeemable prior to maturity and have no sinking fund requirements. We redeemed $50 million of 9.65% medium-term notes in September 1992 and $50 million of 9.75% medium-term notes in September 1993. 5. Sewage Facility Revenue Bonds In December 1991, Harbor Electric Energy Company (HEEC), a wholly-owned subsidiary, issued $36.3 million of long-term sewage facility revenue bonds. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds was used to retire $21 million of short-term sewage facility revenue bonds at maturity. The remainder of the proceeds, which is on deposit with the trustee, is being used to finance the construction of HEEC's permanent substation located on Deer Island (in Boston Harbor) and to 39 41 fund an amount which must remain in reserve with the trustee. If HEEC should have insufficient funds to pay certain costs on a timely basis or be unable to meet certain net worth requirements, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $7 million. 6. 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:
(thousands of dollars) 1993 1992 1991 - ------------------------------------------------------------------------------ Maximum short-term borrowings $320,000 $314,998 $324,400 Weighted average amount outstanding $220,149 $233,286 $221,481 Weighted average interest rates, excluding commitment fees 3.4% 4.1% 6.4% - ------------------------------------------------------------------------------
NOTE G. 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 fund The fair value of $70.1 million is based on quoted market prices of securities held. Cash and cash equivalents The carrying amount of $8.8 million approximates fair value due to the short-term nature of these securities. Mandatory redeemable cumulative preferred stock, first mortgage bonds, sewage facility revenue bonds and debentures 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, 1993 are as follows:
Carrying Fair (in thousands) Amount Value - ---------------------------------------------------------------------- Mandatory redeemable cumulative preferred $ 98,000 $ 105,935 stock First mortgage bonds 40,000 44,132 Sewage facility revenue bonds 36,300 40,528 Debentures 1,200,000 1,237,924 - ----------------------------------------------------------------------
NOTE H. COMMITMENTS AND CONTINGENCIES 1. Capital Commitments At December 31, 1993, we had estimated contractual obligations for plant and equipment of approximately $71 million. 40 42 2. Lease Commitments We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both noncancelable leases and transmission agreements for the years after 1993 are as follows:
(in thousands) - ------------------------------------------------------------------------ 1994 $ 27,375 1995 23,878 1996 21,299 1997 19,217 1998 17,969 Years thereafter 139,474 - ------------------------------------------------------------------------ Total $249,212 ========================================================================
We will capitalize a portion of these lease rentals as part of plant expenditures in the future. Our total expense for both lease rentals and transmission agreements for 1993, 1992 and 1991 was $30 million, $30 million and $33.5 million, respectively, net of capitalized expenses of $5 million, $5 million, and $4.8 million, respectively. 3. 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 in 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, 1993, our portion of these guarantees was approximately $22 million. 4. Yankee Atomic Electric Company In February 1992 the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and, in time, decommission that facility. We relied on Yankee Atomic for less than one percent of our system capacity. We have a 9.5% stock investment of approximately $2 million in Yankee Atomic. In 1993 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 $33 million as of December 31, 1993. This estimate is recorded on our consolidated balance sheet as a power contract liability in deferred credits. An offsetting power contract regulatory asset is included in deferred debits as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement. 5. Nuclear Insurance The federal Price-Anderson Act currently provides $9.4 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 $8.8 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 116 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 new commercial nuclear units are licensed and 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 41 43 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 approximately $14.6 million under both 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 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 an assessment. 6. Litigation In March 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 is vigorously defending this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings. 7. Hazardous Waste State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the Massachusetts Department of Environmental Protection. We are currently evaluating the potential costs associated with the cleanup of sites where we have been identified as the owner or operator. There are uncertainties associated with these potential 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 certain other multi-party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings. NOTE I. PENSIONS, OTHER POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS 1. Pensions We have a noncontributory funded retirement plan, with certain features that allow voluntary contributions. Benefits are based upon an employee's years of service and compensation during the last years of employment. Our funding policy is to contribute each year an amount that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Plan assets are primarily equities, bonds, insurance contracts and real estate. 42 44 Net pension cost included the following components:
(in thousands) 1993 1992 1991 - ----------------------------------------------------------------------------- Current service cost - benefits earned $11,734 $10,683 $ 8,567 Interest cost on projected benefit obligation 33,181 32,287 29,817 Actual return on plan assets (44,470) (23,281) (60,873) Net amortization and deferral 8,528 (13,549) 26,811 - ----------------------------------------------------------------------------- Net pension cost(a) $ 8,973 $ 6,140 $ 4,322 ============================================================================= (a) In accordance with an agreement with our state regulators, we deferred our net pension costs in excess of the annual funding amounts and will recover these costs from customers over time. Net pension costs recorded as expense were approximately $5 million in 1993 and $0 in 1992 and 1991.
We used the following assumptions for calculating pension cost:
1993 1992 1991 - ----------------------------------------------------------------------------- Discount rate 8.25% 8.25% 9.00% Expected long-term rate of return on assets 10.00% 10.00% 10.00% Compensation increase rate 4.50% 4.50% 4.50% - -----------------------------------------------------------------------------
We changed our discount rate assumption to 7.0% for calculating pension cost effective January 1994. The plan's funded status at December 31, 1993 and 1992 was as follows:
(in thousands) 1993 1992 - ----------------------------------------------------------------------------- Actuarial present value of benefit obligations: Accumulated benefit obligation, including vested benefits of $384,150 and $322,836 $400,895 $339,035 ============================================================================= Plan assets at fair value $394,233 $392,407 Projected obligation for service rendered to date (509,661) (418,312) - ----------------------------------------------------------------------------- Projected benefit obligation in excess of plan assets (115,428) (25,905) Unrecognized prior service cost 8,139 8,817 Unrecognized net (gain) loss 75,352 (6,810) Unrecognized net obligation 9,932 10,866 - ----------------------------------------------------------------------------- Net pension liability $(22,005) $(13,032) =============================================================================
We used the following assumptions for calculating the plan's year-end funded status:
1993 1992 - --------------------------------------------------------------------------- Discount rate 7.00% 8.25% Compensation increase rate 4.50% 4.50% - ---------------------------------------------------------------------------
2. Other Postretirement Benefits In addition to pension benefits, we also currently provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. Effective January 1993 we adopted Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). This requires us to record a liability during the working years of employees for the expected costs of providing their postretirement benefits other than pensions (PBOPs). Prior to 1993 our 43 45 policy was to record the cost of PBOPs when paid. Our transition obligation on January 1, 1993 was approximately $183 million, which we elected to recognize over 20 years as permitted by SFAS 106. Our total cost of PBOPs under SFAS 106 in 1993 was approximately $28 million, an increase of approximately $18 million over costs incurred under our prior method of accounting for PBOPs. Our 1992 settlement agreement provides us with a phase-in of a portion of the increased costs and allows us to defer the additional costs in excess of the phase-in amounts to the extent that we fund an external trust. In December 1993 we deposited $18 million on a tax deductible basis into external trusts for the payment of PBOPs. Accordingly, in 1993 we recorded an expense of approximately $16 million, reflecting the amount of cost recovery from customers, and deferred approximately $12 million for future recovery. We capitalized approximately 19% of these costs. Postretirement benefits cost consisted of the following in 1993:
(in thousands) - ------------------------------------------------------------------------------ Current service cost - benefits earned $ 4,351 Interest cost on transition obligation 14,286 Amortization of transition obligation 9,151 - ------------------------------------------------------------------------------ Net postretirement benefits cost $27,788 ==============================================================================
We used an 8.0% weighted average discount rate and 4.5% rate of compensation increase assumption for calculating the transition obligation and the 1993 postretirement benefits cost. Our expected long-term rate of return on assets is 9.0%. We also assumed a 12.5% health care cost trend rate. Effective January 1, 1994 we changed the discount and health care cost trend rates to 7.0% and 9.0%, respectively, in order to more accurately estimate our future benefit payments. The health care cost trend rate is assumed to decrease by one percent each year to 5% in 1998 and years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. For example, a one percent increase in the rate would increase the total service and interest costs in 1993 by approximately 16% and would increase the accumulated obligation at December 31, 1993 by approximately 13%. The postretirement benefits program's funded status at December 31, 1993 was as follows:
(in thousands) - ------------------------------------------------------------------------------------- Trust assets at fair value $ 18,016 Accumulated obligation for service rendered to date from: Retirees $(75,216) Active employees eligible to retire (64,880) Active employees not eligible to retire (73,285) (213,381) - ------------------------------------------------------------------------------------- Accumulated benefit obligation in excess of trust assets (195,365) assets Unrecognized loss 21,497 Unrecognized net obligation 173,868 - ------------------------------------------------------------------------------------- Net postretirement benefits liability $ 0 =====================================================================================
The trust assets consist of money market funds at December 31, 1993. 3. Postemployment Benefits Statement of Financial Accounting Standards No. 112, Employers' Accounting for Postemployment Benefits, will be effective for the first quarter of 1994. This statement will require us to record a liability computed on an actuarial basis for the estimated cost of providing postemployment benefits. Postemployment benefits provided to former or inactive employees, their beneficiaries and covered dependents include salary continuation, severance benefits, disability-related benefits (including workers' compensation), job training and counseling and continuation of health care and life insurance coverage. We currently recognize 44 46 the cost of these benefits primarily as claims are paid. We do not anticipate a material effect on net income from adopting this statement. NOTE J. NEW ACCOUNTING PRONOUNCEMENT We will adopt Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities, in the first quarter of 1994. This statement may require us to classify the investments in our nuclear decommissioning fund on our consolidated balance sheet based on how long we intend to hold the individual securities. These investments may be classified as "available for sale" and we may also be required to report any unrealized gains and losses on the investments as a separate component of shareholders' equity. We do not expect the adoption of this statement to have a material effect on shareholders' equity. NOTE K. 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 in our consolidated income statements. Information relating to these contracts as of December 31, 1993 is as follows: 45 47
proportionate share (in thousands) Units of --------------------------------------- Capacity 1993 1993 Interest Debt Contract Purchased(a) Minimum Portion of Outstanding Expiration ------------ Debt Minimum Through Cont. Contract Date % MW Service Debt Service Exp. Date - -------------------------------------------------------------------------------------- Canal Unit 1 2001 25.0 142 $ 781 $ 314 $ 2,118 Mass. Bay Trans- portation Authority 2005 100.0 35 (b) (b) (b) Connecticut Yankee Atomic 2007 9.5 56 2,579 1,670 15,898 Ocean State Power - Unit 1 2010 23.5 65 5,323 3,948 22,747 Ocean State Power - Unit 2 2011 23.5 65 4,422 3,376 19,401 Northeast Energy Associates (c) (c) 219 (c) (c) (c) L'Energia 2013 73.0 64 (d) (d) (d) - --------------------------------------------------------------------------------------- Total 646 $13,105 $9,308 $60,164 ======================================================================================= (a) The Northeast Energy Associates contract represents 6.4% of our total system generation capability. The remaining units listed above represent 12.6% 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 33.6MW) plus incremental operating, maintenance and fuel costs. The total charges for this contract in 1993 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 1993 were approximately $116 million. (d) The L'Energia contract started in March 1993. We purchase 73% of the energy output of this unit. We pay for this energy based on a price per kWh actually received. The total charges under this contract for 1993 were approximately $15 million.
Our total fixed and variable costs for these contracts in 1993, 1992 and 1991 were approximately $225 million, $217 million and $154 million, respectively. Our minimum fixed payments under these contracts for the years after 1993 are as follows:
(in thousands) - ---------------------------------------------------------------------------- 1994 $ 69,432 1995 72,418 1996 75,376 1997 71,147 1998 72,429 Years thereafter 725,236 - ----------------------------------------------------------------------------- Total $1,086,038 ============================================================================= Total present value $ 558,600 =============================================================================
46 48 2. Long-Term Power Sales In addition to our power sales to four wholesale customers, 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 Units of Capacity Sold Expiration ----------------------- 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. Selected Consolidated Quarterly Financial Data (Unaudited) (in thousands, except earnings per share)
Balance Earnings Available Per Share of Operating Operating Net for Common Common Revenues Income Income Stock Stock (a) - ----------------------------------------------------------------------------- 1993 First quarter $354,752 $ 41,721 $15,452 $11,377 $0.25 Second quarter 346,074 49,282 22,829 19,125 0.43 Third quarter 436,024 96,319 70,015 66,052 1.47 Fourth quarter 345,403 37,997 9,922 5,959 0.13 1992 First quarter $343,505 $ 41,930 $13,816 $ 9,553 $0.23 Second quarter 300,566 32,629 4,953 852 0.02 Third quarter 408,255 100,890 73,698 69,593 1.60 Fourth quarter 359,427 45,451 14,831 10,750 0.24 (a) Based upon the weighted average number of common shares outstanding during the quarter.
Electricity sales and revenues are seasonal in nature, with both being lower in the spring and fall seasons. Quarterly earnings for 1993 reflect a change in the months for which certain customers were billed at higher rates as mandated by the DPU. These customers were billed at these higher rates in July through October in 1992 and in June through September in 1993. The change in billing increased second quarter earnings and reduced fourth quarter earnings by approximately $0.23 per share in 1993. 47 49 Item 9. Changes in and Disagreements with Accountants on Accounting and - ------- --------------------------------------------------------------- Financial Disclosure -------------------- None. 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 17, 1994 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 17, 1994, 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 5 through 11 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference. 48 50 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 pages 4 through 5 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference. (c) Changes in Control - ----------------------- Not applicable. Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Not applicable. 49 51 Part IV ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - -------------------------------------------------------------------------
(a) Exhibits and Consolidated Financial Statement Schedules Page - ----------------------------------------------------------- ---- Consolidated Statements of Income for each of the three years in the period ended December 31, 1993 28 Consolidated Statements of Retained Earnings for each of the three years in the period ended December 31, 1993 28 Consolidated Balance Sheets as of December 31, 1993 and 1992 29 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1993 30 Notes to Consolidated Financial Statements 31 Selected Consolidated Quarterly Financial Data (Unaudited) 47 Report of Independent Accountants 64 Schedules for years ended December 31, 1993, 1992 and 1991: V - Property, Plant and Equipment S-1 VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment S-4 VII - Guarantees of Securities of Other Issuers S-7 IX - Short-Term Borrowings S-8 X - Supplementary Income Statement Information S-9
All other schedules are omitted since they are not required, not applicable, or contain only information which is otherwise provided in the financial statements or notes in Item 8. 50 52
Exhibit SEC Docket ------- ---------- Exhibit 3 Articles of Incorporation and By-Laws - --------- ------------------------------------- Incorporated herein by reference: 3.1 Restated Articles of Organization 2(a)4 2-58587 3.1.1 Amendment to Restated Articles of 2.4 2-64975 Organization, filed May 5, 1977 3.1.2 Amendment to Restated Articles of 3.1.2 1-2301 Organization, filed May 26, 1978 Form 10-K for the year ended December 31, 1991 3.1.3 Amendment to Restated Articles of 3.1.3 1-2301 Organization, filed May 6, 1980 Form 10-K for the year ended December 31, 1991 3.1.4 Amendment to Restated Articles of 3.1 1-2301 Organization, filed May 4, 1983 Form 10-Q for the quarter ended March 31, 1983 3.1.5 Amendment to Restated Articles of 3.1 1-2301 Organization, filed April 28, 1986 Form 10-Q for the quarter ended March 31, 1986 3.1.6 Amendment to Restated Articles of 3.5 1-2301 Organization, filed August 27, 1986 Form 10-K for the year ended December 31, 1986 3.1.7 Amendment to Restated Articles of 3.1 1-2301 Organization, filed February 19, 1987 Form 10-Q for the quarter ended March 31, 1987 3.1.8 Certificate of Vote of Directors 4.2 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed March 9, 1987 for the quarter ended September 30, 1988
51 53
Exhibit SEC Docket ------- ---------- 3.1.9 Amendment to Restated Articles of 3.1.8 1-2301 Form 10-K Organization, filed May 5, 1987 for the year ended December 31, 1987 3.1.10 Amendment to Restated Articles of 4.1 33-24271 Organization, filed May 27, 1988 Registration Statement dated September 22, 1988 3.1.11 Certificate of Vote of Directors 4.3 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed October 4, 1988 for the quarter ended September 30, 1988 3.1.12 Amendment to Restated Articles of 3.1.12 1-2301 Organization, filed November 7, 1991 Form 10-K for the year ended December 31, 1991 3.1.13 Certificate of Vote of Directors 3.1.13 1-2301 Establishing a Series of a Class Form 10-K of Stock, filed November 26, 1991 for the year ended December 31, 1991 3.1.14 Certificate of Vote of Directors 4.1 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed June 8, 1992 for the quarter ended June 30, 1992 3.1.15 Certificate of Vote of Directors 3.1 1-2301 Establishing a Series of a Class Form 10-Q of Stock, filed April 30, 1993 for the quarter ended June 30, 1993 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
52 54
Exhibit SEC Docket ------- ---------- Exhibit 4 Instruments Defining the Rights of - --------- ---------------------------------- Security Holders, Including Indentures -------------------------------------- Incorporated herein by reference: 4.1 Indenture of Trust and First Mortgage B-2 2-4564 dated December 1, 1940 with State Street Trust Company 4.1.1 Tenth supplemental indenture dated 7.5 2-8349 April 1, 1950 4.1.2 Twelfth supplemental indenture dated 4.2 2-80748 November 15, 1951 4.1.3 Twenty-fourth supplemental indenture 4.1.3 1-2301 dated June 1, 1962 Form 10-K for the year ended December 31, 1990 4.1.4 Twenty-seventh supplemental indenture 4.1.4 1-2301 dated November 1, 1965 Form 10-K for the year ended December 31, 1990 4.1.5 Twenty-ninth supplemental indenture 4.1.5 1-2301 dated June 1, 1967 Form 10-K for the year ended December 31, 1990 4.1.6 Thirtieth supplemental indenture 4.1.6 1-2301 dated November 1, 1968 Form 10-K for the year ended December 31, 1990 4.1.7 Thirty-first supplemental indenture 4.1.7 1-2301 dated December 1, 1969 Form 10-K for the year ended December 31, 1990 4.1.8 Thirty-second supplemental indenture 4.1.8 1-2301 dated July 1, 1970 Form 10-K for the year ended December 31, 1990
53 55
Exhibit SEC Docket ------- ---------- 4.1.9 Thirty-third supplemental indenture 4.1.9 1-2301 dated May 15, 1971 Form 10-K for the year ended December 31, 1990 4.1.10 Thirty-fifth supplemental indenture 4.1.10 1-2301 dated April 15, 1977 Form 10-K for the year ended December 31, 1989 4.1.11 Thirty-sixth supplemental indenture 4.1.11 1-2301 dated December 15, 1978 Form 10-K for the year ended December 31, 1989 4.1.12 Thirty-seventh supplemental indenture 4.1.12 1-2301 dated October 31, 1979 Form 10-K for the year ended December 31, 1989 4.1.13 Thirty-eighth supplemental indenture 4.1.13 1-2301 dated January 1, 1982 Form 10-K for the year ended December 31, 1991 4.1.14 Thirty-ninth supplemental indenture 4.1 1-2301 dated April 15, 1983 Form 10-Q for the quarter ended March 31, 1983 4.1.15 Fortieth supplemental indenture 4.1 1-2301 dated April 1, 1984 Form 10-Q for the quarter ended March 31, 1984 4.1.16 Forty-first supplemental indenture 4.1 1-2301 dated April 1, 1985 Form 10-Q for the quarter ended March 31, 1985
54 56
Exhibit SEC Docket ------- ---------- 4.1.17 Forty-second supplemental indenture 4.1 1-2301 dated July 15, 1986 Form 10-Q for the quarter ended June 30, 1986 4.1.18 Forty-third supplemental indenture 4.1 1-2301 dated September 15, 1987 Form 10-Q for the quarter ended September 30, 1987 4.1.19 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 4.1.20 First Supplemental Indenture 4.1 1-2301 dated June 1, 1990 to Form 8-K Indenture dated September 1, dated 1988 with Bank of Montreal Trust June 28, 1990 Company - 9 7/8% debentures due June 1, 2020 4.1.21 Votes of the Pricing Committee of the 4.1 1-2301 Board of Directors of Boston Edison Form 10-Q Company taken December 11, 1990 for the re 8 7/8% debentures due quarter ended December 15, 1995 March 31, 1991 4.1.22 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, 1991 Shawmut Bank, N.A., as Trustee, dated November 1, 1991 4.1.23 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 4.1.24 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K for the year ended December 31, 1992
55 57
Exhibit SEC Docket ------- ---------- 4.1.25 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 4.1.26 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 6.8% debentures due February 1, 2000 year ended December 31, 1992 4.1.27 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, 1992 5.95% debentures due March 15, 1998, 6.80% debentures due March 15, 2003, 7.80% debentures due March 15, 2023 Filed herewith: 4.1.28 Votes of the Pricing Committee of the -- -- Board of Directors of Boston Edison Company taken August 18, 1993 re 6.05% debentures due August 15, 2000
Exhibit 10 Material Contracts - ----------- ------------------ Executive Compensation: Incorporated herein by reference: 10.1 Key Executive Benefit Plan 10.13 1-2301 (1982 Form of Agreement) Form 10-K for the year ended December 31, 1992 10.1.1 Amendment to Key Executive Benefit 10.4.1 1-2301 Plan dated February 1, 1986 Form 10-K for the year ended December 31, 1985 10.1.2 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, for the May 1986 quarter ended June 30, 1986
56 58
Exhibit SEC Docket ------- ---------- 10.1.3 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May Form 10-K 1986, with modifications, applicable for the to Bernard W. Reznicek, George W. year ended Davis and Thomas J. May 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 Performance Share Plan 10.1 1-2301 Form 10-Q for the quarter ended September 30, 1991 10.4 1991 Director Stock Plan 10.1 1-2301 Form 10-Q for the quarter ended March 31, 1991 10.5 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 1, 1990 Form 10-K for the year ended December 31, 1992 10.6 Boston Edison Company Deferred 10.12 1-2301 Compensation Plan dated Form 10-K January 1, 1990 for the year ended December 31, 1992 10.7 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 10.8 Description of Supplemental 10.5 1-2301 Fee Arrangement for Certain Form 10-K Directors for the year ended December 31, 1983 Filed herewith: 10.8.1 Directors Retirement Benefit -- -- (1993 Plan)
57 59
Exhibit SEC Docket ------- ---------- Exhibit 18 Letter re Change in Accounting Principle - ---------- ---------------------------------------- Incorporated herein by reference: 18.1 Letter of Independent Certified 18.1 1-2301 Public Accountants Form 10-Q for the quarter ended March 31, 1990
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.
58 60
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) 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) and March 17, 1993 (33-59662 and 33-59682).
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, 1989 Light Department of the Town of 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, 1989 21, 1989 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
59 61
Exhibit SEC Docket ------- ---------- 99.5 Information required by SEC Form - 1-2301 11-K for certain Company employee Form 8 benefit plans for the years ended Amendments to December 31, 1992, 1991 and 1990 Form 10-K for the years ended December 31, 1992, 1991 and 1990 dated June 29, 1993, June 26, 1992 and June 28, 1991, 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
60 62 (b) Reports on Form 8-K - ------------------------ A Form 8-K dated October 28, 1993 was filed with the Securities and Exchange Commission by the Company. This report announced the Company's earnings for the three and twelve months ended September 30, 1993. A Form 8-K dated January 27, 1994 was filed with the Securities and Exchange Commission by the Company. This report contained a press release announcing the Company's earnings for the twelve and three months ended December 31, 1993. 61 63 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/ Charles E. Peters, Jr. ------------------------------- Charles E. Peters, Jr. Senior Vice President - Finance (Principal Financial Officer) Date: March 24, 1994 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 24th day of March 1994. /s/ Bernard W. Reznicek - ------------------------------- Chairman of the Board and Chief Executive Bernard W. Reznicek Officer /s/ Thomas J. May - ------------------------------- President and Chief Operating Officer Thomas J. May and Director /s/ George W. Davis - ------------------------------- Executive Vice President and Director George W. Davis /s/ Robert J. Weafer, Jr. - ------------------------------- Vice President, Controller and Robert J. Weafer, Jr. Chief Accounting Officer /s/ William F. Connell - ------------------------------- Director William F. Connell /s/ Gary L. Countryman - ------------------------------- Director Gary L. Countryman - ------------------------------- Director Thomas G. Dignan, Jr.
62 64 /s/ Charles K. Gifford - ------------------------------- Director Charles K. Gifford /s/ Nelson S. Gifford - ------------------------------- Director Nelson S. Gifford /s/ Kenneth I. Guscott - ------------------------------- Director Kenneth I. Guscott /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 /s/ Paul E. Tsongas - ------------------------------- Director Paul E. Tsongas /s/ Charles A. Zraket - ------------------------------- Director Charles A. Zraket
63 65 REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Directors of Boston Edison Company: We have audited the consolidated financial statements and the financial statement schedules of Boston Edison Company and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, 1993 and 1992, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. In addition, in our opinion, the consolidated financial statement schedules referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein. COOPERS & LYBRAND Boston, Massachusetts January 25, 1994 64 66 Boston Edison Company Schedule V Property, Plant and Equipment December 31, 1993 (in thousands)
Column A Column F - ------------------------------ ---------- Balance at end Classification of period - ------------------------------ ---------- Electric plant: Land and rights of way $ 38,944 Generating station and substation buildings and misc. structures 472,789 Electric generating equipment 1,622,664 Transmission, distribution, street lighting and other utilization equipment 1,720,798 Capitalized DSM 48,625 ---------- Total electric plant 3,903,820 Nuclear fuel 273,867 Non-utility property 956 Construction work in progress 144,835 Total $4,323,478 ========== (1) The information required in columns B, C, D and E is omitted as neither the total additions nor the total retirements during the year exceed 10% of the balance at the end of 1993. Total additions and retirements were $252,770 and $34,147, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates ranging from 1.80% to 4.03% in 1993. For further information relating to the Company's policies regarding depreciation and amortization, see Note A included in Item 8. (3) Approximately $92,000 of additions in 1993 relate to various modifications made to the Company's transmission and distribution systems, approximately $73,000 represent an increase in generating equipment, approximately $37 million represent capitalized DSM and the remainder includes additions to generating station and other plant.
S-1 67 Boston Edison Company Schedule V Property, Plant and Equipment December 31, 1992 (in thousands)
Column A Column F - ------------------------------ ---------- Balance at end Classification of period - ------------------------------ ---------- Electric plant: Land and rights of way $ 38,488 Generating station and substation buildings and misc. structures 427,780 Electric generating equipment 1,484,509 Transmission, distribution, street lighting and other utilization equipment 1,666,525 Capitalized DSM 11,469 ---------- Total electric plant 3,628,771 Nuclear fuel 270,420 Non-utility property 956 Construction work in progress 182,458 ---------- Total $4,082,605 ========== (1) The information required in columns B, C, D and E is omitted as neither the total additions nor the total retirements during the year exceed 10% of the balance at the end of 1992. Total additions and retirements were $244,215 and $34,036, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates ranging from 2.67% to 4.29% in 1992. For further information relating to the Company's policies regarding depreciation and amortization, see Note A included in Item 8. (3) Approximately $95,000 of additions in 1992 relate to various modifications made to the Company's transmission and distribution systems, approximately $78,000 represent an increase in generating equipment, approximately $31,000 represent increases in nuclear fuel and the remainder includes additions to generating station and other plant.
S-2 68 Boston Edison Company Schedule V Property, Plant and Equipment December 31, 1991 (in thousands)
Column A Column F - ----------------------------- ---------- Balance at end Classification of period - ----------------------------- ---------- Electric plant: Land and rights of way $ 38,495 Generating station and substation buildings and misc. structures 408,249 Electric generating equipment 1,475,395 Transmission, distribution, street lighting and other utilization equipment 1,609,912 ---------- Total electric plant 3,532,051 Nuclear fuel 256,199 Non-utility property 956 Construction work in progress 99,870 ---------- Total $3,889,076 ========== (1) The information required in columns B, C, D and E is omitted as neither the total additions nor the total retirements during the year exceed 10% of the balance at the end of 1991. Total additions and retirements were $210,885 and $30,333, respectively. (2) Electric plant was depreciated on a straight-line basis at various rates ranging from 2.84% to 4.59% in 1991. For further information relating to the Company's policies regarding depreciation and amortization, see Note A included in Item 8. (3) Approximately $87,000 of additions in 1991 relate to various modifications made to the Company's transmission and distribution systems, approximately $99,000 represent an increase in generating equipment and the remainder includes additions to generating station and other plant.
S-3 69 Boston Edison Company Schedule VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 1993 (in thousands)
- ------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F - ------------------------------------------------------------------------------------------ Additions Balance at Charged to Balance beginning Costs and Other at end Description of period Expenses Retirements Changes of period - ------------------------------------------------------------------------------------------ Depreciation reserve: Electric plant: Production-fossil $ 275,749 $ 25,981 $17,619 $ 182 $ 284,293 -nuclear 352,997 43,184(A) 2,883 0 393,298 -other 18,884 1,089 579 100 19,494 -------------------------------------------------------------------- Total production 647,630 70,254 21,081 282 697,085 Transmission 129,710 6,627 289 46 136,094 Distribution 339,153 29,727 17,863 2,428 353,445 General 58,490 15,584(B) 12,608 65 61,531 Capitalized DSM 0 6,968 0 0 6,968 Harbor Electric Energy Company 2,311 925 0 0 3,236 -------------------------------------------------------------------- Total electric 1,177,294 130,085 51,841 2,821(D) 1,258,359 Accumulated amortization of nuclear fuel (F) 201,978 21,815 0 (3,316)(E) 220,477 -------------------------------------------------------------------- Total $1,379,272 $151,900 $51,841(C) $ (495) $1,478,836 ==================================================================== (A) Excludes $12,865 of nuclear decommissioning costs. (B) Includes $9,237 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $17,694 of removal costs. (D) Includes salvage value of property retired of $2,568 and FERC audit adjustments from audit report covering the period 1/1/87 - 12/31/90 of $253. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial statements included in Item 8.
S-4 70 Boston Edison Company Schedule VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 1992 (in thousands)
- --------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F - -------------------------------------------------------------------------------------- Additions Balance at Charged to Balance beginning Costs and Other at end Description of period Expenses Retirements Changes of period - -------------------------------------------------------------------------------------- Depreciation reserve: Electric plant: Production-fossil $ 268,744 $ 26,106 $19,141 $ 40 $ 275,749 -nuclear 313,870 39,948(A) 1,209 388 352,997 -other 18,499 1,713 1,978 650 18,884 ------------------------------------------------------------------ Total production 601,113 67,767 22,328 1,078 647,630 Transmission 120,533 9,770 628 35 129,710 Distribution 323,178 34,362 19,919 1,532 339,153 General 51,795 10,416(B) 3,723 2 58,490 Harbor Electric Energy Company 1,372 939 0 0 2,311 ------------------------------------------------------------------ Total electric 1,097,991 123,254 46,598 2,647(D) 1,177,294 Accumulated amortization of nuclear fuel (F) 180,137 25,473 0 (3,632)(E) 201,978 ------------------------------------------------------------------ Total $1,278,128 $148,727 $46,598(C) $ (985) $1,379,272 ================================================================== (A) Excludes $5,575 of nuclear decommissioning costs. (B) Includes $5,976 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $12,562 of removal costs. (D) Represents salvage value of property retired. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial statements included in Item 8.
S-5 71 Boston Edison Company Schedule VI Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 1991 (in thousands)
- ---------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Column F - ---------------------------------------------------------------------------------------- Additions Balance at Charged to Balance beginning Costs and Other at end Description of period Expenses Retirements Changes of period - ---------------------------------------------------------------------------------------- Depreciation reserve: Electric plant: Production-fossil $ 254,402 $ 24,989 $10,790 $ 143 $ 268,744 -nuclear 276,126 38,109(A) 365 0 313,870 -other 16,713 1,788 2 0 18,499 ----------------------------------------------------------------- Total production 547,241 64,886 11,157 143 601,113 Transmission 110,369 10,308 148 4 120,533 Distribution 312,855 33,711 25,112 1,724 323,178 General 44,444 10,238(B) 2,889 2 51,795 Harbor Electric Energy Company 462 910 0 0 1,372 ----------------------------------------------------------------- Total electric 1,015,371 120,053 39,306 1,873(D) 1,097,991 Accumulated amortization of nuclear fuel (F) 163,694 19,869 0 (3,426)(E) 180,137 ----------------------------------------------------------------- Total $1,179,065 $139,922 $39,306(C) $(1,553) $1,278,128 ================================================================= (A) Excludes $4,675 of nuclear decommissioning costs. (B) Includes $6,179 of amortization of leasehold improvements, computer software and load management program costs. (C) Includes $8,974 of removal costs. (D) Represents salvage value of property retired. (E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal. (F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial statements included in Item 8.
S-6 72 Boston Edison Company Schedule VII Guarantees of Securities of Other Issuers December 31, 1993 (in thousands)
- ------------------------------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F Column G - ------------------------------------------------------------------------------------------------------------------------------ Amount in Total amount treasury of guaranteed Amount issuer of Nature of Name of issuer and owned by securities Nature of default of securities Title of issue outstanding Company guaranteed guarantee by issuer - ------------------------------------------------------------------------------------------------------------------------------ Yankee Atomic Electric Company: $40 Million Amortizing Term Loan - expires 1997 $ 1,300 none none guarantee of none principal and interest New England Hydro Finance Company, Inc.: (1) Series A Note - due 2001 $10,000 none none guarantee of none Series B Note - due 2007 6,300 principal Series C Note - due 2015 5,700 and interest ------- Total $22,000 ======= (1) As part of Hydro-Quebec Phase II, the Company and other New England electric utilities became equity owners in New England Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation, the parent companies and guarantors of New England Hydro Finance Company, Inc. The Company and other equity participants agreed to guarantee severally their proportionate share of the borrowings outstanding of these companies pursuant to the Note and Guarantee Agreement dated April 15, 1991. The Company and other equity participants also guarantee their proportionate share of the total obligations of the participants who do not meet certain credit criteria.
S-7 73 Boston Edison Company Schedule IX Short-Term Borrowings Year ended December 31, (in thousands)
- ------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Column F - ------------------------------------------------------------------------------------------------ Weighted Maximum Average average Category of December 31 amount amount interest aggregate Balance weighted outstanding outstanding rate short-term at end average during the during the during the borrowings of period interest rate period period period - ------------------------------------------------------------------------------------------------ 1993 (1) $204,151 3.5% $320,000 $220,149 3.4% 1992 (1) $275,500 3.8% $314,998 $233,286 4.1% 1991 (1) $210,300 6.1% $324,400 $221,481 6.4%
(1) Borrowings under: Year ended December 31, --------------------------------------
1993 1992 1991 -------- -------- -------- Lines of credit $106,501 $162,500 $ 89,000 Commercial paper 97,650 113,000 121,300 -------- -------- -------- Total $204,151 $275,500 $210,300 ======== ======== ========
For information regarding the Company's borrowing arrangements, see Note F, part 6, to the consolidated financial statements included in Item 8. S-8 74 Boston Edison Company Schedule X Supplementary Income Statement Information Year ended December 31, (in thousands)
Column A Column B - ------------------------------------------- ---------------------------- Charged to costs Item and expenses - ------------------------------------------- ---------------------------- 1993 1992 1991 ---------------------------- Maintenance and repairs* $94,826 $87,113 $102,215 ============================ Taxes other than payroll and income taxes: Municipal property $77,238 $63,430 $ 51,486 ============================ * Amounts are net of capitalized expenses.
For amortization of deferred cost of cancelled nuclear unit and amortization of deferred nuclear outage costs, see the consolidated statements of income included in Item 8. S-9 EX-4.1.28 2 VOTES OF THE PRICING COMMITTEE 1 Exhibit 4.1.28 Pricing Committee Meeting Boston, August 18, 1993 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, August 18, 1993, at five minutes past twelve o'clock p.m., local time, the Chairman presiding. Present: Messrs. Reznicek and 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, Messrs. Peters, Alpert, Frigard and Conway and Ms. O'Neil. Absent: None. Messrs. Reznicek and Peters presented management's proposal to sell $100,000,000 principal amount of debentures. Mr. Reznicek summarized the votes being presented for action by the directors. 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 on January 28, 1993, the Company issue and sell $100,000,000 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 6.05% Debentures due August 15, 2000 (the "Debentures"). Voted: That the Debentures be issued with the following terms: Maturity Date: August 15, 2000 Interest Rate: 6.05% Interest Payment Date: February 15 and August 15 of each year commencing February 15, 1994 Price to the Public: 99.935% Proceeds to the Company: 99.31% 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 executive or senior vice president, the treasurer or any assistant treasurer of the Company be, and each of them acting 65 2 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 executive or 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. 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 executive or senior vice president, the treasurer or any assistant treasurer be, and each of them is, hereby authorized to file with the Trustee 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. 66 3 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: Theodora S. Convisser Clerk 67 EX-10.8.1 3 DIRECTORS OF RETIREMENT PLAN 1 Exhibit 10.8.1 Directors Retirement Benefit (1993 Plan) At its April 6, 1993 meeting, the Executive Committee voted to recommend to the Board of Directors that the Company's retirement benefit for outside directors be amended as follows: Vesting: The benefit will vest upon the earlier of (1) the completion of ten years of service on the Board; (2) service on the Board until retirement at the annual meeting of stockholders following a director's seventieth birthday; or (3) death while serving on the Board. Annual Amount: The annual amount of the benefit will be equal to the cash component of the annual Board retainer plus two annual Committee member retainers, as those retainers are in effect at the time of a director's retirement or death (currently $10,000 + $2,750 + $2,750 or $15,500). The annual amount will be paid in quarterly installments. Duration of Benefit: A director while living will receive the annual amount for a period of years equal to his or her service on the Board. Survivor Benefit: Should a director die prior to full receipt of the benefit, his or her survivors will continue to receive the benefit for a period of time equal to the lesser of (1) the full years-of-service term to which the director would have been entitled if living or (2) a period of ten years from the commencement of payment of the benefit. Survivors may elect to receive the benefit in the form of a lump sum. The lump sum will be equal to the present value of the remaining benefit, calculated with reference to the Pension Benefit Guarantee Corporation rate as in effect at the time of the director's death. Commencement of Benefit: Payment of the benefit to a qualified director will commence at the quarterly payment date following the director's departure from the Board and attainment of age 65. Should a qualified director die prior to the commencement of the benefit, payment of the benefit to his or her survivors as described above will commence at the next quarterly payment date following the director's death. Applicability: The amended director retirement benefit as proposed herein will take effect for all retirements from the Board occurring in 1993 and thereafter. 68 2 Service of Less than a Year: Service of less than a year will be calculated with reference to the applicable fraction for determining both vesting and benefit duration. Thus, for example, if a director has service equal to six years and nine months when he retires at age 70, he will receive the annual amount for 6 3/4 years. 69 EX-23.1 4 CONSENT OF INDEPENDENT ACCOUNTANTS 1 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 and 33- 57840) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424, 33-48425, 33-59662 and 33-59682) of our report dated January 25, 1994 on our audits of the consolidated financial statements and financial statement schedules of Boston Edison Company as of December 31, 1993 and 1992 and for each of the three years in the period ended December 31, 1993, which report is included in this Annual Report on Form 10-K. Boston, Massachusetts COOPERS & LYBRAND March 30, 1994 70 -----END PRIVACY-ENHANCED MESSAGE-----