-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S46D+e5b8ZBwMRrNRinjQVV4eKNG0olaUDfGWGS2ki4pmVjNCEGZwMcbiihHcdL4 RIg0OmIsWdtvV4+0yqFJLQ== 0000013372-97-000005.txt : 19970329 0000013372-97-000005.hdr.sgml : 19970329 ACCESSION NUMBER: 0000013372-97-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: BSE SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BOSTON EDISON CO CENTRAL INDEX KEY: 0000013372 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041278810 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02301 FILM NUMBER: 97566494 BUSINESS ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: ROOM P 344 CITY: BOSTON STATE: MA ZIP: 02199 BUSINESS PHONE: 6174242000 MAIL ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: ROOM P 344 CITY: BOSTON STATE: MA ZIP: 02199 10-K 1 BOSTON EDISON COMPANY 1996 FORM 10-K UNITED STATES 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 For the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 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 whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting stock held by non-affiliates of the registrant as of March 21, 1997 computed as the average of the high and low market price of the common stock as reported in the listing of composite transactions for New York Stock Exchange listed securities in the Wall Street Journal: $1,261,389,298. 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 March 21, 1997 -------------------------- ----------------------------- Common Stock, $1 par value 48,514,973 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document - ---- -------- III Portions of definitive proxy statement dated March 26, 1997 for Annual Meeting of Stockholders to be held May 15, 1997.
1 Boston Edison Company - -------------------------------------------------------------------------- Form 10-K Annual Report - -------------------------------------------------------------------------- December 31, 1996 - --------------------------------------------------------------------------
Part I Page - -------------------------------------------------------------------------- Item 1. Business 2 Item 2. Properties and Power Supply 7 Item 3. Legal Proceedings 9 Item 4. Submission of Matters to a Vote of Security Holders 9 Part II - -------------------------------------------------------------------------- Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 13 Item 6. Selected Financial Data 14 Item 7. Management's Discussion and Analysis 15 Item 8. Financial Statements and Supplementary Financial Information 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 51 Part III - -------------------------------------------------------------------------- Item 10. Directors and Executive Officers of the Registrant 52 Item 11. Executive Compensation 52 Item 12. Security Ownership of Certain Beneficial Owners and Management 53 Item 13. Certain Relationships and Related Transactions 53 Part IV - -------------------------------------------------------------------------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 54
2 Part I ------ Item 1. Business - ----------------- (a) General Development of Business - ----------------------------------- Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law. The Company operates in the energy and energy services business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. Refer to the Positioning in the Industry section of Item 7 for information regarding the restructuring of the electric utility industry process currently underway and its potential impacts on the Company. The Company also conducts unregulated activities through its wholly owned subsidiary, Boston Energy Technology Group (BETG). Through BETG and its subsidiaries, the Company is engaged in certain nonutility businesses, including energy utilization and conservation, construction management and district energy. Refer to Note A to the Consolidated Financial Statements in Item 8 for more information regarding the Company's nonutility business ventures. In January 1997, the Company announced a plan to form a holding company structure. The holding company structure, which is subject to shareholder and regulatory approvals, is further described in Note A to the Consolidated Financial Statements in Item 8. (b) Financial Information about Industry Segments - ------------------------------------------------- The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable. (c) Narrative Description of Business - ------------------------------------- Principal Products and Services The Company supplies electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 1996 the Company served an average of 657,487 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues by class for the last three years consisted of the following:
1996 1995 1994 - --------------------------------------------------------------------------- Retail electric revenues: Commercial 50% 50% 50% Residential 27% 28% 28% Industrial 9% 9% 9% Other 2% 2% 2% Wholesale and contract revenues 12% 11% 11% ===========================================================================
3 Sources and Availability of Fuel The Company owns two stations whose generating units have the ability to burn oil, natural gas or both, one nuclear power station and ten combustion turbine generators. The Company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:
Percentage of Company Average Cost of Fuel Generation by Source (%) ($ per Million BTU) -------------------------------- -------------------------------- 1996 1995 1994 1993 1992 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------ Oil 16.1 17.5 27.8 31.3 33.7 3.04 2.66 2.35 2.38 2.40 Gas 33.3 39.9 31.6 24.3 25.7 3.11 2.20 2.28 2.67 2.55 Nuclear 50.6 42.6 40.6 44.4 40.6 0.41 0.43 0.50 0.51 0.52 ==============================================================================
The majority of the Company's residual oil purchases consists of imported oil acquired primarily from international suppliers. The Company has contracts with major oil companies that can supply most of its estimated requirements, assuming no major disruptions in oil producing regions. Within contract provisions, the Company has the ability to purchase significant amounts of oil in the spot market when it is economical to do so. A portion of the Company's natural gas is supplied on an interruptible basis by contract. These contracts permit interruptions in deliveries by the supplier when natural gas supplies or pipeline capacity is unavailable. The Company is currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances, as part of a 1991 consent order with the Massachusetts Department of Environmental Protection. The Company has arrangements for a firm supply of natural gas to run the station at a minimum level and has a least-cost plan for operating beyond this minimum level which principally utilizes interruptible gas supplies or short- term capacity purchases. In order to obtain fuel for use at its nuclear generating unit, the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 2002, 2000, 2004 and 2012, respectively. Franchises Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for the Company's electric transmission and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the action of these authorities is subject to appeal to the Massachusetts Department of Public Utilities (MDPU). The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature. 4 Seasonal Nature of Business The Company's kWh sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. In addition, the Company currently bills higher base rates to commercial and industrial customers during the billing months of June through September as mandated by the MDPU. Accordingly, greater than half of the Company's annual earnings typically occurs in the third quarter. As part of the Company's settlement agreement which is discussed in the Positioning in the Industry section of Item 7, it is expected that the seasonal variances of the Company's rates will be discontinued. Refer also to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8. Competitive Conditions The Company is operating in an increasingly competitive environment. Changes in the industry include ongoing competition in wholesale power markets and increased pressure for retail customer choice. These forces are due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels designed to foster competition and changes in customers expectations. Refer to the Positioning in the Industry and Outlook for the Future sections of Item 7 for information regarding electric utility industry restructuring and the Company's response to the competitive environment. Environmental Matters The Company is subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. Environmental-related capital expenditures for the years 1996 and 1995 were $2.7 million and $2.9 million, respectively. These expenditures are forecasted to be approximately $2 million in each of the years 1997 and 1998. The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur. Refer to the Environmental section of Item 7 for more information. Number of Employees As of March 22, 1997, the Company had 3,323 full-time and 44 part-time utility employees including 2,260 represented by two locals of the Utility Workers Union of America, AFL-CIO. The locals' labor contracts are effective through May of the year 2000. Subsidiary operations had 54 full-time employees. Employee relations are considered satisfactory by the Company. 5 (d) Financial Information about Foreign and Domestic Operations and Export - -------------------------------------------------------------------------- Sales - ----- Refer to Principal Products and Services of this item for information regarding the geographical area served by the Company and revenues by class for the last three years. (e) Additional Information - -------------------------- Regulation The Company and its wholly owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the MDPU, whose jurisdiction includes supervision over retail rates for electricity and financing and investing activities. 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 that power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation. The Company is required to submit annual performance standards to the MDPU applicable to its generating units and other units from which the Company purchases power through long-term contracts. Under this generating unit performance program, the Company provides quarterly progress reports to the MDPU. The MDPU has the right to reduce subsequent fuel and purchased power billings if it finds that the Company has been unreasonable or imprudent in the operation of its generating units or in the procurement of fuel. The Company believes that its current provision for refunds is sufficient to cover potential refunds. The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which 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 nuclear plants in the United States, including Pilgrim Station. NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties. In January 1997, the Company submitted a request for NRC review regarding the calculation of Pilgrim's emergency core cooling system net postive suction head. NRC practice will not allow the plant to restart until this review is performed. The Company anticipates that the review will be completed prior to the completion of Pilgrim's current refueling and maintenance outage. The unit is currently expected to return to service in late April. In addition, the Company could undertake certain actions regarding Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations, a voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants. Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests for various kinds of federal, state and local legislative or regulatory action, direct voter initiatives or referenda or litigation. The Company cannot predict the extent, cost or timing of any modifications to 6 Pilgrim Station which could be necessary in the future as a result of additional regulatory or other requirements, nor can it determine the effect of such future requirements on the continued operation of Pilgrim Station. The Company continuously evaluates 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. Capital Expenditures and Financings The Company's most recent estimates of capital and nuclear fuel expenditures, allowance for funds used during construction (AFUDC), long-term debt maturities and sinking fund requirements for the years 1997 through 2001 are as follows:
(in thousands) 1997 1998 1999 2000 2001 - ------------------------------------------------------------------------------ Capital expenditures (1) $140,000 $150,000 $160,000 $160,000 $140,000 Nuclear fuel expenditures 0 $ 29,500 $ 14,000 $ 33,000 $ 16,000 AFUDC (2) $ 2,000 $ 2,000 $ 2,000 $ 2,000 $ 2,000 Long-term debt $101,600 $101,600 $ 1,600 $166,600 $ 1,600 Preferred stock sinking fund $ 2,000 $ 2,000 $ 2,000 $ 2,000 $ 52,000 ============================================================================== (1) Includes unregulated business ventures. (2) Excludes AFUDC on nuclear fuel.
The Company continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates shown above are subject to revision due to changes in regulatory requirements and the effects of the industry restructuring process, environmental standards, availability and cost of capital, interest rates and other assumptions. Utility plant expenditures in 1996 were $151 million and consisted primarily of additions to the Company's transmission and distribution systems and nuclear generation facility. Refer to the Liquidity section of Item 7 for more information regarding the Company's capital resources. 7 Item 2. Properties and Power Supply - ------------------------------------ The Company's total electric generation capacity from Company-owned facilities consisted of the following:
Year Unit Location Capacity(a) Type Installed - ----------------------------------------------------------------------------- Pilgrim Nuclear Plymouth, Mass. 670 Nuclear 1972 Power Station New Boston Station South Boston, Mass. 730 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, Mass. Units 4-5-6 388 Fossil 1957-1961 Unit 7 592 Fossil 1975 Combustion turbine 14 Fossil 1969 generator Combustion turbine Various 278 Fossil 1966-1971 generators (nine) ============================================================================= (a) In megawatts (MW) based on winter capability audit results.
The Company also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil- fired unit located in Yarmouth, Maine, began operations in 1978 and is operated by Central Maine Power Company. Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and nonutilities and its participation in the New England Power Pool as further described in this item. The Company's significant items of property consist of electric generating stations, substations and service centers, and are generally located on Company-owned land. The Company's high-tension transmission lines are generally located on land either owned or subject to easements in its favor. The Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by municipal and other state authorities. As of December 31, 1996, the Company's transmission system consisted of 362 miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 156 miles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 45 transmission or combined transmission and distribution substations with transformer capacity of 10,281 megavolt amperes (MVA), 63 4 kV distribution substations with transformer capacity of 1,205 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 242 customers' substations. The overhead and underground distribution systems cover approximately 4,700 and 900 miles of streets, respectively. HEEC, the Company's regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115 kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts. HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water Resources Authority, at this location. 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 8 policies. The Company currently has one proceeding before the EFSB, which concerns proposed transmission and station facilities in Hopkinton and Milford, Massachusetts. Purchased Power Contracts Information regarding long-term contracts for the purchase of electricity is included in Note M to the Consolidated Financial Statements in Item 8. Under the Company's two long-term purchased power contracts with the Massachusetts Bay Transportation Authority (MBTA), the MBTA retains the right to utilize the combustion turbines for its own emergency use and for testing purposes while the Company retains New England Power Pool credit for their capacity and output. Sales Contracts The Company has agreements with Commonwealth Electric Company and Montaup Electric Company under which each purchase 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and operating costs plus an annual return on investment. 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 and other electricity suppliers in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To obtain maximum benefits of power pooling, the electric facilities of all member companies are operated by NEPOOL as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest cost generation and transmission equipment available at any given time. This operation is the responsibility of NEPOOL's central dispatch center, the New England Power Exchange (NEPEX). As a result of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of the other members. The dispatching of Company-owned generating facilities by NEPEX may be affected by minimally increasing energy requirements and any additions to New England generation capacity. In December 1996, NEPOOL filed with the FERC to restructure the power pool to comply with recent FERC orders requiring open access to transmission and changes to the membership and governance provisions of the power pooling agreement. The filing also proposed changes which would transfer operating responsibility of the integrated transmission and generation system in New England to an Independent System Operator and establish a bid-based market for unbundled energy services in lieu of the current cost-based pricing mechanism. The FERC has allowed the transmission and governance changes to become effective March 1, 1997, subject to refund and further orders. NEPOOL proposed that the changes in operations responsibility and market-based pricing would become effective in the second half of 1997. These changes were proposed in anticipation of the restructuring of the electric utility industry and the entrance of new providers in the energy market. The Company's net capacity was 3,613 MW at its winter peak and 3,385 MW at its summer peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,399 MW and 3,256 MW, respectively. 9 Item 3. Legal Proceedings - -------------------------- The Company was named as a party in lawsuits filed in both the US District Court and the Massachusetts Norfolk Superior Court by Subaru of New England, Inc. and Subaru Distributors Corporation in 1992. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from the Company's New Boston generating station. In February 1997, the Company settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a material impact on the Company's financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending. In 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts (US District Court) alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning employees affected by the Company's 1988 workforce reduction. In December 1996, the Company reached a settlement of this lawsuit under which there is no finding or admission of discriminatory employment practices. The Company anticipates full recovery from its insurance carrier for this settlement. Also refer to Note L.6. 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 1996. 10 Executive Officers of the Registrant - ------------------------------------ The names, ages, positions and business experience during the past five years of all the executive officers of Boston Edison Company and its subsidiaries as of March 1, 1997 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 position as officer is held. Officers of the Company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until their respective successors are chosen and qualified.
Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Thomas J. May, 49 Chairman of the Board, President Chairman of the Board, President and Chief Executive Officer (since and Chief Executive Officer 1995), Chairman of the Board and Chief Executive Officer (1994- 1995), President and Chief Operating Officer (1993-1994) and Executive Vice President (1990- 1993); Director (since 1991) Chairman of the Board and Chief Executive Officer and Director, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp. and Boston Edison Services, Inc.; Chairman of the Board and Director, Rez-Tek International Corp. and Coneco Corp.; Director, BecoCom, Inc. and Northwind Boston, LLC Alison Alden, 48 Senior Vice President - Sales, Senior Vice President - Sales, Services Services and Human Resources and Human Resources (since 1996), Vice President - Sales & Service (1993-1996) and Director - Organizational Development (1990-1993) Director, Harbor Electric Energy Company, Boston Energy Technology Group and Coneco Corp. E. Thomas Boulette, 54 Senior Vice President - Nuclear Senior Vice President - Nuclear (since 1993), Vice President - Nuclear Operations and Station Director (1992-1993) and Vice President - Operations (1989- 1992) of Maine Yankee Atomic Power Company
11
Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- L. Carl Gustin, 53 Senior Vice President - Corporate Senior Vice President - Corporate Relations (since 1995), Senior Relations Vice President - Marketing & Corporate Relations (1989-1995) John J. Higgins, Jr., 64 Senior Vice President (since 1990) Senior Vice President Douglas S. Horan, 47 Senior Vice President and General Senior Vice President and Counsel (since 1995), Vice General Counsel President and General Counsel (1994-1995) and Deputy General Counsel (1991-1994) Director and General Counsel, Harbor Electric Energy Company; Director, Boston Energy Technology Group and BecoCom, Inc. James J. Judge, 41 Senior Vice President and Senior Vice President and Treasurer (since 1995), Assistant Treasurer Treasurer (1989-1995) and Director - Corporate Planning (1993-1995) Senior Vice President, Treasurer and Director, Harbor Electric Energy Company and Boston Energy Technology Group; Director, TravElectric Services Corp., Boston Edison Services, Inc., BecoCom, Inc., Northwind Boston, LLC and EnergyVision, LLC Ronald A. Ledgett, 58 Senior Vice President - Fossil, Senior Vice President - Fossil, Field Service and Electric Field Service and Electric Delivery (since 1996), Senior Vice Delivery President - Power Delivery (1991- 1995) Robert J. Weafer, Jr., 50 Vice President - Finance, Vice President - Finance, Controller and Chief Accounting Controller and Chief Officer (since 1991) Accounting Officer
12
Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Theodora S. Convisser, 49 Clerk of the Corporation (since Clerk of the Corporation 1986) and Assistant General Counsel (since 1984) Clerk, Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Boston Edison Services, Inc., Rez-Tek International Corp., Coneco Corp., BecoCom, Inc. and Northwind Boston, LLC
13 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 is the high and low market value per share of the Company's common stock as reported in the Wall Street Journal for each of the quarters in 1996 and 1995:
1996 1995 - ------------------------------------------------------------------------------ High Low High Low - ------------------------------------------------------------------------------ First quarter $30 1/8 $26 1/4 $25 1/2 $23 1/8 Second quarter $27 1/8 $23 5/8 $27 $23 3/8 Third quarter $25 3/8 $21 3/4 $27 1/2 $24 1/2 Fourth quarter $27 $21 3/4 $29 1/2 $26 3/4 ==============================================================================
(b) Holders - ----------- As of March 21, 1997, the Company had 35,630 holders of record of its common stock. (c) Dividends - ------------- Following are the dividends declared per share of common stock for each of the quarters in 1996 and 1995:
1996 1995 - ----------------------------------------------------------- First quarter $0.470 $0.455 Second quarter $0.470 $0.455 Third quarter $0.470 $0.455 Fourth quarter $0.470 $0.470 ===========================================================
(d) Other Information - --------------------- Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements for the year ended December 31, 1996: Ratio of earnings to fixed charges 2.91 Ratio of earnings to fixed charges and preferred stock dividend requirements 2.41
14 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).
1996 1995 1994 1993 1992 - --------------------------------------------------------------------------- Operating revenues $1,666,303 $1,628,503 $1,544,735 $1,482,159 $1,411,753 Net income $ 141,546 $ 112,310 $ 125,022 $ 118,218 $ 107,298 Earnings per share of common stock $ 2.61 $ 2.08(a) $ 2.41 $ 2.28 $ 2.10 Total assets $3,729,291 $3,637,170 $3,608,699 $3,468,724 $3,286,335 Long-term debt $1,058,644 $1,160,223 $1,136,617 $1,272,497 $1,091,073 Redeemable preferred stock $ 203,419 $ 206,514 $ 208,514 $ 210,514 $ 210,514 Cash dividends declared per common share $ 1.880 $ 1.835 $ 1.775 $ 1.715 $ 1.655 =========================================================================== (a) Includes $0.44 per share restructuring charge. Excluding the restructuring charge, 1995 earnings per share were $2.52. Certain reclassifications were made to the data reported in prior years to conform with the current method of presentation.
15 Item 7. Management's Discussion and Analysis - --------------------------------------------- Positioning in the Industry Background Electric utilities have traditionally operated under a monopolistic regulatory framework. Under this framework customers have been restricted to a single electricity provider, typically a vertically integrated electric utility engaged in the generation, transmission and distribution of electricity. However, since the 1970's, the electric energy business has become increasingly competitive. With the enactment of the Public Utility Regulatory Policies Act of 1978, a new independent power producer industry commenced, competing with traditional electric utilities for opportunities to generate electric power. In recent years many state utility commissions, including the Massachusetts Department of Public Utilities (MDPU), have initiated inquiries into restructuring the electric utility industry with a goal of promoting competition and extending to all customers the option of choosing their own electricity suppliers. In 1996, Massachusetts electric utilities and other interested parties participated in the industry restructuring proceeding before the MDPU. This process culminated in the latter part of the year with a series of settlement agreements and the issuance by the MDPU of its formal electric industry restructuring plan. Electric utility industry restructuring In December 1996, we reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Division of Energy Resources that resolves certain necessary issues surrounding electric industry restructuring. This agreement must be filed with and approved by the MDPU. If approved, the settlement agreement allows retail electric customers the ability to choose their electricity supplier (referred to as retail access). Retail access would occur at the later of January 1, 1998 or the date when retail access is made available to all customers of Massachusetts investor-owned utilities (the Retail Access Date). The settlement agreement provides us with the ability to fully recover our stranded costs incurred under the traditional electric ratemaking structure. Under the settlement agreement, all retail customers will have the opportunity to select their electricity provider starting on the Retail Access Date. Retail customers will continue to receive electric delivery service under regulated rates. Customers who choose not to participate in the competitive market will have the option of continuing to buy power from our electric delivery business at "Standard Offer" prices for seven years. The "Standard Offer" will provide customers with electric service at rates designed to give a 10% savings in electric prices. Our electric delivery business will purchase power for "Standard Offer" service from suppliers through a competitive bidding process. Commencing with the Retail Access Date, the retail delivery rates of our distribution business will include a non-bypassable access charge designed to recover all of our stranded costs which are currently estimated to be approximately $3 billion. These costs include the above-market commitments under existing purchased power contracts, our net generation plant investment, nuclear decommissioning commitments and regulatory assets related to our generation business. 16 As part of the settlement we have agreed to divest our fossil generating plants no later than six months after the Retail Access Date. We expect to continue operation of Pilgrim Nuclear Power Station with a new revenue mechanism for recovery of Pilgrim's future costs and have agreed to estimate the market value of the station by December 31, 2002. Regulatory assets related to our generation business and our net generation plant investment will be recovered with a return over a twelve-year period. As an incentive to mitigate stranded costs, our return on equity will be increased for mitigation prior to the Retail Access Date and as the transition access charge declines thereafter. The aggregate amount of the access charge will be reduced by the net proceeds from the fossil divestiture and the market valuation of Pilgrim Station. Nuclear decommissioning commitments and above-market commitments under existing purchased power contracts will be collected over the lives of the underlying obligations which are expected to exceed twelve years. Certain severance, employee training and community- related transitional payments are also recoverable through the access charge. Our electric delivery business will remain fully subject to rate regulation. As part of the agreement, while there will be some rate design changes, our base rate revenue level (non-fuel) will be frozen until the Retail Access Date when customer choice begins. Effective with the commencement of retail choice and pursuant to the settlement agreement, our electric delivery business will annually file with the MDPU a computation supporting our return on average common equity associated with distribution system operations. The return on equity would be subject to a floor of 6% and a ceiling of 11.75%. If the return on equity is below 6%, we would be authorized to add a surcharge to customer rates in order to reach the 6% floor. If the return on equity is above 11%, we would be required to adjust customer rates by an amount necessary to reduce the calculated return on equity between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment would be made if the return on equity falls between 6% and 11%. The settlement also provides for the continued protection of the environment through stringent emissions standards, a continued commitment to energy conservation and renewable resource programs and protections for low-income customers. In October 1996, another major electric utility in Massachusetts, along with the Massachusetts Attorney General, the Massachusetts Division of Energy Resources and other parties filed a settlement agreement with the MDPU. Their settlement agreement provides for retail choice, full compensation for potential stranded costs and the divestiture of its fossil and hydroelectric generating business. In addition, customers that do not choose an alternative supplier would receive "Standard Offer" service that would provide a 10% savings in electric prices upon the Retail Access Date. On February 26, 1997, the MDPU issued an order accepting this utility's settlement agreement. We anticipate that the MDPU will issue a decision on our settlement agreement in the second or third quarter of 1997. Implementation of the settlement will also be subject to enactment of enabling legislation by the Massachusetts legislature and rulings by the Federal Energy Regulatory Commission (FERC). In the first quarter of 1997, both the Massachusetts Governor and a Joint Committee of the Massachusetts legislature filed separate bills on restructuring the electric utility industry. The major principles of these bills are substantially consistent with those of the MDPU restructuring plan, including the opportunity for stranded cost recovery and reduced electricity 17 prices. The bills clarify the MDPU's authority to create the opportunity for retail customer choice by January 1, 1998. In December 1996, the MDPU issued its formal electric industry restructuring plan. The stated goal of the plan is to reduce costs, over time, for all consumers of electricity. Under the MDPU's proposal, the current monopoly regulatory framework will evolve into a competitive market system featuring consumer choice among providers of generation services. The transmission and distribution of electricity will remain monopolies subject to rate regulation. Joint ventures We currently conduct unregulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG). In December 1996, BETG signed a joint venture agreement with Residential Communications Network, Inc., currently known as RCN Telecom Services, Inc. (RCN), to form a limited liability company to provide local and long-distance telephone service, video, high-speed Internet access and other telecommunications-related services (the "Telecommunications Venture"). The unregulated entity will be owned up to 49% by BETG, with RCN having the day-to-day management responsibility. The projected costs of creating the "Telecommunications Venture", which is planned to serve 1.6 million customers in the greater Boston area, is approximately $300 million over several years. The joint venture agreement is subject to a number of conditions which must be satisfied before formal operations begin, including the obtaining of certain regulatory approvals. In January 1997, BETG, through one of its wholly owned subsidiaries, signed definitive agreements with Williams Energy Services Company (WESCO), a subsidiary of The Williams Companies, Inc., to form EnergyVision, LLC, an unregulated limited liability company. This "Energy Marketing Venture" will market electricity, natural gas and energy-related services to retail customers in the six New England states. EnergyVision began operations in February 1997. BETG, through its subsidiary, and WESCO each own 50% of the new company, with an expected combined initial investment of less than $10 million. Holding Company In January 1997, we announced a plan to form a holding company structure. The holding company structure, which is subject to shareholder and regulatory approvals, is intended to provide increased financial, managerial and organizational flexibility in order to better position us to operate in the changing electric utility industry. It will permit us to take advantage of nonutility business opportunities in a more timely manner. In addition, the holding company structure will clearly separate our regulated and unregulated lines of business enabling us to pursue nonutility business ventures in a manner consistent with the electric utility industry restructuring principles outlined by the MDPU. The holding company structure is a well-established form of organization for companies conducting multiple lines of business, particularly entities engaging in both regulated and unregulated activities. All investor-owned Massachusetts electric utilities, other than Boston Edison, are currently organized in a holding company structure. 1992 Rate Settlement As referred to in the following Results of Operations, the MDPU had previously approved our three-year settlement agreement effective November 1992. This agreement provided us with retail rate increases, allowed for the recovery of demand side management conservation program costs, specified certain 18 accounting adjustments and clarified the timing and recognition of certain expenses. The agreement also set a limit of 11.75% on our rate of return on common equity for each of the calendar years 1993, 1994 and 1995, excluding any penalties or rewards from performance incentives. The retail rate increases consisted of two annual retail base rate increases of $29 million effective November 1993 and November 1994 and an annual performance adjustment charge effective November 1992 through October 2000. The performance adjustment charge varies annually based on the performance of Pilgrim Nuclear Power Station. This charge is further described in the Electric Sales and Revenues section. We did not make a base rate filing upon the expiration of the 1992 settlement agreement, therefore base rates have remained in effect at their 1995 levels. Results of Operations 1996 versus 1995 Earnings per share of common stock were $2.61 in 1996 compared to $2.08 in 1995. Earnings in 1995 reflected a nonrecurring before tax charge of $34 million ($20.7 million net of tax, or $0.44 per share) associated with our corporate restructuring. The restructuring is discussed further in Note F to the Consolidated Financial Statements. Excluding the nonrecurring restructuring charge, earnings per common share increased 3.6% over 1995 primarily due to lower operations and maintenance and interest expenses and higher Pilgrim performance revenues. These positive changes were partially offset by an increase in depreciation expense. Operating revenues Operating revenues increased 2.3% over 1995 as follows:
(in thousands) - ------------------------------------------------------ Retail electric revenues $48,649 Demand side management revenues (20,545) Wholesale revenues (2,072) Short-term sales and other revenues 11,768 - ------------------------------------------------------ Increase in operating revenues $37,800 ======================================================
Retail electric revenues increased $48.6 million. Fuel and purchased power revenues increased approximately $36 million. These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect on earnings. Performance revenues, which vary annually based on the operating performance of Pilgrim Station, increased $14.5 million as Pilgrim Station operated at a higher capacity in 1996. Pilgrim's annual performance adjustment charge is discussed further in the Electric Sales and Revenues section. Retail kWh sales increased 2.8% in 1996, primarily due to the positive economic impacts on our commercial customers. Demand side management (DSM) revenues decreased primarily due to a decline in current DSM program expenditures. The primary reason for the decrease in wholesale revenues is due to a decrease in Pilgrim contract customer revenues. These revenues decreased despite increased kWh sales due to lower operations and maintenance expense related to Pilgrim Station. Pilgrim contract customers are billed for their proportionate share of the unit's costs. Net short-term sales and other revenues increased $11.8 million. Despite lower kWh sales, short-term sales revenues increased approximately $6 million 19 due to higher fuel prices. Revenues from short-term sales result in a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, have no net effect on earnings. This increase also reflects an increase in revenue from non-electric sources in 1996. Operating expenses Fuel and purchased power expenses increased $53 million. Fuel expense increased, despite a slight decrease in company generation, due to significantly higher oil and natural gas prices. Purchased power expense reflects a higher volume of energy purchases and an overall increase in energy prices. These increases were partially offset by the timing effect of fuel and purchased power cost collection. Fuel and purchased power expenses are substantially recoverable through fuel and purchased power revenues. Operations and maintenance expense decreased $41 million primarily due to lower labor costs resulting from our 1995 restructuring and the continuing cost control efforts of each of our business units. In addition, the amortization of deferred nuclear outage costs decreased $9 million. As discussed in Note B to the Consolidated Financial Statements, in the third quarter of 1995 we made a retroactive change to the amortization period of these deferred costs from five years to two years, consistent with the two-year cycle between refueling outages at Pilgrim Station. The 1995 operating expenses reflect a $34 million nonrecurring charge related to our corporate restructuring. Refer to the Results of Operations for 1995 versus 1994 and Note F to the Consolidated Financial Statements for additional information regarding our 1995 restructuring. Depreciation and amortization increased $32 million. The increase is primarily the result of a change in the estimated remaining economic lives of our Mystic 4, 5 and 6 fossil generating units in the second quarter of 1996, retroactive to the beginning of the year, and an increase in the depreciable plant balance. The change in estimated economic lives of Mystic 4, 5 and 6 resulted in a $22 million increase in depreciation expense for the year. Refer to Note B to the Consolidated Financial Statements for more information on depreciation expense. The decrease in DSM programs expense reflects the decline in current DSM program expenditures. The increase in income taxes is due to higher net income and a higher effective tax rate in 1996. Our effective tax rate in 1996 is 38.2% versus 37.1% in 1995. Interest charges Interest on long-term debt decreased due to the maturity of $100 million 8 7/8% debentures in December 1995 and $100 million 5 1/8% debentures in March 1996. These decreases were partially offset by the issuance of $125 million 7.80% debentures in May 1995 which were outstanding for all of 1996. Other interest charges increased due to an increase in interest on short-term debt caused by the higher average short-term debt level partially offset by a lower average short-term borrowing rate. The short-term debt balance increased as a result of the debenture maturities and the redemption of $4 million of preferred stock in 1996. Allowance for borrowed funds used during construction (AFUDC), which represents the financing costs of construction, decreased due to lower overall construction activity during 1996, shorter construction periods, and lower short-term interest rates 20 1995 versus 1994 Earnings per share of common stock were $2.08 in 1995 compared to $2.41 in 1994. Earnings in 1995 reflect the nonrecurring before tax charge of $34 million ($20.7 million net of tax, or $0.44 per share) associated with our corporate restructuring. The charge reflects the costs of early retirement and severance programs implemented as part of our organizational streamlining and reorganization into business units. Excluding the restructuring charge, earnings per common share were $2.52 in 1995, an increase of 4.6% over 1994. This increase is due to the $29 million annual retail base rate increase effective November 1994, the ending of amortization of deferred cancelled nuclear costs in 1994, a 1.2% increase in retail kWh sales and lower revenue reserve provisions. These positive impacts were partially offset by higher income and property taxes, nuclear outage amortization and employee benefit expenses in 1995 over 1994 levels, and a gain recorded in 1994 related to a favorable court ruling on an eminent domain case. Operating revenues Operating revenues increased 5.4% over 1994 as follows:
(in thousands) - ------------------------------------------------------ Retail electric revenues $69,851 Demand side management revenues 8,783 Wholesale revenues (1,799) Short-term sales and other revenues 6,933 - ------------------------------------------------------ Increase in operating revenues $83,768 ======================================================
Retail electric revenues increased $69.9 million. Approximately $28 million of the increase was due to the November 1994 base rate increase while approximately $11 million was due to the increase in retail kWh sales. Fuel and purchased power revenues increased $11 million as a result of the timing effect of fuel and purchased power cost recovery. These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect on earnings. Pilgrim performance revenues increased $9 million primarily due to a higher performance rate effective in 1995 and a 17% increase in generation. A new annual conservation charge for recovery of demand side management program costs was implemented in February 1995. Under this charge all 1995 program costs were recovered in 1995. This resulted in higher DSM revenues and expenses than in prior years when certain program costs were deferred and recovered over a six-year period. Short-term sales increased as a result of higher generating availability in 1995. Revenues from short-term sales result in a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, have no net effect on earnings. Operating expenses Fuel and purchased power expenses increased $22 million primarily due to the timing effect of fuel and purchased power cost collection. Excluding the timing effect, fuel expense increased due to an 8% increase in fossil generation while purchased power expense was substantially unchanged. Fuel and purchased power expenses are substantially recoverable through fuel and purchased power revenues. 21 Operations and maintenance expense increased 3.3% over 1994. This was primarily due to an $11 million increase in the amortization of deferred nuclear outage costs. In the third quarter of 1995 we made a retroactive change to the amortization period of deferred nuclear outage costs from five years to two years as discussed in Note B to the Consolidated Financial Statements. In addition, employee benefit expenses increased primarily due to higher postretirement benefit expenses recorded in accordance with the 1992 settlement agreement. We also incurred higher administrative costs in positioning the company for changes in the industry, which were offset by lower operating costs in the electric delivery business. Electric generation costs increased only 1% in 1995, primarily due to a refueling and maintenance outage at Pilgrim Station. The $34 million nonrecurring restructuring charge was incurred over the third and fourth quarters of 1995 as a result of our corporate reorganization announced in July 1995. As part of the reorganization, 330 employees elected to retire under enhanced retirement programs and 149 employees whose positions were eliminated became eligible for benefits under a special severance program. Refer to Note F to the Consolidated Financial Statements for additional information. Depreciation and amortization expense increased due to a higher average depreciable plant balance. In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. The increase in demand side management programs expense is related to the increase in DSM revenues. Beginning with the annual conservation charge implemented in February 1995, DSM costs are recovered and expensed primarily in the year incurred. The 1995 expense includes $31 million of 1995 program costs and $14 million of amortization of costs capitalized in 1992 through 1994. Property and other taxes increased primarily due to higher Boston property taxes resulting from capital additions. Our effective annual income tax rate for 1995 was 37.1% vs. 31.4% for 1994. The higher rate is the result of a $10 million adjustment to deferred income tax expense made in 1994 in accordance with the 1992 settlement agreement. Other income The net decrease in other income is primarily due to a $5.7 million gain recognized in 1994 from a court ruling on a 1989 eminent domain taking of certain of our property. Interest charges Interest on long-term debt increased due to a $125 million debenture issuance in May 1995, partially offset by interest savings from first mortgage bond and debenture redemptions in 1994. Other interest charges increased slightly due to higher short-term interest rates partially offset by a lower average short- term debt level. AFUDC decreased due to a lower construction work-in-progress balance and shorter construction periods, partially offset by higher short- term interest rates. 22 Electric Sales and Revenues Electric sales Retail kWh sales increased 2.8% in 1996. The major contributor to this increase was the positive effect on commercial customers of a continued strong economy in our retail service territory. The strong economy's impact in greater Boston is illustrated by the highest commercial office occupancy rate in 15 years. In addition, hotel occupancy rates and non-manufacturing employment increased over 1995. The commercial sector represents approximately 50% of our electric operating revenues. Residential sales, which represent approximately 27% of electric operating revenues, decreased slightly primarily due to overall milder than normal weather conditions. Industrial sales remained relatively flat. This sector represents approximately 9% of electric operating revenues. Total kWh sales, including wholesale, increased 3.3%. The increase in wholesale sales was primarily due to higher sales to our Pilgrim contract customers as the plant was operating for substantially all of 1996. In addition, sales to our municipal customers increased due to a reduction in available energy supply in New England. A 1.2% increase in retail kWh sales in 1995 was primarily due to a stronger economy, partially offset by the impact of demand side management programs. Total kWh sales increased 3.8% primarily due to an increase in Pilgrim contract customer sales. Electric revenues Our retail electric rates are subject to the jurisdiction of the MDPU. As discussed in the Positioning in the Industry section, we reached a settlement agreement in December 1996 that, if approved, resolves certain necessary issues surrounding electric industry restructuring. As part of the settlement agreement our electric delivery business will provide "Standard Offer" customers service at rates designed to give a 10% savings in electric prices. Under the agreement, our base rates will remain frozen until the Retail Access Date (the later of January 1, 1998 or the date when retail access is made available to all customers of Massachusetts investor-owned utilities). We do not expect that maintaining base rates at their current level until the Retail Access Date will have a material adverse effect on our financial condition or results of operations. After the Retail Access Date, the return on equity on our electric delivery business will be subject to an 11.75% ceiling which is lower than has been experienced in the recent past. The annual performance adjustment charge from our 1992 settlement agreement with the MDPU remains in effect through the year 2000 and provides us with opportunities to improve our financial results. The most significant potential impact of this performance incentive is based on Pilgrim Station's annual capacity factor. An annual capacity factor between 60% and 68% would provide us with approximately $54.5 million of revenues in the performance year ended October 1997. For each percentage point increase in capacity factor above 68%, annual revenues will increase by approximately $800,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease by approximately $900,000. We are currently billing customers based on an 85% capacity factor. This is a decrease from the capacity factor of 90.9% achieved in the performance year ended October 1996 due to the scheduled routine refueling outage that began in February 1997. We earned $67.6 million in revenues related to Pilgrim's capacity factor in the performance year ended October 31, 1996. 23 Pilgrim Station was shut down for approximately three months in 1994 due to a non-nuclear problem with its electrical generator. Regularly scheduled maintenance work was also performed during the shutdown. The power needs usually met by the station were met by other generating plants or purchased from other suppliers as necessary. We do not believe that the generator damage resulted from actions within our control. Our recovery of the incremental purchased power costs during the outage through fuel and purchased power revenues, however, remains subject to review by the MDPU under a generating unit performance program. Liquidity We ordinarily meet most of our cash requirements for plant expenditures with internally generated funds. These funds are cash flows from operating activities, adjusted for changes in working capital and the payment of dividends. During 1996, 1995 and 1994 our internal generation of cash provided 170%, 102% and 109%, respectively of our plant expenditures. The capital spending level, excluding nuclear fuel, forecasted for 1997 is $144 million which includes amounts for utility plant and our new business ventures. The capital spending level over the next five years is forecasted to be approximately $750 million. In addition to capital expenditures, we have long-term debt and preferred stock payment requirements of $103.6 million per year in 1997 and 1998, $3.6 million in 1999, $168.6 million in 2000 and $53.6 million in 2001. External financings continue to be necessary to supplement our internally generated funds, primarily through the issuance of short-term commercial paper and bank borrowings. We have authority from the FERC to issue up to $350 million of short-term debt. We also 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, 1996, we had approximately $201 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1994 the MDPU approved our financing plan to issue up to $500 million of equity and long-term securities through 1996. In 1996 the MDPU approved our request to extend this financing plan through 1998. Authority to issue approximately $322 million remains under this plan. Proceeds from issuances under this plan are to be used to refinance short and long-term securities and to fund capital expenditures and working capital requirements. Refer to Notes H and I to the Consolidated Financial Statements for additional information relating to our financing activities. We intend to issue $100 million of two- year debt in March 1997. Outlook for the Future Competitive forces within the electric utility industry continued to increase in 1996. Changes in the industry include ongoing competition in wholesale power markets and increased pressure for retail customer choice. These forces are due to a variety of factors, including legislative and regulatory proceedings at both federal and state levels designed to foster competition and changes in customer expectations. The trend continues toward increased competition through modified regulation of the industry. In Massachusetts, open access to generation markets for retail customers is approaching rapidly. The effects of competition have been evident in the wholesale energy market. In response to the competition from other electric utilities and nonutility generators to sell electricity for resale, we secured long-term power supply agreements with our seven wholesale customers that set rates through 2002 and beyond. This segment represents 3% of our operating revenues. 24 In January 1997, we filed an open access tariff with the FERC that incorporates our transmission rates into a New England regional transmission tariff. This filing, which is subject to approval, was made in response to the FERC's open access transmission order that was issued in April 1996. The order requires all utilities with transmission systems to file open access tariffs, to provide service under those tariffs to transmission customers comparable to service provided to their electric energy customers and to take service under the tariffs for wholesale purchases and sales. The order also supports the full recovery of legitimate and verifiable costs previously incurred under federal and state regulation. The provisions in the order provide a framework for significant changes in the electric utility industry. We do not expect the FERC order to significantly impact the results of our operations, which are primarily regulated by the MDPU. Additional competition exists with alternative fuel suppliers as customers are able to substitute natural gas, steam or oil for electricity for heating or cooling purposes. In addition, industrial and large commercial customers may pursue options to generate their own electric power or factor the cost of electricity into their decisions to relocate to new service territories. In addition to our involvement in the MDPU's restructuring proceeding, we have actively responded to the changing electric utility industry in other ways. In 1995 we reorganized the company into separate business units in order to strengthen our competitiveness. The Customer, Fossil Generation, Nuclear Generation and Corporate Services business units were designed to sharpen management focus along our significant lines of operation while maintaining company-wide strategic goals. The restructuring reduced our workforce which resulted in a significant increase in labor efficiencies and cost savings. We also continued to develop customer alliances and provided economic development rates to some customers. These actions all illustrate our commitment to be a competitively priced, reliable provider of energy. In the traditional revenue requirements model, our electric revenues have been based on the cost of providing electric service. As such, we are subject to certain accounting standards that are not applicable to other businesses and industries in general. We believe that we currently meet the criteria of these standards. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71) requires us to defer recognition of certain costs when incurred when we expect to receive future rate recovery of these costs. The Securities and Exchange Commission has recently begun to focus on how the changes in the electric utility industry have affected utilities' ability to continue to apply regulatory accounting. The final rules issued by the MDPU or the enactment of legislation in Massachusetts could, in the near term, cause us to no longer meet the criteria for application of SFAS 71 for some of our operations. Should this occur, we would be required to take an immediate noncash charge to income for all of our affected regulatory assets and the above-market portion of purchased power contracts. In addition, a write-down of utility plant assets would be required under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, if competitive or regulatory change results in a probability that future cash flows will not be sufficient to recover our investment in those assets. Based on our settlement agreement we expect to recover all strandable costs through a non-bypassable access charge to be paid by customers of our electric delivery business. Under our settlement agreement, our delivery business will remain subject to rate-regulation and, therefore, will continue to meet the criteria of these accounting standards. As noted earlier, under our settlement agreement we expect to continue to operate Pilgrim Station with the ability to collect stranded costs related to 25 the unit. Although not anticipated based on our settlement agreement, the nonrecovery of strandable costs could have a material impact on our results of operations and financial condition. However, if laws are enacted or regulatory decisions are made that do not offer Massachusetts electric utilities an opportunity to recover previously reviewed, prudently incurred commitments to provide service to our customers, we believe we have strong legal arguments to challenge such laws or decisions. We will actively pursue the full recovery of stranded costs and are prepared to take the action necessary to protect the interests of our shareholders. Other Matters Connecticut Yankee On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power Company (CYAPC), which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the Haddam Neck, Connecticut unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of its operating license, compared to the costs of closing the unit and incurring replacement power costs for the same period. We have a 9.5% equity investment in CYAPC of approximately $10 million. Refer to Note L.4. to the Consolidated Financial Statements for more information regarding Connecticut Yankee. Environmental We are subject to numerous federal, state and local standards with respect to waste disposal, air and water quality and other environmental considerations. These standards can require that we modify our existing facilities or incur increased operating costs. We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. Refer to Note L.6. to the Consolidated Financial Statements for more information regarding hazardous waste issues. In October 1996, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 96-1, Environmental Remediation Liabilities, effective in 1997. This statement contains authoritative guidance on specific accounting issues that are present in the recognition, measurement, display and disclosure of environmental remediation liabilities. We do not believe that this statement will have a material effect on our financial position or results of operations. Uncertainties continue to exist with respect to the disposal of both spent nuclear fuel and low-level radioactive waste (LLW) resulting from the operation of Pilgrim Station. The United States Department of Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel; however, there are uncertainties regarding the DOE's schedule of acceptance of spent fuel for disposal. In 1995 we regained access to the LLW disposal facility located in Barnwell, South Carolina. Refer to Note E to the Consolidated Financial Statements for further discussion regarding spent nuclear fuel and LLW disposal. The 1990 Clean Air Act Amendments require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel-fired generating 26 units. Sulfur dioxide emissions will be restricted through a market-based system of allowances. In 1996 we sold sulfur dioxide allowances related to the years 2000 to 2010 that are expected to be in excess of our needs. Proceeds from the sale of these allowances were recorded as a regulatory liability as it is probable that we will be required to refund the proceeds to customers. We have the option to repurchase certain of these allowances at specified prices from 2000 to 2010. We currently do not anticipate exercising these options; however, their potential exercise will be based on numerous factors, including the timing of the Retail Access Date. As discussed in the Positioning in the Industry section, under our settlement agreement we have agreed to the divestiture of our fossil generating plants no later than six months after the Retail Access Date (the later of January 1, 1998 or the date when retail access is made available to all customers of Massachusetts investor-owned utilities). If regulatory approval is not obtained or is delayed, it is possible that we could continue to operate these units. Other provisions of the 1990 Clean Air Act Amendments involve limitations on emissions of nitrogen oxides from existing generating units. Combustion system modifications made to New Boston and Mystic Stations, including the installation of low nitrogen oxides burners at New Boston, have allowed the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain Massachusetts Department of Environmental Protection air quality modeling studies currently in progress, the continued operation of these units could require additional emission reductions by 1999 or years thereafter. The extent of any additional emission restrictions and the cost of any further modifications is uncertain at this time. Public concern continues regarding electromagnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Such concerns have included the possibility of adverse health effects caused by EMF as well as perceived effects on property values. Some scientific reviews conducted to date have suggested associations between EMF and potential health effects, while other studies have not substantiated such associations. The National Research Council recently reported that there is no conclusive evidence that exposure to EMF from power lines and appliances presents a health hazard. The panel of scientists, working with the National Academy of Sciences, report that more than 500 studies over the last several years have produced no proof that EMF causes leukemia or other cancers or harms human health in other ways. We continue to support research into the subject and are participating in the funding of industry-sponsored studies. We are aware that public concern regarding EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities in proceedings before regulators or in requests for legislation or regulatory standards concerning EMF levels. We have addressed issues relative to EMF in various legal and regulatory proceedings and in discussions with customers and other concerned persons; however, to date we have not been significantly affected by these developments. We continue to closely monitor all aspects of the EMF issue. Litigation We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from our New Boston Station generating unit. In February 1997, we settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a material impact on our financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending. 27 Refer to Note L.7. to the Consolidated Financial Statements for more information on these lawsuits and other legal matters in which we are involved. Safe harbor cautionary statement We occasionally make forward-looking statements such as forecasts and projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements. Actual results could potentially differ materially from these statements. Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved. The preceding sections include certain forward-looking statements about the effects of the industry restructuring process and our related settlement agreement, our joint ventures, operating results, Pilgrim Station's performance, Connecticut Yankee and environmental and legal issues. The effects of the industry restructuring process currently underway at the MDPU and our related settlement agreement could differ from our expectations. This could occur as regulatory decisions and negotiated settlements between utilities and intervenors are finalized. In addition, the development of a competitive electric generation market, the impacts of actual electric supply and demand in New England and legislative action may affect the ultimate results of the industry restructuring and our settlement agreement. The timing and activities of our joint ventures as well as our actual investments may differ from our expectations. This could occur if required regulatory approvals are delayed or not obtained. The impacts of our continued cost control procedures on our operating results could differ from our expectations. The effects of changes in economic conditions, tax rates, interest rates, technology and the prices and availability of operating supplies could materially affect our projected operating results. Pilgrim Station's performance could differ from our expectations. The station's capacity factor could be impacted by changes in regulations or by unplanned outages resulting from certain operating conditions. The ultimate liability related to the shutdown of Connecticut Yankee could differ from the current estimate. In addition, although not anticipated, it is possible that some portion of our share of post-operation costs may not be recoverable from ultimate customers. The impacts of various environmental and legal issues could differ from our expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect our estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect our estimated litigation costs. 28 Item 8. Financial Statements and Supplementary Financial Information - --------------------------------------------------------------------- Consolidated Statements of Income
years ended December 31, (in thousands, except earnings per share) 1996 1995 1994 - --------------------------------------------------------------------------- Operating revenues $1,666,303 $1,628,503 $1,544,735 - --------------------------------------------------------------------------- Operating expenses: Fuel and purchased power 588,893 535,806 513,825 Operations and maintenance 417,372 458,196 443,545 Restructuring costs 0 34,000 0 Depreciation and amortization 185,494 153,339 148,845 Amortization of deferred costs of cancelled nuclear unit 0 0 19,791 Demand side management programs 30,825 45,125 35,438 Taxes-property and other 107,086 106,361 100,015 Income taxes 88,703 68,276 54,798 - --------------------------------------------------------------------------- Total operating expenses 1,418,373 1,401,103 1,316,257 - --------------------------------------------------------------------------- Operating income 247,930 227,400 228,478 Other income (expense), net 698 (575) 3,979 - --------------------------------------------------------------------------- Operating and other income 248,628 226,825 232,457 - --------------------------------------------------------------------------- Interest charges: Long-term debt 94,823 106,640 102,570 Other 14,551 12,642 12,343 Allowance for borrowed funds used during construction (2,292) (4,767) (7,478) - --------------------------------------------------------------------------- Total interest charges 107,082 114,515 107,435 - --------------------------------------------------------------------------- Net income 141,546 112,310 125,022 Preferred stock dividends 15,365 15,571 15,765 - --------------------------------------------------------------------------- Earnings available for common shareholders $ 126,181 $ 96,739 $ 109,257 =========================================================================== Weighted average common shares outstanding 48,265 46,592 45,338 Earnings per share of common stock $ 2.61 $ 2.08 $ 2.41 ===========================================================================
Consolidated Statements of Retained Earnings
years ended December 31, (in thousands) 1996 1995 1994 - --------------------------------------------------------------------------- Balance at the beginning of the year $ 257,344 $ 247,004 $ 218,292 Net income 141,546 112,310 125,022 - --------------------------------------------------------------------------- Subtotal 398,890 359,314 343,314 - --------------------------------------------------------------------------- Cash dividends declared: Preferred stock 15,365 15,571 15,765 Common stock 90,834 86,399 80,545 - --------------------------------------------------------------------------- Subtotal 106,199 101,970 96,310 - --------------------------------------------------------------------------- Provision for preferred stock redemption and issuance costs (a) 905 0 0 - --------------------------------------------------------------------------- Balance at the end of the year $ 291,786 $ 257,344 $ 247,004 =========================================================================== (a) Refer to Note B.7. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial statements 29 Consolidated Balance Sheets
December 31, (in thousands) 1996 1995 - ------------------------------------------------------------------------------ Assets Utility plant in service, at original cost $4,393,585 $4,315,422 Less: accumulated depreciation 1,550,317 $2,843,268 1,439,996 $2,875,426 - ------------------------------------------------------------------------------ Nuclear fuel 351,453 302,594 Less: accumulated amortization 268,509 82,944 251,951 50,643 - ------------------------------------------------------------------------------ Construction work in progress 30,376 29,573 - ------------------------------------------------------------------------------ Net utility plant 2,956,588 2,955,642 Investments in electric companies, at equity 23,054 23,620 Nuclear decommissioning trust 132,076 102,894 Current assets: Cash and cash equivalents 5,651 5,841 Accounts receivable 233,024 219,114 Accrued unbilled revenues 34,922 37,113 Fuel, materials and supplies, at average cost 57,075 59,631 Other 45,146 375,818 23,607 345,306 - ------------------------------------------------------------------------------ Deferred debits: Regulatory assets-power contracts 88,963 21,396 Other regulatory assets 113,063 128,699 Other 39,729 59,613 - ------------------------------------------------------------------------------ Total assets $3,729,291 $3,637,170 ============================================================================== Capitalization and Liabilities Common stock equity $1,036,424 $ 989,438 Cumulative preferred stock: Nonmandatory redeemable series 119,954 119,677 Mandatory redeemable series 81,465 84,837 Long-term debt 1,058,644 1,160,223 Current liabilities: Long-term debt/preferred stock due within one year $ 102,667 $ 102,667 Notes payable 201,454 126,441 Accounts payable 134,083 133,474 Accrued interest 24,378 25,113 Dividends payable 25,343 25,351 Other 115,812 603,737 138,044 551,090 - ------------------------------------------------------------------------------ Deferred credits: Power contracts 88,963 21,396 Accumulated deferred income taxes 498,718 497,282 Accumulated deferred investment tax credits 58,899 62,970 Nuclear decommissioning liability 133,388 113,288 Other 49,099 36,969 Commitments and contingencies - ------------------------------------------------------------------------------ Total capitalization and liabilities $3,729,291 $3,637,170 ==============================================================================
The accompanying notes are an integral part of the consolidated financial statements 30 Consolidated Statements of Cash Flows
years ended December 31, (in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Operating activities: Net income $141,546 $112,310 $125,022 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 228,259 202,294 203,222 Deferred income taxes and investment tax credits (4,057) (25,193) (8,276) Allowance for borrowed funds used during construction (2,292) (4,767) (7,478) Net changes in: Accounts receivable and accrued unbilled revenues (11,719) (34,626) (20,701) Fuel, materials and supplies (2,171) 7,202 3,093 Accounts payable 609 2,978 23,196 Other current assets and liabilities (44,514) 26,485 35,217 Other, net 50,921 23,975 14,847 - ----------------------------------------------------------------------------- Net cash provided by operating activities 356,582 310,658 368,142 - ----------------------------------------------------------------------------- Investing activities: Plant expenditures (excluding AFUDC) (151,045) (180,822) (198,771) Nuclear fuel expenditures (52,967) (13,621) (21,934) Demand side management expenditures 0 0 (37,007) Sale of plant assets, net (106) 3,018 15,972 Nuclear decommissioning trust investments (29,182) (20,063) (16,771) Electric company investments 566 1,058 (386) - ----------------------------------------------------------------------------- Net cash used in investing activities (232,734) (210,430) (258,897) - ----------------------------------------------------------------------------- Financing activities: Issuances: Common stock 12,559 64,888 10,634 Long-term debt 0 125,000 15,000 Redemptions: Preferred stock (4,000) (2,000) (2,000) Long-term debt (101,600) (100,600) (50,000) Net change in notes payable 75,013 (88,345) 10,635 Dividends paid (106,010) (100,152) (95,460) - ----------------------------------------------------------------------------- Net cash used in financing activities (124,038) (101,209) (111,191) - ----------------------------------------------------------------------------- Net decrease in cash and cash equivalents (190) (981) (1,946) Cash and cash equivalents at the beginning of the year 5,841 6,822 8,768 - ----------------------------------------------------------------------------- Cash and cash equivalents at the end of the year $ 5,651 $ 5,841 $ 6,822 ============================================================================= Supplemental disclosures of cash flow information: Cash paid during the year for: Interest, net of amounts capitalized $100,810 $104,011 $ 99,287 Income taxes $ 98,668 $ 96,180 $ 46,074
The accompanying notes are an integral part of the consolidated financial statements. 31 Notes to Consolidated Financial Statements Note A. Nature of Operations We are an investor-owned regulated public utility operating in the energy and energy services business. This includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. A portion of our generation is produced by our wholly owned nuclear generating unit, Pilgrim Nuclear Power Station. We supply electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric departments. Electric operating revenues were 88% retail and 12% wholesale in 1996. We also conduct unregulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG). Through BETG and its subsidiaries, we are engaged in certain nonutility businesses, including energy utilization and conservation, construction management and district energy. In December 1996, BETG signed a joint venture agreement with Residential Communications Network, Inc., currently known as RCN Telecom Services, Inc. (RCN), to form a limited liability company to provide local and long-distance telephone service, video, high-speed Internet access and other telecommunications-related services (the "Telecommunications Venture"). The unregulated entity will be owned up to 49% by BETG, with RCN having the day-to-day management responsibility. The joint venture agreement is subject to a number of conditions which must be satisfied before formal operations begin, including the obtaining of certain regulatory approvals. In January 1997, BETG, through one of its wholly owned subsidiaries, signed definitive agreements with Williams Energy Services Company (WESCO), a subsidiary of The Williams Companies, Inc., to form EnergyVision, LLC, an unregulated limited liability company. This "Energy Marketing Venture" will market electricity, natural gas and energy-related services to retail customers in the six New England states. BETG, through its subsidiary, and WESCO each own 50% of the new company which began operations in February 1997. In January 1997, we announced a plan to form a holding company structure. The holding company structure, which is subject to shareholder and regulatory approvals, is intended to provide increased financial, managerial and organizational flexibility in order to better position us to operate in the changing electric utility industry. It will permit us to take advantage of nonutility business opportunities in a more timely manner. In addition, the holding company structure will clearly separate our regulated and unregulated lines of business enabling us to pursue nonutility business ventures in a manner consistent with the electric utility industry restructuring principles outlined by the Massachusetts Department of Public Utilities (MDPU). The holding company structure is a well-established form of organization for companies conducting multiple lines of business, particularly entities engaging in both regulated and unregulated activities. All investor-owned Massachusetts electric utilities, other than Boston Edison, are currently organized in a holding company structure. Refer also to Note C to these Consolidated Financial Statements for potential changes in the nature of our operations as a result of the electric utility industry restructuring. 32 Note B. Significant Accounting Policies 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year data to conform with the current presentation. We follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the MDPU. We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The consolidated financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company we are subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. 2. Revenues We record estimates of revenues for electricity used by our customers but not yet billed at the end of each accounting period. 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate. The difference between actual costs and the amounts billed to customers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated balance sheet until subsequent rates are adjusted. The MDPU has the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel. 4. Utility Plant Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation. 5. Depreciation and Nuclear Fuel Amortization Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. Excluding the adjustment discussed below, the overall composite depreciation rates were 3.26%, 3.28% and 3.31% in 1996, 1995 and 1994, respectively. 33 Upon the completion of a review of our electric generating units, we determined that our oldest and least efficient fossil units (Mystic 4, 5 and 6) are unlikely to provide competitively priced power beyond the year 2000. Therefore, during the second quarter of 1996, we revised the estimated remaining economic lives of these units to five years retroactive to the beginning of the year. The effect of this change in estimate is an annual increase to depreciation expense of $22 million. The cost of decommissioning Pilgrim Station is excluded from our depreciation rates. Refer to Note E to these Consolidated Financial Statements for a discussion of nuclear decommissioning. 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 spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates. 6. Deferred Nuclear Outage Costs We defer the incremental costs associated with nuclear refueling outages when incurred and amortize them over future periods. In 1995 we changed the amortization period from five years to two years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station. 7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemption and issuance of long-term debt and preferred stock. The costs related to long-term debt are recognized as an addition to interest expense over the life of the debt or replacement debt. Beginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock redemptions and issuances as a direct reduction to retained earnings over the average life of the replacement preferred stock series. 8. Allowance for Borrowed Funds Used During Construction (AFUDC) AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1996, 1995 and 1994 were 5.87%, 6.35% and 4.45%, respectively, and represented only the cost of short-term debt. 9. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased. Outstanding checks are included in cash and accounts payable until they are presented for payment. 10. Allowance for Doubtful Accounts Our accounts receivable are substantially 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. 34 11. Regulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with agreements with our regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. No return on investment is being earned on the regulatory assets. Regulatory assets consisted of the following:
December 31, 1996 1995 - -------------------------------------------------------------------- Power contracts $ 88,963 $ 21,396 Redemption premiums 31,052 36,832 Income taxes, net 47,483 46,121 Postretirement benefits costs 15,009 15,009 Decontamination and decommissioning 13,190 13,968 Nuclear outage costs 3,432 13,471 Other 2,897 3,298 - -------------------------------------------------------------------- $202,026 $150,095 ====================================================================
12. Earnings Per Share of Common Stock Earnings per share of common stock is calculated by dividing net income, after the payment of preferred stock dividends, by the weighted average common shares outstanding during the year. Note C. Electric Utility Industry In December 1996, we reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Division of Energy Resources that, if approved by the MDPU, allows all retail electric customers in our service area to choose their electricity supplier (referred to as retail access) beginning as early as January 1, 1998. As part of the settlement, we have agreed to divest our fossil generating plants no later than six months after the commencement of retail access. Accordingly, other than Pilgrim Nuclear Power Station, we will no longer own any electricity generating facilities. The rates of our retained electric delivery business will continue to be regulated by the MDPU and will include a non-bypassable access charge for the collection of our stranded costs. These costs include the above-market commitments under existing purchased power contracts, our net generation plant investment, nuclear decommissioning commitments and regulatory assets related to our generation business. Implementation of the settlement will be subject to enactment of enabling legislation by the Massachusetts legislature and rulings by the FERC. In the traditional revenue requirements model, our electric revenues have been based on the cost of providing electric service. As such, we are subject to certain accounting standards that are not applicable to other businesses and industries in general. We believe that we currently meet the criteria of these standards. SFAS 71 requires us to defer recognition of certain costs when incurred when we expect to receive future rate recovery of these costs. The Securities and Exchange Commission has recently begun to focus on how the changes in the electric utility industry have affected utilities' ability to continue to apply regulatory accounting. The final rules issued by the MDPU or the enactment of legislation in Massachusetts could, in the near term, cause us to no longer meet the criteria for application of SFAS 71 for some of our operations. Should this occur, we would be required to take an immediate 35 noncash charge to income for all of our affected regulatory assets and the above-market portion of purchased power contracts. In addition, a write-down of utility plant assets would be required under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, if competitive or regulatory change results in a probability that future cash flows will not be sufficient to recover our investment in those assets. Based on our settlement agreement we expect to recover all strandable costs through a non-bypassable access charge to be paid by our delivery business customers. Under our settlement agreement, our delivery business will remain subject to rate regulation and, therefore, will continue to meet the criteria of these accounting standards. As noted earlier, under our settlement agreement we expect to continue to operate Pilgrim Station with the ability to collect stranded costs related to the unit. Although not anticipated based on our settlement agreement, the nonrecovery of strandable costs could have a material impact on our results of operations and financial condition. However, if laws are enacted or regulatory decisions are made that do not offer Massachusetts electric utilities an opportunity to recover previously reviewed, prudently incurred commitments to provide service to our customers, we believe we have strong legal arguments to challenge such laws or decisions. We will actively pursue the full recovery of stranded costs and are prepared to take the action necessary to protect the interests of our shareholders. Our 1992 settlement agreement provided us with two annual retail base rate increases of $29 million effective in November 1993 and November 1994 and an eight-year annual performance adjustment charge. We did not make a base rate filing upon the expiration of the settlement agreement in 1995, therefore base rates have remained in effect at their 1995 levels. Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory assets of $47.5 million and $46.1 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1996, and December 31, 1995, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 1996 1995 - ------------------------------------------------------------------------------ Deferred tax liabilities: Plant-related $532,390 $521,280 Other 95,642 95,148 - ------------------------------------------------------------------------------ 628,032 616,428 - ------------------------------------------------------------------------------ Deferred tax assets: Plant-related 8,406 12,590 Investment tax credits 38,005 40,632 Other 82,903 65,924 - ------------------------------------------------------------------------------ 129,314 119,146 - ------------------------------------------------------------------------------ Net accumulated deferred income taxes $498,718 $497,282 ==============================================================================
36 No valuation allowances for deferred tax assets are deemed necessary. Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits. Components of income tax expense were as follows:
years ended December 31, (in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Current income tax expense $92,760 $93,469 $63,358 Deferred income tax expense 14 (21,115) (4,468) Investment tax credits (4,071) (4,078) (4,092) - ----------------------------------------------------------------------------- Income taxes charged to operations 88,703 68,276 54,798 - ----------------------------------------------------------------------------- Taxes on other income: Current (721) (1,729) 2,550 Deferred 0 0 284 - ----------------------------------------------------------------------------- (721) (1,729) 2,834 - ----------------------------------------------------------------------------- Total income tax expense $87,982 $66,547 $57,632 =============================================================================
The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
1996 1995 1994 - ----------------------------------------------------------------------------- Statutory tax rate 35.0% 35.0% 35.0% State income tax, net of federal income tax benefit 4.3 4.3 4.3 Investment tax credits (1.8) (2.3) (2.3) Reversal of deferred taxes - settlement agreement - - (5.5) Other 0.7 0.1 (0.1) - ----------------------------------------------------------------------------- Effective tax rate 38.2% 37.1% 31.4% =============================================================================
Note E. Nuclear Decommissioning and Nuclear Waste Disposal 1. Nuclear Decommissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We record an estimate of decommissioning costs in depreciation expense on the consolidated statements of income over Pilgrim's expected service life. Decommissioning expense was $12 million, $14 million and $15 million in 1996, 1995 and 1994, respectively. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the "green field" method, which provides for the plant site to be completely restored to its original state. The cost estimate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a contracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted to use for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning trust balance, thus reducing the amount to be collected from customers. The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact of long-term spent fuel storage options resulting from delays in the United States Department of Energy (DOE) spent fuel removal program. Refer to part 2 below for a discussion of spent fuel removal. The partial update indicates an estimated decommissioning cost of $400 million in 1991 dollars based upon a revised 37 spent fuel removal schedule and utilization of dry spent fuel storage technology. No further update is currently available; however, we will continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate. We anticipate that we will be permitted to recover our actual ultimate decommissioning costs from our retail and contract customers. In February 1996, the Financial Accounting Standards Board (FASB) issued proposed new rules for accounting for liabilities related to closure and removal of long-lived assets, which include decommissioning of nuclear generating facilities. If these proposed rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to utility plant. The plant addition would be depreciated over Pilgrim's remaining expected service life. The liability would be measured based on the present value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result in the recognition of a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for decommissioning. In addition, trust fund earnings would be reported on the income statement. Depending on the results of the FASB's redeliberation of certain issues regarding these proposed rules, it plans to issue either a final statement or revised proposed rules in the second quarter of 1997. 2. Spent Nuclear Fuel The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the Nuclear Regulatory Commission to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the MDPU. We are actively exploring the feasibility of other spent fuel storage facilities and technologies, including proposed participation in a limited liability company (LLC) which would undertake construction of a private spent fuel storage facility in the state of Utah or other locations. Our participation in this LLC requires approval by the MDPU and is currently the subject of a petition seeking such approval. In July 1996, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. The decision was in response to petitions filed by us and other interested parties in 1994 seeking declaratory rulings concerning this obligation. In December 1996, the DOE notified us and other nuclear plant owners that it would be unable to begin acceptance of spent nuclear fuel for disposal in 1998. Along with other interested parties, we again filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking declaratory rulings concerning enforcement and remedies for DOE's failure to accept spent fuel for disposal in a timely manner. Under the Nuclear Waste Policy Act of 1982 it is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. The DOE has been conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political opposition and the DOE has publicly stated that it will be unable to begin acceptance of spent nuclear fuel for disposal by the date specified in the Nuclear Waste Policy Act. We cannot predict at this time whether or on what 38 schedule the DOE will eventually construct a spent fuel repository or what the effect will be of any delays in such construction. 3. Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us. Legislation has been enacted in Massachusetts establishing a regulatory process for managing the state's LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agreement with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management procedure, we will continue to monitor the situation and investigate other available options. Note F. Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement programs and implemented a special severance program to reduce employee staffing levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 million net of tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 million for the severance program. The enhanced retirement programs were offered to all employees at least 55 years old, with different years of service requirements for management and union employees. The programs provided for supplemental salary payments and waivers of the early retirement pension reduction and the medical and life insurance benefits years of service requirement. The special severance program, which applied to management and support personnel, was provided for all employees whose positions were eliminated in the reorganization. Severance benefits provided included salary payments, medical insurance and outplacement services. As of December 31, 1996, there was no material obligation remaining for these programs. Note G. Pensions and Other Postretirement Benefits 1. Pensions We have a defined benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market funds, insurance contracts and real estate funds. We also have a supplemental retirement plan for certain management employees. Benefits under this plan are based on final compensation upon retirement. The plan is not funded. The plan's cost and benefit obligation amounts are included in the following pension information for 1995 and 1996. Amounts related to the plan prior to 1995 were not material to our total pension costs. 39 Net pension cost consisted of the following components:
years ended December 31, (in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Current service cost - benefits earned $13,452 $11,339 $15,057 Interest cost on projected benefit obligation 32,325 31,789 33,961 Actual net (return)/loss on plan assets (40,335) (72,192) 214 Net amortization and deferral 17,064 49,557 (32,169) - ----------------------------------------------------------------------------- Net pension cost $22,506 $20,493 $17,063 =============================================================================
In accordance with our 1992 settlement agreement we deferred the difference between the net pension cost of the retirement plan and its annual funding amount through 1995. Net pension costs recognized in 1995 and 1994 were $28.2 million and $25.0 million, respectively. We used the following assumptions for calculating pension cost:
1996 1995 1994 - ----------------------------------------------------------------------------- Discount rate 7.25% 8.25% 7.00% Expected long-term rate of return on assets 10.00% 10.00% 10.00% Compensation increase rate 3.90% 3.90% 4.50% - -----------------------------------------------------------------------------
The plans' funded status were as follows:
December 31, (in thousands) 1996 1995 - ----------------------------------------------------------------------------- Supplemental Supplemental Retirement Retirement Retirement Retirement Plan Plan Plan Plan - ----------------------------------------------------------------------------- Actuarial present value of accumulated benefit obligation: Vested $316,101 $ 7,576 $377,272 $ 8,748 Non-vested 10,867 943 13,902 1,409 - ----------------------------------------------------------------------------- Total (a) $326,968 $ 8,519 $391,174 $ 10,157 ============================================================================= Plan assets at fair value $331,299 $ 0 $358,572 $ 0 Projected obligation for service rendered to date (400,561) (9,199) (476,666) (11,036) - ----------------------------------------------------------------------------- Projected benefit obligation in excess of plan assets (69,262) (9,199) (118,094) (11,036) Unrecognized prior service cost 11,238 9,436 12,283 10,223 Unrecognized net loss/(gain) 78,853 (1,141) 82,935 252 Unrecognized net obligation 7,130 0 8,064 0 Additional minimum liability (b) 0 (7,615) (17,790) (9,596) - ----------------------------------------------------------------------------- Net pension prepayment/ (liability) $ 27,959 $ (8,519) $(32,602) $(10,157) ============================================================================= (a) The accumulated benefit obligation at December 31, 1995, includes $13.5 million related to the enhanced retirement programs offered in 1995 as discussed in Note F to these Consolidated Financial Statements. (b) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SFAS 87), requires the recognition of an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SFAS 87 we 40 recorded additional minimum liabilities and corresponding intangible assets of $7.6 million and $27.4 million on our consolidated balance sheets at December 31, 1996 and 1995, respectively.
We used the following assumptions for calculating the plans' year-end funded status:
1996 1995 - ----------------------------------------------------------------------------- Discount rate 7.75% 7.25% Compensation increase rate 3.90% 3.90% - -----------------------------------------------------------------------------
We also provide defined contribution 401(k) plans for substantially all our employees. We match a percentage of employees' voluntary contributions to the plans. We made matching contributions of $8 million in 1996, $9 million in 1995 and $8 million in 1994. 2. Other Postretirement Benefits In addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). Our 1992 settlement agreement provided us with a phase-in to full expense of the PBOP costs incurred under SFAS 106. The 1992 settlement agreement allowed us to defer any costs in excess of the specified phase-in amounts to the extent that we funded an external trust. Our funding policy is to generally contribute 100% of PBOP costs to external trusts. Therefore, we recorded $23 million and $17 million of PBOP costs in 1995 and 1994, respectively in accordance with the 1992 settlement agreement. In 1996 we recorded the full PBOP costs incurred under SFAS 106 of $26 million. The net deferred PBOP costs of $15 million resulting from the delayed phase-in are included in regulatory assets as these costs are expected to be recovered from customers in future periods. Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Current service cost - benefits earned $ 4,616 $ 3,408 $ 4,978 Interest cost on accumulated benefit obligation 16,815 13,521 13,632 Actual return on plan assets (9,584) (7,151) (187) Amortization of transition obligation 9,151 9,151 9,151 Net amortization and deferral 5,209 3,017 (2,581) - ----------------------------------------------------------------------------- Net postretirement benefits cost $26,207 $21,946 $24,993 =============================================================================
We used the following assumptions for calculating postretirement benefits cost:
1996 1995 1994 - ----------------------------------------------------------------------------- Discount rate 7.25% 8.25% 7.00% Expected long-term rate of return on assets 9.00% 9.00% 9.00% Health care cost trend rate 7.00% 7.00% 9.00% - -----------------------------------------------------------------------------
The health care cost trend rate is assumed to decrease by one percent in 1997 and 1998 and to remain at 5% in years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. A one percent increase in the assumed health care cost trend rate would increase the total 41 service and interest cost components by 7.6% and would increase the accumulated benefit obligation at December 31, 1996, by 6.7%. The PBOP program's funded status was as follows:
December 31, (in thousands) 1996 1995 - ----------------------------------------------------------------------------- Trust assets at fair value $ 72,702 $ 51,064 Accumulated obligation for service rendered to date from: Retirees $(156,694) $(110,877) Active employees eligible to retire (12,644) (31,980) Active employees not eligible to retire (61,567) (230,905) (53,514) (196,371) - ----------------------------------------------------------------------------- Accumulated benefit obligation in excess of trust assets (158,203) (145,307) Unrecognized prior service cost (16,274) (17,889) Unrecognized net loss 26,663 5,612 Unrecognized transition obligation 146,413 155,564 - ----------------------------------------------------------------------------- Net postretirement benefits liability $ (1,401) $ (2,020) =============================================================================
The weighted average discount rates used to measure the accumulated benefit obligation were 7.75% in 1996 and 7.25% in 1995. The trust assets consist of equities, bonds and money market funds. 42 Note H. Capital Stock
December 31, (dollars in thousands, except per share amounts) 1996 1995 - ----------------------------------------------------------------------------- Common stock equity: Common stock, par value $1 per share, 100,000,000 shares authorized; 48,509,537 and 48,003,178 shares issued and outstanding: $ 48,510 $ 48,003 Premium on common stock 695,723 683,686 Retained earnings 291,786 257,344 Surplus invested in plant 405 405 - ----------------------------------------------------------------------------- Total common stock equity $1,036,424 $989,438 =============================================================================
Dividends declared per share of common stock were $1.88, $1.835 and $1.775 in 1996, 1995 and 1994, respectively. Cumulative preferred stock: Par value $100 per share, 2,890,000 shares authorized; issued and outstanding: Nonmandatory redeemable series:
Current Shares Redemption Series Outstanding Price/Share - ----------------------------------------------------------------------------- 4.25% 180,000 $103.625 $ 18,000 $ 18,000 4.78% 250,000 $102.800 25,000 25,000 7.75% 400,000 - 40,000 40,000 8.25% 400,000 - 40,000 40,000 - ----------------------------------------------------------------------------- 123,000 123,000 Less: redemption and issuance costs (3,046) (3,323) - ----------------------------------------------------------------------------- Total nonmandatory redeemable series $ 119,954 $119,677 =============================================================================
Mandatory redeemable series:
Current Shares Redemption Series Outstanding Price/Share - ----------------------------------------------------------------------------- 7.27% 400,000 $102.910 $ 40,000 $ 44,000 8.00% 500,000 - 50,000 50,000 - ----------------------------------------------------------------------------- 90,000 94,000 Less: redemption and issuance costs (6,535) (7,163) due within one year (2,000) (2,000) - ----------------------------------------------------------------------------- Total mandatory redeemable series $ 81,465 $ 84,837 =============================================================================
1. Common Stock Common stock issuances in 1994 through 1996 were as follows:
Number Total Premium on (in thousands) of Shares Par Value Common Stock - ----------------------------------------------------------------------------- Balance at December 31, 1993 45,129 $45,129 $612,653 Dividend reinvestment plan 406 406 10,150 - ----------------------------------------------------------------------------- Balance at December 31, 1994 45,535 45,535 622,803 Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 - ----------------------------------------------------------------------------- Balance at December 31, 1995 48,003 48,003 683,686 Dividend reinvestment plan 507 507 12,037 - ----------------------------------------------------------------------------- Balance at December 31, 1996 48,510 $48,510 $695,723 =============================================================================
43 2. Cumulative Mandatory Redeemable Preferred Stock The 400,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $102.910. The redemption price declines annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each May to redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends. In 1996, 1995 and 1994, we redeemed, at par value, 40,000 shares, 20,000 shares and 20,000 shares, respectively. The redemptions in 1996 include 20,000 shares of optional redemptions. We are not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share, plus accrued dividends. Note I. Indebtedness
December 31, (in thousands) 1996 1995 - ----------------------------------------------------------------------------- Long-term debt: Debentures: 5.125%, due March 1996 $ 0 $ 100,000 5.700%, due March 1997 100,000 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 - ----------------------------------------------------------------------------- Total debentures 1,115,000 1,215,000 Less: due within one year (100,000) (100,000) - ----------------------------------------------------------------------------- Net long-term debentures 1,015,000 1,115,000 - ----------------------------------------------------------------------------- Sewage facility revenue bonds 34,100 35,700 Less: due within one year (667) (667) Less: funds held by trustee (4,789) (4,810) - ----------------------------------------------------------------------------- Net long-term sewage facility revenue bonds 28,644 30,223 - ----------------------------------------------------------------------------- Massachusetts Industrial Finance Agency bonds: 5.750%, due February 2014 15,000 15,000 - ----------------------------------------------------------------------------- Total long-term debt $1,058,644 $1,160,223 ============================================================================= Short-term debt: Notes payable: Bank loans $ 129,631 $ 75,941 Commercial paper 71,823 50,500 - ----------------------------------------------------------------------------- Total notes payable $ 201,454 $ 126,441 =============================================================================
44 1. Long-Term Debt The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity. There is no sinking fund requirement for any series of our debentures. Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In May 1995 and 1996, we redeemed $0.6 million and $1.6 million, respectively, as scheduled. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million. The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006. The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2001 are $101.6 million per year in 1997 and 1998, $1.6 million in 1999, $166.6 million in 2000 and $1.6 million in 2001. 2. Short-Term Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have regulatory authority to issue up to $350 million of short-term debt. We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. Information regarding our short-term borrowings, comprised of bank loans and commercial paper, is as follows:
(dollars in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------- Maximum short-term borrowings $272,500 $327,769 $268,100 Weighted average amount outstanding $208,914 $165,720 $214,640 Weighted average interest rates excluding commitment fees 5.65% 6.21% 4.47% - -----------------------------------------------------------------------------
Note J. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value: Nuclear decommissioning trust: The cost of $132.1 million approximates fair value based on quoted market prices of securities held. 45 Cash and cash equivalents: The carrying amount of $5.7 million approximates fair value due to the short-term nature of these securities. Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt: The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 1996, are as follows:
Carrying Fair (in thousands) Amount Value - ------------------------------------------------------------------------------ Mandatory redeemable cumulative preferred stock $ 83,465 $ 93,900 Sewage facility revenue bonds $ 34,100 $ 35,082 Unsecured debt $1,130,000 $1,131,363 - ------------------------------------------------------------------------------
Note K. New Accounting Pronouncement In October 1996, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 96-1, Environmental Remediation Liabilities, effective in 1997. This statement contains authoritative guidance on specific accounting issues that are present in the recognition, measurement, display and disclosure of environmental remediation liabilities. We do not believe this statement will have a material effect on our financial position or results of operations. Note L. Commitments and Contingencies 1. Contractual Commitments At December 31, 1996, we had estimated contractual obligations for plant and equipment of approximately $8 million. We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1996 are as follows:
(in thousands) - ------------------------------------------------------ 1997 $ 22,842 1998 20,042 1999 17,568 2000 16,684 2001 12,067 Years thereafter 98,945 - ------------------------------------------------------ Total $188,148 ======================================================
The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $455,117. We will capitalize a portion of these lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $26.3 million in 1996, $24.5 million in 1995 and $28.6 million in 1994, net of capitalized expenses of $2.9 million in 1996, $2.7 million in 1995 and $2.4 million in 1994. We also have various outstanding commitments for take or pay and throughput agreements, primarily to supply our New Boston generating station with natural 46 gas. The fixed and determinable portions of the obligations are $19.5 million in 1997, 1998 and 1999 and $14.6 million in 2000. We are also committed to purchase natural gas at market prices. The total expense under these agreements was $49.5 million in 1996, $13.9 million in 1995, and $6.5 million in 1994. 2. Hydro-Quebec We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. 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. At December 31, 1996, our portion of these guarantees was approximately $18 million. 3. Yankee Atomic We have a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and decommission the facility. Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 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 $16.5 million as of December 31, 1996. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement. 4. Connecticut Yankee On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power Company (CYAPC), which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the Haddam Neck, Connecticut unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of its operating license, compared to the costs of closing the unit and incurring replacement power costs for the same period. We have a 9.5% equity investment in CYAPC of approximately $10 million. The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee is approximately $763 million. Our share of these remaining estimated costs is $72.5 million. On December 24, 1996, CYAPC filed its cost estimate along with certain amendments to its power contracts with the FERC. The power contract amendments are designed to clarify the obligations of CYAPC's power purchasers, including Boston Edison, following the decision to cease power production. Based upon regulatory precedent, CYAPC believes it will continue to collect from its power purchasers its decommissioning costs, the owners' unrecovered investments in CYAPC and other costs associated with the permanent closure of the unit over the remaining period of the unit's operating license. We expect that we will continue to be allowed to recover our share of such costs from our customers and, therefore, have recorded our share of these costs on our consolidated balance sheet as a regulatory asset with a corresponding power contract liability. 47 5. Nuclear Insurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately $8.7 billion is provided by a retrospective assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. 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 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 $10.4 million under both the replacement power and excess property damage, decontamination and decommissioning policies. 6. Hazardous Waste We own or operate approximately 40 properties where oil or hazardous materials were previously spilled or released. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of approximately ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. At the majority of these sites we are one of many potentially responsible parties and currently expect to have only a small percentage of the potential liability. Through December 31, 1996, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. 48 7. Litigation We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation. The plaintiffs claimed certain automobiles stored on lots in South Boston suffered pitting damage caused by emissions from our New Boston Station generating unit. In February 1997, we settled the lawsuit brought by Subaru Distributors Corporation. The settlement did not have a material impact on our financial position or results of operations. The Subaru of New England, Inc. lawsuit is still pending. In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning employees affected by our 1988 reduction in force. In December 1996, we reached a settlement of this lawsuit under which there is no finding or admission of discriminatory employment practices. We anticipate full recovery from our insurance carrier for this settlement. In the normal course of our business we are also involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. 49 Note M. Long-Term Power Contracts 1. Long-Term Contracts for the Purchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of the generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidated income statements. Information relating to these contracts as of December 31, 1996, is as follows:
proportionate share (in thousands) ------------------------------------- Units of Capacity Debt Contract Purchased(a) Minimum Outstanding Expiration ------------ Debt Through Cont. Annual Generating Unit Date % MW Service Exp. Date Cost - ------------------------------------------------------------------------------ Canal Unit 1 2002 25.0 141 $ 1,415 $ 5,373 $ 24,399 Mass. Bay Trans- portation Authority - 1 2005 100.0 34 - - 1,999 Connecticut Yankee Atomic 2007 9.5 - 2,427 12,519 (b) Ocean State Power - Unit 1 2010 23.5 68 4,487 20,447 23,689 Ocean State Power - Unit 2 2011 23.5 67 3,538 16,529 24,091 Northeast Energy Associates (c) (c) 219 - - 124,730 L'Energia (d) 2013 73.0 63 - - 30,920 MassPower 2013 44.3 117 11,738 76,524 50,322 Mass. Bay Trans- portation Authority - 2 2019 100.0 34 - - 371 - ------------------------------------------------------------------------------ Total 743 $23,605 $131,392 $280,521 ============================================================================== (a) The Northeast Energy Associates contract represents 6% of our total system generation capability. The remaining units listed above represent 14.5% in total. (b) Connecticut Yankee permanently ceased operation in 1996. Refer to Note L.4. to these Consolidated Financial Statements for more details. (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. (d) We pay for this energy based on a price per kWh actually received.
50 Our total fixed and variable costs for these contracts in 1996, 1995 and 1994 were approximately $281 million (excluding Connecticut Yankee Atomic), $283 million and $286 million, respectively. Our minimum fixed payments under these contracts for the years after 1996 are as follows:
(in thousands) - ------------------------------------------------------ 1997 $ 85,429 1998 87,540 1999 88,401 2000 88,927 2001 91,089 Years thereafter 1,047,479 - ------------------------------------------------------ Total $1,488,865 ====================================================== Total present value $ 797,683 ======================================================
2. Long-Term Power Sales In addition to wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts. Information relating to these contracts is as follows:
Contract Expiration Units of Capacity Sold ---------------------- Contract Customer Date % MW - ------------------------------------------------------------------------------ Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 Various municipalities 2000(a) 3.7 25.0 - ------------------------------------------------------------------------------ Total 25.7 172.4 ============================================================================== (a) Subject to certain adjustments.
Under these contracts, the utilities pay their proportionate 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. 51 Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share) Balance Available Earnings Operating Operating Net for Common Per Average Revenues Income Income Stock Common Share(a) - -------------------------------------------------------------------------- 1996 - ---- First quarter $387,849 $ 52,093 $25,203 $21,313 $0.44 Second quarter 389,756 55,232 27,926 24,086 0.50 Third quarter 497,968 105,353 80,011 76,194 1.58 Fourth quarter 390,730 35,252 8,406 4,588 0.09 1995 - ---- First quarter $379,678 $ 47,610 $20,202 $16,300 $0.36 Second quarter 380,828 55,683 26,137 22,247 0.48 Third quarter 498,554 102,695(b) 72,368 (b) 68,478 (b) 1.46 (b) Fourth quarter 369,443 21,412(b) (6,397)(b) (10,286)(b) (0.21)(b) (a) Based on the weighted average number of common shares outstanding during each quarter. (b) As discussed in Note F to the Consolidated Financial Statements, we incurred a $34 million nonrecurring pre-tax charge related to our corporate restructuring over the third and fourth quarters of 1995. Amounts excluding the restructuring charge were as follows:
Balance Available Earnings Operating Net for Common Per Average Income Income Stock Common Share - -------------------------------------------------------------------------- 1995 - ---- Third quarter $107,779 $77,452 $73,562 $1.57 Fourth quarter 36,991 9,182 5,293 0.11
Item 9. Changes in and Disagreements with Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure - -------------------- Not applicable. 52 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 7 through 9 of the definitive proxy statement dated March 26, 1997, 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 7 through 9 of the definitive proxy statement dated March 26, 1997, 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 "Executive Compensation" on pages 27 through 33 of the definitive proxy statement dated March 26, 1997, incorporated herein by reference. 53 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 9 through 10 of the definitive proxy statement dated March 26, 1997, incorporated herein by reference. (c) Changes in Control - ----------------------- Not applicable. Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Not applicable. 54 Part IV ------- Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - ------------------------------------------------------------------------- (a) The following documents are filed as part of this Form 10-K:
1. Financial Statements: Page ---- Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994 28 Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994 28 Consolidated Balance Sheets as of December 31, 1996 and 1995 29 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994 30 Notes to Consolidated Financial Statements 31 Selected Consolidated Quarterly Financial Data (Unaudited) 51 Report of Independent Accountants 65
2. Financial Statement Schedules: No financial statement schedules are included as they are either not required or not applicable. 3. Exhibits: Refer to the exhibits listing beginning on the following page. (b) Reports on Form 8-K: A Form 8-K dated December 20, 1996, was filed during the fourth quarter of 1996 announcing that the Company reached a settlement agreement with the Massachusetts Attorney General and the Massachusetts Division of Energy Resources. 55
Exhibit SEC Docket ------- ---------- Exhibit 3 Articles of Incorporation and By-Laws - --------- ------------------------------------- Incorporated herein by reference: 3.1 Restated Articles of Organization 3.1 1-2301 Form 10-Q for the quarter ended June 30, 1994 3.2 Boston Edison Company Bylaws 3.1 1-2301 April 19, 1977, as amended Form 10-Q January 22, 1987, January 28, 1988, for the May 24, 1988 and November 22, 1989 quarter ended June 30, 1990 Exhibit 4 Instruments Defining the Rights of - --------- ---------------------------------- Security Holders, Including Indentures -------------------------------------- Incorporated herein by reference: 4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301 dated September 1, 1988, between Form 10-Q Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 4.1.1 First Supplemental Indenture 4.1 1-2301 dated June 1, 1990 to Form 8-K Indenture dated September 1, 1988 dated with Bank of Montreal Trust Company - June 28, 1990 9 7/8% debentures due June 1, 2020 4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301 the City of Boston, Massachusetts Form 10-K (acting by and through its Industrial for the Development Financing Authority) and year ended Harbor Electric Energy Company and December 31, Shawmut Bank, N.A., as Trustee, dated 1991 November 1, 1991 4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 5, 1991 re for the 9 3/8% debentures due August 15, 2021 year ended December 31, 1991
56
Exhibit SEC Docket ------- ---------- 4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K for the year ended December 31, 1992 4.1.4.1 First Amendment to Revolving Credit 4.1.10 1-2301 Agreement dated May 19, 1995 Form 10-K for the year ended December 31, 1995 4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301 Board of Directors of Boston Edison Form 10-K Company taken September 10, 1992 re for the 8 1/4% debentures due September 15, 2022 year ended December 31, 1992 4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301 Board of Directors of Boston Edison Form 10-K Company taken January 27, 1993 re for the 6.80% debentures due February 1, 2000 year ended December 31, 1992 4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken March 5,1993 re for the 5 1/8% debentures due March 15, 1996, year ended 5.70% debentures due March 15, 1997, December 31, 5.95% debentures due March 15, 1998, 1992 6.80% debentures due March 15, 2003, 7.80% debentures due March 15, 2023 4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 18, 1993 re for the 6.05% debentures due August 15, 2000 year ended December 31, 1993 4.1.9 Votes of the Pricing Committee of the 4.1.9 1-2301 Board of Directors of Boston Edison Form 10-K Company taken May 10, 1995 re for the 7.80% debentures due May 15, 2010 year ended December 31, 1995
57 The Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long-term debt whose authorization does not exceed 10% of the Company's total assets.
Exhibit SEC Docket ------- ---------- Exhibit 10 Material Contracts - ---------- ------------------ Incorporated herein by reference: 10.1 Key Executive Benefit Plan 10.1 1-2301 Standard Form of Agreement, May Form 10-Q 1986 for the quarter ended June 30, 1986 10.1.1 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May Form 10-K 1986, with modifications for the year ended December 31, 1991 10.2 Executive Annual Incentive 10.5 1-2301 Compensation Plan Form 10-K for the year ended December 31, 1988 10.3 1991 Director Stock Plan 10.1 1-2301 Form 10-Q for the quarter ended March 31, 1991 10.4 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 14, 1993 Form 10-K for the year ended December 31, 1992
58
Exhibit SEC Docket ------- ---------- 10.5 Deferred Compensation Trust 10.10 1-2301 between Boston Edison Company Form 10-K and State Street Bank and for the Trust Company dated year ended February 2, 1993 December 31, 1992 10.5.1 Amendment No. 1 to Deferred 10.5.1 1-2301 Compensation Trust dated Form 10-K March 31, 1994 for the year ended December 31, 1994 10.6 Directors Retirement Benefit 10.8.1 1-2301 (1993 Plan) Form 10-K for the year ended December 31, 1993 10.7 Performance Share Plan, Amendment 10.8 1-2301 and Restatement dated October 24, 1994 Form 10-K for the year ended December 31, 1994 10.8 Boston Edison Company Deferred 10.9 1-2301 Compensation Plan, Amendment and Form 10-K Restatement dated January 31, 1995 for the year ended December 31, 1994 10.9 Employment Agreement applicable to 10.10 1-2301 Ronald A. Ledgett dated April 30, 1987 Form 10-K for the year ended December 31, 1994 10.10 Retention Agreement applicable to 10.1 1-2301 Ronald A. Ledgett dated May 15, 1996 Form 10-Q for the quarter ended June 30, 1996
59
Exhibit SEC Docket ------- ---------- 10.11 Change in Control Agreement applicable 10.2 1-2301 to Thomas J. May dated July 8, 1996 Form 10-Q for the quarter ended June 30, 1996 10.12 Form of Change in Control Agreement 10.3 1-2301 applicable to Ronald A. Ledgett, Form 10-Q E. Thomas Boulette, L. Carl Gustin, for the John J. Higgins, Douglas S. Horan quarter ended and certain other officers dated June 30, 1996 July 8, 1996 Filed herewith: 10.13 Retention Agreement applicable to Douglas S. Horan dated May 15, 1996
60
Exhibit SEC Docket ------- ---------- Exhibit 12 Statement re Computation of Ratios - ---------- ---------------------------------- Filed herewith: 12.1 Computation of Ratio of Earnings to Fixed Charges for the Year Ended December 31, 1996 12.2 Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year Ended December 31, 1996 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
61
Exhibit SEC Docket ------- ---------- Exhibit 23 Consent of Independent Accountants - ---------- ---------------------------------- Filed herewith: 23.1 Consent of Independent Accountants to incorporate by reference their opinion included with this Form 10-K in the Form S-3 Registration Statements filed by the Company on February 3, 1993 (File No. 33-57840), May 31, 1995 (File No. 33-59693) and in the Form S-8 Registration Statements filed by the Company on October 10, 1985 (File No. 33-00810), July 28, 1986 (File No. 33-7558), December 31, 1990 (File No. 33-38434), June 5, 1992 (33-48424 and 33-48425), March 17, 1993 (33-59662 and 33-59682) and April 6, 1995 (33-58457) and in the Form S-4 Registration Statement filed by Boston Edison Holdings, currently known as BEC Energy, on March 17, 1997 (File No. 333-23439) Exhibit 27 Financial Data Schedule - ---------- ----------------------- Filed herewith: 27.1 Schedule UT Exhibit 99 Additional Exhibits - ---------- ------------------- Incorporated herein by reference: 99.1 MDPU Settlement Agreement with 28.1 1-2301 Boston Edison Company dated Form 8-K October 3, 1989 dated October 3, 1989 99.2 Settlement Agreement between Boston 28.1 1-2301 Edison Company and Commonwealth Form 8-K Electric Company, Montaup Electric dated Company and the Municipal December 21, Light Department of the Town of 1989 Reading, Massachusetts, dated January 5, 1990
62
Exhibit SEC Docket ------- ---------- 99.3 Pilgrim Outage Case Settlement between 28.2 1-2301 Boston Edison Company and Reading Form 8-K Municipal Light Department regarding dated Contract Demand Rate, dated December December 21, 21, 1989 1989 99.4 Settlement Agreement Between Boston 28.2 1-2301 Edison Company and City of Holyoke Form 10-Q Gas and Electric Department et. al., for the dated April 26, 1990 quarter ended March 31, 1990 99.5 Information required by SEC Form 1-2301 11-K for certain Company employee Form 10-K/A benefit plans for the years ended Amendments to December 31, 1995, 1994 and 1993 Form 10-K for the years ended December 31, 1995, 1994 and 1993 dated June 27,1996, June 29, 1995 and June 30, 1994, respectively 99.6 MDPU Settlement Agreement with 28.2 1-2301 Boston Edison Company, dated Form 10-Q October 23, 1992 for the quarter ended September 30, 1992
63 SIGNATURES ---------- Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BOSTON EDISON COMPANY By: /s/ James J. Judge --------------------------------------- James J. Judge Senior Vice President and Treasurer (Principal Financial Officer) Date: March 27, 1997 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 27th day of March 1997. /s/ Thomas J. May Chairman of the Board, President - ---------------------------------- and Chief Executive Officer Thomas J. May /s/ Robert J. Weafer, Jr. Vice President - Finance, - ---------------------------------- Controller and Chief Accounting Robert J. Weafer, Jr. Officer /s/ William F. Connell Director - ---------------------------------- William F. Connell /s/ Gary L. Countryman Director - ---------------------------------- Gary L. Countryman /s/ Thomas G. Dignan, Jr. Director - ---------------------------------- Thomas G. Dignan, Jr. /s/ Charles K. Gifford Director - ---------------------------------- Charles K. Gifford /s/ Nelson S. Gifford Director - ---------------------------------- Nelson S. Gifford /s/ Matina S. Horner Director - ---------------------------------- Matina S. Horner 64 /s/ Sherry H. Penney Director - ---------------------------------- Sherry H. Penney /s/ Herbert Roth, Jr. Director - ---------------------------------- Herbert Roth, Jr. Director - ---------------------------------- Stephen J. Sweeney
65 Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company: We have audited the consolidated financial statements of Boston Edison Company and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1996 and 1995, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. COOPERS & LYBRAND L.L.P. Boston, Massachusetts January 23, 1997 EX-10.13 2 RETENTION AGREEMENT APPLICABLE TO DOUGLAS S. HORAN Exhibit 10.13 May 15, 1996 Mr. Douglas S. Horan Senior Vice President and General Counsel Boston Edison Company 800 Boylston Street Boston, MA 02199 Dear Doug: At its April 25, 1996 meeting, the Board of Directors voted to adopt a Special Retention Program to provide particularly valued employees with an incentive to remain in the employment of the Company during the next three-year period. I am pleased to inform you that the directors agreed with my assessment that your contributions will be very important to the success of the Company during this critical time. Under the terms of the Agreement adopted by the Board, if you remain continuously in the employment of the Company through December 31, 1998, the Company will pay you an amount equal to the difference between the Performance Share Plan award which the Board determines to award you in January, 1999, if any, and $50,000. The net effect of this program is to guarantee you, if you stay for the required period, a long-term incentive plan bonus in January of 1999 which will be no less than $50,000. I look forward to, and depend upon, your assistance over the next three years in positioning the Company to thrive in the new industry environment. Sincerely, /s/ Thomas J. May - -------------------------- Thomas J. May EX-12.1 3 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12.1 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges Year ended December 31, 1996 (in thousands) Net income from continuing operations $141,546 Income taxes 87,982 Fixed charges 120,359 -------- Total $349,887 ======== Interest expense $109,374 Interest component of rentals 10,985 -------- Total $120,359 ======== Ratio of earnings to fixed charges 2.91 ====
EX-12.2 4 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS Exhibit 12.2 Boston Edison Company Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements Year ended December 31, 1996 (in thousands) Net income from continuing operations $141,546 Income taxes 87,982 Fixed charges 120,359 -------- Total $349,887 ======== Interest expense $109,374 Interest component of rentals 10,985 -------- Subtotal $120,359 -------- Preferred stock dividend requirements 24,862 -------- Total $145,221 ======== Ratio of earnings to fixed charges and preferred stock dividend requirements 2.41 ====
EX-23.1 5 CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Boston Edison Company on Form S-3 (File Nos. 33-57840 and 33-59693) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424, 33-48425, 33-59662, 33-59682 and 33-58457) and on Form S-4 (File No. 333-23439) of our report dated January 23, 1997 on our audits of the consolidated financial statements of Boston Edison Company as of December 31, 1996 and 1995 and for each of the three years in the period ended December 31, 1996, which report is included in this Annual Report on Form 10-K. By: /s/ Coopers & Lybrand, L.L.P. ----------------------------- Coopers & Lybrand, L.L.P. Boston, Massachusetts March 27, 1997 EX-27 6 FINANCIAL DATA SCHEDULE
UT 1,000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 2,956,588 155,130 375,818 241,755 0 3,729,291 48,510 695,723 292,191 1,036,424 81,465 119,954 1,058,644 129,631 0 71,823 100,667 2,000 0 0 1,128,683 3,729,291 1,666,303 88,703 1,329,670 1,418,373 247,930 698 248,628 107,082 141,546 15,365 126,181 90,834 3,394 356,582 2.61 0
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