View source for BECO-LTR-95-042, Forwards 1994 Annual Rept to Shareholders Boston Edison & Securities & Exchange Commission Form 10-K

{{Adams
| number = ML20082L382
| issue date = 04/10/1995
| title = Forwards 1994 Annual Rept to Shareholders Boston Edison & Securities & Exchange Commission Form 10-K
| author name = Fairbank R
| author affiliation = BOSTON EDISON CO.
| addressee name = 
| addressee affiliation = NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
| docket = 05000293
| license number = 
| contact person = 
| document report number = BECO-LTR-95-042, BECO-LTR-95-42, NUDOCS 9504210140
| package number = ML20082L385
| document type = CORRESPONDENCE-LETTERS, INCOMING CORRESPONDENCE
| page count = 63
}}

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:*-                                                                                    10CFR50.71(b) g                  10CFR140.15(b)(1)
BOSTONENSON Pilgrim Nuclear Power Station 600 Rocky Hill Road Plymouth, Massachusetts 02360 April 10, 1995 BECo Ltr. #95-042 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Docket No. 50-293 License No. DPR-35 Annual Financial Statement for 1994 in accordance with 10CFR 50.71(b) and 10CFR 140.15(b)(1), Boston Edison submits the enclosed -
1994 Annual Report, and the Securities and Exchange Commission (SEC) Form 10-K which
: corresponds to the 1994 Annual Report.
If you have say questions on this documentation, please contact Mr. Gerald Whitney at (508) 830-7872.
Respectfully,                     ,
_   J-             !
Y
                                                                                              . V. Fairbank fw                -j Manager, Regulatory               i Affairs and Emergency             i Preparedness Department -
GGW/ Rap 95/10K-94 Attachment                                                                                                    l cc:       Mr. R. Eaton, Project Manager                                                                       !
Division of Reactor Projects - 1/11                                                                 i Mail Stop: 1401 I
U. S. Nuclear Regulatory Commission 1 White Flint North                                                                                 ;
11555 Rockville Pike Rockville, MD 20852 U.S. Nuclear Regulatory Commission Region 1 475 Allendale Road King of Prussia, PA 19406 Senior Resident inspector Pilgrim Nuclear Power Station                                                               [ i     l 9504210140 950410                                                             {t PDR ADOCK 05000293 I                           PDR j

SECURITIES AND EXCHANGE COMMISSION Washi gton, D.C. 20549
 .                                                                   FORM 10-K
[X]       ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [ FEE REQUIRED]
For the fiscal year ended December 31,1994 OR
[ ] ' TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from                     to Commission file number 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter)
Massachusetts                                                                  04-1278810 (Stateorotherjurisdiction of                                                        (1.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 clag                                                                  on which renistered Common stock, par value $1 per sharc                                                New York Stock Exchange Boston Stock Exchange Cumulative preferred stock:
7.75% Series, par value $100 per sharc                                          New York Stock Exchange (represented by depositary shares-cach represents one-fourth interest in par value) 8.25% Series, par value $100 per share                                          New York Stock Exchange (represented by depositary sharcs-each represents one-fourth interest in par value)
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES .X_ NO._
The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 28,1995 computed by reference 12 the last reported sale price of the common stock, $1 par value, of the registrant of the New York Stock Exchange composite tape on that date: $1,117,923,951.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class                                               Outstanding at February 28.1995 Common Stock, $1 par value                                                45,629,549 shares DOCUMENTS INCORPORATED BY REFERENCE
    .lirl      Document 111      Portions of definitive proxy statement dated March 27,1995 for Annual Meeting of Stockholders to be held May 12,1995.

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!                                                                                       i Boston Edison Company i
I Form 10-K Annual Report December 31, 1994                                                       ;
l Part I                                                            Page !
Item   1. Business                                                  2 Item   2. Properties and Power Supply                               8 Item   3.- Legal Proceedings                                       11   l Item   4. Submission of Matters to a Vote of Security Holders     11 i
Part II                                                                 i Item   5. Market for the Registrant's Common Stock and Related Stockholder Matters                                     15  j Item   6. Selected Financial Data                                 16  j Item   7. Management's Discussion and Analysis                    17  ;
Item   8. Financial Statements and Supplementary Financial            j Information                                             27' Item   9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                     47  ;
i Part III                                                                i Item 10. Directors and Executive Officers of the Registrant      48 Item 11. Executive Compensation                                   48 l Item 12. Security ownership of Certain Beneficial owners and Management                                               49 Item 13. Certain Relationships and Related Transactions           49 Part IV I
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K                                                 50 i
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Part I Item 1. Business (a) General Development of Business Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law. The Company operates     in the energy and energy services business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of demand side management (DSM) programs.
In 1993 the Company established an unregulated subsidiary, Boston Energy Technology Group (BETG), following approval from the Massachusetts Department of Public Utilities (DPU). The Company has authority to invest up to $45 million in this wholly-owned subsidiary. BETG engages in demand side management activities and businesses involving electric transportation and the related infrastructure through its two wholly-owned subsidiaries. In 1994 BETG acquired a substantial majority interest in two additional businesses.
REZ-TEK International Corporation produces systems that treat cooling water used in commercial and industrial air conditioning systems in an energy efficient and environmentally sound manner, and coneco Corporation provides engineering and project management services to energy and water conservation project developers and contractors. The company does not currently have a substantial investment in BETG and does not expect the subsidiary to significantly impact the results of operations in the next several years.
(b) Financial Information about Industry Segments The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable.
(c) Narrative Description of Business Principal Products and Services The Company supplies electricity at retail to an area of 590 square miles encompassing the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approxinately 1.5 million. In 1994 the Company served an average of 656,000 customers. The company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Revenues by class for the last three years consisted of the following:
1994      1993       1992 Retail electric revenues:
Commercial                                         50%       49%        48%
Residential                                        28%       28%        27%
Industrial                                          9%       10%        10%
Other                                               2%         1%        2%
Wholesale and contract revenues                       11%        12%       13%
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Sources and Availability of Fuel The Company owns two stations whose generating units are fueled by oil, natural gas or both, one nuclear power station and ten combustion turbine generators. See the Company-owned Facilities section of Item 2. The company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:
Percentage of Company                   Average Cost of Fuel Generation by Source (%)                ($ per Million BTU) 1994    1993    1992   1991    1990    1994    1993   1992  1991    1990 011      27.8    31.3    33.7   42.8    33.6    2.35   2.38    2.40  2.60   2.76 Gas      31.6    24.3    25.7   24.9    33.3    2.28   2.67    2.55  2.08   2.35 Nuclear 40.6     44.4    40.6   32.3    33.1    0.50    0.51   0.52  0.56    0.59 i
The majority of the Company's residual oil parchases consists of imported oil acquired primarily from international suppliers. The Company has contracts with major oil companies that can supply most of its estimated requirements, assuming no major disruptions in oil producing regions. Within contract provisions, the Company has the ability to purchase significant amounts of oil in the spot market when it is economical to do so.
Most of the Company's natural gas is supplied on an interruptible basis by contract. These contracts permit interruptions in deliveries by the supplier when natural gas pipeline capacity is unavailable. Deliveries of natural gas to the Company's generating units from suppliers may also be dependent on the availability of pipeline capacity to the New England region and competitive forces prevailing in the pipeline industry. Beginning in April 1995 the Company will be required to operate New Boston Station using exclusively natural gas as fuel, except in certain emergency circumstances, as part of a 1991 consent order with the Massachusetts Department of Environmental Protection (DEP). The Company has made arrangements for a firm supply of natural gas to run the station at a minimum level and is developing a least-cost plan for operation beyond this minimum level involving principally the utilization of interruptible gas supplies or short-term capacity purchases.
In order to obtain nuclear fuel for use at Pilgrim Station the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 1998, 2000, 1998 and 2012, respectively.
Franchises Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for the Company's electric transmission and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act
,           as agents for the state. In some cases the action of these authorities is subject to appeal to the DPU. The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature.
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                                                                              . e Seasonal Nature of Business The Company's kWh sales and revenues are typically higher in the winter and summer than in spring and fall as sales tend to vary with weather conditions.
In addition, the company bills higher base rates to commercial and industrial customers during the billing months of June through September as mandated by the DPU. Accordingly, a significant portion of annual earnings occurs in the company's third quarter. See Selected consolidated Quarterly Financial Data (Unaudited) in Item 8.
Working Capital Practices The Company has no special practices with respect to working capital that would be considered unusual for the electric utility industry or significant for the understanding of the Company's business.
Customer Dependence No material portion of the Company's business is dependent upon one or a few customers.
Government Contracts No material portion of the Company's business is subject to renegotiation or termination of government contracts or subcontracts.
Conpetitive Conditions The Company is operating in an increasingly competitive environment. The electric utility business is in a period of transition from a traditional rate-regulated environment based on cost recovery to an environment with both competition and modified regulation. The effects of competition to date have been most evident in the wholesale electric narket. In response to increased competition from other electric utilities and non-utility generators to sell electricity for resale, the Company has secured long-term power supply agreements with its five wholesale customers. These agreements set the Company's rates through the year 2002 and beyond.
Direct competition with other electric utilities and other energy suppliers for retail electricity sales is still subject to substantial limitations, but there is potential for these limitations to be reduced in the future. The Company and other Massachusetts electric utilities are currently protected in several ways by the DPU and municipal statutes against other utilities offering service to retail customers in their service areas. Another electric utility may not extend its service area to include municipalities other than those named in its agreement of association or charter without DPU authorization granted after notice and public hearing. Also, another company may not obtain an initial location for its lines in a municipality served by the Company without the approval of municipal authorities, subject to the right of appeal to the DPU. Additionally, a municipality may not engage in the electric utility business without complying with statutes requiring specific city or town approval and the purchase of Company property within municipality limits.
However, the Company is currently experiencing some forms of competition in the retail electric market. Current legislation allows industrial and large commercial customers to own and operate their own electric generating units.
Retail customers may also substitute natural gas or oil for electricity as fuel for heating and cooling purposes. Large facilities may factor the cost 4

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of electricity into their decisions to relocate into or out of a given service territory. In addition, the DPU is currently investigating the benefits of restructuring the electric utility industry in Massachusetts and encouraging utilities to devise and propose incentive ratemaking plans. The Company is responding to the current and anticipated retail competitive challenges in several ways. These include actively participating in the formulation of regulatory policy concerning potential stranded invesdnents, planning to not seek additional base rate increases for at least five years, continuing aggressive control of costs and increasing operating efficiencies.
Research Activities The Company actively participates in several industry-sponsored research                                                                           l activities. These expenditures, included in other operations and maintenance                                                                       j expense on the consolidated income statement in Item 8, were not material in                                                                       l 1994.                                                                                                                                             )
Environmental Matters The Company is subject to numerous federal, state and local standards with                                                                        t respect to the management of wastes, air and water quality and other                                                                             )i environmental considerations. These standards can require modification of existing facilities or curtailment or termination of operations at these facilities, delay er discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. The company believes that its operating facilities are in substantial compliance with currently applicable statutory and             '
regulatory environmental requirements.
The Company's capital expenditures for environmental purposes during the five years 1990 through 1994 totalled approximately $137 million.                                                                    Environmental-related capital expenditures for the years 1995 through 1999 are currently expected to total approximately $47 million, including $11 million in both 1995 and 1996. These amounts exclude costs associated with asbestos removal which totalled approximately $8 million during the five years 1990 through 1994 and are currently expected to total approximately $3 million for the years 1995 through 1999. The company's capital expenditures for environmental purposes through 1994 included approximately $80 million related to certain improvements in the emission control systems at New Boston Station as discussed in the Environmental section of Other Matters in Item 7.
Substantial additional expenditures could be required as changes in environmental requirements occur.
The Company is required to clean up 48 properties that it owns or operates in which hazardous materials were released in the past. In addition, the Company has exposure to potential joint and several liability for the cleanup of ten multi-party hazardous waste sites where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Complex litigation or negotiations among the parties and with regulatory authorities is in process concerning the scope and cost of cleanup and the sharing of costs among the potentially responsible parties for several of these sites. The company's potential hazardous waste liabilities are described further in the Environmental section of Item 7.
Spent nuclear fuel and low-level radioactive waste (LLW) result from the operations of Pilgrim Station. Uncertainties currently exist regarding the ultimate disposal of both the spent nuclear fuel and LLW.                                                          See Note D to the 5

a consolidated financial statements in Item B for further discussion regarding spent nuclear fuel and LLW.
As a facility which treats and stores hazardous wastes, Pilgrim Station is required to be licensed by the United States Eavironmental Protection Agency (EPA). Pilgrim has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive.
The Company is subject to regulation by the EPA and the DEP relative to emissions from its fossil-fired generating' units under federal and Massachusetts clean air laws, including the 1990 Clean Air Act Amendments.
These regulations require the installation of various emissions controls and, in certain cases, the use of low sulfur content fuels. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section of Item 7.
The Company      also subject to regulation by the EPA and the DEP with respect to discharges of effluent from its generating stations into receiving waters.
The federal Clean Water Act and the Massachusetts Clean Waters Act require the Company to receive permits that limit discharges in accordance with applicable water quality standards and are subject to renewal every five years. The company has received the required discharge permits for each of its electric generating stations.
There are public concerns regarding electromagnetic fields ( EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. These concerns include the possibility of adveret health effects as well as perceived effects on property values. Refer to the Environmental section of Item 7 for a discussion of the EMF issue.
Number of Employees The Company had 4,026 full-time and 25 part-time utility employees as of the end of 1994, 2,560 of which are represented by two locale of the Utility Workers Union of America, AFL-CIO. In 1994 the Company and the locals signed new six-year labor contracts. BETG had 46 full-time employees at the end of 1994.
(d) Financial Information about Foreign and Domestic Operations and Export Sales See Principal Products and Services for information regarding the geographical area served by the Company and revenues by elssa 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 DFU, whose jurisdiction includes supervision over retail rates for electricity, financing, investing and accounting. In addition, the Federal Energy Regulatory Commission has jurisdiction over various phases of the Company's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of such power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation.
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The Company is required to 6ubmit to the DPU annual performance standards applicable to its generating units and other units from which the Company purchases power through long-term contracts. Under this generating unit performance program, the Company provides quarterly progress reports to the DPU. The DPU has the right to reduce subsequent fuel and purchased power billings if it finds that the Company has been unreasonable or imprudent in the operation of its generating units or in the procurement of fuel. The Company has not yet received orders from the DPU for the performance years ended October 1993 and October 1994. The Company believes that its current provision for refunds is sufficient to cover potential refunds.
The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which was issued in 1972 and expires in 2012.
Continuing NRC review of existing regulations and certain operating occurrences at other nuclear plants have periodically resulted in the imposition of additional requirements for all domestic nuclear plants, including Pilgrim Station. NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties. In addition, the Company could undertake certain actions regarding Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations (INPO), a voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants.
Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests for various kinds of federal, state and local legislative or regulatory action, direct voter initiatives or referenda or litigation. The Company cannot predict the extent, cost or timing of any modifications to Pilgrim Station which could be necessary in the future as a result of additional regulatory or other requirements nor can it determine the effect of such future requirements on the continued operation of Pilgrim Station. The Company continues to evaluate the operation of the station from the standpoint of safety, reliability and economics and believes that such continued operation is in the best interests of the Company and its customers.
Capital Expenditures and Financings The Company's most recent estimates of capital expenditures, allowance for funds used during construction (ATUDC), long-term debt maturities and sinking fund requirements for the years 1995 through 1999 are as follows:
(in thousands)        1995          1996         1997          1998         1999 I
Plant                                                                             1 expenditures     S200,000     $172,000      $172,000     $159,000     $156,000   I Nuclear fuel                                                                      ;
expenditures       11,000        18,000       13,000        24,000       13,000  l AFUDC (1)            6,000         5,000        4,000         5,000        4,000  j Long-term debt     100,600       101,600      101,600       101,600        1,600  i Preferred stock                                                                   I sinkinc fund        2,000         2,000        2,000         2,000        2,000  l 1
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                                                                                      .         )
e   o                                                     ,
(1)      Excludes estimated AFUDC on nuclear fuel of approximately $1,000 per year. The estimated AFUDC rate varies from 5.0% to 6.5%.                             '
The company conducts a continuing review of its capital expenditure and financing programs. These programs and the estimates shown above are therefore subject to revision due to changes in regulatory requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. In addition, depending upon the outcome of certain DEP air quality modeling studies currently in progress, the Company could be required to make additional expenditures by 1999 in order to comply with the provisions                '
of the 1990 Clean Air Act Amendments. The extent of any additional expenditures is uncertain at this time.
Plant expenditures in 1994 were approximately $199 million consisting
* primarily of additions to the Company's distribution system and fossil and                    1 nuclear ganeration facilities. Significant projects included spending of                      l approxiraately $13 million for the replacement of electric system property,
  $10.5 ndllion for a new energy control center, $10 million for a new substation and $9 ndllion for the replacement of the main turbine low pressure rotors at Pilgrim Station.
The company spent approximately $58 milJ f an on its DSM programs in 1994, of which $37 million was capitalized and is being collected from customers over                  i six years. DSM expenditures for 1995 are currently estimated to be approximately $43 million. Beginning in 1995 all costs will be collected primarily in the year incurred in accordance with an order from the DPU.
In 1994 the DPU approved the Company's financing plan to issue up to $500 million of securities through 1996 and to use the proceeds to refinance short and long-term securities and for capital expenditures. See Note H to the consolidated financial statements in Item 8 for specific information relating to the company's financing activities.
Item 2. Properties and Power Supply conpany-owned Facilities The Company's total electric generation capacity as of December 31, 1994                      i consisted of the following:
Maximum Capacity                      Year                -
Unit                    Location              (MW)       Type         Installed Pilgrim Nuclear        Plymouth, Mass.        669     Nuclear             1972               [
Power Station New Boston Station      South Boston, Mass. 760      Fossil        1965-1967 Units 1 and 2                                                                              ;
Mystic Station           Everett, Mass.
Units 4-5-6                                  399     Fossil        1957-1961 Unit 7                                      592      Fossil             1975 Combustion turbine     Various                 302     Fossil        1966-1971
_oenerators (ten) 8
* C  C   O      O All of the Company's steam fossil fuel-fired generating units are located at tide water and have access to fuel oil storage and/or natural gas or oil pipelines from nearby suppliers.
The Conpany is also a 5.888% joint owner in W.F. Wyman Unit 4. The 619 MW oil-fired unit located in Yarmouth, Maine began operations in 1978 and is operated by Central Maine Power Company.
Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and non-utilities and its participation in the New England Power Pool as further described in this item.
The Company's significant items of property consist of electric generating     >
stations, substations and certain service centers and are generally located on Company-owned land. The Company's high-tension transudssion lines are generally ?.ocated on land either owned by the company or subject to easements in its favor. The' Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by municiptl and other state authorities.
As of December 31, 1994 the Company's transmission system consisted of 362 miles of overhead circuits operating at 115, 230 and 345 kV and 156 ndles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 44 transmission or combined transmission and distribution    '
substations with transformer capacity of 10,112 megavolt amperes (MVA) , 70 distribution substations with transformer capacity of 1,213 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 231 customers' substations. The overhead and underground distribution systems cover 4,652 and 892 miles of streets, respectively.
HEEC, the Company's regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts.
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 roscurce nee and development policies. The Company currently has no proceedings cefore the EPSB.
Long-Term Power Contracts Refer to Note L to the consolidated financial statements in Item 8 for further information regarding the following contracts. The Company also has short-term agreements with several other utilities for varying periods for purchases of system and unit power, for sales of company system and unit power and for transmission services.
Utility Purchase Contracts:
The Company has a long-term contract with a subsidiary of Commonwealth Energy     <
I System in which it receives 25% of the output of an oil-fired electric generating plant. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return on investment.
The Company has two long-term purchased power contracts with the Massachusetts Bay Transportation Authority (MBTA) for the availability of two of the MBTA's jet turbines. The MBTA retains the right to utilize the jets for its own emergency use and for testing purposes while the Company retains New England      i Power Pool credit for their capacity and output.
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* O The company owns 9.5% of the common stock of Connecticut Yankee Atomic Power            ;
company, which operates a nuclear generating unit. The Company is entitled to.
receive 9.5% of the unit's output and is obligated to pay Connecticut Yankee 9.5% of its fixed and operating costs plus an annual return on investment.
Non-Utility Generator Purchase Contracts:
i The Company currently purchases 535 MW of capacity and associated energy from non-utility generators. These purchases are from Ocean State Power, Northeast Energy Associates, L'Energia and MassPower. In addition, the Company purchases power from two small hydro facilities.
In March 1995 the Company received a decision from the Massachusetts Supreme Judicial Court (SJC) regarding the Company's appeal of a 1994 DPU order that reaffirmed a 1993 order requiring it to purchase power from an independent power producer (see Resource regulation in Item 7) . The SJC decision reversed          '
the DPU order and remanded the case to the department for further consideration of evidence.
Sales Contracts:                                                                        ,
The Company has agreements with Commonwealth Electric Company, a subsidiary of          '
Commonwealth Energy System, and with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, under which Commonwealth and Montaup each                  ,
purchase 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and operating costs plus an annual return on                '
inves tment. Commonwealth and Montaup have also agreed to indemnify the Company to the extent of 11% each of all losses, liability or damage net covered by insurance resulting from the operation, condemnation, shutdown or retirement of the unit. In addition, the company has similar agreements with i
multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station.
New England Power Pool The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To 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.
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l The table below sets forth certain information as of the date of the Company's 1994-1995 winter and 1994 summer peak loads i
February 6, 1995      July 21, 1994       j (winter 1994-95)      (summer 1994)       l NEPEX utilities installed capacity:                                             l Seasonal maximum rating               25,645 MW           24,602 MW          I Seasonal normal rating                25,299 MW           24,379 MW          l NEPEX peak load (estimate)                19,205 MW          20,519 MW Company territory peak load                2,473 MW           2,798 MW The Company's net capacity was 3,561 MW at its winter peak and 3,484 MW at its summer peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,379 MW and 3,306 MW, respectively.
NEPOOL participants have two agreements with Hydro-Quebec of Canada for hydro-electric power. The first agreement, Phase I, provides up to three ndllion     i MWH of hydro-electric power to NEPOOL annually through 1997. The second agreement, Phase II, is a firm contract that provides seven million MWH of hydro-electric power annually through 2001. The price of the Phase II energy is based on the average cost of fossil fuel in New England for the previous year. The contract price is 80% of that average through 1996 and will be 95%
of that average in 1997-2001. The Company receives capacity credit through NEPOOL for approximately 11% of the generation equivalent of the total Hydro-Quebec interconnection.
The Company has an approximately 11% equity ownership interest in the two companies which own and operate the Phase II facilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants who do not meet certain credit criteria. Amounts so guaranteed by the Company were approximately $21 ndllion at December 31, 1994.
Item 3. Legal Proceedings
.         In 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by the Company's 1988 reduction in force.
Legal counsel continues to vigorously defend this case. Based on the information presently available the Company does not expect that this           ,
litigation or certain other legal matters in which it is currently involved will have a material impact on financial condition. However, an unfavorable     i decision ordered against the Company could have a material impact on the        l results of a reporting period.
See also Environmental Matters in Item 1 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 1994.
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Executive Officers of the Registrant The names, ages, positions and business experience during the last five years                   .
of all the executive officers of Boston Edison Company and its subsidiaries as                  I of March 1, 1995 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding between any Company officer and another person pursuant to which the officer                    i was elected. officers of the company hold office until the first meeting of                     l the directors following the next annual meeting of the stockholders and until                   ;
their respective successors are chosen and qualified.                                           j i
Business Experience                               ;
Name, Age and Position                        During Past Five Years i
Thomas J. May, 47                            Chairman of the Board and Chief Chairman of the Board and                     Executive Officer (since 1994),                   ,
Chief Executive Officer                       formerly President and Chief                      ,
Operating officer (1993-1994),                     ,
Executive Vice President (1990-                   l 1993) and Senior Vice President                   ;
(1987-1990). Director (since                      ;
1991). Chairman of the Board                      i and Chief Executive Officer and                   !
Director, Harbor Electric Energy                  l Company and Boston Energy                         {
Technology Group; Chairman of the                  i Board and Chief Executive officer,                i TravElectric Services Corp. and                   i Ener-G-Vision, Inc.; Chairman of
* the Board, REZ-TEK International Corp. and Coneco Corp.                            !
George W. Davis, 61                           President and Chief Operating President and Chief                           Officer (since 1994), formerly Operating officer                             Executive Vice President (1992-1994), responsible for all                        >
l power supply and delivery i
operations, Senior Vice President
                                              - Nuclear (1990-1992) and Vice                    j President - Nuclear Administration (1989-1990). Director (since 1991). President and Director,                    i Harbor Electric Energy Company and Boston Energy Technology Group;                   '
Director, TravElectric Services Corp. and Ener-G-Vision, Inc.
12                                                       ;
                                                          - - ,                   - ~ - -

Business Experience Name, Age and Position                       During Past Five Years E Thomas Boulette, $2                      ' 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.
Cameron H. Daley, 49                         Senior Vice President - Power Senior Vice President - Power Supply         supply (since 1989) .              _
L. Carl Gustin, 51                           Senior Vice President - Marketing L
b              Senior Vice President - Marketing &          & Corporate Relations (since-Corporate Relations                          1989).
John J. Higgins, Jr., 62                     Senior Vice President - Human Senior Vice President    Human Resources     Resources (since 1990) and Vice President - Human Resources (1988-1990).
Ronald A. Ledgett, 56                        Senior Vice President - Power Senior / ice President - Power Delivery      Delivery (since 1991) and     .
Director, Special Projects (1989-1991).
Charles E. Peters, Jr., 43                   Senior Vice President - Finance canior Vice President -- Finance              (since 1991), formerly Chief Financial Officer and Senior Vice President of Genrad, Inc. (1985-1991). Senior Vice President, Treasurer and Director, Harbor Electric Energy Company and Boston Energy Technology Group; Director, TravElectric Services Corp., Ener-G-Vision, Inc.,'REZ-TEK International Corp.
and Coneco Corp.
Marc S. Alpert, 50                           Vice President and Treasurer Vice President and Treasurer                  (since 1988). Assistant Treasurer, Harbor Electric Energy.
Company and Boston Energy Technology Group.
l 13

4+     .
I Business Experience Name, Age and Position                  During Past Five Years Robert J. Weafer, Jr., 48               Vice President, Controller and           l Vice President, Controller and Chief    Chief Accounting Officer (since Accounting Officer                      1991). Controller (1988-1991) and Chief Accounting Officer (1983-1991).
Theodora S. Convisser, 47               Clerk of the Corporation (since Clerk of the Corporation                1986). Clerk of Harbor Electric Energy Company, Boston Energy Technology Group, TravElectric Services Corp., Ener-G-Vision, Inc., REZ-TEK International Corp. and Coneco Corp.
Douglas S. Horan, 45                    Vice President and General Counsel Vice President and                       (since 1994), formerly Deputy General Counsel                         General Counsel (1991-1994) and Associate General Counsel (1986-1991). General Counsel of Harbor Electric Energy Company.
14

Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters (a) Market Information The company's common stock is listed on the New York and Boston Stock Exchanges.
Following are the reported high and low sales prices of the Company's common stock on the New York Stock Exchange as reported daily in the Wall Street Journal for each of the quarters in 1994 and 1993:
1994                                 1993 High         Low                    High          Low First quarter           $29 7/8      $26                    $30 1/2       $26 3/8 Second quarter           29 1/8       25 1/4                 30 7/8        27 7/8 Third quarter            27 5/8       22 3/4                 32 5/8        29 3/4 Fourth auarter           24 1/4       21 1/2                 32 1/4        27 7/8 (b) Holders As of December 31, 1994, the Company had 39,904 holders of record of its common stock (actual count of record holders).
(c) Dividends Following are the dividends declared per share of common stock for each of the quarters in 1994 and 1993:
1994               1993 First quarter                                 $0.440            $0.425 Second quarter                                 0.440             0.425 Third quarter                                  0.440             0.425 Fourth quarter                                 0.455             0.440 (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, 1994:
Ratio of earnings to fixed charges         2.45 Ratio of earnings to fixed charges and preferred stock dividend requirements      2.07 15

                                                                                              .'     )
l
                                                                                                   . l 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).                                    l 1994           1993           1992       1991          1990 Operating                                                                                     i revenues     $1,548,554   $1,482,253    $1,411,753    $1,354,501    $1,314,440 Net income-       125,022       118,218       107,298       94,670        79,616(a)
Earnings per                                                                                 ,
common share       2.41           2.28           2.10       1.96          1.60(a)
Total assets 3,616,610        3,477,288     3,294,234    3,119,285     3,012,589             i Long-term debt          1,136,617     1,272,497     1,091,073    1,136,765     1,074,025 Redeemable preferred /
preference stock           219,000       221,000       221,000      221,333       221,333             ,.
Cash dividends declared per common share      1.775          1.715        1.655        1.595         1.535              i (a)   Before cumulative effect of change in accounting principle ($15,824 or
               $0.41 per common share).                                                              t L
i l                                                                                                    P t
t I
f 16

Item 7. Management's Discussion and Analysis Regulatory Proceedings Retail settlement agreements In 1992 our state regulators, the Massachusetts Department of Public Utilities, approved a three-year settlement agreement effective November 1992.
This agreement provided us with retail rate increases, allowed for the recovery of demand side management (DSM) conservation program costs, specified certain accounting adjustments and clarified the timing and recognition of certain expenses. The agreement also set a limit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any penalties or rewards from performance incentives.
The retail rate increases consisted of a new annual performance adjustment charge effective November 1992 and two annual base rate increases of $29 ndllion ef fective November 1993 and November 1994. The performance adjustment charge varies annually based upon the performance of our Pilgrim Nuclear Power Station. This charge is further described in our discussion of financial condition.
In addition to the retail rate increases, our results of operations were affected by the recovery of DSM program costs, accounting adjustments and the timing and recognition of certain expenses as further described in the following Results of Operations section.
Our state    regulators previously approved a three-year settlement agreement effective    November 1989. That agreement also provided us with retail rate increases    and specified certain accounting adjustments. The 1989 agreement primarily   affected our results of operations through 1992.
We do not currently plan to make a base rate filing upon the expiration of the 1992 settlement agreement, therefore we anticipate that base rates will remain in effect at their current levels.
Results of Operations 1994 versus 1993                                                               l Earnings per common share were $2.41 in 1994 and $2.28 in 1993. The increase in earnings was primarily the result of the expiration of a long-term purchased power contract in October 1993, a retail base rate increase          4 effective November 1993, a 2.0% increase in retail kWh sales and an award relating to an eminent domain case. These positive changes were partially offset by higher operations and maintenance, depreciation and amortization and 1 income tax expenses.                                                           I l
27                                    ,
l

Qperating revenues operating revenues increased 4.5% over 1993 as follows:
(in thousands)
Retail electric revenues                         $62,945 Demand side management revenues                     5,056 Wholesale and other revenues                       (2,919)
Short-term sales revenues                           1,219 Increase in operatina revenues                $66,301 Retail electric revenues increased $63 million. The November 1993 and 1994' base rate increases resulted in $28.6 million of the increased revenues and approximately $6 million was due to the 2%-increase in retail sales. Fuel and purchased power revenues increased $28.5 udllion primarily due to the recovery of certain new purchased power expenses. In accordance with the 1992                   .
settlement agreement specific revenues related to the purchased power contract that expired in October 1993 were not affected.
The decrease in wholesale and other revenues is primarily due to an estimated provision for refunds to wholesale customers due to contract isse'i, qperating expenses Total fuel and purchased power expenses decreased $27 million. ruel expense decreased partly due to lower fossil fuel prices and a 12% decrease in nuclear output. Purchased power expense reflects lower costs associated with the long-term contract that expired in october 1993, partially offset.by the costs         ,
of new contracte. The timing effect of fuel and purchased power cost collection also contributed to the decrease in fuel and purchased power expenses. ruel and purchased power expenses are substantially all recoverable through fuel and purchased power revenues.
Other operations and maintenance expense increased 8.7% primarily due to higher employee benefit expenses. Pension expense increased $20 million due to a higher contribution made to the pension plan for the year.      In accordance with the 1992 settlement agreement, we record pension expense in the amount of the contribution to the plan.
Depreciation and amortization expense increased primarily due to a higher depreciable plant balance. In 1994 we fully expensed the remaining deferred costs of the cancelled Pilgrim 2 nuclear unit. In accordance with the 1992 settlement agreement we did not expense any of these costs in 1993.
Amortization of deferred nuclear outage costs consists of amounts related to the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we deferred approximately $14 million of refueling outage costs. We began to amortize these costs in June 1993 over five years as approved in the 1992 settlement agreement.
The $2 million decrease in demand side management programs expense was due to           !
the timing of recovery of program costs. DSM expense includes some program costs recovered over twelve months and other program costs recovered over six years. The 1994 expense (snsists of $22 million of costs primarily related to           ,
1994 expenditures and $13 million of costs capitalized in 1992 through 1994.           l l
Municipal property and other taxes increased primarily as a result of higher            l Boston property taxes due to a tax rate increase and capital additions.
                                                                                         )
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our effective ~ annual income tax rate for 1994 was 31.4% vs. 23.4% for 1993.
Both rates were reduced by adjustments to deferred income taxes of $10 million in 1994 and $20 million in 1993 made in accordance with the 1992 settlement agreement. .No further deferred income tax adjustments may be made and we expect our effective tax rate to be close to the statutory rate in 1995.              ;
other income                                                                          l In November 1994 a court ruling became effective providing us with an-                :
additional $5.7 ndllion gain on a 1989 eminent domain taking of our property.         ;
Interest charges Interest charges in total did not change significantly. Interest charges on long-term debt decreased due to the first mortgage bond and debenture                 i redemptions in 1994 and the significant first mortgage bond refinancing in            i 1993 at lower interest rates. This decrease was partially offset by higher            i amortization of redemption premiums. Other interest charges increased due to          :
higher short-term interest rates partially offset by a lower average short-           l term debt level. Allowance for borrowed funds used during construction                :
(ArUDC), which represents the financing costs of construction, increased as a        ;
result of a higher AFUDC rate related to higher short-term interest rates.           ,
I 1993 versus 1992                                                                      !
Earnings per common share were $2.28 in 1993 and $2.10 in 1992. The increase          i in earnings was primarily the result of a retail rate increase effective-November 1992, the expiration of a long-term purchased power contract in October 1993, no' amortization of deferred cancelled nuclear unit costs and           ;
lower interest expense. These positive changes were partially offset by               j higher operations and maintenance, income tax and property tax expenses.              i Operating revenues I
operating revenues increased 5.0% over 1992-as follows:
i (in thousands)                                                                       i Retail electric revenues                          $70,837                             i Demand side management revenues                     33,601                             l Wholesale and other revenues                         (2,794)                            l Short-term sales revenues                          (31,144)                           j Increase in operatine revenues                  $70,500                            1 1
Retail electric revenues increased $71 million. The November 1992 and 1993             l rate increases resulted in $40.6 million of additional revenues in 1993. Fuel       !
and purchased power revenues increased $29.5 million over 1992 primarily due           ,
to the timing effect of fuel and purchased power cost collection and lower             i revenues received from short-term power sales as discussed below.
l We began recovery of certain demand side management program costs, lost base revenues and incentives in August 1992. Our 1993 revenues provided $45.9 million related to 1991, 1992 and 1993 DSM programs. Our.1992 revenues of
          $12.3 ndllion related primarily to 1991 programs.                                      l The decrease in wholesale and other revenues reflects an estimated provision for refunds to customers of $8.6 million in 1993 as a result of orders fro:m our state regulators on our genei 'ing unit performance program.
19

                 . . _ .      _                   _    _   _ .      _    .      -_ _ ._~   __
I Lower short-term power sales revenues were a result of changes in our generation availability and the needs of short-term power purchasers.
Revenues from short-term sales serve to reduce fuel and purchased power                            i billings to retail customers and therefore have no effect on earnings.
Qperating expenses Total fuel and purchased power expenses decreased $12 million. Fuel expense decreased primarily due to a 21.5% decrease in fossil generation and an 8.5%                       l decrease in nuclear generation, resulting from planned plant overhauls and a                       i nuclear refueling outage.        Purchased power expense reflects both higher                      l interchange purchases, caused by the lower generation, and lower costs                             j associated with the long-term contract that expired in October 1993. The                           ;
decreases in expense were partially offset by the timing effect of fuel and purchased power cost collection.
Other operations and maintenance expense increased 7.1% primarily due to                          J increases in employee benefits and nuclear production expenses.
Postretirement benefits expense increased by $7 million primarily as a result of the adoption of a new accounting standard and pension expense increased by                     i
  $5 ndllion; both are provided for in our 1992 settlement agreement and further                    >
explained in Note E to the consolidated financial statements. A refueling                        i outage at Pilgrim Station in 1993 resulted in higher nuclear production                           ,
expenses.
Depreciation and amortization expense increased in 1993 primarily due to a                        ,
higher annual decommissioning charge for Pilgrim Station effective November                       ,
1992 provided by the 1992 settlement agreement. The charge is based on a 1991 estimate of decommissioning costs as further discussed in Note'D to the                           '
consolidated financial statements.       In addition, the effect of lower depreciation rates implemented in accordance with the settlement agreement was offset by the effect of a higher depreciable plant balance.
In accordance with our 1992 settlement agreement we did not expense any of the                    '
  $19 million of remaining deferred costs associated with the cancelled Pilgrim                     -
2 nuclear unit in 1993.                                                                           ,
Amortization of deferred nuclear outage costs consists of amounts related to the 1993 and 1991~ refueling outages at Pilgrim Station as discussed in the results of operations for 1994 versus 1993.                                                      ,
l The increase in demand side management programs expense is consistent with the increase in DSM revenues. DSM expense includes some costs recovered over twelve months and other costs recovered over six years. We began to recover previously deferred DSM expenses in August 1992.      In 1993 we expensed and collected from customers approximately $30 million of deferred 1991, 1992 and 1993 program costs. Over six years we are expensing and collecting from our customers $11 million of costs capitalized in 1992 and $37 million of costs capitalized in 1993. The 1993 expense related to these capitalized costs was
   $7 ndllion.
Municipal property and other taxes increased in 1993 due to the absence of tax                   ,
abatements. In 1992 property taxes were reduced by $10.4 million of tax                          .
abatements in accordance with our 1989 settlement agreement.
Our effective annual income tax rate for 1993 was 23.4% vs. 8.7% for 1992.                       '
Both rates were significantly reduced by adjustments to deferred income taxes of $20 ndllion in 1993 and $23 million in 1992 made in accordance with the 1992 and 1989 settlement agreements. The 1992 rate was also reduced due to 20

4 -
tax benefits of approximately $7 million resulting from mandated payments made in accordance with the 1989 agreement. Our adoption of a new accounting standard for income taxes in 1993 did not significantly affect earnings.
Interest charges and preferred and preference dividends Total interest charges decreased $4 million in 1993. Interest on long-term debt decreased primarily due to tne refinancing of substantially all our first mortgage bonds in 1993 at lower interest rates, partially offset by higher amortization of redemption premiums. Other interest charges decreased due to a lower short-term debt level and lower short-term interest rates. AFUDC decreased as a result of a lower AFUDC rate related to lower short-teon interest rates.
Preferred and preference dividends decreased 5.1% due to the replacement of a preferred and a preference stock issue with less costly issues of preferred stock.
Financial Condition Our 1992 settlement agreement is providing us with increased revenues from retail customers over the three-year period ending October 1995.
Additionally, a significant long-term purchased power contract expired in October 1993 with no change in related revenues. The settlement agreement also limits the annual rate of return on equity during the three-year period to 11.75%, excluding any penalties or rewards from performance incentives.
Our ability to achieve or exceed the 11.75% rate of return on equity is primarily dependent upon our ability to control costs and to earn performance incentives from generation performance mechanisms. The most significant impact that incentives can have on our financial results is based on Pilgrim Station's annual capacity factor. An annual capacity factor between 60% and 68% would provide us with approximately $47 million of revenues in the performance year ended October 1995. For each percentage point increase in capacity factor above 68%, annual revenues will increase by approximately
       $690,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%), annual revenues will decrease by approximately $790,000.
Pilgrim's capacity factor for the performance year ending October 1995 is currently expected to be approximately 69%, a decrease from the 72% capacity factor achieved in the performance year ended October 1994, primarily due to the refueling outage scheduled for 1995. We earned approximately $47 million in revenues related to Pilgrim's capacity factor in the performance year ended   i October 31, 1994.
1 Pilgrim Station automatically shut down in August 1994 as a result of a non-nuclear problem with its electrical generator. The plant returned to service three months later following the completion of necessary repairs as well as     ,
maintenance work originally scheduled for an October 1994 mid-cycle outage.      l The power needs usually met by the station were met by our other generating      i plants or purchased from other suppliers as necessary. We do not believe that    '
the generator damage resulted from actions within our control, however, our recovery of the incremental purchased power costs during the outage through fuel and purchased power revenues is subject to review by our state regulators under our generating unit performance program.
As discussed in Regulatory Proceedings, we do not plan to make a base rate       l filing with our state regulators upon the expiration of the 1992 settlement     l agreement, therefore we anticipate that our base rates will remain in effect    i at their current levels.
21                                      4 1
i

a 0
1 l
I Liquidity We meet our capital expenditure cash requirements primarily with internally generated funds. These funds provided for 90%, 76% and 88% of our plant and nuclear fuel expenditures in 1994, 1993 and l's92, respectively. Our current estimate of plant expenditures for 1995 is $200 million. These expenditures will be used primarily to naintain and improve existing transmission, distribution and generation facilities. We do not expect plant expenditures          '
to vary significantly from the 1995 amount in the four years thereafter. We have long-term debt and preferred stock payment requirements of $102.6 ndllion in 1995, 5103.6 millier per year in 1996 through 1998 and $3.6 million in 1999.
External financings continue to be necessary to supplement our internally generated funds, primarily through the issuance of short-term commercial paper and bank borrowings. We currently have authority from our federal regulators to issue up to $350 million of short-term debt. We have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At December 31, 1994 we had $215 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1994 our state regulators approved our financing plan to issue up to $500 million of securities through 1996. The proceeds will be used to refinance short and long-term securities and for capital expenditures. Refer to Note H to the consolidated financial statements for specific information relating to our recent financing activities.
Outlook for the Future Electricity sales A significant portion of our electricity sales are made to commercial customers rather than industrial customers. As a result our sales have been only moderately impacted by the unfavorable economic factors affecting the manufacturing industry in Massachusetts, including defense cutbacks and continued downsizing in the computer industry. Increased sales to commercial customers more than offset the decrease in sales to industrial customers as economic factors provided growth in the commercial sector in 1994. Total retail sales increased 2% in 1994.
Implementation of DSM prograns, which are designed to assist customers in reducing electricity use, will result in lower growth in electricity sales.
We receive approval from our state regulators for annual DSM spending levels and recovery amounts. Through 1994 we collected from customers certain DSM program costs primarily in the year incurred and other DSM program costs over a six-year period. We are also provided with incentives and recovery of lost revenues based on the actual reduction in customer electricity usage from these programs and a return on the costs that we recover over six years.
Beginning in 1995 all costs are expected to be collected primarily in the year incurred. We will continue to recover the DSM costs capitalized during 1992 through 1994 along with a return on investament on the unrecovered balance.
Competition The electric utility business is in a period of transition from a traditional rate-regulated environment based on cost recovery to an environment with both competition and modified regulation. The effects of competition to date have been most evident in the wholesale electric market. In response to increased 22

1 l
1 l
competition from other electric utilities and non-utility generators to sell       j electricity for resale, we have secured long-term power supply agreements with     j our five wholesale customers. These agreements set our rates through the year      1 2002 and beyond.
We are also beginning to face some forms of competition in the retail electric market. This is happening as industrial and large commercial customers pursue their options to generate their own electric power, as customers look to obtain lower electricity prices and to substitute natural gas or oil for electricity for heating or cooling purposes and as large facilities factor the cost of electricity into their decisions to relocate into or out of a given service territory. In the future, the potential exists for electric utilities and other energy suppliers to sell electricity to retail customers of other electric utilities without regard for existing service territories.      In addition, our state regulators are currently investigating two issues related to the onset of competition, incentive regulation and industry restructuring.
We are responding to the current and anticipated retail competitive challenges in several ways. We do not plan on seeking any additional base rate increases until at least the year 2000 and are working to accomplish this by controlling costs and increasing operating efficiencies without sacrificing quality of service or profitability. During 1994 we reduced our workforce by 8.4%, we negotiated six-year contracts with our two union locals which resulted in cost-saving changes and limits wage growth and we implemented various other cost control strategies. We also developed customer alliances and provided economic development rates to some customers. In addition, we filed with our state regulators for approval of lower rates for a small number of large manufacturing customers on a limited basis. These actions all signify our commitment to be a competitively priced, reliable provider of energy. We are also actively participating in regulatory and legislative discussions and proceedings concerning the future structure of the electric utility industry.
We do not expect the economic development rates or the proposed lower manufacturing customer rates to have a significant impact on our financial condition or results of operations.
As a regulated company, we are subject to certain accounting rules that are not applicable to other businesses and industries. These accounting rules allow regulated companies, as appropriate, to record certain costs as regulatory assets instead of expenses when they are incurred. These regulatory assets are expected to be recovered from customers through future rates. The effects of competition or changes in regulation could ultimately cause us to no longer be able to follow these accounting rules, in which case our regulatory assets would have to be fully expensed at that time.
Resource regulation our state regulators require utilities to purchase power from qualifying non-utility generators at prices set through a bidding process.      In 1993 our state regulators ordered us to purchase 132 megawatts of power from an independent power producer, Altresco Lynn, LP, starting as early as 1995. We oppose this order since we do not believe we need any new power for several years. We asked the Massachusetts Supreme Judicial Court (SJC) to reverse the order and in 1994 the SJC remanded the case to our state regulators for further consideration. Our regulators then issued an order requiring us to negotiate a contract with Altresco Lynn. We filed an appeal of this order with the SJC in October 1994 and are currently awaiting a decision. In addition, we supported an appeal filed by other parties of a state regulatory body's conditional approval of construction of Altresco Lynn's generating station project. In January 1995 the SJC reversed the regulator's approval on the 23

i basis that there was no showing of need for the project in Massachusetts prior to 2000.
We are also subject to our state regulators' integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs with all other supplies of energy. We submitted an IRM filing in 1994 and received a favorable ruling in January 1995. Our regulators found that we do not have a need for additional resources through 2001 and we are not required to issue a competitive request for proposal for new generating capacity at this time. We are required to update our IRM filing in January 1996.
Non-utility business In 1993 we created an unregulated subsidiary, Boston Energy Technolt y Group (BETG), following approval from our state regulators. We have authority to invest up to $45 ndllion in this wholly-owned subsidiary. BETG engages in demand side management activities and businesses involving electric transportation and the related infrastructure through two wholly-owned subsidiaries. In 1994 BETG acquired a substantial majority interest in two additional businesses. REZ-TEK International Corp. produces systems that treat cooling water used in commercial and industrial air conditioning systems in an energy efficient and environmentally sound manner, and Coneco corporation provides engineering and project management services to energy and water conservation project developers and contractors. These acquisitions were not material.
We do not currently have a substantial investment in BETG and do not anticipate it significantly impacting our results of operations in the next several years.
Other Matters a
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 48 properties where hazardous materials were released in the past. We are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection (DEP) and are continuing to evaluate the costs associated with their cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of ten multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transpotted or disposed of hazardous waste at the sites.
At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability. Through December 31, 1994, we have accrued approximately S7 m!111on related to our cleanup liabilities. We are unable to fully                <
determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any such additional costs to have a material impact on our financial condition. However, additional provisions for cleanup costs could have a material impact on our results of a reporting period.
I 24

   +   .
'.                                                                                  j l
l Uncertainties continue to exist with respect to the disposal of both low-level radioactive waste (LLW) and spent nuclear fuel resulting from the operation of l Pilgrim Station. In July 1994 our access to off-site LLW disposal facilities ended. Until access is attained to other disposal facilities we are nanaging LLW through on-site storage. 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. Refer to Note D to the consolidated financial statements for further discussion regarding LLW and spent nuclear fuel disposal.
Under a 1991 consent order with the DEP and other interested parties we made certain improvements in the emission control systems at New Boston Station.
These improvements included the replacement of four existing chimney stacks with two taller stacks in order to improve the air quality in the vicinity of the station, and the installation of low nitrogen oxides burners. The capital costs of these modifications along with other associated improvements, which were substantially completed in 1994, were approximately $80 million.
New Boston Station has the ability to burn natural gas, oil or both.
Beginning in April 1995, as part of the DEP consent order, we will be required to operate the station fueled exclusively by natural gas, except in certain emergency circumstances. We have made arrangements for a firm supply of natural gas to run the station at a minimum level. We are developing a least-cost plan for operation beyond this minimum level involving principally the utilization of interruptible gas supplies or short-term capacity purchases.
The 1990 Clean Air Act Amendments will require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel-fired generating units. The reduction will be accomplished by restricting sulfur dioxide emissions through a market-based system of allowances. We currently have allowances that are in excess of our needs and which may be marketable. Any gain from the sale of these may be subject to future regulatory treatment.     ,
other provisions of the 1990 Clean Air Act Amendments involve limitations on   i emissions of nitrogen oxides from existing generating units. Combustion system modifications made to New Boston and Mystic Stations, including the installation of the low nitrogen oxides burners at New Boston, will allow the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain DEP air quality modeling studies currently in progress, additional emission reductions may also be required by 1999. The extent of any additional reductions and the cost of any further modifications is uncertain at this time.                                                        1 l
In recent years there have been increasing public concerns 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          l potential health effects, while other studies have not substantiaced such      l associations. We support further research into the subject and are             1 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 i or in requests for legislation or regulatory standards concerning EMF levels.
J 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.
l l
25                                       I
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                                                                                 , I Li tiga tion                                                                       !
l In 1991 we were named in a lawsuit alleging discriminatory employment              ;
practices under the Age Discrimination in Employment Act of 1967 concerning 46     I employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a naterial impact on our financial condition. l However, an unfavorable decision ordered against us could have a material impact on our results of a reporting period.
                                                                                   )
Executive Office Changes In July 1994 our former President, Thomas May, became Chairman and Chief Executive Officer, former Executive Vice President George Davis became President and Chief Operating Officer and former Chairman and Chief Executive Officer Bernard Reznicek retired. In January 1995 George Davis announced his anticipated retirement effective September 1995.
26

7 __
Item 8. Financial Statements and Supplementary Financial Information Consolidated Statements of Income years ended December 31, (in thousands, except earnings per share)         1994          1993         1992 Operating revenues                         $1,548,554 S1,482,253 $1,411,753 Operating expenses:
Fuel                                     156,951       170,799      200,774 Purchased power                          356,874       370,049      352,030 Other operations and maintenance         441,423       406,271      379,350 Depreciation and amortization            149,122       137,722      129,045 Amortization of deferred cost of cancelled nuclear unit                   19,791             0       24,381 Amortization of deferred nuclear outage costs                              7,721         6,546        4,901 Demand side management programs           35,438        37,504        8,221 Taxes - property and other               100,132        93,102       80,426 Income taxes                              54,279        34,941       11,725 Total operating expenses              1,321,731     1,256,934    1,190,853 Operating income                               226,823       225,319      220,900 Other income (expense), net                      5,658           589       (2,074)
Operating and other income                     232,481       225,908      218,826 Interest charges:
Long-term debt                           102,570       104,375      106,850 Other                                     12,367         9,778       12,525 Allowance for borrowed funds used during construction                      (7,478)       (6,463)      (7,847)
Total interest charges                  107,459       107,690      111,528 Net income                                     125,022       118,218      107,298 Preferred and preference dividends provided 15,765            15,705       16,550 Balance available for common stock         $ 109,257 $ 102,513 $           90,748 Common shares outstanding (weighted average) 45,338           44,959       43,144 Earninas per share of common stock         $      2.41   S      2.28  $      2.10 Consolidated Statements of Retained Earnings years ended December 31, (in thousands)                                    1994          1993         1992 Balance at beginning of year               $ 218,292 $ 192,948 $ 174,477 Net income                               125,022       118,218      107,298 Subtotal                                343,314       311,166      281,775 Cash dividends declared:
Preferred stock                           15,765        15,705       14,923 Preference stock                               0             0        1,953 Common stock                              80,545        77,169       71,951 Subtotal                                 96,310        92,874       88,827 Balance at end of year                     $ 247,004 S 218,292 S 192,948 The accompanying notes are an integral part of the consolidated financial statements.
27

e Consolidated Balance Sheets December 31, (in thousands)                                                                          1994                        1993 Assets Utility plant, at original cost:
In service                                                         $4,074,810               $3,904,776 Less: accumulated depreciation 1,344,452 $2,730,358                                       1,258,359 $2,646,417 Nuclear fuel                                                          291,836                  273,867 Less: accumulated amortization                                     236,239       55,597     220,477        53,390 Construction work in progress                                                     144,048                  144,835 2,930,003                2,844,642 Investments in electric companies, at equity                                                                            24,678                    24,292 Nuclear decommissioning trust                                                         82,831                    66,060 Current assets:
Cash and cash equivalents                                               6,822                   8,768 Accounts receivable                                                   189,382                  171,098 Accrued unbilled revenues                                               32,240                  29,823 Fuel, materials and supplies, at average cost                                                       71,560                  79,381 Prepaid expenses rad other                                             26,705    326,709        9,738     298,808 Deferred debits:
Regulatory assets                                                    197,455                  210,144 Intangible asset pension                                               22,849                       0 other                                                                  32,085    252,389       33,342     243,486 Total assets                                                                 $3,616,610              $3,477,288 Capitalization and Liabilities Common stock equity                                                              S 915,747               $ 876,479 Cumulative preferred stock:
Non-mandatory redeemable series                                                  123,000                  123,000 Mandatory redeemable series                                                         94,000                    96,000 Long-term debt                                                                    1,136,617                1,272,497 Current liabilities:
Long-term debt / preferred stock due within one year                                          $102,250                 S 2,000 Notes payable                                                        214,786                  204,151 Accounts payable                                                     139,119                  117,614 Interest accrued                                                       24,464                  25,467 Dividends payable                                                      23,533                  22,696 Pension benefits                                                       31,908                  22,005 other                                                                  76,615     612,675      32,477     426,410 Deferred credits:
Power contracts                                                        40,277                  36,275 Accumulated deferred income taxes 515,454                                                     484,785 Accumulated deferred investment tax credits                                                           67,048                  71,140 Nuclear decommissioning reserve                                        92,404                  73,744                       !
Other                                                                  19,388     734,571      16,958     682,902, Commitments and contingencies                                                               -                            -
Total capitalization and liabilities                                         $3,616,610               $3,477,208 The accompanying notes are an integral part of the consolidated financial statements.
28

4 ...
Consolidated Statements of Cash Flows years ended December 31,      ,
(in thousands)                                              1994        1993       1992   !
Cash flows from operating activities:
Net income                                         $125,022 $118,218 $107,298 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation                                      142,932      130,074    123,243 Amortization of nuclear fuel                        18,810      21,816     25,473 Amortization of deferred cost of cancelled nuclear unit, net                                  19,067            0    22,340 Amortization of deferred nuclear outage costs                                               7,721        6,546      4,901 Other amortization                                  13,967        9,433      2,132 Deferred income taxes                               (4,184)      10,303     17,165 Investment tax credits                              (4,092)      (4,073)    (4,273)
Allowance for borrowed funds used during construction                                       (7,478)      (6,463)    (7,847)
Net changes in:
Accounts receivable and accrued unbilled revenues                                (20,701)       13,206   (18,188) ruel, materials and supplies                          3,093       9,722     (2,330)
Accounts payable                                    21,505     (18,465)     35,759 Rate and contract settlements                              0       (175)  (31,363)
Other current assets and liabilities                36,908       25,209      3,575 other, net                                          15,561     (19,548)   (15,844)
Net cash provided by opera ting activities             368,131      295,803    262,041 Investing activities:
Plant expenditures (excluding AEUDC)               (198,760) (246,763) (213,827)
Nuclear fuel expenditures                            (21,934)       (6,491)  (17,198)
Capitalized demand side management expenditures                                       (37,007)     (37,156)   (11,469)
Sale of plant assets, net                             15,972            0           0 Nuclear decommissioning trust investments            (16,771)     (15,189)     (7,210)
Electric company investsents                              (386)     1,106      1,836 Net cash used by investing activi ties                (258,886) (304,493) (247,868)
Financing activities:
Issuances Common stock                                          10,634       10,855     70,412 Preferred stock                                              0     40,000     40,000 Long-term debt                                        15,000     815,000      60,000 Redemptions:
Preferred and preference stock                         (2,000)    (40,000)   (40,333)
Long-term debt retirements                           (50,000) (648,625) (123,600)
Net change in short-term debt                            10,635      (71,349)    65,200 Dividends paid                                          (95,460)     (92,370)   (86,184)
Net cash provided (used) by financing activities (111,191)            13,511    (14,505)
Net increase (decrease) in cash and cash equivalents                                              (1,946)      4,821        (332)  ,
Cash and cash equivalents at the                                                           I beginning of the year                                     8,768       3,947      4,279 Cash and cash ecuivalents at the end of the year S 6,822 S             8,768  S 3,947      l l
Cash paid during the year for Interest, net of amounts capitalized               $108,462 $103,720 $113,076 Income taxes                                       S 46,074 $ 30,305 $ 10,095 The accompanying notes are an integral part of the consolidated financial statements.
l l
29                                                I i

9 Notes to Consolidated Financial Statements Note A. Significant Accounting Policies
: 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly-owned subsidiaries, Harbor Electric Energy Company and Boston Energy Technology Group.
All significant intercompany transactions have been eliminated.
* We follow accounting policies prescribed by our federal and state regulators.          .
We are also subject to the accounting and reporting requirements of the                '
Securities and Exchange Commission. The financial statements comply with generally accepted accounting principles. Certain prior period amounts on the financial statements were reclassified to conform with current presentation.
: 2. Revenues                                                                          ,
We record revenues for electricity used by our customers but not yet billed at the end of each accounting period.
: 3. Forecasted Tuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and some purchased power costs to be billed to customers using a forecasted rate. The difference between actual and estinated costs is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel and purchased power rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.
: 4. Depreciation and Bruclear ntel Amortisation our physical property was depreciated on a straight-line basis in 1994, 1993           !
and 1992 at composite rates of 3.11%, 3.09% and 3.36% per year, respectively, based on estimated useful lives of the various classes of property. The cost of decommissioning Pilgrim Station, our nuclear unit, is excluded from the i
depreciation rates. When property units are retired, their cost, net of salvage value, is charged to secumulated depreciation.
The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates.
: 5. Amortisation of Deferred Bruclear Outage Costs We expense deferred nuclear outage costs over five years as approved in the 1992 settlement agreement. The deferred cost balances in 1994 and 1993 consist of amounts related to the 1993 and 1991 refueling outages at Pilgrim Station.
30
: 6. Amortisation of Discounts, Preanisans and Jtedenption Premiums on Debt We expense discounts, premiums, redemption premiums and related costs associated with issuances or redemptions of long-term debt or the refinancing of existing debt over the life of the debt or the replacement debt subject to regulatory approval.
: 7. Allowance for Bunds Creed During Constzuction (AEDDC)
AFUDC represents the estimated costs to finance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the fcom of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1994, 1993 and 1992 were 4.45%, 3.62% and 4.48%, respectively, and represented only the cost of short-term debt.
: 8. Cash and cash Equivalents cash and cash equivalents are comprised of highly liquid securities with maturities of three months or less. Outstanding checks are included in cash and accounts payable until they are presented for payment.
: 9. Allowance for Doubtful Accounts our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
: 10. Blegulatory Assets Regulatory assets represent costs incurred which will be collected from customers through future charges in accordance with agreements with our state regulators. These costs are to be expensed when the corresponding revenues are received in order to appropriately natch revenues and expenses. A portion of these costs is currently being recovered from customers. No return on investment was earned on the regulatory assets.
Regulatory assets consisted of the following:
December 31, 1994                1993 Redemption premiums                        $52,859             $59,116 Income taxes, net                           44,745              26,916 Power contracts                             40,277              36,275 Pension and postretirement costs            22,761              24,416 Nuclear outage costs                        17,804              25,524 Cancelled nuclear unit                            0             19,067 other                                       19,009              18,830 S197,455            $210,144 Note B. Retail Settlement Agreements In 1992 and 1989 our state regulators, the Massachusetts Department of Public Utilities, approved three-year settlement agreements relating to our rate case proceedings. These agreements provided for retail rate increases, accounting adjustments and demand side nanagement program expenditures; clarified the 31

timing and recognition of certain expenses and set limits on our rate of return on common equity. Refer to Management's Discussion and Analysis for further information related to these settlement agreements.
The settlement agreements did not affect our contract or wholesale power rates charged to other utilities, which are regulated by our federal regulators, the Federal Energy Regulatory Commission.
Note C. Income Taxes In 1993 we prospectively adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SEAS 109). This required us to change our methodology of accounting for income taxes from the deferred method to an asset and liability approach. The deferred method was based on the tax effects of timing differences between income for financial reporting purposes and taxable income. The asset and liability approach requires the recognition of deferred tax 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 SEAS 109 we recorded net regulatory assets of
$44.7 million and $26.9 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1994 and December 31, 1993, 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)                                       1994                       1993 Deferred tax liabilities:
Plant-related                                  $511,572                $496,731 Other                                           105,786                    95,161 617,358                  591,892 Deferred tax assets:
Plant-related                                     13,216                    9,999 Investment tax credits                           43,273                   45,914 Alternative minimum tax                            1,332                   18,672 Other                                             44,083                   32,522 101,904                 107,107 Net accumulated deferred income taxes       $515,454                $484,785 No valuation allowances for deferred tax assets are deemed necessary.
Components of income tax expense were as follows:
years ended December 31, (in thousands)                                        1994        1993        1992 Current income tax expense                        $62,839      $28,711   $    (385)
Deferred tax expense                                (4,468)     10,303     16,383 Investment tax credits                              (4,092)     (4,073)     (4,273)
Income taxes charged to operations               54,279      34,941     1),725 Taxes on other income:
Current                                           2,550       1,205      (2,348)
Deferred                                            284            0         782 2,834       1,205      (1,566)
Total income tax expense                     $57.113     $36,146    S10,159 32

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:
1994                   1993             1992 Statutory tax rate                                                           35.0%                  35.0%           34.0%
State income tax, net of federal income tax benefit 4.3                                              4.2                      3.9 Investment tax credits                                                       (2.3)                  (2.6)              (3.6)
Hunicipal property tax adjustment                                                -
(0.6)              (1.6)
Adjustment of deferred taxes on cancelled nuclear unit                                                                    -                      -
2.7 Reversal of deferred taxes-settlement agreement                              (5.5)               (13.0)      (19.6)
Federal tax benefit of mandated payments from settlement agreements                                             -                      -
(6.2)
Other                                                                        (0.1)                   0.4              (0.9)
Effective tax rate                                                      31.4%                  23.4%                     8.7%
Note D. Nuclear Decommissioning and Nuclear Waste Disposal
: 1.        braclear Deccanissioningr I
When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. We are expensing an estimate of the deconadssioning costs over Pilgrim's expected service life. The 1994 expense of approximately $15 ndllion is included in depreciation expense on the consolidated income statement. The estimate used to determine our annual expense is based on a 1991 study which documents a cost of approximately $328 million to decommission the plant using the " green field" method, which provides for the plant site to be completely restored to its original state.
The cost estimate, which involves many uncertainties, was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense from charges to our retail customers and from other utility companies and municipalities who purchase a contracted amount of Pilgrim's electric generation. The funds we collect from deconadssioning charges are deposited in an external trust and are restricted so that they may only be used for decommissioning and related expenses. The net earnings on the trust funds, j     which are also restricted, increase the nuclear decomndssioning fund balance i
and nuclear decommissioning reserve, thus reducing the amount to be collected from customers.
The 1991 decommissioning study was partially updated for internal planning purposes to evaluate the potential impact of long-term spent fuel storage options resulting from delays in United States Department of Energy (DOE) spent fuel removal on the estimated decommissioning cost.                             (See part 2 below for a discussion of spent fuel removal). The partial update indicates an estimated decommissioning cost of approximately $400 million in 1991 dellars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. No further update is currently available, however we will continue to monitor DOE spent fuel removal schedules and develorments in spent fuel storage technology along with their impact on the deconadssioning
!     estimate.
In 1994 the Financial Accounting Standards Board began to review the                                                                    {
accounting for decommissioning. If current industry accounting practices are changed our annual decommissioning expense could increase and trust fund earnings could be reported as investment income. In addition, the total                                                                 j estimated liability for decommissioning costs may be recorded on the balance                                                            l sheet, most likely fully offset by an addition to utility plant costs. We do 33 l
l l
                                                                                                                                              )

not expect that these potential changes would have a material effect on our results of operations.
: 2. Spent Ruclear 1%el In 1994 we received a license amendment from the Nuclear Regulatory Commission to modify our fuel storage facility at Pilgrim Station to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. We have modified the facility to provide spent fuel storage capacity through approximately 2003, however any further modifications are subject to review by our state regulators. In addition we are actively exploring the feasibility of other spent fuel storage facilities and technologies.
It is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. The DOE is currently conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political opposition and the DOE has publicly stated that it may be unable to construct such a repository in a timely manner. In June 1994 we and other interested parties filed petitions in the U.S. Court of Appeals for the D.C. Circuit seeking declaratory rulings that the DOE is obligated to begin taking spent nuclear fuel for disposal in 1998. The DOE has sought to dismiss those petitions and a court ruling is awaited. It is unknown at this time whether and on what schedule the DOE will eventually construct a spent fuel repository and what the effect on us will be of any delays in such construction.
.T . Low-Level Radioactive Waste our access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina ended in July 1994. Until access is attained to other disposal facilities we are managing LLW generated at Pilgrim Station through en-site storage. 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.
However, it appears unlikely that either option will be available in the near future. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW ranagement procedure, we will continue to monitor the situation and investigate other available options.
: 4. Other Raclear Units We are an investor in and customer of two other domestic nuclear units. Both of these units receive, through the rates charged to their customers, an amount to cover the estimated costs to dispose of their spent nuclear fuel and to decommission the units at the end of their useful lives.
34

Note E. Pensions, Other Postratiressent'and Postemployment Benefits                       !
: 2. Pensions We have a Jefined benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and compensation during the last years of 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. Plan assets are primarily equities,                   !
bonds, insurance contracts and real estate funds.                                             l Net pension cost consisted of the following components:
                                                                                                       ~
years ended December 31, (in thousands)                                        1994           1993            1992 Current service cost - benefits earned              $15,057      $ 11,734       $ 10,683 Interest cost on projected benefit obligation                                     33,961         33,181         32,287 Actual net loss /(return) on plan assets                 214       (44,470)       (23,281)
Net amortization and deferral                       (32,169)         8,528        (13,549)    >
Net Dension cost (a)                           $17,063      $   8,973      $ 6,140 (a)    In accordance with an agreement with our state regulators we deferred the difference in net pension costs and the annual funding amounts. Net deferred costs amounted to $6 udllion and $14 million at December 31, 1994 and 1993, respectively. Net pension costs recorded as expense were
                   $25 ndllion in 1994, $5 ndllion in 1993 and $0 in 1992.                               ,
We used the following assumptions for calculating pension cost:
1994          1993            1992 Discount rate                                          7.00%          8.25%           0.25%
Expected long-term rate of return on assets           10.00%         10.00%         10.00%
Compensation increase rate                              4.50%         4.50%           4.50%    l The pension plan's funded status was as follows:
December 31, (in thousands)                                                       1994            1993 Actuacial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of $305,632 and $384,150                        $321.072      $400,895 Plan assets at fair value                                        $289,164      $394,233 Projected obligation for service rendered to date                                                        (387,910)      (509,661)
Projected benefit obligation in excess of plan assets                                                      (98,746)      (115,428)
Unrecognized prior service cost                                     13,328           8,139     1 Unrecognized net loss                                               67,361         75,352      l Unrecognized net obligation                                          8,998           9,932 Minimum liability adjustment (b)                                   (22,849)               0 Net pension liability                                        $(31,908)     $(22,005)
(b) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SEAS 87), requires the recognition of an additional udnimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accordance with SEAS 87 we-35                                                 l l
i l

i I
recorded an additional minimwm liability and corresponding intangible asset of $23 million on our consolidated balance sheet at December 31, 1994.
We used the following assumptions for calculating the plan's year-end funded status:
1994       1993 Discount rate                                                      8.25%     7.00%
Compensation increase rate                                         3.90%     4.50%
f We also provide defined contribution 401(k) plans for substantially all our
! employees. We match a percentage of employees' voluntary contributions to the plans, which amounted to $8 ndllion in 1994, $7 million in 1993 and $5 ndllion in 1992.
(
: 2. Other Postretirement Benefits                                                      l In addition to pension benefits, we also currently provide health care and                j other benefits to our retired employees who meet certain age and years of service eligibility requirements. In 1993 we adopted Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106) . This requires us to record a liability during the working years of employees for the expected costs of i
providing their postretirement benefits other than pensions (PBOPs). Prior to 1993 our policy was to record the cost of PBOPs when paid. Our transition obligation upon adopting this standard was approximately $183 million, which we elected to recognize over 20 years as permitted by SEAS 106.
Our 1992 settlement agreement provides us with a phase-in of a portion of the higher PBOP costs incurred under SEAS 106 and allows us to defer the additiona) costs in excess of the phase-in amounts to the extent that we fund             ,
an external trust. Our funding policy is to contribute 100% of postretirement benefit :ostn to external trusts. Accordingly, we recorded expenses of $17 million in 1994 and $15 million in 1993, reflecting the amount of current cost recovery flom customers, and deferred the net costs in excess of amounts expensed for future recovery. Net deferred costs amountel to $16 million and              !
   $10 million at December 31, 1994 and 1993, respectively.                                 l Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands)                                                    1994       1993 Current service cost - benefits earned                         $ 4,978    4 4,351 Interest cost on accumulated benefit obligation                 13,632     14,286 Actual return on plan assets                                        (187)         0 Amortization of transition obligation                            9,151      9,151 Net amortization and deferral                                   (2,581)          0 Net postretirement benefits cost                           $24,993    $27,788 36

1 1
l i
i We used the following assumptions for calculating postretirement benefits cost:                                                                                        l 1994            1993 Discount rate                                                         7.0%            8.0%
Expected long-term rate of return on assets                           9.0%            9.0%
Health care cost trend rate                                           9.0%           12.5%
The health care' cost trend rate is assumed to decrease by one percent each year beginning in 1995 to 5% in 1998 and years thereafter. Changes in the                  !'
health care cost trend rate will affect our cost and obligation amounts. A one percent increase in the assumed health care cost trend rate would increase the total service and interest cost components by 20% and would increase the accumulated benefit obligation at December 31, 1994 by 18 % .
The postretirement benefits program's funded status was as follows:                          l i
December 31, (in thousands)                                              1994                    1993   >
Trust assets at fair value                            $ 33,300               S 18,016 Accumulated obligation for service rendered to date from:
Retirees                                 $ (93,960)            $(75,216)
Active employees eligible to retire         (31,159)             (64,880)
Active employees not eligible to retire (51,545)(176,664) (73,285) (213,381)
Accumulated benefit obligation in excess of trust assets                                        (143,364)             (195,365)
Unrecognized prior service cost                           (19,502)                       0 Unrecognized net (gain)/ loss                              (1,849)               21,497 Unrecognized transition obligation                        164,715               173,868 Net postretirement benefits liability              S        0            $           0 The weighted average discount rates we used to measure the accumulated benefit              :
l obligation were 8.25% in 1994 and 7.0% in 1993. The trust assets consist of equities, bonds and money market funds.
: 3. Postenployment Benet'its In 1994 we adopted Statement of Financial Accounting Standards No. 112, Employers' Accounting for Postemployment Benefits (SEAS 112). This required us to record a liability for the estimated costs of providing postemployment benefits. Postemployment benefits provided to former or inactive employees, their beneficiaries and covered dependents consist primarily of disability-related benefits, including workers' compensation. We previously recognized the costs of these benefits primarily as claims were paid. The adoption of SEAS 112 did not have a material effect on our results of operations.
Note F. Eminent Domain Taking In November 1994 a Norfolk Superior Court ruling against the Massachusetts Metropolitan District Cornission (MDC) became effective, providing us with an additional $5.7 million gain on an eminent domain land taking case. We had filed suit against the MDC in 1992 related to the eminent domain taking of certain of our property in 1989.
1 Note G. Cancelled Nuclear Unit In May 1962 we began to expense the cost of our cancelled Pilgrim 2 nuclear                j unit over approximately eleven and one-half years in accordance with an order 37

L received from state regulators. We did not expense any of these costs in 1993. The remaining balance of $19 million was fully expensed in 1994 as allowed by our state regulators in our 1992 settlement agreement.
Note E. Capital Stock and Indebtedness C4pital Stock December 31, (dollars in thousands, except per share amounts)                                                             1994      1993         1992 Common stock equity:
Common stock, par value $1 per share, i            100,000,000 shares authorized; 45,535,477, f            45,129,227 and 44,763,055 shares issued and outstanding                                                                                            $ 45,535 $ 45,129 $ 44,763                      {
Premium on common stock                                                                                   622,803   612,653    602,196                  l Retained earnings                                                                                         247,004   218,292    192,948 Surplus invested in plant                                                                                     405        405         405                ]
Total common stock couity                                                                          $915,747 $876,479 $840,312 Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
Non-mandatory redeemable series:
Current Shares                                                         Redemption j                Series        Outstanding                                                            Price / Share f
4.25%             180,000                                                            $103.625     $ 18,000 $ 18,000 $ 18,000 l                 4.78%            250,000                                                             $102.800        25,000    25,000     25,000 7.75%             400,000                                                                 -          40,000    40,000            0 8.25%             400,000                                                                 -          40,000    40,000     40,000 8.88%                                                                       0             -
0          0    40,000 Total non-mandatory redeemable series                                                           $123,000 $123,000 $123,000 Mandatory redeemable series:
Current Shares Series        outstanding 7.27%             460,000                                                                         $ 46,000 $ 48,000 $ 48,000 8.00%            500,000                                                         ,
50,000    50,000     50,000 Total mandatory redeemable series                                                                     96,000    98,000     98,000 Less: due within one year                                                                              2,000     2,000            0 Total mandatory redeemable seriis, net                                                          S 94,000 $ 96,000 $ 98,000                      .
Dividends Declared per Share Common stock                                                                                            $ 1.775 $ 1.715 $ 1.655 Preferred stocks 4.25% series                                                                                    $ 4.250 $ 4.253 $ 4.250 4.78% series                                                                                        4.780     4.785      4.780                  1 7.27% series                                                                                        7.270     7.270      7.270                  '
7.75% series                                                                                        7.750     5.707            0 8.00% series                                                                                        8.000     8.000       8.000 8.25% series                                                                                        8.250     8.250       5.278 8.88% series                                                                                            0     2.220       8.880 Preference stock
                    $1.46 series                                                                                    $       0 $        0 $ 0.365 38

f
      .                                                                                       l, i
Zadabtedness December 31,      i (dollars in thousands)                                     1994                  1993 Long-term debt:
First mortgage bonds:
Series S, variable rate, due 2002           $          0       $     25,000 Series U, 10.250%, due 2014                            0             15,000 Total first mortgage bonds                                  0             40,000 Sewage facility revenue bonds                            36,300              36,300 Less: due within one year                                  600                     0 Less: funds held by trustee                             4,083                3,803 Net long-term sewage facility revenue bonds           31,617              32,497 Debentures:
8.875%, due 1995                                100,000             100,000 5.125%, due 1996                                100,000             100,000 5.700%, due 1997                                100,000             100,000 5.950%, due 1998                                100,000             100,000 6.800%, due 2000                                 65,000              65,000 6.C50%, due 2000                                100,000             100,000 6.800%, due 2003                                150,000             150,000 9.875%, due 2020                                100,000             100,000 9.375%, due 2021                                115,000             125,000 8.250%, due 2022                                 60,000              60,000 7.800%, due 2023                                200,000             200,000 Total debentures                                   1,190,000          1,200,000 Less: due within one year                            100,000                     0 Net long-term debentures                           1,090,000          1,200,000 Massachusetts Industrial Finance Agency bonds:
5.750%, due 2014                                 15,000                     0 ;
Total lono-term debt                      $1,136,617         S1,272,497 Short-term debt:
Notes payable Bank loans                                  S    80,786        $ 106,501 Commercial paper                                134,000              97,650 Total notes payable                       S 214,786           S 204,151
: 1. Ccamon Stock Since December 31, 1991, we issued the following shares of common stock:
Number          Total    Premium on (in thousands)                            of Shares      Par Value Common Stock Balance December 31, 1991                      42,047        $42,047      $536,567 Dividend reinvestment plan                 416            416            9,658 New issue (a)                            2,300          2,300          55,971 Balance December 31, 1992                      44,763         44,763        602,196 Dividend reinvestment plan                 366            366          10,457 Balance December 31, 1993                      45,129         45,129        612,653 Dividend reinvestment plan (b)             406            406          10,150 Balance December 31, 1994                      45,535        $45,535       $622,803 39

(a)     We used the net proceeds of the 1992 common stock issuance to reduce short-term debt.
(b)    'At December 31, 1994, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 2,,408,920 shares.
: 2. Cussalative Non-Mandatory 3tedeemable Preferred stock In May 1993 we issued 400,000 shares of 7.75% eumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in May 1998. These shares were sold in the               -
form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulative non-mandatory redeemable preferred stock.
: 3. Cumulative Mandatory Jtedeemable Preferre<* Stock                                  !
The 460,000 shares of our 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $103.88. The redemption price declines annually each May to par value in May 2002. The stock is subject to             i a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the non-cumulative option each May to redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per            -
share plus accrued dividends.                                                            ,
We are not able to redeem any part of our 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.
: 4. Long-Tema Debt The aggregate principal amounts of our debentures and sewage facility revenue            ,
bonds (including sinking fund requirements) due are $100.6 million in 1995,              !
 $101.6 million per year in 1996 through 1998 and $1.6 million in 1999.
In February 1993 we issued $65 million of 6.80% debentures due in 2000. We used the proceeds of this issue to reduce short-term debt. These debentures are not redeemable prior to maturity.
In March 1993 we issued $650 million of debentures and used the proceeds to retire ten series of first mortgage bonds and reduce short-term debt. The debentures were issued in five separate series with interest rates ranging from 5.125% to 7.8% and maturing between 1996 and 2023. The 5 1/8% debentures due 1996, 5.70% due 1997, 5.95% due 1998 and 6.80% due 2003 are not redeemable prior to maturity. The 7.80% debentures due 2023 are first redeemable in March 2003 at a redemption price of 103.73%.       The redemption price decreases annually each March to par value in March 2013. There is no sinking fund requirement for any series of these debentures.
In August 1993 we issued $100 million of 6.05% debentures due in 2000. We used the proceeds from this sale to reduce short-term debt. These debentures are not redeemable prior to maturity and have no sinking fund requirements.
In March 1994 the Massachusetts Industrial Finance Agency, on our behalf, issued $15 ndllion of 5.75% tax-exempt unsecured bonds due in 2014. The bonds are redeemable beginning in February 2004 at a redemption price of 102%. The 40

I I
redemption price decreases to 101% in February 2005 and to par in February 2006. The proceeds from this issuance together with sufficient other funds were used to fully redeem the Series U first mortgage bonds.                     j i
We redeemed at par the $25 million variable rate Series S first mortgage bonds   1 I
in 1994. These bonds paid interest at 9.2% for the period January 15, 1993 through January 14, 1994. The rate was adjusted to 8.2% beginning January 15,    ;
1994 based upon the ten-year constant maturity Treasury rate as published by     l the Federal Reserve Board.
As a result of the redemption of all outstanding first mortgage bonds, the Indenture of Trust and First Mortgage that had mortgaged substantially all our property since 1940 was terminated in November 1994.
Sewage facility revenue bonds were issued by Harbor Electric Energy Company (HEEC), a wholly-owned subsidiary. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. 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 certain costs on a timely basis or be unable to meet certain net worth requirements, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of
    $7 ndllion.
: 5. Short-Tezm Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have authority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings.
Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.
Information regarding our short-term borrowings, comprised of bank loans and commercial paper is as follows:
(in thousands of dollars)                            1994       1993      1992 Maximum short-term borrowings                     $268,100 $320,000 $314,998 Weighted average amount outstanding               $214,640 $220,149 $233,286 Weighted average interest rates, excluding commitment fees                                      4.5%       3.4%      4.1%
Note I. Fair Value of Securities The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:
Nuclear decommissioning trust The cost of $82.8 ndllion approximates fair value based on quoted market prices of securities held.
Cash and cash equivalents The carrying amount of $6.8 ndllion approximates fair value due to the short-term nature of these securities.
41

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, 1994 are as follows:
1 1                                                                                       Carrying        Fair l (in thousands)                                                                          Amount       Value Mandatory redeemable cumulative preferred stock                                    $    96,000 $    93,780 Sewage facility revenue bonds                                                           36,300      37,037 Unsecured debt                                                                       1,205,000   1,111,317 Note J. New Accounting Pronouncement Statement of Financial Accounting Standards No. 115, Accounting for certain Investments in Debt and Equity Securities, became effective in 1994. This statement did not have a material effect on our consolidated financial statements.
Note K. Comunitments and Contingencies l 1. Capital Coannitments                                                                                     l At December 31, 1994, we had estimated contractual obligations for plant and equipment of approximately $50 million.
: 2. Lease Coannitments We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both noncancellable leases and transmission agreements for the years after 1994 are as follows:
(in thousands) 1995                                                                      $ 26,540 1996                                                                        24,305 1997                                                                        21,396 1998                                                                        19,438 1999                                                                        17,794 Years thereafter                                                           127,646 I        Total                                                              $237,119 l
i
! We will capitalize a portion of these lease rentals as part of plant expenditures in the future. Our total expense for both lease rentals and transudssion agreements was $27 million in 1994 and $30 million in 1993 and 1992, net of capitalized expenses of $4 million in 1994 and $5 million in 1993 l  and 1992.
J. 3rydro-Quebeo We have an approximately lit equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included in our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria and are compensated accordingly. At December 31, 1994, our portion of these guarantees was approximately $21 million.
42

I
~.
: 4. Yankee Atcania Electxto Ccam We have a 9.5% stock investment of approximately $2.5 ndllion in Yankee Atomic  j Electric Company (Yankee Atomic). In 1992 the Board of Directors of Yankee      j Atomic decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and decommission the facility. We relied on Yankee Atomic for less than one percent of our system capacity under a long-term       1 purchased power contract.
In 1993 Yankee Atomic received approval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $39 million as of December 31, 1994. 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.
: 5. Nuclear Insurance The federal Price-Anderson Act currently provides approximately $8.9 billion of financial protection for public liability clains and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately $8.3 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 110 units licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional fiss percent of the maximum retrospective assessment.
We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is approximately $14.8 ndllion under both the replacement power and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses are in excess of the total funds available to NEIL. While assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in an assessment.
: 6. Litigation In 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel continues to vigorously defend this case. Based on the infornation presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition.
However, an unfavorable decision ordered against us could have a material impact on our results of a reporting period.
43
: 7. Rasardous Waste We own or operate 48 properties where hazardous materials were released in the past. 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 costa 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 ten multi-party' hazardous waste-sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at.the sites.
At the majority of these sites we are one of many potentially responsible parties and we currently expect to have only a small percentage of the potential liability. Through December 31, 1994, we have accrued approximately
$7 ndllion related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not expect any such additional costs to have a material impact on our financial condition. However, additional provisions for cleanup costs could have a naterial impact on our results of a reporting period.
f 3
D I
i I
44 l

:e i
Note L. I.ong-Term Power contracts                                                                           ;
i
: 2. Long-Tezus contracts for' the Purchase of Electricity                                                   l We purchase electric power under several long-term contracts for which we pay                                f a share of the generating unit's capital and fixed operating costs through the                               (
contract expiration date. The total cost of these contracts is included in                                   :
purchased power expense in our consolidated income: statements. Information relating to these contracts as of December 31, 1994 is as follows:                                           l proportionate share' (in thousands)                    !
Units of             1994 1994 Interest                            Debt Contract    Capacity         Minimum          Portion.of             Outstanding Expiration    Purchased '*8        Debt              Minimum Through Cont.
Generating Unit           Date   %         MW Service            Debt Service                  E3p. Date Canal Unit 1             2001   25.0      140 $          796             $     321               $ 1,928 Mass. Bay Trans-portation Authority               2005 100.0        34            (b)                   D)                    .( b)
Connecticut Yankee Atomic                  2007    9.5       55       2,607                  1,695                  14,678 Ocean State Power -
Unit 1                 2010   23.5     67.5       5,072                  3,653-                 21,563 Ocean State Power -
Unit 2                 2011   23.5     67.5        4,266                 3,223                  18,316 Northeast Energy                                                                                           '[
7msociates               (c)     (c)    219             (c)                  (c)                   -(c)    :
L'Energia                2013   73.0       64             (d)                  (d)                    (d)    ,
MassPower (e)            2013   44.3      117      12,642                  8,088                  86,538 Total                               764 $25.383                    $16.980                $143.023     ,
(a) The Northeast Energy Associates contract represents 6.4% of our total system generation capability. The remaining units listed above represent                              :
15.9% in total.
(b) We are required to pay the greater of $22.00 per kilowatt-year or 90% of the New England Power Pool capability responsibility adjustment charge up                             '
to $63.00 per kilowatt-year times the qualified capacity (currently rated at 34MW) plus incremental operating, maintenance and fuel costs. The total charges for this contract in 1994 were approximately $2 million.
(c) We purchase approximately 75.5% of the energy output of this unit'under two contracts. One contract represents 135MW and expires in the year                                 '
2015. The other contract is for 84MW r.nd expires in 2010. We pay for this energy based on a price per kWh actually receive.. We do not pay a                              j proportionate share of the unit's capital and fixed operating costs. The total charges for these contracts in 1994 were approximately $119                                    '
million.
(d) We pay for this energy based on a price per kWh actually received. The total charges under this contract for 1994 were approximately $31                                    I million.
i s
e 45                                                              ;

(e) The MassPower contract started in January 1994. Payments are based on a stipulated price per HW rating of the unit subject to the unit maintaining a twelve month average availability of at least 90%.
Payments are adjusted proportionately if the twelve month average is below 90%. If the twelve month average is less than 10% no payment is required. Total charges for this contract in 1994 were approximately $47 ndllion.
Our total fixed and variable costs for these contracts in 1994, 1993 and 1992 were approximately $286 million, $225 ndllion and $217 million, respectively.
Our minimum fixed payments under these contracts for the years after 1994 are as follows:
(in thousands) 1995                                           $ 105,574 1996                                               108,187 1997                                               105,622 1998                                               109,837 1999                                               108,196 Years thereafter                                 1,318,000 Total                                    $1,855,424 Total present value                            S 928,594
: 2. Long-Texxn Power Sales In addition to our power sales to five wholesale customers, we sell a percentage of Pilgrim Station's output to other utilities under long-term contracts. Information relating to these contracts is as follows:
Contract Expiration          Units of Capacity Sold Contract Customer                            Date           %                  MW Commonwealth Electric Company                2012          11.0              73.7 Montaup Electric Company                     2012          11.0              73.7 various municipalities                       2000(a)        3.7              25.0 Total                                                25.7             172.4 (a)  Subject to certain adjustments.
Under these contracts, the utilities pay their proportional share of the costs of operating Pilgrim Station and associated transmission facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decommissioning and a return on capital.
l 46                                            l

V
   .c.
Selected Consolidated Quarterly Financial Data (Unaudited)                          f i
(in thousands, except earnings per share)
Balance Available       Earnings Operating     Operating         Net for Common     Per Average Revenues        Income      Income       Stock   Common Share    j 1994                                                                                !
First quarter      $377,449       $45,795     $19,812     $15,850          $0.35    ,
second quarter       368,655       50,395      23,982      20,031           0.44    ;
Third quarter        449,094       96,599      70,182      66,256-          1.46 Fourth quarter       353,356       34,034      11,046       7,120           0.16  .
1993 First quarter      $354,752       $41,722     $15,452     $11,377          $0.25 Second quarter       346,074       49,282      22,829      19,125           0.43-Third quarter        436,024       96,319      70,015      66,053           1.47    s Fourth quarter       345,403       37,996       9,922       5,958           0.13
* Item 9. Changes in and    Disagreements with Accountants on Accounting and          '
Financial Disclosure Not applicable.
i 47 I

e Part III Item 10. Directors and Executive Officers of the Registrant (a)     Identification of Directors See " Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 27, 1995, 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.
Information regarding delinquent filers pursuant to Item 405 of Regulation S-K is included under " Stock ownership by Directors and Executive Officers" on pages 4 through 5 of the definitive proxy statement dated March 27, 1995, incorporated herein by reference.
(c)   Identification of Certain Significant Employees Not applicable.
(d)   Family Relationships Not applicable.
(e)   Business Experience For information relating to the business experience during the past five years and other directorships (of companies subject to certain SEC requirements) held by each person nominated to be a director, see " Election of Directors -
Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 27, 1995, incorporated herein by reference.
For information relating to the business experience during the past five years of each person who is an executive officer, see Executive Officers of the Registrant in this Form 10-K.
(f)  Involvement in certain Legal Proceedings Not applicable.
(g)  Promoters and Control Persons Not applicable.
Item 11. Executive Compensation See " Director and Executive Compensation" on pages 5 through 11 of the definitive proxy statement dated March 27, 1995, incorporated herein by reference.
1 48 l
1

Item 12. Security ownarship of Certain Beneficial owners and Management (a)  Security ownership of certain Beneficial owners To the knowledge of management, no persan owns beneficially more than five percent of the outstanding voting secu :ities of the company.
(b)  Security Ownership of Management See " Stock ownership by Directors and Executive Officers" on pages 4 through 5 of the definitive proxy statement dated March 27, 1995,= incorporated herein by reference.
(c)  Changes in Control Not applicable.
Item 13. Certain Relationships and Related Transactions Not applicable.
i l
l 49

Part IV Item 14. Exhibits, Financial Statement Schedules and Reports 00 Form 8-K (a) Exhibits and Consolidated Financial Statement Schedules              Page Consolidated Statements of Income for the three years ended December 31, 1994, 1993 and 1992                                         27 Consolidated Statements of Retained Earnings for the three years ended December 31, 1994, 1993 and 1992                             27 Consolidated Balance Sheets as of December 31, 1994 and 1993             28 Consolidated Statements of Cash Flows for the three years ended December 31, 1994, 1993 and 1992                                   29 Notes to Consolidated Financial Statements                               30 Selected Consolidated Quarterly Financial Data (Unaudited)               47 Report of Independent Accountants                                        61 Financial statement scheduler. have been omitted as they are either not required or not applicable.
50

0     .
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   Votes of the Pricing Committee of the        4.1  1-2301 Board of Directors of Boston Edison              Form 10-Q Company taken December 11, 1990 re               for the 8 7/8% debentures due December 15, 1995          quarter ended Mareh 31, 1991 4.1.3   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 51

Exhibit SEC Docket 4.1.4   Votes of the Pricing Committee of the     4.1.27  1-2301 Board of Directors of Boston Edison               Form 10-K Company taken August 5, 1991 re                    for the 9 3/8% debentures due August 15, 2021             year ended December 31, 1991 4.1.5   Revolving Credit Agreement dated          4.1.24   1-2301 February 12, 1993                                  Form 10-K for the year ended December 31, 1992 4.1.6   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 4.1.7   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 4.1.8   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                                   ;
4.1.9    Votes of the Pricing Committee of the     4.1.28  1-2301              l Board of Directors of Boston Edison               Form 10-K Company taken August 18, 1993 re                  for the             j 6.05% debentures due August 15, 2000              year ended          ;
December 31,        I 1993 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, ex eed 10% of the Company's total assets.
I 1
l 1
52                                            I l

Exhibit .SEC Docket            i Exhibit 10    Material Contracts Incorporated herein by reference:
10.1   Key Executive Benefit Plan                                10.13 1-2301 (1982 Form of Agreement)                                           Fo rm ' 10-K    ;
for the .
year ended      ;
December 31,    ,
1992            i 10.1.1    Amendment to Key Executive Benefit                       10.4.1    1-2301 Plan dated February 1, 1986                                        Form 10-K for the year ended December 31, 1985 l
10.1.2    Key Executive Benefit Plan                                 10.1 1-2301 Standard Form of Agreement, May                                    Form 10-Q 1986                                                              for the quarter ended June 30, 1986   l t
10.1.3    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,    j 1991 i
10.2  Executive Annual Incentive                                10.5 1-2301             i Compensation Plan                                                  Foam 10-K      l for the year ended December 31,    a 1988 I
10.3  1991 Director Stock Plan                                   10.1 1-2301 Form 10-Q for the        .
quarter ended March 31, 1991 53

Exhibit -SEC Docket 10.4    Boston Edison Company Deferred            10.11 1-2301 Fee Plan dated January 1, 1990                    Form 10-K for the year ended December 31, 1992 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 10.6   Directors Retirement Benefit             10.8.1    1-2301 (1993 Plan)                                       Form 10-K for the year ended         t December 31, 1993 Filed herewith:
10.5.1    Amendment No. I to Deferred Compensation Trust dated March 31, 1994 10.7    Description of Supplemental Fee Arrangement for Certain Directors 10.8    Performance Share Plan, Amendment and Restatement dated October 24, 1994 10.9    Boston Edison Company Deferred Compensation Plan, Amendment and Restatement dated January 31, 1995 10.10    Employment Agreement applicable to Ronald A. Ledgett dated April 30, 1987 54

i Exhibit SEC Docket         I i
10.11     Description of. compensation                                           :
I Arrangement with Bernard W.
Reznicek dated June 23, 1994
                     - Exhibit 12    - Statement re Computation of Ratios Filed herewith:
12.1     Computation of Ratio of Earnings to Fixed Charges for the Year                                        -l~
Ended December 31, 1994 12.2     Computation of Ratio of Earnings                                       ;
to Fixed Charges and Preferred Stock                                   ,
Dividend Requirements for the Year Ended December 31, 1994                                               <
Exhibit 18      Letter re Change in Accounting Principle Incorporated herein by reference:
18.1     Letter of Independent Certified                18.1 1-2301 Public Accountants                                    Form 10-Q        l for the quarter ended March 31, 1990  ;
Exhibit 21      Subsidiaries of tha Registrant 21.1     Harbor Electric Energy Company                                         !
(incorporated in Massachusetts),                                      j 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                                                         l i
21.3     Ener-G-Vision, Inc. (incorporated                                     !
in Massachusetts), a wl.olly-owned subsidiary of Boston Energy                                            j Technology Group, Inc.                                                ;
l 21.4     TravElectric Services Corporation                                      ;
(incorporated in Massachusetts),                                      j a wholly-owned subsidiary of Boston                                     i Energy Technology Group, Inc.
                                                                                                             ]
                                                                                                             ]
55                                         {
l 4
t                              en     m . ,     ,..  - , . _ _           . , ,

Exhibit SEC Docket 21.5    REZ-TEK International Corporation (incorporated in Massachusetts),
a umjority-owned subsidiary of Boston Energy Technology Group, Inc.
21 6     Coneco Corporation (incorporated in Massachusetts), a majority-owned subsidiary of Boston Energy Technology Group, Inc.
Exhibit 23       Consent of Independent Accountants Filed herewith:
23.1     Consent of Independent Accountants to incorporate by reference their opinion included with this Form 10-K in the Form S-3 Registration Statements filed by the Company on September 14, 1990 (File No.
33-36824), February 3, 1993 (File No. 33-57840) and in the Form S-8 Registration Statements filed by the Company on October 10, 1985 (File No. 33-00810), July 28, 1986 (File No. 33-7558), December 31, 1990 (File No. 33-38434), June 5, 1992 (33-48424 and 33-48425) and March 17, 1993 (33-59662 and
                  .33-59682).
Exhibit 27      Financial Data Schedule Filed herewith:
27.1     Schedule UT Exhibit 99     Additional Exhibiq3 Incorporated herein by reference:
99.1     DPU Settlement Agreement with              28.1 1-2301 Boston Edison Company dated                      Form 8-K october 3, 1989                                   dated October 3, 1989 56                                                  ;
i

yu 4
Exhibit SEC Docket       i i
99.2 Settlement Agreement between Boston       28.1 1-2301 Edison Company and Conunonwealth                Form 8-K        ,
Electric Company, Montaup Electric              dated.
Company and the Municipal                       December 21, Light Department of the Town of                 1989            ,
Reading, Massachusetts, dated                                   j January 5, 1990 99.3 Pilgrim Outage Case Settlement between    28.2 1-2301           ,
Boston Edison Company and Reading               Form 8-K Municipal Light Department regarding            dated Contract Demand Rate, dated December.           December 21,    t 21, 1989                                        1989 99.4 Settlement Agreement Between Boston       28.2 1-2301
'.              Edison Company and City of Holyoke              Form 10-Q       l Gas and Electric Department et. al.,            for the         e dated April 26, 1990                            quarter ended March 31, 1990  ,
i 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               Amendment to December 31, 1993, 1992 and 1991                Form 10-K for the year ended  ;
December 31, 1993 and Form 8 Amendments to Form 10-K for the years ended l December 31, 1992 and 1991, dated June 30, 1994, June 29,  i 1993 and       '
June 26, 1992, respectively.
i 99.6 DPU Settlement Agreement with             28.2 1-2301           !
Boston Edison Company, dated                     Form 10-Q October 23,'1992                                 for the quarter ended September 30, 1992 1
57

o (b) Reports on Form B-K There were no Form 8-K's filed during the fourth quarter of 1994.
58

1 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 i
By: L/s/ Charles E. Peters, Jr.
Charles E. Peters, Jr.
Senior Vice President L- Finance (Principal Financial Of ficer) i i
Date: March 23, 1995 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             ,
i registrant and in the capacities indicated on the 23rd day of March 1995. .
                    /s/ Thomas J. May                                  Chairman of the Board and Chief Thomas J. May                              Executive Officer               ,
                    /s/ George W. Davis                                President.and Chief Operating   l George W. Davis                            Officer and Director            t
                    /s/ Robert J. Weafer, Jr.                          Vice President, Controller and Robert J. Weafer, Jr.                      Chief Accounting Officer e
                    /s/ William F. Connell                             Director William F. Connell                                                         ,
                    /s/ Gary L. Ceuntryman                             Director                        j Gary L. Countryman                                                         l Director Thomas G. Dignan, Jr.
Director                       !
Charles K. Gifford                                                         (
                     /s/ Nelson S. Gifford                           Director Nelson S. Gifford e
59

7_ .
       /s/ Kenneth I. Guscott      Director Kenneth I. Guscott
       /s/ Matina S. Horner        Director Matina S. Horner
       /s/ Sherry H. Penney        Director Sherry h. Penney
       /s/ Bernard W. Reznicek    Director Bernard W. Reznicek
       /s/ Herbert Roth, Jr.       Director Herbert Roth, Jr.
Director Stephen J. Sweeney Director Paul E. Tsongas I
60

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 ndsstatement. 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, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts January 26, 1995 61}}