Annual Report (Form 10-K), fiscal year 1993

Item 1. Business - -----------------
(a) General Development of Business - -----------------------------------
Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law. The Company operates in the energy and energy services business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of demand side management (DSM) programs.
In 1993 the Company established an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from the Massachusetts Department of Public Utilities (DPU). The Company was granted authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management, electric transportation and electric generation and distribution activities through its wholly-owned subsidiaries Ener-G-Vision, Inc. and TravElectric Services Corporation. In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc. The new entity, REZ-TEK International Corporation, will continue the business of manufacturing ozone water treatment systems. The Company does not currently have a substantial investment in BETG and does not expect the subsidiary to significantly impact the results of operations in the next several years.
(b) Financial Information about Industry Segments - -------------------------------------------------
The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable.
(c) Narrative Description of Business - -------------------------------------
Principal Products and Services
The Company supplies electricity at retail to an area of approximately 590 square miles encompassing the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 1993 the Company served an average of approximately 651,000 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments. Revenues by class for the last three years are as follows:
Sources and Availability of Fuel
The majority of the Company's residual oil purchases consists of imported oil acquired primarily from international suppliers. The Company has contracts with major oil companies that can supply most of its estimated requirements, assuming no major disruptions in oil producing regions. Within contract provisions, the Company has the ability to purchase significant amounts of oil in the spot market when it is economical to do so.
Most of the Company's natural gas is supplied on an interruptible basis whereby a contract permits interruptions in deliveries by the supplier when natural gas pipeline capacity is unavailable. Deliveries of natural gas to the Company's generating units from suppliers may also be dependent on the availability of pipeline capacity to the New England region and competitive forces prevailing in the pipeline industry. Beginning in April 1995 the Company will be required to operate New Boston Station using exclusively natural gas as fuel, except in certain emergency circumstances, as part of a 1991 consent order from the Massachusetts Department of Environmental Protection (DEP). The Company has arrangements for a nine month supply of natural gas to the station until April 1995 and is currently in the process of negotiating with suppliers and transporters concerning the economics and availability of natural gas to the station on a year-round basis after that time. Year-round gas supplies are currently not available to the station and, as a result, the outcome of the Company's negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain.
In order to obtain nuclear fuel for use at Pilgrim Station the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication that will individually allow operation of Pilgrim Station through 1998, 2000, 2001 and 2012, respectively.
Franchises
Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for the Company's electric transmission and distribution lines are obtained from
municipal and other state authorities, which in granting these locations act as agents for the state. In some cases the action of these authorities is subject to appeal to the DPU. The locations are unlimited in time, but their rights are not vested and are subject to the action of these authorities and the legislature.
Seasonal Nature of Business
The Company's kWh sales and revenues have historically been less in the spring and fall than during winter and summer as sales tend to vary with weather conditions. In addition, the Company bills higher base rates to commercial and industrial customers during the billing months of June through September as mandated by the DPU. Accordingly, a significant portion of annual earnings occurs in the Company's third quarter. See Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8.
Working Capital Practices
The Company has no special practices with respect to working capital that would be considered unusual for the electric utility industry or significant for the understanding of the Company's business.
Customer Dependence
No material portion of the Company's business is dependent upon one or a few customers.
Government Contracts
No material portion of the Company's business is subject to renegotiation or termination of government contracts or subcontracts.
Competitive Conditions
The Company is experiencing a substantial increase in competition from other electric utilities and non-utility generators to sell electricity for resale. In response to the current environment the Company has secured long-term power supply agreements with its four current wholesale customers which set rates principally through the year 2002. The Company also obtained a new wholesale customer for which it will provide up to 30 megawatts (MW) of contract demand power for ten years beginning November 1994.
The DPU has created an integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs with all other supplies of energy. The Company submitted a draft IRM filing in March 1994 that covers the period 1994 through 2004. In this filing the Company concluded that adequate resources exist to meet customer needs for continued reliable, low cost power through the period without procurement of any new generation resources. The IRM process requires a settlement period in which intervenors and other interested parties have the opportunity to review, comment and request information on the draft filing. Any settlements reached will be reflected in the Company's final IRM filing to be submitted in July 1994. Any remaining issues will be litigated at the DPU through formal proceedings.
Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. The Company and other Massachusetts electric utilities are protected in several ways by the DPU and municipal statutes against other utilities offering service to retail customers in their service areas. Another electric utility may not extend its service area to include municipalities other than those named in its agreement of association or charter without DPU authorization granted after notice and public hearing. Also, another company may not obtain an initial location for its lines in a municipality served by the Company without the approval of municipal authorities, subject to the right of appeal to the DPU. Additionally, a municipality may not engage in the electric utility business without complying with statutes requiring specific city or town approval and the purchase of Company property within municipality limits.
However, the Company is currently experiencing some forms of competition in the retail electric market. Current legislation allows industrial and large commercial customers to own and operate their own electric generating units. Retail customers may also substitute natural gas or oil for electricity as fuel for heating and cooling purposes. The Company is responding to the current and anticipated competitive pressures with a commitment to cost control and increased operating efficiencies without sacrificing quality of service or profitability.
Research Activities
The Company actively participates in several industry-sponsored research activities. These expenditures, included in other operations and maintenance expense on the consolidated income statements in Item 8, were not material in 1993.
Environmental Matters
The Company is subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require modification of existing facilities or curtailment or termination of operations at facilities, delay construction of new facilities or increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties. The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements.
The Company's capital expenditures for environmental purposes during the five years 1989 through 1993 were approximately $125 million. Environmental-related capital expenditures for the years 1994 through 1998 are currently expected to approximate $43 million, including $17 million in 1994 and $9 million in 1995. These amounts exclude costs associated with asbestos removal which were approximately $11 million during the five years 1989 through 1993 and are currently expected to be approximately $10 million for the years 1994 through 1998. The 1994 expected capital expenditures for environmental purposes include costs to complete modifications at New Boston Station in order to improve air quality and reduce emissions of nitrogen oxides, as discussed in the Environmental section of Other Matters in Item 7, and to install air monitoring systems at other Company generating units.
Substantial additional expenditures could be required as changes in environmental requirements occur.
The Company is subject to regulation by the United States Environmental Protection Agency (EPA) and the Massachusetts Department of Environmental Protection (DEP) with respect to discharges of effluent from the Company's generating stations into receiving waters. The Federal Clean Water Act and the Massachusetts Clean Waters Act require the Company to receive permits that limit discharges in accordance with applicable water quality standards and are subject to renewal every five years. The Company has received discharge permits as required by the EPA and the DEP for each of its electric generating stations.
The Company is also subject to EPA and DEP regulation relative to emissions from its fossil-fired generating units pursuant to Federal and Massachusetts clean air laws, including the 1990 Clean Air Act Amendments. These regulations require the installation of various emissions controls and the use of low sulfur content fuels in certain cases. The Company's current status regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments is discussed in the Environmental section in Item 7.
The Company is subject to various federal, state and local laws and regulations pertaining to the generation, treatment, transportation, storage and disposal of certain hazardous substances and to the cleanup of locations where such substances have either been disposed of or spilled. One of the requirements of these laws and regulations is that certain facilities which treat, store or dispose of hazardous wastes must be licensed. The only facility owned by the Company which requires such a license is Pilgrim Station. Currently Pilgrim Station has received interim status approval for the treatment and storage of certain wastes that are both hazardous and radioactive.
The Company has exposure to potential joint and several liability for the cleanup of sites where hazardous wastes may have been spilled or disposed of in the past. The Company has been notified of such potential liability for approximately twelve sites, most of which involve numerous parties. Complex litigation or negotiations among the parties and with regulatory authorities is in process concerning the scope and cost of cleanup and the sharing of costs among the potentially responsible parties for several of these sites. The Company also faces additional exposure for the cleanup of Company-owned or operated sites due to state regulations revised in 1993. The potential hazardous waste liabilities are further described in the Environmental section of Item 7.
The Company currently disposes of low-level radioactive waste (LLW) generated at Pilgrim Station through arrangements with licensed disposal facilities located in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, the Company's continued access to such disposal facilities has become severely limited and significantly increased in cost. See Note D to the consolidated financial statements in Item 8 for further discussion regarding LLW disposal.
The Company's existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. A request for a license amendment to allow modification of the storage facility
to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012 is pending before the Nuclear Regulatory Commission (NRC). The Company expects approval of the request in 1994. At that time the Company will initially modify the facility to provide spent fuel storage capacity through approximately 2003. In addition, the United States Department of Energy (DOE), which is ultimately responsible for the disposal of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982, is currently conducting scientific studies evaluating a potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The potential site, however, has encountered substantial public and political opposition and litigation and the DOE has publicly stated that it may be unable to construct such a repository in a timely manner. The Company is unable to predict whether and on what schedule the DOE will eventually construct a repository and what the effect will be on the Company.
Published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. This topic is discussed more fully in the Environmental section of Item 7.
Number of Employees
The Company had 4,404 full-time and 14 part-time employees as of the end of 1993, 2,775 of which are represented by two locals of the Utility Workers Union of America, AFL-CIO. The current four-year labor contract in effect with the locals is scheduled to expire in May 1994. Labor contract negotiations began in early February 1994 and the Company anticipates favorable resolution of these negotiations.
(d) Financial Information about Foreign and Domestic Operations - --------------------------------------------------------------- and Export Sales - ----------------
See Principal Products and Services for information regarding the geographical area served by the Company and revenues by class for the last three years.
(e) Additional Information - --------------------------
Regulation
The Company and its wholly-owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the DPU, whose jurisdiction includes supervision over retail rates for electricity, financing, investing and accounting. In addition, the Federal Energy Regulatory Commission (FERC) has jurisdiction over various phases of the Company's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of such power, certain issuances of short-term debt and regulation of the system of accounts. The Company's subsidiary BETG and its subsidiaries are not subject to such regulation.
Recent requirements imposed on the Company by the DPU are discussed under Competitive Conditions of this item and Non-Utility Generator Purchase Contracts in Item 2.



Item 2. Properties and Power Supply - ------------------------------------
Company-Owned Facilities
The Company's total installed electric generation capacity as of December 31, 1993 is as follows:
All of the Company's steam fossil fuel-fired electric generating units are located at tide water and have access to fuel oil storage and/or natural gas or oil pipelines from nearby suppliers.
The Company is also a 5.888% joint owner in W.F. Wyman Unit 4. The 619 MW oil-fired unit located in Yarmouth, Maine began operations in 1978 and is operated by Central Maine Power Company.
Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and non-utilities and its participation in the New England Power Pool as further described in this item.
As of December 31, 1993 the Company's transmission system was comprised of approximately 362 miles of overhead circuits operating at 115,000, 230,000 and 345,000 volts and approximately 155 miles of underground circuits operating at 115,000 and 345,000 volts. The substations supported by these lines consist of 42 transmission or combined transmission and distribution substations with transformer capacity of 10,025 megavolt amperes (MVA), 71 distribution substations with transformer capacity of 1,238 MVA and 18 primary network units with 88 MVA capacity. In addition, high tension service was delivered to 231 customers' substations. The overhead distribution system covers approximately 4,652 miles of streets and the underground distribution system extends through approximately 892 miles of streets. HEEC, the Company's regulated subsidiary, has a distribution system that consists
principally of a 4.09 mile 115Kv submarine distribution line and a temporary substation which is located on Deer Island in Boston, Massachusetts.
The Company's significant items of property consist of electric generating stations, substations and certain service centers and are generally located on Company-owned land, with certain exceptions as set forth in the Company's First Mortgage Bond Indenture and its supplements. The Company's high-tension transmission lines are generally located on land either owned by the Company or subject to easements in its favor. The Company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by local or state authorities.
The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company plans for the construction of certain new generation or transmission facilities based upon findings that such facilities are consistent with state public health, environmental protection and resource use and development policies. The Company currently has no proceedings before the EFSB.
Long-Term Power Contracts
Refer to Note K to the consolidated financial statements in Item 8 for further information regarding the following contracts. The Company also has short-term agreements with several other utilities for varying periods for purchases of system and unit power, for sales of Company system and unit power and for transmission services.
Utility Purchase Contracts: - ---------------------------
The Company has a contract with a subsidiary of Commonwealth Energy System and two other utilities in which the participants are sharing in equal amounts the output of an oil-fired electric generation plant. The Company is obligated to pay 25% of the unit's fixed and operating costs plus an annual return over a period of approximately 33 years for its proportionate share of generation.
The Company has two long-term purchased power contracts with the Massachusetts Bay Transit Authority (MBTA) for the availability of two of the MBTA's jet turbines. The MBTA retains the right to utilize the jets for its own emergency use and for testing purposes but the Company retains New England Power Pool credit for their capacity and output.
The Company owns 9.5% of the common stock of Connecticut Yankee Atomic Power Company, which operates a nuclear generating unit. The Company is entitled to receive 9.5% of the unit's output and is obligated to pay Connecticut Yankee 9.5% of its fixed and operating costs plus an annual return on investment.
Non-Utility Generator Purchase Contracts: - -----------------------------------------
The Company currently purchases approximately 500 MW of capacity and associated energy from non-utility generators. A majority of these purchases are from Ocean State Power and Northeast Energy Associates. In 1993 the L'Energia facility located in Lowell, Massachusetts was declared commercial and the Company began purchasing electricity from this unit under a twenty-year agreement. In addition, the Company is purchasing power from two
small hydro facilities, and began purchasing capacity and energy from the MassPower facility located in Springfield, Massachusetts in January 1994.
In June 1993 the DPU ordered the Company to purchase 132 MW of power from Altresco Lynn, LP, an independent power producer, starting as early as 1995. The Company opposes this order since it does not believe it needs any new power for several years. In July 1993 the Company asked the Massachusetts Supreme Judicial Court to reverse the order. The Court has not yet ruled on the Company's request. The Company has supported an appeal filed by other interested parties of the Energy Facilities Siting Board's conditional approval of Altresco Lynn's project. In February 1994 Altresco Lynn alleged that the Company's actions in opposing the project were improper and that it may seek to hold the Company responsible for any resulting damages.
Sales Contracts: - ----------------
The Company has agreements with Montaup Electric Company, a subsidiary of Eastern Utilities Associates, and with Commonwealth Electric Company, a subsidiary of Commonwealth Energy System, under which Montaup and Commonwealth each purchase 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's fixed and operating costs plus an annual return. Montaup and Commonwealth have also agreed to indemnify the Company to the extent of 11% each of all loss, liability or damage not covered by insurance resulting from the operation, condemnation, shutdown or retirement of the unit. In addition, the Company has similar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station.
New England Power Pool
The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To assume maximum benefits of power pooling, the electric facilities of all member companies are operated by NEPOOL as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest cost generating and transmission equipment available at any given time. This operation is the responsibility of NEPOOL's central dispatch center, the New England Power Exchange (NEPEX). As a result of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of the other members.
The Company's net capacity was 3,663 MW at its summer peak and 3,533 MW at is winter peak. Its corresponding NEPOOL capacity obligations were estimated to be 3,190 MW and 3,289 MW, respectively.
In 1983 the NEPOOL participants signed an agreement, known as Phase I, with Hydro-Quebec of Canada to provide up to three million MWH of hydro-electric power annually to NEPOOL from 1986-1997. In 1985 a second agreement, known as Phase II, was made between NEPOOL and Hydro-Quebec to provide an additional seven million MWH of hydro-electric power annually for ten years. This agreement required expansion of the existing 690 MW Phase I interconnection. The Company and other New England electric utilities entered into an agreement to expand the interconnection with the Hydro-Quebec system of Canada to 2,000 MW.
The Phase II facilities began full commercial operation up to the 2,000 MW level in July 1991. The price of this energy is based on the average cost of fossil fuel in New England for the previous year. The contract price for the first five years is 80% of that average, and for the second five years will be 95% of that average. The Company receives capacity credit through NEPOOL for approximately 11% of the generation equivalent of the total Hydro-Quebec interconnection.
The Company has an approximately 11% equity ownership interest in the two companies which constructed the Phase II facilities. All equity participants are required to guarantee, in addition to their own share, the total obligations of those participants not meeting certain credit criteria. Amounts so guaranteed by the Company were approximately $22 million at December 31, 1993.
As a result of the continuing additions to New England generating capacity and minimally increasing energy requirements, the dispatching of Company-owned generating facilities by NEPEX may be affected.
Item 3.

Item 3. Legal Proceedings - --------------------------
In March 1991 the Company was named in a lawsuit brought in the United States District Court for the District of Massachusetts alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by the Company's 1988 reduction in force. Legal counsel is vigorously defending this case. Based on the information presently available, the Company does not expect that this litigation will have a material impact on the Company's financial condition. However, an unfavorable decision ordered against the Company could have a material impact on quarterly earnings.
See also Item 1, Environmental Matters and Note H to the consolidated financial statements in Item 8 for a discussion of legal issues involving hazardous waste sites.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------
There were no matters submitted to a vote of security holders during the fourth quarter of 1993.
Executive Officers of the Registrant - ------------------------------------
The names, ages, positions and business experience during the last five years of all the executive officers of Boston Edison Company and its subsidiaries as of March 1, 1994 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding between any Company officer and another person pursuant to which the officer was elected. Officers of the Company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until their respective successors are chosen and qualified.
Part II
Item 5.

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.
(b) Holders - -----------
As of December 31, 1993, the Company had 42,392 holders of record of its common stock (actual count of record holders).
(c) Dividends - -------------
Item 6.

Item 6. Selected Financial Data - --------------------------------
Item 7.

Item 7. Management's Discussion and Analysis - ---------------------------------------------
REGULATORY PROCEEDINGS
Retail settlement agreements
Effective November 1992 our state regulators, the Massachusetts Department of Public Utilities, approved a three-year settlement agreement. This agreement provides us with retail rate increases, allows for the recovery of demand side management (DSM) conservation program expenditures, specifies certain accounting adjustments and clarifies the timing and recognition of certain expenses. The agreement also sets a limit on our rate of return on common equity of 11.75% for 1993 through 1995, excluding any penalties or rewards from performance incentives.
The retail rate increases consist of a new annual performance adjustment charge effective November 1992 and two additional rate increases of $29 million effective November 1993 and November 1994. The performance adjustment charge varies annually based upon the performance of our Pilgrim Nuclear Power Station. This charge is further described in our discussion of financial condition.
Our 1993 results of operations were affected by the recovery of DSM program expenditures, accounting adjustments and timing and recognition of certain expenses as further described in the following Results of Operations section.
Our state regulators approved a previous three-year settlement agreement effective November 1989. That agreement also provided us with retail rate increases and specified certain accounting adjustments. The 1989 agreement primarily affected our results of operations through 1992.
RESULTS OF OPERATIONS
1993 VERSUS 1992
Earnings per common share were $2.28 in 1993 and $2.10 in 1992. The increase in earnings is primarily the result of an annual rate increase effective November 1992, lower purchased power expense due to a long-term contract expiration, no amortization of deferred cancelled nuclear unit costs and lower interest expense. These positive changes were partially offset by higher operations and maintenance expense and higher income tax and property tax expenses.
Operating revenues
Retail electric revenues increased $70.8 million. The November 1992 and 1993 rate increases resulted in $40.6 million of additional revenues in 1993. Fuel and purchased power revenues increased $29.5 million over 1992, partly due to lower revenues received from short-term power sales as discussed below.
We began recovery of certain demand side management program costs, lost base revenues and incentives in August 1992. Our 1993 revenues provided $45.9 million related to 1991, 1992 and 1993 DSM programs. Our 1992 revenues of $12.3 million related primarily to 1991 programs.
The decrease in wholesale and other revenues reflects an estimated provision for refunds to customers of approximately $8 million as a result of orders from our state regulators on our generating unit performance program.
Lower short-term power sales revenues were a result of changes in our generation availability and the needs of short-term power purchasers. All revenues from short-term sales serve to reduce fuel and purchased power billings to retail customers and have no effect on earnings.
Operating expenses
Fuel expense decreased $19.5 million primarily due to a 21.5% decrease in generation, resulting from planned overhauls of our fossil plants. Interchange purchases increased due to the lower generation, resulting in a $7.5 million net increase in purchased power expense. The net increase also reflects savings of approximately $10 million from a long-term purchased power contract that expired in October 1993. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues.
Other operations and maintenance expense increased 7.1% primarily due to increases in employee benefits and nuclear production expenses. Postretirement benefits expense increased by $7 million primarily as a result of the adoption of a new accounting standard and pension expense increased by $5 million; both are provided for in our 1992 settlement agreement and further explained in Note I to the consolidated financial statements. A refueling outage at Pilgrim Station in 1993 resulted in higher nuclear production expenses.
Depreciation and amortization expense increased in 1993 primarily due to a higher annual decommissioning charge for Pilgrim Station effective November 1992 provided by the 1992 settlement agreement. The new charge is based on a 1991 estimate of decommissioning costs as further discussed in Note D to the consolidated financial statements. In addition, the effect of lower depreciation rates implemented in accordance with the settlement agreement was offset by the effect of a higher depreciable plant balance.
In accordance with our 1992 settlement agreement we did not expense any of the $19 million of remaining deferred costs associated with the cancelled Pilgrim 2 nuclear unit in 1993. We will expense the remaining costs in 1994 and/or 1995.
Amortization of deferred nuclear outage costs includes amounts related to the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we deferred approximately $14 million of refueling outage costs. We began to amortize
these costs in June 1993 over five years are approved in the 1992 settlement agreement.
The increase in demand side management programs expense is consistent with the increase in DSM revenues. DSM expense includes some costs recovered over a twelve month period and other costs recovered over six years. We began to recover previously deferred DSM expenses in August 1992. In 1993 we expensed and collected from customers approximately $30 million of deferred 1991, 1992 and 1993 program costs. Over six years we are expensing and collecting from our customers $11 million of costs capitalized in 1992 and $37 million of costs capitalized in 1993. The 1993 expense related to these capitalized costs was $7 million.
Municipal property and other taxes increased in 1993 due to the absence of tax abatements. In 1992 property taxes were reduced by $10.4 million of tax abatements in accordance with our 1989 settlement agreement.
Our effective annual income tax rate for 1993 was 23.4% vs. 8.7% for 1992. Both rates were significantly reduced by adjustments to deferred income taxes of $20 million in 1993 and $23 million in 1992 made in accordance with the 1992 and 1989 settlement agreements. The 1992 rate was also reduced due to tax benefits of approximately $7 million resulting from mandated payments made in accordance with the 1989 agreement. Our adoption of a new accounting standard for income taxes in 1993 did not significantly affect earnings. We expect our effective tax rate to be close to the statutory rate in 1994.
Interest charges and preferred and preference dividends
Total interest charges decreased $3.8 million in 1993. Interest on long-term debt decreased primarily due to the refinancing of substantially all our first mortgage bonds in 1993 at lower interest rates, partially offset by higher amortization of redemption premiums. Other interest charges decreased due to a lower short-term debt level and lower short-term interest rates. Allowance for funds used during construction (AFUDC), which represents the financing costs of construction, decreased as a result of a lower AFUDC rate related to lower short-term interest rates.
Preferred and preference dividends decreased 5% due to the replacement of a preferred and a preference stock issue with less costly issues of preferred stock.
1992 VERSUS 1991
Earnings per common share were $2.10 in 1992 and $1.96 in 1991. The increase in earnings is primarily the result of a rate increase effective November 1991, incentive revenues earned from the performance of Pilgrim Station and lower income tax and interest expenses. These increases were partially offset by higher operations and maintenance and property tax expenses. We also had a one-time charge in 1992 for costs incurred for a deferred generating plant project.
Operating revenues
Retail electric revenues increased $27.7 million. We received a $25 million rate increase effective November 1991 as part of the 1989 settlement agreement. We also earned $8.2 million in incentive revenues in 1992 as a result of Pilgrim Station's capacity factor exceeding its target set in the agreement. Fuel and purchased power revenues decreased approximately $5 million due to higher purchased power costs more than offset by higher revenues received from short-term power sales as discussed below.
In 1992 we began to receive revenues for the recovery of certain DSM program costs, lost base revenues and incentives. The 1992 revenues relate primarily to 1991 DSM programs.
Our short-term power sales increased in 1992 as a result of our high generating unit availability and the greater power needs of other New England utilities. All revenues from short-term sales served to reduce fuel and purchased power billings to retail customers and had no effect on earnings.
Operating expenses
Purchased power expense increased $18 million in 1992 due to new long-term purchased power contracts. Both our fuel and purchased power expenses are substantially fully recoverable through fuel and purchased power revenues.
Other operations and maintenance expense increased 2.3% due primarily to increases in employee benefit expenses and bad debts.
Amortization of deferred nuclear outage costs in 1992 and 1991 includes amounts primarily related to the 1991 refueling outage at Pilgrim Station. In 1991 we deferred approximately $23 million of refueling outage costs. We began to expense these costs over five years in September 1991 as approved by our state regulators.
Municipal property and other taxes increased 21% primarily due to a reduction in residential and commercial real estate values caused by the depressed economy. This resulted in higher tax rates applied to our personal property values. In accordance with our 1989 settlement agreement, municipal property tax expenses were reduced by tax abatements of $10.4 million in 1992 and $13.6 million in 1991.
Our effective annual income tax rate for 1992 was 8.7% vs. 16.5% for 1991. Both rates were significantly reduced by adjustments to deferred income taxes of $23 million in 1992 and $13 million in 1991 made in accordance with the 1989 settlement agreement. We also received tax benefits in both years as a result of payments mandated by the agreement.
Other income and expense
In 1992 we expensed $8 million of costs previously invested in the proposed Edgar Energy Park generation project. This project was deferred indefinitely as additional generating capacity is not expected to be needed for several years.
Interest charges and preferred and preference dividends
Total interest charges decreased 4.6% primarily due to lower interest rates on our average short-term borrowings. AFUDC decreased 12.7% due to a lower AFUDC rate related to lower short-term interest rates.
Preferred and preference dividends decreased approximately $1 million primarily due to the replacement of two preference stock series with less costly issues of preferred stock.
Earnings per share
Net income increased 13%. However, earnings per common share for 1992 increased only 7%, reflecting an increase in the weighted average number of common shares outstanding primarily a result of our 1991 and 1992 common stock issuances.
FINANCIAL CONDITION
Our 1992 settlement agreement provides us with increased revenues from retail customers over the three-year period ending October 1995. Additionally, a long-term purchased power contract with annual charges of approximately $60 million expired in October 1993 with no related change in revenues. We are limited to an annual rate of return on equity during the three-year period of 11.75%, excluding any penalties or rewards from performance incentives.
Our continued ability to achieve or exceed the 11.75% rate of return on equity will be primarily dependent upon our ability to control costs and to earn performance incentives from generation performance mechanisms specified in both the 1989 and 1992 settlement agreements. The most significant impact that incentives can have on our financial results is based on Pilgrim Station's annual capacity factor. Effective November 1993 an annual capacity factor between 60% and 68% will provide us with approximately $45 million of revenues through the performance adjustment charge. For each percentage point increase in capacity factor above 68%, annual revenues will increase by $670,000. For each percentage point decrease in capacity factor below 60% (to a minimum of 35%) annual revenues will decrease by $770,000. Pilgrim's capacity factor for the performance year ending October 1994 is expected to be approximately 81% (assuming normal operating conditions), an increase over the 66% capacity factor achieved in the performance year ended October 1993, as no refueling outage is scheduled for 1994. We earned approximately $40 million in performance charge revenues in the performance year ended October 1993.
Our fossil generation unit performance can provide an increase or decrease of up to $4 million in revenues in each performance year, however, we do not expect any revenue adjustments from this mechanism.
LIQUIDITY
We meet our plant expenditure cash requirements primarily with internally generated funds. These funds (excluding payments made related to settlement agreements) provided for 74%, 90% and 89% of our plant expenditures in 1993, 1992 and 1991, respectively. Our current estimate of plant expenditures for 1994 is $233 million, including $20 million of nuclear fuel additions. These expenditures will be used primarily to maintain and improve existing transmission, distribution and generation facilities. We also estimate capitalizable DSM expenditures to be $38 million in 1994, which will be collected from customers over six years. We do not expect plant expenditures, excluding nuclear fuel and DSM, to vary significantly from the 1994 amount in the four years thereafter. We have long-term debt and preferred stock payment requirements of $2 million in 1994, $102.6 million in 1995, and $103.6 million per year in 1996 through 1998.
External financings continue to be necessary to supplement our internally generated funds, primarily the issuance of short-term commercial paper and bank borrowings. We currently have authority from our federal regulators to issue up to $350 million of short-term debt. We have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on a committed as well as on an uncommitted and as available basis. At December 31, 1993 we had $204.1 million of short-term debt outstanding, none of which was incurred under the revolving credit agreement. In 1993 our state regulators approved a financing plan allowing us to issue up to $1.1 billion in securities through 1994 and to use the proceeds to refinance long-term securities and short-term debt. At December 31, 1993 we had $245 million remaining authorized to be issued under the plan which can be used to issue common stock, preferred stock and long-term debt. As a result of our refinancing activities in 1993 we expect to realize annualized savings of approximately $11.5 million. Refer to Note F to the consolidated financial statements for specific information relating to our recent financing activities.
OUTLOOK FOR THE FUTURE
Electricity sales
A significant portion of our electricity sales are made to commercial customers rather than industrial customers. As a result our sales have been only moderately impacted by the decline in the local Massachusetts economy. Our retail sales increased 1.2% in 1993 and we anticipate only slight growth in retail sales in the near term.
Implementation of DSM programs, which are designed to assist customers in reducing electricity use, will result in lower growth in electricity sales. The 1992 settlement agreement established annual DSM spending levels over $50 million through 1994. The agreement provides for collection from customers of certain costs primarily in the year incurred and others over a six-year period. We are also provided with incentives and recovery of lost revenues based on the actual reduction in customer electricity usage from these programs and a return on the costs that we recover over six years.
Competition
As we are operating in a time of increasing competition from other electric utilities and non-utility generators to sell electricity for resale, we have secured long-term power supply agreements with our four wholesale customers. Through these
agreements our rates are set principally through the year 2002. We also obtained a new wholesale customer in 1993 for which we will provide up to 30 megawatts of contract demand power for ten years beginning November 1994.
Our state regulators require utilities to purchase power from qualifying non-utility generators at prices set through a bidding process. In June 1993 our state regulators ordered us to purchase 132 megawatts of power from an independent power producer, starting as early as 1995. We oppose this order since we do not believe we need any new power for several years. In July 1993 we asked the Massachusetts Supreme Judicial Court to reverse the order. We are currently awaiting a decision from the court. In addition, our state regulators have created an integrated resource management (IRM) process in which electric utilities forecast their future energy needs and propose how they will meet those needs by balancing conservation programs with all other supplies of energy. We will submit an IRM filing in March 1994.
Direct competition with other electric utilities for retail electricity sales is still subject to substantial limitations, but these limitations may be reduced in the future. In 1993 we announced our goal of not seeking additional rate increases, other than those provided in the 1992 settlement agreement, for our residential, commercial and industrial customers until at least the year 2000. We plan to accomplish this by controlling costs and increasing operating efficiencies without sacrificing quality of service or profitability. The announcement reflects our strong commitment to be a competitively priced reliable provider of energy.
Non-utility business
In 1993 we created an unregulated subsidiary known as the Boston Energy Technology Group (BETG) following approval from our state regulators. We have authority to invest up to $45 million in this wholly-owned subsidiary over the next three years. BETG will engage in demand side management activities through its wholly-owned subsidiary Ener-G-Vision, Inc. and businesses involving electric transportation and the related infrastructure through its wholly-owned subsidiary TravElectric Services Corporation. We do not currently have a substantial investment in BETG and do not anticipate it significantly impacting our results of operations in the next several years.
In January 1994 BETG acquired a substantial majority interest in the assets of REZ-TEK International, Inc., a manufacturer of ozone water treatment systems. The new entity, which will be known as REZ-TEK International Corp., will continue the business of producing a system that treats cooling water used in commercial and industrial air conditioning systems in an energy efficient and environmentally sound manner.
OTHER MATTERS
Environmental
We are subject to numerous federal, state and local standards with respect to air and water quality, waste disposal and other environmental considerations. These standards can require that we modify our existing facilities or incur increased operating costs.
In 1991 we entered into a consent order with the Massachusetts Department of Environmental Protection (DEP) and other interested parties to undertake certain improvements in the emission control systems at New Boston Station. These
improvements included the replacement of four existing chimney stacks with two taller stacks in order to improve the air quality in the vicinity of the station, and the installation of low nitrogen oxides burners. The capital cost of these modifications along with other associated improvements has been approximately $78 million through 1993 with an additional $3 million expected to complete these projects in 1994.
New Boston Station has the ability to burn natural gas, oil or both. As part of the DEP consent order we also agreed to operate the station using natural gas as fuel for a minimum of nine months per year beginning in April 1992. Beginning in April 1995 we will be required to operate the station fueled exclusively by natural gas, except in certain emergency circumstances. We have made arrangements for a nine month supply of natural gas to the station until April 1995 and are currently in the process of negotiating with natural gas suppliers and transporters concerning the economics and availability of natural gas to New Boston on a year-round basis after that time. Year- round gas supplies are currently not available to the station and, as a result, the outcome of our negotiations with natural gas suppliers and transporters and the impact on the operation of New Boston Station are uncertain.
The 1990 Clean Air Act Amendments will require a significant reduction in nationwide emissions of sulfur dioxide from fossil fuel- fired generating units. The reduction will be accomplished by restricting sulfur dioxide emissions through a market-based system of allowances. We believe that we will have allowances issued to us that are in excess of our needs and which may be marketable. Any gain from the sale of these may be subject to future regulatory treatment. Other provisions of the 1990 Clean Air Act Amendments involve limitations on emissions of nitrogen oxides from existing generating units. Combustion system modifications made to New Boston and Mystic Stations, including the installation of the low nitrogen oxides burners at New Boston, will allow the units to meet the provisions of the 1995 standards. Depending upon the outcome of certain air quality modeling studies, additional emission reductions may also be required by 1999. The extent of any additional reductions and the cost of any further modifications is uncertain at this time.
State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the DEP. We are currently evaluating the potential costs associated with the cleanup of sites where we have been identified as the owner or operator. There are uncertainties associated with these potential costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of certain other multi-party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings.
We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. Refer to Note D to the consolidated financial statements for further discussion regarding LLW disposal.
In recent years a number of published reports have discussed the possibility that adverse health effects may be caused by electromagnetic fields (EMF) associated with
electric transmission and distribution facilities and appliances and wiring in buildings and homes. Some scientific reviews conducted to date by several state and federal agencies have suggested associations between EMF and such health effects, while other studies have not substantiated such associations. We support further research into the subject and are participating in the funding of industry sponsored studies. We are aware that public concern regarding EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities before regulators, or in requests for legislation or regulatory standards concerning EMF levels. We have not been significantly affected to date by these developments and cannot predict their potential impact on us, however, we continue to closely monitor all aspects of the EMF issue.
Litigation
In March 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel is vigorously defending this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings.
Labor negotiations
We began negotiations involving our labor contracts in early February 1994. These contracts expire on May 15, 1994. We anticipate favorable resolution of these negotiations prior to that date.
New accounting pronouncements
We will adopt Statement of Financial Accounting Standards (SFAS) No. 112, Employers' Accounting for Postemployment Benefits, and SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, in the first quarter of 1994. Refer to Notes I and J to the consolidated financial statements for further discussion of these pronouncements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A. SIGNIFICANT ACCOUNTING POLICIES
1. Basis of Consolidation and Accounting
The consolidated financial statements include the activities of our wholly-owned subsidiaries, Harbor Electric Energy Company and Boston Energy Technology Group. All significant intercompany transactions have been eliminated.
We follow accounting policies prescribed by our federal and state regulators. We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The financial statements comply with generally accepted accounting principles. Certain prior period amounts on the financial statements were reclassified to conform with current presentation.
2. Revenue Recognition
We record revenues for electricity used by our customers, but not yet billed, in order to more closely match revenues with expenses.
3. Forecasted Fuel and Purchased Power Rates
The rate charged to retail customers for fuel and purchased power allows for all fuel costs, the capacity portion of some purchased power costs and some transmission costs to be billed to customers monthly using a forecasted rate. The difference between actual and estimated costs is included in accounts receivable on our consolidated balance sheets until subsequent rates are adjusted. State regulators have the right to reduce our subsequent fuel rates if they find that we have been unreasonable or imprudent in the operation of our generating units or in purchasing fuel.
4. Depreciation and Nuclear Fuel Amortization
Our physical property was depreciated on a straight-line basis in 1993, 1992 and 1991 at composite rates of approximately 3.09%, 3.36% and 3.41% per year, respectively, based on estimated useful lives of the various classes of property. The cost of decommissioning Pilgrim Station, our nuclear unit, is excluded from the depreciation rates. When property units are retired, their cost, net of salvage value, is charged to accumulated depreciation.
The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of the spent nuclear fuel and for the decontamination and decommissioning of the United States enrichment facilities used in the production of nuclear fuel. These costs are recovered from our customers through fuel charges.
5. Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance plant expenditures. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant. AFUDC is not an item of current cash income, but payment is received for these costs from customers over the service life of the plant in the form of increased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1993, 1992 and 1991 were 3.62%, 4.48%, and 6.85%, respectively, and represented only the cost of debt.
6. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with maturities of three months or less.
7. Allowance for Doubtful Accounts
Our accounts receivable are substantially all recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
8. Deferred Debits
Deferred debits consist primarily of costs incurred which will be collected from customers through future charges in accordance with agreements with our state regulators. These costs will be expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. A portion of these costs is currently being charged to and collected from customers.
9. Amortization of Discounts, Premiums and Redemption Premiums on Securities
We expense discounts, premiums, redemption premiums and related expenses associated with issuances of securities or refinancing of existing securities in equal annual installments over the life of the replacement securities subject to regulatory approval.
NOTE B. RETAIL SETTLEMENT AGREEMENTS
In 1992 and 1989 our state regulators, the Massachusetts Department of Public Utilities, approved three-year settlement agreements relating to our rate case proceedings. These agreements provided for retail rate increases, accounting adjustments and demand side management program expenditures; clarified the timing and recognition of certain expenses and set limits on our rate of return on common equity. Refer to Management's Discussion and Analysis for further information related to these settlement agreements.
The settlement agreements did not affect our contract or wholesale power rates charged to other utilities, which are regulated by our federal regulators, the Federal Energy Regulatory Commission.
NOTE C. INCOME TAXES
In the first quarter of 1993 we prospectively adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). This required us to change our methodology of accounting for income taxes from the deferred method to an asset and liability approach. The deferred method of accounting was based on the tax effects of timing differences between income for financial reporting purposes and taxable income. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded a net regulatory asset of $26.9 million and a corresponding net increase in accumulated deferred income taxes as of December 31, 1993. The regulatory asset represents the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes on our consolidated balance sheet at December 31, 1993 includes $587.8 million of gross deferred income tax liabilities net of $103.0 million of gross
deferred income tax assets. We have approximately $19 million of alternative minimum tax carryforwards available at December 31, 1993. The major components of accumulated deferred income taxes are a result of differences between book and tax expenses relating to property, plant and equipment.
Deferred income tax expense reflected in our consolidated income statements is incurred when certain income and expenses are reported on the tax return in different years than reported in the financial statements. Investment tax credits are included in income over the estimated useful lives of the related property.
NOTE D. ESTIMATED FUTURE COSTS OF DISPOSING OF SPENT NUCLEAR FUEL AND RETIRING NUCLEAR GENERATING PLANTS
The existing fuel storage facility at Pilgrim Station includes sufficient room for spent nuclear fuel generated through early 1995. We have a request for a license amendment pending before the Nuclear Regulatory Commission (NRC) to allow modification of the storage facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012. The NRC is reviewing our request and we expect approval in 1994. At that time we will initially modify the facility to provide spent fuel storage capacity through approximately 2003. It is the ultimate responsibility of the United States Department of Energy (DOE) to permanently dispose of spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982. We currently pay a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges.
When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. During rate proceedings we provided our regulators a 1991 study documenting a cost of $328 million to decommission the plant. The study is based on the "green field" method of decommissioning, which provides for the plant site to be completely restored to its original state. We are expensing these estimated decommissioning costs over Pilgrim's expected service life. The 1993 expense of approximately $13 million is included in depreciation expense on the consolidated income statements. We receive recovery of this expense from charges to our retail customers and from other utility companies and municipalities who purchase a contracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted so that they may only be used for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning fund balance and nuclear decommissioning reserve, thus reducing the amount to be collected from customers. The 1991 decommissioning study has been partially updated for internal planning purposes to evaluate the potential financial impact of long-term spent fuel storage options resulting from delays in DOE spent fuel removal on the estimated decommissioning cost. The partial update indicates an estimated decommissioning cost of approximately $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. We will continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate.
We are also an investor in two other domestic nuclear units. Both of these units receive through the rates charged to their customers an amount to cover the estimated cost to dispose of their spent nuclear fuel and to retire the units at the end of their useful lives.
We presently dispose of low-level radioactive waste (LLW) generated at Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina. As a result of developments which have occurred pursuant to the Low-Level Radioactive Waste Policy Amendments Act of 1985, our continued access to such disposal facilities has become severely limited and significantly increased in cost. We have access to the South Carolina site through July 1994, but do not presently believe that disposal site access will be provided after that date. Although legislation has been enacted in Massachusetts establishing a regulatory method for managing the state's LLW including the possible siting, licensing and construction of a LLW disposal facility within the state, it appears unlikely that such a facility will be constructed in a timely manner. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management method, we continue to monitor the situation and are investigating other available options, including the possibility of on-site storage.
NOTE E. CANCELLED NUCLEAR UNIT
In May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear unit over approximately eleven and one-half years in accordance with an order received from state regulators. We did not expense any of these costs in 1993. Instead, the remaining balance of approximately $19 million at December 31, 1993 and 1992 will be expensed in 1994 and/or 1995 as approved by our state regulators in our 1992 settlement agreement.
NOTE F. CAPITAL STOCK AND INDEBTEDNESS
(a) In November 1991 our Articles of Organization were amended to increase authorized common stock from 50 million to 100 million shares and reduce the par value from $5 to $1 per common share.
(b) We used the net proceeds of the 1991 common stock issuance to retire $55 million of Series X, 11% first mortgage bonds.
(c) We used the net proceeds of the 1992 common stock issuance to reduce short-term debt.
(d) At December 31, 1993, the remaining authorized common shares reserved for future issuance under the Dividend Reinvestment and Common Stock Purchase Plan were 815,170 shares.
2. Cumulative Non-Mandatory Redeemable Preferred and Preference Stock
In June 1992 we issued 400,000 shares of 8.25% cumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in June 1997. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the $1.46 series cumulative non-mandatory redeemable preference stock.
In May 1993 we issued 400,000 shares of 7.75% cumulative non-mandatory redeemable preferred stock at par. The stock is redeemable at $100 per share plus accrued dividends beginning in May 1998. These shares were sold in the form of 1.6 million depositary shares, each representing a one-fourth interest in a share of the preferred stock. We used the proceeds of this issue to fully retire the 8.88% series cumulative non-mandatory redeemable preferred stock.
3. Cumulative Mandatory Redeemable Preferred Stock
The 480,000 shares of our 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $104.36. The redemption price declines annually each May to par value in May 2002. In May 1993 the stock became subject to sinking fund requirements to retire 20,000 shares at $100 per share plus accrued dividends each year through May 2002. In 1992 we purchased 20,000 shares at a discount on the open market which satisfied the mandatory sinking fund requirement for May 1993. Beginning in 1993, we have the non-cumulative option each May to redeem additional shares, not to exceed 20,000, for the sinking fund at $100 per share plus accrued dividends.
We are not able to redeem any part of our 500,000 shares of $100 par value 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share, plus accrued dividends.
4. Long-Term Debt
Substantially all our property, plant, equipment, materials and supplies are subject to lien under the terms of our Indenture of Trust and First Mortgage dated December 1, 1940, and its supplements. Currently only the outstanding Series S and U first mortgage bonds are subject to the terms of the indenture.
The aggregate principal amounts of our first mortgage bonds, debentures, and sewage facility revenue bonds (including sinking fund requirements) due in 1994 and 1995 are $0 and $100.6 million, respectively, and $101.6 million per year in 1996 through 1998.
Our first mortgage bonds, Series S, adjustable rate due 2002, paid interest at 9.2% per year for the period January 15, 1993 through January 14, 1994. The rate is adjusted annually and is based upon the ten-year constant maturity Treasury rate as published by the Federal Reserve Board. The interest rate for the period January 15, 1994 through January 14, 1995 is 8.2%.
In September 1992 we issued $60 million of 8.25% debentures which mature in September 2022. The debentures are redeemable at prices decreasing from 103.78% of par beginning in September 2002, to 100% of par beginning in September 2012. We used the net proceeds from the sale to reduce short-term debt. In October 1992 we redeemed the remaining balance of $45 million Series X first mortgage bonds.
In February 1993 we issued $65 million of 6.8% debentures due in 2000. We used the proceeds of this issue to reduce short-term debt. These debentures are not redeemable prior to maturity.
In March 1993 we issued $650 million of debentures and used the proceeds to retire ten of twelve outstanding series of first mortgage bonds and reduce short-term debt. The debentures were issued in five separate series with interest rates ranging from 5.125% to 7.8% and maturing between 1996 and 2023. The 5 1/8% debentures due 1996, 5.70% due 1997, 5.95% due 1998 and 6.80% due 2003 are not redeemable prior to maturity. The 7.80% debentures due 2023 are first redeemable in March 2003 at a redemption price of 103.73%. The redemption price decreases annually each March to par value in March 2013. There is no sinking fund requirement for any series of the debentures.
In August 1993 we issued $100 million of 6.05% debentures due in 2000. We used the proceeds from this sale to reduce short-term debt. These debentures are not redeemable prior to maturity and have no sinking fund requirements.
We redeemed $50 million of 9.65% medium-term notes in September 1992 and $50 million of 9.75% medium-term notes in September 1993.
5. Sewage Facility Revenue Bonds
In December 1991, Harbor Electric Energy Company (HEEC), a wholly-owned subsidiary, issued $36.3 million of long-term sewage facility revenue bonds. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature in the years 1995-2015. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds was used to retire $21 million of short-term sewage facility revenue bonds at maturity. The remainder of the proceeds, which is on deposit with the trustee, is being used to finance the construction of HEEC's permanent substation located on Deer Island (in Boston Harbor) and to
fund an amount which must remain in reserve with the trustee. If HEEC should have insufficient funds to pay certain costs on a timely basis or be unable to meet certain net worth requirements, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $7 million.
6. Short-Term Debt
We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have authority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.
NOTE G. FAIR VALUE OF SECURITIES
The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:
Nuclear decommissioning fund The fair value of $70.1 million is based on quoted market prices of securities held.
Cash and cash equivalents The carrying amount of $8.8 million approximates fair value due to the short-term nature of these securities.
Mandatory redeemable cumulative preferred stock, first mortgage bonds, sewage facility revenue bonds and debentures
NOTE H. COMMITMENTS AND CONTINGENCIES
1. Capital Commitments
At December 31, 1993, we had estimated contractual obligations for plant and equipment of approximately $71 million.
2. Lease Commitments
We will capitalize a portion of these lease rentals as part of plant expenditures in the future. Our total expense for both lease rentals and transmission agreements for 1993, 1992 and 1991 was $30 million, $30 million and $33.5 million, respectively, net of capitalized expenses of $5 million, $5 million, and $4.8 million, respectively.
3. Hydro-Quebec
We have an approximately 11% equity ownership interest in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada, which is included in our consolidated financial statements. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria and are compensated accordingly. At December 31, 1993, our portion of these guarantees was approximately $22 million.
4. Yankee Atomic Electric Company
In February 1992 the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) decided to permanently discontinue power operation of the Yankee Atomic nuclear generating station and, in time, decommission that facility. We relied on Yankee Atomic for less than one percent of our system capacity. We have a 9.5% stock investment of approximately $2 million in Yankee Atomic.
In 1993 Yankee Atomic received approval from federal regulators to continue to collect its investment and decommissioning costs through July 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $33 million as of December 31, 1993. This estimate is recorded on our consolidated balance sheet as a power contract liability in deferred credits. An offsetting power contract regulatory asset is included in deferred debits as we continue to collect these costs from our customers in accordance with our 1992 settlement agreement.
5. Nuclear Insurance
The federal Price-Anderson Act currently provides $9.4 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to approximately $8.8 billion is provided by a retrospective assessment of up to $75.5 million per incident levied on each of the 116 units licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year. The additional nuclear liability insurance amount may change as new commercial nuclear units are licensed and existing units give up their licenses. In addition to the nuclear liability retrospective assessments, if the sum of all public liability claims and legal costs arising
from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional five percent of the maximum retrospective assessment.
We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage at Pilgrim Station and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is approximately $14.6 million under both the replacement power and excess property damage, decontamination and decommissioning policies. All companies insured with NEIL are subject to retroactive assessments if losses are in excess of the total funds available to NEIL. While assessments may also be made for losses in certain prior policy years, we are not aware of any losses in those years which we believe are likely to result in an assessment.
6. Litigation
In March 1991 we were named in a lawsuit alleging discriminatory employment practices under the Age Discrimination in Employment Act of 1967 concerning 46 employees affected by our 1988 reduction in force. Legal counsel is vigorously defending this case. Based on the information presently available we do not expect that this litigation or certain other legal matters in which we are currently involved will have a material impact on our financial condition. However, an unfavorable decision ordered against us could have a material impact on quarterly earnings.
7. Hazardous Waste
State regulations revised in 1993 require that properties where releases of hazardous materials occurred in the past be further cleaned up according to a timetable developed by the Massachusetts Department of Environmental Protection. We are currently evaluating the potential costs associated with the cleanup of sites where we have been identified as the owner or operator. There are uncertainties associated with these potential costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of certain other multi-party hazardous waste sites in Massachusetts and other states. At the majority of these other sites we are one of many potentially responsible parties and our alleged share of the responsibility is a small percentage. We do not expect any of our potential cleanup liabilities to have a material impact on financial condition, although provisions for cleanup costs could have a material impact on quarterly earnings.
NOTE I. PENSIONS, OTHER POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS
1. Pensions
We have a noncontributory funded retirement plan, with certain features that allow voluntary contributions. Benefits are based upon an employee's years of service and compensation during the last years of employment. Our funding policy is to contribute each year an amount that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Plan assets are primarily equities, bonds, insurance contracts and real estate.
We changed our discount rate assumption to 7.0% for calculating pension cost effective January 1994.
2. Other Postretirement Benefits
In addition to pension benefits, we also currently provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. Effective January 1993 we adopted Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). This requires us to record a liability during the working years of employees for the expected costs of providing their postretirement benefits other than pensions (PBOPs). Prior to 1993 our
policy was to record the cost of PBOPs when paid. Our transition obligation on January 1, 1993 was approximately $183 million, which we elected to recognize over 20 years as permitted by SFAS 106. Our total cost of PBOPs under SFAS 106 in 1993 was approximately $28 million, an increase of approximately $18 million over costs incurred under our prior method of accounting for PBOPs. Our 1992 settlement agreement provides us with a phase-in of a portion of the increased costs and allows us to defer the additional costs in excess of the phase-in amounts to the extent that we fund an external trust. In December 1993 we deposited $18 million on a tax deductible basis into external trusts for the payment of PBOPs. Accordingly, in 1993 we recorded an expense of approximately $16 million, reflecting the amount of cost recovery from customers, and deferred approximately $12 million for future recovery. We capitalized approximately 19% of these costs.
We used an 8.0% weighted average discount rate and 4.5% rate of compensation increase assumption for calculating the transition obligation and the 1993 postretirement benefits cost. Our expected long-term rate of return on assets is 9.0%. We also assumed a 12.5% health care cost trend rate. Effective January 1, 1994 we changed the discount and health care cost trend rates to 7.0% and 9.0%, respectively, in order to more accurately estimate our future benefit payments. The health care cost trend rate is assumed to decrease by one percent each year to 5% in 1998 and years thereafter. Changes in the health care cost trend rate will affect our cost and obligation amounts. For example, a one percent increase in the rate would increase the total service and interest costs in 1993 by approximately 16% and would increase the accumulated obligation at December 31, 1993 by approximately 13%.
The trust assets consist of money market funds at December 31, 1993.
3. Postemployment Benefits
Statement of Financial Accounting Standards No. 112, Employers' Accounting for Postemployment Benefits, will be effective for the first quarter of 1994. This statement will require us to record a liability computed on an actuarial basis for the estimated cost of providing postemployment benefits. Postemployment benefits provided to former or inactive employees, their beneficiaries and covered dependents include salary continuation, severance benefits, disability-related benefits (including workers' compensation), job training and counseling and continuation of health care and life insurance coverage. We currently recognize
the cost of these benefits primarily as claims are paid. We do not anticipate a material effect on net income from adopting this statement.
NOTE J. NEW ACCOUNTING PRONOUNCEMENT
We will adopt Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities, in the first quarter of 1994. This statement may require us to classify the investments in our nuclear decommissioning fund on our consolidated balance sheet based on how long we intend to hold the individual securities. These investments may be classified as "available for sale" and we may also be required to report any unrealized gains and losses on the investments as a separate component of shareholders' equity. We do not expect the adoption of this statement to have a material effect on shareholders' equity.
NOTE K. LONG-TERM POWER CONTRACTS
1. Long-Term Contracts for the Purchase of Electricity
We purchase electric power under several long-term contracts for which we pay a share of the generating unit's capital and fixed operating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense in our consolidated income statements. Information relating to these contracts as of December 31, 1993 is as follows:
Our total fixed and variable costs for these contracts in 1993, 1992 and 1991 were approximately $225 million, $217 million and $154 million, respectively. Our minimum fixed payments under these contracts for the years after 1993 are as follows:
2. Long-Term Power Sales
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.
Electricity sales and revenues are seasonal in nature, with both being lower in the spring and fall seasons. Quarterly earnings for 1993 reflect a change in the months for which certain customers were billed at higher rates as mandated by the DPU. These customers were billed at these higher rates in July through October in 1992 and in June through September in 1993. The change in billing increased second quarter earnings and reduced fourth quarter earnings by approximately $0.23 per share in 1993.
Item 9. Changes in and Disagreements with Accountants on Accounting and - ------- --------------------------------------------------------------- Financial Disclosure -------------------- None.
Part III --------
Item 10. Directors and Executive Officers of the Registrant - ------------------------------------------------------------
(a) Identification of Directors - --------------------------------
See "Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive Proxy Statement dated March 17, 1994 incorporated herein by reference.
(b) Identification of Executive Officers - -----------------------------------------
The information required by this item is included at the end of Part I of this Form 10-K under the caption Executive Officers of the Registrant.
(c) Identification of Certain Significant Employees - ----------------------------------------------------
Not applicable.
(d) Family Relationships - -------------------------
Not applicable.
(e) Business Experience - ------------------------
For information relating to the business experience during the past five years and other directorships (of companies subject to certain SEC requirements) held by each person nominated to be a director, see "Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference.
For information relating to the business experience during the past five years of each person who is an executive officer, see Executive Officers of the Registrant in this Form 10-K.
(f) Involvement in Certain Legal Proceedings - ---------------------------------------------
Not applicable.
(g) Promoters and Control Persons - ----------------------------------
Not applicable.
Item 11. Executive Compensation - --------------------------------
See "Director and Executive Compensation" on pages 5 through 11 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners - ----------------------------------------------------
To the knowledge of management, no person owns beneficially more than five percent of the outstanding voting securities of the Company.
(b) Security Ownership of Management - -------------------------------------
See "Stock Ownership by Directors and Executive Officers" on pages 4 through 5 of the definitive Proxy Statement dated March 17, 1994, incorporated herein by reference.
(c) Changes in Control - -----------------------
Not applicable.
Item 13. Certain Relationships and Related Transactions - --------------------------------------------------------
Not applicable.
Part IV -------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - -------------------------------------------------------------------------
All other schedules are omitted since they are not required, not applicable, or contain only information which is otherwise provided in the financial statements or notes in Item 8.