Item 1. Business
(a) General Development of Business
Boston Edison Company ("Boston Edison" or "the Company") is a regulated public utility company incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. NSTAR is Massachusetts' largest investor-owned combined electric and gas utility. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including more than one million electric customers in 81 communities and 244,000 gas customers in 51 communities. Boston Edison serves approximately 681,000 electric customers in the city of Boston and 39 surrounding communities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas) and its wholesale electric subsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric.
The electric industry has continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries, including Boston Edison, and concentrating its activities in the transmission and distribution of energy. The 1997 Massachusetts Electric Restructuring Act (Restructuring Act) required all electric utilities to divest their generating assets and leave the retail power supply business, in exchange for the right to recover all non-mitigable stranded costs associated with the creation of customer choice and competition.
To complete its divestiture of generating assets, Boston Edison sold Pilgrim Nuclear Generating Station (Pilgrim) in July 1999 for $81 million to Entergy Nuclear Generating Company (Entergy). As part of the sale, Boston Edison, the first company in the nation to successfully sell a nuclear facility, transferred approximately $228 million in decommissioning funds to the purchaser. Entergy, by contract, assumed all future liability related to the ultimate decommissioning of the plant. The difference between the total proceeds from the sale and the net book value of the Pilgrim assets, plus the net amount to fully fund the decommissioning trust, is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers through the year 2010.
In 1998, Boston Edison completed the sale of all of its fossil generating assets. The amount received above net book value on the sale of these assets is being returned to retail customers over approximately 11 years. Refer to the Generating Assets Divestiture section in Item 7, "Management's Discussion and Analysis" for more information.
Harbor Electric Energy Company (HEEC), a wholly owned subsidiary of Boston Edison, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority's wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison's other wholly owned special-purpose subsidiary, BEC Funding LLC (BEC Funding), was established to facilitate the sale, on July 29, 1999, of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed on the sale of $725 million of electric rate reduction certificates at a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison's retail customers as permitted by the Restructuring Act and authorized by the Commonwealth of Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non- recourse to Boston Edison.
(b) Financial Information about Industry Segments
Boston Edison operates as a regulated electric public utility; therefore industry segment information is not applicable.
(c) Narrative Description of Business
Principal Products and Services
Boston Edison currently delivers electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 2000, Boston Edison served an average of approximately 681,000 customers. Boston Edison also supplies electricity at wholesale for resale to municipal electric departments. Electric operating revenues by class for the last three years consisted of the following:
Sources and Availability of Electric Power Supply
Boston Edison entered into a six-month agreement effective January 1, 2000 to transfer all of the unit output entitlements in long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In return, Select provided full energy service requirements, including New England Power Pool (NEPOOL) capability responsibilities, at Federal Energy Regulatory Commission (FERC)-approved tariff rates to meet the Company's standard offer and default service load requirements through June 30, 2000. Subsequently, Boston Edison entered into two similar six-month agreements to meet the Company's standard offer and default service load requirements with agreements that extended to December 31, 2000. Beginning January 1, 2001, NSTAR Electric's existing portfolio of power purchase contracts has been supplying the majority of Boston Edison's standard offer (including wholesale) energy requirements, supplemented with long- term and daily purchases.
In addition, Boston Edison will continue to buy power generated by Pilgrim from Entergy on a declining basis through 2004.
Information relative to nuclear units that are no longer operating in which Boston Edison has an equity ownership as of December 31, 2000 was as follows:
NEPOOL
During 1997, NEPOOL was restructured with changes effecting the membership and governance provisions of the power pooling agreement along with the transfer of operating responsibility of the integrated transmission and generation system in New England to Independent System Operator-New England (ISO-New England). Previously, NEPOOL dispatched generating units for operation based on the lowest operating costs of available generation and transmission. Under the new structure, generators will be required to provide ISO-New England with market prices at which they will sell short-term energy supply. These prices formed the basis for dispatch that began in the second quarter of 1999. As noted in the Sources and Availability of Electric Power Supply section above, NSTAR Electric has existing long-term power purchase contracts that have been supplying the majority of Boston Edison's standard offer (including wholesale) energy requirements, supplemented with long-term and daily purchases/sales in bilateral and spot markets. Therefore, the change to NEPOOL's operations and pricing structure is expected to have no material adverse impact on Boston Edison's costs for purchased electric energy.
Boston Edison entered into a six-month agreement effective January 1, 2001 through June 30, 2001 with a supplier to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. A default service request for proposal, for default service power supply beginning July 1, 2001 was issued in early 2001. In addition, NSTAR Electric is managing its ISO-New England capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. Refer to Long-Term Power Contracts, Note J, of the Notes to Consolidated Financial Statements for more information.
Franchises
Through its charter, which is unlimited in time, Boston Edison 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 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 actions of these authorities is subject to appeal to the MDTE. 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. Pursuant to the Restructuring Act enacted in November 1997, the MDTE has defined the service territory of Boston Edison based on the territory actually served on July 1, 1997, and following, to the extent possible, municipal boundaries. The legislation further provided that, until terminated by effect of law or otherwise, Boston Edison shall have the exclusive obligation to provide distribution service to all retail customers within such service territory. No other entity shall provide distribution service within this territory without the written consent of Boston Edison which consent must be filed with the MDTE and the municipality so affected.
Regulation
Boston Edison and its wholly owned subsidiaries, HEEC and BEC Funding, operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, financing and investing activities. In addition, the FERC has jurisdiction over various phases of Boston Edison's electric utility businesses including rates for electricity sold at wholesale, facilities used for the transmission or sale of that energy, certain issuances of short- term debt and regulation of the system of accounts.
Retail Electric Rates
As a result of electric industry restructuring, Boston Edison has unbundled its rates, provided customers with inflation adjusted rates that are 15 percent lower than rates in effect prior to March 1, 1998, the retail access date, and have afforded customers the opportunity to purchase generation supply in the competitive market. Unbundled delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge (to collect the costs of delivering electricity), a transition charge (to collect past costs for investments in generating plants and costs related to power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Electricity supply services provided by Boston Edison include optional standard offer service and default service.
Standard offer service is the electricity that is supplied to eligible customers by the retail electric subsidiaries until a competitive power supplier is chosen by the customer. It is designed as a seven-year transitional service (from March 1, 1998) to give the customer time to learn about competitive power suppliers. The price of standard offer service increases over time. Default service is supplied by the local distribution company when a customer is not eligible for standard offer service or receiving power from a competitive power supplier. The market price for default service will fluctuate based on the average market price for power. Amounts collected through these various charges are reconciled to actual expenditures on an on- going basis.
Prior to the implementation of industry restructuring on March 1, 1998, Boston Edison had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs.
Competitive Conditions
The electric industry has continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy.
Environmental Matters
Boston Edison is subject to numerous federal, state and local standards with respect to the management of wastes and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 2000 and 1999 were zero and $0.6 million, respectively, and reflect in large measure, the Company's exit from the electric generation business. Management believes that its operating facilities were in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur.
Number of Employees
As of December 31, 2000, Boston Edison had approximately 2,014 full-time employees, including approximately 1,442, or 72% of employees, represented by three collective bargaining units covered by separate contracts. In December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America AFL-CIO. The new agreement results in a single bargaining unit of 2,000 NSTAR Electric and NSTAR Gas employees into one five-year contract expiring May 15, 2005 that will replace seven separate and widely diverse agreements. Management believes it has satisfactory employee relations.
Expenditures and Financings
Management continuously reviews its plant expenditure and financing programs. These programs and the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.
Plant expenditures in 2000 and 1999 were $110 million and $125 million, respectively, and consisted primarily of additions to Boston Edison's distribution and transmission systems. The majority of these expenditures were for system reliability and control improvements, customer service enhancements and capacity expansion to allow for long-range growth in the Boston Edison service territory.
(d) Financial Information about Foreign and Domestic Operations and Export Sales
Boston Edison delivers electricity to retail and wholesale customers in the Boston area. Boston Edison does not have any foreign operations or export sales.
Item 2.
Item 2. Properties
Boston Edison's high-tension transmission lines are generally located on land either owned or subject to easements in its favor. Its low-tension distribution lines are located principally on public property under permission granted by municipal and other state authorities.
As of December 31, 2000, Boston Edison's transmission system consisted of 376 miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 177 miles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 45 transmission or combined transmission and distribution substations with transformer capacity of 11,053 megavolt amperes (MVA), 574 distribution substations with transformer capacity of 932 MVA and 16 primary network units with 79 MVA capacity. In addition, high tension service was delivered to 248 customers' substations. Primary and secondary overhead and underground distribution systems cover approximately 10,800 and 5,980 circuit miles, respectively. HEEC, Boston Edison's regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115 kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts. HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water Resources Authority, at this location.
Item 3.
Item 3. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving Boston Edison's restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows or results of operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there would be a material adverse impact on Boston Edison's business operations, the consolidated financial position, results of operations and cash flows in the near term.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999 and no further developments have occurred at this time. Management is currently unable to determine the timing and outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and results of operations for a reporting period.
Other litigation
In the normal course of its business, Boston Edison and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, management does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period.
Part II
Item 5.
Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters
The information required by this item is not applicable because all of the common stock of Boston Edison is held solely by NSTAR, its parent company.
Market information for the common stock of NSTAR is included in Item 5 of NSTAR's Annual Report on Form 10-K for the year ended December 31, 2000.
Item 7.
Item 7. Management's Discussion and Analysis
Boston Edison Company ("Boston Edison" or "the Company") is a regulated public utility incorporated in 1886 under Massachusetts' law and is a wholly owned subsidiary of NSTAR. NSTAR is Massachusetts' largest investor-owned combined electric and gas utility. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts including more than one million electric customers in 81 communities and 244,000 gas customers in 51 communities. Boston Edison serves approximately 681,000 electric customers in the city of Boston and 39 surrounding communities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas) and its wholesale electric subsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric.
Merger of BEC Energy and Commonwealth Energy System
An integral part of the merger creating NSTAR is the rate plan of the retail utility subsidiaries of BEC and COM/Energy, including Boston Edison, that was approved by the Massachusetts Department of Telecommunications and Energy (MDTE) on July 27, 1999. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Refer to the Retail Electric Rates section of this Discussion and Analysis for more information.
The merger of BEC and COM/Energy was accounted for as an acquisition of COM/Energy by BEC using the purchase method of accounting. In accordance with Accounting Principles Board (APB) No. 16 - Business Combinations, all goodwill has been recorded on the books of the subsidiaries of COM/Energy. However, under the merger rate plan approved by the MDTE, all of NSTAR's utility subsidiaries share in the recovery of goodwill in their rates. As a result, goodwill amortization expense is allocated to Boston Edison from ComElectric, Cambridge Electric and NSTAR Gas through an intercompany charge. The Company is currently recovering such amount in its rates.
NSTAR recorded goodwill associated with the merger of BEC Energy and COM/Energy of approximately $490 million, resulting in an annual amortization of goodwill of approximately $12.2 million. Boston Edison will be allocated $319 million of goodwill and will expense this amount. Such amount is being recovered in Boston Edison's rates and is treated as an intercompany charge among the Company and its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas. Costs to achieve are being amortized based on the filed estimate of $111 million over 10 years. As of December 31, 2000, Boston Edison's portion of goodwill and costs to achieve amortization are approximately $8 million and $7 million, respectively. NSTAR's retail utility subsidiaries will reconcile the ultimate costs to achieve with that estimate, and any difference is expected to be recovered over the remainder of the amortization period. A majority of costs to achieve the merger have been for severance costs associated with a voluntary separation program (VSP) in which approximately 700 NSTAR Electric and Gas employees elected to participate. The VSP was completed by the end of August 2000. These amounts are expected to be offset by ongoing future cost savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy.
As a result of the merger, cost savings have been realized due to reduced staffing levels and operating efficiencies.
Generating Assets Divestiture
To complete its divestiture of generating assets, Boston Edison sold its Pilgrim Nuclear Generating Station (Pilgrim) in July 1999 for $81 million to Entergy Nuclear Generating Company (Entergy). As part of the sale, Boston Edison, the first company in the nation to successfully sell a nuclear facility, transferred approximately $228 million in decommissioning funds to Entergy. Entergy, by contract, assumed all future liability related to the ultimate decommissioning of the plant. The difference between the total proceeds from the sale and the net book value of the Pilgrim assets, plus the net amount to fully fund the decommissioning trust, is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers through the year 2010.
In 1998, Boston Edison completed the sale of all of its fossil generating assets. The amount received above net book value on the sale of these assets is being returned to customers over approximately 11 years.
Securitization of Boston Edison's Transition Charge
On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary of Boston Edison, closed the sale of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed the sale on $725 million of electric rate reduction certificates as a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison's retail customers as permitted under the Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the MDTE. These certificates are non-recourse to Boston Edison.
Retail Electric Rates
As a result of the Restructuring Act, Boston Edison currently provides its standard offer customers service at inflation- adjusted rates that are 15% lower than rates in effect prior to March 1, 1998, the retail access date.
All distribution customers must pay a transition charge as a component of their rate. The purpose of the transition charge is to allow for the collection of generation-related costs that would not be collected in the competitive energy supply market. The plant and regulatory asset balances that will be recovered through the transition charge until 2009 were approved by the MDTE.
The Restructuring Act requires electric distribution companies to obtain and resell power to retail customers that choose not to buy energy from a competitive energy supplier. This is through either "standard offer service" or "default service." Standard offer service will be available to eligible customers through 2004 at prices approved by the MDTE set at levels so as to guarantee mandatory overall rate reductions provided by the Restructuring Act. New retail customers in the Boston Edison service territory and previously existing customers that are no longer eligible for the standard offer service and have not chosen to receive service from a competitive supplier are provided "default service." The price of default service is intended to reflect the average competitive market price for power. NSTAR Electric has existing long-term power purchase contracts. These long-term contracts will supply approximately 90% - 95% of its standard offer obligations. NSTAR Electric has entered into six-month and shorter-term agreements to meet the remaining standard offer service obligation and continues to evaluate further proposals. In November 2000, NSTAR Electric entered into power purchase agreements to meet all of its default service supply obligation for the period January through June 2001. NSTAR Electric expects to continue periodic market solicitations for default service power supply consistent with provisions of the Restructuring Act and MDTE orders. The cost of providing standard offer and default service, which includes purchased power costs, is recovered from customers on a fully reconciling basis.
Boston Edison's accumulated cost to provide default and standard offer services is in excess of the revenues it has been allowed to bill as of December 31, 2000. As a result, Boston Edison has recorded, at December 31, 2000, a regulatory asset of approximately $193.6 million that is reflected as a component of Current assets on the accompanying Consolidated Balance Sheets. At December 31, 1999, costs incurred in excess of revenues collected amounted to $44.3 million and were reflected as a non- current Regulatory asset.
Under applicable restructuring plans or settlements approved by the MDTE, Boston Edison must, on an annual basis, file proposed adjustments to its rates for the upcoming year along with a proposed reconciliation of prior year revenues and costs for its standard offer, default service, transmission and transition charges. Boston Edison made such a filing with the MDTE in the Fall of 1999. The MDTE subsequently approved proposed rate adjustments effective January 1, 2000, and conducted further hearings for the purpose of reconciling the prior year's costs and revenues related to the Company's transition and transmission charges and the charges for standard offer and default service. The MDTE approved a settlement agreement that resolved the majority of these issues, including all outstanding issues related to Pilgrim, certain cost allocations and other related issues that have been contested; however, the MDTE has not yet rendered a final decision. In November 2000, Boston Edison made a similar filing containing proposed rate adjustments for 2001, including a reconciliation of costs and revenues through 1999. The MDTE has approved rate adjustments effective January 1, 2001, but it has not yet ruled on the reconciliation component of the filings. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there would be a material adverse impact on Boston Edison's consolidated financial position, results of operations and cash flows in the near term.
In addition to the annual rate filings referenced above, Boston Edison has also made separate filings with the MDTE concerning charges for standard offer and default service. Boston Edison has filed with the MDTE a request for approval to increase its standard offer service rate for 2001 based on a fuel adjustment formula contained in its standard offer tariffs that reflects the prices of natural gas and oil. On December 11, 2000, the MDTE approved an increase in the standard offer rate of 1.321 cents per kWh for the Company. The MDTE ruled that the fuel adjustments did not have to meet the 15% rate reduction requirement under the Restructuring Act. The MDTE will re-examine these rates in July 2001. On October 19, 2000, the MDTE approved Boston Edison's request to increase the price of default service to 6.28 cents per kWh, effective December 1, 2000. On November 9, 2000, the Company filed a request with the MDTE for an additional increase for default service to reflect market costs for the period January 1, 2001 through June 30, 2001. On December 4, 2000, the MDTE approved market-based default service rates covering this period. These and future prices for default service are based upon market solicitations for power supply for default service consistent with provisions of the Restructuring Act and MDTE orders.
Under its restructuring settlement agreement, Boston Edison's distribution business was subject to an annual minimum and maximum return on average common equity (ROE) through December 31, 2000. The ROE was subject to a floor of 6% and a ceiling of 11.75%. If the ROE was below 6%, Boston Edison was authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE was above 11%, it was required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment was made if the ROE was between 6% and 11%. In addition, distribution rates continue to be subject to adjustment for any changes in tax laws or accounting principles that result in a change in costs of more than $1 million. No adjustments have been made to Boston Edison's distribution rates due to either one of these mechanisms.
Results of Operations
2000 verses 1999
Net income was $146 million in 2000 compared to $160.3 million in 1999, a decrease of 9%.
Operating revenues
Retail revenues were $1,533.2 million in 2000 compared to $1,387.5 million in 1999, an increase of $145.7 million or 11%. This change reflects a 3.2% increase in retail kilowatt-hour (kWh) electric sales. The increase in retail kWh sales is the result of a strong local economy as indicated by a 2.2% improvement in the overall Massachusetts employment rate, new construction and customer growth. Additionally, Boston Edison recognized incentive revenue entitlements for successfully lowering transition charges, and will continue to earn these entitlements as it lowers transition charges through 2009. The incentive entitlements relate to 1998, 1999 and 2000, and will be collected from customers in 2001. In addition, Boston Edison increased standard offer and default service rates in January and December 2000, which are fully reconciled to the costs incurred and have no impact on net income.
Wholesale electric revenues were $73.2 million in 2000 compared to $102.5 million in 1999, a decrease of $29.3 million or 29%. This decrease in wholesale revenues primarily reflects the absence of sales to Pilgrim contract customers due to the sale of Pilgrim in July 1999.
Other revenues were $65.5 million in 2000 compared to $56.9 million in 1999, an increase of $8.6 million or 15%. This revenue increase primarily reflects higher transmission revenues in 2000 compared to refunds credited to wholesale customers in 1999 resulting from a Federal Energy Regulatory Commission (FERC)- approved settlement with transmission contract customers.
Operating expenses
Purchased power and fuel expense was $839.7 million in 2000 compared to $645.2 million in 1999, an increase of $194.5 million or 30%. Purchased power expense increased $223 million reflecting the increase in purchased power requirements due to the sale of Pilgrim during 1999, an overall increase in the cost of wholesale power and increased requirements resulting from increased kWh sales. Boston Edison adjusts its electric rates to collect the costs related to fuel and purchased power from customers on a fully reconciling basis. Boston Edison's fuel and purchased power expenses reflects a deferral of $145 million in 2000 and $56 million in 1999 related to these rate recovery mechanisms. Due to rate adjustment mechanisms, changes in the amount of fuel and purchased power expense have no impact on earnings. Offsetting these increases was the absence in the current period of fuel expense related to Pilgrim, which decreased $9.4 million due to the sale of the plant in July 1999.
Operations and maintenance expense was $205.7 million in 2000 compared to $271.4 million in 1999, a decrease of $65.7 million or 24%. This change primarily reflects the absence of $36.3 million in nuclear power production expenses due to the sale of the Pilgrim plant in July 1999. As a result of the merger, operations and maintenance cost savings have been realized due to reduced staffing levels and operating efficiencies. In addition, Boston Edison experienced significantly lower costs for employee pensions and benefits in 2000.
Depreciation and amortization expense was $169.3 million in 2000 compared to $176.7 million in 1999, a decrease of $7.4 million or 4%. This decrease primarily reflects the impact of the sale of Pilgrim in July 1999. This decrease was partially offset by $7.2 million from the amortization of costs to achieve related to the merger and $8 million from an affiliated company charge for Boston Edison's portion of goodwill. These amounts are being collected from Boston Edison's customers in accordance with the rate plan that was approved by the MDTE on July 27, 1999.
Demand side management (DSM) and renewable energy programs expense was $54.8 million in 2000 compared to $57.5 million in 1999, a decrease of $2.7 million or 5%. This decrease reflects an 8.1% decrease in the energy conservation rate as of January 1, 2000. In accordance with restructuring legislation and the settlement agreement, these costs are collected from customers on a fully reconciling basis. Therefore, the change has no impact on earnings.
Property and other taxes were $55.9 million in 2000 compared to $68.8 million in 1999, a decrease of $12.9 million or 19%. The decrease primarily reflects lower municipal property taxes resulting from the divestiture of Pilgrim.
Income taxes from operations were $95.9 million in 2000 compared to $91 million in 1999, an increase of $4.9 million or 5.4%. This increase reflects higher pretax operating income in 2000.
Other income (expense), net
Other income, net of tax was $7.7 million in 2000 compared to $19.8 million in 1999, a net decrease of $12.1 million or 61%. Income tax benefits in 1999 were $13.9 million, which included $20.8 million related to the recognition of previously deferred investment tax credits associated with the Pilgrim station that was sold in 1999, partially offset by miscellaneous non-operating expense of $8.5 million. Interest income of $5 million in 2000 compared to $3.7 million in 1999, reflects an increase due to interest received from a third party amounting to $4.4 million related to the Pilgrim wholesale contract buyout and was partially offset by a decrease in non-utility revenues.
Interest charges
Interest on long-term debt and transition property securitization certificates was $98.3 million in 2000 compared to $91.6 million in 1999, an increase of $6.7 million or 7.3%. The increase reflects approximately $25.1 million of interest related to transition property securitization certificates issued in July 1999. These increases were partially offset by approximately $18.4 million in reductions related to the following retirements: $65 million of 6.8% debentures, $34 million of 9.875% debentures and $100 million of 6.05% debentures during 2000.
Other interest charges were $15.9 million in 2000 compared to $6.2 million in 1999, an increase of $9.7 million or 156%. The increase primarily reflects interest associated with the reconciliation of the 1998 and 1999 transition charge true-up filings with the MDTE in November 2000. In addition, interest on short-term debt used to finance the above referenced long-term debt retirements contributed toward this increase.
Other Matters
Environmental
Boston Edison is involved in approximately 16 state-regulated properties where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up these properties in accordance with specific state regulations. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. Boston Edison also continues to have potential liability as a potentially responsible party (PRP) in the cleanup of five multi- party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Through December 31, 2000, Boston Edison had approximately $5 million accrued on its Consolidated Balance Sheets related to these cleanup liabilities. Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount. Based on preliminary assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on Boston Edison's consolidated financial position. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of operations for a reporting period in the near term.
Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. Boston Edison is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of Boston Edison's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on Boston Edison's financial position or results of operations for a reporting period.
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving Boston Edison's electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows or results of operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is currently unable to determine the timing and outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on the Company's business operations, its consolidated financial position, cash flows or results of operations for a reporting period.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group (BETG) and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999 and no further developments have occurred as of this time. Management is currently unable to determine the timing and outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows or results of operations for a reporting period.
Other litigation
In the normal course of its business, Boston Edison and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period.
Number of employees
As of December 31, 2000, Boston Edison had approximately 2,014 full-time employees, including approximately 1,442 or 72% of employees represented by three collective bargaining units covered by separate contracts. In December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America AFL-CIO. The new agreement results in a single bargaining unit of 2,000 NSTAR Electric and NSTAR Gas employees into one five-year contract expiring May 15, 2005 that will replace seven separate and widely diverse agreements. Management believes it has satisfactory employee relations.
Interest rate risk
Boston Edison is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. Carrying amounts, fair values of mandatory redeemable cumulative preferred stock and indebtedness (excluding notes payable) and the weighted average cost as of December 31, 2000 and 1999, were as follows:
New accounting principles
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) and as amended by Statements of Financial Accounting Standards Nos. 137 and 138, collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed- price fuel supply and power contracts) be recorded on the Consolidated Balance Sheets as either an asset or liability measured at its fair value. SFAS 133 is effective for fiscal years beginning after June 15, 2000.
Boston Edison has begun to adopt SFAS 133 as of January 1, 2001. The impact of this adoption has been assessed by the management of the Company. As a part of this assessment, the Company formed an implementation team in 2000 consisting of key individuals from various operational and financial areas of the organization. The primary role of this team was to inventory and determine the impact of potential contractual arrangements for SFAS 133 application. The implementation team has performed extensive reviews of critical operating areas of Boston Edison and has documented its procedures in applying the requirements of SFAS 133 to Boston Edison's contractual arrangements in effect on January 1, 2001. Based on Boston Edison's assessment to date, the adoption of SFAS 133 will not have a material adverse effect on its results of operations, cash flows, or financial position as of January 1, 2001.
Safe harbor cautionary statement
Management occasionally makes forward-looking statements such as forecasts and projections of expected future performance or statements of its plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements. Actual results could potentially differ materially from these statements. Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about operating results and environmental and legal issues.
The impact of continued cost control procedures on operating results could differ from current expectations. The effects of changes in economic conditions, tax rates, interest rates, technology, prices and availability of operating supplies could materially affect the projected operating results.
The impacts of various environmental, legal issues, and regulatory matters could differ from current expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect the estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect the estimated litigation costs.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although the Company has material commodity purchase contracts and financial instruments (debt), these instruments are not subject to market risk. The Company has a standard offer service mechanism which allows for the recovery of fuel costs from customers. The fuel adjustment mechanism allows the Company to pass all costs related to the purchase of commodities to the customer, thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's prudently incurred debt obligations realized by the Company would be borne by customers through future rates.
Report of Independent Accountants
To the Stockholder and Directors of Boston Edison Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) on page 42, present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14 (a)(2) on page 42, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Boston, Massachusetts January 26, 2001
Item 8.
Item 8. Financial Statements and Supplementary Financial Information
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
1. Nature of Operations
Boston Edison Company ("Boston Edison" or "the Company") is a regulated public utility incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. NSTAR is Massachusetts' largest investor-owned combined electric and gas utility. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including more than one million electric customers in 81 communities and 244,000 gas customers in 51 communities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric), and NSTAR Gas Company (NSTAR Gas) and its wholesale electric subsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric.
Boston Edison currently supplies electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 2000, Boston Edison served an average of approximately 681,000 customers. Boston Edison also supplies electricity at wholesale for resale to other utilities and municipal electrical departments.
2. Basis of Consolidation and Accounting
The accompanying consolidated financial statements for each period presented include the activities of Boston Edison's wholly owned subsidiaries, Harbor Electric Energy Company (HEEC) and BEC Funding LLC (BEC Funding). All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year data to conform with the current presentation.
Boston Edison follows accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, Boston Edison is subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying consolidated financial statements conform with Generally Accepted Accounting Principles (GAAP). As a rate- regulated company, Boston Edison has been subject to Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. The distribution business remains subject to rate- regulation and continues to meet the criteria for application of SFAS 71. Refer to Note B to these Consolidated Financial Statements for more information on the accounting implications of the electric utility industry restructuring in Massachusetts.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company's Board of Directors has determined and voted that a portion of the dividends declared on June 24, 1999 and July 22, 1999, which were paid out of retained earnings to its sole shareholder, was a partial distribution of a return of capital. As a result, the Company has appropriately transferred the portion of its dividends deemed return of capital against Premium on Common Stock.
3. Revenues
Rate-regulated utility revenues are based on authorized rates approved by the MDTE and the FERC. Estimates of retail base (transmission, distribution and transition) revenues for electricity used by customers but not yet billed are accrued at the end of each accounting period. Revenues of the Company's non- utility subsidiaries are recognized when services are rendered or when the energy is delivered.
4. Utility Plant
Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation. Non-utility property is stated at cost or its net realizable value.
5. Depreciation
Depreciation of utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. Excluding the effect of the adjustment discussed below, the overall composite depreciation rates were 3.17%, 3.31% and 3.28% in 2000, 1999 and 1998, respectively.
6. Costs Associated with Issuance and Redemption of Debt and Preferred Stock
Consistent with the recovery in electric rates, discounts, redemption premiums and related costs associated with the issuance and redemption of long-term debt and preferred stock are deferred. The costs related to long-term debt are recognized as an addition to interest expense over the life of the original or replacement debt. Consistent with an accounting order received from the FERC, costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.
7. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2000, 1999 and 1998 were 6.00%, 5.82% and 5.88%, respectively, and represented only the cost of short-term debt.
8. Cash and Cash Equivalents
Cash and cash equivalents are comprised of liquid securities with maturities of 90 days or less when purchased.
9. Restricted Cash
Restricted cash represents funds held in reserve for a special- purpose trust on behalf of Boston Edison's wholly owned subsidiary, BEC Funding LLC. If BEC Funding should have insufficient funds to pay for extraordinary expenses, Boston Edison would be required to make additional contributions or loans.
10. Regulatory Assets
Regulatory assets represent costs incurred that are expected to be collected from customers through future charges in accordance with agreements with regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses.
The current purchased power costs shown in the table above as of December 31, 2000 is based on a recent MDTE approval of standard offer and default service rates. It is anticipated that this amount will be collected from customers during 2001.
11. Equity Method of Accounting
Boston Edison uses the equity method of accounting for investments in corporate joint ventures in which it does not have a controlling interest. Under this method, it records as income or loss the proportionate share of the net earnings or losses of the joint ventures with a corresponding increase or decrease in the carrying value of the investment. The investment is reduced as cash dividends are received.
12. Related Party Transactions
The accompanying Consolidated Balance Sheets include receivables of $13.7 million and $10 million as of December 31, 2000 and 1999, respectively, from NSTAR Communications, Inc., an affiliate. The receivables are for construction and construction management services provided by Boston Edison and its contractors. Additionally, the December 31, 2000 Consolidated Balance Sheet also includes a $28.6 million receivable from affiliate NSTAR Services Corporation, a $22.8 million payable to ComElectric and Cambridge Electric relating to purchased power. Boston Edison's goodwill amortization expense allocation from its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $8 million for 2000 as compared to $2.6 million for 1999. The December 31, 1999 Consolidated Balance Sheet also includes a $67 million receivable from NSTAR. This represents Boston Edison's share of consolidated federal income tax benefits.
13. Amortization of Goodwill and Costs to Achieve
The merger of BEC and COM/Energy was accounted for as an acquisition of COM/Energy by BEC using the purchase method of accounting. In accordance with Accounting Principles Board (APB) No. 16 - Business Combinations, all goodwill was recorded on the books of the subsidiaries of COM/Energy. However, under the merger rate plan approved by the MDTE, all of NSTAR's utility subsidiaries share in the recovery of goodwill in their rates. As a result, goodwill amortization expense has been allocated to Boston Edison from ComElectric, Cambridge Electric and NSTAR Gas through an intercompany charge. The Company is currently recovering such amount in its rates.
Goodwill and costs to achieve related to the merger discussed in Note B are being amortized by NSTAR over 40 years and 10 years, respectively.
Note B. Electric Utility Industry Restructuring
1. Merger of BEC Energy and Commonwealth Energy System
NSTAR recorded goodwill associated with the merger of BEC Energy and COM/Energy of approximately $490 million and the original estimate of transaction and integration costs to achieve the merger was $111 million. Boston Edison's share of goodwill and costs to achieve are approximately $319 million and $72 million, respectively. For NSTAR, goodwill is being amortized over 40 years and will amount to approximately $12.2 million annually, while the cost to achieve is being amortized over 10 years and will initially be approximately $11.1 million annually. As of December 31, 2000, Boston Edison's portion of goodwill and costs to achieve amortization are approximately $8 million and $7 million, respectively. Goodwill is being recovered in Boston Edison's rates and is treated as an intercompany charge among the Company and its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas. The ultimate amortization of the cost to achieve will reflect the total actual costs.
2. Accounting Implications
Under the traditional revenue requirements model, electric rates are based on the cost of providing electric service. Under this model, Boston Edison has been subject to certain accounting standards that are not applicable to other businesses and industries in general. The application of SFAS 71 requires companies to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected.
The implementation of electric utility industry restructuring has certain accounting implications. The highlights of these include:
a.) Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation business are recovered through the transition charge. This recovery occurs over a twelve-year period that began on March 1, 1998, the retail access date in Massachusetts.
b.) Depreciation
The composite depreciation rate for distribution utility plant increased from 2.88% to 2.98% as of the retail access date.
c.) Purchased power and fuel charge
The fuel and purchased power charge ceased as of the retail access date. The net remaining over-collection of fuel and purchased power costs were returned to customers through March 31, 2000. These over-recovered costs are included as an offset to the settlement recovery mechanisms and were included in Regulatory assets on the accompanying Consolidated Balance Sheet for 1999.
d.) Standard offer and default service charge
Customers of Boston Edison as of March 1, 1998 have the option of continuing to buy power at standard offer prices through 2004. The standard offer charge began at 2.8 cents/kWh at the retail access date, increased to 3.2 cents/kWh on June 1, 1998, to 3.69 cents/kWh on January 1, 1999, to 4.5 cents/kWh on January 1, 2000 and 4.894 cents/kWh on January 1, 2001. In addition to the annual rate filings referenced above, the Company has also made separate filings with the MDTE concerning charges for standard offer and default service. The Company has filed with the MDTE a request for approval to increase its standard offer service rates for 2001 based on a fuel adjustment formula contained in its standard offer tariffs that reflects the prices of natural gas and oil. On December 11, 2000, the MDTE approved an increase of 1.321 cents/kWh in addition to the standard offer rate of 4.894 cents/kWh for Boston Edison, which resulted in a standard offer service rate of 6.215 cents/kWh. The MDTE ruled that the fuel adjustment did not have to meet the 15% rate reduction requirements under the Restructuring Act. The MDTE will reexamine these rates in July 2001. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from either standard offer service or a third-party supplier. The market price for default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service rates are recovered on a fully reconciling basis.
e.) Distribution and transmission charges
An integral part of the merger is the rate plan of the retail utility subsidiaries of NSTAR that was approved by the MDTE on July 27, 1999. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years.
Distribution rates were subject to a minimum and maximum return on average common equity (ROE) from its distribution business through December 31, 2000. The ROE was subject to a floor of 6% and a ceiling of 11.75%. If the ROE is below 6%, Boston Edison is authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE was above 11%, it was required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment was made if the ROE was between 6% and 11%. In addition, distribution rates continue to be subject to adjustment for any changes in tax laws or accounting principles that result in a change in costs of more than $1 million. No adjustments have been made to Boston Edison's distribution rates due to either one of these rate mechanisms.
The cost of providing transmission service to distribution customers is recovered on a fully reconciling basis.
f.) Generating Assets Divestiture
On July 13, 1999, Boston Edison completed the sale of the Pilgrim Nuclear Generating Station to Entergy Nuclear Generating Company (Entergy), a subsidiary of Entergy Corporation, for $81 million. In addition to the amount received from Entergy, Boston Edison received a total of approximately $233 million from the Pilgrim contract customers, including $103 million from ComElectric, to terminate their contracts. Approximately $5 million remains to be collected under these termination agreements at December 31, 2000. This compares to $80 million at December 31, 1999. As part of the sale, Boston Edison, the first company in the nation to successfully sell a nuclear facility, transferred its decommissioning trust fund to Entergy. In order to provide Entergy with a fully funded decommissioning trust fund, Boston Edison contributed approximately $271 million to the fund at the time of the sale. As a result of a favorable IRS tax ruling, Boston Edison received $43 million from Entergy reflecting a reduction in the required decommissioning funding. The difference between the total proceeds received and the net book value of the Pilgrim assets sold plus the net amount to fully fund the decommissioning trust is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers through the year 2010 under Boston Edison's settlement agreement. The final amounts to be collected from customers related to Pilgrim are subject to regulatory review.
Completion of the sale of Boston Edison's fossil generating assets took place in May 1998. Boston Edison received proceeds from the sale of $674 million, including $121 million for a six- month transitional power purchase contract. The amount received above net book value on the sale of these assets is being returned to Boston Edison's customers over the settlement period.
On July 27, 1999 BEC Funding closed the sale of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed the sale of $725 million of electric rate reduction certificates to the public. The certificates are secured by a portion of the transition charge assessed on Boston Edison's retail customers as permitted under the Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison.
Note C. Income Taxes
Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109, net regulatory assets of $64.8 million and $65.9 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2000 and 1999, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Previously deferred investment tax credits are amortized over the estimated remaining lives of the property giving rise to the credits.
Income tax expense is reflected net of $20.8 million in 1999 and $10.9 million in 1998, representing investment tax credits recognized as a result of generation asset divestitures. Excluding this shareholder benefit, the effective tax rate would have been approximately 39% in each year.
Note D. Pensions and Other Postretirement Benefits
1. Pensions
The Company participates in a defined benefit funded retirement plan that covers substantially all employees. The Company also maintains unfunded supplemental retirement plans for certain management employees of Boston Edison. Effective January 1, 2000, the defined benefit plan was amended to reflect the impact of the transition of all NSTAR union locals to the pension benefits provided under the Local 369 formula. This amendment is reflected in the December 31, 2000 benefit obligation.
Effective January 1, 2000, the COM/Energy defined benefit plan merged into the Company's plan and was subsequently renamed as "The NSTAR Pension Plan." The defined benefit plan was also amended to provide management employees lump sum benefits under a final average pay pension equity formula. Prior to January 1, 2000, these pension benefits were provided under a traditional final average pay formula. This amendment is reflected in the December 31, 1999 benefit obligation.
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the supplemental retirement plan with accumulated benefit obligations in excess of plan assets were $14,067,000, $13,306,000 and $0, respectively, as of December 31, 2000, and $10,325,000, $8,232,000 and $0, respectively, as of December 31, 1999.
As a result of merger-related separation agreements and nuclear divestiture, amounts recognized for curtailment, settlement and special termination benefit costs were $9,555,000, $930,000 and $8,158,000, respectively, for 1999. In addition, $9,623,000 was recognized as a result of pension settlements in 2000. The majority of these charges will be recovered from customers and is a component of Regulatory assets on the accompanying Consolidated Balance Sheets. The amounts resulting from the merger-related separation agreements and generation divestitures are recoverable under the Boston Edison settlement agreement.
Boston Edison also provides defined contribution 401(k) plans for substantially all employees. Matching contributions (which are equal to 50% of the employees' deferral up to 8% of compensation) included in the accompanying Consolidated Statements of Income amounted to $4 million in 2000 and $8 million in both 1999 and 1998.
2. Other Postretirement Benefits
In addition to pension benefits, Boston Edison also provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits include health and life insurance coverage and reimbursement of certain Medicare premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits. Effective January 1, 2001, amendments were added to reflect negotiated changes to Local 369 as well as the impact of the transition of primarily all NSTAR union locals to the benefits provided under the Local 369 formula. These amendments are reflected in the December 31, 2000 benefit obligation. Effective January 1, 2000, an amendment was added to include certain new managed care features. This amendment is reflected in the December 31, 1999 benefit obligation.
For measurement purposes an 11% weighted annual rate of increase in per capita cost of covered medical claims was assumed for 2001. This rate is assumed to decrease gradually to 5% in 2012 and remain at that level thereafter. Dental claims and Medicare premiums are assumed to increase at a weighted annual rate of 4% and 5%, respectively.
As a result of merger-related separation packages and nuclear divestiture, amounts recognized for curtailment and settlement costs were $8,114,000 and $172,000, respectively, for 1999. As a result of the nuclear divestiture, amounts recognized for curtailment and special termination benefit costs were $21,187,000 and $79,000, respectively, for 1998. The amounts resulting from the merger-related separation packages are recoverable as part of the approved rate plans of the retail utility subsidiaries of NSTAR. The amounts resulting from the nuclear divestiture are recoverable under the Boston Edison settlement agreement.
Note E. Capital Stock
Cumulative Preferred Stock
Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
1. Common Shares
(a) The Company's Board of Directors has determined and voted that a portion of the dividends declared on June 24, 1999 and July 22, 1999, which were paid out of retained earnings to its sole shareholder, was a partial distribution of a return of capital. As a result, the Company has appropriately transferred the portion of its dividends deemed return of capital against Premium on Common Stock.
2. Cumulative Mandatory Redeemable Preferred Stock
Boston Edison is not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share plus accrued dividends.
Boston Edison is not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share plus accrued dividends.
Note F. Indebtedness
1. Long-term Debt
The 9.375% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. None of the other series are redeemable prior to maturity. There is no sinking fund requirement for any series of debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.6 million were made in 2000 and 1999. The weighted average interest rate of the bonds was 7.3%. A portion of the proceeds from the bonds is in a reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, Boston Edison would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006.
Boston Edison's Financing Application with the MDTE was approved in October 2000 for authorization to issue from time to time up to $500 million of debt securities through 2002. Proceeds from such issuances covered under this approved financing will be used for repayment or refinancing of certain outstanding equity securities, long-term indebtedness, and for other corporate purposes. On February 20, 2001, Boston Edison filed a registration statement on Form S-3 with the SEC, using a shelf registration process, to issue up to $500 million in debt securities. The registration statement was declared effective by the SEC on February 28, 2001. When issued, Boston Edison will use the proceeds to pay at maturity long-term debt and equity securities, refinance short-term debt and for other corporate purposes.
The aggregate principal amounts of Boston Edison's long-term debt (including securitization certificates and HEEC sinking fund requirements) due through 2005 are approximately $63.1 million in 2001, $71.8 million in 2002, $219.7 million in 2003, $70.4 million in 2004 and $70.1 in 2005.
In 1999, BEC Funding issued notes in the principal amount of $725 million to a special purpose trust created by two Massachusetts state agencies in exchange for the net proceeds from the sale of $725 million of Rate Reduction certificates issued by the trust on July 29, 1999.
2. Short-term Debt
Boston Edison has regulatory approval from the FERC to issue up to $350 million of short-term debt. Boston Edison also has a $200 million revolving credit agreement with a group of banks effective through December 31, 2001. In addition, the Company has a $100 million line of credit. Both of these arrangements serve as back-up to Boston Edison's $300 million commercial paper program. As of December 31, 2000, there was $97 million outstanding under its commercial paper program. There was no amount outstanding under this program as of December 31, 1999. Under the terms of this agreement, Boston Edison is required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the total agreement amount. The Company was in compliance with these requirements for 2000 and 1999.
Note G. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:
Cash and cash equivalents
The carrying amount of $12 million and $118 million, for the years 2000 and 1999, respectively, approximates fair value due to the short-term nature of these securities.
Mandatory redeemable cumulative preferred stock
Note H. Segment and Related Information
Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information, requires the disclosure of certain financial and descriptive information by operating segments. Boston Edison operates primarily as a regulated electric public utility for which separate segment information is not applicable.
Note I. Commitments and Contingencies
1. Contractual Commitments
At December 31, 2000, Boston Edison had estimated contractual obligations for plant and equipment of approximately $104 million.
The total expense for both lease rentals and transmission agreements was $45.3 million in 2000, $38.7 million in 1999 and $29.4 million in 1998, net of capitalized expenses of $1.7 million in 2000, $1.5 million in 1999 and $1.3 million in 1998.
2. Equity Investments
Boston Edison has an equity investment of approximately 11% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, Boston Edison is required to guarantee, in addition to its own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 2000, Boston Edison's portion of these guarantees was $8 million.
Boston Edison has a 9.5% equity investment of approximately $1 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992, the board of directors of Yankee Atomic voted to discontinue operations of the Yankee Atomic nuclear generating station permanently and decommission the facility. Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through July 9, 2000, the expiration date of the unit's power contracts. Also, as of that date, the equity owners of the unit completed the recovery of closure (decommissioning) costs and net unrecovered assets. Subsequently, Yankee Atomic initiated a stock buy-back program, approved by the SEC, to redeem 95% of the outstanding stock of Yankee Atomic. Through December 31, 2000, 50% of the 95% of shares outstanding, or 72,866 shares, were redeemed. Boston Edison's reduction of its equity ownership resulting from the buy- back of 6,922 shares was approximately $692,000.
Boston Edison also has a 9.5% equity investment in Connecticut Yankee Atomic Power Company (CYAPC) of approximately $7 million. In December 1996, the board of directors of CYAPC, which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the unit. Boston Edison's share of Connecticut Yankee's remaining investment and estimated costs of decommissioning is approximately $26 million as of December 31, 2000. This estimate is recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting Regulatory asset.
In December 1996, CYAPC filed for rate relief at the FERC seeking to recover certain post-operating costs, including decommissioning. In August 1998, the FERC Administrative Law Judge (ALJ) released an initial decision regarding CYAPC's filing. This decision called for the disallowance of the common equity return on the CYAPC investment subsequent to the shutdown. The decision also stated that decommissioning collections should continue to be based on a previously approved estimate, with an adjustment for inflation, until a more reliable estimate is developed. In October 1998, both CYAPC and Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ decision. The case is still pending before the FERC. If the initial decision is upheld by the FERC, CYAPC could be required to write off a portion of its investment in the generating unit and refund a portion of the previously collected return on investment to ratepayers. Management is currently unable to determine the ultimate outcome of this proceeding. However, the estimate of the effect of the ALJ's initial decision does not have a material impact on the Company's consolidated financial position or results of operations.
3. Environmental Matters
Boston Edison is involved in approximately 16 state-regulated properties where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up these properties in accordance with specific state regulations. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. Boston Edison also continues to have potential liability as a potentially responsible party in the cleanup of five multi-party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Approximately $5 million is included in the Consolidated Balance Sheets as of December 31, 2000 related to these cleanup liabilities. Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount. Based on its assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on the Company's consolidated financial position. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of operations for a reporting period in the near term.
Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. Boston Edison is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of Boston Edison's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on Boston Edison's financial position or results of operations for a reporting period.
4. Legal Proceedings
Industry and corporate restructuring legal proceedings
The MDTE order approving Boston Edison's restructuring settlement agreement was appealed by certain parties to the SJC. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows or results of operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is unable to determine the timing and the outcome of this proceeding. However, if an unfavorable outcome were to occur, there would be a material adverse impact on Boston Edison's consolidated financial position, results of operations and cash flows for a reporting period.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with the 1993 order that permitted the formation of Boston Energy Technology Group and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999 and no further developments have occurred as of this time. Management is currently unable to determine the timing and the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and results of operations for a reporting period.
Other litigation
In the normal course of its business, Boston Edison is also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period.
Note J. Long-Term Power Contracts
Long-Term Contracts for the Purchase of Electricity
Boston Edison entered into a six-month agreement effective January 1, 2000 to transfer all of the unit output entitlements in long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In return, Select provided full energy service requirements to Boston Edison, including NEPOOL capability responsibilities, at FERC approved tariff rates to meet its standard offer and default service load requirements through June 30, 2000. Subsequently, Boston Edison entered into two similar six-month agreements to meet the Company's standard offer and default service load requirements that extended to December 31, 2000. Boston Edison entered into a six-month agreement effective January 1, 2001 through June 30, 2001 with a supplier to provide full default service energy and ancillary service requirements. A default service request for proposal, applicable for default service power supply beginning July 1, 2001, was issued in early 2001. NSTAR Electric's existing portfolio of power purchase contracts is supplying the majority of Boston Edison's standard offer (including wholesale) energy requirements, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR is managing its NEPOOL capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001.
(a) Boston Edison purchases 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. Energy is paid for based on a price per kWh actually received. Boston Edison does not pay a proportionate share of the unit's capital and fixed operating costs.
(b) Boston Edison pays for this energy based on a price per kWh actually received. Boston Edison does not pay a proportionate share of the unit's capital and fixed operating costs.
Boston Edison's total capacity and energy costs associated with these contracts in 2000, 1999 and 1998 were approximately $428 million, $315 million and $239 million, respectively. Boston Edison's capacity charge obligation under these contracts for the years after 2000 is as follows:
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
FORM 10-K DECEMBER 31, 2000
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.