10-K 1 bostonedison10k2001b.txt BOSTON EDISON 10K 7 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission file number 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter)
Massachusetts 04-1278810 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 800 Boylston Street, Boston, Massachusetts 02199 (Address of principal executive offices) (Zip Code)
(617) 424-2000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [ x ] NO [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Outstanding at Class of Common Stock March 28, 2002 Common Stock, $1 par 100 shares value
The Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this Form with the reduced disclosure format.
Documents Incorporated Part in Form 10-K by Reference None Not Applicable
List of Exhibits begins on page 51 of this report. Boston Edison Company Form 10-K Annual Report December 31, 2001
Part I Page Item 1. Business 2 Item 2. Properties 8 Item 3. Legal Proceedings 8 Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 9 Item 7. Management's Discussion and Analysis 10 Item 7A. Quantitative and Qualitative Disclosures About 24 Market Risk Item 8. Financial Statements and Supplementary Financial 26 Information Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 50 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 51
Part I Item 1. Business (a) General Development of Business Boston Edison Company ("Boston Edison" or "the Company") is a regulated public utility incorporated in 1886 under Massachusetts law and is a subsidiary of NSTAR. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 246,000 gas customers in 51 communities. Boston Edison serves approximately 681,000 electric customers in the city of Boston and 39 surrounding communities. NSTAR's retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas). 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 encouraged the utility industry to seek efficiencies and other benefits through business combinations. NSTAR is prepared to operate in this changing marketplace by combining the resources of its utility subsidiaries, including Boston Edison, and concentrating its activities in the transmission and distribution of energy. 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 consolidated 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 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Commonwealth of Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison. NSTAR Electric has committed resources to implement a System Improvement Program to better serve its customers by focusing on improving customer service and system reliability. This comprehensive, non-recurring System Improvement Program was implemented to upgrade NSTAR Electric's distribution system, primarily within the Boston Edison service territory and is expected to be completed during 2002. The cost of this non- recurring program is expected to be $65 million. Approximately $11 million will be included in operations and maintenance expense in 2002 and $54 million will be invested in delivery assets during the year. A combination of unusually severe storms, record heat and extreme customer load in the Boston area led to prolonged and wide-spread outages in the summer of 2001 that underscored the need to address system upgrades and improve maintenance. The program includes non-recurring costs to eliminate the backlog of critical maintenance activities and complete non-routine systems enhancements. This program will also serve to allow NSTAR Electric to meet the growing load in its service territory, as evidenced by the fact that NSTAR's extraordinary peak demand electric load reached an all-time level on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior year's peak load by 12% and the previous all-time peak load by 8.5%. An integral part of the merger creating NSTAR is the rate plan of the retail utility subsidiaries of BEC and COM/Energy that was approved by the Massachusetts Department of Telecommunication 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 "New Accounting Principles" section in Item 7, Management's Discussion and Analysis for more information. In 1998, Boston Edison completed the sale of all of its fossil generating assets and in 1999, sold its Pilgrim Nuclear Generating Station. Refer to the "Generating Assets Divestiture" section in Item 7, Management's Discussion and Analysis for more information. (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 1.6 million. In 2001, 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 of customers for the last three years consisted of the following:
2001 2000 1999 Retail electric revenues: Commercial 57% 53% 51% Residential 31% 30% 29% Industrial 9% 9% 9% Other 1% 1% 1% Wholesale and contract revenues 2% 7% 10%
Sources and Availability of Electric Power Supply NSTAR Electric, including the Company, has existing long-term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of short-term power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders. NSTAR Electric entered into six-month agreements effective January 1, 2001 through June 30, 2001 and July 1, 2001 through December 31, 2001 with suppliers to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. NSTAR Electric's existing portfolio of power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2001, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric managed its Independent System Operator- New England Power capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. For further information refer to Note I of the Consolidated Financial Statements in Item 8. In July 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 the buyer, Boston Edison received a total of approximately $233 million from the Pilgrim contract customers, including $103 million from ComElectric, to terminate their contracts. As part of the sale, Boston Edison, 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 Internal Revenue Service 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 under Boston Edison's settlement agreement. In addition, Boston Edison continues 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, 2001 was as follows:
Connecticut Yankee Yankee Atomic (dollars in thousands) Year of Shutdown 1996 1992 Equity Ownership 9.5% 9.5% Equity Ownership Balance $6,470 $82
New England Power Pool (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. Franchises Through its charter, which is unlimited in time, Boston Edison has the right to engage in the business of producing and selling electricity, 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 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 Federal Energy Regulatory Commission (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. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through 2004. 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 standard offer service. The market price for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis. 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 pressures 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 in 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. Employees and Employee Relations All NSTAR employees, including those of Boston Edison, are employees of NSTAR Electric & Gas. As of December 31, 2001, NSTAR had approximately 3,300 full-time employees, including approximately 2,300 or 70% of who are represented by two collective bargaining units covered by separate contracts. Effective in May 2001, all employees are employed by NSTAR Electric & Gas. As of 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 approximately 2,000 NSTAR Electric & Gas employees with a five-year contract expiring May 15, 2005 that replaced seven separate and widely diverse agreements. On March 24, 2002, Local 12004, United Steelworkers of America, AFL-CIO-CLC ratified a new four-year contract that expires on March 31, 2006. Management believes it has satisfactory employee relations with a significant majority of its employees. Capital Expenditures and Financings The most recent estimates of plant expenditures and long-term debt maturities for the years 2002 through 2006 are as follows:
(in thousands) 2002 2003 2004 2005 2006 Capital $191,00 $141,00 $123,00 $107,000 $ 93,000 expenditures(a) Long-term debt $ 41,60 $219,70 $ 70,40 $ 70,100 $ 70,300
(a) Includes plant expenditures and costs related to a non- recurring System Improvement Program 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 2001 and 2000 were $138.6 million and $110.4 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. Properties Substantially all of Boston Edison's fossil generating assets were sold as of December 30, 1998. The Pilgrim Nuclear Generating Station was sold in July 1999. Other Boston Edison properties included an integrated system of distribution lines and substations that are located primarily in the Boston area as well as the outlying communities. 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, 2001, primary and secondary overhead and underground distribution systems cover approximately 10,900 and 5,900 circuit miles, respectively. In addition, Boston Edison's transmission system consisted of 117 substations and approximately 711,000 active customer meters. 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. Legal Proceedings Industry and corporate restructuring legal proceedings The 1998 MDTE order approving the Boston Edison 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 and the results of operations for a reporting period. The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy was appealed by certain parties to the Massachusetts Supreme Judicial Court. The appeals of the Massachusetts Attorney General (AG) and a separate group that consists of The Energy Consortium and Harvard University remain pending. In October 2001, the MDTE certified the record of the case to the court; however, there has to date been no briefing, hearing or other action taken with respect to this proceeding. If an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period. Regulatory proceedings In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the AG contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on Boston Edison's consolidated financial position or results of operations. 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, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current customers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This charge had no material adverse effect on Boston Edison's consolidated financial position or results of operations. Other legal matters 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 changes in estimates could have a material impact on the results for a reporting period. Part II 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 BEC Energy, Boston Edison's parent company, and all of BEC Energy's common shares are held by NSTAR. Market information for the common shares of NSTAR is included in Item 5 of NSTAR's Annual Report on Form 10-K for the year ended December 31, 2001. 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 subsidiary of NSTAR. NSTAR is Massachusetts' largest investor-owned combined electric and gas utility and is an exempt public utility holding company. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 246,000 gas customers in 51 communities. Boston Edison serves approximately 681,000 electric customers in the city of Boston and 39 surrounding communities. NSTAR's retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas). 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 consolidated 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 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Commonwealth of Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison. NSTAR Electric has committed resources to implement a System Improvement Program to better serve its customers by focusing on improving customer service and system reliability. This comprehensive, non-recurring System Improvement Program was implemented to upgrade NSTAR Electric's distribution system and is expected to be completed by 2002. The cost of this non- recurring program is expected to be $65 million and primarily is associated with improvement to Boston Edison's electric systems. Approximately $11 million will be included in operations and maintenance expense in 2002 and $54 million will be invested in delivery assets during the year. A combination of unusually severe storms, record heat and extreme customer load in the Boston area led to prolonged and wide-spread outages in the summer of 2001 that underscored the need to address system upgrades and improve maintenance. The program includes non- recurring costs to eliminate the backlog of critical maintenance activities and complete non-routine systems enhancements. This program will also serve to allow NSTAR Electric to meet the growing load in its service territory, as evidenced by the fact that NSTAR's peak demand electric load reached an all-time level on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior year's peak load by 12% and the previous all-time peak load by 8.5%. Cautionary Statement This Management's Discussion and Analysis contains some forward- looking statements such as forecasts and projections of expected future performance or statements of management's plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission (SEC) and in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe" and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward- looking statements may not turn out to be what the Company expected. Actual results could potentially differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved. The impact of continued cost control procedures on operating results could differ from current expectations. Boston Edison's revenues from its electric sales are weather-sensitive, particularly sales to residential and commercial customers. Accordingly, Boston Edison's sales in any given period reflect, in addition to other factors, the impact of weather, with warmer temperatures generally resulting in increased electric sales. Boston Edison anticipates that these sensitivities to seasonal and other weather conditions will continue to impact its sales forecasts in future periods. The effects of changes in weather, economic conditions, tax rates, interest rates, technology, prices and availability of operating supplies could materially affect the projected operating results. Boston Edison undertakes no obligation to publicly update forward- looking statements, whether as a result of new information, future events, or otherwise. You are advised, however, to consult any further disclosures Boston Edison makes in its Forms 10-Q and 8-K to the SEC. Also note that Boston Edison provides in the next paragraph a cautionary discussion of risks and other uncertainties relative to its business. These are factors that could cause its actual result to differ materially from expected and historical results. Other factors in addition to those listed here could also adversely affect Boston Edison. Boston Edison's forward-looking information depends in large measure on prevailing governmental policies and regulatory actions, including those of the Massachusetts Department of Telecommunications and Energy (MDTE) and the Federal Energy Regulatory Commission (FERC), with respect to allowed rates of return, rate structure, financings, purchased power, acquisition and disposition of assets, operation and construction of facilities, changes in tax laws and policies and changes in and compliance with environmental and safety laws and policies. 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 the specific cleanup technology could affect the estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect any estimated litigation costs. Accounting Policies The accompanying consolidated financial statements for each period presented include the activities of Boston Edison's wholly owned subsidiaries, HEEC and 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 FERC and the MDTE. In addition, Boston Edison is subject to the accounting and reporting requirements of the 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 (SFAS) 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. 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. Goodwill 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 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 "New Accounting Principles" section of this Management's 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 these amounts 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 was allocated $319 million of goodwill and is expensing this amount. This 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. For the year ended December 31, 2001, 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 employees elected to participate. The VSP was completed by the end of August 2000. These amounts are expected to be offset by ongoing cost savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. Refer to the "New Accounting Principles" in this section for further information related to goodwill. Generating Assets Divestiture In July 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 the buyer, Boston Edison received a total of approximately $233 million from the Pilgrim contract customers, including $103 million from ComElectric, to terminate their contracts. As part of the sale, Boston Edison 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 these amounts are currently being collected from customers under Boston Edison's settlement agreement. Securitization of Boston Edison's Transition Charge On July 27, 1999, BEC Funding LLC, a wholly owned consolidated 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 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the MDTE. These certificates are non-recourse to Boston Edison. Service Quality Index On October 29, 2001, and as subsequently updated, NSTAR Electric, including Boston Edison, filed with the MDTE proposed service quality plans for each company, which replaced the service quality plan that had previously been filed as a part of the NSTAR merger rate plan and includes guidelines that had been established by the MDTE as a result of its generic investigation of service quality issues. The service quality plans established performance benchmarks effective January 1, 2002 for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance. The companies are required to report annually concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks. On October 29, 2001, NSTAR Electric also filed with the MDTE a report concerning their performance on the identified service quality measures for the two twelve-month periods ended August 31, 2000 and 2001. This report included a calculation of penalties in accordance with MDTE guidelines whereby penalties were calculated totaling approximately $3.9 million relating primarily to Boston Edison's electric system reliability performance for the summer of 2001. NSTAR disputes the legal applicability of penalties for these performance periods; however, NSTAR proposed in settlement of this matter to provide credits to Boston Edison customers totaling $3.9 million, offset in part by other payments to Boston Edison customers, which totaled approximately $1 million, relating to summer 2001 electric service outages. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.2 million to be refunded to customers as a credit to their bills in 2002. Also on October 29, 2001, NSTAR Electric, including Boston Edison, filed with the MDTE a comprehensive report regarding electric system performance issues encountered during the summer of 2001. The filing included detailed analyses of factors affecting performance, as well as, the companies' plans to address issues identified. The MDTE also requested similar filings from other Massachusetts electric distribution companies and has held public hearings and will hold adjudicatory hearings concerning each such filing. On January 30, 2002, the AG and the Massachusetts Division of Energy Resources (DOER) filed comments urging the MDTE to assess the maximum penalties allowed pursuant to the established service quality benchmarks and to require an independent management audit as a result of alleged service quality deficiencies. On February 6, 2002, NSTAR Electric filed its brief arguing against the AG's and DOER's positions. On March 22, 2002, following a number of public hearings throughout the NSTAR Electric service area, the MDTE issued an order finding that NSTAR Electric had made progress in addressing the issues which initiated the investigation and requiring that NSTAR Electric submit further updated reports on specific issues on a quarterly and annual basis. Boston Edison is unable to estimate its ultimate liability for future costs or penalties as a result of any further filings relating to this investigation. However, in view of Boston Edison's current assessment of its electric distribution system performance responsibilities, existing legal requirements and regulatory policies, management believes it would not have a material effect on Boston Edison's consolidated financial position, cash flows or results of operations for a reporting period. Retail Electric Rates 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 recovery 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 2016 were approved by the MDTE. This schedule is subject to adjustment by the MDTE. The 1997 Restructuring Act requires electric distribution companies to obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier 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 other customers who are no longer eligible for 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. As of December 31, 2001, Boston Edison had approximately 19% of its load requirements provided by competitive suppliers. Boston Edison's accumulated cost to provide default and standard offer service was in excess of the revenues it was allowed to bill. As a result, Boston Edison reflected a regulatory asset of approximately $193.6 million at December 31, 2000 that is reflected as a component of Regulatory assets on the accompanying Consolidated Balance Sheets. Boston Edison was permitted by the MDTE to increase its rates charged to customers to collect this shortfall. As a result of new rates for standard offer and default service that became effective January 1 and July 1, 2001, and the reduction in power supply costs in 2001, resulted in a slight net over-collection of $2.5 million as of December 31, 2001. In December 2000, the MDTE approved a standard offer fuel index of 1.321 cents per kilowatt-hour (kWh) that was added to Boston Edison's standard offer service rates for the first-half of 2001. In June 2001, the MDTE approved an additional increase of 1.23 cents per kWh effective July 1, 2001 based on a fuel adjustment formula contained in its standard offer tariffs to reflect the prices of natural gas and oil. In December 2001, the MDTE approved a decrease in this fuel index of 1.125 cents to 1.426 cents per kWh for the first quarter of 2002 based on a decrease in the cost of fuel. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act. Boston Edison must, on an annual basis, file a forecast of its rates for the upcoming year along with any reconciliation of prior year revenues and costs for standard offer, default service, transmission and transition charges. The MDTE will, in the ordinary course, approve rates for the coming year before the current year-end to allow the new rates to become effective the first of January. Subsequently, the estimates for the prior year are reconciled to the actual amounts for that year. The MDTE reviews these costs and approves the amounts subject to any required adjustments. In December 2001, Boston Edison made a filing containing proposed rate adjustments for 2002, including a preliminary reconciliation of costs and revenues through 2001. The MDTE subsequently approved the tariffs effective January 1, 2002. The filings were updated in February 2002 to include final costs for 2001. The MDTE has approved the reconciliation of costs and revenues for Boston Edison through 2000 in its approval on November 16, 2001 of a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in Boston Edison's prior reconciliation filings. As a part of this settlement, Boston Edison agreed to reduce the costs sought to be collected through the transition charge by approximately $2.9 million as compared to the amounts that were originally sought. This settlement did not have a material adverse effect on NSTAR's consolidated financial position or results of operations for the period ended December 31, 2001. In addition to the annual rate filings referenced above, NSTAR Electric has also made interim filings with the MDTE concerning charges for a standard offer fuel adjustment and for (market- based) default service rates. NSTAR Electric has existing long- term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders. At December 31, 2001, approximately 31% of Boston Edison's customers were on default service. Other Legal Matters 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 changes in estimates could have a material impact on the results for a reporting period. Other Matters The September 11, 2001 terrorist attack that occurred in New York City and in Washington, D.C., resulted in a tremendous loss of life and property. This unfortunate incident has had unprecedented pervasive negative impacts on several U.S. industries and on the U.S. economy in general. While Boston Edison was not directly impacted by the event, the Company believes that it could be impacted indirectly in the near future. The indirect impacts may include lower revenues due to the negative impact on certain of Boston Edison's commercial and industrial customers and higher costs related to items such as insurance and security. Results of Operations The following section of Management's Discussion and Analysis compares the results of operations for each of the three fiscal years ended December 31, 2001 and should be read in conjunction with the consolidated financial statements and the accompanying notes included elsewhere in this report. 2001 versus 2000 Net income was $150.4 million in 2001 compared to $146 million in 2000, an increase of 3%. Operating revenues Operating revenues for 2001 increased 18.6% from 2000 as follows:
(in thousands) Retail revenues $292,795 Wholesale revenues 6,834 Short-term sales and other revenues 11,227 Increase in operating revenues $310,856 ========
Despite virtually no change in energy sales in 2001, retail revenues were $1,826 million in 2001 compared to $1,533.2 million in 2000, an increase of $292.8 million, or 19%. The change in retail revenues includes higher rates implemented in January and July 2001 for standard offer and default services, which increased retail revenues by $178.6 million and $209 million, respectively, the absence in 2001 of a $23.7 million fuel charge refund to customers in 2000, and increases in net distribution revenues of $6.6 million and transmission revenues of $24.1 million. These revenue increases were partially offset by lower transition revenues of $69.8 million due to a decline in rates. The increase in Boston Edison's retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on net income. Boston Edison forecasts its electric sales based on normal weather conditions. Forecasted results may differ from those projected due to actual weather conditions above or below these normal weather levels. Weather conditions greatly impact the change in electric sales and revenues in Boston Edison's service area. Boston Edison's revenues from its electric sales are weather-sensitive, particularly sales to residential and commercial customers. Accordingly, Boston Edison's sales in any given period reflect, in addition to other factors, the impact of weather, with warmer temperatures generally resulting in increased electric sales. Boston Edison anticipates that these sensitivities to seasonal and other weather conditions will continue to impact its sales forecasts in future periods. The summer period of 2001 was significantly warmer than the same period in 2000, resulting in a 39.8% increase in cooling degree days from the prior year and a 21.2% increase from the 30-year average. Below is comparative information on cooling and heating degree days in 2001 and 2000 and the number of degree days in a "normal" year as represented by a 30-year average.
30-Year 2001 2000 Average Cooling degree days 822 588 678 Percentage change from prior year 39.8% (34.0)% Percentage change from 30-year 21.2% (13.3)% average Heating degree days 5,637 6,147 5,939 Percentage change from prior year (8.3)% 11.7% Percentage change from 30-year (5.1)% 3.5% average
Wholesale electric revenues were $80 million in 2001 compared to $73.2 million in 2000, an increase of $6.8 million, or 9%. This increase in wholesale revenues reflects increased kWh sales of 2.9%, primarily as the result of increased demand from a public transit authority and municipal contracts. In 2002, wholesale electric sales are forecasted to decrease due to the expiration of contracts with several municipalities. The expiration of these contracts is not expected to impact Boston Edison's consolidated earnings. Other revenues were $76.7 million in 2001 compared to $65.5 million in 2000, an increase of $11.2 million, or 17%. This change reflects higher New England Power Pool related transmission revenues, partially offset by the absence of a $1.6 million transmission refund relating to Local Network Services transmission revenues as recognized in 2000 due to a FERC- approved settlement with transmission contract customers. Operating expenses Purchased power was $1,159.7 million in 2001 compared to $839.7 million in 2000, an increase of $320 million or 38%. The increase in purchased power expense reflects the impact of the recognition of previously deferred standard offer and default service supply costs resulting from collection of these costs in 2001. Boston Edison adjusts its electric rates to collect the costs related to purchased power from customers on a fully reconciling basis. Due to the rate adjustment mechanisms, changes in the amount of purchased power expense have no impact on earnings. Also impacting this increase were higher purchased power requirements due to a slight increase in retail sales, partially offset by lower costs that reflect the prices of natural gas and oil. Operations and maintenance expense was $203.3 million in 2001 compared to $205.7 million in 2000, a decrease of $2.4 million or 1.2%. This slight decrease reflects the full integration of NSTAR Electric & Gas and includes the re-alignment of costs allocated to NSTAR subsidiaries and other merger-related operating efficiencies. This decrease was partially offset by higher electric distribution weather-related maintenance costs related to a major late-winter storm in March and severe summer weather during 2001, higher bad debt expense primarily due to the increased revenues and higher costs related to pension and postretirement benefits. In 2002, consolidated operations and maintenance expense for NSTAR is forecasted to increase significantly to support the utility System Improvement Program of approximately $11 million. It is anticipated that a significant portion of these costs will be incurred by Boston Edison. NSTAR has forecasted that pension cost will increase by approximately $20 million for 2002 as compared to 2001. Accordingly, Boston Edison will be allocated approximately 60% of this cost. This is due to the downturn in equity markets, which have reduced the value of NSTAR's pension investments and the impact of lower interest rates. This expected level of expense could vary due to external factors beyond the Company's control. Depreciation and amortization expense was $167.9 million in 2001 compared to $169.3 million in 2000, a decrease of $1.4 million or 0.8%. The decline in amortization expense is directly attributable to the lower level of amortization expense associated with software-related costs, partially offset by a higher level of depreciable plant-in-service in the current year. Demand side management (DSM) and renewable energy programs expense was $47.6 million in 2001 compared to $54.8 million in 2000, a decrease of $7.2 million, or 13%, primarily due to the timing of DSM expense. These costs are in accordance with program guidelines established by regulators and are collected from customers on a fully reconciling basis. In addition, Boston Edison earns incentive amounts in return for increased customer participation. Property and other taxes were $69.8 million in 2001 compared to $55.9 million in 2000, an increase of $13.9 million, or 25%. The increase was due to the fact that during 2000, Boston Edison was reimbursed for the majority of its payments, in lieu of property taxes to the Town of Plymouth by Entergy Nuclear Generating Company (Entergy). Entergy purchased Pilgrim Station in 1999. Income taxes from operations were $94.0 million in 2001 compared to $95.9 million in 2000, a decrease of $1.9 million, or 2%, reflecting the reversal of a previously recorded income tax reserve. Other income, net Other income, net was $7.9 million in 2001 compared to $7.7 million in 2000, a net decrease of $0.2 million or 2.6%. The decrease reflects the result of a one-time income item recognized in 2000 related to $4.4 million received from a third party related to the Pilgrim wholesale contract buyout. Offsetting this gain in 2000 was the allocation from NSTAR Electric & Gas of $2.7 million of income associated with the receipt of equity securities in connection with demutualization of two insurance companies in 2001 and a favorable settlement associated with a property tax reserve. Interest charges Interest on long-term debt and transition property securitization certificates was $87.5 million in 2001 compared to $98.3 million in 2000, a decrease of $10.8 million or 11%. Approximately $4.0 million of the decrease is related to securitization certificate interest reflecting the scheduled partial retirement of this debt. The decrease also reflects approximately $6.4 million in reductions related to the following retirements: $65 million of 6.8% debentures, $34 million of 9.875% debentures, $100 million of 6.05% debentures during 2000 and $24.3 million of 9.375% debentures in August 2001. Other interest charges were $11.5 million in 2001 compared to $15.9 million in 2000, a decrease of $4.4 million or 27.7%. This decrease is primarily due to a reconciliation adjustment of regulatory deferrals in conjunction with a MDTE reconciliation that resulted in the recognition of interest expense in 2000, and lower interest borrowing rates, offset by higher average short- term borrowing levels from banks. The increase in borrowing is primarily the result of financing long-term debt and preferred stock retirements with short-term borrowings and other working capital requirements. Other Matters Environmental Boston Edison is involved in approximately 15 state-regulated properties ("Massachusetts Contingency Plan, or "MCP sites") where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are uncertainties associated with the remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. In addition to the MCP sites, Boston Edison also faces possible 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. Approximately $4.8 million and $5 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2001 and 2000, respectively, related to the non- recoverable portion of these cleanup liabilities. 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 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 an 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 and as either additional sites are identified or Boston Edison's responsibilities for such sites are resolved. 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 the Boston Edison 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. 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 the results of operations for a reporting period. The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy was appealed by certain parties to the Massachusetts Supreme Judicial Court. The appeals of the AG and a separate group that consists of The Energy Consortium and Harvard University remain pending. In October 2001, the MDTE certified the record of the case to the court; however, there has to date been no briefing, hearing or other action taken with respect to this proceeding. If an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period. Regulatory Proceedings In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the AG contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on NSTAR's consolidated financial position or results of operations. 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, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current ratepayers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This charge had no material adverse effect on Boston Edison's consolidated financial position or results of operations. Employees and Employee Relations All NSTAR employees, including those of Boston Edison, are employees of NSTAR Electric & Gas. As of December 31, 2001, NSTAR had approximately 3,300 full-time employees, including approximately 2,300 or 70% of who are represented by two collective bargaining units covered by separate contracts. Effective in May 2001, all employees are employed by NSTAR Electric & Gas. As of 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 approximately 2,000 NSTAR Electric & Gas employees with a five-year contract expiring May 15, 2005 that replaced seven separate and widely diverse agreements. On March 24, 2002, Local 12004, United Steelworkers of America, AFL-CIO-CLC ratified a new four-year contract that expires on March 31, 2006. Management believes it has satisfactory employee relations with a significant majority of its employees. 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, 2001 and 2000, were as follows:
(in thousands) Weighted Carrying Fair Average 2001 Amount Value Interest Rate Long-term indebtedness $1,107,346 $1,153,380 7.15% (including current indebtedness) 2000 Mandatory redeemable cumulative preferred stock $ 49,519 $ 50,890 8.00% Long-term indebtedness $1,198,857 $1,198,695 7.16% (including current indebtedness)
The mandatory redeemable cumulative preferred stock was redeemed in total on December 3, 2001. New Accounting Principles In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). This Statement, which is effective for Boston Edison in the first quarter of 2002, establishes accounting and reporting standards for acquired goodwill and other indefinite lived intangible assets. It prohibits entities from continuing amortization of these assets. Instead, goodwill and other intangible assets will be subject to review for impairment. However, in accordance with paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the utility subsidiaries of NSTAR plan to continue amortization of this asset over its estimated regulatory recovery period including the portion allocated to Boston Edison. Boston Edison has determined that its unique regulatory rate structure, resulting from the rate plan approved by the MDTE on July 27, 1999 in connection with the formation of NSTAR, requires continued amortization of goodwill. A significant element of this rate plan includes recovery of the acquisition premium over 40 years and provides for the reasonable assurance of the existence of a regulatory asset. Also, in accordance with SFAS 142, NSTAR will transfer to Boston Edison, a reporting unit, $319 million of goodwill as a component of common equity, effective January 1, 2002. This allocation of goodwill represents the level of anticipated recovery from Boston Edison's customers. Therefore, Boston Edison's adjusted common equity as of December 31, 2001 including this adjustment would be as follows:
(in thousands) Total Common Equity as of December 31, 2001 $ 956,945 Goodwill transferred 319,048 Adjusted Common Equity as of January 1,2002 $1,275,993 ==========
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). This Statement, which is effective for fiscal years beginning after June 15, 2002, establishes accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Management is currently assessing the impact of SFAS 143 in light of its regulatory and accounting requirements. However, based on Boston Edison's assessment to date, the adoption of SFAS 143 is not expected to have a material effect on the Company's results of operations, cash flows, or financial position. As of January 1, 2001, Boston Edison adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in 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. The management of NSTAR has assessed the impact of the adoption of SFAS 133. As part of this assessment, NSTAR 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 performed extensive reviews of critical operating areas of Boston Edison and documented its procedures in applying the requirements of SFAS 133 to Boston Edison's contractual arrangements in effect on January 1, 2001. NSTAR continues its assessment on any impact that potentially may result from FASB revisions and clarifications, including, but not limited to, FASB Derivative Implementation Group Issue C15, to SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133 has not had a material effect on the Company's results of operations, cash flows, or financial position. 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. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through 2004. 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 standard offer service. The market prices for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis. 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 51, present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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 51, 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 /s/ PRICEWATERHOUSECOOPERS LLP Boston, Massachusetts January 31, 2002, (except as to Note B(2), as to which the date is March 22, 2002) Item 8. Financial Statements and Supplementary Financial Information Boston Edison Company Consolidated Statements of Income (in thousands)
Years ended December 31, 2001 2000 1999 Operating revenues $1,982,701 $1,671,846 $1,546,817 Operating expenses: Purchased power and fuel 1,159,706 839,715 645,175 Operations and maintenance 203,320 205,734 271,358 Depreciation and amortization 167,905 169,333 176,705 Demand side management and renewable energy programs 47,639 54,836 57,467 Taxes-property and other 69,777 55,905 68,826 Income taxes 93,967 95,852 91,029 Total operating expenses 1,742,314 1,421,375 1,310,560 Operating income 240,387 250,471 236,257 Other income, net 7,930 7,699 19,803 Operating and other income 248,317 258,170 256,060 Interest charges: Long-term debt 45,994 52,804 71,150 Transition property securitization certificates 41,475 45,505 20,408 Short-term and other 11,467 15,902 6,199 Allowance for borrowed funds used during construction (972) (2,069) (2,011) Total interest charges 97,964 112,142 95,746 Net income $ 150,353 $ 146,028 $ 160,314 ========== ========== ==========
Per share data is not relevant because Boston Edison Company's common stock is wholly owned by NSTAR. The accompanying notes are an integral part of the consolidated financial statements. Boston Edison Company Consolidated Statements of Comprehensive Income (Loss) (in thousands)
Years ended December 31, 2001 2000 1999 Net income $ 150,353 $ 146,028 $ 160,314 Other comprehensive (loss) income, net: Non-qualified benefit obligations 117 (117) - Comprehensive income $ 150,470 $ 145,911 $ 160,314 ========= ========= ========= Boston Edison Company Consolidated Statements of Retained Earnings (in thousands) Years ended December 31, 2001 2000 1999 Balance at the beginning of the year $ 352,832 $ 1,462 $ 297,347 Add: Net income 150,353 146,028 160,314 Dividends transferred from paid in - 226,541 - capital (a) Subtotal 503,185 374,031 457,661 Deduct: Dividends declared: Dividends to Parent 68,927 15,000 450,000 Preferred stock 5,627 5,960 5,960 Subtotal 74,554 20,960 455,960 Provision for preferred stock redemption and issuance costs 481 239 239 Balance at the end of year $ 428,150 $ 352,832 $ 1,462 ========= ========= ========
(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 the Company's sole shareholder, was a partial distribution of a return of capital. As a result, the Company has transferred the portion of its dividends deemed return of capital against Premium on Common Stock. The accompanying notes are an integral part of the consolidated financial statements. Boston Edison Company Consolidated Balance Sheets (in thousands)
The accompanying notes are an integral part of the consolidated financial statements. Boston Edison Company Consolidated Statements of Cash Flows (in thousands)
Years ended December 31, 2001 2000 1999 Operating activities: Net income $ 150,353 $ 146,028 $ 160,314 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 167,905 161,371 188,078 Deferred income taxes and (51,242) 86,962 99,504 investment tax credits Power contract buyout - - (65,781) Allowance for borrowed funds used (972) (2,069) (2,011) during construction Net changes in: Accounts receivable and accrued (26,356) 13,556 (50,736) unbilled revenues Fuel, materials and supplies 160 605 (1,387) Accounts payable 102,292 128,753 (49,084) Other current assets and liabilities (194,582) (363,521) (77,628) Other, net 58,727 14,991 27,828 Net cash provided by operating activities 206,285 186,676 229,097 Investing activities: Plant expenditures (excluding AFUDC) (138,565) (110,437) (125,419) Costs of nuclear divestiture and fuel - - (103,366) expenditures, net Investments 11,500 4,368 (6,301) Net cash used in investing activities (127,065) (106,069) (235,086) Financing activities: Capital contribution 43,937 - - Long-term debt - - 725,000 Redemptions: Preferred stock (50,000) - - Long-term debt (91,513) (251,559) (203,214) Net change in notes payable 95,000 96,500 - Dividends paid (75,220) (30,960) (480,960) Net cash (used in) provided by financing (77,796) (186,019) 40,826 activities Net increase (decrease) in cash and cash 1,424 (105,412) 34,837 equivalents Cash and cash equivalents at the 12,125 117,537 82,700 Cash and cash equivalents at the end of $ 13,549 $ 12,125 $ 117,537 the year ========== ========== ========== Supplemental disclosures of cash flow information: Interest, net of amounts capitalized $ 91,007 $ 105,735 $ 76,926 Income taxes (refunded) paid $ 164,194 $ (47,312) $ 87
The accompanying notes are an integral part of the consolidated financial statements. 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 subsidiary of NSTAR. NSTAR is Massachusetts' largest investor-owned combined electric and gas utility and is an exempt public utility holding company. NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 246,000 gas customers in 51 communities. Boston Edison serves approximately 681,000 electric customers in the city of Boston and 39 surrounding communities. NSTAR's retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas). 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 1.6 million. In 2001, 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 (SFAS) 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. In 2000, 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 FERC and the MDTE. 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. 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. The overall composite depreciation rates were 2.87%, 2.99% and 3.31% in 2001, 2000 and 1999, 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 2001, 2000 and 1999 were 4.14%, 6.00% and 5.82%, 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. These funds are available to pay the principal and interest on the transition property securitization certificates. 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. Regulatory assets consisted of the following: (in thousands)
2001 2000 Generation-related regulatory $ 559,712 $ 559,121 assets, net Purchased power costs (2,498) 193,641 Costs to achieve 79,227 71,823 Power contracts 22,697 25,868 Income taxes, net 62,070 64,775 Postretirement benefits costs 7,217 12,040 Redemption premiums 12,853 14,403 Other 27,498 32,944 Total regulatory assets $ 768,776 $ 974,615 ========= =========
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. Boston Edison participates in several corporate joint ventures in which it has investments, principally its 11.1% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec System in Canada, and its equity investments both of 9.5% in two regional nuclear generating facilities that are currently being decommissioned. 12. Related Party Transactions The accompanying Consolidated Balance Sheets include an Accounts payable of $277,400 and an Accounts receivable of $13.7 million as of December 31, 2001 and 2000, respectively, from NSTAR Communications, Inc., an affiliate. These balances represent the construction and construction management services provided by Boston Edison and its contractors. Additionally, the December 31, 2001 Consolidated Balance Sheet includes a net payable of $45.4 million to NSTAR Electric & Gas, for management and support services. The December 31, 2001 Consolidated Balance Sheet also includes a $3.9 million receivable from affiliate BETG associated with the MDTE ruling in the BETG proceeding. Boston Edison's goodwill amortization expense allocation from its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $8 million for 2001. 13. Amortization of Goodwill and Costs to Achieve 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. 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. Boston Edison's share of goodwill and costs to achieve are approximately $319 million and $72 million, respectively. Total 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, 2001, 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. Refer to the following Item 14 "New Accounting Principles" for a further discussion of goodwill. 14. New Accounting Principles In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). This Statement, which is effective for Boston Edison in the first quarter of 2002, establishes accounting and reporting standards for acquired goodwill and other indefinite lived intangible assets. It prohibits entities from continuing amortization of these assets. Instead, goodwill and other intangible assets will be subject to review for impairment. However, in accordance with paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the utility subsidiaries of NSTAR plan to continue amortization of this asset over its estimated regulatory recovery period including the portion allocated to Boston Edison. Boston Edison has determined that its unique regulatory rate structure, resulting from the rate plan approved by the MDTE on July 27, 1999 in connection with the formation of NSTAR, requires continued amortization of goodwill. A significant element of this rate plan includes recovery of the acquisition premium over 40 years and provides for the reasonable assurance of the existence of a regulatory asset. Also, in accordance with SFAS 142, NSTAR will transfer to Boston Edison, a reporting unit, $319 million of goodwill as a component of common equity, effective January 1, 2002. This allocation of goodwill represents the level of anticipated recovery from Boston Edison's customers. Therefore, Boston Edison's adjusted common equity as of December 31, 2001 including this adjustment would be as follows:
(in thousands) Total Common Equity as of December 31, 2001 $ 956,945 Goodwill transferred 319,048 Adjusted Common Equity as of January 1, 2002 $1,275,993 ==========
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). This Statement, which is effective for fiscal years beginning after June 15, 2002, establishes accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Management is currently assessing the impact of SFAS 143 in light of its regulatory and accounting requirements. However, based on Boston Edison's assessment to date, the adoption of SFAS 143 is not expected to have a material effect on the Company's results of operations, cash flows, or financial position. As of January 1, 2001, Boston Edison adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in 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. The management of NSTAR has assessed the impact of the adoption of SFAS 133. As part of this assessment, NSTAR 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 performed extensive reviews of critical operating areas of Boston Edison and documented its procedures in applying the requirements of SFAS 133 to Boston Edison's contractual arrangements in effect on January 1, 2001. NSTAR continues its assessment on any impact that potentially may result from FASB revisions and clarifications, including, but not limited to, FASB Derivative Implementation Group Issue C15, to SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133 has not had a material effect on the Company's results of operations, cash flows, or financial position. Note B. Electric Utility Industry Restructuring 1. Accounting Implications Under the traditional revenue requirements model, electric rates are based on the cost of providing electric service. Under this traditional model, Boston Edison is 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 through 2016 and is subject to adjustment by the MDTE. b.) Standard offer and default service charge Customers have the option of continuing to buy power from Boston Edison at standard offer prices through 2004. In December 2000, the MDTE approved a standard offer fuel index of 1.321 cents per kilowatt-hour (kWh) that was added to Boston Edison's standard offer service rates for the first-half of 2001. In June 2001, the MDTE approved an additional increase of 1.23 cents per kWh effective July 1, 2001 based on a fuel adjustment formula contained in its standard offer tariffs to reflect the prices of natural gas and oil. In December 2001, the MDTE approved a decrease in this fuel index of 1.125 cents to 1.426 cents per kWh for the first quarter of 2002 based on a decrease in the cost of fuel. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act. 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. c.) 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. The cost of providing transmission service to distribution customers is recovered on a fully reconciling basis plus an approved return. 2. Service Quality Index On October 29, 2001, and as subsequently updated, NSTAR Electric, including Boston Edison, filed with the MDTE proposed service quality plans for each company, which replaced the service quality plan that had previously been filed as a part of the NSTAR merger rate plan and includes guidelines that had been established by the MDTE as a result of its generic investigation of service quality issues. The service quality plans established performance benchmarks effective January 1, 2002 for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance. The companies are required to report annually concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks. On October 29, 2001, NSTAR Electric also filed with the MDTE a report concerning their performance on the identified service quality measures for the two twelve-month periods ended August 31, 2000 and 2001. This report included a calculation of penalties in accordance with MDTE guidelines whereby penalties were calculated totaling approximately $3.9 million relating primarily to Boston Edison's electric system reliability performance for the summer of 2001. NSTAR disputes the legal applicability of penalties for these performance periods; however, NSTAR proposed in settlement of this matter to provide credits to Boston Edison customers totaling $3.9 million, offset in part by other payments to Boston Edison customers, which totaled approximately $1 million, relating to summer 2001 electric service outages. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.2 million to be refunded to customers as a credit to their bills in 2002. Also on October 29, 2001, NSTAR Electric, including Boston Edison, filed with the MDTE a comprehensive report regarding electric system performance issues encountered during the summer of 2001. The filing included detailed analyses of factors affecting performance, as well as, the companies' plans to address issues identified. The MDTE also requested similar filings from other Massachusetts electric distribution companies and has held public hearings and will hold adjudicatory hearings concerning each such filing. On January 30, 2002, the AG and the Massachusetts Division of Energy Resources (DOER) filed comments urging the MDTE to assess the maximum penalties allowed pursuant to the established service quality benchmarks and to require an independent management audit as a result of alleged service quality deficiencies. On February 6, 2002, NSTAR Electric filed its brief arguing against the AG's and DOER's positions. On March 22, 2002, following a number of public hearings throughout the NSTAR Electric service area, the MDTE issued an order finding that NSTAR Electric had made progress in addressing the issues which initiated the investigation and requiring that NSTAR Electric submit further updated reports on specific issues on a quarterly and annual basis. Boston Edison is unable to estimate its ultimate liability for future costs or penalties as a result of any further filings relating to this investigation. However, in view of Boston Edison's current assessment of its electric distribution system performance responsibilities, existing legal requirements and regulatory policies, management believes it would not have a material effect on Boston Edison's consolidated financial position, cash flows or results of operations for a reporting period. Note C. Income Taxes Income taxes are accounted for in accordance with SFAS 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 $62.1 million and $64.8 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2001 and 2000, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 2001 2000 Deferred tax liabilities: Plant-related $ 211,506 $ 202,475 Transition costs 233,465 291,222 Other 154,148 257,619 599,119 751,316 Deferred tax assets: Investment tax credits 12,423 12,150 Other 29,015 148,526 41,438 160,676 Net accumulated deferred $ 557,681 $ 590,640 income taxes ======== ========
Previously deferred investment tax credits are amortized over the estimated remaining lives of the property giving rise to the credits. Components of income tax expense were as follows:
Years ended December 31, (in thousands) 2001 2000 1999 Current income tax expense (benefit) $ 144,779 $ 8,890 $(29,306) Deferred income tax (benefit)expense (49,715) 87,953 122,584 Investment tax credit amortization (1,097) (991) (2,249) Income taxes charged to operations 93,967 95,852 91,029 Current tax expense (benefit)on other income (deductions), net 3,607 5,046 (22,465) Total income tax expense $ 97,574 $100,898 $ 68,564 ======== ======= =======
The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
2001 2000 1999 Statutory tax rate 35.0% 35.0% 35.0% State income tax, net of federal income tax benefit 4.4 4.4 4.3 Investment tax credit amortization (0.4) (0.4) (10.1) Other 0.4 1.8 0.8 Effective tax rate 39.4% 40.8% 30.0% ===== ===== =====
Income tax expense is reflected net of $20.8 million in 1999 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%. Note D. Pension and Other Postretirement Benefits 1. Pension Effective January 1, 2000, the pension plans of BEC and COM/Energy were combined under NSTAR to form the NSTAR Pension Plan (the Plan). Since the merger date and following the renaming of the plans, Boston Edison has remained the sponsor of the Plan. The Company participates with other subsidiaries of NSTAR in the noncontributory Plan, with certain limited contributory features, that covers substantially all employees of NSTAR Electric & Gas. Effective January 1, 2000, the defined benefit plan was 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. It is the Company's policy to fund the Plan in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974 The Company also maintains unfunded supplemental retirement plans for certain management employees of NSTAR Electric & Gas. Consistent with the transfer of all Boston Edison employees to NSTAR Electric & Gas, the liability for its supplemental retirement plan has also been transferred accordingly effective December 31, 2001. The changes in the benefit obligation and plan assets were as follows:
December 31, (in thousands) 2001 2000 Change in benefit obligation: Benefit obligation, beginning of the year $ 804,358 $ 800,084 Transfer of obligation to affiliate company (14,067) - Service cost 13,727 14,636 Interest cost 56,418 59,798 Plan participants' contributions 71 81 Plan amendments - (4,387) Actuarial loss 14,091 59,815 Settlement payments (16,573) (77,256) Benefits paid (47,508 (48,413) ) Benefit obligation, end of the year $ 810,517 $ 804,358 ========= =========
Change in plan assets: 2001 2000 Fair value of plan assets, beginning of the $ 846,207 $ 955,498 year Actual loss on plan assets, net (52,493) (28,041) Employer contribution 61,000 44,338 Plan participants' contributions 71 81 Settlement payments (16,573) (77,256) Benefits paid (47,508) (48,413) Fair value of plan assets, end of the year $ 790,704 $ 846,207 ========= =========
The plan's funded status was as follows:
December 31, (in thousands) 2001 2000 Funded status $ (33,598) $ 41,849 Liability transfer to affiliate company 13,785 Unrecognized actuarial net loss 246,708 104,817 Unrecognized transition obligation 1,581 2,182 Unrecognized prior service cost (9,762) (3,340) Net amount recognized $ 218,714 $ 145,508 ========= =========
Amounts recognized in the Consolidated Balance Sheets consisted of:
2001 2000 (in thousands) Prepaid retirement cost $ 218,714 $ 149,890 Accrued supplemental retirement liability - (13,306) Intangible asset - 7,285 Accumulated other comprehensive income - 1,639 Net amount recognized $ 218,714 $ 145,508 ========= =========
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 $0, $0 and $0, respectively, as of December 31, 2001, and $14,067,000, $13,306,000 and $0, respectively, as of December 31, 2000. Weighted average assumptions were as follows:
2001 2000 1999 Discount rate at the end of the year 7.25% 7.50% 8.00% Expected return on plan assets for the year (net of investment expenses) 9.40% 9.30% 9.00% Rate of compensation increase at the end of the year 4.00% 4.00% 4.00%
Components of net periodic benefit (income)/cost were as follows:
>C> (in thousands) 2001 2000 1999 Service cost $ 14,027 $ 14,636 $ 13,137 Interest cost 57,050 59,798 31,658 Expected return on plan assets (78,397) (85,884) (41,295) Amortization of prior service cost (118) 448 1,610 Amortization of transition obligation 601 601 664 Recognized actuarial loss 775 - 3,754 Net periodic benefit (income)/cost $(6,062) $(10,401) $ 9,528 ========= ========= ========
Certain postretirement health care benefits are eligible to certain active NSTAR Electric & Gas employees and certain retired non-union employees in conjunction with the NSTAR postretirement plan. Pursuant to the Internal Revenue Code, the Company has the benefits through a 401(h) subaccount of the Pension Plan, subject to certain conditions and limitations. Assets in the trust beyond those in the 401(h) subaccount must be used to pay pension benefits and cannot be used to pay postretirement health care benefits. Assets included in the 401(h) subaccount must only be used for postretirement health care benefits. 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 are a component of Regulatory assets on the accompanying Consolidated Balance Sheets. The previous amounts resulting from the merger-related separation agreements and generation divestitures are recoverable as part of the approved rate plans of the Boston Edison settlement agreement. The Company, as the sponsor of the plan, allocated net expenses and were reimbursed by its affiliated companies of $1,159,000 and $2,644,000 in 2001 and 2000, respectively. 2. Savings Plan Boston Edison also participates in a defined contribution 401(k) plan for substantially all employees NSTAR Electric & Gas. 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 2001, $4 million in 2000 and $8 million in 1999. The plan was amended, effective April 1, 2001, to allow participants the ability to reallocate their investments in NSTAR shares to other investment options. 3. 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. On January 1, 2000, other postretirement benefit plans of Boston Edison and COM/Energy were combined under NSTAR. On December 1, 2001, the investments previously held by those plans were combined into two voluntary employees' beneficiary association (VEBA) trusts. The COM/Energy Post-Retirement Benefits Plans merged with and were consolidated into the Group Welfare Benefits Plan for Retirees of Boston Edison, which was then renamed the Group Welfare Benefits Plan for Retirees of NSTAR and was transferred to NSTAR in 2001. To fund postretirement benefits, Boston Edison makes contributions to various VEBA trusts that were established pursuant to section 501(c)(9) of the Internal Revenue Code. The funded status of the Plan for 2001 cannot be presented separately for the Company since the Company participates in the Plan trusts with other subsidiaries of NSTAR. Plan assets are available to provide benefits for all Plan participants who are former employees of the Company and of other subsidiaries of NSTAR. The net periodic postretirement benefit cost allocated to the Company was $14,096,000 and $12,732,000 in 2001 and 2000, respectively. The accrued benefit cost in the Company's statement of financial position was $0 and $16,982,000 at December 31, 2001 and 2000, respectively. As a result of the Company participating in a single NSTAR sponsored plan effective January 1, 2000 where the assets are held in the two VEBA trusts for the exclusive benefit of Plan participants, the Company no longer reflects any plan assets or liabilities. For 2000, the changes in benefit obligation and plan assets were as follows:
(in thousands) 2000 Change in benefit obligation: Benefit obligation, beginning of the year $ 221,415 Service cost 2,100 Interest cost 17,816 Plan participants' contributions 754 Plan amendments 5,419 Actuarial loss/(gain) 22,129 Curtailment loss - Settlement payments - Benefits paid (14,024) Benefit obligation, end of the year $ 255,609 =========
Change in plan assets: Fair value of plan assets, beginning of the year 119,838 Actual (loss)/return on plan assets (12,276) Employer contribution 53,407 Plan participants' contributions 754 Settlement payments - Benefits paid (14,024) Fair value of plan assets, end of the year $ 147,699 =========
The plans' funded status and amount recognized in the accompanying Consolidated Balance Sheets were as follows:
(in thousands) 2000 Funded status $(107,910) Unrecognized actuarial net loss/(gain) 36,907 Unrecognized transition obligation 67,400 Unrecognized prior service cost (13,378) Net amount recognized $ (16,981) =========
Weighted average assumptions were as follows:
2000 1999 Discount rate at the end of the year 7.50% 8.00% Expected return on plan assets for the year 9.00% 9.00%
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. Components of net periodic benefit cost were as follows:
(in thousands) 2000 1999 Service cost $ 2,100 $ 4,043 Interest cost 17,816 17,848 Expected return on plan assets (11,234) (10,107) Amortization of prior service cost (1,566) (683) Amortization of transition obligation 5,616 6,162 Recognized actuarial loss - 957 Net periodic benefit cost $ 12,732 $ 18,220 ======== ========
Note E. Capital Stock
(dollars in thousands, except per share 2001 2000 amounts) Common equity: Common stock, par value $1 per share, 100,000,000 shares authorized; 100 shares issued and outstanding $ - $ - Premium on common stock 528,795 482,004 Retained earnings 428,150 352,832 Total common equity $ 956,945 $ 834,836 ======== ========
Cumulative Preferred Stock (in thousands, except per share amounts) Par value $100 per share, 2,660,000 shares authorized and 430,000 issued and outstanding: Non-mandatory redeemable series:
Current Shares Redemption December 31, Series Outstanding Price/Share 2001 2000 4.25% 180,000 $103.625 $18,000 $18,000 4.78% 250,000 $102.80 25,000 25,000 Total non-mandatory redeemable series 43,000 43,000
Mandatory redeemable series:
Current Shares Redemption Series Outstanding Price/Share 8.00% 500,000 $100.00 - 50,000 Less redemption and issuance costs - 481 Total mandatory redeemable series - 49,519 43,000 92,519 Less amount due within one year - 49,519 Total cumulative preferred stock $43,000 $43,000 ======= =======
The 8% series was redeemed in total on December 3, 2001, plus accrued dividends from November 1, 2001 to December 1, 2001. 1. Common Shares Common shares issuances and repurchases in 1999 through 2001 were as follows:
Common Shares Number of (in thousands) Shares Par Value Premium Balance at December 31,1998 - $ - $742,544 Reclassification of retained earnings at merger (25,000) Stock incentive plan (1,183) Balance at December 31, 1999 - - 716,361 Reclassification of return of capital dividends (a) (226,541) Return of capital dividends (10,000) Merger of COM/Energy's pension plan 6,283 Stock incentive plan (4,099) Balance at December 31, 2000 - - $ 482,004 Capital Contribution 43,937 Benefits and other 2,854 Balance at December 31, 2001 - $ - $ 528,795 ======= ========= =========
(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. Note F. Indebtedness
December 31, (in thousands) 2001 2000 Long-term debt Debentures: 6.80%, due March 2003 $ 150,000 $ 150,000 7.80%, due May 2010 125,000 125,000 9.375%, due August 2021 - 24,270 8.25%, due September 2022 60,000 60,000 7.80%, due March 2023 181,000 181,000 Sewage facility revenue bonds, due 21,470 23,014 through 2015 Massachusetts Industrial Finance Agency (MIFA) bonds: 5.75%, due February 2014 15,000 15,000 Transition Property Securitization Certificates: 5.99%, due March 2003 - 4,073 6.45%, due through September 2005 108,986 170,610 6.62%, due March 2007 103,390 103,390 6.91%, due September 2009 170,876 170,876 7.03%, due March 2012 171,624 171,624 1,107,346 1,198,857 Amounts due within one year (41,6 39) (37,109) Total long-term debt $ 1,065,707 $ 1,161,748 =========== ===========
1. Long-term Debt The 9.375% series due 2021 was redeemed 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 2001 and 2000. The weighted average interest rate of the bonds was 7.4%. 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 has approval from the MDTE to issue from time to time up to $500 million of debt securities through 2002. In connection with this, 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 SEC declared the registration statement effective 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. No issuance of debt securities were made during 2001 under this authorization. The aggregate principal amounts of Boston Edison's long-term debt (including securitization certificates and HEEC sinking fund requirements) due in the five years subsequent to 2001 are approximately $41.6 million in 2002, $219.7 million in 2003, $70.4 million in 2004, $70.1 in 2005 and $70.3 in 2006. Boston Edison has no covenant requirements under its long-term debt arrangements. 2. Short-term Debt Boston Edison has approval from the FERC to issue up to $350 million of short-term debt. Boston Edison has a $300 million revolving credit agreement with a group of banks effective through December 2002. At December 31, 2001 and 2000, there were no amounts outstanding under this revolving credit agreement. This arrangement serves as back-up to Boston Edison's $300 million commercial paper program that, at December 31, 2001 and 2000, had outstanding $191.5 million and $96.5 million, respectively. Under the terms of this agreement, Boston Edison is required to maintain a common equity ratio of not less than 30% at all times. Interest rates on the outstanding borrowings generally are money market rates and averaged 4.14% and 6.61% in 2001 and 2000, respectively. Commitment fees must be paid on the total agreement amount. Separately, Boston Edison, effective July 20, 2001, has an additional $50 million line of credit with no outstanding amounts at December 31, 2001. 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: 1. Cash and Cash Equivalents The carrying amount of $14 million and $12 million, for 2001 and 2000, respectively, approximates fair value due to the short-term nature of these securities. 2. Mandatory Redeemable Cumulative Preferred Stock and Unsecured Debt (Excluding Notes Payable) The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 2001 and 2000 were as follows:
2001 2000 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Mandatory redeemable cumulative preferred stock - - $ 49,519 $ 50,890 Long-term unsecured debt $1,107,346 $1,153,380 $1,198,857 $1,198,695 (including current maturities)
Note H. Commitments and Contingencies 1. Contractual Commitments Boston Edison also has leases for certain facilities and equipment. The estimated minimum rental commitments under non- cancelable capital and operating leases for the years after 2001 are as follows:
(in thousands) 2002 $ 14,244 2003 11,634 2004 10,978 2005 10,870 2006 10,126 Years thereafter 43,936 Total $ 101,788 =========
The total expense for both lease rentals and transmission agreements was $57.1 million in 2001, $45.3 million in 2000 and $38.7 million in 1999, net of capitalized expenses of $2.3 million in 2001, $1.7 million in 2000 and $1.5 million in 1999. 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 obligations of those participants who do not meet certain credit criteria. At December 31, 2001, Boston Edison's portion of these guarantees was $10.9 million. New England Hydro-Transmission Electric Company, Inc. (NEH) and New England Hydro-Transmission Corporation (NHH) have agreed to use their best efforts to limit their equity investment to 40% of their total capital during the time NEH and NHH have outstanding debt in their capital structure. In order to meet its best efforts obligation pursuant to the Equity Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in September 2001, NEH repurchased a total of 250,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,100 outstanding shares from all equity holders. Through December 31, 2001, Boston Edison's reduction of its equity ownership resulting from NEH buy-back of 27,627 shares and NHH buy-back of 122 shares was approximately $622,000. Boston Edison has a 9.5% equity investment 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. As of December 31, 2001, this program was completed and 145,730 shares were redeemed. Boston Edison's reduction of its equity ownership resulting from the buy-back of 13,844 shares was approximately $1.4 million. Boston Edison also has a 9.5% equity investment in the Connecticut Yankee Atomic Power Company (CYAPC) unit that has been retired. Boston Edison's share of CYAPC remaining investment and estimated costs of decommissioning is approximately $23 million as of December 31, 2001. This estimate was 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. During April 2000, CYAPC signed settlement agreements with the major intervening parties in the 1996 FERC rate case. CYAPC received final FERC approval related to the settlement agreements and revised rates went into effect September 1, 2000. CYAPC received FERC approval on September 11, 2000, regarding the decommissioning collections, a return on equity of 6% and full recovery of assets. 3. Environmental Matters Boston Edison is involved in approximately 15 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 properties due to the final method of cleanup and site-specific characteristics. 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 $4.8 million is included in the Consolidated Balance Sheets as of December 31, 2001 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 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 1998 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 and the results of operations for a reporting period. Regulatory proceedings In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the AG contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on Boston Edison's consolidated financial position or results of operations. 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, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current customers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This change had no material adverse effect on Boston Edison's consolidated financial position or results of operations. Other legal matters 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 in the near term. Note I. Long-Term Power Contracts Long-Term Contracts for the Purchase of Electricity NSTAR Electric has existing long-term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of short-term power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders. Capacity costs of long-term contracts reflect Boston Edison's proportionate share of capital and fixed operating costs of certain generating units. In 2001, these costs were attributed to 892 MW of capacity purchased. Energy costs are paid to generators based on a price per kWh actually received into Boston Edison's distribution system and are included in the total cost. Total capacity purchased in 2001 was 1,362 MW. Information related to long-term power contracts as of December 31, 2001 was as follows:
Proportionate share (in thousands) Range of Units of Capacity Charge Contract Capacity 2001 2001 Obligation Fuel Type of Exploration Purchased Capacity Total Through Contract Generating Unit Dates % Range Total Cost Cost Expiration Date MW Natural Gas 2010-2015 23.5-46.5 480 $68,397 $241,294 $ 951,916 Nuclear 2004 78 673 - 141,402 - Oil 2002-2019 25-100 209 11,004 32,656 58,842 1,362 $79,401 $415,352 $1,010,758 ===== ======= ======== ==========
NSTAR Electric entered into six-month agreements effective January 1, 2001 through June 30, 2001 and July 1, 2001 through December 31, 2001 with suppliers to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. NSTAR Electric's existing portfolio of power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2001, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric managed its Independent System Operator- New England Power capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. Boston Edison's total capacity and energy costs associated with these contracts in 2001, 2000 and 1999 were approximately $415 million, $428 million and $315 million, respectively. Boston Edison's capacity charge obligation under these contracts for the years after 2001 is as follows:
Capacity (in thousands) Charge Obligation 2002 $ 86,683 2003 84,288 2004 84,055 2005 85,589 2006 86,913 Years thereafter 583,230 Total $1,010,758 ==========
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) The following documents are filed as part of this Form 10-K:
1. Financial Statements: Page Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 26 Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999 27 Consolidated Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999 27 Consolidated Balance Sheets as of December 31, 2001 28 and 2000 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 29 Report of Independent Accountants 25 Notes to Consolidated Financial Statements 30 2. Financial Statement Schedules: Schedule II Valuation and Qualifying Accounts - For the Years Ended December 31, 2001, 2000 and 1999 58 3. Exhibits: Refer to the exhibits listing beginning on the 51 following page
(b) Reports on Form 8-K None Incorporated herein by reference:
(S> Exhibit SEC Docket Exhibit 3 Articles of Incorporation and By- Laws 3.1 Restated Articles of 3.1 1-2301 Organization Form 10-Q for the quarter ended June 30, 1994. 3.2 Boston Edison Company Bylaws 3.1 1-2301 April 19, 1977, as amended January Form 10-Q for 22, 1987, January 28, 1988, May 24, the quarter 1988 and November 22, 1989 ended June 30, 1994. Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.1 Debt Securities issued under Form S-3 - an Indenture between Boston Registration Edison Company and The Bank Statement, of New York (as successor to filed Bank of Montreal Trust Company) February 3, 1993, File No.33- 57840. 4.2 Indentures of Trust and Agreement 4.1.26 1-2301 among the City of Boston, Form 10-K for Massachusetts (acting by and the year through its Industrial Development ended Financing Authority) and Harbor December 31, Electric Energy Company and Shawmut 1991. Bank, N.A., as Trustees dated November 1, 1991. 4.4 Revolving Credit Agreement 4.1.24 1-2301 dated February 12, 1993. Form 10-K for the year ended December 31, 1992. 4.4.1 First Amendment to Revolving 4.1.10 1-2301 Credit Agreement dated May Form 10-K for 19, 1995 the year ended December 31, 1995. 4.4.2 Second Amendment to Revolving 4.1.4.2 1-2301 Credit Agreement dated July Form 10-K for 1, 1997 the year ended December 31, 1997. 4.5 Votes of the Pricing Committee 4.1.25 1-2301 of the Board of Directors of Boston Form 10-K for Edison Company taken September 10, the year 1992 re 8 % debentures due ended September 15, 2022. December 31, 1992. 4.6 Votes of the Pricing Committee of 4.1.27 1-2301 the Board of Directors of Boston Form 10-K for Edison Company taken March 5, 1993 the year re 6.80% debentures due March ended 15,2003, 7.80% debentures due December 31, March 15, 2023 1992. 4.7 Votes of the Pricing Committee of 4.1.5 1-2301 the Board of Directors of Boston Form 10-K for Edison Company taken May 18, 1995 the year re 7.80% debentures due May 15, ended 2010. December 31, 1995. 4.9 Debt Securities to be issued on a Form S-3 - delayed or continuous basis under Registration an Indenture between Boston Edison Statement, Company and The Bank of New York dated (as successor to Bank of Montreal February 20, Trust Company) 2001, File No. 333- 55890. Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of the Registrant defining the rights of holders of any long-term debt whose authorization does not exceed 10% of total assets. Exhibit 10 Material Contracts 10.1 Boston Edison Company Restructuring 10.12 1-2301 Settlement Agreement dated July 1997 Form 10-K for the year ended December 31, 1997. 10.2 Boston Edison Company and Sithe 10.1 1-2301 Energies, Inc. Purchase and Sale Form 10-Q for and Transition Agreements dated the quarter December 10, 1997. ended March 31, 1998. 10.3 Boston Edison Company and Entergy 10.12 1-2301 Nuclear Generation Company Purchase Form 10-K for and Sale Agreement dated November the year 18, 1998. ended December 31, 1999. 10.4 NSTAR Excess Benefit Plan effective 10.1 1-14768 August 25, 1999. (NSTAR) Form 10-K/A for the year ended December 31, 1999. 10.5 NSTAR Supplemental Executive 10.2 1-14768 Retirement Plan effective August (NSTAR) 25, 1999. Form 10-K/A for the year ended December 31, 1999. 10.6 Special Supplemental Executive 10.3 1-14768 Retirement Agreement between Boston (NSTAR) Edison Company and Thomas J. May Form 10-K/A dated March 13, 1999, regarding Key for the year Executive Benefit Plan and ended Supplemental Executive Retirement December 31, Plan. 1999. 10.7 Key Executive Benefit Plan 10.4 1-14768 Agreement dated as of October 1, (NSTAR) 1983 between Boston Edison Company Form 10-K/A and Thomas J. May. for the year ended December 31, 1999. 10.8 Change in Control Agreement between 10.9 1-14768 NSTAR and Thomas J. May dated May (NSTAR) 11, 1999. Form 10-K/A for the year ended December 31, 1999. 10.9 NSTAR Deferred Compensation Plan 10.12 1-14768 (Restated Effective August 25, (NSTAR) 1999). Form 10-K/A for the year ended December 31, 1999. 10.10 NSTAR 1997 Share Incentive Plan, as 10.14 1-14768 amended June 30, 1999 and assumed (NSTAR) by NSTAR effective August 28, 2000. Form 10-Q for the quarter ended September 30, 2000. 10.11 Amended and Restated Change in 10.9 NSTAR Form Control Agreement between James J. 10-K for the Judge and NSTAR, dated November 1, year ended 2001. December 31, 2001, File No. 1-14768. 10.12 Amended and Restated Change in 10.12 NSTAR Form Control Agreement between Douglas 10-K for the S. Horan and NSTAR, dated November 1, year ended 2001. December 31, 2001, File No. 1-14768. 10.13 Amended and Restated Change in 10.13 NSTAR Form Control Agreement between Joseph R. 10-K for the Nolan, Jr. and NSTAR, dated year ended November 1, 2001. December 31, 2001, File No. 1-14768. 10.14 Amended and Restated Change in 10.14 NSTAR Form Control Agreement between Eugene J. 10-K for the Zimon and NSTAR, dated November 1, year ended 2001. December 31, 2001, File No. 1-14768. 10.15 Amended and Restated Change in 10.15 NSTAR Form Control Agreement between Werner J. 10-K for the Schweiger and NSTAR, dated March 1, year ended 2002. December 31, 2001, File No. 1-14768. 10.16 Master Trust Agreement between 10.5 NSTAR Form NSTAR and State Street Bank and 10-Q for the Trust Company (Rabbi Trust), dated quarter ended August 25, 1999 September 30, 2000, File No. 1-14768. 10.17 Employment Agreement between Thomas NSTAR Form S- J. May and NSTAR dated May 11, 1999 4, Annex A, (Incorporated by reference to Annex) Dated May 11, 1999, File No. 333-78285. 10.18 NSTAR Trustees' Deferred Plan 10.4 NSTAR Form (Restated Effective August 25, 10-Q for the 1999), dated October 20, 2000 quarter ended September 30, 2000, File No. 1-14768. Filed herewith: Exhibit 12 Statement to Computation of Ratios 12.1 Computation of Ratio of Earnings to Form 10-K for Fixed Charges for the Year Ended the year December 31, 2001 ended December 2001. File No. 1-2301 12.2 Computation of Ratio of Earnings to Form 10-K for Fixed Charges and Preferred Stock the year Dividend Requirements for the Year ended Ended December 31, 2001 December 31, 2001. File No. 1-2301 Incorporated herein by reference: Exhibit 21 Subsidiaries of the Registrant 21.1 Harbor Electric Energy Company Form 10-K for (incorporated in Massachusetts), a the year wholly owned subsidiary of Boston ended Edison Company December 31, 1999. File No. 1-2301 Filed herewith: Exhibit 23 Consent of Independent Accountants 23.1 Consent of Independent Accountants Form 10-K for to incorporate by reference their the year opinion included with this Form ended 10-K in the Form S-3 Registration December 31, Statements filed by Boston Edison 2000. Company on February 1, 1993 (File File No. No. 33-57840) and February 20, 2001 1-2301 (File No. 333-55890). Incorporated herein by reference: Exhibit 99 Additional Exhibits 99.1 Settlement Agreement between Boston 28.1 Form 8-K Edison Company and Commonwealth dated Electric Company, Montaup Electric December 21, Company the Municipal Light 1989. Department of the Town of Reading, File No. Massachusetts, dated January 5,1990. 1-2301 99.2 Settlement Agreement Between Boston 28.2 Form 10-Q for Edison Company and City of Holyoke the quarter Gas and Electric Department et. ended March 31, Al., dated April 24, 1990. 1990. File No. 1-2301 99.3 Information required by SEC Form Form 10-K/A 11-K for certain employee benefit Amendments to plans for the years ended December Form 10-K for 31, 1996 and 1995. the years ended December 31, 1996 and 1995 dated June 26, 1997 and June 27, 1996 respectively. File No. 1-2301
SCHEDULE II BOSTON EDISON COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 and 1999 (in thousands)
Balance at Provisions Deductions Balance Beginning Charged to Accounts At End Description Of Year Operations Recoveries Written Off Of Year Year Ended December 31, 2001 Allowance for Doubtful Accounts $22,415 $13,000 $ 2,089 $ 12,813 $24,691 Year Ended December 31, 2000 Allowance for Doubtful Accounts $19,380 $11,954 $ 471 $(9,38 0) $22,415 Year Ended December 31, 1999 Allowance for Doubtful Accounts $ 9,071 $22,649 $ 4,356 $(16,696) $19,380
FORM 10-K BOSTON EDISON COMPANY DECEMBER 31, 2001 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BOSTON EDISON COMPANY (Registrant)
Date: March 28,2002 By: /s/ JAMES J. JUDGE James J. Judge, Senior Vice President, Treasurer and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Principal Executive Officer:
/s/ THOMAS J. MAY March 28, 2002 Thomas J. May, Chairman of the Board, President and Chief Executive Officer Principal Financial Officer: /s/ JAMES J. JUDGE March 28, 2002 James J. Judge, Senior Vice President, Treasurer and Chief Financial Officer Principal Accounting Officer: /s/ ROBERT J. WEAFER, JR. March 28, 2002 Robert J. Weafer, Jr., Vice President, Controller and Chief Accounting Officer A majority of the Board of Directors: /s/ THOMAS J. MAY March 28, 2002 Thomas J. May, Director /s/ JAMES J. JUDGE March 28, 2002 James J. Judge, Director /s/ DOUGLAS S. HORAN March 28, 2002 Douglas S. Horan, Director