-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OYvV8LbewNbV1Kgs7eysSuiQpGejZD3tW/mrI1zq/IWBzzcJ3Ui61LlFqw0PgOxR 98Kx8Qf0MSga8fdcL+U21Q== 0000013372-03-000003.txt : 20030327 0000013372-03-000003.hdr.sgml : 20030327 20030327160356 ACCESSION NUMBER: 0000013372-03-000003 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030327 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BOSTON EDISON CO CENTRAL INDEX KEY: 0000013372 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041278810 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02301 FILM NUMBER: 03621061 BUSINESS ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: P1600 CITY: BOSTON STATE: MA ZIP: 02199 BUSINESS PHONE: 6174242000 MAIL ADDRESS: STREET 1: 800 BOYLSTON ST STREET 2: P1600 CITY: BOSTON STATE: MA ZIP: 02199 10-K 1 beco10k2002.txt BOSTON EDISON COMPANY FORM 10-K 2002 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, 2002 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 27, 2003 Common Stock, $1 par 75 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 by Reference Part in Form 10-K None Not Applicable
List of Exhibits begins on page 54 of this report.
Boston Edison Company Form 10-K Annual Report December 31, 2002 Part I Page Item 1. Business 2 Item 2. Properties 7 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 of Financial Condition and Results of Operations 9 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 53 Part IV Item 14. Controls and Procedures 53 Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 54 Signatures 58 Certification Statements 59
Part I Item 1. Business Boston Edison Company makes available on its website at www.nstaronline.com ("SEC filings") its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). The Company provides this service free of charge. (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 wholly owned subsidiary of NSTAR. NSTAR is an energy delivery company focusing its activities in the transmission and distribution of energy. NSTAR serves approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 0.3 million gas customers in 51 communities. Boston Edison serves approximately 683,000 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). 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 Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison. NSTAR was created in 1999 through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy). An integral part of the merger was the rate plan of the retail utility subsidiaries of BEC, which includes Boston Edison, and COM/Energy that was approved by the MDTE in an order on July 27, 1999. Significant elements of the rate plan included 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 "Rate and Regulatory Proceedings" section in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, 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 2002, Boston Edison served an average of approximately 683,000 customers. Boston Edison also supplies electricity at wholesale for resale to municipal electric departments. Electric operating revenues by customer class for the last three years consisted of the following:
2002 2001 2000 Retail electric revenues: Commercial 55% 57% 53% Residential 33% 31% 30% Industrial 7% 9% 9% Other 1% 1% 1% Wholesale and contract revenues 4% 2% 7%
Retail Electric Rates As a result of electric industry restructuring, Boston Edison 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. The 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 February 2005 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 Boston Edison's 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, 2002 and 2001, customers of Boston Edison had approximately 28% and 20%, respectively, of their load requirements provided by competitive suppliers. During 2000, Boston Edison's accumulated cost to provide default and standard offer service was in excess of the revenues it was allowed to bill by approximately $193.6 million. On January 1 and July 1, 2001, Boston Edison received approval from the MDTE to increase its rates to customers for standard offer and default service to collect this shortfall. Furthermore, when combined with the reduction in energy supply costs experienced in 2001 and through the first half of 2002, rates were reduced on January 1, 2002, April 1, 2002, July 1, 2002 and January 1, 2003. At December 31, 2002, Boston Edison's accumulated cost to provide default and standard offer service was in excess of the revenues it was allowed to bill by approximately $8.7 million. This amount is reflected as a component of Regulatory assets on the accompanying Consolidated Balance Sheets. Sources and Availability of Electric Power Supply Boston Edison has existing long-term power purchase agreements that are expected to supply approximately 75% of its standard offer service obligation for 2003. Boston Edison has contracted for its standard offer supply obligation through December 31, 2003. Boston Edison expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the 1997 Restructuring Act and MDTE orders. Boston Edison is recovering its payments to suppliers through MDTE-approved rates billed to customers. Boston Edison's existing portfolio of long-term power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2002. Also during 2002, Boston Edison entered into an agreement whereby all of its energy supply resource entitlements were transferred to an independent energy supplier, following which Boston Edison repurchased its energy resource needs from this independent energy supplier for Boston Edison's ultimate sale to standard offer customers. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for the period January 1, 2003 through June 30, 2003 and for 50% of its obligation for the second-half of 2003. A Request for Proposals will be issued in the second quarter of 2003 for the remainder of the obligation. Boston Edison entered into agreements ranging in length from five to twelve-months effective January 1, 2002 through December 31, 2002 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. 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. Independent System Operator - New England (ISO-NE) Prior to March 1, 2003, ISO-NE dispatched generating units based on the lowest operating costs of available generation and transmission. Under this structure, generators were required to provide ISO-NE with market prices at which they sell short-term energy supply. For each participant actively involved in the power market, the imbalance in energy provided by a participant and the energy consumed by such participant in each hour is settled at a single real-time clearing hourly price for such power. Pursuant to orders issued by the Federal Energy Regulatory Commission (FERC) in September and December of 2002, these markets have been further restructured into Standard Market Design (SMD), which began on March 1, 2003. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, with prices increasing in areas where less efficient resources close to the load are dispatched to meet the load requirements due to the fact that the more efficient resources cannot be imported as a result of transmission limitations. As part of the movement to SMD, load-serving entities, like Boston Edison, will be granted proceeds from the auction of "financial transmission rights" that is conducted by ISO-NE. Holders of these rights are essentially entitled to the positive differences in the prices between the locations specified for such rights and are subject to additional costs for negative differences. Boston Edison can either use these proceeds to mitigate costs to customers directly or transfer them to the suppliers of its energy resource needs to reduce the cost to customers. Therefore, the impact of the change to SMD on Boston Edison's costs to meet its standard offer service and default service obligations are mitigated somewhat. Franchises 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, 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. Capital Expenditures and Financings
The most recent estimates of plant expenditures and long-term debt maturities for the years 2003 through 2007 are as follows: (in thousands) 2003 2004 2005 2006 2007 Capital expenditures $186,000 $172,000 $139,000 $122,000 $124,000 Long-term debt $191,242 $ 70,390 $170,052 $70,254 $70,170
Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. Plant expenditures in 2002 and 2001 were $239 million and $138.6 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. Seasonal Nature of Business Boston Edison's kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. 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. There were no environmental-related capital expenditures for the years 2002 and 2001. Management believes that its facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur. Employees and Employee Relations Management, engineering, financing and support services are provided to Boston Edison by employees of NSTAR Electric & Gas. As of December 31, 2002, NSTAR Electric & Gas had approximately 3,200 employees, including approximately 2,300 or 73% of whom are represented by two collective bargaining units covered by separate contracts. The five-year labor contract with Local 369 of the Utility Workers Union of America, AFL-CIO covering approximately 2,075 employees expires May 15, 2005. A labor contract with Local 12004, United Steelworkers of America, AFL- CIO-CLC covering 260 employees has a four-year term that expires on March 31, 2006. Management believes it has satisfactory relations with its employees. (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 Boston Edison properties include 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 transmission lines are generally located on land either owned or subject to easements in its favor. Its distribution lines are located principally on public property under permission granted by municipal and other state authorities. As of December 31, 2002, primary and secondary overhead and underground distribution systems cover approximately 10,900 and 6,000 circuit miles, respectively. In addition, Boston Edison's transmission system consists of 127 substation facilities and approximately 720,400 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 Merger Rate Plan On December 16, 2002, the Massachusetts Supreme Judicial Court (SJC) upheld the MDTE's 1999 decision to allow for the merger of BEC and COM/Energy as originally structured. The SJC decision finalized the resolution of all issues related to the appeal and did not have any impact on Boston Edison's 2002 or prior periods' consolidated financial position, cash flows or results of operations. The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy, was appealed to the SJC by the Massachusetts Attorney General (AG) and a separate group that consisted of The Energy Consortium (TEC) and Harvard University (Harvard). TEC and Harvard alleged that, in approving the rate plan and merger proposal, the MDTE committed errors of law in the following areas: (1) in adopting a public interest standard, the MDTE applied the wrong standard of review, and failed to investigate the propriety of rates and to determine that the resulting rates of Boston Edison, Cambridge Electric, ComElectric and NSTAR Gas were just and reasonable; (2) that in permitting Cambridge Electric and ComElectric to adjust their rates by $49.8 million to reflect demand-side management costs, the MDTE failed to determine whether such an adjustment was warranted in light of other cost decreases; (3) that the MDTE's approval results in an arbitrary and unjustified sharing of benefits and costs between ratepayers and shareholders; and (4) that the MDTE's approval of the rate plan guarantees shareholders recovery of future costs without any future demonstration of customer savings. The AG's brief included similar arguments in each of these areas and added that, in allowing recovery of the acquisition premium, the MDTE improperly deviated from a cost basis in setting approved rates and the ratemaking policies in other jurisdictions. Other legal matters In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil lawsuits. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs ("legal liabilities") that would be in excess of amounts accrued. Based on the information currently available, Boston Edison does not believe that it is probable that any such additional legal liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations 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 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, 2002. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) 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 focusing its activities in the transmission and distribution of energy. NSTAR serves approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 0.3 million gas customers in 51 communities. Boston Edison serves approximately 683,000 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). 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 Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison. Cautionary Statement This MD&A 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 also be contained in other filings with the SEC, 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 sensitive to weather, the economy and other variable conditions, 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 summer 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, and prices and availability of operating supplies could materially affect the projected operating results. Boston Edison's forward-looking information depends in large measure on prevailing governmental policies and regulatory actions, including those of the MDTE and the FERC, with respect to allowed rates of return, rate structure, continued recovery of regulatory assets, 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. 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 filings to the SEC. Also note that Boston Edison provides in the above paragraphs a cautionary discussion of risks and other uncertainties relative to its business. These are factors that could cause its actual results to differ materially from expected and historical performance. Other factors in addition to those listed here could also adversely affect Boston Edison. This report also describes material contingencies and critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements, and Boston Edison encourages a review of these Notes. Critical Accounting Policies and Estimates Boston Edison's discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and judgments that affect the reported amount of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Actual results may differ from these estimates under different assumptions or conditions. Critical accounting policies and estimates are defined as those that are reflective of significant judgment and uncertainties, and potentially may result in materially different outcomes under different assumptions and conditions. Boston Edison believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below. a. Revenue Recognition Utility revenues are based on authorized rates approved by the FERC and the MDTE. Estimates of transmission, distribution and transition revenues for electricity delivered to customers but not yet billed are accrued at the end of each accounting period. The determination of unbilled revenues requires management to estimate the volume and pricing of electricity delivered to customers prior to actual meter readings. Revenues related to the sale, transmission and distribution of electricity are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the electricity sales to individual customers is based on the reading of their meters which are read on a systematic basis throughout the month. Meters which are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of electricity delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on daily generation volumes (territory load), line losses and applicable customer rates. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2002 and 2001 were $21.5 million and $29.1 million, respectively. b. Regulatory Accounting Boston Edison follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a rate-regulated company, Boston Edison is subject to the Financial Accounting Standards Board (FASB) 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 revenues and expenses from that of other businesses and industries. Boston Edison's energy delivery business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash flows. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. As of December 31, 2002 and 2001, Boston Edison has recorded regulatory assets of $1,265 million and $768.7 million, respectively. This increase is primarily the result of the recognition of certain purchased power costs. Boston Edison continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Boston Edison expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, Boston Edison would be required to charge these assets to current earnings. However, impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Regulatory assets related to the generation business are recovered through the transition charge. c. Derivative Instruments - Power Contracts Typically, the electric power industry contracts to buy and sell electricity under option contracts, which allow the buyer some flexibility in determining when to take electricity and in what quantity to match fluctuating demand. These contracts would normally meet the definition of a derivative requiring mark-to- market accounting. However, because electricity cannot be stored and an entity is obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception described in SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and Derivative Implementation Group (DIG) Issue No. C15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity." Boston Edison has long-term purchased power agreements that are used primarily to meet its standard offer obligation. The majority of these agreements are above-market but are not reflected on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, in Issue C15, the DIG concluded that contracts with a pricing mechanism that are subject to future adjustment based on a generic index that is not specifically related to the contracted service commodity generally would not qualify for the normal purchases and sales exception. Boston Edison has one purchased power contract that contains components with pricing mechanisms that are based on a pricing index, such as the GNP or CPI. Although these factors are only applied to certain ancillary pricing components of the agreement, as required by the interpretation of DIG Issue C15, Boston Edison began recording this contract at fair value on the Consolidated Balance Sheets during 2002. This action resulted in the recognition of a liability for the fair value of the above-market portion of this contract at December 31, 2002 of approximately $305 million and is reflected as a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets. This contract is valued using a discounted cash flow model and a 10% discount rate. The market value assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the value of this contract at December 31, 2002 would have changed significantly. A one percent increase or decrease to the discount rate would change the above-market value by approximately $12 million from what is presently recorded. Boston Edison recovers all of its electricity supply costs, including the above-market costs. The recovery of its above- market costs occurs through 2016. The recovery period coincides with the contractual terms of this purchased power agreement. Therefore, in addition to the liability recorded, Boston Edison also recorded a corresponding regulatory asset representing the future recovery of these actual costs. d. Pension and Other Postretirement Benefits Boston Edison is the sponsor of NSTAR's qualified Pension Plan (the Plan). As its sponsor, Boston Edison allocates the costs of the Plan among itself and the other NSTAR subsidiary companies based on a percentage of total direct labor charged to the Company. The Company's pension and other postretirement benefits costs are dependent upon several factors and assumptions, such as employee demographics, the level of cash contributions made to the plan, earnings on the plans' assets, the discount rate, the expected long-term rate of return on the plans' assets and health care cost trends. In accordance with SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), changes in pension and postretirement benefit obligations other than pensions (PBOP) associated with these factors may not be immediately recognized as pension and PBOP costs in the statements of income, but generally are recognized in future years over the remaining average service period of the plans' participants. There were no changes to pension plan benefits in 2002, 2001 and 2000 that had a significant impact on recorded pension costs. As further described in Note D to the accompanying Consolidated Financial Statements, the Company has revised the discount rate in 2002 as compared to 2001 and 2000. In addition, the Company revised the expected long-term rate of return on its pension and PBOP plan assets for 2003 to 8.4% and 8% respectively, reduced from 9.4% and 9% in 2002, respectively. These changes will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact will be mitigated, to an extent, through the Company's regulatory accounting treatment of pension and PBOP costs. (See further discussion of regulatory accounting treatment below). In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements. The Plan's assets, which partially consist of equity investments, have been affected by significant declines in the equity markets in the past three years. Fluctuations in equity market returns may result in increased or decreased pension costs in future periods. These conditions impacted the funded status of the Plan at December 31, 2002, and therefore, will also impact pension costs for 2003. The following chart reflects the projected benefit obligation and cost sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption. Only a portion of the impact indicated would be allocated to the Company.
(in thousands) Impact on Projected Change in Benefit Impact on 2002 Cost Actuarial Assumption Assumption Obligation (Increase)/Decrease Increase in discount rate 50 basis points $ (48,693) $ (3,220) Decrease in discount rate 50 basis points $ 52,580 $ 3,410 Increase in expected long-term 50 basis points NA $ 3,935 rate of return on plan assets Decrease in expected long-term 50 basis points NA $ (3,935) rate of return on plan assets NA - Not applicable
The discount rate is based on rates of high quality corporate bonds as published by nationally recognized rating agencies. In determining the long-term rate of return on plan assets, the Company considers past performance and economic forecasts for the types of investments held by the Plan. In 2003, the Company reduced the expected long-term rate of return on plan assets from 9.4% to 8.4% as a result of the prevailing outlook for equity market returns. Reported pension costs will increase in 2003 and future years as a result of this changed assumption. However, as a result of the MDTE Accounting Order (Accounting Order) discussed below, this increase will not have a material impact on the Company's results of operations. The unfavorable market conditions have impacted the value of Plan assets. As a result of the negative investment performance, the Plan's accumulated benefit obligation (ABO) exceeded Plan assets at December 31, 2002. The ABO represents the present value of benefits earned without considering future salary increases. Since the fair value of its Plan assets is less than the ABO, the Company is required to record this difference as an additional minimum pension liability on the accompanying Consolidated Balance Sheets. Under SFAS 87, the Company is also required to eliminate its prepaid pension balance. The additional minimum pension liability adjustment is equal to the sum of the minimum pension liability and the prepaid pension that would be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability will be adjusted each year to reflect this measurement. At such time that the Plan assets exceed the ABO, the minimum liability would be reversed. In November 2002, the Company and certain affiliates filed a request with the MDTE seeking an accounting ruling to mitigate the impact of the non-cash charge to OCI in 2002 and the increases in expected pension and PBOP costs in 2003. On December 20, 2002, the MDTE approved the Accounting Order. Based on this Accounting Order and an opinion from legal counsel regarding the probability of recovery of these costs in the future, the Company recorded a regulatory asset in lieu of taking a charge to OCI at December 31, 2002. In addition, the Accounting Order permits the Company to defer, as a regulatory asset or liability, the difference between the level of pension and PBOP expenses that are included in rates and the amounts that are required to be recorded under SFAS 87 and SFAS 106 beginning in 2003. The regulatory asset of $263 million, recorded as a result of this Accounting Order, consists of the prepaid pension asset ($257 million) related to the Plan and the Company's portion of the minimum liability ($5.6 million) incurred at December 31, 2002. The regulatory asset is shown in Deferred debits on the accompanying Consolidated Balance Sheets. Boston Edison anticipates filing with the MDTE, during 2003, a specific mechanism designed to address pension and PBOP costs. It is Boston Edison's goal to eliminate the volatility of these costs. The Plan currently meets the minimum funding requirements of the Employee Retirement Income Security Act of 1974. While not required to make contributions to the Plan, the Company anticipates increasing the level of its cash contributions to the Plan in 2003 to mitigate the projected adverse impact. Such cash contributions may be material to its consolidated cash flows from operations. Boston Edison believes it has adequate access to capital resources to support these contributions. e. Decommissioning Cost Estimates The accounting for decommissioning costs of nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Changes in these estimates will not affect Boston Edison's results of operations or cash flows because these costs will be collected from customers through Boston Edison's transition charge filings with the MDTE. While Boston Edison no longer directly owns any nuclear power plants, it owns, through its equity investments, 9.5% of Connecticut Yankee Atomic Power Company (CYAPC) and 9.5% of Yankee Atomic Electric Company (YAEC) (the Yankee Companies). Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities. Based on estimates from the Yankee Companies' management as of December 31, 2002, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $247.7 million for CY and $224.9 million for YA. Of these amounts, Boston Edison is obligated to pay $23.6 million towards the decommissioning of CY and $21.4 million toward YA. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. Boston Edison expects the Yankee Companies to seek recovery of these costs and any additional increases to these costs in rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including Boston Edison. Boston Edison would recover its share of any allowed increases from customers through the transition charge. New Accounting Standards See Note A, "New Accounting Standards," of the accompanying Consolidated Financial Statements. Rate and Regulatory Proceedings a. Distribution Rate Proceedings On February 14, 2003, NSTAR notified the MDTE that it is in the process of reviewing the 2002 test-year cost of service for its utility subsidiaries, including Boston Edison, in order to determine whether to request a general base rate increase. This assessment coincides with the expiration of NSTAR's four-year rate freeze presently in effect as part of the Merger Rate Plan that created NSTAR. If NSTAR decides not to seek a general base rate increase, NSTAR will request a specific rate recovery mechanism relating to pension and PBOP costs in conjunction with the MDTE Accounting Order dated December 20, 2002. Management intends to finalize its decision on the appropriate regulatory proceedings during the second quarter of 2003. b. Merger Rate Plan An integral part of the merger of BEC and COM/Energy that created NSTAR was the rate plan of the retail utility subsidiaries that was approved by the MDTE on July 27, 1999 and affirmed by the SJC in December 2002 as further discussed below. Significant elements of the rate plan included a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Refer to the "Retail Electric Rates" section of this MD&A for more information on retail rates and cost recovery. On December 16, 2002, the SJC affirmed the MDTE's 1999 decision to allow for the merger of BEC and COM/Energy as originally structured. This decision did not have an impact on Boston Edison's 2002 or prior periods' consolidated financial position, cash flows or results of operations. The 1999 MDTE order approving the rate plan associated with the merger, was appealed to the SJC by the Massachusetts Attorney General (AG) and a separate group that consisted of The Energy Consortium (TEC) and Harvard University (Harvard). TEC and Harvard alleged that, in approving the rate plan and merger proposal, the MDTE committed errors of law in the following areas: (1) in adopting a public interest standard, the MDTE applied the wrong standard of review, and failed to investigate the propriety of rates and to determine that the resulting rates of Boston Edison, Cambridge Electric, ComElectric and NSTAR Gas were just and reasonable; (2) that in permitting Cambridge Electric and ComElectric to adjust their rates by $49.8 million to reflect demand-side management costs, the MDTE failed to determine whether such an adjustment was warranted in light of other cost decreases; (3) that the MDTE's approval results in an arbitrary and unjustified sharing of benefits and costs between ratepayers and shareholders; and (4) that the MDTE's approval of the rate plan guarantees shareholders recovery of future costs without any future demonstration of customer savings. The AG's brief included similar arguments in each of these areas and added that, in allowing recovery of the acquisition premium, the MDTE improperly deviated from a cost basis in setting approved rates and the ratemaking policies in other jurisdictions. c. Goodwill and Costs to Achieve The merger that created NSTAR was accounted for using the purchase method of accounting. In accordance with Accounting Principles Board (APB) No. 16 - "Business Combinations," all goodwill was recorded on the books of the subsidiaries of COM/Energy. However, under the merger rate plan approved by the MDTE, all of NSTAR's utility subsidiaries share in the recovery of goodwill in their rates. As a result, goodwill amortization expense 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 (CTA) are being amortized based on the filed estimate of $111 million over 10 years. For the year ended December 31, 2002, Boston Edison's portions of goodwill and CTA amortization were approximately $8 million and $7.2 million, respectively. NSTAR's retail utility subsidiaries will reconcile the actual CTA costs incurred with the original estimate in a future rate proceeding and any difference is expected to be recovered over the remainder of the amortization period. This reconciliation will include a final accounting of the deductibility for income tax purposes of each component of CTA. The total CTA is approximately $143 million of which approximately $93 million has been allocated to Boston Edison. This increase from the original estimate for NSTAR is partially mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. Boston Edison anticipates that these incremental costs are probable of recovery in future rates. CTA are the costs incurred to execute the merger including the employee costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. 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. d. Service Quality Index On October 29, 2001, and as subsequently updated, NSTAR Electric, including Boston Edison, filed proposed service quality plans for each company with the MDTE. 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. Concurrently, NSTAR Electric filed with the MDTE a report concerning its 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. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.25 million on NSTAR Electric, of which $3.2 million related specifically to Boston Edison, that was refunded to customers as a credit to their bills during the month of May 2002. This refund had no material effect on Boston Edison's consolidated financial position, cash flows or results of operations in 2002. For the four-month period ended December 31, 2001, the MDTE determined that NSTAR Electric's performance relative to service quality measures did not warrant a penalty assessment. On February 28, 2003, NSTAR Electric and NSTAR Gas filed their 2002 Service Quality Reports with the MDTE that reflected significant improvements in reliability and performance and indicate that no penalty will be assessed for this period. The Company accounts for its service quality penalties pursuant to SFAS No. 5, "Accounting for Contingencies." Accordingly, these penalties are monitored on a monthly basis to determine the Company's contingent liability, and if the Company determines it is probable that a liability has been incurred and is estimable, the Company would then accrue an appropriate liability. Annually, each NSTAR utility subsidiary makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability (or credit) level from what has been accrued would be adjusted in the period an agreement is reached with the MDTE. e. Retail Electric Rates The 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 February 2005 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, 2002, Boston Edison had approximately 28% of its load requirements provided by competitive suppliers. In December 2002, Boston Edison filed proposed transition rate adjustments for 2003, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2002. The MDTE subsequently approved tariffs for the Company effective January 1, 2003. The filing was updated in February 2003 to include final costs for 2002. On November 14, 2002, Boston Edison and the AG (Settling Parties), received approval from the MDTE on a Settlement Agreement resolving issues in Boston Edison's reconciliation of costs and revenues for the year 2001. Among other issues, the Settlement Agreement includes an adjustment relating to the reconciliation of costs relating to securitization and maximum mitigation of costs incurred in relation to the purchased power agreement with Hydro Quebec. As a result of this Settlement Agreement with the AG, Boston Edison recognized approximately $11.4 million in transition charge revenues in 2002. This benefit was significantly offset by other regulatory reconciliation 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 approved the reconciliation of costs and revenues for Boston Edison through 2000 in its approval of a Settlement Agreement on November 16, 2001 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 Boston Edison's consolidated financial position, results of operations or cash flows. During 2000, Boston Edison's accumulated costs to provide default and standard offer service were in excess of the revenues it was allowed to bill customers by approximately $193.6 million. On January 1 and July 1, 2001, Boston Edison was permitted by the MDTE to increase its rates to customers for standard offer and default service to collect this shortfall. Furthermore, when combined with the reduction in energy supply costs experienced in 2001 and through the first half of 2002, rates were reduced on January 1, 2002, April 1, 2002, July 1, 2002 and January 1, 2003. As a result, Boston Edison reflected a regulatory liability of approximately $2.5 million at December 31, 2001 and a regulatory asset of $8.7 million at December 31, 2002, that are reflected as components of Regulatory assets - other on the accompanying Consolidated Balance Sheets. 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. Effective April 1, 2002, each NSTAR Electric company's fuel index was set to zero. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act. f. Standard Market Design Effective March 1, 2003, the wholesale electric energy market in the Northeast has been restructured into what is known as "Standard Market Design" (SMD) in conjunction with FERC orders issued in September and December of 2002. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, with prices increasing in areas where less efficient resources close to the load are dispatched to meet the load requirements due to the fact that the more efficient resources cannot be imported as a result of transmission limitations. SMD is not expected to have an impact on Boston Edison's results of operations because of the recovery mechanism for wholesale energy costs approved by the MDTE. Other Legal Matters In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil lawsuits. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs ("legal liabilities") that would be in excess of amounts accrued. Based on the information currently available, Boston Edison does not believe that it is probable that any such additional legal liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations for a reporting period. 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, 2002 and should be read in conjunction with the accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements included elsewhere in this report. 2002 compared to 2001 Net income was $134.1 million in 2002 compared to $150.4 million in 2001, a decrease of 10.8%. Operating revenues
Operating revenues for 2002 decreased 15.7% from 2001 as follows: (in thousands) Retail revenues $(297,001) Wholesale revenues (23,461) Short-term sales and other revenues 9,909 Decrease in operating revenues $(310,553) ========
Despite a 0.5% increase in kWh sales in 2002, retail revenues were $1,529 million in 2002 compared to $1,826 million in 2001, a decrease of $297 million, or 16%. The change in retail revenues reflects lower rates implemented in January and April 2002 for standard offer service and January and July 2002 for default service as a result of a significant decline in purchased power costs. This revenue decrease was partially offset by higher transition revenues of $36 million primarily due to the reconciliation of securitization costs and to higher rates for transition cost recovery. The decrease 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 for 2002 was significantly warmer than the same period in 2001, resulting in an 18% increase in cooling degree days from the prior year and a 43% increase from the 30-year average. Below is comparative information on cooling and heating degree days in 2002 and 2001 and the number of degree days in a "normal" year as represented by a 30-year average.
30-Year 2002 2001 Average Cooling degree-days 972 822 777 Percentage change from prior year 18.2% 39.8% Percentage change from 30-year average 25.1% 5.8% Heating degree-days 5,279 5,243 5,630 Percentage change from prior year 0.7% (8.6)% Percentage change from 30-year average (6.2)% (6.9)%
Wholesale electric revenues were $56.6 million in 2002 compared to $80 million in 2001, a decrease of $23.4 million, or 29%. This decrease was primarily due to the expiration of two municipal contracts on May 31, 2002 and a third contract on October 31, 2002. After October 31, 2005, the Company will no longer have contracts for the supply of wholesale power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts has no impact on Boston Edison's consolidated net income. Other revenues were $86.6 million in 2002 compared to $76.7 million in 2001, an increase of $9.9 million, or 13%. This increase reflects higher transmission revenues. Operating expenses Purchased power was $838.4 million in 2002 compared to $1,159.7 million in 2001, a decrease of $321.3 million or 28%. The decrease in purchased power expense reflects lower prices for natural gas and oil that are reflected in the Company's default and standard offer service rates and the 24% decrease in wholesale sales offset somewhat by the increase in retail sales. The decrease also reflects the impact of the recovery of previously deferred standard offer and default service costs in 2001 compared to an under-recovery of these costs in 2002. 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. Operations and maintenance expense was $228.7 million in 2002 compared to $203.3 million in 2001, an increase of $25.4 million or 12%. This increase primarily reflects increased costs related to pension and postretirement benefits and corrective electric systems maintenance costs. Depreciation and amortization expense was $170.9 million in 2002 compared to $167.9 million in 2001, an increase of $3 million or 2%. The increase reflects a higher level of depreciable plant-in- service in the current year. Demand side management (DSM) and renewable energy programs expense was $48.6 million in 2002 compared to $47.6 million in 2001, an increase of $1 million, or 2%. 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 $70.1 million in 2002 compared to $69.8 million in 2001, an increase of $0.3 million, or less than 1%. The change reflects higher tax rates and assessments in the City of Boston offset by lower payments in lieu of taxes to the Town of Plymouth due to a lower assessed value. Income taxes from operations were $90.5 million in 2002 compared to $94 million in 2001, a decrease of $3.5 million, or 4%. This decrease reflects a lower level of pretax operating income in 2002. Other income, net Other income, net was $4 million in 2002 compared to $8.2 million in 2001, a decrease of $4.2 million or 51%. The decrease was primarily due to the absence in 2002 of income related to the receipt of equity securities in connection with the demutualization of John Hancock Financial Services, Inc. and MetLife, Inc. A decline in interest income of $2.5 million primarily associated with the reconciliation of securitization costs also contributed to the decline. Other deductions, net Other deductions, net increased $0.5 million due primarily to an increase in charitable contributions. Interest charges Interest on long-term debt and transition property securitization certificates was $85 million in 2002 compared to $87.5 million in 2001, a decrease of $2.5 million or 3%. The decrease is related to securitization certificate interest reflecting the scheduled partial retirement of this debt, and the retirement of the $24.3 million 9.375% debentures in August 2001 offset somewhat by the issuance of $500 million in new long-term debt in October 2002. Other interest charges were $10.8 million in 2002 compared to $11.5 million in 2001, a decrease of $0.7 million or 6%. This decrease reflects the repayment of short-term debt with the proceeds from the aforementioned long-term debt issue offset by an $8.1 million increase in carrying charges due the Company associated with reductions in the level of regulatory deferrals. Other Matters Environmental As of December 31, 2002, Boston Edison was involved in 12 state- regulated properties ("Massachusetts Contingency Plan, or "MCP" sites") where oil or other hazardous materials were previously spilled or released. On February 4, 2003, Boston Edison closed out one of these sites and filed the required information with the Massachusetts Department of Environmental Protection. 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 result of involvement in multi-party disposal sites or third party claims associated with contamination remediation. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.7 million and $4.8 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2002 and 2001, respectively, and are the total amount of Boston Edison's estimated environmental clean-up obligations. Accordingly, this amount has not been reduced by any potential rate recovery treatment of these costs or any potential recovery from Boston Edison's insurance carriers. Prospectively, should Boston Edison be allowed regulatory rate recovery of these specific costs, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs. 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. 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 evolve or are resolved. Boston Edison's ultimate liability for future environmental remediation costs may vary from these estimates. Although, 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 consolidated financial position or results of operations for a reporting period. Interest Rate Risk Boston Edison is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. Carrying amounts and fair values of long-term indebtedness (excluding notes payable) and the weighted average interest rate as of December 31, 2002 and 2001, were as follows:
(in thousands) Weighted Carrying Fair Average 2002 Amount Value Interest Rate Long-term indebtedness $1,477,326 $1,480,510 6.19% (including current indebtedness) 2001 Long-term indebtedness $1,107,346 $1,153,380 7.15% (including current indebtedness)
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Although the Company has material commodity purchase contracts, these instruments are not subject to market risk. The Company has a rate-making mechanism that 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 February 2005. 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. On October 15, 2002, Boston Edison issued $100 million of 3-year floating rate debentures priced at LIBOR plus 50 basis points. An immediate change of one percent for these variable rate debentures would cause a change in interest expense of approximately $1 million per year. 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 15(a)(1) on page 54, present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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 15 (a)(2) on page 54, 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 22, 2003 Item 8. Financial Statements and Supplementary Financial Information
Boston Edison Company Consolidated Statements of Income (in thousands) Years ended December 31, 2002 2001 2000 Operating revenues $1,672,148 $1,982,701 $1,671,846 Operating expenses: Purchased power 838,435 1,159,706 839,715 Operations and maintenance 228,666 203,320 205,734 Depreciation and amortization 170,932 167,905 169,333 Demand side management and renewable energy programs 48,579 47,639 54,836 Taxes-property and other 70,077 69,777 55,905 Income taxes 90,487 93,967 95,852 Total operating expenses 1,447,176 1,742,314 1,421,375 Operating income 224,972 240,387 250,471 Other income, net: Other income, net 4,008 8,154 8,281 Other deductions, net (736) (224) (582) Total other income, net 3,272 7,930 7,699 Interest charges: Long-term debt 47,867 45,994 52,804 Transition property 37,135 41,475 45,505 securitization Short-term and other 10,769 11,467 15,902 Allowance for borrowed funds used during construction (1,630) (972) (2,069) Total interest charges 94,141 97,964 112,142 Net income $ 134,103 $ 150,353 $ 146,028 ========= ========= ========= 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 (in thousands) Years ended December 31, 2002 2001 2000 Net income $ 134,103 $ 150,353 $ 146,028 Other comprehensive income (loss), net: Non-qualified benefit obligations - 195 (195) Deferred income taxes - (78) 78 Comprehensive income $ 134,103 $ 150,470 $ 145,911 ======== ======== ======== The accompanying notes are an integral part of the Consolidated Financial Statements.
Boston Edison Company Consolidated Statements of Retained Earnings (in thousands) Years ended December 31, 2002 2001 2000 Balance at the beginning of the year $ 428,150 $ 352,832 $ 1,462 Add: Net income 134,103 150,353 146,028 Dividends transferred from paid in capital (a) - - 226,541 Subtotal 562,253 503,185 374,031 Deduct: Dividends declared: Dividends to Parent 84,300 68,927 15,000 Preferred stock 1,960 5,627 5,960 Subtotal 86,260 74,554 20,960 Provision for preferred stock redemption and issuance costs - 481 239 Balance at the end of year $ 475,993 $ 428,150 $ 352,832 ======= ======= ======= (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 in 2000. The accompanying notes are an integral part of the Consolidated Financial Statements.
Boston Edison Company Consolidated Balance Sheets (in thousands) December 31, Assets 2002 2001 Utility plant in service, at original cost $2,782,854 $2,641,759 Less: accumulated depreciation 854,857 $1,927,997 875,158 $1,766,601 Construction work in progress 41,944 38,818 Net utility plant 1,969,941 1,805,419 Equity and other investments 11,592 13,611 Current assets: Cash and cash equivalents 44,062 13,549 Restricted cash 3,616 3,625 Accounts receivable - customers, net of allowance of $19,084 and $24,691 in 2002 and 2001, respectively 177,681 264,633 Accrued unbilled revenues 21,468 29,081 Fuel, materials and supplies, at average cost 13,291 15,461 Deferred tax asset 18,141 1,835 Other 5,575 283,834 22,335 350,519 Deferred debits: Regulatory assets 1,265,062 768,776 Prepaid pension costs - 218,713 Other 178,429 27,763 Total assets $3,708,858 $3,184,801 ========= ========= Capitalization and Liabilities Common equity: Common stock, par value $1 per share, 100,000,000 shares authorized; 75 shares issued and outstanding $ - $ - Premium on common stock 278,795 528,795 Retained earnings 475,993 $ 754,788 428,150 $ 956,945 Cumulative non-mandatory redeemable preferred stock of subsidiary 43,000 43,000 Long-term debt 840,194 551,803 Transition property 445,890 513,904 securitization Current liabilities: Long-term debt 150,687 667 Transition property securitization 40,555 40,972 Notes payable - 191,500 Accounts payable: Affiliates 32,450 54,663 Other 117,600 91,522 Accrued interest 13,899 10,738 Other 46,971 402,162 67,098 457,160 Deferred credits Accumulated deferred income taxes and unamortized investment tax credits 611,469 578,765 Power contracts 350,117 22,697 Other 261,238 60,527 Commitments and contingencies Total capitalization and liabilities $3,708,858 $3,184,801 ========== ========== 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, 2002 2001 2000 Operating activities: Net income $ 134,103 $ 150,353 $ 146,028 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 170,932 167,905 161,371 Deferred income taxes and investment tax credits 16,125 (51,242) 86,962 Allowance for borrowed funds used during construction (1,630) (972) (2,069) Net changes in: Accounts receivable and accrued unbilled revenues 94,565 (26,356) 13,556 Fuel, materials and supplies, at average cost 2,170 160 605 Accounts payable 3,865 102,292 128,753 Other current assets and liabilities (16,503) (194,582) (363,521) Deferred debits and credits 26,897 58,727 14,991 Net cash provided by operating activities 430,524 206,285 186,676 Investing activities: Plant expenditures (excluding AFUDC) (239,032) (138,565) (110,437) Investments 2,019 11,500 4,368 Net cash used in investing activities (237,013) (127,065) (106,069) Financing activities: Capital contribution - 43,937 - Long-term debt 500,000 - - Financing costs (5,218) - - Redemptions: Preferred stock - (50,000) - Long-term debt (130,020) (91,513) (251,559) Net change in notes payable (191,500) 95,000 96,500 Repurchase of Common shares (250,000) - - Dividends paid (86,260) (75,220) (30,960) Net cash used in financing activities (162,998) (77,796) (186,019) Net increase (decrease) in cash and cash equivalents 30,513 1,424 (105,412) Cash and cash equivalents at the beginning of the year 13,549 12,125 117,537 Cash and cash equivalents at the end of the year $ 44,062 $ 13,549 $ 12,125 ========= ======== ========= Supplemental disclosures of cash flow information: Interest, net of amounts capitalized $ 81,158 $ 91,007 $ 105,735 Income taxes (refunded) paid $ 46,483 $ 164,194 $ (47,312) The accompanying notes are an integral part of the Consolidated Financial Statements.
Notes to Consolidated Financial Statements Note A. Business Organization and 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 an energy delivery company focusing its activities in the transmission and distribution of energy. NSTAR serves approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 0.3 million gas customers in 51 communities. Boston Edison serves approximately 683,000 electric customers in the city of Boston and 39 surrounding cities and towns. NSTAR's retail utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). 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. The population of the area served with electricity at retail is approximately 1.6 million. 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 accounting principles generally accepted in the United States of America (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 regulatory assets. 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. 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. 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 2.89%, 2.87% and 2.99% in 2002, 2001 and 2000, 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 2002, 2001 and 2000 were 2.89%, 4.14% and 6.00%, respectively, and represented only the cost of short-term debt. 8. Cash, Cash Equivalents and Restricted Cash Cash, cash equivalents and restricted cash are comprised of liquid securities with maturities of 90 days or less when purchased. 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. 9. 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. 10. Related Party Transactions The accompanying Consolidated Balance Sheet as of December 31, 2002 includes $171 million in Other deferred charges that results from the Company's role as the sponsor of the NSTAR Pension Plan and represents the amount of the additional minimum liability recognized in 2002 that was allocated to the other subsidiaries of NSTAR. Additionally, the accompanying December 31, 2002 and 2001 Consolidated Balance Sheets include net payables of $24.1 million and $45.4 million, respectively, to NSTAR Electric & Gas, for management and support services. Boston Edison's goodwill amortization expense allocation payable to its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $26.6 million and $18.6 million for 2002 and 2001, respectively. These amounts were included in Other deferred credits. Also, included in the accompanying Consolidated Balance Sheet as of December 31, 2002 was a payable of approximately $10 million to the Parent Company NSTAR representing the Company's share of postretirement benefits costs. These statements also include an Accounts payable of $226,600 and $277,400 as of December 31, 2002 and 2001, respectively, from NSTAR Communications, Inc., an affiliate. These balances represent the construction and construction costs management services provided by Boston Edison and its contractors. 11. 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 costs to achieve are being amortized over 10 years and will initially be approximately $11.1 million annually. As of December 31, 2002, Boston Edison's portion of goodwill and costs to achieve amortization was approximately $8 million and $7.2 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 costs to achieve will reflect the total actual costs. 12. Other income, net
Major components of Other income, net were as follows: (in thousands) 2002 2001 2000 Equity earnings $1,463 $ 1,434 $ 3,230 Income from demutualized securities - 2,743 - Interest income 926 3,433 5,265 Rental income 1,737 1,921 1,638 Settlement of claims 1,041 943 2,000 Miscellaneous other income (includes applicable income tax expense for total other income) (1,159) (2,320) (3,852) 4,008 8,154 8,281
Major components of Other deductions, net were as follows: (in thousands) Charitable contributions (970) (22) (573) Property taxes (129) (119) (116) Miscellaneous other deductions (includes applicable income tax benefit for total other deductions) 363 (83) 107 (736) (224) (582) Total other income, net $3,272 $ 7,930 $ 7,699 ===== ====== ======
13. New Accounting Standards On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). This Statement, which is effective for Boston Edison on January 1, 2003, establishes accounting and reporting standards 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. SFAS 143 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. Management has identified several minor long-lived assets, including lease arrangements, and has determined that it is legally responsible to remove such property and comply with the requirement of this standard. However, based on Boston Edison's assessment of its potential liability and rate regulatory treatment for the identified assets, the adoption of SFAS 143 will not have an effect on its results of operations, cash flows, or financial position. The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146) that requires entities to record a liability for costs related to exit or disposal activities when the costs are incurred. Previous accounting guidance required the liability to be recorded at the date of commitment to an exit or disposal plan. Boston Edison is required to comply with SFAS 146 beginning January 1, 2003. Boston Edison anticipates that the implementation of this standard will not have an adverse impact on its financial position or results of operations. In November 2002, FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (the Interpretation). The Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. For Boston Edison, disclosure requirements are effective with the 2002 financial statements contained in this report. Refer to Note K, "Commitments and Contingencies," for more discussion. The application of this Interpretation is not expected to materially impact the financial condition, results of operations, and cash flows of Boston Edison. 14. Purchases and Sales Transactions with ISO - New England (ISO- NE) During 2001, as part of Boston Edison's normal business operations in order to meet its energy obligation to its standard offer and default service customers, Boston Edison entered into hourly transactions to purchase or sell energy supply to its ISO-NE. The Boston Edison transactions with the ISO-NE have been treated as the ISO-NE servicing the incremental needs of Boston Edison, that is, transactions with ISO-NE associated with the difference between Boston Edison's resource needs compared to Boston Edison's resource availability. Boston Edison records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense. During 2002, NSTAR Electric entered into an agreement whereby all of its energy supply resource entitlements are transferred to an independent energy supplier, following which NSTAR Electric repurchases its energy resource needs from this independent energy supplier for NSTAR Electric's ultimate sale to its standard offer customers. This transaction has been and will continue to be recorded as a net purchase, similar to those transactions with ISO-NE during 2001. Note B. 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) December 31, 2002 2001 Generation-related regulatory assets, net $ 466,894 $ 555,514 Power contracts (including Yankee units) 350,117 22,697 Pension costs 262,616 - Merger costs to achieve 68,601 79,227 Income taxes, net 60,278 62,070 Redemption premiums 13,479 12,853 Purchased power costs 8,713 (2,498) Deferred postretirement benefits and pension costs 11,415 11,415 Other 22,949 27,498 Total regulatory assets $1,265,062 $ 768,776 ========= ========
Under the traditional revenue requirements model, electric rates are based on the cost of providing electric service. Under this 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. This is applicable to Boston Edison's distribution and transmission operations. Generation-related regulatory assets, net Plant and other regulatory assets related to the divestiture of Boston Edison's generation business are recovered through the transition charge. This recovery continues through 2016 for Boston Edison and is subject to adjustment by the MDTE. Power contracts Approximately $45 million at December 31, 2002 represents the remaining unamortized balance of the estimated costs to close the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants that are currently being decommissioned. Boston Edison's liability for CY decommissioning and its recovery ends in 2007 and for YA in 2010. However, should the actual costs exceed current estimates and anticipated decommissioning dates, Boston Edison could have an obligation beyond these periods that would be fully recoverable. These costs are recovered in Boston Edison's transition charge. Refer to Note K, "Commitments and Contingencies," for more discussion. The remaining balance includes $305.2 million at December 31, 2002 representing the recognition of a purchased power contract as a derivative and its above-market value and future recovery through Boston Edison's transition charge. Refer to Note I for further details. Pension costs The regulatory asset attributable to pension costs represents the deferral of pension related costs, which Boston Edison expects to recover from customers in future years. This amount results from the reclassification of amounts, which in the absence of the MDTE Accounting Order issued on December 20, 2002 (see Note D), would otherwise have been classified as a charge to other comprehensive income pursuant to SFAS 87 (as amended by SFAS 130). The amount of the deferral consists of approximately $5.6 million that represents the additional minimum pension liability recorded to reflect the Company's share of the unfunded liability of NSTAR's pension plan, and approximately $257 million, which represents the adjustment to reverse the prepaid pension costs. Prepaid pension costs represent the cumulative excess of cash contribution over the cumulative net periodic pension costs. For purposes of financial statement presentation, the amount previously reported as prepaid pension costs in 2001 has been displayed net of the additional minimum pension liability in 2002, as required by SFAS 87. Merger costs to achieve 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 included 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. Costs to achieve are the costs incurred to execute the merger including costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These costs are collected from all distribution customers and exclude a return component. These costs have been adjusted since the original recovery began and any unrecovered costs will be included in the Company's next rate case filing. Income taxes, net Approximately $32 million of this regulatory asset balance reflects deferred tax reserve deficiencies that the MDTE has allowed recovery of from ratepayers over a 17-year period. In addition, approximately $40 million in additional deferred tax reserve deficiencies has been recorded in accordance with an MDTE- approved settlement agreement. Offsetting these amounts is approximately $12 million of a regulatory liability associated with unamortized investment tax credits. Redemption premiums These amounts reflect the unamortized balance of redemption premium on Boston Edison Debentures that is amortized over the life of the respective debentures pursuant to MDTE approval and is consistent with the recovery from ratepayers of such costs. There is no return recognized on this balance. Purchased power costs The purchased power costs relate to deferred standard offer service and deferred default service costs. Customers have the option of continuing to buy power from Boston Edison at standard offer prices through February 2005. Since 1998, Boston Edison has been allowed to defer the difference between the retail price per kWh for standard offer and default service revenues and the cost to supply the power, plus carrying 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. Deferred postretirement benefits and pension costs These amounts represent the costs deferred by the Company during a three-year phase-in period approved by the MDTE related to the adoption of SFAS 106. Boston Edison will include these costs in a future rate proceeding. There is no current recovery of these deferred costs. Other These amounts primarily consist of deferred transmission revenues that are set to be recovered over a subsequent twelve-month period. The deferred revenue represents the difference between the level of billed transmission revenues and the current period costs incurred to provide transmission-related services. 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 $60.3 million and $62.1 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2002 and 2001, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes and unamortized investment tax credits consisted of the following: December 31, (in thousands) 2002 2001 Deferred tax liabilities: Plant-related $ 303,411 $ 211,506 Transition costs 206,895 233,465 Other 121,136 154,148 631,442 599,119 Deferred tax assets: Investment tax credits 11,784 12,423 Other 44,536 29,015 56,320 41,438 Net accumulated deferred income taxes 575,122 557,681 Accumulated unamortized investment tax credits 18,206 19,249 $593,328 $576,930 ======== ======== 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) 2002 2001 2000 Current income tax expense $ 74,362 $144,779 $ 8,890 Deferred income tax expense (benefit) 17,168 (49,715) 87,953 Investment tax credit amortization (1,043) (1,097) (991) Income taxes charged to operations 90,487 93,967 95,852 Current tax expense on other income (deductions), net 1,795 3,607 5,046 Total income tax expense $ 92,282 $ 97,574 $100,898 ======= ======= ========
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: 2002 2001 2000 Statutory tax rate 35.0% 35.0% 35.0% State income tax, net of federal income tax benefit 4.4 4.4 4.4 Investment tax credits (0.5) (0.4) (0.4) Other 1.9 0.4 1.8 Effective tax rate 40.8% 39.4% 40.8% ==== ==== ====
Note D. Pension and Other Postretirement Benefits 1. Pension Effective January 1, 2000, the pension plans of BEC and COM/Energy were combined to form the NSTAR Pension Plan (the Plan). Boston Edison is the sponsor of the Plan which is a defined benefit funded retirement plan that covers substantially all employees of NSTAR Electric & Gas. In 2002, the Plan was amended to comply with the Economic Growth and Tax Relief Reconciliation Act of 2001 (EGTRRA). EGTRRA, among other things, increased the annual benefits limit for amounts payable from the Plan to $160,000, increased the number of rollover options for distributions, and allowed surviving spouses to rollover distributions to their employer's plan. This amendment also brought the Plan into compliance with recently issued Internal Revenue Service revenue rulings and regulations that require the change of the mortality table used for computing lump sum pension distributions and annuity conversions. The Company also maintained 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 was transferred accordingly effective December 31, 2001.
The changes in benefit obligation and Plan assets were as follows: December 31, (in thousands) 2002 2001 Change in benefit obligation: Benefit obligation, beginning of the year $ 810,517 $ 804,358 Transfer of obligation to affiliate company - (14,067) Service cost 14,871 13,727 Interest cost 57,564 56,418 Plan participants' contributions 74 71 Plan amendments 671 - Actuarial loss 102,598 14,091 Settlement payments (19,545) (16,573) Benefits paid (49,258) (47,508) Benefit obligation, end of the year $ 917,492 $ 810,517 ======== ========
Change in plan assets: 2002 2001 Fair value of plan assets, beginning of the year $ 790,704 $ 846,207 Actual loss on plan assets, net (105,578) (52,493) Employer contribution 49,500 61,000 Plan participants' contributions 74 71 Settlement payments (19,545) (16,573) Benefits paid (49,258) (47,508) Fair value of plan assets, end of the year $ 665,897 $ 790,704 ======== ========
The Plan's funded status was as follows: December 31, (in thousands) 2002 2001 Funded status $(251,595) $ (33,598) Liability transfer to affiliate company - 13,785 Unrecognized actuarial net loss 515,859 246,708 Unrecognized transition obligation 980 1,581 Unrecognized prior service cost (8,228) (9,762) Net amount recognized $ 257,016 $ 218,714 ======== ========
Amounts recognized in the accompanying Consolidated Balance Sheets consisted of: 2002 2001 (in thousands) Prepaid retirement cost $ - $ 218,714 Accrued retirement liability (177,675) - Intangible asset 980 - Regulatory asset 262,616 - Amount allocated to affiliates 171,095 - Net amount recognized $ 257,016 $ 218,714 ======== ========
Weighted average assumptions were as follows: 2002 2001 2000 Discount rate at the end of the year 6.5% 7.25% 7.5% Expected return on plan assets for the year (net of investment expenses) 9.4% 9.4% 9.3% Rate of compensation increase at the end of the year 4.0% 4.0% 4.0% The expected return on Plan assets has been adjusted to 8.4% in 2003.
Components of net periodic benefit (income)/cost were as follows: (in thousands) 2002 2001 2000 Service cost $ 14,871 $ 14,027 $ 14,636 Interest cost 57,564 57,050 59,798 Expected return on plan assets (74,426) (78,397) (85,884) Amortization of prior service cost (863) (118) 448 Amortization of transition obligation 601 601 601 Recognized actuarial loss 13,451 775 - Net periodic benefit (income)/cost before allocation to affiliates $ 11,198 $ (6,062) $(10,401) ======= ======= =======
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 funds these 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. The Company, as the sponsor of the Plan, allocated net costs and was reimbursed by its affiliated companies a total of $4.4 million and $1.2 million in 2002 and 2001, respectively. Funded Status The Plan's assets have been affected by significant declines in the equity markets in the past three years. These conditions have impacted the funded status of the Plan at December 31, 2002. As a result of the negative investment performance, at December 31, 2002, the accumulated benefit obligation exceeded Plan assets. Therefore, the Company is required to recognize an additional minimum liability as prescribed by SFAS No. 87, "Employers' Accounting for Pensions" (SFAS 87) and SFAS No. 132, "Employers' Disclosures about Pensions and Postretirement Benefits." The additional minimum liability results in the netting of the Prepaid pension cost with the additional minimum liability on the accompanying Consolidated Balance Sheet. Under SFAS 87, Boston Edison is also required to net its prepaid pension balance. The additional minimum liability adjustment, which is equal to the sum of the minimum pension liability and the prepaid pension adjustment, would be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income and would not affect the results of operations for 2002. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability will be adjusted each year to reflect this measurement. At such time that the Plan assets exceed the ABO, the minimum liability would be reversed. In November 2002, the Company filed a request with the MDTE seeking an accounting ruling to mitigate the impact of the non- cash charge to OCI in 2002 and the increases in expected pension and PBOP costs in 2003. On December 20, 2002, the MDTE approved the Accounting Order. Based on this Accounting Order and an opinion from legal counsel regarding the probability of recovery of these costs in the future, the Company recorded a regulatory asset in lieu of taking a charge to OCI at December 31, 2002. In addition, the order permits the Company to defer, as a regulatory asset or liability, the difference between the level of pension and PBOP expense that is included in rates and the amounts that are required to be recorded under SFAS 87 and SFAS 106 beginning in 2003. The regulatory asset of $262.6 million, recorded as a result of this accounting ruling, consists of the prepaid pension asset ($257 million) and includes the Company's portion of the additional minimum liability ($5.6 million) incurred at December 31, 2002. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets. 2. Other Postretirement Benefits Boston Edison also provides, through the Group Welfare Benefits Plan for Retirees of NSTAR, 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, until April 1, 2003, of certain Medicare premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits. To fund these postretirement benefits, NSTAR, on behalf of Boston Edison and other subsidiaries, 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 cannot be presented separately for Boston Edison since the Company participates in the Plan trusts with other subsidiaries. Plan assets are available to provide benefits for all Plan participants who are former employees of Boston Edison and of other subsidiaries of NSTAR. The net periodic postretirement benefits cost allocated to the Company was $16.2 million, $14.1 million and $12.7 million in 2002, 2001 and 2000, respectively. 3. Savings Plan Boston Edison also contributes proportionately into a defined contribution 401(k) plan for substantially all employees of 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 $5 million in 2002 and $4 million in both 2001 and 2000. The plan was amended, effective April 1, 2001, to allow participants the ability to reallocate their investments in the NSTAR Common Share Fund to other investment options. Effective January 1, 2002, consistent with the EGTRRA, the plan was further amended to allow for increased maximum annual pre-tax contributions and additional "catch-up" pre-tax contributions for participants age 50 or older, acceptance of other types of "roll-over" pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share Fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year on February 1, May 1, August 1, and November 1. Note E. Capital Stock 1. Common Stock Repurchase On October 15, 2002, Boston Edison repurchased and retired 25 shares of its Common stock, par value $1 per share, for $250 million with a portion of the proceeds from the $500 million long-term debt that was issued in October 2002. 2. Cumulative Preferred Stock
Non-mandatory redeemable series: Par value $100 per share, 2,660,000 shares authorized and 430,000 issued and outstanding: (in thousands, except per share amounts) Current Shares Redemption December 31, Series Outstanding Price/Share 2002 2001 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 ====== ======
500,000 shares of the mandatory redeemable 8% Series with a par value of $100 per share were redeemed in total on December 3, 2001, plus accrued dividends from November 1, 2001 to December 1, 2001. Note F. Indebtedness
1. Long-term Debt Boston Edison's long-term debt consisted of the following: December 31, (in thousands) 2002 2001 Long-term debt Debentures: 6.80%, due March 2003 $ 150,000 $ 150,000 Floating rate (2.275% in 2002), due October 2005 100,000 - 7.80%, due May 2010 125,000 125,000 4.875%, due October 2012 400,000 - 8.25%, due September 2022 - 60,000 7.80%, due March 2023 181,000 181,000 Sewage facility revenue bonds, due through 2015 19,882 21,470 Massachusetts Industrial Finance Agency (MIFA) bonds: 5.75%, due February 2014 15,000 15,000 Transition Property Securitization Certificates: 6.45%, due through September 2005 40,555 108,986 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 1,477,327 1,107,346 Amounts due within one year (191,242) (41,639) Total long-term debt $ 1,286,085 $ 1,065,707 ========= =========
The 8.25% series due 2022 was redeemed in September 2002 at 103.780%. A $2.3 million redemption premium was paid; this transaction had minimal impact on earnings. The 7.80% series debentures 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 are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.6 million were made in 2002 and 2001. The weighted average interest rate of the bonds was 7.4% in 2002 and 2001. 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. On October 15, 2002, Boston Edison issued two new debentures: $400 million, 4.875% due in 2012 and $100 million, floating rate debentures due in 2005 priced at three-month LIBOR plus 50 basis points. Boston Edison used the proceeds to pay down short-term debt. 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 2002 are approximately $191.2 million in 2003, $70.4 million in 2004, $170.1 million in 2005, $70.3 million in 2006, and $70.2 million in 2007. 2. Financial Covenant Requirements Boston Edison has no financial covenant requirements under its long-term debt arrangements. The Transition Property Securitization Certificates held by Boston Edison's subsidiary, BEC Funding, LLC, are collaterized with a securitized regulatory asset with a balance of $493.6 million as of December 31, 2002. Boston Edison, as servicing agent for BEC Funding, collected $105.7 million in 2002. These collected funds are remitted daily to the trustee of BEC Funding. These certificates are non-recourse to Boston Edison. Boston Edison had approval from the FERC to issue up to $350 million of short-term debt until December 31, 2002. On May 31, 2002, Boston Edison received FERC authorization to issue short- term debt securities from time to time on or before December 31, 2004, with maturity dates no later than December 31, 2005, in amounts such that the aggregate principal does not exceed $350 million at any one time. Boston Edison had a $300 million revolving credit agreement with a group of banks effective through December 2002. Boston Edison replaced this credit facility with a 364-day, $350 million revolving credit agreement that expires on November 14, 2003. At December 31, 2002 and 2001, there were no amounts outstanding under these revolving credit agreements. These arrangements serve as backup to Boston Edison's $350 million commercial paper program that had no outstanding balance at December 31, 2002 and had an outstanding balance of $191.5 million at December 31, 2001. In October 2002, following receipt of the proceeds of its $500 million debt issue previously referenced, its short-term debt balance was reduced to zero. Under the terms of this agreement, Boston Edison is required to maintain a maximum total consolidated debt to total capitalization of not greater than 60% at all times, excluding Transition Property Securitization Certificates and excluding Accumulated other comprehensive income (loss) from Common Equity. Commitment fees must be paid on the total agreement amount. At December 31, 2002 and 2001, Boston Edison was in full compliance with all of the aforementioned covenants. Interest rates on the outstanding borrowings generally are money market rates and averaged 1.85% and 4.14% in 2002 and 2001, respectively. 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 $44.1 million and $13.5 million, for 2002 and 2001, respectively, approximates fair value due to the short- term nature of these securities.
2. 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, 2002 and 2001 were as follows: 2002 2001 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Long-term unsecured debt $1,477,326 $1,480,510 $1,107,346 $1,153,380 (including current maturities)
Note H. Long-Term Contracts for the Purchase of Electricity Boston Edison expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Massachusetts Electric Restructuring Act of 1997 (Restructuring Act) and MDTE orders. Boston Edison has existing long-term power purchase agreements that are expected to supply approximately 75% of its standard offer service obligation for 2003. Boston Edison has contracted with a third party supplier to provide 100% of its standard offer supply obligation through December 31, 2003. In connection with this arrangement, Boston Edison has assigned its long-term power purchase agreements to this supplier through December 31, 2003. Boston Edison is recovering its payments to suppliers through MDTE approved rates billed to customers. Boston Edison's existing portfolio of long-term power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2002. Also during 2002, Boston Edison entered into an agreement whereby all of its energy supply resource entitlements were transferred to an independent energy supplier, following which Boston Edison repurchased its energy resource needs from this independent energy supplier for Boston Edison's ultimate sale to standard offer customers. Capacity costs of long-term contracts reflect Boston Edison's proportionate share of capital and fixed operating costs of certain generating units. In 2002, these costs were attributed to 470 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 2002 was 1,109 MW.
Information related to long-term power contracts during 2002 was as follows: Proportionate share (in thousands) Range of Units of Capacity Charge Contract Capacity 2002 2002 Obligation Fuel Type of Expiration Purchased Capacity Total Through Contract Generating Unit Dates % Range Total MW Cost Cost Expiration Date Natural Gas 2010-2015 23.5-46.5 480 $70,378 $239,144 $878,541 Nuclear 2004 62 420 - 140,000 - Oil 2005-2019 25-100 209 9,675 27,653 49,423 1,109 $80,053 $406,797 $927,964 ===== ======= ======== ========
Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for the period January 1, 2003 through June 30, 2003 and for 50% of its obligation for the second-half of 2003. A Request for Proposals will be issued in the second quarter of 2003 for the remainder of the obligation. Boston Edison entered into agreements ranging in length from five to twelve-months effective January 1, 2002 through December 31, 2002 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. Boston Edison's total capacity and energy costs associated with these contracts in 2002, 2001 and 2000 were approximately $407 million, $415 million and $428 million, respectively. Boston Edison's capacity charge obligation under these contracts for the years after 2002 is as follows:
(in thousands) Capacity Charge Obligation 2003 $ 80,689 2004 85,749 2005 86,933 2006 88,283 2007 88,403 Years thereafter 497,907 Total $ 927,964 ========
Note I. Derivative Instruments - Power Contracts Boston Edison adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), effective January 1, 2001. The accounting for derivative financial instruments is subject to change based on the guidance received from the Derivative Implementation Group (DIG) of FASB. The DIG issued No. C15, "Scope Exceptions: Normal Purchases and Sales Exception for Option-Type Contracts and Forward Contracts in Electricity" on October 10, 2001, which specifically addressed the interpretation of clearly and closely related contracts that qualify for the normal purchases and sales exception under SFAS 133. The conclusion reached by the DIG was that contracts with a pricing mechanism that are subject to future adjustment based on a generic index that is not specifically related to the contracted service commodity, generally would not qualify for the normal purchases and sales exception. On April 1, 2002, the effective date of DIG C15, Boston Edison adopted the interpretation of this guidance and began marking to market certain of its long-term purchased power contracts that previously qualified for the normal purchases and sales exception. Boston Edison has one purchased power contract that contains components with pricing mechanisms that are based on a generic index, such as the GNP or CPI. Although these factors are only applied to certain ancillary pricing components of these agreements, as required by the interpretation of DIG Issue C15, Boston Edison began recording this contract at fair value on its Consolidated Balance Sheets during 2002. This action resulted in the recognition of a liability for the fair value of the above- market portion of this contract at December 31, 2002 of approximately $305 million and is a component of Deferred credits- Power contracts on the accompanying Consolidated Balance Sheets. Boston Edison has recorded a corresponding regulatory asset to reflect the future recovery of the above-market component of this contract through the transition charge. Therefore, as a result of this regulatory treatment, the recording of this contract on the accompanying Consolidated Balance Sheets does not result in an earnings impact. Boston Edison has other purchased power contracts in which the contract value is significantly above-market. However, these contracts have met the criteria for the normal purchases and sales exception pursuant to SFAS 133 and DIG Issue C15 and have not been recorded on the accompanying Consolidated Balance Sheets. The above-market portion of this contract is currently being recovered through the transition charge. Therefore, Boston Edison does not account for these types of capacity and energy contracts or purchase orders for numerous supply arrangements as derivatives. Note J. Other Electric Utility Matters Service Quality Index On October 29, 2001, and as subsequently updated, NSTAR Electric, including Boston Edison, filed proposed service quality plans for each company with the MDTE. 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. Concurrently, NSTAR Electric 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. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.25 million on NSTAR Electric of which $3.2 million related specifically to Boston Edison that was refunded to customers as a credit to their bills during the month of May 2002. This refund had no material effect on Boston Edison's consolidated financial position, cash flows or results of operations in 2002. For the four-month period ended December 31, 2001, the MDTE determined that NSTAR's performance relative to service quality measures did not warrant a penalty assessment. On February 28, 2003, NSTAR Electric and NSTAR Gas filed their 2002 Service Quality Reports with the MDTE that reflected significant improvements in reliability and performance and indicate that no penalty will be assessed for this period. The Company accounts for its service quality penalties pursuant to SFAS 5, "Accounting for Contingencies." Accordingly, these penalties are monitored on a monthly basis to determine the Company's contingent liability, and if the Company determines it is probable that a liability has been incurred and is estimable, the Company would then accrue an appropriate liability. Annually, each NSTAR utility subsidiary makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability (or credit) level from what has been accrued would be adjusted in the period an agreement is reached with the MDTE. Note K. 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 2002 are as follows: (in thousands) 2003 $ 12,811 2004 11,822 2005 10,697 2006 8,987 2007 7,737 Years thereafter 33,590 Total $ 85,644 ========
The total expense for both lease rentals and transmission agreements was $58.1 million in 2002, $57.1 million in 2001 and $45.3 million in 2000, net of capitalized expenses of $1.9 million in 2002, $2.3 million in 2001 and $1.7 million in 2000. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for the period January 1, 2003 through June 30, 2003 and for 50% of its obligation for the second-half of 2003. A Request for Proposals will be issued in the second quarter of 2003 for the remainder of the obligation. Boston Edison entered into agreements ranging in length from five to twelve-months effective January 1, 2002 through December 31, 2002 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. Boston Edison is completely recovering all of the payments it is making to suppliers and has financial and performance assurances and financial guarantees in place with those suppliers to protect Boston Edison from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, Boston Edison receives a credit rating below investment grade, that company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer to Note H, "Long-Term Contracts for the Purchase of Electricity" for a further discussion. 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, 2002, Boston Edison's portion of these guarantees was $10 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 2002, NEH repurchased a total of 325,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,725 outstanding shares from all equity holders. Through December 31, 2002, Boston Edison's reduction of its equity ownership resulting from NEH buy-back of 35,915 shares and NHH buy-back of 191 shares was approximately $870,000. Boston Edison has a 9.5% equity investment in Connecticut Yankee Atomic Power Company (CYAPC) and Yankee Atomic Electric Company (YAEC), together the Yankee Companies. Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities. Based on estimates from the Yankee Companies' management as of December 31, 2002, the total cost for decommissioning each nuclear unit is approximately as follows: $247.7 million for CY and $224.9 million for YA. Of these amounts, Boston Edison is obligated to pay $23.6 million towards the decommissioning of CY and $21.4 million toward YA. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. Boston Edison expects the Yankee Companies to seek recovery of these costs and any additional increases to these costs in rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including Boston Edison. Boston Edison would recover its share of any allowed increases from customers through its own filings with the MDTE. The various decommissioning trusts for which Boston Edison is responsible through its equity ownership are established pursuant to the Code of Federal Regulations, Title 18 - Conservation of Power and Water Resources. The investment of decommissioning funds that have been established, are managed in accordance with these federal guidelines, state jurisdictions and with the applicable Internal Revenue Service requirements. Some of the requirements state that these investments be managed independently by a prudent fund manager and that funds are to be invested in conservative, minimum risk investment securities. Any gains or losses are anticipated to be refunded to or collected from customers, respectively. 3. Environmental Matters As of December 31, 2002, Boston Edison was involved in 12 state- regulated properties ("Massachusetts Contingency Plan, or "MCP" sites") where oil or other hazardous materials were previously spilled or released. On February 4, 2003, Boston Edison closed out one of these sites and filed the required information with the Massachusetts Department of Environmental Protection. 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 result of involvement in multi-party disposal sites or third party claims associated with contamination remediation. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.7 million and $4.8 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2002 and 2001, respectively, and are the total amount of Boston Edison's estimated environmental clean-up obligations. Accordingly, this amount has not been reduced by any potential rate recovery treatment of these costs or any potential recovery from Boston Edison's insurance carriers. Prospectively, should Boston Edison be allowed regulatory rate recovery of these specific costs, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs. 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. 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 evolve or are resolved. Boston Edison's ultimate liability for future environmental remediation costs may vary from these estimates. Although, 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 consolidated financial position or results of operations for a reporting period. 4. Regulatory and Legal Proceedings a. Regulatory proceedings In December 2002, Boston Edison filed proposed transition rate adjustments for 2003, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2002. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2003. The filings were updated in February 2003 to include final costs for 2002. On November 14, 2002, Boston Edison and the AG (Settling Parties) received approval from the MDTE on a Settlement Agreement resolving issues in Boston Edison's reconciliation of costs and revenues for the year 2001. Among other issues, the Settlement Agreement includes an adjustment relating to the reconciliation of costs relating to securitization and maximum mitigation of costs incurred in relation to the purchased power agreement with Hydro Quebec. As a result of this Settlement Agreement with the AG, Boston Edison recognized approximately $11.4 million in transition charge revenues in 2002. This benefit was significantly offset by other regulatory reconciliation adjustments. In December 2001, Boston Edison filed proposed transition rate adjustments for 2002, including a preliminary reconciliation of costs and revenues through 2001. The MDTE subsequently approved tariffs for the Company effective January 1, 2002. The filing was updated in February 2002 to include final costs for 2001. The MDTE approved the reconciliation of costs and revenues for Boston Edison through 2000 in its approval of a Settlement Agreement on November 16, 2001 between Boston Edison and the Massachusetts Attorney General (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 Boston Edison's consolidated financial position, results of operations or cash flows. b. Merger Rate Plan On December 16, 2002, the Massachusetts Supreme Judicial Court (SJC) upheld the MDTE's 1999 decision to allow for the merger of BEC and COM/Energy as originally structured. The SJC decision finalized the resolution of all issues related to the appeal and did not have any impact on Boston Edison's 2002 or prior periods' consolidated financial position, cash flows or results of operations. The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy, was appealed to the SJC by the Massachusetts Attorney General (AG) and a separate group that consisted of The Energy Consortium (TEC) and Harvard University (Harvard). TEC and Harvard alleged that, in approving the rate plan and merger proposal, the MDTE committed errors of law in the following areas: (1) in adopting a public interest standard, the MDTE applied the wrong standard of review, and failed to investigate the propriety of rates and to determine that the resulting rates of Boston Edison, Cambridge Electric, ComElectric and NSTAR Gas were just and reasonable; (2) that in permitting Cambridge Electric and ComElectric to adjust their rates by $49.8 million to reflect demand-side management costs, the MDTE failed to determine whether such an adjustment was warranted in light of other cost decreases; (3) that the MDTE's approval results in an arbitrary and unjustified sharing of benefits and costs between ratepayers and shareholders; and (4) that the MDTE's approval of the rate plan guarantees shareholders recovery of future costs without any future demonstration of customer savings. The AG's brief includes similar arguments in each of these areas and adds that, in allowing recovery of the acquisition premium, the MDTE has improperly deviated from a cost basis in setting approved rates and the ratemaking policies in other jurisdictions. c. Other legal matters In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil lawsuits. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs ("legal liabilities") that would be in excess of amounts accrued. Based on the information currently available, Boston Edison does not believe that it is probable that any such additional legal liability will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in estimates could have a material impact on its results of operations for a reporting period. 5. Performance Assurances from Electricity Agreements Boston Edison has entered into a series of purchased power agreements to meet its default and standard offer service supply obligations through December 31, 2003. These agreements are generally for a term of six to twelve months. Boston Edison currently is recovering payments it is making to suppliers from its customers. Most of Boston Edison's power suppliers are subsidiaries of larger companies with investment grade or better credit ratings. Boston Edison has financial assurances and guarantees that include letters of credit in place with the parent company of the supplier, to minimize Boston Edison risk in the event the supplier encounters financial difficulties or otherwise fails to perform. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit rating, it is required to provide additional security for performance of its obligations. Boston Edison's policy is to enter into power supply arrangements only if the supplier (or its parent guarantor) has an investment grade or better credit rating. In view of current volatility in the energy supply industry, Boston Edison is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event, the supplier (or its guarantor) may not be in a position to provide the required additional security, Boston Edison may then terminate the agreement. Some of these agreements include a reciprocal provision, where in the event that Boston Edison receives a credit rating below investment grade, that company could be required to provide additional security for performance, such as a letter of credit. 6. Financial and Performance Guarantees On a limited basis, Boston Edison may enter into agreements providing financial assurance to third parties. Such agreements include surety bonds and other guarantees.
At December 31, 2002, outstanding guarantees totaled $17 million as follows: (in thousands) Surety Bonds $ 7,013 Other Guarantees 10,000 Total Guarantees $ 17,013 =======
At December 31, 2002, Boston Edison has purchased a total of approximately $600,000 of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, Boston Edison has purchased $6.4 million in workers' compensation self-insurer bonds. These bonds support the guarantee by Boston Edison to the Commonwealth of Massachusetts required as part of Boston Edison's workers' compensation self-insurance program. Boston Edison has also issued $10 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies. Management believes the likelihood Boston Edison would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Part IV Item 14. Controls and Procedures Boston Edison's disclosure controls and procedures are designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Within 90 days prior to the date of filing this Annual Report on Form 10-K, Boston Edison carried out an evaluation, under the supervision and with the participation of Boston Edison's management, including Boston Edison's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Boston Edison's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that Boston Edison's disclosure controls and procedures are effective in order to timely alert them to material information required to be disclosed by Boston Edison in the reports that it files or submits under the Securities Exchange Act of 1934. Subsequent to the date of that evaluation, there have been no significant changes in Boston Edison's internal controls or in other factors that could significantly affect internal controls, nor were any corrective actions required with regard to significant deficiencies and material weaknesses. Item 15. 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, 2002, 2001 and 2000 26 Consolidated Statements of Comprehensive Income for the years ended December 31, 2002, 2001 and 2000 27 Consolidated Statements of Retained Earnings for the years ended December 31, 2002, 2001 and 2000 27 Consolidated Balance Sheets as of December 31, 2002 and 2001 28 Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 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, 2002, 2001 and 2000 57 3. Exhibits: Refer to the exhibits listing beginning on the following page. (b) Reports on Form 8-K: A report on Form 8-K was filed on October 11, 2002 that reported on including certain exhibits for incorporation by reference into the Registration Statements on Form S-3 previously filed with the Securities and Exchange Commission (Nos. 33-57840 and 333-55890) and declared effective on February 12, 1993 and February 28, 2001, respectively with regard to the issuance of $500 million in debentures. A report on Form 8-K was filed on November 27, 2002 that reported on revised decommissioning costs of certain nuclear units in which Boston Edison has an equity ownership interest. A report on Form 8-K was filed on December 17, 2002 that reported on the Massachusetts Supreme Judicial Court affirming a 1999 MDTE order associated with the merger of BEC Energy and Commonwealth Energy System that created NSTAR. A report on Form 8-K was filed on January 3, 2003 following the MDTE approval received on December 20, 2002 to allow the Company to defer as a regulatory asset, an additional minimum liability, and the difference between the level of pension and postretirement benefits that is included in rates and the amounts that would have been recorded under SFAS 87 and SFAS 106 in 2003.
Incorporated herein by reference unless designated otherwise: 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 Form 10-Q January 22, 1987, January 28, for the 1988, May 24, 1988 and quarter November 22, 1989. ended June 30, 1994. Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.1 Indenture dated September 1, 4.1 1-2301 1988, between Boston Edison Form 10-Q Company and The Bank of New for the York (as successor to Bank of quarter Montreal Trust Company). ended September 30, 1988. 4.2 Votes of the Pricing 4.1.5 1-2301 Committee of the Board of Form 10-K Directors of Boston Edison for the Company taken May 18, 1995 re year ended 7.80% debentures due May 15, December 2010. 31, 1995. 4.3 Votes of the Board of 4.2 1-2301 Directors of Boston Edison Form 8-K Company taken October 8, 2002 dated re $500 million aggregate October 11, principal amount of unsecured 2002. debentures ($400 million, 4.875% due in 2012 and $100 million, floating rate due in 2005). 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 10.12 1-2301 Restructuring Settlement Form 10-K Agreement dated July 1997. for the year ended December 31, 1997. 10.2 Boston Edison Company and 10.1 1-2301 Sithe Energies, Inc. Purchase Form 10-Q and Sale and Transition for the Agreements dated December 10, quarter 1997. ended March 31, 1998. 10.3 Boston Edison Company and 10.12 1-2301 Entergy Nuclear Generation Form 10-K Company Purchase and Sale for the Agreement dated November 18, year ended 1998. December 31, 1999. Exhibit 12 Statement re Computation of Ratios 12.1 Computation of Ratio of Earnings to Fixed Charges for the Year Ended December 31, 2002 (filed herewith). 12.2 Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year Ended December 31, 2002 (filed herewith). Exhibit 21 Subsidiaries of the Registrant 21.1 Filed herewith. Exhibit 99 Additional Exhibits 99.1 Certification Statement of Chief Executive Officer of Boston Edison Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 99.2 Certification Statement of Chief Financial Officer of Boston Edison Company pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
SCHEDULE II BOSTON EDISON COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000 (in thousands) Balance at Provisions Deductions Balance Beginning Charged to Accounts at End Description Of Year Operations Recoveries Written Off Of Year Allowance for Doubtful Accounts Year Ended December 31, 2002 $24,691 $10,699 $4,630 $20,936 $19,084 Year Ended December 31, 2001 $22,415 $13,000 $2,089 $12,813 $24,691 Year Ended December 31, 2000 $19,380 $11,954 $ 471 $9,390 $22,415
FORM 10-K Boston Edison Company DECEMBER 31, 2002 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 27, 2003 By: /s/Robert J. Weafer, Jr. Robert J. Weafer, Jr. Vice President, Controller and Chief Accounting 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 indicated on the 27th day of March 2003.
Signature Title Chairman, President, Chief /s/ Thomas J.May Executive Officer and Director Thomas J. May Senior Vice President, /s/ James J. Judge Treasurer, Chief Financial James J. Judge Officer and Director Director /s/ Douglas S. Horan Douglas S. Horan
Sarbanes - Oxley Section 302(a) Certifications I, Thomas J. May, certify that: 1. I have reviewed this Annual Report on Form 10-K of Boston Edison Company; 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of Boston Edison Company as of, and for, the periods presented in this Annual Report; 4. Boston Edison Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a- 14 and 15d-14) for Boston Edison Company and we have: a) designed such disclosure controls and procedures to ensure that material information relating to Boston Edison Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of Boston Edison Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. Boston Edison Company's other certifying officer and I have disclosed, based on our most recent evaluation, to Boston Edison Company's auditors and the audit committee of NSTAR's Board of Trustees: a) all significant deficiencies in the design or operation of internal controls which could adversely affect Boston Edison Company's ability to record, process, summarize and report financial data and have identified for Boston Edison Company's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. Boston Edison Company's other certifying officer and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 27, 2003 By /s/ THOMAS J. MAY Thomas J. May Chairman, President and Chief Executive Officer I, James J. Judge, certify that: 1. I have reviewed this Annual Report on Form 10-K of Boston Edison Company: 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of Boston Edison Company as of, and for, the periods presented in this Annual Report; 4. Boston Edison Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a- 14 and 15d-14) for Boston Edison Company and we have: a) designed such disclosure controls and procedures to ensure that material information relating to Boston Edison Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of Boston Edison Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. Boston Edison Company's other certifying officer and I have disclosed, based on our most recent evaluation, to Boston Edison Company's auditors and the audit committee of NSTAR's Board of Trustees: a) all significant deficiencies in the design or operation of internal controls which could adversely affect Boston Edison Company's ability to record, process, summarize and report financial data and have identified for Boston Edison Company's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in Boston Edison Company's internal controls; and 6. Boston Edison Company's other certifying officer and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 27, 2003 By: /s/ JAMES J. JUDGE James J. Judge Senior Vice President, Treasurer and Chief Financial Officer
EX-12 3 becoexhibit12.txt BOSTON EDISON EXHIBIT 12.1 AND 12.2 Exhibit 12.1
Boston Edison Company Computation of Ratio of Earnings to Fixed Charges Year Ended December 31, 2002 (in thousands) Net income from continuing operations $ 134,103 Income taxes 92,282 Fixed charges (including securitization certificates) 115,149 Total $ 341,534 ========= Interest expense $ 95,771 Interest component of rentals 19,378 Total $ 115,149 ========= Ratio of earnings to fixed charges 2.97 ====
Exhibit 12.2
Boston Edison Company Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements Year Ended December 31, 2002 (in thousands) Net income from continuing operations $ 134,103 Income taxes 92,282 Fixed charges (including securitization certificates) 115,149 Total $ 341,534 ======== Interest expense $ 95,771 Interest component of rentals 19,378 Subtotal 115,149 Preferred stock dividend requirements 3,309 Total $ 118,457 ======== Ratio of earnings to fixed charges 2.88 ====
EX-21 4 becoexhibit21.txt BOSTON EDISON EXHIBIT 21 Exhibit 21.1
Subsidiaries of Boston Edison Company State of Incorporation Harbor Electric Energy Company Massachusetts BEC Funding LLC Delaware
EX-99 5 becoexhibit991.txt BOSTON EDISON EXHIBIT 99.1 EXHIBIT 99.1
CERTIFICATION PURSUANT TO 18 U.S.C SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 The undersigned hereby certifies, in my capacity as an officer of Boston Edison Company, for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge: (i) the enclosed Annual Report of Boston Edison Company on Form 10-K for the year ended December 31, 2002 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (ii) the information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of Boston Edison Company. Dated: March 27, 2003 By: /s/ THOMAS J. MAY Thomas J. May Chairman, President and Chief Executive Officer
EX-99 6 becoexhibit992.txt BOSTON EDISON EXHIBIT 99.2 EXHIBIT 99.2
CERTIFICATION PURSUANT TO 18 U.S.C SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 The undersigned hereby certifies, in my capacity as an officer of Boston Edison Company, for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge: (i) the enclosed Annual Report of Boston Edison Company on Form 10-K for the year ended December 31, 2002 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (ii) the information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of Boston Edison Company. Dated: March 27, 2003 By: /s/ JAMES J. JUDGE James J. Judge Senior Vice President, Treasurer and Chief Financial Officer
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