-----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, HRagMJxOpFIp2WUKGLpWSEe/WWf6+y2J/YLij2F6CdWg64qsW0TztQglBAU8AjGH HwXecoBiHkPOyknA1LZJlw== 0001035675-01-500009.txt : 20010326 0001035675-01-500009.hdr.sgml : 20010326 ACCESSION NUMBER: 0001035675-01-500009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010323 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NSTAR/MA CENTRAL INDEX KEY: 0001035675 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 046830187 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-14768 FILM NUMBER: 1577573 BUSINESS ADDRESS: STREET 1: 800 BOYLSTON ST CITY: BOSTON STATE: MA ZIP: 02199 BUSINESS PHONE: 6174242000 MAIL ADDRESS: STREET 1: 800 BOYLSTON ST CITY: BOSTON STATE: MA ZIP: 02199 FORMER COMPANY: FORMER CONFORMED NAME: B E C ENERGY DATE OF NAME CHANGE: 19980421 FORMER COMPANY: FORMER CONFORMED NAME: BOSTON EDISON HOLDINGS DATE OF NAME CHANGE: 19970313 10-K 1 anstar200010k.txt NSTAR 10K FOR 2000 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 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, 2000 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 1-14768 NSTAR (Exact name of registrant as specified in its charter) Massachusetts 04-346630 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 800 Boylston Street, Boston Massachusetts 02199 (Address of principle executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Shares, Par Value $1 per New York Stock Exchange share Boston Stock Exchange
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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X The aggregate market value of the voting stock held by non- affiliates of the registrant as of March 15, 2001 computed as the average of the high and low market price of the common shares as reported in the listing of composite transactions for New York Stock Exchange listed securities in the Wall Street Journal: $2,079,671,291. Indicate the number of shares outstanding of each for the registrant's classes of common stock, as of the latest practicable date. Class Outstanding at March 15,2001 Common Shares, $1 par value 53,032,546 Shares Documents Incorporated by Reference Part in Form 10-K Portions of the Registrant's Parts I, II and III Definitive Proxy Statement Dated March 23, 2001 (pages as specified herein)
NSTAR Form 10-K Annual Report December 31, 2000 Page Part I Item 1. Business 2 Item 2. Properties 10 Item 3. Legal Proceedings 11 Item 4. Submission of Matters to a Vote of Security Holders 12 Item 4A. Executive Officers of the Registrant 13 Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 14 Item 6. Selected Financial Data 15 Item 7. Management's Discussion and Analysis 15 Item 7A. Quantitative and Qualitative Disclosures About 33 Market Risk Item 8. Financial Statements and Supplementary Financial 34 Information Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 66 Part III Item 10. Trustees and Executive Officers of the Registrant 67 Item 11. Executive Compensation 67 Item 12. Security Ownership of Certain Beneficial Owners and 67 Management Item 13. Certain Relationships and Related Transactions 67 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports 68 on Form 8-K
Part I Item 1. Business (a) General Development of Business NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts including more than one million electric customers in 81 communitites and 244,000 gas customers in 51 communitites. NSTAR also supplies electricity at wholesale for resale to municipalities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas) and its wholesale electric sudsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR's non-utility operations include telecommunications - NSTAR Communications, Inc (NSTAR Com), district heating and cooling operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation) and liquefied natural gas services (Hopkinton LNG Corp.). Utility operations accounted for more than 97% of revenues in both 2000 and 1999. The electric and natural gas industries have continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. The demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy. An integral part of the merger creating NSTAR is the rate plan of the retail utility subsidiaries of BEC and COM/Energy that was approved by the Massachusetts Department of Telecommunication and Energy (MDTE) in July 1999. The costs associated with the merger consisting primarily of severance costs associated with a voluntary separation program are expected to be offset by ongoing future cost savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. As a result of the merger, cost savings have been realized due to reduced staffing levels and operating efficiencies. Refer to the Retail Electric Rates section in Item 7, "Management's Discussion and Analysis" for more information. In 1998, Boston Edison completed the sale of all of its fossil generating assets and in 1999, sold its Pilgrim Nuclear Generating Station. COM/Energy sold substantially all of its fossil generating assets in 1998. Refer to the Generating Assets Divestiture section in Item 7, "Management's Discussion and Analysis" for more information. (b) Financial Information about Industry Segments NSTAR's principal operating segments are the electric and natural gas utilities that provide energy delivery services in over 100 cities and towns in Massachusetts. Refer to Note K of the Consolidated Financial Statements in Item 8 for specific financial information related to NSTAR's electric utility, gas utility and unregulated non-utility segments. (c) Narrative Description of Business Principal Products and Services NSTAR ELECTRIC NSTAR Electric operating revenues by class of customers for the last three years consisted of the following:
2000 1999 1998 Retail electric revenues: Commercial 47% 51% 51% Residential 32% 30% 27% Industrial 8% 9% 9% Other 1% 1% 1% Wholesale and contract revenues 12% 9% 12%
The results for 2000 reflect NSTAR for a full year, while the results for 1999 reflect eight months of BEC and four months of NSTAR. NSTAR Electric currently supplies electricity at retail to an area of 1,702 square miles. The territory served includes the city of Boston and 80 surrounding cities and towns including Cambridge, New Bedford and Plymouth and the geographic area comprising Cape Cod and Martha's Vineyard. The population of the area served with electricity at retail is approximately 2.2 million. In 2000, NSTAR Electric served approximately 1.1 million customers. Sources and Availability of Electric Power Supply NSTAR Electric entered into various six-month agreements during 2000 to transfer substantially all of the unit output entitlements in long-term power purchase contracts to suppliers, who in turn provided full energy service to meet NSTAR Electric's standard offer and default service load requirements. NSTAR Electric entered into a six-month agreement effective January 1, 2001 through June 30, 2001 with a supplier to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. A default service request for proposal, applicable to the second half of 2001, will be issued in early 2001. NSTAR Electric's existing portfolio of power purchase contracts is supplying the majority of its standard offer and wholesale energy requirements, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric is managing its Independent System Operator-New England (ISO-New England) capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. For further information refer to Note M of the Consolidated Financial Statements in Item 8. ComElectric had an 11% contract entitlement in the output of the Pilgrim nuclear power plant that was sold by Boston Edison in 1999 to Entergy Nuclear Generating Company (Entergy). Boston Edison and ComElectric will buy power generated by the Pilgrim plant from Entergy on a declining basis through 2004. NSTAR Electric also has a 2.5% equity investment in the 540 MW Vermont Yankee nuclear power plant. NSTAR Electric is entitled to electricity produced from the facility based on its ownership interest and is billed for its entitlement pursuant to a contractual agreement that is approved by the Federal Energy Regulatory Commission (FERC). Vermont Yankee has received the approval of FERC to include charges for the estimated costs of decommissioning its unit in the costs of energy that it sells. Periodically, Vermont Yankee re-estimates the cost of decommissioning and applies to the FERC for increased rates in response to increased decommissioning costs. The Vermont Yankee unit was under agreement to be sold to Amergen Energy Company, but this transaction was disapproved on February 14, 2001 by the state of Vermont's regulatory authority. Information relative to nuclear units that are no longer operating in which NSTAR has an equity ownership is as follows:
Connecticut Maine Yankee Yankee Yankee Atomic (dollars in thousands) Year of Shutdown 1996 1997 1992 Equity Ownership (%) 14 4 14 Equity Ownership Balance $ 10,409 $ 2,881 $ 1,078
New England Power Pool (NEPOOL) During 1997, NEPOOL was restructured with changes taking effect to the membership and governance provisions of the power pooling agreement along with the transfer of operating responsibility of the integrated transmission and generation system in New England to ISO-New England. Previously, NEPOOL dispatched generating units for operation based on the lowest operating costs of available generation and transmission. Under the new structure, generators will be required to provide ISO-New England with market prices at which they will sell short-term energy supply. These prices formed the basis for dispatch that began in the second quarter of 1999. As noted in the Sources and Availability of Electric Power Supply section above, NSTAR Electric has existing long-term power purchase contracts that will supply 90% - - 95% of its standard offer service obligations. Therefore, the change to NEPOOL's operations and pricing structure is expected to have no material adverse impact on NSTAR's costs for purchased electric energy. Retail Electric Rates As a result of electric industry restructuring, NSTAR Electric has unbundled its rates, provided customers with inflation adjusted rates that are 15 percent lower than rates in effect prior to March 1, 1998, the retail access date, and have afforded customers the opportunity to purchase generation supply in the competitive market. Unbundled delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge (to collect the costs of delivering electricity), a transition charge (to collect past costs for investments in generating plants and costs related to power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Electricity supply services provided by NSTAR Electric include optional standard offer service and default service. Standard offer service is the electricity that is supplied to eligible customers by the retail electric subsidiaries until a competitive power supplier is chosen by the customer. It is designed as a seven-year transitional service (from March 1, 1998) to give the customer time to learn about competitive power suppliers. The price of standard offer service increases over time. Default service is supplied by the local distribution company when a customer is not eligible for standard offer service or receiving power from a competitive power supplier. The market price for default service will fluctuate based on the average market price for power. Amounts collected through these various charges are reconciled to actual expenditures on an on- going basis. Prior to the implementation of industry restructuring on March 1, 1998, NSTAR Electric had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. NSTAR Gas NSTAR Gas operating revenues by class of customers for 2000 and 1999 (effective September 1, 1999), consisted of the following:
2000 1999 Retail Gas revenues: Residential 59% 61% Commercial 24% 24% Industrial 3% 4% Other 8% 6% Wholesale and contract revenues 6% 5%
Natural gas is distributed by NSTAR Gas to approximately 244,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1,128,000. 25 of these communities are also served by NSTAR Electric with electricity. Some of the larger communities served by NSTAR Gas include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston. Gas Supply NSTAR Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that bring gas from major supply areas to the final delivery points. NSTAR Gas purchases all of its gas supplies from third-party vendors, primarily under firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil producers. In November 2000, NSTAR Gas entered into a five-month full services firm supply agreement with a major marketer in order to more fully optimize its supply portfolio. In June 2000, the MDTE approved various changes that NSTAR Gas had made to its pipeline transportation and storage portfolio. These changes enabled NSTAR Gas to reduce its overall upstream portfolio cost while maintaining supply reliability. In addition to firm transportation and gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a combination of existing and new agreements that are the result of FERC Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season. On November 17, 1995, the MDTE approved the NSTAR Gas Original Alberta Northeast (ANE) Contract between NSTAR Gas and ANE for the purchase of approximately 4.5 million cubic feet per day of natural gas from Alberta, Canada. The MDTE approved the Gas Sales Agreement between ANE Gas Limited and NSTAR Gas as filed on March 3, 1999. Previous to the Agreement, NSTAR Gas purchased its Canadian supply through Boston Gas Company. The agreement allows NSTAR Gas to receive up to 4,500 MMBtu/day of Canadian supply delivered into the Iroquois Gas Transmission system. In compliance with this order, NSTAR Gas also signed transportation agreements with the Tennessee Gas Pipeline and Iroquois Pipeline. NSTAR Gas also transports gas on its distribution system for end- users. As of December 31, 2000, there were approximately 725 commercial and industrial NSTAR GAS customers using transportation service, accounting for 12,696 BBTU or approximately 26% of total throughput. Effective November 1, 2000, with the MDTE's approval of NSTAR Gas' Transportation Terms and Conditions, transportation service became available to all system customers. A portion of the gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of NSTAR. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas. In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG trucked from Hopkinton. NSTAR Gas has contracts for LNG service with Hopkinton extending on a year-to-year basis with notice of termination required five years in advance of the anticipated termination date. Current contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge that covers liquefaction and vaporization expenses. NSTAR Gas furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of NSTAR Gas. Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, NSTAR Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales. Off-system Gas Sales and Capacity Release Service NSTAR Gas utilizes the off-system sales and capacity release markets as a means to sell excess resources. Off-system sales totaled 2,458 BBTU in 2000, while 36,810 BBTU of capacity was sold in the capacity release market. NSTAR Gas retains 25% of the gross margins realized above a certain threshold amount as set from year to year, with the remaining margins credited to firm customers. As a result of this margin-sharing agreement, NSTAR Gas retained approximately $189,000 and $294,000 in 2000 and 1999, respectively. Natural Gas Industry Restructuring and Rates In September 1997, NSTAR Gas along with other gas utilities initiated the Massachusetts Gas Unbundling Collaborative (the Collaborative) to explore and develop generic principles to achieve the MDTE's goals of establishing choice of gas supplier for all customers (comprehensive unbundling). In August 1998, the MDTE approved the unbundled rate settlement submitted by NSTAR Gas, followed in September with compliance rates submitted by NSTAR Gas that were consistent with a settlement agreement. These unbundled rates became effective on November 1, 1998. NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers do not materially affect NSTAR Gas' operating income because substantially all the margin on such service is returned to its firm customers as cost reductions. In addition to delivery services rates, NSTAR Gas' tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas supply costs from firm sales customers or default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. In late 1998, the MDTE issued an order establishing rules and regulations governing the unbundling of retail gas service to all customers in Massachusetts. Prior to this, only commercial and industrial customers were able to obtain competitive gas supply service from a source other than the local distribution company (LDC) such as NSTAR Gas. These regulations are similar to those adopted by the MDTE governing electric restructuring. Among the important provisions are: setting the LDC as the default service provider, certification of competitive suppliers/marketers, extension of the MDTE's consumer protection rules to residential customers taking competitive service, requirement for LDCs to provide suppliers/marketers with customer usage data, and requirement for suppliers/marketers to disclose service terms to potential customers. In addition, the MDTE has standardized the eligibility requirements for low-income rates for all LDCs that are identical to previously established requirements for electric customers. In February 1999, the MDTE issued an order requiring the mandatory assignment of the LDC's upstream pipelines and storage capacity and downstream peaking capacity to customers who elect a competitive gas supply during a three-year transition period. This eliminates potential stranded cost exposure for the LDCs until they are relieved from their responsibility as suppliers of last resort and the establishment of a "workably competitive" interstate pipeline capacity market. In January 2000, the MDTE approved the Model Terms and Conditions submitted by the LDCs that provided the framework for implementing the regulations. In October 2000, the MDTE approved compliance Terms and Conditions submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. With the issuance of these orders and regulations, the MDTE moved the date for full customer choice to November 1, 2000. NSTAR Gas has modified its billing, customer and gas supply systems to accommodate full retail choice. As a result of these orders, gas restructuring is likely to have no significant financial impact on LDCs. RCN Joint Venture and Investment Conversion NSTAR Com is a participant in a telecommunications venture with RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN Corporation (RCN). NSTAR Com accounts for its Class A Equity investment in the joint venture using the equity method of accounting. As part of the Joint Venture Agreement, NSTAR Com has the option to exchange portions of its joint venture interest for common shares of RCN at specified periods. For a further discussion on these exchanges and other developments, refer to the RCN Joint Venture and Investment Conversion section in Item 7, "Management's Discussion and Analysis" for more information. Franchises Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of distributing and selling electricity, natural gas, steam and other forms of energy, have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines or gas distribution are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the actions of these authorities is subject to appeal to the MDTE. The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature. Pursuant to the Restructuring Act enacted in November 1997, the MDTE has defined the service territory of NSTAR Electric and NSTAR Gas 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, these companies 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 NSTAR Electric and/or NSTAR Gas, which consent must be filed with the MDTE and the municipality so affected. Regulation NSTAR Electric, NSTAR Gas, and Boston Edison's wholly owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, natural gas and financing and investing activities. In addition, the FERC has jurisdiction over various phases of NSTAR Electric and NSTAR Gas utility businesses including rates for electricity and natural gas 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 capital expenditures, long-term debt maturities and preferred stock redemption requirements for the years 2001 through 2005 are as follows:
2001 2002 2003 2004 2005 (in thousands) Capital expenditures (1) $295,300 $187,900 $163,700 $181,100 $136,900 Long-term debt $ 45,619 $108,836 $241,168 $ 78,659 $ 77,559 Preferred stock $ 50,000 $ - $ - $ - $ -
(1) Includes both plant expenditures and capital requirements of non-utility ventures. 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, environmental standards, availability and cost of capital, interest rates and other assumptions. Plant expenditures in 2000 were $182.7 million and consisted primarily of additions to NSTAR'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 NSTAR service territory. Refer to the Liquidity section of Item 7 for more information regarding capital resources to fund NSTAR's construction programs. Seasonal Nature of Business 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. Refer to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 6 for specific financial information by quarter for 2000 and 1999. NSTAR Gas' sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. Competitive Conditions The electric and natural gas industries have 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 NSTAR's subsidiaries are subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality 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. Refer to the Other Matters - Environmental section in Item 7, "Management's Discussion and Analysis" for more information. Environmental-related capital expenditures for the years 2000 and 1999 were $4.5 million and $0.6 million, respectively. Management believes that its remaining operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur. Number of Employees As of December 31, 2000, NSTAR's subsidiaries had approximately 3,300 full-time employees, including approximately 2,300 or 70% of employees represented by nine collective bargaining units covered by separate contracts. In December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America, AFL-CIO. The new agreement results in a single bargaining unit of 2,000 NSTAR Electric and Gas employees and one five-year contract expiring May 15, 2005 that will replace seven separate and widely diverse agreements. The other remaining collective bargaining unit contract expires March 31, 2002. Management believes it has satisfactory employees relations. (d) Financial Information about Foreign and Domestic Operations and Export Sales None of NSTAR's subsidiaries have any foreign operations or export sales. Item 2. Properties Substantially all of NSTAR's fossil generating assets were sold as of December 30, 1998. The Pilgrim Nuclear Generating Station was sold in 1999. NSTAR, through its Canal Electric subsidiary, still retains a 3.52% interest (40.5 MW of capacity) in Seabrook 1. Other NSTAR Electric properties include an integrated system of distribution lines and substations that are located primarily in the Boston area as well as the outlying communities, including Plymouth, New Bedford, Cape Cod communities and Martha's Vineyard. In addition, NSTAR Electric's other principal properties consist of an office building and other structures such as garages and service buildings. At December 31, 2000, the NSTAR Electric transmission and distribution system consisted of 17,078 pole miles of overhead lines, 10,867 cable miles of underground lines, 287 substations and 1,112,000 active customer meters. The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 2000, the gas system included 2,884 miles of gas distribution lines, 173,247 services and 251,919 customer meters together with the necessary measuring and regulating equipment. In addition, NSTAR owns a liquefaction and vaporization plant, a satellite vaporization plant and above- ground cryogenic storage tanks having an aggregate storage capacity equivalent to 3.5 million MCF of natural gas. NSTAR Gas owns an office and service building in Southborough, Massachusetts, five district office buildings and several natural gas receiving and take stations. NSTAR Electric's high-tension transmission lines are generally located on land either owned or subject to easements in its favor. Its low-tension distribution lines are located principally on public property under permission granted by municipal and other state authorities. In completion of its corporate facilities consolidation, NSTAR is constructing a 370,000 square foot office building (the Summit) sited on 33 acres in the Boston suburb of Westwood. This site is centrally located in NSTAR's service area and will house central corporate offices including finance, human resources, sales, engineering, information technology, and customer care. NSTAR expects to consolidate more than a third of its workforce into the building during the third quarter of 2001. District heating and cooling operations primarily consist of the Medical Area Total Energy Plant (MATEP) located in the Longwood Medical Area of Boston. MATEP provides steam, chilled water and electricity to over 9 million square feet in medical and teaching facilities. 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 only customer, the Massachusetts Water Resources Authority, at this location. Item 3. Legal Proceedings Industry and corporate restructuring legal proceedings The MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court (SJC). One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations. Regulatory proceedings In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be a material adverse impact on NSTAR's consolidated financial position, cash flows and the results of operations in the near term. In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Edison Technology Group and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999 and no further developments have occurred at this time. Management is currently unable to determine the timing of and the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and results of operations for a reporting period. Other litigation In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Station, filed suit against Boston Edison. The town claimed that Boston Edison wrongfully failed to execute an agreement with the town for payments in addition to or in lieu of taxes due to the town under the Restructuring Act. Boston Edison and the town settled the suit and agreed in March 1999 on a 15- year, $141 million payment as required by the Restructuring Act. Payments in each of the first four years are approximately $15 million after which payments gradually decline. All payments under this agreement will be recovered from customers through the transition charge. In the normal course of its business, NSTAR and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the fourth quarter of 2000. Item 4A. Executive Officers of Registrant Identification of Executive Officers
Age Name of Officer Position and Business Experience December 31, 2000 Thomas J. May Chairman of the Board, Chief 53 Executive Officer and a Director/Trustee (since 1999), NSTAR and its subsidiaries; formerly Chairman of the Board, President and Chief Executive Officer and a Trustee (1998-1999) BEC Energy, and Chairman of the Board, President, and Chief Executive Officer and a Director (1995-1999), Boston Edison Company; Director, FleetBoston Financial; Liberty Financial Companies, Inc.; Liberty Mutual Insurance Company; New England Business Services, Inc. and RCN Corporation. Russell D. Wright President, Chief Operating Officer 54 and a Director/Trustee (since 1999), NSTAR and its subsidiaries; formerly President, and Chief Executive Officer and a Trustee (1998-1999), Commonwealth Energy System; and President, Chief Operating Officer and a Director (1993-1998), Commonwealth Energy System's operating subsidiaries; Director, Reed and Barton. Deborah A. Executive Vice President-Customer 42 McLaughlin Care/Shared Services, NSTAR (since 1999); President and Chief Operating Officer, Commonwealth Energy System's operating subsidiaries (1998-1999); Vice President - Customer Service, Commonwealth Energy System's operating subsidiaries (1993- 1998). Douglas S. Horan Senior Vice President/Strategy, 50 Law & Policy, Clerk and General Counsel, NSTAR (since 1999); formerly Senior Vice President-Strategy and Law and General Counsel, BEC Energy (1998- 1999) and Boston Edison Company (1995-1999). James J. Judge Senior Vice President, Treasurer 44 and Chief Financial Officer, NSTAR (since 2000); formerly Senior Vice President and Chief Financial Officer, NSTAR (1999-2000); Senior Vice President-Corporate Services and Treasurer, BEC Energy (1998- 1999); Senior Vice President-Corporate Services and Treasurer, Boston Edison Company (1995-1999). Age December Name of Officer Position and Business Experience 31, 2000 Joseph R. Nolan, Senior Vice President - Corporate 37 Jr. Relations, NSTAR (since 2000); formerly Vice President of Government Affairs, NSTAR (1999- 2000); Director of Regulatory Relations, BEC Energy (1998-1999); Manager of Legislative Affairs, Boston Edison Company (1994-1998); Robert J. Weafer, Vice President, Controller and 53 Jr. Chief Accounting Officer, NSTAR (since 1999), BEC Energy (1998- 1999) and Boston Edison Company (1991-1998).
Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters (a) Market Information NSTAR's common shares are listed on the New York and Boston Stock Exchanges. The high and low market value per common share as reported in the Wall Street Journal for each of the quarters in 2000 and 1999 was as follows. (Prior to September 1999, the information listed refers to BEC Energy common shares.)
2000 1999 High Low High Low First quarter $47.00 $38.25 $41.1875 $36.4375 Second quarter $46.125 $40.375 $44.625 $37.1875 Third quarter $44.5625 $39.00 $43.3125 $36.75 Fourth quarter $43.1875 $36.375 $42.375 $36.625
(b) Holders As of December 31, 2000, there were 32,635 holders of NSTAR common shares. (c) Dividends Dividends declared per common share for each of the quarters in 2000 and 1999 were as follows. (Prior to September 1999, the information listed refers to BEC Energy common shares.)
2000 1999 First quarter $0.500 $0.485 Second quarter $0.500 $0.485 Third quarter $0.500 $0.485 Fourth quarter $0.515 $0.500
Item 6. Selected Financial Data The following table summarizes five years of selected consolidated financial data (in thousands, except per share data). Prior to September 1999, the information below refers to BEC Energy.
2000 1999(b) 1998 1997 1996 Operating revenues $2,699,506 $1,851,427 $1,622,515 $1,778,531 $1,668,856 Net income $ 180,962 $ 146,463 $ 141,046 $ 144,642 $ 141,546 Earnings per share of common stock: Basic $ 3.19 $ 2.77 $ 2.76 $ 2.71 $ 2.61 Diluted $ 3.18 $ 2.76 $ 2.75 $ 2.71 $ 2.61 Total assets $5,569,514 $5,466,143 $3,204,036 $3,622,347 $3,729,291 Long-term debt (a) $1,440,431 $ 986,843 $ 955,563 $1,057,076 $1,058,644 Transition property securitization certificates (a) $ 584,130 $ 646,559 $ - $ - $ - Redeemable preferred stock (a) $ 43,000 $ 92,279 $ 92,040 $ 163,093 $ 203,419 Cash dividends declared per common share $ 2.015 $ 1.955 $ 1.895 $ 1.880 $ 1.880
(a) Excludes the current portion of long-term debt or preferred stock. (b) Due to the application of the purchase method of accounting, the results for 1999 reflect eight months of BEC Energy and four months of NSTAR. Selected Consolidated Quarterly Financial Data (Unaudited)
Earnings Basic Available Earnings Operating Operating Net for Common Per Average Revenue Income Income Shareholders Common Share(a) (in thousands, except earnings per share) 2000 First quarter $ 665,262 $ 79,401 $ 37,099 $ 35,609 $ 0.62 Second quarter $ 630,194 $ 76,955 $ 32,928 $ 31,438 $ 0.57 Third quarter $ 709,519 $ 127,158 $ 66,286 $ 64,796 $ 1.21 Fourth quarter $ 694,531 $ 106,556 $ 44,649 $ 43,159 $ 0.81 1999 First quarter $ 371,870 $ 43,729 $ 19,562 $ 18,072 $ 0.38 Second quarter $ 379,290 $ 58,669 $ 36,253 $ 34,763 $ 0.76 Third quarter $ 517,151 $ 85,022 $ 68,260 $ 66,770 $ 1.32 Fourth quarter $ 583,116 $ 76,278 $ 22,388 $ 20,898 $ 0.35
(a) The sum of the quarters may not equal basic annual earnings per average common share since the result is based on the weighted average number of common shares outstanding each quarter. Item 7. Management's Discussion and Analysis NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts including more than one million electric customers in 81 communities and 244,000 gas customers in 51 communities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas) and its wholesale electric subsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR's non-utility operations include telecommunications - NSTAR Communications, Inc. (NSTAR Com), district heating and cooling operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation) and liquefied natural gas services (Hopkinton LNG Corp.). Utility operations accounted for more than 97% of revenues in both 2000 and 1999. The electric and natural gas industries have continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy. The 1997 Massachusetts Electric Restructuring Act (Restructuring Act) required all electric utilities to divest their generating assets and leave the retail power supply business, in exchange for the right to recover all non-mitigable stranded costs associated with the creation of customer choice and competition. Merger of BEC Energy and Commonwealth Energy System An integral part of the merger creating NSTAR is the rate plan of the retail utility subsidiaries of BEC and COM/Energy that was approved by the Massachusetts Department of Telecommunications and Energy (MDTE) on July 27, 1999. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Refer to the Retail Electric Rates section of this Discussion and Analysis for more information. The merger was accounted for by NSTAR as an acquisition of COM/Energy by BEC under the purchase method of accounting. Goodwill amounted to approximately $490 million, resulting in annual amortization of goodwill of approximately $12.2 million. Costs to achieve are being amortized based on the filed estimate of $111 million over 10 years. NSTAR's retail utility subsidiaries will reconcile the ultimate costs to achieve with that estimate, and any difference is expected to be recovered over the remainder of the amortization period. A majority of costs to achieve the merger have been for severance costs associated with a voluntary separation program (VSP) in which approximately 700 employees elected to participate. The VSP was completed by the end of August 2000. These amounts are expected to be offset by ongoing future cost savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. As a result of the merger, cost savings have been realized due to reduced staffing levels and operating efficiencies. Generating Assets Divestiture On October 26, 2000, the MDTE approved the filing made by Cambridge Electric and ComElectric (together, "the Companies") for the partial buydown of their contract with Canal Electric for power from the Seabrook nuclear generating facility (Seabrook Contract). The buydown transaction was effected by means of an amendment to the Seabrook Contract. On November 8, 2000, $120.5 million of funds held by an affiliate, Energy Investment Services, Inc. (EIS), were transferred to ComElectric and Cambridge Electric in the amount of $113.4 million and $7.1 million, respectively. EIS was established as the vehicle to invest the net proceeds from the sale of the generation assets. The Companies, in turn, have reduced their respective future stranded costs to be recovered from customers. In addition, Cambridge Electric also made a $21.1 million payment to Canal Electric as a further buydown of its share of the Seabrook Contract with after-tax proceeds received from the sale of Cambridge Electric's Kendall Station in December 1998. Approval of a November 1, 2000 buydown amount is pending at the MDTE. The impact of these transactions is reflected on the accompanying Consolidated Balance Sheets at December 31, 2000 as reductions in Restricted cash and Regulatory assets. Canal Electric also made a filing with the Federal Energy Regulatory Commission (FERC) to amend the Seabrook Contract to reflect the buydown effective November 1, 2000. Action by the FERC on this filing is pending. In 1998, Boston Edison completed the sale of all of its fossil generating assets. The amount received above net book value on the sale of these assets is being returned to retail customers over approximately 11 years. To complete its divestiture of generating assets, Boston Edison sold its Pilgrim Nuclear Generating Station (Pilgrim) in July 1999 for $81 million to Entergy Nuclear Generating Company (Entergy). As part of the sale, Boston Edison, the first company in the nation to successfully sell a nuclear facility, transferred approximately $228 million in decommissioning funds to Entergy. Entergy, by contract, assumed all future liability related to the ultimate decommissioning of the plant. The difference between the total proceeds from the sale and the net book value of the Pilgrim assets, plus the net amount to fully fund the decommissioning trust, is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers. Also in 1998, COM/Energy sold substantially all of its fossil generating assets. As part of an agreement with the MDTE, COM/Energy established EIS. Both the principal amount and income earned were used to reduce the stranded costs that would otherwise be billed to customers of the Companies. The net proceeds were classified as Restricted cash on the accompanying Consolidated Balance Sheets for 2000 and 1999. Securitization of Boston Edison's Transition Charge On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary of Boston Edison, closed the sale of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed the sale of $725 million of electric rate reduction certificates in a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison's retail customers as permitted under the Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison. Retail Electric Rates As a result of the Restructuring Act, standard offer customers of the retail electric subsidiaries of NSTAR currently pay rates that are 15% lower, on an inflation-adjusted basis, than rates in effect prior to March 1, 1998, the retail access date. All distribution customers must pay a transition charge as a component of their rate. The purpose of the transition charge is to allow for the collection of generation-related costs that would not be collected in the competitive energy supply market. The plant and regulatory asset balances that will be recovered through the transition charge until 2009 were approved by the MDTE. The Restructuring Act requires electric distribution companies to obtain and resell power to retail customers that choose not to buy energy from a competitive energy supplier. This is through either "standard offer service" or "default service." Standard offer service will be available to eligible customers through 2004 at prices approved by the MDTE set at levels so as to guarantee mandatory overall rate reductions provided by the Restructuring Act. New retail customers in the NSTAR Electric service territories and previously existing customers that are no longer eligible for the standard offer service and have not chosen to receive service from a competitive supplier are provided "default service." The price of default service is intended to reflect the average competitive market price for power. NSTAR Electric has existing long-term power purchase contracts. These long-term contracts will supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into six-month and shorter term agreements to meet the remaining standard offer service obligation and continues to evaluate further proposals. In November 2000, NSTAR Electric entered into power purchase agreements to meet all of its default service supply obligation for the period January through June of 2001. NSTAR Electric expects to continue periodic market solicitations for default service power supply consistent with provisions of the Restructuring Act and MDTE orders. The cost of providing standard offer and default service, which includes purchased power costs, is recovered from customers on a fully reconciling basis. NSTAR Electric's accumulated cost to provide default and standard offer service is in excess of the revenues it has been allowed to bill as of December 31, 2000. As a result, NSTAR has recorded, at December 31, 2000, a regulatory asset of approximately $242.7 million that is reflected as a component of Current assets on the accompanying Consolidated Balance Sheets. At December 31, 1999, costs incurred in excess of revenues collected amounted to $95.7 million and were reflected as a non-current Regulatory asset. Under applicable restructuring plans or settlements approved by the MDTE, NSTAR Electric must, on an annual basis, file proposed adjustments to its rates for the upcoming year along with a proposed reconciliation of prior year revenues and costs for its standard offer, default service, transmission and transition charges. NSTAR Electric made such a filing with the MDTE in the Fall of 1999. The MDTE subsequently approved proposed rate adjustments effective January 1, 2000, and conducted further hearings for the purpose of reconciling prior year's costs and revenues related to NSTAR Electric's transition and transmission charges and the charges for standard offer and default service. In each such proceeding, certain cost allocations and other related issues have been contested; however, the MDTE has not yet rendered a final decision. In November 2000, NSTAR Electric made a similar filing containing proposed rate adjustments for 2001, including a reconciliation of costs and revenues through 1999. The MDTE has approved rate adjustments effective January 1, 2001, but it has not yet ruled on the reconciliation component of NSTAR Electric's filings. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be a material adverse impact on NSTAR's consolidated financial position, results of operations and cash flows in the near term. In addition to the annual rate filings referenced above, NSTAR Electric has also made separate filings with the MDTE concerning charges for standard offer and default service. NSTAR Electric has filed with the MDTE a request for approval to increase its standard offer service rates for 2001 based on a fuel adjustment formula contained in its standard offer tariffs that reflects the prices of natural gas and oil. On December 11, 2000, the MDTE approved an increase in standard offer rates of 1.321 cents per kWh for NSTAR Electric. The MDTE ruled that these fuel adjustments did not have to meet the 15% rate reduction requirement under the Restructuring Act. The MDTE will re-examine these rates in July 2001. On October 19, 2000, the MDTE approved NSTAR Electric's request to increase the price of default service to 6.28 cents per kWh, effective December 1, 2000. On November 9, 2000, NSTAR Electric filed a request with the MDTE for an additional increase for default service to reflect market costs for the period January 1, 2001 through June 30, 2001. On December 4, 2000, the MDTE approved market-based default service rates covering this period. These and future prices for default service are based upon market solicitations for power supply for default service consistent with provisions of the Restructuring Act and MDTE orders. Under its restructuring settlement agreement, Boston Edison's distribution business was subject to an annual minimum and maximum return on average common equity (ROE) through December 31, 2000. The ROE was subject to a floor of 6% and a ceiling of 11.75%. If the ROE was below 6%, Boston Edison was authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE was above 11%, it was required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment was made if the ROE was between 6% and 11%. In addition, distribution rates continue to be subject to adjustment for any changes in tax laws or accounting principles that result in a change in costs of more than $1 million. No adjustments have been made to Boston Edison's distribution rates due to either one of these mechanisms. Natural Gas Industry Restructuring and Rates In late 1998, the MDTE issued an order establishing rules and regulations governing the unbundling of retail gas service to all customers in Massachusetts. Prior to this, only commercial and industrial customers were able to obtain competitive gas supply service from a source other than the local distribution company (LDC) such as NSTAR Gas. These regulations are similar to those adopted by the MDTE governing electric restructuring. Among the important provisions are: setting the LDC as the default service provider, certification of competitive suppliers/marketers, extension of the MDTE's consumer protection rules to residential customers taking competitive service, requirement for LDCs to provide suppliers/marketers with customer usage data, and requirement for suppliers/marketers to disclose service terms to potential customers. In addition, the MDTE has standardized the eligibility requirements for low-income rates for all LDCs that are identical to previously established requirements for electric customers. In February 1999, the MDTE issued an order requiring the mandatory assignment of the LDC's upstream pipeline and storage capacity and downstream peaking capacity to customers who elect a competitive gas supply during a three-year transition period. This eliminates potential stranded cost exposure for the LDCs until they are relieved from their responsibility as suppliers of last resort and the establishment of a "workably competitive" interstate pipeline capacity market. In January 2000, the MDTE approved the Model Terms and Conditions submitted by the LDCs that provided the framework for implementing the regulations. In October 2000, the MDTE approved compliance Terms and Conditions submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. With the issuance of these orders and regulations, the MDTE moved the date for full customer choice to November 1, 2000. NSTAR Gas has modified its billing, customer and gas supply systems to accommodate full retail choice. As a result of these orders, gas restructuring is likely to have no significant financial impact on LDCs. Results of Operations 2000 versus 1999 NSTAR's energy delivery businesses continue to be subject to traditional utility accounting and ratemaking principles, since NSTAR earns a regulated equity return on its investments in those businesses. Consistent with the application of the purchase method of accounting, the results for 2000 reflect the results of NSTAR for a full year while the results for 1999 reflect eight months of BEC and four months of NSTAR. Basic and diluted earnings per common share were $3.19 and $3.18, respectively, in 2000, compared to $2.77 and $2.76, respectively, in 1999, a 15% increase in earnings per share. The dilutive impact on earnings of an additional 4.1 million average common shares outstanding at year-end 2000 ($0.26 per share) reflects shares issued to transact the merger in 1999, partially offset by 5 million shares repurchased in 2000 upon completion of the most recent common share repurchase plan. Operating Revenues Operating revenues increased 46% from 1999 as follows:
(in thousands) Retail revenues $ 514,627 Wholesale revenues (30,691) Other revenues 94,214 Gas revenues 269,929 Increase in operating revenues $ 848,079 ===========
Retail electric revenues were $2,065.4 million in 2000 compared to $1,550.8 million in 1999, an increase of $514.6 million, or 33%. The change in retail revenues reflects a full year of NSTAR operations, the recognition of incentive revenue entitlements for successfully lowering transition charges, the higher costs of natural gas and oil as a component of purchased power and the impact of a 25% increase in retail kWh sales reflecting the addition of COM/Energy. On a combined pro-forma basis as if BEC and COM/Energy were NSTAR for the entire year of 1999, retail kWh sales increased 3.3%. The increase in retail kWh sales is the result of a strong local economy as indicated by a 2.2% improvement in the overall Massachusetts employment rate, new construction and customer growth. In addition, NSTAR Electric increased its standard offer and default service rates in January and December 2000. NSTAR Electric's standard offer revenues were $616.4 million and $467.7 million in 2000 and 1999, respectively. The revenues derived from standard offer and default service are fully reconciled to the costs incurred and have no impact on net income. Wholesale electric revenues were $77.9 million in 2000, compared to $108.5 million in 1999, a decrease of $30.6 million, or 28%. This decrease in wholesale revenues primarily reflects the absence of sales to Pilgrim contract customers due to the sale of Pilgrim in July 1999. Other revenues were $178.2 million in 2000 compared to $84 million in 1999, an increase of $94.2 million, or 112%. This revenue increase primarily reflects non-utility district heating and cooling energy sales operations in 2000 and higher transmission revenues related to refunds to wholesale customers in 1999 resulting from a FERC-approved settlement with transmission contract customers. Gas revenues were $378 million in 2000 compared to $108.1 million in 1999, an increase of $269.9 million, or 250%. The increase represents NSTAR Gas operations for a full year. In addition, on a comparable basis, the fourth quarter firm and transportation sales were higher by 25% due to colder weather. Heating degree days for the fourth quarter totaled 2,369, 19% above the same period last year and 6% greater than the normal level of 2,242. On a combined pro-forma basis as if BEC and COM/Energy were NSTAR for the entire year of 1999, firm gas sales and transportation increased 15%. NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories; firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers do not materially affect NSTAR Gas' operating income because substantially all the margin on such service is returned to its firm customers as cost reductions. In addition to delivery service rates, NSTAR Gas' tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC). The CGAC provides for the recovery of all gas supply costs from firm sales customers or default service customers. The LDAC provides for the recovery of certain costs applicable to both sales and transportation customers. The CGAC is filed semi-annually for approval by the MDTE. The LDAC is filed annually for approval. NSTAR Gas' sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. In December 2000 and in a revised filing in January 2001, NSTAR Gas filed for interim increases to its CGAC charges for the period February through April 2001 in order to recover significant increases in the costs to buy natural gas supplies. These filings were made to ensure that prices to customers are set at levels that recover all or a significant portion of incurred costs in order to avoid the accumulation of significant under-recoveries that would impair NSTAR Gas' ability to serve its customers. NSTAR Gas estimated that without this adjustment, it would under-collect approximately $50 million of gas supply costs by the end of the current winter heating season. On January 31, 2001, the MDTE approved an adjustment to increase the cost of gas to $1.1123 per therm from the prior charge of $0.7608 per therm. Subsequently, on February 28, 2001, as a result of a recent decline in wholesale natural gas prices, NSTAR Gas received approval from the MDTE to reduce the rate per therm to $0.94 effective March 1, 2001. Operating Expenses Operating expenses for 2000 include a full year of expenses for NSTAR, while the level of expenses for 1999 reflect eight months of BEC Energy and four months of NSTAR. Purchased power, fuel and cost of gas sold expense was $1,390.7 million in 2000, compared to $794.7 million in 1999, an increase of $596 million, or 75%. The increase in 2000 primarily reflects a full year of NSTAR operations, an increase in purchased power requirements due to the sale of Pilgrim in 1999, an overall increase in the cost of wholesale power and increased requirements resulting from increased kWh sales and firm gas sales. NSTAR Electric adjusts its rates to collect the costs related to fuel and purchased power from customers on a fully reconciling basis. Fuel and purchased power expenses reflect a reduction of $212.7 million in 2000 and $67.3 million in 1999 related to these rate recovery mechanisms. Due to the rate adjustment mechanisms, changes in the amount of fuel and purchased power expense have no impact on earnings. The cost of gas sold, representing NSTAR Gas' supply expense, was $212.8 million in 2000 compared to $57.9 million in 1999, an increase of $154.9 million and is also fully reconciled. Operations and maintenance expense was $414.3 million in 2000 compared to $353.8 million in 1999, an increase of $60.5 million, or 17%. The increase primarily reflects a full year of NSTAR operations that was partially offset by the absence of $70 million of nuclear power production expenses due to the sale of Pilgrim. As a result of the merger, operations and maintenance cost savings have been realized due to reduced staffing levels and operating efficiencies. In addition, NSTAR experienced significantly lower costs for employee pensions and benefits in 2000. Depreciation and amortization expense was $223.5 million in 2000 compared to $210.3 million in 1999, an increase of $13.2 million, or 6%. The increase reflects approximately $23.2 million resulting from a full year of amortization of goodwill and costs to achieve related to the merger compared to $8 million in 1999 and approximately $13.4 million related to other amortization and depreciation for a full year of NSTAR operations and capital additions. These increases were partially offset by the sale of Pilgrim in July 1999. Demand side management (DSM) and renewable energy programs expense was $78.8 million in 2000 compared to $63.4 million in 1999, an increase of $15.4 million, or 24% primarily due to a full year of NSTAR operations. In accordance with the restructuring legislation and the settlement agreement, these costs are collected from customers on a fully reconciling basis. Therefore, the increase has no impact on earnings. Property and other taxes were $78.7 million in 2000 compared to $77.8 million in 1999, an increase of $0.9 million, or 1%. The increase is primarily due to a full year of NSTAR operations partially offset by lower municipal property taxes primarily related to the sale of Pilgrim. Other Income (Expense), net Other expense, net of taxes was $3.7 million in 2000 compared to income of $8.1 million in 1999, a net decline in income of $11.8 million, or 146%. The decline in income in 2000 reflects the absence of $20.8 million related to the 1999 recognition of previously deferred investment tax credits associated with the Pilgrim station that was sold in 1999. In 2000, the change in other income consisted primarily of lower NSTAR Communications, Inc. (NSTAR Com) joint venture losses amounting to $5.6 million as a result of NSTAR Com's decreased ownership interest compared to an equity loss of $16.2 million in 1999. In addition, the change in 2000 reflects interest income on funds held by EIS of $7.6 million compared to $2.8 million in the prior year. These amounts were offset entirely with interest charges. Also, 2000 includes a gain of $3.4 million from the sale of land by a non- utility subsidiary and $4.4 million received from a third party related to the Pilgrim wholesale contract buyout. Interest Charges Interest on long-term debt and transition property securitization certificates was $154.8 million in 2000 compared to $104.6 million in 1999, an increase of $50.2 million, or 48%. The increase reflects $25.1 million of interest related to transition property securitization certificates issued in July 1999, $24.7 million related to the $500 million 8% bonds issued in February 2000 ($300 million) and in October 2000 ($200 million) and a full year of NSTAR operations. These increases were partially offset by approximately $12.3 million in reductions related to the following retirements: $65 million of 6.80% debentures in February 2000, $34 million of 9.875% debentures in June 2000 and $100 million of 6.05% debentures in August 2000. Interest on short-term obligations was $55.2 million in 2000 compared to $22.9 million in 1999, an increase of $32.3 million, or 141%. This increase is directly related to increases in short- term borrowings, primarily the result of increases in the unrecovered cost of standard offer and default service during 2000 of approximately $147 million. In addition, 2000 reflects $7.5 million of interest costs associated with additional borrowing used to finance deferred transition costs and $1.1 million on deferred gas costs. Allowance for borrowed funds used during construction (AFUDC) amounted to $4.6 million in 2000 compared to $2.2 million in 1999, an increase of $2.4 million. This increase is primarily related to capitalized interest associated with construction of NSTAR's new office facility located in Westwood, Massachusetts. 1999 versus 1998 Due to the application of the purchase method of accounting, the results for 1999 reflect eight months of BEC and four months of NSTAR. Results for 1998 only reflect BEC. Basic and diluted earnings per common share were $2.77 and $2.76, respectively, in 1999 compared to $2.76 and $2.75, respectively, in 1998, a 0.4% increase in earnings per share. Operating Revenues Operating revenues increased 14% from 1998 as follows:
(in thousands) Retail electric revenues $ 175,708 Wholesale revenues (33,480) Other revenues (21,433) Gas revenues 108,117 Increase in operating revenues $ 228,912 =======
Retail electric revenues were $1,550.8 million in 1999 compared to $1,375.1 million in 1998, an increase of $175.7 million, or 13%. The change in 1999 reflects an increase of $163.3 million representing four months of revenues from the former COM/Energy retail electric subsidiaries from the date of the merger. Without the impact of the merger, retail revenues would have been $1,387.5 million in 1999, an increase from 1998 of $12.4 million, or 1%. This change reflects greater retail kWh electric sales that were partially offset by a decrease in retail revenues reflecting the impact of the 10% reduction in retail rates mandated by the Restructuring Act initially implemented in March 1998, and an additional 5% rate reduction effective September 1, 1999. Retail kWh sales increased 18% in 1999. This increase includes an increase of 12% representing four months of sales by the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, 1999 kWh sales would have increased 5% from 1998. This increase in retail kWh sales was primarily due to weather conditions that favored electric sales as well as a continued strong local economy and an increase in the number of customers. The commercial sector represents approximately 50% of electric operating revenues. The commercial sales increase was partially the result of economic growth as indicated by a 2% increase in the Massachusetts employment rate and increased hotel occupancy rates in the Boston area. Wholesale electric revenues were $108.5 million in 1999 compared to $142 million in 1998, a decrease of $33.5 million, or 24%. Offsetting this decrease in 1999 was an increase of $6.1 million representing four months of revenues from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, wholesale revenues would have been $102.4 million, a decrease from 1998 of $39.6 million, or 28%. This decline was primarily the result of a decrease of $37 million reflecting the absence of sales to Pilgrim contract customers due to a scheduled 1999 refueling and maintenance outage and subsequent sale of the Pilgrim station in July 1999. Other revenues were $84 million in 1999 compared to $105.4 million in 1998, a decrease of $21.4 million, or 20%. 1999 reflects an increase of $31.4 million representing four months of revenues from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, short-term and other revenues would have been $52.6 million in 1999, a decrease from 1998 of $52.8 million, or 50%. The decrease reflects $20 million of revenue received in 1998 as a result of support of standard offer service by Boston Edison's fossil generating stations prior to divestiture. The decline in short-term sales revenue of $35 million was consistent with the decrease in short- term kWh sales. Under agreements with Select Energy, a subsidiary of Northeast Utilities, NSTAR Electric is only purchasing enough power to meet obligations to its retail and wholesale customers. Gas revenues were $108.1 million in 1999, representing four months of revenues from NSTAR Gas from the date of the merger. Operating Expenses Operating expenses include the additional expenses associated with the merger of COM/Energy for four months in 1999. 1998 reflects expenses of only BEC. Purchased power, fuel and cost of gas sold expense was $794.7 million in 1999 compared to $567.8 million in 1998, an increase of $226.9 million, or 40%. 1999 reflects an increase of $151.2 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, purchased power, fuel and cost of gas sold would have been $643.5 million in 1999, an increase from 1998 of $75.7 million, or 13%. Purchased power expense increased $91 million reflecting the increase in Boston Edison's purchased power requirements due to the 1999 Pilgrim refueling outage and its sale. NSTAR Electric adjusts its rates to collect the costs related to fuel and purchased power from customers on a fully reconciling basis. Boston Edison's fuel and purchased power expense reflects a reduction of $56 million in 1999 and $128 million in 1998 related to these rate recovery mechanisms. Due to rate adjustment mechanisms, changes in the amount of fuel and purchased power expense have no impact on earnings. The fuel expense related to Boston Edison's fossil generation units decreased $66 million reflecting the divestiture of those units in May 1998. Fuel expense related to Pilgrim decreased $17 million due to the 1999 refueling outage and the sale of the plant in July 1999. Operations and maintenance expense was $353.8 million in 1999 compared to $382.4 million in 1998, a decrease of $28.6 million, or 7%. 1999 reflects an increase of $73.7 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, operations and maintenance expense would have been $280.1 million in 1999, a decrease from 1998 of $102.3 million, or 27%. This reflects a decrease of $70 million of nuclear power production expenses due to the deferral of costs related to the 1999 refueling outage and the ultimate sale of the Pilgrim plant in July 1999, and a decrease of $22 million in fossil-fuel related power production expenses due to the fossil generation divestiture in May 1998. In addition, 1999 reflects a decrease of $9 million in expenses reflecting the discontinued operations of two unregulated subsidiaries. Depreciation and amortization expense was $210.3 million in 1999 compared to $195.6 million in 1998, an increase of $14.7 million, or 8%. 1999 reflects an increase of $18.7 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without this impact, depreciation and amortization would have been $191.6 million in 1999, a decrease from 1998 of $4 million, or 2%. This decrease reflects the amortization of the gain on the sale of the fossil plants that began in June 1998. These decreases are partially offset by an increase of $8 million resulting from the amortization of goodwill and costs to achieve related to the merger and an increase of $11 million reflecting a reduction in the carrying amount of non-utility property. DSM and renewable energy programs expense was $63.4 million in 1999 compared to $51.8 million in 1998, an increase of $11.6 million, or 22%. 1999 reflects an increase of $6 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, DSM and renewable energy programs expense would have been $57.4 million, an increase from 1998 of $5.6 million, or 11%. Property and other taxes were $77.8 million in 1999 compared to $84.1 million in 1998, a decrease of $6.3 million, or 7%. 1999 reflects an increase of $8.9 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, property and other taxes would have been $68.9 million, a decrease from 1998 of $15.2 million, or 18%. This decrease reflects lower municipal property taxes resulting from the divestiture of the fossil and nuclear generating facilities. Other Income (Expense), net Other income, net of taxes was $8.1 million in 1999 compared to other expense, net of $11.8 million in 1998, a net increase in income of $19.9 million. Prior to the consideration of tax benefits, other expense was $17.7 million in 1999 compared to $35.9 million in 1998. 1999 reflects an increase of $1.4 million reflecting four months of expense from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, other expense would have been $16.3 million in 1999. NSTAR's equity loss in the RCN joint venture was $16.2 million in 1999, compared to its total equity losses from both the RCN and EnergyVision joint ventures in 1998 of $19.7 million. 1999 reflects $7 million of anticipated non-recoverable expenses related to the Pilgrim plant divestiture. 1998 reflects $23.2 million of costs related to the fossil plants' divestiture. 1998 also reflects an additional $3.5 million of costs related to discontinued operations of a Boston Energy Technology Group subsidiary, Coneco Corporation, and $2.6 million of costs associated with opposition to a referendum that sought to repeal the Restructuring Act. These amounts were offset by $5.6 million of interest income in 1999 compared to $7.6 million in 1998, a decrease of $2 million, reflecting the higher level of cash on hand in 1998 as a result of the proceeds from the fossil plant divestiture. Other miscellaneous income was $0.4 million in 1999 compared to $5.5 million in 1998. Income tax benefits related to other income (expense), net were $27.6 million in 1999 and $24.1 million in 1998. The income tax benefit includes $20.8 million in 1999 and $10.9 million in 1998 related to the recognition of previously deferred investment tax credits associated with the Pilgrim nuclear plant divested in 1999 and the fossil generating stations divested in 1998. Interest Charges Interest on long-term debt and transition property securitization certificates was $104.6 million in 1999 compared to $83 million in 1998, an increase of $21.6 million, or 26%. 1999 reflects an increase of $13 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. Without the impact of the merger, interest on long-term debt and transition property securitization certificates were $91.6 million in 1999, an increase from 1998 of $8.6 million or 10%. The increase reflects approximately $20 million related to securitization. This increase is partially offset by a reduction of approximately $6 million due to the retirement of $19 million of 7.80% debentures due March 15, 2023, $66 million of 9.875% debentures and $91 million of 9.375% debentures during the third quarter of 1999. The increase is additionally offset by reductions of approximately $2 million due to the maturity of $100 million, 5.95% debentures in March 1998 and the cessation of amortization of the associated discounts and premiums, as well as a reduction of approximately $3 million due to the redemption of a $100 million 6.662% bank loan in June 1998. Interest on short-term debt and other obligations was $22.9 million in 1999 compared to $8.8 million in 1998, an increase of $14.1 million, or 160%. 1999 reflects an increase of $9.2 million representing four months of expenses from the former COM/Energy subsidiaries from the date of the merger. The remaining increase primarily reflects increased borrowings from the revolving line of credit agreements to finance common shares repurchased in connection with the merger, the common share repurchase program and investments in non-utility subsidiaries. Preferred Stock Dividends and Redemptions Preferred dividends of Boston Edison were approximately $6 million in both 2000 and 1999 and $8.8 million in 1998. The decrease in 1999 was due to the redemption of 400,000 shares of 7.75% series cumulative preferred stock and the remaining 320,000 shares of 7.27% series in July 1998. 500,000 shares of 8% series cumulative preferred stock is subject to mandatory redemption in December 2001. Liquidity and Capital Resources During 2000, 1999 and 1998 internal generation of cash provided 181%, 174% and 97%, respectively, of plant expenditures. Internally generated funds consist of cash flows from operating activities, adjusted to exclude changes in working capital and the payment of dividends. NSTAR companies supplement internally generated funds as needed, primarily through the issuance of short-term commercial paper and bank borrowings. The capital spending level forecasted for 2001 is $295 million, which includes amounts for utility plant and the capital requirements of non-utility ventures. The capital spending level over the next four years is forecasted to aggregate approximately $670 million. In addition to capital expenditures, long-term debt principal (including securitized debt) and preferred stock redemption requirements will be approximately $123 million in 2001, $109 million in 2002, $241 million in 2003, $79 million in 2004 and $78 million in 2005. In February and October 2000, NSTAR issued $300 million and $200 million, respectively, 8% notes, due February 2010, of long-term debt related to its $500 million shelf registration. Proceeds from these issues were used to pay down short-term borrowings. These increases in long-term debt were partially offset in 2000 by $199 million in long-term debt retirements, consisting of Boston Edison debenture redemptions of $65 million (6.8% Series) in February, $34 million (9.875% Series) in June and $100 million (6.05% Series) in August. NSTAR has a $450 million revolving credit agreement with a group of banks effective through November 2002. As of December 31, 2000, there was no amount outstanding and at December 31, 1999, there was $350 million outstanding under this revolving credit agreement. Also, NSTAR has a $450 million commercial paper program. At December 31, 2000 and 1999, NSTAR had $252 million outstanding and no amount outstanding, respectively, under its commercial paper program. The primary purpose of the revolving credit agreement is to provide back-up liquidity for NSTAR's commercial paper program. Boston Edison has approval from the FERC to issue up to $350 million of short-term debt. Boston Edison has a $200 million revolving credit agreement with a group of banks effective through December 2001. In addition, it also has a $100 million line of credit. Both of these arrangements serve as back-up to Boston Edison's $300 million commercial paper program. As of December 31, 2000 and 1999, there were no amounts outstanding under this revolving credit agreement. As of December 31, 2000, there was $97 million outstanding under its commercial paper program. There was no amount outstanding under this program as of December 31, 1999. In addition, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $185 million available under several lines of credit. Approximately $120 million and $108 million was outstanding under these lines of credit as of December 31, 2000 and 1999, respectively. Boston Edison's Financing Application with the MDTE was approved in October 2000 for authorization to issue from time to time up to $500 million of debt securities through 2002. Proceeds from such issuances covered under this approved financing will be used for repayment or refinancing of certain outstanding equity securities, long-term indebtedness, and for other corporate purposes. On February 20, 2001, Boston Edison filed a registration statement on Form S-3 with the Securities and Exchange Commission (SEC), using a shelf registration process, to issue up to $500 million in debt securities. The registration statement was declared effective by the SEC on February 28, 2001. When issued, Boston Edison will use the proceeds to pay at maturity long-term debt and equity securities, refinance short- term debt and for other corporate purposes. In April 1998, BEC announced a common share repurchase program under which it would repurchase up to four million of its common shares. NSTAR assumed this program effective as of the merger date. In October 1999, this program was completed by NSTAR. Four million shares were repurchased at a total cost of approximately $157 million. NSTAR subsequently announced a second common share repurchase program, which began in November 1999, of $300 million that was completed in September 2000 with the repurchase of approximately 7.2 million shares. In July 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary (SPS) of Boston Edison, closed the sale of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed the sale of $725 million of electric rate reduction certificates to the public. A portion of the transition charge assessed to Boston Edison's retail customers, as permitted under the Restructuring Act and authorized by the MDTE, secures the certificates held by BEC Funding. The certificates were issued in five separate classes with variable payment periods ranging from approximately one to ten years and bearing fixed interest rates ranging from 5.99% to 7.03%. The certificates are non-recourse to Boston Edison. Net proceeds ($719 million received by Boston Edison from BEC Funding) were utilized to finance a portion of the stranded costs that are being collected from customers under Boston Edison's restructuring settlement agreement. Boston Edison will collect a portion of the transition charge on behalf of BEC Funding and remit the proceeds to the SPS. Boston Edison used a portion of the proceeds received from the financing to fund a portion of the nuclear decommissioning fund transferred to Entergy as part of the sale of the Pilgrim generating station. Boston Edison used the remaining proceeds to reduce its capitalization and for general corporate purposes. NSTAR's goal is to maintain a capital structure that preserves an appropriate balance between debt and equity. Management believes its liquidity and capital resources are sufficient to meet its current and projected requirements. New Accounting Principles In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) and as amended by Statements of Financial Accounting Standards No. 137 and 138, collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed- price fuel supply and power contracts) be recorded on the Consolidated Balance Sheets as either an asset or liability measured at its fair value. SFAS 133 is effective for fiscal years beginning after June 15, 2000. NSTAR will adopt SFAS 133 as of January 1, 2001. The impact of this adoption has been assessed by the management of NSTAR. As part of this assessment, NSTAR formed an implementation team in 2000 consisting of key individuals from various operational and financial areas of the organization. The primary role of this team was to inventory and determine the impact of potential contractual arrangements for SFAS 133 application. The implementation team has performed extensive reviews of critical operating areas of NSTAR and has documented its procedures in applying the requirements of SFAS 133 to NSTAR's contractual arrangements in effect on January 1, 2001. Based on NSTAR's assessment to date, the adoption of SFAS 133 will not have a material adverse effect on its results of operations, cash flows, or financial position as of January 1, 2001. RCN Joint Venture and Investment Conversion NSTAR Com is a participant in a telecommunications venture with RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN Corporation (RCN). NSTAR Com accounts for its Class A Equity investment in the joint venture using the equity method of accounting. As part of the Joint Venture Agreement, NSTAR Com has the option to exchange portions of its joint venture interest for common shares of RCN at specified periods. During 1998, NSTAR Com exercised its option to convert a portion of its interest. In the first quarter of 1999, NSTAR Com received 1.1 million RCN common shares in exchange for a portion of its joint venture interest that had a net book value of $7.8 million. In May 1999, NSTAR Com notified RCN of its intention to exercise its option to convert an additional portion of its joint venture interest that had a net book value of $72.3 million at that time. In March 2000, NSTAR Com received approximately three million shares of RCN associated with this second exchange. The RCN shares received are included in Other investments on the accompanying Consolidated Balance Sheets at their fair value of approximately $25.9 million at December 31, 2000. This fair value may increase or decrease, at any time, as a result of changes in the market price of RCN common shares. The unrealized gain or loss due to the changes in fair value on these shares during each period is reflected, net of associated income taxes, as Comprehensive (loss) income on the accompanying Consolidated Statements of Comprehensive Income. The cumulative increase or decrease in fair value of these shares as of December 31, 2000 and 1999 is reflected as Accumulated other comprehensive (loss) income, net on the accompanying Consolidated Balance Sheets. Management continues to evaluate the carrying value of its investment in RCN. As a result of the current decline in the market value of RCN shares, it is reasonably possible that an adjustment may result. Management is unable at this time to estimate the amount, if any, of a potential adjustment. On April 6, 2000, NSTAR Com issued its third and final notice to exchange substantially all of its remaining interest in the joint venture with a net book value of approximately $129 million into common shares of RCN that is reflected on the accompanying Consolidated Balance Sheets in Equity investments. Effective with the third notice, NSTAR Com's profit and loss sharing ratio was reduced to zero and therefore NSTAR Com no longer recognized any results of operations from its interest in the joint venture. Through April 6, 2000, NSTAR Com recognized $5.6 million in equity losses from the joint venture and for the year ended December 31, 1999, it recognized $16.2 million in losses. On October 18, 2000, NSTAR Com and RCN signed an agreement in principle to amend the Joint Venture Agreement. Among other items, this proposal would settle the number of shares to be exchanged associated with the third conversion of NSTAR Com's Class A Equity at 7.5 million shares. This amendment also offers NSTAR Com the option to continue to invest in the joint venture through a new "Class B Preferred Equity" guaranteed by RCN. This Class B Equity has no voting rights and no sharing of profits or losses. NSTAR Com has an option to invest up to $100 million in such security. NSTAR Com, at its election, may choose to designate the amounts it contributes under future capital calls as either Class A Equity or Class B Equity in the joint venture. Future investments by NSTAR Com will not be convertible into RCN common shares. In addition, under the agreement in principle, the joint venture and NSTAR Com would amend certain of their agreements to incorporate an incentive and penalty provision for construction activities and expand the relevant market in which the joint venture operates. No final agreement has been reached relating to the October 18, 2000 agreement in principle. Management expects to have a final amended Joint Venture Agreement in place during the first half of 2001. At December 31, 2000 and 1999, NSTAR Com had $47.9 million and $26.6 million, respectively, in accounts receivable due from RCN. Other Matters Environmental The subsidiaries of NSTAR are involved in approximately 30 state- regulated properties where oil or other hazardous materials were spilled or released. The companies are required to clean up these properties in accordance with specific state regulations. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. NSTAR subsidiaries also face possible liability as a potentially responsible party (PRP) in the cleanup of six multi-party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. NSTAR generally expects to have only a small percentage of the total potential liability for these sites. Approximately $7 million is included as a liability on the accompanying Consolidated Balance Sheets related to the non-recoverable portion of these cleanup liabilities. Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount. Based on its assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on NSTAR's consolidated financial position. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of operations for a reporting period in the near term. NSTAR Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether NSTAR Gas may be responsible for remedial action. The MDTE has approved recovery of costs associated with MGP sites. As of December 31, 2000, NSTAR Gas has recorded a liability of $2.6 million as an estimate for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a PRP. Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. NSTAR is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of NSTAR'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 NSTAR's consolidated financial position or results of operations for a reporting period. Industry and corporate restructuring legal proceedings The MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows or results of operations for a reporting period. Regulatory proceedings In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, results of operations and cash flows in the near term. In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999. Management is currently unable to determine the timing of and the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and results of operations for a reporting period. In the normal course of its business, NSTAR and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, management does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period. Employees As of December 31, 2000, NSTAR's subsidiaries had approximately 3,300 full-time employees, including approximately 2,300 or 70% of employees represented by nine collective bargaining units covered by separate contracts. In December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America, AFL-CIO. The new agreement results in a single bargaining unit of approximately 2,000 NSTAR Electric and Gas employees and one five-year contract expiring May 15, 2005 that will replace seven separate and widely diverse agreements. The other remaining collective bargaining unit contract expires March 31, 2002. Management believes it has satisfactory employee relations. Interest rate risk NSTAR is exposed to changes in interest rates primarily based on levels of short-term debt outstanding. The weighted average interest rates for mandatory redeemable cumulative preferred stock and long-term indebtedness were 8.0% and 7.5%, respectively, for 2000 and 8.0% and 7.25%, respectively, for 1999. Carrying amounts and fair values of mandatory redeemable cumulative preferred stock and indebtedness (excluding notes payable) as of December 31, 2000 and 1999 were as follows:
2000 1999 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Mandatory redeemable cumulative preferred stock $ 49,519 $ 50,890 $ 49,279 $ 52,250 Indebtedness $2,070,180 $2,090,290 $1,854,794 $1,842,373
Safe Harbor Cautionary Statement NSTAR occasionally makes forward-looking statements such as forecasts and projections of expected future performance or statements of its plans and objectives. These forward-looking statements may be contained in filings with the SEC, press releases and oral statements. 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 preceding sections include certain forward-looking statements about operating results and environmental and legal issues. The impact of continued cost control procedures on operating results could differ from current expectations. The effects of changes in economic conditions, tax rates, interest rates, technology, prices and availability of operating supplies could materially affect the projected operating results. The impacts of various environmental, legal issues, and regulatory matters could differ from current expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect the estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect the estimated litigation costs. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Although NSTAR has material commodity purchase contracts and financial instruments (debt), these instruments are not subject to market risk. NSTAR's electric and gas distribution subsidiaries have rate making mechanisms that allow for the recovery of fuel costs from customers. The fuel adjustment mechanisms allow NSTAR's subsidiaries to pass all costs related to the purchase of commodities to the customer, thereby insulating NSTAR from market risk. Similarly, any change in the fair market value of NSTAR's prudently incurred debt obligations realized by NSTAR would be borne by customers through future rates. Item 8. Financial Statements and Supplementary Financial Information NSTAR Consolidated Statements of Income
Years ended December 31, 2000 1999 1998 (in thousands, except earnings per share) Operating revenues $2,699,506 $1,851,427 $1,622,515 Operating expenses: Fuel, purchased power and cost of gas sold 1,390,740 794,748 567,806 Operations and maintenance 414,270 353,768 382,434 Depreciation and amortization 223,491 210,306 195,607 Demand side management and renewable energy programs 78,774 63,425 51,839 Taxes-property and other 78,694 77,761 84,091 Income taxes 123,467 87,721 97,798 Total operating expenses 2,309,436 1,587,729 1,379,575 Operating income 390,070 263,698 242,940 Other income (expense), net (3,715) 8,078 (11,811) Operating and other income 386,355 271,776 231,129 Interest charges: Long-term debt 109,299 84,196 82,951 Transition property securitization certificates 45,505 20,408 - Other 55,182 22,873 8,800 Allowance for borrowed funds used during construction (AFUDC) (4,593) (2,164) (1,668) Total interest charges 205,393 125,313 90,083 Net income 180,962 146,463 141,046 Preferred stock dividends of subsidiary 5,960 5,960 8,765 Earnings available for common shareholders $ 175,002 $ 140,503 $ 132,281 ========= ========= ========== Weighted average common shares outstanding: Basic 54,887 50,796 47,973 Diluted 55,045 50,921 48,149 Earnings per common share: Basic $ 3.19 $ 2.77 $ 2.76 Diluted $ 3.18 $ 2.76 $ 2.75 The accompanying notes are an integral part of the consolidated financial statements.
NSTAR Consolidated Statements of Comprehensive Income
Years ended December 31, 2000 1999 1998 (in thousands) Net income $180,962 $146,463 $141,046 Comprehensive (loss) income, net: Unrealized (loss) gain on investments (53,255) 20,115 - Excess non-qualified benefit obligation (1,004) - - Comprehensive income $126,703 $166,578 $141,046 ======== ======== ======== The accompanying notes are an integral part of the consolidated financial statements.
NSTAR Consolidated Statements of Retained Earnings
Years ended December 31, 2000 1999 1998 (in thousands) Balance at the beginning of the year $ 389,989 $ 360,509 $ 328,802 Add: Net income 180,962 146,463 141,046 Subtotal 570,951 506,972 469,848 Deduct: Dividends declared: Common shares 109,315 103,099 90,610 Preferred stock 5,960 5,960 8,765 Subtotal 115,275 109,059 99,375 Deduct: Provision for preferred stock redemption and issuance costs 239 239 7,833 Common share repurchase programs 8,850 7,685 2,131 Balance at the end of the year $ 446,587 $ 389,989 $ 360,509 ========= ========= ========= 2284: The accompanying notes are an integral part of the consolidated financial statements
.
NSTAR Consolidated Balance Sheets December 31, (in thousands) 2000 1999 Assets Utility Plant in service, at original cost $3,724,754 $3,652,257 Less: Accumulated depreciation 1,249,685 $2,475,069 1,239,201 $2,413,056 Construction work in progress 48,524 64,644 Net utility plant 2,523,593 2,477,700 Non-utility property 105,827 93,887 Goodwill 475,877 485,990 Equity investments 155,457 173,290 Other investments 41,163 69,942 Current assets: Cash and cash equivalents 23,198 168,599 Restricted cash 20,827 147,941 Accounts receivable, net of allowance of $28,309 and $23,836 in 2000 and 1999 respectively 454,499 389,702 Regulatory assets 242,663 - Accrued unbilled revenues 101,732 42,112 Fuel, materials and supplies, at average cost 44,659 48,756 Prepaid pension expense 149,890 104,900 Other 54,246 1,091,714 42,569 944,579 Deferred debits: Regulatory assets 1,029,341 1,045,925 Other 146,542 174,830 Total assets $5,569,514 $5,466,143 ========= ========= Capitalization and Liabilities Common equity $1,376,369 $1,523,532 Accumulated other comprehensive (loss) income, net (34,144) 20,115 Cumulative preferred stock of subsidiary 43,000 92,279 Long-term debt 1,440,431 986,843 Transition property securitization certificates 584,130 646,559 Current liabilities: Long-term debt and preferred stock due within one year $ 58,695 $ 170,470 Transition property securitization certificates, due within one year 36,443 50,922 Notes payable 468,347 458,000 Accounts payable 275,778 193,937 Accrued interest 44,220 21,830 Dividends payable 28,305 29,871 Other 323,672 1,235,460 338,745 1,263,775 Deferred credits: Accumulated deferred income taxes 666,544 608,587 Accumulated deferred investment tax credits 39,960 41,946 Power contracts 25,868 100,741 Other 191,896 181,766 Commitments and contingencies Total capitalization and liabilities $5,569,514 $5,466,143 ========= ========= The accompanying notes are an integral part of the consolidated financial statements.
NSTAR Consolidated Statements of Cash Flows 2360: December 31, (in thousands) 2000 1999 1998 Operating activities: Net income $180,962 $146,463 $141,046 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 225,459 212,880 229,668 Deferred income taxes and investment tax credits 54,835 88,174 (152,798) Allowance for borrowed funds used during construction (3,057) (2,164) (1,668) Power contract buy out (11,679) (65,781) - Net changes (net of effect of acquisition) in: Accounts receivable and accrued unbilled revenues (124,417) (96,909) 20,544 Fuel, materials and supplies, at average cost 4,097 (2,192) 29,565 Accounts payable 93,520 19,469 13,316 Other current assets and liabilities (195,158) (87,032) (33,535) Other, net (53,587) (29,548) 18,851 Net cash provided by operating activities 170,975 183,360 264,989 Investing activities: Plant expenditures (excluding AFUDC) (182,709) (159,295) (120,202) Costs of nuclear divestiture, net - (87,248) - Proceeds from sale of fossil generating assets - - 533,633 Nuclear fuel expenditures (1,597) (16,117) (26,182) Investments (53,843) (82,403) (81,589) Payment for cost of acquisition, net of cash acquired - (296,262) - Net cash (used in) provided by investing activities (238,149) (641,325) 305,660 Financing activities: Proceeds from transition property securitization - 725,000 - Issuances/(repurchases): Common shares (212,611) (189,715) (53,285) Long-term debt 500,000 20,000 - Redemptions: Preferred stock - - (71,519) Long-term debt (257,853) (255,361) (201,600) Financing costs (2,100) - - Net change in short-term notes 10,347 340,550 (59,013) Dividends paid (116,010) (103,036) (100,246) Net cash (used in) provided by financing activities (78,227) 537,438 (485,663) Net (decrease) increase in cash and cash equivalents (145,401) 79,473 84,986 Cash and cash equivalents at the beginning of the year 168,599 89,126 4,140 Cash and cash equivalents at the end of $ 23,198 $168,599 $ 89,126 the year ========= ======= ========
Supplemental disclosure of cash flow information: 2000 1999 1998 Cash paid during the year for: Interest, net of amounts capitalized $ 166,072 $125,840 $ 89,720 Income taxes $ (11,441) $ 36,092 $230,260 Supplemental disclosure of investing activity: Common shares issued for acquisition of COM/Energy - 20,251 - 2433: The accompanying notes are an integral part of the consolidated financial statements.
2437: Notes to Consolidated Financial Statements 2439: Note A. Summary of Significant Accounting Policies 2441: 1. About NSTAR NSTAR is an energy delivery company serving approximately 1.3 million customers in Massachusetts including more than one million electric customers in 81 communities and 244,000 gas customers in 51 communities. NSTAR also supplies electricity at wholesale for resale to municipalities. NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 and is an exempt public utility holding company. Its retail utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas) and its wholesale electric subsidiary is Canal Electric Company (Canal Electric). Effective November 1, 2000, NSTAR's three retail electric companies began to operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR's non- utility operations include telecommunications - NSTAR Communications, Inc. (NSTAR Com), district heating and cooling operations (Advanced Energy Systems, Inc. and NSTAR Steam Corporation) and liquefied natural gas services (Hopkinton LNG Corp.). NSTAR is focusing its utility operations on the transmission and distribution of energy. The 1997 Massachusetts Electric Restructuring Act (Restructuring Act) required all electric utilities to divest their generating assets and leave the retail power supply business in exchange for the right to recover all non-mitigable stranded costs associated with the creation of customer choice and competition. 2. Basis of Consolidation and Accounting The accompanying consolidated financial statements reflect the results of operations, comprehensive income, financial position and cash flows of NSTAR and its subsidiaries. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year data to conform with the current year's presentation. NSTAR's utility subsidiaries follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, NSTAR and its subsidiaries are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying consolidated financial statements conform with Generally Accepted Accounting Principles (GAAP). The utility subsidiaries are subject to Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. The distribution business remains subject to rate- regulation and continues to meet the criteria for application of SFAS 71. Refer to Note D to these Consolidated Financial Statements for more information on the accounting implications of the electric utility industry restructuring. The preparation of financial statements in conformity with GAAP requires management of NSTAR and its subsidiaries 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 Utility revenues are based on authorized rates approved by the FERC and the MDTE. Estimates of transmission and distribution revenues for electricity and natural gas used by customers but not yet billed are accrued at the end of each accounting period. NSTAR Electric also recognizes unbilled revenue related to transition charges similar to transmission and distribution. Revenues for NSTAR's non-utility subsidiaries are recognized when services are rendered or when the energy is delivered. 4. Utility Plant Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation. Non-utility property is stated at cost or its net realizable value. 5. Depreciation Depreciation of utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. The overall composite depreciation rates were 3.20%, 3.31% and 3.28% in 2000, 1999 and 1998, respectively. Depreciation of non-utility property is computed on a straight-line basis over the estimated life of the asset. 6. Costs Associated with Issuance and Redemption of Debt and Preferred Stock Consistent with the recovery in utility rates, discounts, redemption premiums and related costs associated with the issuance and redemption of long-term debt and preferred stock are deferred. The costs related to long-term debt are recognized as an addition to interest expense over the life of the original or replacement debt. Consistent with an accounting order received from the FERC, costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable. 7. Allowance for Borrowed Funds Used During Construction (AFUDC) AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2000, 1999 and 1998 were 6.16%, 5.82% and 5.88%, respectively, and represented only the cost of short-term debt. AFUDC also includes capitalized interest on non-utility plant. 8. Cash and Cash Equivalents Cash and cash equivalents are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash represents the net proceeds from the sale of Canal Electric's generation assets that are required to be used to reduce the transition costs that otherwise would be billed to customers. 9. Equity Method of Accounting NSTAR 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. 10. Amortization of Goodwill and Costs to Achieve The merger of BEC and COM/Energy was accounted for as an acquisition of COM/Energy by BEC using the purchase method of accounting. Under this method, the accompanying consolidated financial statements of NSTAR for 2000 include the results of operations, comprehensive income, financial position and cash flows of NSTAR for the entire period presented. However, the accompanying consolidated financial statements of NSTAR for the year 1999 reflect the results of BEC consolidated with those of COM/Energy from the date of the merger (August 25, 1999). Goodwill amounted to approximately $490 million, while the original estimate of transaction and integration costs to achieve the merger was $111 million. Goodwill is being amortized over 40 years and will amount to approximately $12.2 million annually, while the cost to achieve is being amortized over 10 years and will initially be approximately $11.1 million annually. The ultimate amortization of the costs to achieve will reflect the total actual costs. 11. 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:
December 31, (in thousands) 2000 1999 Generation-related regulatory assets, net $ 694,902 $ 631,639 Purchased power costs - 95,654 Cost to achieve 119,519 79,681 Power contract 61,131 96,911 Income taxes, net 55,887 71,057 Postretirement benefits costs 26,692 24,887 Redemption premiums 14,403 16,014 Other 56,807 30,082 1,029,341 1,045,925 Current Assets Purchased power costs 242,663 - Total regulatory assets $1,272,004 $1,045,925 ========= =========
The current purchased power costs shown in the table above as of December 31, 2000 is based on a recent MDTE approval of standard offer and default service rates and it is anticipated that this amount will be collected from customers during 2001. Note B. Earnings Per Common Share Basic earnings per common share (EPS) is calculated by dividing net income, after deductions for preferred dividends, by the weighted average common shares outstanding during the year. Statement of Financial Accounting Standards No. 128, "Earnings per Share," requires the disclosure of diluted EPS. Diluted EPS is similar to the computation of basic EPS except that the weighted average common shares is increased to include the number of dilutive potential common shares. Diluted EPS reflects the impact on shares outstanding of the deferred (nonvested) shares and stock options granted under the NSTAR Stock Incentive Plan. The following table summarizes the reconciling amounts between basic and diluted EPS:
(in thousands, except per share amounts) 2000 1999 1998 Earnings available for common shareholders $175,002 $140,503 $132,281 Basic EPS $3.19 $2.77 $2.76 Diluted EPS $3.18 $2.76 $2.75 Weighted average common shares outstanding for basic EPS 54,887 50,796 47,973 Effect of dilutive shares: Weighted average dilutive potential common shares 158 125 176 Weighted average common shares outstanding for diluted EPS 55,045 50,921 48,149
Note C. RCN Joint Venture and Investment Conversion NSTAR Com is a participant in a telecommunications venture with RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN Corporation (RCN). NSTAR Com accounts for its Class A Equity investment in the joint venture using the equity method of accounting. As part of the Joint Venture Agreement, NSTAR Com has the option to exchange portions of its joint venture interest for common shares of RCN at specified periods. During 1998, NSTAR Com exercised its option to convert a portion of its interest. In the first quarter of 1999, NSTAR Com received 1.1 million RCN common shares in exchange for a portion of its joint venture interest that had a net book value of $7.8 million. In May 1999, NSTAR Com notified RCN of its intention to exercise its option to convert an additional portion of its joint venture interest that had a net book value of $72.3 million at that time. In March 2000, NSTAR Com received approximately three million shares of RCN associated with this second exchange. The RCN shares received are included in Other investments on the accompanying Consolidated Balance Sheets at their fair value of approximately $25.9 million at December 31, 2000. This fair value may increase or decrease, at any time, as a result of changes in the market price of RCN common shares. The unrealized gain or loss due to the changes in fair value on these shares during each period is reflected, net of associated income taxes, as Comprehensive (loss) income on the accompanying Consolidated Statements of Comprehensive Income. The cumulative increase or decrease in fair value of these shares as of December 31, 2000 and 1999 is reflected as Accumulated other comprehensive (loss) income, net on the accompanying Consolidated Balance Sheets. Management continues to evaluate the carrying value of its investment in RCN. As a result of the current decline in the market value of RCN shares, it is reasonably possible that an adjustment may result. Management is unable at this time to estimate the amount, if any, of a potential adjustment. On April 6, 2000, NSTAR Com issued its third and final notice to exchange substantially all of its remaining interest in the joint venture with a net book value of approximately $129 million into common shares of RCN that is reflected on the accompanying Consolidated Balance Sheets in Equity investments. Effective with the third notice, NSTAR Com's profit and loss sharing ratio was reduced to zero and therefore NSTAR Com no longer recognized any results of operations from its interest in the joint venture. Through April 6, 2000, NSTAR Com recognized $5.6 million in equity losses from the joint venture and for the year ended December 31, 1999, it recognized $16.2 million in losses. On October 18, 2000, NSTAR Com and RCN signed an agreement in principle to amend the Joint Venture Agreement. Among other items, this proposal would settle the number of shares to be exchanged associated with the third conversion of NSTAR Com's Class A Equity at 7.5 million shares. This amendment also offers NSTAR Com the option to continue to invest in the joint venture through a new "Class B Preferred Equity" guaranteed by RCN. This Class B Equity has no voting rights and no sharing of profits or losses. NSTAR Com has an option to invest up to $100 million in such security. NSTAR Com, at its election, may choose to designate the amounts it contributes under future capital calls as either Class A Equity or Class B Equity in the joint venture. Future investments by NSTAR Com will not be convertible into RCN common shares. In addition, under the agreement in principle, the joint venture and NSTAR Com would amend certain of their agreements to incorporate an incentive and penalty provision for construction activities and expand the relevant market in which the joint venture operates. No final agreement has been reached relating to the October 18, 2000 agreement in principle. Management expects to have a final amended Joint Venture Agreement in place during the first half of 2001. At December 31, 2000 and 1999, NSTAR Com had $47.9 million and $26.6 million, respectively, in accounts receivable due from RCN. Note D. Electric Utility Industry Restructuring 1. Accounting Implications Under the traditional revenue requirements model, electric rates are based on the cost of providing electric service. Under this model, NSTAR Electric 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. NSTAR's remaining generation business, Canal Electric's 3.52% joint ownership interest in the Seabrook Nuclear Power Station is subject to the provisions of SFAS 71. The implementation of electric utility industry restructuring has certain accounting implications. The highlights of these include: a. Generation-related plant and other regulatory assets Plant and other regulatory assets related to the generation business are recovered through the transition charge. This recovery occurs over a 12-year period for Boston Edison and over an 11-year period for ComElectric and Cambridge Electric, beginning on March 1, 1998, the retail access date in Massachusetts. b. Fuel and purchased power charge The fuel and purchased power charge ceased as of the retail access date. The net remaining over-collection of fuel and purchased power costs were returned to customers through March 31, 2000. These over-recovered costs are included as an offset to the settlement recovery mechanisms and were included in Regulatory assets on the accompanying Consolidated Balance Sheets. c. Standard offer and default service charges Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices as of the retail access date through 2004. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market price for 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. d. Distribution and transmission charges An integral part of the merger is the rate plan of the retail utility subsidiaries of NSTAR that was approved by the MDTE on July 27, 1999. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Boston Edison distribution rates were subject to a minimum and maximum return on average common equity (ROE) from its distribution business through December 31, 2000. The ROE was subject to a floor of 6% and a ceiling of 11.75%. If the ROE was below 6%, Boston Edison was authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE was above 11%, it was required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment was made if the ROE was between 6% and 11%. In addition, distribution rates continue to be subject to adjustment for any changes in tax laws or accounting principles that result in a change in costs of more than $1 million. No adjustments have been made to Boston Edison's distribution rates due to either one of these rate mechanisms. The cost of providing transmission service to all NSTAR Electric distribution customers is recovered on a fully reconciling basis. 2. Generating Assets Divestiture On July 13, 1999, Boston Edison completed the sale of the Pilgrim Nuclear Generating Station to Entergy Nuclear Generating Company (Entergy), a subsidiary of Entergy Corporation, for $81 million. In addition to the amount received from 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. Approximately $5 million remains to be collected under these termination agreements at December 31, 2000. This compares to $80 million at December 31, 1999. As part of the sale, Boston Edison, the first company in the nation to successfully sell a nuclear facility, transferred its decommissioning trust fund to Entergy. In order to provide Entergy with a fully funded decommissioning trust fund, Boston Edison contributed approximately $271 million to the fund at the time of the sale. As a result of a favorable IRS tax ruling, Boston Edison received $43 million from Entergy reflecting a reduction in the required decommissioning funding. The difference between the total proceeds received and the net book value of the Pilgrim assets sold plus the net amount to fully fund the decommissioning trust is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers under Boston Edison's settlement agreement. The final amounts to be collected from customers related to Pilgrim are subject to regulatory review. Completion of the sale of Boston Edison's fossil generating assets took place in May 1998. Boston Edison received proceeds from the sale of $674 million, including $121 million for a six- month transitional power purchase contract. The amount received above net book value on the sale of these assets is being returned to Boston Edison's customers over the settlement period. On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary of Boston Edison, closed the sale of $725 million of notes to a special purpose trust created by two Massachusetts state agencies. The trust then concurrently closed the sale of $725 million of electric rate reduction certificates to the public. The certificates are secured by a portion of the transition charge assessed on Boston Edison's retail customers as permitted under the Restructuring Act and authorized by the MDTE. These certificates are non-recourse to Boston Edison. COM/Energy completed the sale of substantially all of its investment in electric generation assets in 1998. Proceeds from the sale of these assets, after construction-related adjustments at the closing that occurred on December 30, 1998, amounted to approximately $453.9 million, or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments, amounted to $358.6 million and are being used to reduce stranded costs related to electric industry restructuring that otherwise would have been collected from customers. COM/Energy established Energy Investment Services, Inc. (EIS) as the vehicle to invest the net proceeds from the sale of Canal Electric generation assets. These proceeds were invested in a portfolio of securities that are designed to maintain principal and earn a reasonable return. Both the principal amount and income earned were used to reduce the future stranded costs that would otherwise have been billed to customers of Cambridge Electric and ComElectric. The net proceeds were classified as Restricted cash on the accompanying Consolidated Balance Sheets for 2000 and 1999. On October 26, 2000, the MDTE approved the filing made by Cambridge Electric and ComElectric (together, "the Companies") for the partial buydown of their contract with Canal Electric for power from the Seabrook nuclear generating facility (Seabrook Contract). The buydown transaction is effected by means of an amendment to the Seabrook Contract. On November 8, 2000, $120.5 million of funds held by EIS, was transferred to ComElectric and Cambridge Electric in the amount of $113.4 million and $7.1 million, respectively. EIS was established as the vehicle to invest the net proceeds from the sale of these assets. The Companies, in turn, have reduced their respective future stranded costs to be recovered from customers. In addition, Cambridge Electric also made a $21.1 million payment to Canal Electric as a further buydown of its share of the Seabrook Contract with after- tax proceeds received from the sale of Cambridge Electric's Kendall Station in December 1998. Approval of a November 1, 2000 buydown amount is pending at the MDTE. The impact of these transactions is shown on the accompanying Consolidated Balance Sheets at December 31, 2000 as reductions in Restricted cash and Regulatory assets. Canal Electric also made a filing with the FERC to amend the Seabrook Contract to reflect the buydown effective November 1, 2000. Action by the FERC on this filing is pending. Note E. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109, net regulatory assets of $55.9 million and $71.1 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2000 and 1999, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes. Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 2000 1999 Deferred tax liabilities: Plant-related $487,714 $484,021 Other 490,079 424,128 977,793 908,149 Deferred tax assets: Plant-related 82,898 78,587 Investment tax credits 25,791 29,013 Other 202,560 191,962 311,249 299,562 Net accumulated deferred income taxes $666,544 $608,587 ======== ========
No valuation allowances for deferred tax assets are deemed necessary. 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:
(in thousands) 2000 1999 1998 Current income tax expense $ 68,944 $(33,121) $239,717 (benefit) Deferred income tax expense 56,508 123,393 (137,992) (benefit) Investment tax credit (1,985) (2,551) (3,927) amortization Income taxes charged to 123,467 87,721 97,798 operations Tax benefit on other expense, 5,433 (27,580) (24,116) net Total income tax expense $128,900 $ 60,141 $ 73,682 ======== ======== ========
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:
2000 1999 1998 Statutory tax rate 35.0% 35.0% 35.0% State income tax, net of federal income tax benefit 5.1 5.5 5.2 Investment tax credit (0.6) (11.3) (6.9) Other 2.1 (0.1) 1.0 Effective tax rate 41.6% 29.1% 34.3% ===== ===== =====
Income tax expense is reflected net of $20.8 million in 1999 and $10.9 million in 1998, representing investment tax credits recognized as a result of generation asset divestitures. Excluding this shareholder benefit, the effective tax rate would have been approximately 39% in each year. Note F. Pensions and Other Postretirement Benefits 1. Pensions NSTAR sponsors a defined benefit funded retirement plan that covers substantially all employees. NSTAR also maintains unfunded supplemental retirement plans for certain management employees. Effective January 1, 2001, the defined benefit plan was amended to reflect the impact of the transition of all NSTAR union locals to the pension benefits provided under the Local 369 formula. This amendment is reflected in the December 31, 2000 benefit obligation. Effective January 1, 2000, the defined benefit plan was amended to provide management employees lump sum benefits under a final average pay pension equity formula. Prior to January 1, 2000, these pension benefits were provided under a traditional final average pay formula. This amendment is reflected in the December 31, 1999 benefit obligation. The changes in benefit obligation and plan assets were as follows:
December 31, (in thousands) 2000 1999 Change in benefit obligation: Benefit obligation, beginning of the year $800,084 $497,988 COM/Energy obligation - 405,868 Service cost 14,636 14,741 Interest cost 59,798 42,426 Plan participants' contributions 81 170 Plan amendments (4,387) (12,697) Actuarial loss/(gain) 59,815 (62,464) Curtailment loss - 18,424 Special termination benefit - 13,582 Settlement payments (77,256) (92,484) Benefits paid (48,413) (25,470) Benefit obligation, end of the year $804,358 $800,084 ======== ========
(in thousands) Change in plan assets: 2000 1999 Fair value of plan assets, beginning of the year $955,498 $474,552 COM/Energy plan assets - 395,783 Actual (loss)/return on plan assets, net (28,041) 143,116 Employer contribution 44,338 59,831 Plan participants' contributions 81 170 Settlement payments (77,256) (92,484) Benefits paid (48,413) (25,470) Fair value of plan assets, end of the year $846,207 $955,498 ======== ========
The plan's funded status was as follows:
December 31, (in thousands) 2000 1999 Funded status $ 41,849 $155,414 Unrecognized actuarial net loss/(gain) 104,817 (59,254) Unrecognized transition obligation 2,182 2,783 Unrecognized prior service cost (3,340) 1,495 Net amount recognized $145,508 $100,438 ======== ========
Amount recognized in the Consolidated Balance Sheets consisted of:
(in thousands) 2000 1999 Prepaid retirement cost $149,890 $104,900 Accrued supplemental retirement (13,306) (10,148) liability Intangible asset 7,285 5,686 Accumulated other comprehensive income 1,639 - Net amount recognized $145,508 $100,438 ======== ========
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the supplemental retirement plan with accumulated benefit obligations in excess of plan assets were $14,067,000, $13,306,000 and $0, respectively, as of December 31, 2000, and $14,291,000, $10,148,000 and $0, respectively, as of December 31, 1999. Weighted average assumptions were as follows:
2000 1999 1998 Discount rate at the end of the year 7.5% 8.0% 6.5% Expected return on plan assets for the year (net of investment expenses) 9.3% 9.0% 9.0% Rate of compensation increase at the end of the year 4.0% 4.0% 4.0%
Components of net periodic benefit cost were as follows:
December 31, (in thousands) 2000 1999 1998 Service cost $ 14,636 $ 14,741 $ 13,645 Interest cost 59,798 42,426 31,981 Expected return on plan assets (85,884) (53,059) (39,140) Amortization of prior service cost 448 1,610 1,847 Amortization of transition obligation 601 664 860 Recognized actuarial loss - 3,594 808 Net periodic benefit/(income)cost $ (10,401) $ 9,976 $ 10,001 ========= ======== ========
Primarily as a result of merger-related separation agreements and nuclear divestiture, amounts recognized for curtailment, settlement and special termination benefit costs were $19,823,000, $930,000 and $13,582,000, respectively, for 1999. In addition, $9,623,000 was recognized as a result of pension settlements in 2000. The majority of these charges will be recovered from customers and is a component of Regulatory assets on the accompanying Consolidated Balance Sheets. The amounts resulting from the merger-related separation agreements and generation divestitures are recoverable as part of the approved rate plans of the retail utility subsidiaries of NSTAR. NSTAR also provides defined contribution 401(k) plans for substantially all employees. Matching contributions (which are equal to 50% of the employees' deferral up to 8% of compensation) included in the accompanying Consolidated Statements of Income amounted to $7 million in 2000, $9 million in 1999 and $8 million in 1998. 2. Other Postretirement Benefits In addition to pension benefits, NSTAR also provides health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits include health and life insurance coverage and reimbursement of certain Medicare premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits. Effective January 1, 2001, amendments were added to reflect negotiated changes to Local 369 as well as the impact of the transition of all NSTAR union locals to the benefits provided under the Local 369 formula. These amendments are reflected in the December 31, 2000 benefit obligation. Effective January 1, 2000, an amendment was added to include certain new managed care features. This amendment is reflected in the December 31, 1999 benefit obligation. The changes in benefit obligation and plan assets were as follows:
December 31, (in thousands) 2000 1999 Change in benefit obligation: Benefit obligation, beginning of the year $ 370,914 $ 258,756 COM/Energy obligation - 146,741 Service cost 3,563 4,505 Interest cost 29,574 21,896 Plan participants' contributions 926 37 Plan amendments 2,807 (14,062) Actuarial loss/(gain) 44,939 (24,186) Curtailment loss - 1,408 Settlement payments - (5,810) Benefits paid (24,382) (18,371) Benefit obligation, end of the year $ 428,341 $ 370,914 ======== ========
(in thousands)
Change in plan assets: Fair value of plan assets, beginning of the year $ 201,053 $ 113,818 COM/Energy plan assets - 73,558 Actual (loss)/return on plan assets (16,411) 23,337 Employer contribution 63,465 14,484 Plan participants' contributions 926 37 Settlement payments - (5,810) Benefits paid (24,382) (18,371) Fair value of plan assets, end of the year $ 224,651 $ 201,053 ======== ========
The plans' funded status and amounts recognized in the accompanying Consolidated Balance Sheets were as follows:
December 31, (in thousands) 2000 1999 Funded status $(203,690) $(169,861) Unrecognized actuarial net loss/(gain) 70,836 (9,524) Unrecognized transition obligation 67,400 73,016 Unrecognized prior service cost (17,644) (22,154) Net amount recognized $ (83,098) $(128,523) ======== ========
Weighted average assumptions were as follows:
2000 1999 1998 Discount rate at the end of the year 7.5% 8.0% 6.5% Expected return on plan assets for the year 9.0% 9.0% 9.0%
For measurement purposes an 11% weighted annual rate of increase in per capita cost of covered medical claims was assumed for 2001. This rate is assumed to decrease gradually to 5% in 2012 and remain at that level thereafter. Dental claims and Medicare premiums are assumed to increase at a weighted annual rate of 4% and 5%, respectively. A 1% change in the assumed health care cost trend rate would have the following effects:
One-Percentage-Point (in thousands) Increase Decrease Effect on total of service and interest costs components for 2000 $ 4,672 $ (3,477) Effect on December 31, 2000 postretirement benefit obligation $57,499 $(44,494)
Components of net periodic benefit cost were as follows:
years ended December 31, (in thousands) 2000 1999 1998 Service cost $ 3,563 $ 4,505 $ 3,892 Interest cost 29,574 21,896 16,895 Expected return on plan assets (19,010) (12,329) (8,563) Amortization of prior service cost (1,703) (683) (942) Amortization of transition obligation 5,616 6,162 8,474 Recognized actuarial loss - 957 662 Net periodic benefit cost $18,040 $20,508 $20,418 ======= ======= =======
As a result of merger-related separation agreements and nuclear divestiture, amounts recognized for curtailment and settlement costs were $8,114,000 and $172,000, respectively, for 1999. As a result of the nuclear divestiture, amounts recognized for curtailment and special termination benefit costs were $21,187,000 and $79,000, respectively, for 1998. The amounts resulting from the merger-related separation packages are recoverable as part of the approved rate plans of the retail utility subsidiaries of NSTAR. The amounts resulting from the nuclear divestiture are recoverable under the Boston Edison settlement agreement. Note G. Stock-Based Compensation NSTAR maintains a Stock Incentive Plan (the Plan) that permits a variety of stock and stock-based awards, including stock options and deferred (non-vested) stock to be granted to certain key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of common shares that may be awarded under the Plan is 2,000,000, including shares issued in lieu of or upon reinvestment of dividends arising from awards. During 2000, 69,750 deferred shares and 316,700 ten-year non-qualified stock options were granted. During 1999, 58,500 deferred shares and 248,000 ten-year non-qualified stock options were granted. During 1998, 19,150 deferred shares and 419,200 ten-year non-qualified stock options were granted under the Plan. The weighted average grant date fair value of the deferred stock issued during 2000, 1999 and 1998 was $44.375, $41.73 and $39.75, respectively. The options were granted at the full market price of the common shares on the date of the grant. All the awards vest ratably over a three-year period. Compensation cost for stock-based awards is computed by measuring the quoted stock market price at the measurement date less the amount, if any, an employee is required to pay. The fair value disclosures were as follows:
(in thousands, except per share amounts) 2000 1999 1998 Net income Actual $180,962 $146,463 $141,046 Pro forma $180,237 $145,955 $140,661 Basic earnings per common share Actual $ 3.19 $ 2.77 $ 2.76 Pro forma $ 3.18 $ 2.76 $ 2.75 Diluted earnings per common share Actual $ 3.18 $ 2.76 $ 2.75 Pro forma $ 3.17 $ 2.75 $ 2.74
Stock option activity of the Plan was as follows:
2000 1999 1998 Options outstanding at January 1 814,267 666,600 273,000 Options granted 316,700 248,000 419,200 Options exercised (125,432) (4,400) (3,800) Options forfeited (87,400) (95,933) (21,800) Options outstanding at December 31 918,135 814,267 666,600 ======= ======= =======
Summarized information regarding stock options outstanding at December 31, 2000:
Options Outstanding Options Exercisable Weighted Average Remaining Weighted Weighted Contractual Average Average Range of Number Life Exercise Numbers Exercise Exercise Prices Outstanding (Years) Price Outstanding Price $25.75-$26.00 162,400 6.45 $25.90 162,400 $25.90 $39.75-$41.375 467,402 7.26 $40.36 242,576 $40.14 $44.375 288,333 9.40 $44.375 - -
There were 404,976, 298,333 and 87,200 stock options exercisable on December 31, 2000, 1999 and 1998, respectively. The stock options granted during 2000, 1999 and 1998 have a weighted average grant date fair value of $7.00, $4.86 and $4.61, respectively. The fair value was estimated using the Black- Scholes option pricing model with the following weighted average assumptions:
2000 1999 1998 Expected life (years) 4.0 4.0 4.0 Risk-free interest rate 6.48% 5.31% 5.66% Volatility 20% 17% 16% Dividends 4.64% 4.86% 4.88%
Compensation cost recognized in the accompanying Consolidated Statements of Income for stock-based compensation awards in 2000, 1999 and 1998 was $1,717,000, $1,044,000 and $850,000, respectively. Note H. Capital Stock Common Shares
December 31, (in thousands, except per share amounts) 2000 1999 Common equity: Common shares, par value $1 per share, 100,000,000 shares authorized; 53,032,546 and 58,059,646 shares issued and outstanding $ 53,033 $ 58,060 Premium on common shares 876,749 1,075,483 Retained earnings 446,587 389,989 Total common equity $1,376,369 $1,523,532 ========= =========
Dividends declared per common share were $2.015, $1.955 and $1.895 in 2000, 1999 and 1998, respectively. Cumulative Preferred Stock (in thousands, except per share amounts) Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
Current Series Shares Redemption December 31, Outstanding Price/Share 2000 1999 4.25% 180,000 $103.625 $18,000 $18,000 4.78% 250,000 $102.80 25,000 25,000 Total non-mandatory redeemable series 43,000 43,000
Mandatory redeemable series:
Current Redemption Series Shares Price/Share Outstanding 8.00% 500,000 $100.00 50,000 50,000 Less redemption and issuance costs 481 721 Total mandatory redeemable series 49,519 49,279 92,519 92,279 Less amount due within one year 49,519 - Total cumulative preferred stock of subsidiary $43,000 $92,279 ====== ======
1. Common Shares Common share issuances and repurchases in 1998 through 2000 were as follows:
Number of Total Premium on (in thousands) Shares Par Value Common Shares Balance at December 31, 1997 48,515 $ 48,515 $ 696,137 Common share repurchase program (1,331) (1,331) (49,823) Stock incentive plan - - (2,109) Balance at December 31, 1998 47,184 47,184 644,205 Common share repurchase program (4,839) (4,839) (179,593) Stock incentive plan - - (3,189) Shares issued to COM/Energy shareholders 20,251 20,251 809,524 BEC Energy shares repurchase under mergeragreement (4,536) (4,536) (195,464) Balance at December 31, 1999 58,060 58,060 1,075,483 Common share repurchase program (5,027) (5,027) (198,113) Stock incentive plan - - (621) Balance at December 31, 2000 53,033 $ 53,033 $ 876,749 ======= ======= ========
2. Cumulative Mandatory Redeemable Preferred Stock Boston Edison is not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share plus accrued dividends. Note I. Indebtedness 1. Long-term debt NSTAR's long-term debt consisted of the following:
December 31, (in thousands) 2000 1999 Mortgage Bonds, collateralized by property of operating subsidiaries: 8.99%, due December 2001 $ 3,500 $ 7,150 6.54%, due September 2007 10,000 10,000 7.04%, due September 2017 25,000 25,000 9.95%, due December 2020 25,000 25,000 7.11%, due December 2033 35,000 35,000 Notes: 7.75%, due June 2002 2,200 2,301 9.30%, due January 2002 29,989 29,978 7.43%, due March 2003 15,000 15,000 9.50%, due December 2004 4,000 5,000 7.62%, due November 2006 20,000 20,000 8.70%, due March 2007 5,000 5,000 9.55%, due December 2007 10,000 10,000 7.70%, due March 2008 10,000 10,000 8.0%, due February 2010 498,008 - 9.37%, due January 2012 12,632 13,684 7.98%, due March 2013 25,000 25,000 9.53%, due December 2014 10,000 10,000 9.60%, due December 2019 10,000 10,000 6.924%, due June 2021 105,994 105,250 8.47%, due March 2023 15,000 15,000 Debentures: 6.80%, due February 2000 - 65,000 6.05%, due August 2000 - 100,000 6.80%, due March 2003 150,000 150,000 7.80%, due May 2010 125,000 125,000 9.875%, due June 2020 - 34,035 9.375%, due August 2021 24,270 24,270 8.25%, due September 2022 60,000 60,000 7.80%, due March 2023 181,000 181,000 Sewage facility revenue bonds, due 23,014 24,645 through 2015 Massachusetts Industrial Finance Agency (MIFA) bonds: 5.75%, due February 2014 15,000 15,000 Transition Property Securitization Certificates: 5.99%, due March 2003 4,073 80,981 6.45%, due September 2005 170,610 170,610 6.62%, due March 2007 103,390 103,390 6.91%, due September 2009 170,876 170,876 7.03%, due March 2012 171,624 171,624 2,070,180 1,854,794 Amounts due within one year (45,619) (221,392) Total long-term debt $2,024,561 $1,633,402 ========= =========
The 9.375% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. None of the other series are redeemable prior to maturity. There is no sinking fund requirement for any series of debentures. Sewage facility revenue bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.6 million were made in 2000, 1999 and 1998. The weighted average interest rate of the bonds was 7.3%. The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006. Boston Edison's Financing Application with the MDTE was approved in October 2000 for authorization to issue from time to time up to $500 million of debt securities through 2002. Proceeds from such issuances covered under this approved financing will be used for repayment or refinancing of certain outstanding equity securities, long-term indebtedness, and for other corporate purposes. On February 20, 2001, Boston Edison filed a registration statement on Form S-3 with the SEC, using a shelf registration process, to issue up to $500 million in debt securities. The registration statement was declared effective by the SEC on February 28, 2001. When issued, Boston Edison will use the proceeds to pay at maturity long-term debt and equity securities, refinance short-term debt and for other corporate purposes. The aggregate principal amounts of NSTAR long-term debt (including securitization certificates and sinking fund requirements) due for the five years subsequent to 2000 are approximately $72 million in 2001, $109 million in 2002, $241 million in 2003, $79 million in 2004 and $78 million in 2005. In 1999, BEC Funding LLC, a wholly owned subsidiary of Boston Edison, issued notes in the principal amount of $725 million to a special purpose trust created by two Massachusetts state agencies, in exchange for the net proceeds from the sale of $725 million of Rate Reduction Certificates issued by the trust on July 29, 1999. 2. Short-term Debt NSTAR has a $450 million revolving credit agreement with a group of banks effective through November 2002. As of December 31, 2000, there were no amounts outstanding and as of December 31, 1999 there was $350 million outstanding under its revolving credit agreement. Also, NSTAR has a $450 million commercial paper program. At December 31, 2000 and 1999, NSTAR had $252 million outstanding and no amount outstanding, respectively, under its commercial paper program. The primary purpose of its revolving agreement is to provide back-up liquidity for the NSTAR commercial paper program. Under the terms of this agreement, NSTAR is required to maintain a consolidated common equity ratio of not less than 35% at all times and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. Boston Edison has regulatory approval to issue up to $350 million of short-term debt. Boston Edison also has a $200 million revolving credit agreement with a group of banks effective through December 31, 2001. In addition, it has a $100 million line of credit. Both of these arrangements serve as back-up to Boston Edison's $300 million commercial paper program. As of December 31, 2000, there was $97 million outstanding under its commercial paper program. There was no amount outstanding under this program as of December 31, 1999. Under the terms of this agreement, Boston Edison is required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the total agreement amount. In addition, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $185 million available under several lines of credit that will expire at varying intervals in 2001. These lines are normally renewed upon expiration and require annual fees of approximately .1875%. Approximately $120 million and $108 million were outstanding under these lines of credit as of December 31, 2000 and 1999, respectively. Interest rates on the outstanding borrowings generally are money market rates and averaged 6.65% and 5.81% in 2000 and 1999, respectively. Notes payable to banks totaled $468.3 million and $458 million at December 31, 2000 and 1999, respectively. Note J. 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 amounts of $23.2 million and $168.8 million for 2000 and 1999, respectively, approximates fair value due to the short- term nature of these securities. 2. Mandatory redeemable cumulative preferred stock and indebtedness (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, 2000 and 1999 were as follows:
2000 1999 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Mandatory redeemable cumulative preferred stock $49,519 $50,890 $ 49,279 $52,250 Long-term indebtedness $2,070,180 $2,090,290 $1,854,794 $1,842,373
Note K. Segment and Related Information For the purpose of providing segment information, NSTAR's principal operating segments, or its traditional core businesses, are the electric and natural gas utilities that provide energy delivery services in over 100 cities and towns in Massachusetts. NSTAR subsidiaries also supply electricity at wholesale for resale to municipalities. The unregulated operating segments engage in non-utility business activities. Such activities include telecommunications, district heating and cooling operations, and liquefied natural gas services. Financial data for the operating segments were as follows:
(in thousands) 2000 1999(b) 1998 Operating revenues Electric utility operations $2,237,939 $1,710,576 $1,622,435 Gas utility operations 370,416 108,117 - Unregulated non-utility operations 91,151 32,734 80 Consolidated total $2,699,506 $1,851,427 $1,622,515 ========== ========== ========== Depreciation and amortization Electric utility operations $ 202,209 $ 190,560 $ 192,644 Gas utility operations 15,573 5,566 - Unregulated non-utility operations 5,709 14,180 2,963 Consolidated total $ 223,491 $ 210,306 $ 195,607 ========= ========== ========= Operating income tax expense (benefit) Electric utility operations $ 125,597 $ 98,125 $ 101,492 Gas utility operations 16,570 4,208 - Unregulated non-utility operations (18,700) (14,612) (3,694) Consolidated total $ 123,467 $ 87,721 $ 97,798 ========= ========== ========== Equity income (loss) in investments accounted for by the equity method (a) Electric utility operations $ 4,241 $ 999 $ 1,725 Unregulated non-utility operations (5,467) (10,505) (11,967) Consolidated total $ (1,226) $ (9,506) $ (10,242) ========= ========== ========== Interest charges Electric utility operations $ 134,767 $ 106,878 $ 88,516 Gas utility operations 10,828 3,742 - Unregulated non-utility operations 59,798 14,693 1,567 Consolidated total $ 205,393 $ 125,313 $ 90,083 ========== ========== ========== Segment net income (loss) Electric utility operations $ 187,646 $ 165,626 $ 170,374 Gas utility operations 24,238 5,379 - Unregulated non-utility operations (30,922) (24,542) (29,328) Consolidated total $ 180,962 $ 146,463 $ 141,046 ========== ========== ========== Equity Investments Electric utility operations $ 43,230 $ 32,995 $ 20,769 Gas utility operations 1,097 9 - Unregulated non-utility operations 111,130 140,286 64,001 Consolidated total $ 155,457 $ 173,290 $ 84,770 ========== ========== ========== Expenditures for property Electric utility operations $ 141,400 $ 134,906 $ 108,344 Gas utility operations 19,500 7,669 - Unregulated non-utility operations 21,809 16,720 11,858 Consolidated total $ 182,709 $ 159,295 $ 120,202 ========== ========== ========== =Segment assets Electric utility operations $4,529,379 $4,409,630 $3,073,058 Gas utility operations 534,430 459,887 - Unregulated non-utility operations 505,705 596,626 130,978 Consolidated total $5,569,514 $5,466,143 $3,204,036 ========== ========== ==========
(a) The net equity income (loss) from equity investments is included in other income (expense), net on the accompanying Consolidated Statements of Income. (b) Financial data for 1999 includes eight months of BEC Energy and four months of NSTAR. Note L. Commitments and Contingencies 1. Contractual Commitments At December 31, 2000, NSTAR and its subsidiaries had estimated contractual obligations for plant and equipment of approximately $295 million. NSTAR also has leases for certain facilities and equipment. The estimated minimum rental commitments under both transmission agreements and non-cancellable operating leases for the years after 2000 are as follows:
(in thousands) 2001 $ 28,905 2002 26,720 2003 21,174 2004 19,920 2005 17,787 Years thereafter 75,686 Total $ 190,192 =========
The total expense for both lease rentals and transmission agreements was $45.3 million in 2000, $38.7 million in 1999 and $29.6 million in 1998, net of capitalized expenses of $1.7 million in 2000, $1.5 million in 1999 and $1.6 million in 1998. Total rent expense for all operating leases, except those with terms of a month or less, amounted to $8.7 million in 2000, $10.8 million in 1999 and $11.5 million in 1998. 2. Electric Equity Investments and Joint Ownership Interest NSTAR Electric has an equity investment of approximately 14.5% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, NSTAR Electric is required to guarantee, in addition to each companies' own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 2000, NSTAR Electric's portion of these guarantees amounted to $18 million. Canal Electric owns a 3.52% joint ownership interest in the Seabrook Nuclear Power Station, and sells its entitlement to Seabrook energy and capacity to ComElectric and Cambridge Electric. The estimate of NSTAR's share of the Seabrook investment and costs of decommissioning was approximately $4.5 million as of December 31, 2000. These estimates were recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting asset in Other investments. NSTAR Electric also has a 2.5% equity investment in the 540 MW Vermont Yankee nuclear power plant. NSTAR Electric is entitled to electricity produced from the facility based on its ownership interest, and is billed for its entitlement pursuant to a contractual agreement that is approved by the FERC. The estimated cost to decommission this plant is $451.9 million in current dollars. NSTAR Electric's share of this liability is approximately $11.3 million, less its share of the market value of the assets held in a decommissioning trust of approximately $7 million, is approximately $4.3 million at December 31, 2000. Vermont Yankee has received the approval of the FERC to include charges for the estimated costs of decommissioning its unit in the cost of energy that it sells. Periodically, Vermont Yankee re- estimates the cost of decommissioning and applies to the FERC for increased rates in response to increased decommissioning costs. The Vermont Yankee unit was under agreement to be sold to Amergen Energy Company, but this transaction was disapproved on February 14, 2001 by Vermont's regulatory authority. NSTAR Electric has a 14% equity investment in Yankee Atomic Electric Company (Yankee Atomic). In 1992, the board of directors of Yankee Atomic voted to discontinue operations of the Yankee Atomic nuclear generating station permanently and decommission the facility. Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through July 9, 2000, the expiration date of the unit's power contracts. Also, as of that date, the equity owners of the unit completed the recovery of closure (decommissioning) costs and net unrecovered assets. Subsequently, Yankee Atomic initiated a stock buy-back program, approved by the SEC, to redeem 95% of the outstanding stock of Yankee Atomic. Through December 31, 2000, 50% of the 95% of shares outstanding, or 72,866 shares, were redeemed. NSTAR Electric's reduction of its equity ownership resulting from the buy-back of 10,201 shares was approximately $1 million. NSTAR Electric also has a 14% equity investment in the Connecticut Yankee Atomic Power Company (CYAPC) unit that has been retired. NSTAR Electric's share of Connecticut Yankee's remaining investment and estimated costs of decommissioning is approximately $38 million as of December 31, 2000. This estimate was recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting Regulatory asset. In December 1996, CYAPC filed for rate relief at the FERC seeking to recover certain post-operating costs, including decommissioning. In August 1998, the FERC Administrative Law Judge (ALJ) released an initial decision regarding CYAPC's filing. This decision called for the disallowance of the common equity return on the CYAPC investment subsequent to the shutdown. The decision also stated that decommissioning collections should continue to be based on a previously approved estimate, with an adjustment for inflation, until a more reliable estimate is developed. In October 1998, both CYAPC and Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ decision. The case is still pending before the FERC. If the initial decision is upheld by the FERC, CYAPC could be required to write off a portion of its investment in the generating unit and refund a portion of the previously collected return on investment to ratepayers. Management is currently unable to determine the ultimate outcome of this proceeding. However, the estimate of the effect of the ALJ's initial decision does not have a material impact on NSTAR's consolidated financial position, the results of operations or its cash flows. NSTAR Electric has a 4% equity investment in the Maine Yankee Atomic Power Company (Maine Yankee). In 1997, the board of directors of Maine Yankee voted to discontinue operations of the Maine Yankee nuclear generating station permanently and decommission the facility. NSTAR Electric's share of Maine Yankee's remaining decommissioning is approximately $23 million as of December 31, 2000. This estimate was recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting Regulatory asset. 3. Nuclear Insurance Under the Price-Anderson Act (the Act), owners of nuclear power plants have the benefit of approximately $9.5 billion of public liability coverage that would compensate the public for covered bodily injury and property loss in the event of an accident at a commercial nuclear power plant. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to $9.3 billion is provided by a retrospective assessment of up to $88.1 million per incident levied on each of the 106 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per incident per year. NSTAR has an equity ownership interest in four nuclear generating facilities and a 3.52% joint ownership interest in Seabrook 1. The operators of these units maintain nuclear insurance coverage (on behalf of the owners of the facilities) with either Nuclear Electric Insurance Limited (NEIL), a combination of NEIL and the American Nuclear Insurers (ANI) or ANI only depending on the limit of insurance required to be maintained. NEIL provides $2.25 billion of property, boiler, machinery and decontamination insurance coverage, including accidental premature decommissioning insurance. All companies insured with NEIL are subject to retroactive assessments. ANI provides $500 million of "all risk" property damage, boiler, machinery and decontamination insurance. Three of the four units in which NSTAR has an equity ownership interest have permanently ceased operations. The Nuclear Regulatory Commission has approved each of these units' requests to withdraw from participation in the financial protection insurance program of the Act and reduce their limits of property insurance. Based on its equity ownership interests in nuclear generating facilities and its joint ownership interest in Seabrook 1, NSTAR's retrospective premium could be $600,000 annually or a cumulative total of $5.3 million under the Act. 4. Environmental Matters The subsidiaries of NSTAR are involved in approximately 30 state- regulated properties where oil or other hazardous materials were previously spilled or released. The companies are required to clean up these properties in accordance with specific state regulations. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. NSTAR subsidiaries also face possible liability as a potentially responsible party (PRP) in the cleanup of six multi- party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. NSTAR generally expects to have only a small percentage of the total potential liability for these sites. Approximately $7 million is included as a liability in the accompanying December 31, 2000 Consolidated Balance Sheets related to the non-recoverable portion of these cleanup liabilities. Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount. Based on its assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on NSTAR's consolidated financial position. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. NSTAR Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether NSTAR Gas may be responsible for remedial action. The MDTE has approved recovery of costs associated with MGP sites. As of December 31, 2000, NSTAR Gas has recorded a liability of $2.6 million as an estimate for site cleanup costs for several MGP sites for which NSTAR Gas was previously cited as a PRP. Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. NSTAR is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of NSTAR'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 NSTAR's consolidated financial position or results of operations for a reporting period. 5. Generating Unit Performance Program The MDTE's generating unit performance programs ceased March 1, 1998. Under these programs the recovery of incremental purchased power costs resulting from generating unit outages occurring through the retail access date was subject to review by the MDTE. Comprehensive settlements relative to generating unit performance including the review of replacement power costs associated with the shutdown of the Connecticut Yankee nuclear electric generating unit that is discussed in item 2, was approved by the MDTE on August 1, 2000. The approved MDTE settlements did not have a material impact on NSTAR's consolidated financial position, cash flows, or results of operations. 6. Legal Proceedings Industry and corporate restructuring legal proceedings The MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period. Regulatory proceedings In the Boston Edison 1999 reconciliation filing with the MDTE, the Massachusetts Attorney General contested cost allocations related to Boston Edison's wholesale customers since 1998. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be a material adverse impact on Boston Edison's consolidated financial position, results of operations and cash flows in the near term. In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group and authorized Boston Edison to invest up to $45 million in non-utility activities. Hearings were completed during 1999. Management is currently unable to determine the timing of and the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and results of operations for a reporting period. Other litigation In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Station, filed suit against Boston Edison. The town claimed that Boston Edison had wrongfully failed to execute an agreement with the town for payments in addition to or in lieu of taxes due to the town under the Restructuring Act. Boston Edison and the town of Plymouth settled the suit and agreed in March 1999 on a 15-year $141 million payment as required by the Restructuring Act. Payments in each of the first four years are approximately $15 million after which payments gradually decline. All payments under this agreement will be recovered from customers through the transition charge. In the normal course of its business, NSTAR and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term. Note M. Long-Term Contracts for the Purchase of Energy 1. NSTAR Electric Agreements NSTAR Electric entered into various six-month agreements during 2000 to transfer substantially all of the unit output entitlements in long-term power purchase contracts to certain suppliers, who in turn provided full energy service to meet NSTAR Electric's standard offer and default service load requirements. Capacity costs reflect NSTAR Electric's proportionate share of capital and fixed operating costs of certain generating units. Energy costs are paid to generators based on a price per kWh actually received into NSTAR Electric's distribution system and are included in the total cost. In 2000, these costs were attributed to 1,121.4 MW of capacity purchased. Information related to long-term power contracts as of December 31, 2000 was as follows:
proportionate share (in thousands) Range of Capacity Charge Contract Units of 2000 2000 Obligation Fuel Type of Expiration Capacity Capacity Total Through Contract Generating Unit Dates Purchased Cost Cost Expiration Date % MW Natural Gas 2008-2017 11.1-100 28.8-135 $132,963 $361,969 $1,519,211 Nuclear 2004-2026 2.3-89 11.9-747.1 35,204 223,437 497,894 Refuse 2015 100 76.9 - 54,006 - Hydro 2014-2023 100 1.3-20 - 11,126 - Oil 2002-2019 50-100 34-282 18,511 69,888 80,555 Total $186,678 $720,426 $2,097,660 ======= ======= =========
NSTAR Electric entered into a six-month agreement effective January 1, 2001 through June 30, 2001 with a supplier to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. A default service request for proposal, applicable to the second half of 2001, will be issued in early 2001. NSTAR Electric's existing portfolio of power purchase contracts is supplying the majority of its standard offer (including wholesale) energy requirements, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric is managing its Independent System Operator-New England Power capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. NSTAR Electric's total capacity and/or energy costs associated with these contracts in 2000, 1999 and 1998 were approximately $720 million, $410 million and $267 million, respectively. NSTAR Electric's capacity charge obligation under these contracts for the years after 2000 are as follows:
Capacity Charge (in thousands) Obligation 2001 $ 158,899 2002 158,286 2003 146,036 2004 146,255 2005 150,196 Years thereafter 1,337,988 $2,097,660 =========
2. NSTAR Gas Contracts NSTAR Gas has various contractual agreements covering the transportation of natural gas, underground storage facilities and the purchase of natural gas, which are recoverable under NSTAR Gas' CGAC. These contracts expire at various times from 2003 to 2013. Report of Independent Accountants To the Shareholders and Trustees of NSTAR: In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(1) on page 68 present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(2) on page 68, respectively, 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 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. /s/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Boston, Massachusetts January 26, 2001 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure No event that would be described in response to this Item 9 has occurred with respect to NSTAR or its subsidiaries. Part III Item 10. Trustees and Executive Officers of the Registrant (a) Identification of Trustees Information required by this item is incorporated herein by reference to the 2001 Proxy Statement dated March 23, 2001. Pages 3-5 (b) Identification of Officers Information required by this item is included in Item 4.A. Item 11. Executive Compensation Information required by this item is incorporated herein by reference to the 2001 Proxy Statement dated March 23, 2001. Pages 7-14 Item 12. Security Ownership of Certain Beneficial Owners and Management Information required by this item is incorporated herein by reference to the 2001 Proxy Statement dated March 23, 2001. Pages 1 and 6 Item 13. Certain Relationships and Related Transactions Information required by this item is incorporated herein by reference to the 2001 Proxy Statement dated March 23, 2001. Page 12 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) The following documents are filed as part of this Form 10-K: 1. Financial Statements:
Page Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998 34 Consolidated Statements of Comprehensive Income for the years ended December 31, 2000, 1999 and 1998 35 Consolidated Statements of Retained Earnings for the years ended December 31, 2000, 1999 and 1998 35 Consolidated Balance Sheets as of December 31, 2000 and 36 1999 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998. 37-38 Notes to Consolidated Financial Statements. 39 Selected Consolidated Quarterly Financial Data 15 (Unaudited) Report of Independent Accountants 65 2. Financial Statement Schedules: Schedule II-Valuation and Qualifying accounts-years ended December 31, 2000, 1999 and 1998. 82
3. Exhibits: Refer to the exhibits listing beginning on the following page. (b) Reports on Form 8-K: None
Filed herewith: Exhibit 21.1 Subsidiaries of the Registrant Consent of PricewaterhouseCoopers LLP Exhibit 23.1 NSTAR (Registrant) Incorporated by reference: Exhibit 2 Plan of Acquisition, Reorganization, Arrangement, Liquidation or Seccession 2.1 Amended and Restated Agreement and Plan of Merger, dated as of December 5, 1998, amended and restated as of May 4, 1999, by and among BEC Energy, Commonwealth Energy System, NSTAR, BEC Acquisition LLC and CES Acquisition LLC (Incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus, Registration Statement on Form S-4 of NSTAR (No. 333-78285)). Exhibit 3 Articles of Incorporation and By-Laws 3.1 Declaration of Trust of NSTAR (incorporated by reference to Annex D to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S- 4 of NSTAR (No. 333-78285)). 3.2 Bylaws of NSTAR (Incorporated by reference to Annex E to the Joint Proxy Statement/Prospectus, which forms part of the Registration Statement on Form S-4 of NSTAR (No. 333-78285)). Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.0 Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any other agreements or instruments of the Registrant and its subsidiaries defining the rights of holders of any long- term debt whose authorization does not exceed 10% of total assets. 4.1 Registration of NSTAR shares in connection with the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies (Form S-8 Registration Statement, dated August 19, 1999, File No. 333-85559). 4.2 Indenture dated as of January 12, 2000 between NSTAR and Bank One Trust Company N.A. (Incorporated by reference, Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735). Exhibit 10 Material Contracts 10.1 NSTAR Excess Benefit Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.2 NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.3 Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (NSTAR Form 10- K/A for the year ended December 31, 1999, File No. 1- 14768). 10.4 Key Executive Benefit Plan Agreement dated as of October 1, 1983 between Boston Edison Company and Thomas J. May (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.5 Key Executive Benefit Plan Agreement dated September 1, 1989 between Boston Edison Company and Ronald A. Ledgett (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.6 Employment Agreement between Thomas J. May and NSTAR dated May 11, 1999 (Incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus in Part I of the Registration Statement of NSTAR on Form S-4, File No. 333-78285). 10.7 Employment Agreement between Russell D. Wright and NSTAR dated May 11, 1999 (Incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus in Part I of the Registration Statement of NSTAR on Form S-4, File No. 333-78285). 10.8 Employment Agreement between Boston Edison Company and Ronald A. Ledgett dated April 30, 1987 (Boston Edison Company Form 10-K for the year ended December 31, 1994, File No. 1-2301). 10.9 Change in Control Agreement between NSTAR and Thomas J. May dated May 11, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.10 Change in Control Agreement between NSTAR and Russell D. Wright dated May 11, 1999 (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.11 NSTAR Deferred Compensation Plan (Restated Effective August 25, 1999) (NSTAR Form 10-K/A for the year ended December 31, 1999, File No. 1-14768). 10.12 NSTAR 1997 Share Incentive Plan, as amended June 30, 1999 and assumed by NSTAR effective August 28, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). 10.13 Waiver and Employment Agreement among Commonwealth Energy System and certain of its Subsidiaries, Deborah A. McLaughlin and NSTAR, dated September 21, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). 10.14 Change in Control Agreement between James J. Judge and NSTAR, dated August 28, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). 10.15 Change in Control Agreement between Deborah A. McLaughlin and NSTAR, dated September 21, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). 10.16 NSTAR Trustees' Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). 10.17 Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), dated August 25, 1999 (NSTAR Form 10-Q for the quarter ended September 30, 2000, File No. 1-14768). BEC Energy and Subsidiaries Exhibit 3 Articles of Incorporation and By-Laws 3.1 Boston Edison Restated Articles of Organization (Form 10- Q for the quarter ended June 30, 1994, File No. 1-2301). 3.2 Boston Edison Company Bylaws April 19, 1977, as amended January 22, 1987, January 28, 1988, May 28, 1988, and November 22, 1989 (Form 10-Q for the quarter ended June 30, 1990, File No. 1-2301). Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.1 Medium-Term Notes Series A-Indenture dated September 1, 1988, between Boston Edison Company and Bank of Montreal Trust Company (Form 10-Q for the quarter ended September 30, 1988, File No. 1-2301). 4.1.1 First Supplemental Indenture dated June 1, 1990 to Indenture dated September 1, 1988 with Bank of Montreal Trust Company 97/8% debentures due June 1, 2020. (Form 8- K dated June 28, 1990, File No. 1-2301). 4.10 Debt Securities to be issued on a delayed or continuous basis under an Indenture between Boston Edison Company and The Bank of New York (as successor to Bank of Montreal Trust company) (Form S-3 Registration Statement, dated February 20, 2001, File No. 333-55890). 4.11 Debt Securities issued under an Indenture between Boston Edison Company and The Bank of New York (as successor to Bank of Montreal Trust Company) (Form S-3 Registration Statement, filed February 3, 1993, File No. 33-57840). 4.26 Indenture of Trust and Agreement among the City of Boston, Massachusetts (acting by and through its Industrial Development Financing Authority) and Harbor Electric Energy Company and Shawmut Bank, N.A., as Trustee, dated November 1, 1991 (Form 10-K for the year end December 31, 1991, File No. 1-2301). 4.27 Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken August 5, 1991 re 93/8% debentures due August 15, 2021 (Form 10-K for the year ended December 31, 1991, File No. 1-2301) 4.25 Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken September 10, 1992 re 8.25% debentures due September 15, 2022 (Form 10-K for the year ended December 31, 1997, File No. 1-2301). 4.28 Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken March 5, 1993 re 6.80% Debentures due March 15, 2003 and 7.80% debentures due March 15, 2023 (Form 10-K for the year ended December 31, 1992, File No. 1-2301). 4.9 Votes of the Pricing Committee of the Board of Directors of Boston Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010 (Form 10-K for the year ended December 31, 1995, File No. 1-2301). Exhibit 10 Material Contracts 10.11 Boston Edison Company Deferred Fee Plan dated January 14, 1993 (Form 10-K for year ended December 31, 1992, File No. 1-2301). 10.10 Deferred Compensation Trust between Boston Edison Company and State Street Bank and Trust Company dated February 2, 1993 (Form 10-K for the year ended December 31, 1992, File No. 1-2301). 10.5.1 Amendment No. 1 to Deferred Compensation Trust dated March 31, 1994 (Form 10-K for the year ended December 31, 1994). 10.10 Employment Agreement Applicable to Ronald A. Ledgett dated April 30, 1987 (Form 10-K for the year ended December 31, 1994, File No. 1-2301). 10.12 Boston Edison Company Restructuring Settlement Agreement dated July 1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301). 10.1 Boston Edison Company and Sithe Energies, Inc. Purchase and Sale and Transition Agreements dated December 10, 1997 (Form 10-Q for the quarter ended March 31, 1998, File No. 1-2301). 10.11 Boston Edison Company Directors' Deferred Fee Plan Restatement effective October 1, 1998 (Form 10-K for the year ended December 31, 1999, File No. 1-2301). 10.12 Boston Edison Company and Entergy Nuclear Generation Company Purchase and Sale Agreement dated November 18, 1998 (Form 10-K for the year ended December 31, 1999, File No. 1-2301). 10.13 License Agreement Between Boston Edison Company and Becocom, Inc., dated July 17, 1997 (Form 10-K for the year ended December 31, 1999, File No. 1-14768). 10.14 Chilled Water Service Agreement between Northwind Boston LLC and Prucenter Acquisition LLC, March 23, 1999. (Form 10-K for the year ended December 31, 1999, File No. 1-14768). Exhibit 99 Additional Exhibits 99.1 Settlement Agreement between Boston Edison Company and Commonwealth Electric Company, Montaup Electric Company and the Municipal Light Department of the Town of Reading, Massachusetts, dated January 5, 1990 (Form 8-K dated December 21, 1989, File No. 1-2301). 99.2 Settlement Agreement between Boston Edison Company and City of Holyoke Gas and City of Holyoke Gas and Electric Department et. al., dated April 26, 1990 (Form 10-Q for the quarter ended March 31, 1990, File No. 1-2301). 99.3 Information required by SEC Form 11-K for certain employee benefit plans for the years ended December 31, 1997, 1996 and 1995 (Form 10-K/A Amendments to Form 10-K for the years December 31, 1997, 1996 and 1995 dated June 25, 1998, June 26, 1997 and June 27, 1996 respectively. Commonwealth Energy System Exhibit 10 Power Contract 10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057). 10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909). 10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form 10-K, File No. 2-7749). 10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE Form 10-Q (June 1988), File No. 2-7749). 10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989), File No. 2-7749). 10.1.4 Power Contract between Connecticut Yankee Atomic Power Company (CYAPC) and CEL dated July 1, 1964 (Exhibit 13- K1 to the Parent's Form S-1, (April 1967) File No. 2- 25597). 10.1.4.1 Additional Power Contract providing for extension on contract term between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2- 7909). 10.1.4.2 Second Supplementary Power Contract providing for decommissioning financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation (VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment dated June 1, 1985 to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1986), File No. 2-7909). 10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1, 1968, both as amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and VYNPC providing for decommissioning financing and contract extension (Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909). 10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and CEL dated May 20, 1968 (Exhibit 5 to the Parent's Form S-7, File No. 2-38372). 10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and Second Amendment dated January 1, 1984 (supplementary payments) to 10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the CEL Form 10-Q (September 1984), File No. 2- 7909). 10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated August 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2- 7749). 10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2-7749). 10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December 1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.7.4 Service Agreement for Non-Firm Transmission Service between BECO and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.8 Agreement for Joint-Ownership, Construction and Operation of New Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as amended below: 10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974 and January 31, 1975, respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7, 1975), File No. 2- 54995). 10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Filed as Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2- 30057). 10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2- 30057). 10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2- 30057). 10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhibit 1 to the CEC 1986 Form 10-K, File No. 2- 30057). 10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2- 30057). 10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.9 Purchase and Sale Agreement together with an implementing Addendum dated December 31, 1981, between CE and CEC, for the purchase and sale of the CE 3.52% joint-ownership interest in the Seabrook units, dated January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.10 Agreement to transfer ownership, construction and operational interest in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981 (Refiled as Exhibit 3 to the 1991 CE Form 10-K, File No. 2-7749). 10.1.11 Power Contract, as amended to February 28, 1990, superseding the Power Contract dated September 1, 1986 and amendment dated June 1, 1988, between CEC (seller) and CE and CEL (purchasers) for seller's entire share of the Net Unit Capability of Seabrook 1 and related energy (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2- 30057). 10.1.12 Capacity Acquisition Agreement between CEC, CEL and CE dated September 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057). 10.1.12.1 Amendment to 10.1.12 as amended and restated June 1, 1993, henceforth referred to as the Capacity Acquisition and Disposition Agreement, whereby Canal Electric Company, as agent, in addition to acquiring power may also sell bulk electric power which Cambridge Electric Light Company and/or Commonwealth Electric Company owns or otherwise has the right to sell (Exhibit 1 to Canal Electric's Form 10-Q (September 1993), File No. 2- 30057). 10.1.13 Phase 1 Vermont Transmission Line Support Agreement and Amendment No. 1 thereto between Vermont Electric Transmission Company, Inc. and certain other New England utilities, dated December 1, 1981 and June 1, 1982, respectively (Exhibits 5 and 6 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.13.1 Amendment No. 2 to 10.1.13 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2- 7749). 10.1.13.2 Amendment No. 3 to 10.1.13 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749). 10.1.14 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for the purchase of available hydro-electric energy produced by a facility located in Ware, Massachusetts, dated September 1, 1983 (Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749). 10.1.15 Power Purchase Agreement between Corporation Investments, Inc. (CI), and CE for the purchase of available hydro-electric energy produced by a facility located in Lowell, Massachusetts, dated January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749). 10.1.15.1 Amendment to 10.1.15 between CI and Boott Hydropower, Inc., an assignee there from, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2- 7749). 10.1.16 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corporation (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.16.1 Amendment No. 3 to 10.1.16 (Exhibit 2 to the CE Form 10- Q (June 1986), File No. 2-7749). 10.1.17 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amendment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2- 7749). 10.1.18 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.18.1 Amendatory Agreement No. 3 to 10.1.18 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.19 Phase I New Hampshire Transmission Line Support Agreement between NEET and certain other New England Utilities dated December 1, 1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.20 Agreement, dated September 1, 1985, with Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain NEPOOL utilities to include Phase II facilities in the definition of ''Project'' (Exhibit 1 to the CEC Form 10- Q (September 1985), File No. 2-30057). 10.1.21 Agreement to Preliminary Quebec Interconnection Support Agreement-Phase II among Public Service Company of New Hampshire (PSNH), New England Power Co. (NEP), BECO and CEC whereby PSNH assigns a portion of its interests under the original Agreement to the other three parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10- K, File No. 2-30057). 10.1.22 Preliminary Quebec Interconnection Support Agreement-Phase II among certain New England electric utilities dated June 1, 1984 (Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.22.1 First, Second and Third Amendments to 10.1.22 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.22.2 Fifth, Sixth and Seventh Amendments to 10.1.22 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.22.3 Fourth and Eighth Amendments to 10.1.22 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). 10.1.22.4 Ninth and Tenth Amendments to 10.1.22 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.22.5 Eleventh Amendment to 10.1.22 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2- 30057). 10.1.22.6 Twelfth Amendment to 10.1.22 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2- 30057). 10.1.23 Phase II Equity Funding Agreement for New England Hydro- Transmission Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.24 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2- 30057). 10.1.25 Phase II New Hampshire Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 8 dated May 1, 1986 through January 1, 1990, respectively, between New England Hydro-Transmission Corporation (New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1990), File No. 2- 30057). 10.1.26 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June 1, 1985, between New Hampshire Hydro and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.26.1 Amendment No. 1 to 10.1.26 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.26.2 Amendment No. 2 to 10.1.26 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.27 Phase II New England Power AC Facilities Support Agreement, dated June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.27.1 Amendments Nos. 1 and 2 to 10.1.27 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.27.2 Amendments Nos. 3 and 4 to 10.1.27 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.28 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.29 Agreements by and between Swift River Company and CE for the purchase of available hydro-electric energy to be produced by units located in Chicopee and North Willbraham, Massachusetts, both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2- 7749). 10.1.30 Power Purchase Agreement by and between SEMASS Partnership, as seller, to construct, operate and own a solid waste disposal facility at its site in Rochester, Massachusetts and CE, as buyer of electric energy and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.30.1 Power Sales Agreement to 10.1.30 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749). 10.1.30.2 Amendment to 10.1.30 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2- 7749). 10.1.30.3 Amendment to 10.1.30 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated May 24, 1991 (Exhibit 1 to CE Form 10-Q (June 1991), File No. 2- 7749). 10.1.31 Power Sale Agreement by and between CE (buyer) and Northeast Energy Associated, Ltd. (NEA) (seller) of electric energy and capacity, dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File No. 2- 7749). 10.1.31.1 First Amendment to 10.1.31 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749). 10.1.31.2 Second Amendment to 10.1.31 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.31.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the purchase of 21 MW of electricity (Exhibit 2 to the CE Form 10-Q (September 1988), File No. 2- 7749). 10.1.31.4 Amendment to 10.1.31.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.32 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between Commonwealth Electric (buyer) and Dartmouth Power Associates Limited Partnership (seller), whereby buyer will purchase all of the energy (67.6 MW) produced by a single gas turbine unit (Exhibit 1 to the CE Form 10-Q (June 1992), File No. 2-7749). 10.1.32.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and between Commonwealth Electric Company and Dartmouth Power Associates, L.P. dated September 5, 1989 (Exhibit 4 to the CE Form 10-Q (June 1995), File No. 2-7749). 10.1.33 Power Purchase Agreement by and between Masspower (seller) and Commonwealth Electric Company (buyer) for a 11.11% entitlement to the electric capacity and related energy of a 240 MW gas-fired cogeneration facility, dated February 14, 1992 (Exhibit 1 to Commonwealth Electric's Form 10-Q (September 1993), File No. 2-7749). 10.1.34 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller) and Commonwealth Electric Company (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 2 to Commonwealth Electric's Form 10-Q (September 1993), File No. 2-7749). 10.1.34.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., Cambridge Electric Light Company, Commonwealth Electric Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to Commonwealth Electric's Form 10-Q (September 1993), File No 2-7749). 10.1.34.2 Power Sale Agreement by and between Altresco Pittsfield, L. P. (seller) and Cambridge Electric Light Company (Cambridge Electric) (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas- fired cogeneration facility, dated February 20, 1992 (Exhibit 1 to Cambridge Electric's Form 10-Q (September 1993), File No. 2-7909). 10.1.34.3 First Amendment, dated November 7, 1994, to 10.1.34 by and between Commonwealth Electric Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 3 to Commonwealth Electric Company's Form 10-Q (June 1995), File 2-7749). 10.1.34.4 First Amendment, dated November 7, 1994, to 10.1.34.2 by and between Cambridge Electric Light Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 2 to Cambridge Electric Light Company's Form 10-Q (June 1995), File 2-7909). 10.2.1 Transportation Agreement between CNG and CG to provide for transportation of natural gas on a daily basis from Steuben Gas Storage Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No. 2-1647). 10.3.1 Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 2 to CES Form 10-Q (September 1993), File No. 1-7316). 10.3.1.1 First Amendment to 10.3.1, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1- 7316). 10.3.1.2 Second Amendment to 10.3.1, effective April 1, 1996 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316). 10.3.1.3 Third Amendment to 10.3.1, effective January 1, 1997 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316). 10.3.2 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731). 10.3.2.1 Thirteenth Amendment to 10.3.2 as amended September 1, 1981 (Refiled as Exhibit 3 to the Parent's 1991 Form 10- K, File No. 1-7316). 10.3.2.2 Fourteenth through Twentieth Amendments to 10.3.2 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316). 10.3.2.3 Twenty-first Amendment to 10.3.2 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316). 10.3.2.4 Twenty-second Amendment to 10.3.2 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316). 10.3.2.5 Twenty-third Amendment to 10.3.2 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316). 10.3.2.6 Twenty-fourth Amendment to 10.3.2 as amended March 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.3.2.7 Twenty-fifth Amendment to 10.3.2 as amended to May 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316). 10.3.2.8 Twenty-sixth Agreement to 10.3.2 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.3.2.9 Twenty-seventh Agreement to 10.3.2 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1- 7316). 10.3.2.10 Twenty-eighth Agreement to 10.3.2 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316). 10.3.2.11 Twenty-ninth Agreement to 10.3.2 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316). Cambridge Electric Light Company Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit 7(a), File No. 2-7909). 4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-7909). 4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-7909). 4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2-7909). 4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit 1, File No. 2-7909). NSTAR Gas Company Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures 4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No. 2-7820). 4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2-1647). 4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No. 2-1647). 4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994) (Exhibit 1, File No. 2-1647). 4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No. 2-1647).
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998 (Dollars in Thousands)
Additions Deductions Balance at Provisions Balance Beginning Charged to Accounts at End Description of Year Operations Recoveries Written Off the Year Year Ended December 31, 2000 Allowance for Doubtful Accounts $23,836 $ 18,920 $ 2,525 $ 16,972 $28,309 Year Ended December 31, 1999 Allowance for Doubtful Accounts $14,227(a) $ 24,437 $ 5,260 $ 20,088 $23,836 Year Ended December 31, 1998 Allowance for Doubtful Accounts $10,298 $ 9,555 $ 4,242 $ 14,959 $ 9,136
(a) The beginning balance includes $5,091,000 that relates to COM/Energy's reserve balance at the merger date of August 25, 1999. FORM 10-K NSTAR DECEMBER 31, 2000 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NSTAR Date: March 22, 2001 By: /s/ James J. Judge James J. Judge Senior Vice President, Treasurer and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 22nd day of March 2001.
Signature Title /s/ Thomas J. May Chairman of the Board and Chief Executive Officer Thomas J. May /s/ Robert J. Weafer, Jr. Vice President, Controller and Chief Accounting Officer Robert J. Weafer, Jr. /s/ Kevin C. Bryant Trustee Kevin C. Bryant /s/ Sheldon A. Buckler Trustee Sheldon A. Buckler /s/ Gary L. Countryman Trustee Gary L. Countryman /s/ Thomas G. Dignan, Jr. Trustee Thomas G. Dignan, Jr. /s/ Charles K. Gifford Trustee Charles K. Gifford /s/ Nelson S. Gifford Trustee Nelson S. Gifford /s/ Matina S. Horner Trustee Matina S. Horner /s/ Franklin M. Hundley Trustee Franklin M. Hundley /s/ Paul A. La Camera Trustee Paul A. La Camera /s/ Thomas J. May Trustee Thomas J. May /s/ Sherry H. Penney Trustee Sherry H. Penney /s/ Gerald L. Wilson Trustee Gerald L. Wilson /s/ Russell D. Wright Trustee Russell D. Wright
EX-21 2 exhibit21.txt SUBSIDIARIES OF THE REGISTRANT Exhibit 21.1 Subsidiaries of the Registrant NSTAR BEC Energy Boston Edison Company Harbor Electric Energy Company BEC Funding LLC Boston Energy Technology Group, Inc. Northwind Boston LLC NSTAR Communications, Inc. NSTAR Communication Securities Corporation Coneco Corporation Commonwealth Energy System Commonwealth Electric Company Cambridge Electric Light Company Canal Electric Company NSTAR Gas Company NSTAR Steam Corporation Hopkinton LNG Corp. Advanced Energy Systems, Inc. MATEP, LLC Advanced Energy Systems Management Company, Inc. Medical Area Total Energy Plant, Inc. COM/Energy Services Company COM/Energy Cambridge Realty Darvel Realty Trust Energy Investment Services, Inc. NSTAR Services Corporation EX-23 3 exhibit23.txt CONSENT OF INDEPENTENT ACCOUNTANTS Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-85559) of our report dated January 26, 2001 relating to the financial statements and the financial statement schedule, which appear in this Form 10-K. /s/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Boston, Massachusetts January 26, 2001 -----END PRIVACY-ENHANCED MESSAGE-----