Item 1. Business
(a) General Development of Business
NSTAR (or "the Company") is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 246,000 gas customers in 51 communities. 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). Its wholesale electric subsidiary is Canal Electric Company (Canal Electric). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR'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 a liquefied natural gas service (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of revenues in both 2001 and 2000.
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 encouraged the utility industry to seek efficiencies and other benefits through business combinations. NSTAR is prepared to operate in this changing marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy.
NSTAR Electric has committed resources to implement a System Improvement Program to better serve its customers by focusing on improving customer service and system reliability. This comprehensive, non-recurring System Improvement Program was implemented to upgrade NSTAR Electric's distribution system and is expected to be completed by the third quarter of 2002. The cost of this non-recurring program is expected to be $65 million. Approximately $11 million will be included in operations and maintenance expense in 2002 and $54 million will be invested in delivery assets (utility plant) during the year. A combination of unusually severe storms, record heat and extreme customer load in the Boston area led to prolonged and wide-spread outages in the summer of 2001 that underscored the need to address system upgrades and improve maintenance. NSTAR's peak demand electric load reached an all-time level on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior year's peak load by 12% and the previous all-time peak load by 8.5%. The program includes non-recurring costs to eliminate the backlog of critical maintenance activities and complete non-routine systems enhancements.
An integral part of the merger creating NSTAR is the rate plan of the retail utility subsidiaries of BEC and COM/Energy that was approved by the Massachusetts Department of Telecommunication and Energy (MDTE) on July 27, 1999. Significant elements of the rate plan include a four-year distribution rate freeze, recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years. Refer to the "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 segments.
(c) Narrative Description of Business
Principal Products and Services
NSTAR ELECTRIC
The results for 2001 and 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 2.3 million. In 2001, NSTAR Electric served approximately 1.1 million customers.
Sources and Availability of Electric Power Supply
NSTAR Electric has existing long-term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of short-term power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders.
NSTAR Electric entered into six-month agreements effective January 1, 2001 through June 30, 2001 and July 1, 2001 through December 31, 2001 with suppliers to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. NSTAR Electric's existing portfolio of power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2001, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric managed its Independent System Operator- New England Power capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001. For further information refer to Note 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 FERC. The estimated cost to decommission this plant is $471.1 million in current dollars. NSTAR Electric's share of this liability is approximately $11.8 million, less its share of the market value of the assets held in a decommissioning trust of approximately $7.4 million, is approximately $4.4 million at December 31, 2001. 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 (Amergen), but this transaction was disapproved on February 14, 2001 by Vermont's regulatory authority. Subsequently, in 2001, FERC approved an agreement between Vermont Yankee and intervening parties that included, among other things, a settlement on the regulatory treatment of costs incurred in conjunction with initiatives, including Amergen to sell the plant and related assets and liabilities.
On August 15, 2001, Vermont Yankee executed a Purchase and Sale Agreement with the intent to sell the plant and related assets and liabilities, including the liability to decommission the plant, to Entergy Nuclear Vermont Yankee, LLC. The sale of the plant, as contemplated, would likely result in the transfer of responsibility for decommissioning the plant to the new owner and make future decommissioning collections unnecessary.
New England Power Pool (NEPOOL)
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 are required to provide ISO-New England with market prices at which they sell short-term energy supply. These prices formed the basis for dispatch that began in the second quarter of 1999. As noted in the "Sources and Availability of Electric Power Supply" section above, NSTAR Electric has existing long- term power purchase contracts that have been supplying 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. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through 2004. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market price for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.
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
Natural gas is distributed by NSTAR Gas to approximately 246,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1,176,000. Twenty-five 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 producing regions in the U.S. Gulf and Canada to the final delivery points in the Company's service area. 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. Based on its firm pipeline transportation capacity entitlements, NSTAR Gas contracts for up to 140,309 Million British thermal units (MMBtu) per day of domestic production. In addition, NSTAR Gas has an agreement for up to 4,500 MMBtu per day of Canadian supplies. In November 2001, NSTAR Gas entered into a one-year full services firm supply agreement with a major marketer in order to more fully optimize its supply and transportation portfolio. The agreement requires the supplier to deliver all of NSTAR Gas' required pipeline supplies utilizing the Company's upstream pipeline capacity.
In addition to firm transportation and gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and liquefied natural gas ("LNG") facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline gas during the warmer months for use during the heating season. The underground storage contracts are a combination of existing and new agreements that are the result of FERC Order 636 service unbundling. During the summer injection season, excess pipeline capacity is used to deliver and store gas in market area storage facilities, located in the New York and Pennsylvania region. Stored gas is withdrawn during the winter season to supplement pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm storage capacity entitlements of over 7.5 billion cubic feet (Bcf).
A portion of the storage for 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 Bcf 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 .5 Bcf of natural gas that are filled with LNG trucked from Hopkinton or purchased from third parties.
NSTAR Gas has contracts for LNG storage 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 during the winter season, LNG is vaporized and placed in the distribution system to supplement pipeline and storage deliveries.
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 in order to optimize the value of its supply portfolio and to mitigate the cost of any excess resources. In 2001 the Company elected to accomplish this through third parties that provided guaranteed payments as compensation for use of any available excess storage and transportation entitlements. NSTAR Gas retains 25% of the gross mitigation 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 $636,000 and $189,000 in 2001 and 2000, respectively.
Natural Gas Industry Restructuring and Rates
Effective November 1, 2000, the MDTE approved regulations that provide for full customer choice to LDCs (local gas distribution companies) such as NSTAR Gas. NSTAR Gas has modified its billing, customer and gas supply systems to accommodate full retail choice. The MDTE previously had approved the compliance process submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. 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. The MDTE has also ruled on 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. Gas restructuring is not likely to have a significant adverse financial impact on LDCs.
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 of 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.
In December 2000 and in a revised filing in January 2001, NSTAR Gas filed for interim increases to its CGAC 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 incurred costs in order to avoid the accumulation of significant under-recoveries that would impair NSTAR Gas' ability to serve its customers. On January 31, 2001, the MDTE approved an adjustment to increase the CGAC factor to $1.1123 per therm from the prior factor of $0.7608 per therm. Subsequently, on February 28, 2001, as a result of a decline in wholesale natural gas prices, NSTAR Gas received approval from the MDTE to reduce the factor per therm to $0.9372 effective March 1, 2001, and in conjunction with its semi-annual filing made on March 15, 2001, NSTAR Gas proposed a CGAC factor of $0.7754 per therm for the period commencing May 1, 2001 through October 31, 2001. This factor, approved by the MDTE, included the collection in the summer period of a portion of the coming winter's gas costs in order to reduce cost deferrals that were projected for the end of October 2001. In October 2001, due to the significant decline in wholesale natural gas prices, NSTAR Gas received approval from the MDTE to reduce the CGAC factor for the period from November 1, 2001 through April 30, 2002 to $0.5261 per therm. In December 2001, NSTAR Gas received approval to further reduce its CGAC factor by 17% to $0.4350 per therm effective January 1, 2002. In January 2002, NSTAR Gas again filed and the MDTE approved a reduction of the NSTAR Gas CGAC factor that became effective February 1, 2002 to $0.3834 per therm as a result of the continuing decline in its supply costs. This represented a 59% decrease from the weighted average factor in effect during the prior winter season.
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 has accounted for its 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. NSTAR Com recognized an impairment of its entire investment in RCN in the first quarter of 2001. 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 and natural gas and 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 are subject to appeal to the MDTE. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Pursuant to the Restructuring Act enacted in November 1997, the MDTE has defined the service territory of 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
(1) Includes plant expenditures, capital requirements of non- utility ventures and $54 million of costs related to a non- recurring System Improvement Program.
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 2001 were $228.7 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 and Capital Resources" 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 2001 and 2000. 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 "Contingencies - Environmental Matters" section in Item 7, Management's Discussion and Analysis for more information.
Environmental-related capital expenditures for the years 2001 and 2000 were $0 and $4.5 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, 2001, NSTAR had approximately 3,300 full-time employees, including approximately 2,300 or 70% of whom are represented by two collective bargaining units covered by separate contracts. Effective in May 2001, all employees are employed by NSTAR Electric & Gas Corporation (NSTAR Electric & Gas). As of December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America, AFL-CIO. The new agreement results in a single bargaining unit of approximately 2,000 NSTAR Electric & Gas employees with a five-year contract expiring May 15, 2005 that replaced seven separate and widely diverse agreements.
A collective bargaining unit contract representing approximately 300 NSTAR Electric & Gas employees expires on March 31, 2002. On March 24, 2002, Local 12004, United Steelworkers of American, AFL- CIO-CLC ratified a new four-year contract that expires on March 31, 2006.
Management believes it has satisfactory employee relations with a significant majority of its employees.
(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.
Item 2. Properties
Substantially all of NSTAR Electric'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, continues to retain 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, 2001, the NSTAR Electric primary and secondary transmission and distribution system consisted of approximately 20,200 circuit miles of overhead lines, approximately 8,400 circuit miles of underground lines, 261 substations and approximately 1,109,000 active customer meters.
NSTAR Electric's high-tension transmission lines are generally located on land either owned or subject to perpetual and exclusive easements in its favor. Its low-tension distribution lines are located principally on public property under permission granted by municipal and other state authorities.
The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 2001, the gas system included approximately 2,900 miles of gas distribution lines, approximately 174,700 services and approximately 266,200 customer meters together with the necessary measuring and regulating equipment. In addition, NSTAR (through Hopkinton) 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 Bcf 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.
In the third quarter of 2001, in conjunction with its corporate facilities consolidation of approximately a third of its work force, NSTAR completed construction of 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 houses central administrative offices including finance, human resources, sales, engineering, information technology, and customer care. NSTAR is expected, in 2002, to close on a like-kind exchange of properties in Boston and Cambridge for the Summit.
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. NSTAR Steam Corporation's distribution system consists primarily of approximately 3.5 miles of high pressure steam lines to 21 customers in Cambridge and Boston.
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.
Item 3. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period.
The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy was appealed by certain parties to the Massachusetts Supreme Judicial Court. The appeals of the AG and a separate group that consists of The Energy Consortium and Harvard University remain pending. In October 2001, the MDTE certified the record of the case to the court; however, there has to date been no briefing, hearing or other action taken with respect to this proceeding. If an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period.
Regulatory proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the AG contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on NSTAR's consolidated financial position or results of operations.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current customers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This change had no material adverse effect on NSTAR's consolidated financial position or results of operations.
Other legal matters
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.
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 2001.
Item 4A. Executive Officers of Registrant
Part II
Item 5.
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. NSTAR's closing market price at December 31, 2001 was $44.85 per share.
(b) Holders
As of December 31, 2001, there were 29,890 holders of NSTAR common shares.
(c) Dividends
Item 6.
Item 6. Selected Consolidated Financial Data
(a) 2001 includes the impact of a non-cash, after-tax charge of $173.9 million, or $3.28 per share, related to NSTAR's investment in RCN Corporation.
(b) Excludes the current portion of long-term debt or preferred stock.
(c) 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.
(a) Includes impact of a non-cash, after-tax charge of $173.9 million, or $3.28 per share, related to NSTAR's investment in RCN Corporation.
(b) The sum of the quarters for 2000 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.
Item 7. Management's Discussion and Analysis
Overview
NSTAR (or "the Company") is an energy delivery company serving approximately 1.3 million customers in Massachusetts, including approximately 1.1 million electric customers in 81 communities and 246,000 gas customers in 51 communities. 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). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR'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 a liquefied natural gas service company (Hopkinton LNG Corp.). Utility operations accounted for approximately 96% of revenues in both 2001 and 2000.
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 encouraged the utility industry to seek efficiencies and other benefits through business combinations. NSTAR is prepared to operate in this changing marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy.
NSTAR Electric has committed resources to implement a System Improvement Program to better serve its customers by focusing on improving customer service and system reliability. This comprehensive, non-recurring System Improvement Program was implemented to upgrade NSTAR Electric's distribution system and is expected to be completed during 2002. The cost of this non- recurring program is expected to be $65 million. Approximately $11 million will be included in operations and maintenance expense in 2002 and $54 million will be invested in delivery assets during the year. A combination of unusually severe storms, record heat and extreme customer load in the Boston area led to prolonged and wide-spread outages in the summer of 2001 that underscored the need to address system upgrades and improve maintenance. NSTAR's peak demand electric load reached an all- time level on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior year's peak load by 12% and the previous all- time peak load by 8.5%. The program includes non-recurring costs to eliminate the backlog of critical maintenance activities and complete non-routine systems enhancements.
Cautionary Statement
This Management's Discussion and Analysis contains certain forward-looking statements such as forecasts and projections of expected future performance or statements of management's plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission (SEC) and in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe" and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward- looking statements may not turn out to be what the Company expected. Actual results could potentially differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.
The impact of continued cost control procedures on operating results could differ from current expectations. NSTAR's revenues from its electric and gas sales are weather-sensitive, particularly sales to residential and commercial customers. Accordingly, NSTAR's sales in any given period reflect, in addition to other factors, the impact of weather, with colder temperatures generally resulting in increased gas sales and warmer temperatures generally resulting in increased electric sales. NSTAR anticipates that these sensitivities to seasonal and other weather conditions will continue to impact its sales forecasts in future periods. The effects of changes in weather, economic conditions, tax rates, interest rates, technology, prices and availability of operating supplies could materially affect the projected operating results.
NSTAR undertakes no obligation to publicly update forward-looking statements, whether as a result of new information, future events, or otherwise. You are advised, however, to consult any further disclosures NSTAR makes in its Forms 10-Q and 8-K to the SEC. Also note that NSTAR provides in the next paragraph a cautionary discussion of risks and other uncertainties relative to its business. These are factors that could cause its actual results to differ materially from expected and historical performance. Other factors in addition to those listed here could also adversely affect NSTAR.
NSTAR's forward-looking information depends in large measure on prevailing governmental policies and regulatory actions, including those of the Massachusetts Department of Telecommunications and Energy (MDTE) and the Federal Energy Regulatory Commission (FERC), with respect to allowed rates of return, rate structure, financings, purchased power and cost of gas recovery, acquisition and disposition of assets, operation and construction of facilities, changes in tax laws and policies and changes in and compliance with environmental and safety laws and policies.
The impacts of various environmental, legal issues, and regulatory matters could differ from current expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and the specific cleanup technology could affect the estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect any estimated litigation costs.
Generating Assets Divestiture
On October 26, 2000, the MDTE approved the filing made by ComElectric and Cambridge Electric (together, "the Companies") for the partial buydown of their contract with Canal for power from the Seabrook nuclear generating facility (Seabrook). In November 2000, a total of $141.6 million of funds held by an affiliate, Energy Investment Services, Inc. (EIS), was transferred to the Companies. EIS was established as the vehicle to invest the net proceeds from the sale of the Companies' generation assets. The Companies, in turn, reduced their respective future costs to be recovered from customers. The FERC and the MDTE approved Canal's request to reflect the buydown effective November 1, 2000. Canal, along with other joint-owners of Seabrook, has begun to actively market the sale of Seabrook.
In July 1999, Boston Edison completed the sale of the Pilgrim Nuclear Generating Station to Entergy Nuclear Generating Company (Entergy), a subsidiary of Entergy Corporation, for $81 million. In addition to the amount received from the buyer, Boston Edison received a total of approximately $233 million from the Pilgrim contract customers, including $103 million from ComElectric, to terminate their contracts. As part of the sale, Boston Edison, transferred its decommissioning trust fund to Entergy. In order to provide Entergy with a fully funded decommissioning trust fund, Boston Edison contributed approximately $271 million to the fund at the time of the sale. As a result of a favorable Internal Revenue Service tax ruling, Boston Edison received $43 million from Entergy reflecting a reduction in the required decommissioning funding. The difference between the total proceeds received and the net book value of the Pilgrim assets sold plus the net amount to fully fund the decommissioning trust is included in Regulatory assets on the accompanying Consolidated Balance Sheets as such amounts are currently being collected from customers under Boston Edison's settlement agreement.
Rate and Regulatory Proceedings
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 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 Management's Discussion and Analysis for more information.
Goodwill relating to the merger 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 commencing in 2003. A majority of costs to achieve the merger were 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 offset by ongoing cost savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. Refer to the "New Accounting Principles" section of this Management's Discussion and Analysis for further information.
In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the Massachusetts Attorney General (AG) contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on NSTAR's consolidated financial position or results of operations.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current customers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This charge had no material adverse effect on NSTAR's consolidated financial position or results of operations.
On June 13, 2001, the MDTE approved a settlement agreement between Cambridge Electric and the Massachusetts Institute of Technology (MIT) involving a dispute over the customer transition charge (CTC) assessed by Cambridge Electric to MIT. Under the settlement, Cambridge Electric refunded approximately $1.7 million to MIT and MIT withdrew (i) its appeal at the Massachusetts Supreme Judicial Court of the MDTE's rate order associated with the merger of BEC Energy and COM/Energy and (ii) its separate rate complaint at the MDTE involving the CTC.
On October 29, 2001, and as subsequently updated, NSTAR Electric and NSTAR Gas each filed with the MDTE proposed service quality plans for each company, which replaced the service quality plan that had previously been filed as a part of the NSTAR merger rate plan and includes guidelines that had been established by the MDTE as a result of its generic investigation of service quality issues. The service quality plans established performance benchmarks effective January 1, 2002 for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance. The companies are required to report annually concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks. On October 29, 2001, NSTAR Electric and NSTAR Gas also filed with the MDTE a report concerning their performance on the identified service quality measures for the two twelve-month periods ended August 31, 2000 and 2001. This report included a calculation of penalties in accordance with MDTE guidelines whereby penalties were calculated totaling approximately $3.9 million relating primarily to Boston Edison's electric system reliability performance for the summer of 2001. NSTAR disputes the legal applicability of penalties for these performance periods; however, NSTAR proposed in settlement of this matter to provide credits to Boston Edison customers totaling $3.9 million, offset in part by other payments to Boston Edison customers, which totaled approximately $1 million, relating to summer 2001 electric service outages. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.25 million to be refunded to customers as a credit to their bills in 2002.
Also on October 29, 2001, NSTAR Electric filed with the MDTE a comprehensive report regarding electric system performance issues encountered during the summer of 2001. The filing included detailed analyses of factors affecting performance, as well as, the companies' plans to address issues identified. The MDTE also requested similar filings from other Massachusetts electric distribution companies and has held public hearings and will hold adjudicatory hearings concerning each such filing. On January 30, 2002, the AG and the Massachusetts Division of Energy Resources (DOER) filed comments urging the MDTE to assess the maximum penalties allowed pursuant to the established service quality benchmarks and to require an independent management audit as a result of alleged service quality deficiencies. On February 6, 2002, NSTAR Electric filed its brief arguing against the AG's and DOER's positions. On March 22, 2002, following a number of public hearings throughout the NSTAR Electric service area, the MDTE issued an order finding that NSTAR Electric had made progress in addressing the issues which initiated the investigation and requiring that NSTAR Electric submit further updated reports on specific issues on a quarterly and annual basis. NSTAR is unable to estimate its ultimate liability for future costs or penalties as a result of any further filings relating to this investigation. However, in view of NSTAR's current assessment of its electric distribution system performance responsibilities, existing legal requirements and regulatory policies, management believes it would not have a material effect on NSTAR's consolidated financial position, cash flows or results of operations for a reporting period.
Retail Electric Rates
All distribution customers must pay a transition charge as a component of their rate. The purpose of the transition charge is to allow for the 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 are approved by the MDTE in annual filings by the NSTAR Electric companies. The current schedule for cost recovery through the transition charge is: Boston Edison through 2016, Cambridge Electric and ComElectric through 2026. This schedule is subject to adjustment by the MDTE.
The 1997 Restructuring Act requires electric distribution companies to obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier through either standard offer service or default service. Standard offer service will be available to eligible customers through 2004 at prices approved by the MDTE, set at levels so as to guarantee mandatory overall rate reductions provided by the Restructuring Act. New retail customers in the NSTAR Electric service territories and other customers who are no longer eligible for standard offer service and have not chosen to receive service from a competitive supplier are provided default service. The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2001, NSTAR Electric had approximately 16% of its load requirements provided by competitive suppliers.
NSTAR Electric's accumulated cost to provide default and standard offer service was in excess of the revenues it was allowed to bill. As a result, NSTAR reflected a regulatory asset of approximately $242.7 million at December 31, 2000 that is reflected as a component of Regulatory assets on the accompanying Consolidated Balance Sheets. NSTAR Electric was permitted by the MDTE to increase its rates charged to customers to collect this shortfall. As a result of new rates for standard offer and default service that became effective January 1 and July 1, 2001, and the reduction in power supply costs in 2001, the regulatory asset has declined to $45.4 million as of December 31, 2001.
In December 2000, the MDTE approved a standard offer fuel index of 1.321 cents per kilowatt-hour (kWh) that was added to each NSTAR Electric company's standard offer service rates for the first half of 2001. In June 2001, the MDTE approved an additional increase of 1.23 cents per kWh effective July 1, 2001 based on a fuel adjustment formula contained in its standard offer tariffs to reflect the prices of natural gas and oil. In December 2001, the MDTE approved a decrease in this fuel index of 1.125 cents to 1.426 cents per kWh for the first quarter of 2002 based on a decrease in the cost of fuel. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.
NSTAR Electric must, on an annual basis, file a forecast of its rates for the upcoming year along with any reconciliation of prior year revenues and costs for standard offer, default service, transmission and transition charges. The MDTE will, in the ordinary course, approve rates for the coming year before the current year-end to allow the new rates to become effective the first of January. Subsequently, the estimates for the prior year are reconciled to the actual amounts for that year. The MDTE reviews these costs and approves the amounts subject to any required adjustments.
In December 2001, NSTAR Electric made filings containing proposed rate adjustments for 2002, including a preliminary reconciliation of costs and revenues through 2001. The MDTE subsequently approved tariffs for each retail electric subsidiary effective January 1, 2002. The filings were updated in February 2002 to include final costs for 2001. The MDTE has approved the reconciliation of costs and revenues for Boston Edison through 2000 in its approval on November 16, 2001 of a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in Boston Edison's prior reconciliation filings. As a part of this settlement, Boston Edison agreed to reduce the costs sought to be collected through the transition charge by approximately $2.9 million as compared to the amounts that were originally sought. This settlement did not have a material adverse effect on NSTAR's consolidated financial position or results of operations for the period ended December 31, 2001.
On June 1, 2001, the MDTE issued its final orders on the reconciliation of ComElectric and Cambridge Electric's transition, standard offer service, default service and transmission costs and revenues for 1998. Reconciliation proceedings for ComElectric and Cambridge Electric reflecting costs and revenues for 1999 and 2000 remain open with hearings not yet having taken place. Management is unable to determine the outcome of the remaining MDTE proceedings. However, based upon past procedures and on information currently available, management does not believe that it is probable that the final MDTE approval will have a material adverse impact on NSTAR's consolidated financial position, results of operations and cash flows.
In addition to the annual rate filings referenced above, NSTAR Electric has also made interim filings with the MDTE concerning charges for a standard offer fuel adjustment and for (market- based) default service rates. NSTAR Electric has existing long- term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders. At December 31, 2001, approximately 29% of NSTAR Electric's customers were on default service.
Natural Gas Industry Restructuring and Rates
Effective November 1, 2000, the MDTE approved regulations that provide for full customer choice to LDCs (local gas distribution companies) such as NSTAR Gas. NSTAR Gas has modified its billing, customer and gas supply systems to accommodate full retail choice. The MDTE previously had approved the compliance process submitted by NSTAR Gas and other LDCs that implement the unbundling of retail gas services to all customers. 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. The MDTE has also ruled on 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. Gas restructuring is not likely to have a significant adverse financial impact on LDCs.
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 of 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.
In December 2000 and in a revised filing in January 2001, NSTAR Gas filed for interim increases to its CGAC 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 incurred costs in order to avoid the accumulation of significant under-recoveries that would impair NSTAR Gas' ability to serve its customers. On January 31, 2001, the MDTE approved an adjustment to increase the CGAC factor to $1.1123 per therm from the prior factor of $0.7608 per therm. Subsequently, on February 28, 2001, as a result of a decline in wholesale natural gas prices, NSTAR Gas received approval from the MDTE to reduce the factor per therm to $0.9372 effective March 1, 2001, and in conjunction with its semi-annual filing made on March 15, 2001, NSTAR Gas proposed a CGAC factor of $0.7754 per therm for the period commencing May 1, 2001 through October 31, 2001. This factor, approved by the MDTE, included the collection in the summer period of a portion of the coming winter's gas costs in order to reduce cost deferrals that were projected for the end of October 2001. In October 2001, due to the significant decline in wholesale natural gas prices, NSTAR Gas received approval from the MDTE to reduce the CGAC factor for the period from November 1, 2001 through April 30, 2002 to $0.5261 per therm. In December 2001, NSTAR Gas received approval to further reduce its CGAC factor by 17% to $0.4350 per therm effective January 1, 2002. In January 2002, NSTAR Gas again filed and the MDTE approved a reduction of the NSTAR Gas CGAC factor that became effective February 1, 2002 to $0.3834 per therm as a result of the continuing decline in its supply costs. This represented a 59% decrease from the weighted average factor in effect during the prior winter season.
Other Legal Matters
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 changes in estimates could have a material impact on the results for a reporting period.
Other Matters
The September 11, 2001 terrorist attack that occurred in New York City and in Washington, D.C., resulted in a tremendous loss of life and property. This unfortunate incident has had unprecedented pervasive negative impacts on several U.S. industries and on the U.S. economy in general. While NSTAR was not directly impacted by the event, the Company believes that it could be impacted indirectly in the near future. The indirect impacts may include lower revenues due to the negative impact on certain of NSTAR's commercial and industrial customers and higher costs related to items such as insurance and security.
Results of Operations
The following section of Management's Discussion and Analysis compares the results of operations for each of the three fiscal years ended December 31, 2001 and should be read in conjunction with the consolidated financial statements and the accompanying notes included elsewhere in this report.
2001 versus 2000
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.
For 2001 NSTAR reported a loss of $2.4 million or $0.05 per basic and diluted common share, compared to earnings for 2000 of $175 million or $3.19 and $3.18 per basic and diluted common share, respectively. Earnings for 2001 were $171.5 million, or $3.23 and $3.22 per basic and diluted common share, respectively, before a non-cash, after-tax charge of $173.9 million, or $3.28 per basic share, recorded in the first quarter related to NSTAR's investment in RCN Corporation (RCN). Factors that contributed to the $3.5 million, or 2%, decline in earnings before the non-cash, after-tax charge include a decline in firm gas sales (in billions of British thermal units or BBTU) of 11%, a proposed refund of $3.9 million to electric customers in conjunction with NSTAR's service quality plan, the accrual of costs associated with a pending shutdown of a district energy facility of $5 million and a decline in the return on equity on the plant investment base of the Seabrook facility. Positive factors included a slight increase in retail kWh sales of 0.6%, a lower regulatory interest expense adjustment due to a reconciliation filing of deferred standard offer and default service costs that resulted in additional interest expense recorded in 2000, a settlement of revenues due NSTAR from a former Pilgrim Unit customer and a one- time gain associated with the receipt of equity securities issued in conjunction with the demutualization of two mutual insurance companies that provide coverage to NSTAR subsidiaries. For 2001, a decrease of approximately 1.9 million average common shares outstanding that resulted from the repurchase of shares during 2000 had a positive impact on earnings per share of approximately eleven cents.
As previously disclosed and further discussed in this report, NSTAR is finalizing the process of converting its joint venture investment in RCN into shares of RCN common stock. NSTAR's investment in RCN includes 4.1 million common shares that it currently holds and 7.5 million common shares that it expects to receive for its remaining interest in the joint venture. Consistent with the performance of the telecommunications sector as a whole, the market value of RCN's common shares decreased significantly during the latter part of 2000 and continued in 2001. As a result, NSTAR recognized an impairment of its investment in RCN in the first quarter of 2001. NSTAR determined, in the first quarter of 2001, that this decline in market value was "other-than-temporary" as defined by Statement of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities."
Operating Revenues
Retail electric revenues were $2,497.5 million in 2001 compared to $2,065.4 million in 2000, an increase of $432.1 million, or 21%. The change in retail revenues includes a 0.6% increase in retail kWh sales, higher rates implemented in January and July 2001 for standard offer and default services, which increased retail revenues by $250.2 million and $257.5 million, respectively and the absence in 2001 of a $30.8 million fuel charge refund to customers in 2000. These revenue increases were partially offset by lower transition revenues of $88.1 million due to a decline in rates, a decline in transmission revenues of $6.5 million and a decline of $1.9 million for demand-side management and other revenues. The increase in NSTAR's retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on net income. The number of retail customers increased in 2001 to 1,086,000 from 1,079,000 customers and represents a growth rate of 0.7%. The customer growth rate in 2002 is projected to be an additional 0.7%.
The 0.6% increase in 2001 retail kWh sales primarily reflects growth in the residential and commercial sectors of 1.1% and 1.7%, respectively. NSTAR Electric's sales to residential and commercial customers were approximately 30% and 59%, respectively, of its total retail sales mix for 2001 and provided 41% and 51% of distribution revenue, respectively. Industrial sector sales declined 7.8% due primarily to a slowdown in economic conditions that resulted from reduced production or facility closings. The industrial sector comprises approximately 10% of NSTAR's energy sales and 6% of distribution revenue.
NSTAR forecasts its electric and gas sales based on normal weather conditions. Forecasted results may differ from those projected due to actual weather conditions above or below these normal weather levels.
Weather conditions greatly impact the change in electric and, to a larger extent, gas sales and revenues in NSTAR's service area. The summer period of 2001 was significantly warmer than the same period in 2000, and this abnormal pattern continued into the fourth quarter heating season of 2001 with above normal temperatures. Below is comparative information on cooling and heating degree days in 2001 and 2000 and the number of degree days in a "normal" year as represented by a 30-year average.
Wholesale electric revenues were $86.9 million in 2001 compared to $77.9 million in 2000, an increase of $9 million, or 12%. This increase in wholesale revenues primarily reflects increased demand from a public transit authority and municipal contracts. In 2002, wholesale electric sales are forecasted to decrease due to the expiration of contracts with several municipalities. The expiration of these contracts is not expected to impact NSTAR's consolidated earnings.
Gas sales revenues were $388.4 million in 2001 compared to $368.7 million in 2000, an increase of $19.7 million, or 5%. The increase in revenues is primarily attributable to the recovery of prior period gas costs, partially offset by an 11% decline in firm sales and transportation due to the economic slowdown in the commercial and industrial sectors. NSTAR Gas' sales are positively impacted by colder weather because a substantial portion of its customer base uses natural gas for space heating purposes. Conversely, warmer weather conditions have a negative impact on gas sales. This was the case during the fourth quarter of 2001 when firm gas sales declined 31.2% from the prior year and were significantly impacted by the 24.6% decline in heating- degree days.
As indicated above, heating degree days in 2001 were 8.3% below 2000 and 5.1% below normal and contributed to the decrease in firm sales and transportation. NSTAR Gas' firm BBTU sales to residential and commercial customers were approximately 65% and 27%, respectively, of total 2001 firm sales. The number of firm customers increased in 2001 to 246,000 customers and represents a growth rate of 0.8%. The customer growth rate in 2002 is projected to be an additional 1.25%.
Other revenues were $219.1 million in 2001 compared to $180.8 million in 2000, an increase of $38.3 million, or 21%. This change reflects higher New England Power Pool related transmission revenues and higher revenues realized from district energy operations.
Operating Expenses
Purchased power and cost of gas sold expense was $1,913 million in 2001, compared to $1,385.7 million in 2000, an increase of $527.3 million, or 38%. The purchased power component of these costs was $1,673.5 million in 2001 compared to $1,172.9 million in 2000, an increase of $500.6 million, or 43%. The increase in purchased power expense reflects the impact of the recognition of previously deferred standard offer and default service supply costs resulting from collection of these costs in 2001. NSTAR Electric adjusts its electric rates to collect the costs related to energy supply from customers on a fully reconciling basis. Due to the rate adjustment mechanisms, changes in the amount of energy supply expense have no impact on earnings. Also impacting this increase were increases in purchased power requirements due to a 0.6% increase in retail sales and a 2.2% increase in wholesale sales, partially offset by lower costs that reflect the prices of natural gas and oil. Further contributing to the increase in total expense is the cost of gas sold, representing NSTAR Gas' supply expense, which was $239.5 million for 2001 compared to $212.8 million in 2000, an increase of $26.7 million, or 13%, due primarily to the higher gas supply costs in 2001. These expenses are also fully reconciled to the current level of revenues collected.
Operations and maintenance expense was $417.1 million in 2001 compared to $415.8 million in 2000, an increase of $1.3 million, or 0.3%. This slight increase reflects higher electric distribution weather-related maintenance costs related to a major late-winter storm in March and severe summer weather during 2001 and higher maintenance costs incurred in connection with NSTAR's unregulated subsidiary activities. Other factors that increased expenses were higher bad debt expense primarily due to the increased sales and higher costs related to post-retirement and other benefits. Offsetting this increase was the absence of non- recurring computer system implementations costs incurred during 2000.
In 2002, operations and maintenance expense is forecasted to increase significantly to support the utility System Improvement Program of $11 million and increased pension costs. NSTAR has forecasted that pension costs will increase by approximately $20 million for 2002 as compared to 2001. This is due to the downturn in equity markets, which have reduced the value of NSTAR's pension investments and the impact of lower interest rates. This expected level of expense could vary due to external factors beyond the Company's control.
Depreciation and amortization expense was $231 million in 2001 compared to $238.6 million in 2000, a decrease of $7.6 million, or 3%. The decrease primarily reflects the buy-down of the Seabrook investment in November 2000 utilizing the majority of the proceeds from the sale of Canal's generating units. Further contributing to this decrease was the write-down of the remaining assets of a district energy facility in 2000 and decreased amortization of software-related costs, partially offset by a slightly higher level of system-wide depreciable plant-in- service.
Demand side management (DSM) and renewable energy programs expense was $70.1 million in 2001 compared to $78.8 million in 2000, a decrease of $8.7 million, or 11%, primarily due to timing of DSM expense. These costs are in accordance with program guidelines established by regulators and are collected from customers on a fully reconciling basis. In addition, NSTAR earns incentive amounts in return for increased customer participation.
Property and other taxes were $96.5 million in 2001 compared to $82.1 million in 2000, an increase of $14.4 million, or 18%. The increase was due to the fact that during 2000, Boston Edison was reimbursed for the majority of its payments in lieu of property taxes to the Town of Plymouth by Entergy. Entergy purchased the Pilgrim Unit from Boston Edison in 1999.
Income taxes from operations were $113.4 million in 2001 compared to $117.4 million in 2000, a decrease of $4 million, or 3%, reflecting the impact of lower pre-tax operating income.
Other Income (Deductions), net
Other deductions were $169 million in 2001 compared to income of $12.1 million in 2000, a net decrease in income of $181.1 million primarily attributable to the aforementioned non-cash, after-tax charge related to the carrying value of the RCN investment. This is discussed further in this section under the caption "RCN Joint Venture and Investment Conversion."
The decrease in other income, net for 2001 reflects the result of income items recognized in 2000 related to a gain of $3.4 million from the sale of land by a non-utility subsidiary, $4.4 million received from a third party related to the Pilgrim wholesale contract buyout and interest income on funds held by EIS of $7.6 million (EIS interest income in 2001 was $743,000 and these amounts were offset entirely with interest charges). Offsetting these gains in 2000 was the impact of NSTAR COM RCN joint venture losses of $5.6 million and in 2001, $4.5 million of income associated with the receipt of common stock in connection with the demutualization of two insurance companies. These factors were offset in 2001 by $3.8 million for the accrual of costs associated with a pending shutdown of an unregulated district energy facility.
Interest Charges
Interest on long-term debt and transition property securitization certificates was $158.4 million in 2001 compared to $154.8 million in 2000, an increase of $3.6 million, or 2%. This change in long-term interest costs includes $15.3 million that reflects a full-year of debt outstanding from the issuance of $300 million and $200 million of NSTAR 8% Notes in February and October of 2000, respectively, offset somewhat by a decrease of $7.6 million that reflects the retirement of $199 million in Boston Edison debt and the paydown of other subsidiary company debt of $7.4 million throughout 2000 as compared to retirements and paydowns in 2001 of $24.3 million and $10.1 million, respectively. Long- term debt interest in 2001 also reflects a reduction of securitization certificates interest of $4 million due to the partial retirement of this debt. Securitization interest represents interest on debt collateralized by the future income stream associated with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison.
Interest on short-term and other obligations was $25.3 million in 2001 compared to $55.2 million in 2000, a decrease of $29.9 million, or 54%. This decrease is primarily due to a reconciliation adjustment of regulatory deferrals in conjunction with an MDTE reconciliation that resulted in the recognition of interest expense in 2000, and the positive impact of approximately $4 million resulting from lower interest rates that includes the impact of higher average short-term borrowing levels from banks. The increase in borrowing is primarily the result of financing long-term debt and preferred stock retirements with short-term borrowing and other working capital requirements. Further contributing to the lower interest expense in 2001 was an offset to previously accrued interest expense on Internal Revenue Service tax matters that were settled in 2001.
2000 versus 1999
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. 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 a common share repurchase plan.
Operating Revenues
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 mitigation 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 services 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 $108.6 million in 1999, a decrease of $30.7 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.
Gas sales revenues were $368.7 million in 2000 compared to $107.1 million in 1999, an increase of $261.6 million, or 244%. The increase represents NSTAR Gas operations for a full year. In addition, on a comparable basis, the fourth quarter firm and transportation BBTU gas sales were higher by 25% due to colder weather. Heating degree days for the fourth quarter of 2000 totaled 2,246, 20% above the same period last year and 12% greater than the normal level of 2,009. 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%.
Other revenues were $180.8 million in 2000 compared to $84.9 million in 1999, an increase of $95.9 million, or 113%. 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.
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 and cost of gas sold expense was $1,385.7 million in 2000, compared to $794.7 million in 1999, an increase of $591 million, or 74%. The purchased power component of these costs was $1,172.9 million in 2000 compared to $736.8 million in 1999, an increase of $436.1 million, or 59%. 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 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 $415.8 million in 2000 compared to $353.8 million in 1999, an increase of $62 million, or 18%. 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 were 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 $238.6 million in 2000 compared to $210.3 million in 1999, an increase of $28.3 million, or 13%. 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.
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. These costs are in accordance with program guidelines established by the MDTE and are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs have no impact on earnings. In addition, NSTAR earns incentive amounts in return for increased customer participation.
Property and other taxes were $82.1 million in 2000 compared to $77.8 million in 1999, an increase of $4.3 million, or 6%. 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 (Deductions), net
Other income, net of taxes was $12.1 million in 2000 compared to income of $8.1 million in 1999, a net increase in income of $4 million, or 49%. The increase in income 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. Offsetting these factors in 2000 was the absence of $20.8 million related to the 1999 recognition of previously deferred investment tax credits associated with the Pilgrim Unit that was sold in 1999. Also in 2000, the change in other income reflected significantly lower NSTAR Com RCN joint venture losses which amounted to $5.6 million in 2000 that reflected NSTAR Com's decreased ownership interest compared to $16.2 million in 1999.
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% Notes 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 retirements as described in this section under the caption "Liquidity and Capital Resources."
Interest on short-term and other 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 of approximately $147 million in the unrecovered costs for standard offer and default service during 2000 (to a balance of $242.7 million at December 31, 2000). 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 and the impact of a full year of NSTAR operations.
Liquidity and Capital Resources
During 2001, 2000 and 1999, internal generation of cash provided 103%, 188% and 174%, 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 2002 is $315 million, which includes approximately $271 million for electric and gas operations and the balance for other capital requirements of non- utility ventures. Also, included in this level of spending is $54 million of costs associated with NSTAR's System Improvement Program. The capital spending level over the following four years is forecasted to aggregate approximately $737 million.
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.
In 2001, long-term debt financing activities included redemptions of securitization certificates of $62 million, redemption of all 500,000 shares outstanding of Boston Edison's Cumulative Preferred Stock, 8% Series, at the mandatory redemption price of $100 per share, the early redemption of $24.3 million 9.375% debentures, and other scheduled sinking fund payments. There were no new long-term debt issuances in 2001. 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 $206 million in long-term debt retirements, that included 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. At December 31, 2001 and 2000, there were no amounts outstanding under this revolving credit agreement. This arrangement serves as back-up to NSTAR's $450 million commercial paper program that, at December 31, 2001 and 2000, had $315.5 million and $252 million outstanding, respectively, under its commercial paper program. NSTAR anticipates renewing its revolving credit agreement under similar terms.
Boston Edison has approval from the FERC to issue up to $350 million of short-term debt. Boston Edison has a $300 million revolving credit agreement with a group of banks effective through December 2002. At December 31, 2001 and 2000, there were no amounts outstanding under this revolving credit agreement. This arrangement serves as back-up to Boston Edison's $300 million commercial paper program that, at December 31, 2001 and 2000, had outstanding balances of $191.5 million and $96.5 million, respectively. Separately, Boston Edison, effective July 20, 2001, has an additional $50 million line of credit with no outstanding amounts at December 31, 2001.
Boston Edison has approval from the MDTE to issue from time to time up to $500 million of long-term debt securities through 2002. In connection with this, on February 20, 2001, Boston Edison filed a registration statement on Form S-3 with the SEC, using a shelf registration process, to issue up to $500 million in debt securities. The SEC declared the registration statement effective on February 28, 2001. When issued, Boston Edison will use the proceeds to pay at maturity long-term debt and equity securities, refinance short-term debt and for other corporate purposes. No issuance of debt securities were made during 2001 under this authorization.
In addition, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $190 million available under several lines of credit. Approximately $118 million and $120 million was outstanding under these lines of credit at December 31, 2001 and 2000, respectively. ComElectric, Cambridge Electric and Canal have approval from FERC to issue short-term debt with amounts ranging from $60 million to $100 million.
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 and completed it in October 1999. 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 consolidated 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.
Performance Assurances and Financial Guarantees
NSTAR Electric has entered into a series of purchased power agreements to meet its default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric is completely recovering all of the payments it is making to suppliers and has financial and performance assurances and financial guarantees in place with those suppliers to protect NSTAR Electric from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, an individual NSTAR Electric distribution company receive a credit rating below investment grade, that company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit.
Preferred Stock Dividends and Redemptions
Preferred dividends of Boston Edison were approximately $5.6 million in 2001 and $6 million in both 2000 and 1999. Boston Edison redeemed all 500,000 shares outstanding of its Cumulative Preferred Stock, 8% Series, at the mandatory redemption price of $100 per share, plus accrued dividends from November 1, 2001 to December 1, 2001. Effective December 1, 2001, the dividends on this series ceased.
Other Investments
In the second quarter of 2001, NSTAR recorded $4.5 million as Other income for equity securities it received in connection with the demutualization of John Hancock Mutual Life Insurance Company and MetLife, Inc. NSTAR and its subsidiaries, as policyholders, received an appropriate distribution of common stock of each company. These securities are currently available for sale and are included in Other investments on the accompanying Consolidated Balance Sheets. The value of these common shares was adjusted to reflect market values as of December 31, 2001. The unrealized gain or loss associated with these shares will fluctuate due to changes in current market values and is reflected, net of applicable income taxes, as a component of Comprehensive income (loss) on the accompanying Consolidated Statements of Comprehensive Income (Loss). The cumulative increase or decrease in fair value of these shares as of December 31, 2001 is reflected as a component of Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets.
New Accounting Principles
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). This Statement, which is effective for NSTAR in the first quarter of 2002, establishes accounting and reporting standards for acquired goodwill and other indefinite lived intangible assets. It prohibits entities from continuing amortization of these assets. Instead, goodwill and other intangible assets will be subject to review for impairment. However, in accordance with paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," NSTAR plans to continue amortization of this asset over its estimated regulatory recovery period. NSTAR has determined that its unique regulatory rate structure, resulting from the merger and approved by the MDTE on July 27, 1999, requires continued amortization of goodwill. A significant element of this rate plan includes recovery of the acquisition premium over 40 years and provides for the reasonable assurance of the existence of a regulatory asset. NSTAR will determine the appropriate balance sheet classification of this asset once adopted. Management will continue to review its determination of SFAS 142.
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). This Statement, which is effective for fiscal years beginning after June 15, 2002, establishes accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Management is currently assessing the impact of SFAS 143 in light of its regulatory and accounting requirements. However, based on NSTAR's assessment to date, the adoption of SFAS 143 is not expected to have a material effect on its results of operations, cash flows, or financial position.
As of January 1, 2001, NSTAR adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts possibly including fixed-price fuel supply and power contracts) be recorded on the Consolidated Balance Sheets as either an asset or liability measured at its fair value.
The management of NSTAR has assessed the impact of the adoption of SFAS 133. As part of this assessment, NSTAR formed an implementation team in 2000 consisting of key individuals from various operational and financial areas of the organization. The primary role of this team was to inventory and determine the impact of potential contractual arrangements for SFAS 133 application. The implementation team performed extensive reviews of critical operating areas of NSTAR and documented its procedures in applying the requirements of SFAS 133 to NSTAR's contractual arrangements in effect on January 1, 2001. NSTAR continues its assessment on any impact that potentially may result from FASB revisions and clarifications, including, but not limited to, FASB Derivative Implementation Group Issue C15, to SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133 has not had a material effect on its results of operations, cash flows, or financial position.
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 has accounted for its 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. To date, NSTAR Com has received approximately 4.1 million shares of RCN common shares from two prior exchanges of its joint venture interest.
On April 6, 2000, NSTAR Com issued its third and final notice to exchange substantially all of its remaining interest in the joint venture into common shares of RCN. Effective with the third notice, NSTAR Com's profit and loss sharing ratio was reduced. During 2000, NSTAR Com recognized $5.6 million in equity losses from the joint venture.
On October 18, 2000, NSTAR Com and RCN signed an agreement in principle to amend the Joint Venture Agreement. Among other items, this proposal settled the number of shares to be received for the third conversion of NSTAR Com's remaining equity investment at 7.5 million shares. After extensive discussions and negotiations, NSTAR Com is finalizing revisions to this agreement and management anticipates having a definitive amended Joint Venture Agreement in 2002.
As previously disclosed, management continues to evaluate the carrying value of its entire investment in RCN. Consistent with the performance of the telecommunications sector as a whole, the market value of RCN's common shares decreased significantly during the latter part of 2000 and continued in 2001. As a result, in the first quarter of 2001, management determined that this decline in market value was "other-than-temporary" in accordance with the SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The market value of RCN common shares has continued to decline in the early part of 2002. Management cannot determine whether this trend will continue or if or when this sector or RCN's common share value will recover. However, should this trend continue for a period of six months or longer, NSTAR may be required to recognize an additional non-cash impairment charge in 2002. Should an impairment charge be necessary, it is reasonably possible that this could have a material adverse effect on NSTAR's result of operations.
Also, during the first quarter of 2001, the status of the amendment to the Joint Venture Agreement with RCN regarding the 7.5 million shares led management to determine that its investment in the joint venture was also impaired based on future market expectations for RCN common shares related to this investment.
As a result, NSTAR Com, recognized an impairment of its entire investment in RCN in the first quarter of 2001. This write-down resulted in a non-cash, after-tax charge of $173.9 million that is reported on the accompanying Consolidated Statements of Income as "Write-down of RCN investment, net."
The RCN shares received, as well as the remaining interest in the joint venture related to the pending 7.5 million shares, are included in Other investments on the accompanying Consolidated Balance Sheets at their estimated fair value of approximately $40.1 million at December 31, 2001. The fair value of the shares currently held may increase or decrease, at any time, as a result of changes in the market value of RCN common shares. As of December 31, 2001 and 2000, the market values of these shares were $2.93 and $6.31, respectively. The unrealized gain or loss associated with shares currently held will fluctuate due to the changes in fair value of these shares during each period and is reflected, net of associated income taxes, as a component of Other comprehensive income (loss), net on the accompanying Consolidated Statements of Comprehensive Income (Loss). The cumulative increase or decrease in fair value of these shares as of December 31, 2001 reflects the change since the write-down of these shares as a component of Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets. Management will continue to evaluate the carrying value of its investment in RCN for declines that are considered other than temporary.
At December 31, 2001 and 2000, NSTAR Com had $2.6 million and $47.9 million, respectively, in accounts receivable due from the joint venture. Amounts due are primarily the result of construction performed by NSTAR Com on behalf of the joint venture.
Contingencies
Environmental Matters
NSTAR's subsidiaries are involved in 26 state-regulated properties ("Massachusetts Contingency Plan, or "MCP" sites") where oil or other hazardous materials were previously spilled or released. The NSTAR subsidiaries are required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are uncertainties associated with the remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. In addition to the MCP sites, NSTAR subsidiaries also face possible liability as a potentially responsible party (PRP) in the cleanup of eight multi-party hazardous waste sites in Massachusetts and other states where one or more NSTAR subsidiaries are 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 $5.8 million and $7 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2001 and 2000, respectively, related to the non-recoverable portion of these cleanup liabilities. Based on its assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on 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 an 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 over a 7-year period without carrying costs. As of December 31, 2001, NSTAR Gas has recorded a liability of $6.7 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 and as either additional sites are identified or NSTAR's responsibilities for such sites are resolved. 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 1998 MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period.
The 1999 MDTE order approving the rate plan associated with the merger of BEC and COM/Energy was appealed by certain parties to the Massachusetts Supreme Judicial Court. The appeals of the AG and a separate group that consists of The Energy Consortium and Harvard University remain pending. In October 2001, the MDTE certified the record of the case to the court; however, there has to date been no briefing, hearing or other action taken with respect to this proceeding. If an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period.
Employees and Employee Relations
As of December 31, 2001, NSTAR had approximately 3,300 full-time employees, including approximately 2,300 or 70% of whom are represented by two collective bargaining units covered by separate contracts. Effective in May 2001, all employees are employed by NSTAR Electric & Gas Corporation (NSTAR Electric & Gas). As of December 2000, the management of NSTAR's utility subsidiaries and eight separate utility union bargaining units reached an agreement to merge most of the unionized workforce, effective January 1, 2001, into Local 369 of the Utility Workers Union of America, AFL-CIO. The new agreement results in a single bargaining unit of approximately 2,000 NSTAR Electric & Gas employees with a five-year contract expiring May 15, 2005 that replaced seven separate and widely diverse agreements.
A collective bargaining unit contract representing approximately 300 NSTAR Electric & Gas employees expires March 31, 2002. On March 24, 2002, Local 12004, United Steelworkers of America, AFL- CIO-CLC ratified a new contract that expires on March 31, 2006.
Management believes it has satisfactory employee relations with a significant majority of its employees.
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 long-term indebtedness were 7.50% in both 2001 and 2000. The weighted average interest rate for mandatory redeemable cumulative preferred stock was 8% in 2000. Carrying amounts and fair values of mandatory redeemable cumulative preferred stock and long-term indebtedness (excluding notes payable) as of December 31, 2001 and 2000 were as follows:
The mandatory redeemable cumulative preferred stock was redeemed in total on December 3, 2001.
Item 7A.
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. Customers have the option of continuing to buy power from the retail electric distribution businesses at standard offer prices through 2004. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market prices for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.
Similarly, any change in the fair market value of NSTAR's prudently incurred debt obligations realized by NSTAR would be borne by customers through future rates.
Item 8.
Item 8. Financial Statements and Supplementary Financial Information
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
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 246,000 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. NSTAR's 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). Its wholesale electric subsidiary is Canal Electric Company (Canal). NSTAR's three retail electric companies operate under the brand name "NSTAR Electric." Reference in this report to "NSTAR Electric" shall mean each of Boston Edison, ComElectric and Cambridge Electric. NSTAR'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 a liquefied natural gas service company (Hopkinton LNG Corp.).
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 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 the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain 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 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, distribution and transition revenues for electricity and natural gas delivered to customers but not yet billed are accrued at the end of each accounting period.
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 for utility and non-utility property were 3.02%, 3.06% and 3.31% in 2001, 2000 and 1999, respectively. Depreciation of non-utility property is computed on a straight- line basis over the estimated life of the asset and ranges from 5 to 33 years.
6. Investments - Available for Sale Securities
NSTAR classifies its investment in marketable securities as available for sale. These investments include 4.1 million common shares of RCN Corporation, 148,400 common shares of John Hancock Financial Services, Inc. and 141,300 common shares of MetLife, Inc. NSTAR includes any unrealized gains or losses on these securities in Accumulated other comprehensive income (loss), net on the accompanying Consolidated Balance Sheets.
7. 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.
8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2001, 2000 and 1999 were 4.31%, 6.16%, and 5.82%, respectively, and represented only the cost of short-term debt and excludes the impact of capitalized interest. AFUDC also includes capitalized interest on non-utility plant.
9. Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the net proceeds from the sale of Canal's generation assets that are required to be used to reduce the transition costs that otherwise would be billed to customers.
10. 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. NSTAR participates in several corporate joint ventures in which it has investments, principally its 14.5% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro- Quebec System in Canada, and its equity investments ranging from 2.5% to 14% in three regional nuclear facilities that are currently being decommissioned and one operating nuclear generating facility.
11. 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. Goodwill associated with this acquisition 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 amounts to approximately $12.2 million annually, while the costs to achieve (CTA) are being amortized over 10 years and will initially be approximately $11.1 million annually. CTA are the costs incurred to execute the merger including the employee costs for a voluntary severance program, legal costs, transaction costs and systems integration costs. The ultimate amortization of the CTA will reflect the total actual costs. Refer to "New Accounting Principles" under Item 13 of this note, for guidance on changes in accounting for goodwill.
12. 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.
13. New Accounting Principles
In June 2001, FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). This Statement, which is effective for NSTAR in the first quarter of 2002, establishes accounting and reporting standards for acquired goodwill and other indefinite lived intangible assets. It prohibits entities from continuing amortization of these assets. Instead, goodwill and other intangible assets will be subject to review for impairment. However, in accordance with paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," NSTAR plans to continue amortization of this asset over its estimated regulatory recovery period. NSTAR has determined that its unique regulatory rate structure, resulting from the merger and approved by the MDTE on July 27, 1999, requires continued amortization of goodwill. A significant element of this rate plan includes recovery of the acquisition premium over 40 years and provides for the reasonable assurance of the existence of a regulatory asset. NSTAR will determine the appropriate balance sheet classification of this asset once adopted. Management will continue to review its determination of SFAS 142.
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). This Statement, which is effective for fiscal years beginning after June 15, 2002, establishes accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. This standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Management is currently assessing the impact of SFAS 143 in light of its regulatory and accounting requirements. However, based on NSTAR's assessment to date, the adoption of SFAS 143 is not expected to have a material effect on its results of operations, cash flows, or financial position.
As of January 1, 2001, NSTAR adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively referred to as SFAS 133. SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts possibly including fixed-price fuel supply and power contracts) be recorded on the Consolidated Balance Sheets as either an asset or liability measured at its fair value.
The management of NSTAR has assessed the impact of the adoption of SFAS 133. As part of this assessment, NSTAR formed an implementation team in 2000 consisting of key individuals from various operational and financial areas of the organization. The primary role of this team was to inventory and determine the impact of potential contractual arrangements for SFAS 133 application. The implementation team performed extensive reviews of critical operating areas of NSTAR and documented its procedures in applying the requirements of SFAS 133 to NSTAR's contractual arrangements in effect on January 1, 2001. NSTAR continues its assessment on any impact that potentially may result from FASB revisions and clarifications, including, but not limited to, FASB Derivative Implementation Group Issue C15, to SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133 has not had a material effect on its results of operations, cash flows, or financial position.
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. SFAS 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 potential dilutive 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.
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 has accounted for its 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. To date, NSTAR Com has received approximately 4.1 million shares of RCN common shares from two prior exchanges of its joint venture interest.
On April 6, 2000, NSTAR Com issued its third and final notice to exchange substantially all of its remaining interest in the joint venture into common shares of RCN. Effective with the third notice, NSTAR Com's profit and loss sharing ratio was reduced. During 2000, NSTAR Com recognized $5.6 million in equity losses from the joint venture.
On October 18, 2000, NSTAR Com and RCN signed an agreement in principle to amend the Joint Venture Agreement. Among other items, this proposal settled the number of shares to be received for the third conversion of NSTAR Com's remaining equity investment at 7.5 million shares. After extensive discussions and negotiations, NSTAR Com is finalizing revisions to this agreement and management anticipates having a definitive amended Joint Venture Agreement in 2002.
As previously disclosed, management continues to evaluate the carrying value of its entire investment in RCN. Consistent with the performance of the telecommunications sector as a whole, the market value of RCN's common shares decreased significantly during the later part of 2000 and continued in 2001. As a result, in the first quarter of 2001, management determined that this decline in market value was "other-than-temporary" in accordance with the SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The market value of RCN common shares has continued to decline in the early part of 2002. Management cannot determine whether this trend will continue or if or when this sector or RCN's common share value will recover. However, should this trend continue for a period of six months or longer, NSTAR may be required to recognize an additional impairment charge in 2002. Should an impairment charge be necessary, it is reasonably possible that this could have a material adverse effect on NSTAR's result of operations.
Also, during the first quarter of 2001, the status of the amendment to the Joint Venture Agreement with RCN regarding the 7.5 million shares led management to determine that its investment in the joint venture was also impaired based on future market expectations for RCN common shares related to this investment.
As a result, NSTAR Com, recognized an impairment of its entire investment in RCN in the first quarter of 2001. This write-down resulted in a non-cash, after-tax charge of $173.9 million that is reported on the accompanying Consolidated Statements of Income as "Write-down of RCN investment, net."
The RCN shares received, as well as the remaining interest in the joint venture related to the pending 7.5 million shares, are included in Other investments on the accompanying Consolidated Balance Sheets at their estimated fair value of approximately $40.1 million at December 31, 2001. The fair value of the shares currently held may increase or decrease, at any time, as a result of changes in the market value of RCN common shares. As of December 31, 2001 and 2000, the market values of these shares were $2.93 and $6.31, respectively. The unrealized gain or loss associated with shares currently held will fluctuate due to the changes in fair value of these shares during each period and is reflected, net of associated income taxes, as a component of Other comprehensive income (loss), net on the accompanying Consolidated Statements of Comprehensive Income (Loss). The cumulative increase or decrease in fair value of these shares as of December 31, 2001 reflects the change since the write-down of these shares as a component of Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets.
At December 31, 2001 and 2000, NSTAR Com had $2.6 million and $47.9 million, respectively, in accounts receivable due from the joint venture. Amounts due are primarily the result of construction performed by NSTAR Com on behalf of the joint venture.
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. This is applicable to NSTAR's distribution and transmission operations, in addition to its remaining generation business that relates to Canal's 3.52% joint ownership interest in the Seabrook Nuclear Power Station (Seabrook).
The implementation of electric utility industry restructuring has certain accounting implications. The highlights of these include:
a. Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation business are recovered through the transition charge. This recovery occurs through 2016 for Boston Edison and through 2026 for ComElectric and Cambridge Electric. This schedule is subject to adjustment by the MDTE.
b. Fuel and purchased power charge
The fuel and purchased power charge ceased in 1998. The net remaining over-collection of fuel and purchased power costs were returned to customers in 1999 and 2000.
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 through 2004. The cost of providing standard offer service includes fuel and purchased power costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service. The market price for standard offer and default service will fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.
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's distribution rates were subject to a minimum and maximum return on average common equity from its distribution business through December 31, 2000.
The cost of providing transmission service to all NSTAR Electric distribution customers is recovered on a fully reconciling basis plus an approved return.
2. Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric and NSTAR Gas each filed with the MDTE proposed service quality plans for each company, which replaced the service quality plan that had previously been filed as a part of the NSTAR merger rate plan and includes guidelines that had been established by the MDTE as a result of its generic investigation of service quality issues. The service quality plans established performance benchmarks effective January 1, 2002 for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance. The companies are required to report annually concerning their performance as to each measure and are subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks. On October 29, 2001, NSTAR Electric and NSTAR Gas also filed with the MDTE a report concerning their performance on the identified service quality measures for the two twelve-month periods ended August 31, 2000 and 2001. This report included a calculation of penalties in accordance with MDTE guidelines whereby penalties were calculated totaling approximately $3.9 million relating primarily to Boston Edison's electric system reliability performance for the summer of 2001. NSTAR disputes the legal applicability of penalties for these performance periods; however, NSTAR proposed in settlement of this matter to provide credits to Boston Edison customers totaling $3.9 million, offset in part by other payments to Boston Edison customers, which totaled approximately $1 million, relating to summer 2001 electric service outages. On March 22, 2002, following hearings on the matter, the MDTE issued an order imposing a service quality penalty of approximately $3.25 million to be refunded to customers as a credit to their bills in 2002.
Also on October 29, 2001, NSTAR Electric filed with the MDTE a comprehensive report regarding electric system performance issues encountered during the summer of 2001. The filing included detailed analyses of factors affecting performance, as well as, the companies' plans to address issues identified. The MDTE also requested similar filings from other Massachusetts electric distribution companies and has held public hearings and will hold adjudicatory hearings concerning each such filing. On January 30, 2002, the AG and the Massachusetts Division of Energy Resources (DOER) filed comments urging the MDTE to assess the maximum penalties allowed pursuant to the established service quality benchmarks and to require an independent management audit as a result of alleged service quality deficiencies. On February 6, 2002, NSTAR Electric filed its brief arguing against the AG's and DOER's positions. On March 22, 2002, following a number of public hearings throughout the NSTAR Electric service area, the MDTE issued an order finding that NSTAR Electric had made progress in addressing the issues which initiated the investigation and requiring that NSTAR Electric submit further updated reports on specific issues on a quarterly and annual basis. NSTAR is unable to estimate its ultimate liability for future costs or penalties as a result of any further filings relating to this investigation. However, in view of NSTAR's current assessment of its electric distribution system performance responsibilities, existing legal requirements and regulatory policies, management believes it would not have a material effect on NSTAR's consolidated financial position, cash flows or results of operations for a reporting period.
3. Generating Asset Divestiture
On October 26, 2000, the MDTE approved the filing made by ComElectric and Cambridge Electric (together, "the Companies") for the partial buydown of their contract with Canal for power from Seabrook. In November 2000, a total of $141.6 million of funds held by an affiliate, Energy Investment Services, Inc. (EIS), was transferred to the Companies. EIS was established as the vehicle to invest the net proceeds from the sale of the Companies' generation assets. The Companies, in turn, reduced their respective future costs to be recovered from customers. The FERC and the MDTE approved Canal's request to reflect the buydown effective November 1, 2000. Canal, along with other joint-owners of Seabrook, has begun to actively market the sale of Seabrook.
Note E. Income Taxes
Income taxes are accounted for in accordance with SFAS No. 109, "Accounting for Income Taxes" (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109, net regulatory assets of $53.4 million and $55.9 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2001 and 2000, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
NSTAR has determined that no current or future income tax benefit is anticipated related to the write-down of its remaining investment in the RCN joint venture. As a result, NSTAR recorded in 2001 a $64.5 million valuation allowance for the entire tax benefit associated with this charge. If all or a portion of this tax benefit is ultimately realized, NSTAR will reflect a corresponding reduction in income tax expense.
Previously deferred investment tax credits are amortized over the estimated remaining lives of the property giving rise to the credits.
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:
Income tax expense is reflected net of $20.8 million in 1999, representing investment tax credits recognized as a result of generation asset divestitures. Excluding this shareholder benefit, the effective tax rate would have been approximately 39% in 1999.
Note F. Pension and Other Postretirement Benefits
1. Pension
NSTAR sponsors a defined benefit funded retirement plan that covers substantially all employees. NSTAR also maintains unfunded supplemental retirement plans for certain management employees.
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 $13,785,000, $10,547,000 and $0, respectively, as of December 31, 2001 and $14,067,000, $13,306,000 and $0, respectively, as of December 31, 2000.
In addition, $9,623,000 was recognized as a result of pension settlements in 2000. The majority of these charges will be recovered from customers and are a component of Regulatory assets on the accompanying Consolidated Balance Sheets. The previous amounts resulting from the merger-related separation agreements and generation divestitures are recoverable as part of the approved rate plans of the retail utility subsidiaries of NSTAR.
2. Savings Plan
NSTAR also provides a defined contribution 401(k) plan 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 $9 million in 2001, $7 million in 2000 and $9 million in 1999. The plan was amended, effective April 1, 2001, to allow participants the ability to reallocate their investments in NSTAR common shares to other investment options. Effective January 1, 2002, consistent with the Economic Growth and tax Relief Reconciliation Act of 2001, the plan was further amended to allow for increased maximum annual pre-tax contributions and additional "catch-up" pre-tax contributions for participants age 50 or older, acceptance of other types of "roll-over" pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash.
3. 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.
For measurement purposes a 9% weighted annual rate of increase in per capita cost of covered medical claims was assumed for 2002. 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.
Note G. Stock-Based Compensation
The NSTAR 1997 Share Incentive Plan (the Plan) permits a variety of stock and stock-based awards, including stock options and deferred (non-vested) stock to be granted to 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 two million, including shares issued in lieu of or upon reinvestment of dividends arising from awards. The Plan was amended in January 2002, subject to shareholder approval at the 2002 Annual Meeting of Shareholders, to increase the number of shares available for issuance to four million. During 2001, 97,850 deferred shares and 240,500 ten-year non-qualified stock options were granted. 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 under the Plan. The weighted average grant date fair value of the deferred stock issued during 2001, 2000 and 1999 was $39.70, $44.375 and $41.73, 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:
There were 546,264, 404,976 and 298,333 stock options exercisable on December 31, 2001, 2000 and 1999, respectively.
The stock options granted during 2001, 2000 and 1999 have a weighted average grant date fair value of $5.10, $7.00 and $4.86, respectively. The fair value was estimated using the Black- Scholes option pricing model with the following weighted average assumptions:
Compensation cost recognized in the accompanying Consolidated Statements of Income for stock-based compensation awards in 2001, 2000 and 1999 was $2,069,000, $1,717,000 and $1,044,000, respectively.
Note H. Capital Stock
1. Common Shares
Dividends declared per common share were $2.075, $2.015 and $1.955 in 2001, 2000 and 1999, respectively.
2. Cumulative Preferred Stock of Subsidiary
(in thousands, except per share amounts) Par value $100 per share, 2,660,000 shares authorized and 430,000 shares issued and outstanding:
Note I. Indebtedness
1. Long-Term Debt
The 8.25% series debentures due 2022 are first redeemable in September 2002 at 103.78% and the 7.80% series debentures due 2023 are first redeemable in March 2003 at 103.73%. 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 2001, 2000 and 1999. The weighted average interest rate of the bonds was 7.4%.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006.
Boston Edison has approval from the MDTE to issue from time to time up to $500 million of long-term debt securities through 2002. In connection with this, on February 20, 2001, Boston Edison filed a registration statement on Form S-3 with the SEC, using a shelf registration process, to issue up to $500 million in debt securities. The SEC declared the registration statement effective on February 28, 2001. When issued, Boston Edison will use the proceeds to pay at maturity long-term debt and equity securities, refinance short-term debt and for other corporate purposes. No issuance of debt securities were made during 2001 under this authorization.
The aggregate principal amounts of NSTAR long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2001 are approximately $108 million in 2002, $241 million in 2003, $79 million in 2004, $78 million in 2005 and $98 million in 2006.
NSTAR and Boston Edison have no covenant requirements under their long-term debt arrangements. COM/Electric, Cambridge Electric and NSTAR Gas have covenant requirements under their long-term debt arrangements and were in compliance at December 31, 2001 and 2000.
2. Short-Term Debt
NSTAR has a $450 million revolving credit agreement with a group of banks effective through November 2002. There were no amounts outstanding as of December 31, 2001 and 2000 under this revolving credit agreement. This arrangement serves as back-up to NSTAR's $450 million commercial paper program. NSTAR anticipates renewing its revolving credit agreement under similar terms. At December 31, 2001 and 2000, NSTAR had $315.5 million and $252 million outstanding, respectively, under its 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 approval from the FERC to issue up to $350 million of short-term debt. Boston Edison has a $300 million revolving credit agreement with a group of banks effective through December 2002. At December 31, 2001 and 2000, there were no amounts outstanding under this revolving credit agreement. This arrangement serves as back-up to Boston Edison's $300 million commercial paper program that, at December 31, 2001 and 2000, had outstanding $191.5 million and $96.5 million, respectively. Under the terms of this agreement, Boston Edison is required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the total agreement amount. Separately, Boston Edison, effective July 20, 2001, has an additional $50 million line of credit with no outstanding amounts at December 31, 2001.
In addition, ComElectric, Cambridge Electric and NSTAR Gas, collectively, have $190 million available under several lines of credit that will expire at varying intervals in 2002. These lines are normally renewed upon expiration and commitment fees are required. Approximately $118 million and $120 million were outstanding under these lines of credit as of December 31, 2001 and 2000, respectively. ComElectric, Cambridge Electric and Canal have approval from FERC to issue short-term debt with amounts ranging from $60 million to $100 million.
Interest rates on the outstanding borrowings generally are money market rates and averaged 4.13% and 6.65% in 2001 and 2000, respectively. In aggregate, notes payable to banks discussed above totaled $624.8 million and $468.3 million at December 31, 2001 and 2000, 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 $11.7 million and $21.9 million for 2001 and 2000, respectively, approximate fair value due to the short- term nature of these securities.
2. Mandatory Redeemable Cumulative Preferred Stock and Indebtedness (Excluding Notes Payable).
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 including telecommunications, district heating and cooling operations, and a liquefied natural gas service. Financial data for the operating segments were as follows:
(a) The equity income (loss) from equity investments is included in other income (expense), net on the accompanying Consolidated Statements of Income.
(b) The net income (loss) for 2001 includes the impact of a non- cash, after-tax charge of $173.9 million, or $3.28 per share, related to the write-down of NSTAR's investment in RCN Corporation and is reflected in the results of unregulated operations.
(c) Financial data for 1999 includes eight months of BEC Energy and four months of NSTAR.
Note L. Commitments and Contingencies
1. Contractual Commitments
The total expense for both lease rentals and transmission agreements was $57.1 million in 2001, $45.3 million in 2000 and $38.7 million in 1999, net of capitalized expenses of $2.3 million in 2001, $1.7 million in 2000 and $1.5 million in 1999.
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $8.3 million in 2001, $8.7 million in 2000 and $10.8 million in 1999.
NSTAR Electric has entered into a series of short-term purchased power agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric is completely recovering all of the payments it is making to suppliers and has financial and performance assurances and financial guarantees in place with those suppliers to protect NSTAR Electric from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, an individual NSTAR Electric distribution company receive a credit rating below investment grade, that company potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit.
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 obligations of those participants who do not meet certain credit criteria. At December 31, 2001, NSTAR Electric's portion of these guarantees amounted to $14.4 million. New England Hydro-Transmission Electric Company, Inc. (NEH) and New England Hydro-Transmission Corporation (NHH) have agreed to use their best efforts to limit their equity investment to 40% of their total capital during the time NEH and NHH have outstanding debt in their capital structure. In order to meet its best efforts obligation pursuant to the Equity Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in September 2001, NEH repurchased a total of 250,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,100 outstanding shares from all equity holders. Through December 31, 2001, NSTAR Electric's reduction of its equity ownership resulting from NEH buy-back of 36,168 shares and NHH buy-back of 159 shares was approximately $814,000.
Canal owns a 3.52% joint ownership interest in the Seabrook Nuclear Power Station, and sells its energy and capacity entitlement to ComElectric and Cambridge Electric. The estimate of NSTAR's share of the costs of decommissioning Seabrook was approximately $5.2 million as of December 31, 2001. These estimates were recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting asset in Other investments. Canal, along with other joint-owners of Seabrook, has begun to actively market the sale of Seabrook.
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 $471.1 million in current dollars. NSTAR Electric's share of this liability is approximately $11.8 million, less its share of the market value of the assets held in a decommissioning trust of approximately $7.4 million, is approximately $4.4 million at December 31, 2001. 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 (Amergen), but this transaction was disapproved on February 14, 2001 by Vermont's regulatory authority. Subsequently, in 2001, FERC approved an agreement between Vermont Yankee and intervening parties that included, among other things, a settlement on the regulatory treatment of costs incurred in conjunction with initiatives, including Amergen, to sell the plant and related assets and liabilities.
On August 15, 2001, Vermont Yankee executed a Purchase and Sale Agreement with the intent to sell the plant and related assets and liabilities, including the liability to decommission the plant, to Entergy Nuclear Vermont Yankee, LLC. The sale of the plant, as contemplated, would likely result in the transfer of responsibility for decommissioning the plant to the new owner and make future decommissioning collections unnecessary.
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. As of December 31, 2001, this program was completed and 145,730 shares, were redeemed. NSTAR Electric's reduction of its equity ownership resulting from the buy-back of 20,402 shares was approximately $2 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 its remaining investment in CYAPC and estimated costs of decommissioning is approximately $33 million as of December 31, 2001. This estimate was recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting Regulatory asset.
In December 1996, CYAPC filed for rate relief at the FERC seeking to recover certain post-operating costs, including decommissioning. In August 1998, the FERC Administrative Law Judge (ALJ) released an initial decision regarding CYAPC's filing. This decision called for the disallowance of the common equity return on the CYAPC investment subsequent to the shutdown. The decision also stated that decommissioning collections should continue to be based on a previously approved estimate, with an adjustment for inflation, until a more reliable estimate was developed. In October 1998, both CYAPC and Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ decision. During April 2000, CYAPC signed settlement agreements with the major intervening parties in the 1996 FERC rate case. CYAPC received final FERC approval related to the settlement agreements and revised rates went into effect September 1, 2000. CYAPC received FERC approval on September 11, 2000, regarding the decommissioning collections, a return on equity of 6% and full recovery of assets.
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. During 2001, Maine Yankee initiated a stock buy-back program to redeem 75,200 of shares outstanding. Through December 31, 2001, NSTAR Electric's reduction of its equity ownership resulting from the buy-back of 3,008 shares was approximately $400,000.
NSTAR Electric's share of Maine Yankee's remaining decommissioning costs is approximately $19.6 million as of December 31, 2001. This estimate was recorded on the accompanying Consolidated Balance Sheets as a Power contract liability and an offsetting Regulatory asset.
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 equity investments 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 Nuclear Electric Insurance Limited (NEIL). NEIL provides $2.75 billion of property, boiler, machinery and decontamination insurance coverage, including accidental premature decommissioning insurance. All companies insured with NEIL are subject to retroactive assessments. Three of the four units in which NSTAR has equity investments 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 investments 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
NSTAR's subsidiaries are involved in 26 state-regulated properties ("Massachusetts Contingency Plan, or "MCP" sites") where oil or other hazardous materials were previously spilled or released. The NSTAR subsidiaries are required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are uncertainties associated with the remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. In addition to the MCP sites, NSTAR subsidiaries also face possible liability as a potentially responsible party (PRP) in the cleanup of eight multi-party hazardous waste sites in Massachusetts and other states where one or more NSTAR subsidiaries are 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 $5.8 million and $7 million are included as liabilities in the accompanying Consolidated Balance Sheets at December 31, 2001 and 2000, respectively, related to the non-recoverable portion of these cleanup liabilities. Based on its assessments of the specific site circumstances, management does not believe that it is probable that any such additional costs will have a material impact on NSTAR's consolidated financial position. However, it is possible that additional provisions for cleanup costs that may result from a change in estimates could have an impact on the results of operations for a reporting period in the near term.
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 over a 7-year period without carrying costs. As of December 31, 2001, NSTAR Gas has recorded a liability of $6.7 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 and as either additional sites are identified or NSTAR's responsibilities for such sites are resolved. 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. Legal Proceedings
a. Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving the Boston Edison electric restructuring settlement agreement was appealed by certain parties to the Massachusetts Supreme Judicial Court. One appeal remains pending. However, there has to date been no briefing, hearing or other action taken with respect to this proceeding. Management is currently unable to determine the outcome of this proceeding. However, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position, cash flows and the results of operations for a reporting period.
b. Regulatory proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE reflecting final costs and revenues through 1998, the AG contested cost allocations related to Boston Edison's wholesale customers. On June 1, 2001, the MDTE approved Boston Edison's revenue-credit approach for wholesale sales to be consistent with Boston Edison's restructuring settlement. The reconciliation of wholesale revenues and costs, along with other reconciliation issues, were addressed in Boston Edison's 2000 filing covering the reconciliation of costs through December 31, 2000. On November 16, 2001, the MDTE approved a Settlement Agreement between Boston Edison and the AG resolving all outstanding issues in this filing. This settlement agreement did not have a material effect on NSTAR's consolidated financial position or results of operations.
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's compliance with a 1993 order that permitted the formation of Boston Energy Technology Group, Inc. (BETG) and authorized Boston Edison to invest up to $45 million in non- utility activities. On December 28, 2001, the MDTE issued its order ruling that Boston Edison exceeded the $45 million investment cap set by the MDTE in 1993 by $3.9 million. BETG was ordered to return this amount to Boston Edison within 30 days. This reimbursement occurred in January 2002. Boston Edison was also ordered to pay approximately $1.9 million representing carrying charges on the over-investment amount since December 31, 1997 to current customers in the form of a credit to Boston Edison's transition costs. Accordingly, this credit has been recorded and is included in the accompanying Consolidated Balance Sheets as a reduction of Regulatory assets. This change had no material adverse effect on NSTAR's consolidated financial position or results of operations.
c. Other legal matters
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 has existing long-term power purchase agreements that are expected to supply approximately 90%-95% of its standard offer service obligations. NSTAR Electric has entered into a series of short-term power purchase agreements to meet its entire default service supply obligations and its remaining unmet standard offer supply obligations through December 31, 2002. NSTAR Electric expects to continue to make periodic market solicitations for default service and standard offer power supply consistent with provisions of the Restructuring Act and MDTE orders.
Capacity costs of long-term contracts reflect NSTAR Electric's proportionate share of capital and fixed operating costs of certain generating units. In 2001, these costs were attributed to 991.6 MW of capacity purchased. 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. Total capacity purchased in 2001 was 1,973 MW.
NSTAR Electric entered into six-month agreements effective January 1, 2001 through June 30, 2001 and July 1, 2001 through December 31, 2001 with suppliers to provide full default service energy and ancillary service requirements at contract rates substantially similar to MDTE-approved tariff rates. NSTAR Electric's existing portfolio of power purchase contracts supplied the majority of its standard offer (including wholesale) energy requirements in 2001, supplemented with long-term and daily purchases/sales in the bilateral and spot markets. In addition, NSTAR Electric managed its Independent System Operator- New England Power capability responsibilities, congestion and uplift costs associated with default service and standard offer load throughout 2001.
NSTAR Electric's total capacity and/or energy costs associated with these contracts in 2001, 2000 and 1999 were approximately $678 million, $720 million and $601 million, respectively. NSTAR Electric's capacity charge obligation under these contracts for the years after 2001 are as follows:
2. NSTAR Gas Contracts
NSTAR Gas has various contractual agreements covering the transportation of natural gas, underground and liquefied natural gas 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. NSTAR Gas' firm contract demand charges associated with these contracts in 2001, 2000 and 1999 were approximately $51.8 million, $54.3 million and $55.1 million. NSTAR Gas' firm contract demand charges at current rates under these contracts for the years after 2001 are as follows:
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 76, present fairly, in all material respects, the financial position of NSTAR and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(2) on page 76, 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 NSTAR's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
/s/ PRICEWATERHOUSECOOPERS LLP
Boston, Massachusetts January 31, 2002, except as to Note D(2), which is as of March 22, 2002
Item 9.
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.
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 2002 Proxy Statement dated March 22, 2002. Pages 3-5
(b) Identification of Officers
Information required by this item is included in Item 4A.
Item 11.
Item 11. Executive Compensation
Information required by this item is incorporated herein by reference to the 2002 Proxy Statement dated March 22, 2002. Pages 9-16
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this item is incorporated herein by reference to the 2002 Proxy Statement dated March 22, 2002. Pages 1, 6 and 7
Item 13.
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by reference to the 2002 Proxy Statement dated March 22, 2002. Page
Part IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K:
None