Item 1. Business
(a) General Development of Business
Boston Edison Company (“Boston Edison” or “the Company”) is a regulated public utility incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy). NSTAR’s retail distribution utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). NSTAR’s three retail electric distribution companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean each of Boston Edison, ComElectric and Cambridge Electric together. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas).
Harbor Electric Energy Company (HEEC), a wholly owned subsidiary of Boston Edison, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority’s wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison’s other wholly owned consolidated special-purpose subsidiary, BEC Funding LLC (BEC Funding), was established to facilitate the sale, on July 29, 1999, of $725 million of electric rate reduction certificates at a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison’s retail customers as permitted by the 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison.
(b) Financial Information about Industry Segments
Boston Edison operates as a regulated electric public utility; therefore industry segment information is not applicable.
(c) Narrative Description of Business
Principal Products and Services
Boston Edison currently supplies electricity at retail to an area of 590 square miles. The territory served includes the City of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.6 million. Boston Edison also supplies electricity at wholesale for resale to municipal electric departments. Electric operating revenues and energy sales percentages by customer class for the last three years consisted of the following:
Retail Electric Rates
Retail electric delivery rates are established by the Massachusetts Department of Telecommunications and Energy (MDTE) and are composed of:
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distribution charges, which include a fixed customer charge and energy and demand charges (to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating and maintenance costs),
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a transition charge (to collect costs primarily for previously held investments in generating plants and costs related to above market power contracts),
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a transmission charge (to collect the cost of moving the electricity over high voltage lines from generating plants to substations located within Boston Edison’s service area),
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an energy conservation charge (an MDTE - mandated charge to collect costs for demand-side management programs) and
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a renewable energy charge (an MDTE - mandated charge to collect the cost to support the development and promotion of renewable energy projects).
Beginning in 2004, rates applicable to distribution were increased to reflect the implementation of a rate mechanism to collect pension and postretirement benefit obligations other than pension (PBOP) costs on a fully reconciling basis. Refer to the accompanying Consolidated Financial Statements, Note H, for more detail.
Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore, effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be provided default service, which will be designated basic service thereafter. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2004, 2003 and 2002, customers of Boston Edison had approximately 25%, 27% and 28%, respectively, of their load requirements provided by competitive suppliers.
Sources and Availability of Electric Power Supply
For default service power supply, Boston Edison expects to continue to make periodic market solicitations consistent with provisions of the Restructuring Act and MDTE orders. During 2004, Boston Edison entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to its largest customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than to these large customers, for the second-half of 2005. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2005. A Request for Proposals will be issued quarterly in 2005 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE requirements. For 2004, Boston Edison entered into agreements ranging in length from three to twelve-months effective January 1, 2004 through December 31, 2004 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE.
For standard offer service power supply, Boston Edison has contracted with third party suppliers to provide 100% of its obligation through February 28, 2005, the date when standard offer service ends and all load migrates to either default service or competitive supply. Boston Edison is fully recovering its payments to suppliers through MDTE-approved rates billed to customers. Boston Edison, during 2004, entered into several agreements to buy-out/restructure certain of its long-term power purchase contracts. Refer to the Consolidated Financial Statements, Note L, for more detail.
Boston Edison’s load for 2004 reached a peak demand of 3,062 megawatts (MW) on August 30, which was 7.5% less than the all-time peak demand level of 3,311 MW established in 2001.
Wholesale Market Rule Changes
Standard Market Design (SMD)
Pursuant to orders issued by the Federal Energy Regulatory Commission (FERC), wholesale electric markets in New England have been operating under SMD since March 1, 2003. Under SMD, generators are dispatched on a least cost basis until the generation dispatched equals the amount of energy required. The clearing price is set at the price of the next available megawatt of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when transmission constraints prevent the lower cost generation from moving from one load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). Boston Edison’s service territory covers two of the eight load zones in New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is import-constrained and SEMA is export-constrained. The majority of Boston Edison’s customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher LMP than SEMA. As part of SMD, load-serving entities, like Boston Edison, were granted proceeds from the auction of “financial transmission rights” that is conducted by Independent System Operator - New England (ISO-NE). Boston Edison uses these proceeds to mitigate costs to customers.
Locational Installed Capacity (LICAP)
The ISO-NE has proposed a new market rule designed to compensate wholesale generators for their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like Boston Edison, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in New England, to count towards a LSE’s obligation, regardless of load zone. At this point, it appears likely that Boston Edison’s new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to converge, which could ultimately render this locational aspect of LICAP a non-factor for Boston Edison customers. (Refer to “Capital Expenditures and Financings” section for more information on Boston Edison’s 345kV transmission project). However, since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of power to Boston Edison’s customers. The proposed LICAP market rules are contentious and are currently being litigated at FERC and in the courts. A final FERC ruling on the issue is expected in 2005 and the current schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, Boston Edison cannot predict the actual impact these changes will have on Boston Edison and its customers.
Regional Transmission Organization (RTO)
On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including Boston Edison. The filing requested an increase in the base ROE component of the regional and local transmission rates, to be provided under the Regional Transmission Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New England is
provided under a two-tier structure, with the potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50 basis points in regional rates as an incentive for joining an RTO for regional service. In addition, FERC has also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. The Transmission Owners maintain that sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law judge and were unsuccessful. Hearings on the base ROE and 100 basis point adder began in January 2005.
The joint ROE filing among the Transmission Owners was made in connection with the proposed formation of RTO-NE by the Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including Boston Edison, which resolved many issues left outstanding from FERC’s March 2004 Order conditionally approving the formation of RTO-NE. The November 3rd Order also provided clarification of certain aspects of the March 2004 Order regarding the Transmission Owners’ request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and the Transmission Owners’ proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission. Finally, the November 3rd Order required the satisfaction of several ministerial conditions before ISO-NE could begin to operate as an RTO. ISO-NE and the Transmission Owners have since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the ISO-NE is an independent entity, without a financial interest in the region’s marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as Boston Edison and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE’s interactions with market participants and merchant transmission facilities. Management cannot estimate the impact of the RTO on the Company.
Franchises
Through its charter, which is unlimited in time, Boston Edison has the right to engage in the business of delivering and selling electricity, and has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines are obtained from municipal and other state authorities who, 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. Under Massachusetts law, no other entity may provide electric delivery service to retail customers within Boston Edison’s territory without the written consent of Boston Edison. This consent must be filed with the MDTE and the municipality so affected.
Regulation
Boston Edison and its wholly owned subsidiaries, HEEC and BEC Funding LLC, operate primarily under the authority of the MDTE, whose jurisdiction includes supervision over retail rates for distribution of electricity, financing and investing activities. In addition, the FERC has jurisdiction over various phases of Boston Edison’s electric utility business, including rates for electricity sold at wholesale, facilities used for the transmission or sale of that energy, certain issuances of short-term debt and regulation of accounting.
Capital Expenditures and Financings
The most recent estimates of capital expenditures and long-term debt maturities for the years 2005 through 2009 are as follows:
Capital expenditures include costs related to Boston Edison’s 345kV transmission project that in the aggregate is expected to total approximately $200 million. A significant portion of these costs will be incurred in 2005 and 2006. Boston Edison has obtained regulatory approval to construct a 345 kV transmission line from Stoughton, Massachusetts, a southern suburb of Boston, to South Boston in order to assure continued reliability of service and improve power import capacity in the Northeast Massachusetts area (NEMA). Construction is set to begin in the first quarter of 2005, subject to final permitting. The entire new transmission line is anticipated to be placed in service during the summer of 2006. This project is a regional transmission investment and, as a result, the cost will be shared by all of New England and recovered by Boston Edison through wholesale and retail transmission rates.
Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, operating requirements, environmental standards, availability and cost of capital, interest rates and other assumptions. Refer to the “Cautionary Statement” section of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Plant expenditures in 2004 were approximately $200 million and consisted primarily of additions to Boston Edison’s distribution and transmission systems. The majority of these expenditures were for system reliability and performance improvements, customer service enhancements and capacity expansion to meet long-range growth in the Boston Edison service territory.
Seasonal Nature of Business
Boston Edison kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions.
Competitive Conditions
The electric industry, in general, has continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These pressures have resulted in an increasing trend in the industry to seek efficiencies and other benefits through business combinations. NSTAR operates in this marketplace by combining the resources of its utility subsidiaries activities in the transmission and distribution of energy.
Environmental Matters
Boston Edison is subject to numerous federal, state and local standards with respect to the management of wastes, 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 of Financial Condition and Results of Operations” for more information.
Management believes that its facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements.
Number of Employees
Boston Edison does not have any employees. All labor services are provided by employees of NSTAR Electric & Gas. As of December 31, 2004, NSTAR Electric & Gas had approximately 3,000 employees, including approximately 2,200, or 73%, who are represented by two units covered by separate collective bargaining contracts. NSTAR’s contract with Local 369 of the Utility Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for a new labor contract. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006.
Management believes it has satisfactory relations with its employees.
(d) Financial Information about Foreign and Domestic Operations and Export Sales
Boston Edison delivers electricity to retail and wholesale customers in the Boston area. Boston Edison does not have any foreign operations or export sales.
Item 2.
Item 2. Properties
Boston Edison properties include an integrated system of distribution lines and substations, an office building and other structures such as garages and service centers that are located primarily in eastern Massachusetts.
Boston Edison’s transmission lines are generally located on land either owned or subject to easements in its favor. Its distribution lines are located principally on public property under permission granted by municipal and other state authorities.
As of December 31, 2004, the primary and secondary overhead and underground distribution system cover approximately 10,900 and 6,000 circuit miles, respectively. In addition, Boston Edison’s transmission system consists of 127 substation facilities and approximately 892,500 active customer meters. HEEC, Boston Edison’s regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115 kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts. HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water Resources Authority, at this location.
Item 3.
Item 3. Legal Proceedings
In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, Boston Edison does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.
PART II
Item 5.
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The information required by this item is not applicable because all of the common stock of Boston Edison is held solely by NSTAR.
Market information for the common shares of NSTAR is included in Item 5 of NSTAR’s Annual Report on Form 10-K for the year ended December 31, 2004.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
Overview
Boston Edison Company (“Boston Edison” or “the Company”) is a regulated public utility incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy and Commonwealth Energy System. NSTAR’s retail distribution utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). NSTAR’s three retail electric distribution companies collectively operate as “NSTAR Electric.” NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas).
Harbor Electric Energy Company (HEEC), a wholly owned subsidiary of Boston Edison, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resource Authority’s wastewater treatment facility located on Deer Island in Boston, Massachusetts. Boston Edison’s other wholly owned consolidated special-purpose subsidiary, BEC Funding LLC (BEC Funding), was established to facilitate the sale, on July 29, 1999, of $725 million of electric rate reduction certificates at a public offering. The certificates are secured by a portion of the transition charge assessed on Boston Edison’s retail customers as permitted by the 1997 Massachusetts Electric Restructuring Act (Restructuring Act) and authorized by the Massachusetts Department of Telecommunications and Energy (MDTE). These certificates are non-recourse to Boston Edison.
Boston Edison generates its revenues primarily from the sale of energy, distribution and transmission services to customers. However, Boston Edison’s earnings are impacted by fluctuations in unit sales of kilowatt-hours, which directly determine the level of distribution and transmission revenues recognized. In accordance with the regulatory rate structure in which Boston Edison operates, its recovery of energy costs are fully reconciled with the level of energy revenues currently recorded and, therefore, do not have an impact on earnings. As a result of this rate structure, any variability in the cost of energy supply purchased will impact purchased power expense and corresponding revenues but will not affect the Company’s earnings.
Cautionary Statement
The MD&A, as well as other portions of this report, contain statements that are considered forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements may also be contained in other filings with the Securities and Exchange Commission (SEC), in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,”
“intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward-looking statements may not turn out to be what Boston Edison expected. Actual results could 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.
Examples of some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to, the following:
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impact of continued cost control procedures on operating results
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weather conditions that directly influence the demand for electricity
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changes in tax laws, regulations and rates
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financial market conditions including, but not limited to, changes in interest rates and the availability and cost of capital
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prices and availability of operating supplies
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prevailing governmental policies and regulatory actions (including those of the MDTE and Federal Energy Regulatory Commission (FERC) with respect to allowed rates of return, rate structure, continued recovery of regulatory assets, financings, purchased power, acquisition and disposition of assets, operation and construction of facilities, changes in tax laws and policies and changes in, and compliance with, environmental and safety laws and policies
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changes in financial accounting and reporting standards
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new governmental regulations or changes to existing regulations that impose additional operating requirements or liabilities
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changes in specific hazardous waste site conditions and the specific cleanup technology
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impact of uninsured losses
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changes in available information and circumstances regarding legal issues and the resulting impact on our estimated litigation costs
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future economic conditions in the regional and national markets
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ability to maintain current credit ratings, and
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the impact of terrorist acts
Any forward-looking statement speaks only as of the date of this filing and Boston Edison undertakes no obligation to publicly update forward-looking statements, whether as a result of new information, future events, or otherwise. You are advised, however, to consult all further disclosures Boston Edison makes in its filings to the SEC. Other factors in addition to those listed here could also adversely affect Boston Edison. This report also describes material contingencies and critical accounting policies and estimates in this section and in the accompanying Notes to Consolidated Financial Statements, and Boston Edison encourages a review of these Notes.
Critical Accounting Policies and Estimates
Boston Edison’s discussion and analysis of its financial condition, results of operations and cash flows are based upon the accompanying Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these Consolidated Financial Statements required management to make estimates and judgements that affect the
reported amount of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Actual results may differ from these estimates under different assumptions or conditions.
Critical accounting policies and estimates are defined as those that require significant judgment and uncertainties, and potentially may result in materially different outcomes under different assumptions and conditions. Boston Edison believes that its accounting policies and estimates that are most critical to the reported results of operations, cash flows and financial position are described below.
a. Revenue Recognition
Utility revenues are based on authorized rates approved by the MDTE and FERC. Revenues related to the sale, transmission and distribution of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters that are read on a systematic basis throughout the month. Meters that are not read during a given month are estimated and trued-up in a future period. At the end of each month, amounts of energy delivered to customers since the date of the last billing date are estimated and the corresponding unbilled revenue is estimated. This unbilled electric revenue is estimated each month based on daily generation volumes (territory load), estimated line losses and applicable customer rates. Accrued unbilled revenues recorded in the accompanying Consolidated Balance Sheets as of December 31, 2004 and 2003 were $28.4 million and $21.9 million, respectively.
The level of unbilled revenue is subject to seasonal weather conditions. Electric sales volumes are typically higher in the winter and summer than in the spring or fall. As a result, Boston Edison records a higher level of unbilled revenue during the seasonal periods mentioned above.
b. Regulatory Accounting
Boston Edison follows accounting policies prescribed by GAAP, the FERC and the MDTE. As a rate-regulated company, Boston Edison is subject to the Financial Accounting Standards Board, Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain revenues and expenses from those of other businesses and industries. Boston Edison’s energy delivery business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. This ratemaking process results in the recording of regulatory assets based on the probability of current and future cash inflows. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers. As of December 31, 2004 and 2003, Boston Edison has recorded regulatory assets of $1.4 billion and $1.1 billion, respectively. Boston Edison continuously reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Boston Edison expects to fully recover these regulatory assets in its rates. If future recovery of costs ceases to be probable, Boston Edison would be required to charge these assets to current earnings. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.
c. Derivative Instruments - Power Contracts
The electric distribution industry may contract to buy and sell electricity under option contracts, which allow the distribution company the flexibility to determine when and in what quantity to take electricity in order to align with its demand for electricity. These contracts would normally meet the definition of a derivative instrument requiring mark-to-market accounting. However, because electricity cannot be stored and utilities are obligated to maintain sufficient capacity to meet the electricity needs of its customer base, an option contract for the purchase of electricity typically qualifies for the normal purchases and sales exception as described in SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities” and Derivative Implementation Group (DIG) interpretations and, therefore, does not require mark-to-market accounting.
Boston Edison has long-term purchase power agreements that are used primarily to meet its standard offer obligation. The majority of these agreements are not reflected as an asset or liability on the accompanying Consolidated Balance Sheets as they qualify for the normal purchases and sales exception. However, based on DIG interpretations, Boston Edison, as of December 31, 2004 and 2003, recorded one purchase power contract at fair value on its Consolidated Balance Sheets. As a result, the recognition of a liability for the fair value of the above-market portion of this contract at December 31, 2004 and 2003 is approximately $235 million and $271 million, respectively, and is reflected as a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets.
During the first quarter of 2005, Boston Edison expects to close on a securitization financing that will affect this one contract that is classified as a derivative instrument. Boston Edison has entered into a buy-out agreement for this contract and expects to finance the buy-out payments through a securitization financing. When this occurs, the fair value of this contract will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an offsetting regulatory asset.
At December 31, 2004, this contract was valued using a discounted cash flow model and a discount rate of 7.5%. The market value assumption used was provided by a third party who determines such pricing for the New England power market. Had management used an alternative assumption, the value of this contract at December 31, 2004 and 2003 would have changed significantly. A one percent increase or decrease to the discount rate would change the above market value by approximately $10 million from what is presently recorded at December 31, 2004.
Boston Edison recovers all of its electricity supply costs, including the above-market costs from customers. For this one purchase power agreement, the recovery of its above-market costs occurs through 2013. This recovery period coincides with the contractual terms of this purchase power agreement. Therefore, in addition to the liability recorded, Boston Edison also recorded a corresponding regulatory asset representing the future recovery of this actual cost. As a result, any changes to the fair value of this contract will not have an effect on Boston Edison’s earnings.
d. Pension and Other Postretirement Benefits
Boston Edison is the sponsor of NSTAR’s qualified Pension Plan (the Plan). As its sponsor, Boston Edison allocates the costs of the Plan to NSTAR Electric & Gas. NSTAR Electric & Gas charges all of its benefit costs to the NSTAR operating companies, including Boston Edison, on a percentage of total direct labor charged to the Company.
Boston Edison’s annual pension and other postretirement benefits costs are dependent upon several factors and assumptions, such as employee demographics, plan design, the level of cash contributions made to the plans, expected and actual earnings on the plans’ assets, the discount rate, the expected long-term rate of return on the plans’ assets and health care cost trends.
In accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS 106), changes in pension and postretirement benefit obligations other than pensions (PBOP) associated with these factors are not immediately recognized as pension and PBOP costs in the statements of income, but generally are recognized in future years over the remaining average service period of the plans’ participants.
There were no significant changes to pension benefits in 2004, 2003 and 2002 that had a significant impact on recorded pension costs. As further described in Note G to the accompanying Consolidated Financial Statements,
management revised the discount rate at December 31, 2004 to 5.75% from 6.25% at December 31, 2003 to reflect market conditions and the characteristics of the pension obligation. The expected long-term rate of return on its pension plan assets for 2004 remained at 8.4% (net of plan expenses), the same as 2003. These assumptions will have a significant impact on reported pension costs in future years in accordance with the cost recognition approach of SFAS 87 described above. This impact, however, will be mitigated through Boston Edison’s regulatory accounting treatment of pension and PBOP costs. (See further discussion of regulatory accounting treatment below.) In determining pension obligation and cost amounts, these assumptions may change from period to period, and such changes could result in material changes to recorded pension and PBOP costs and funding requirements.
The Plan’s assets, which partially consist of equity investments, were affected by significant declines in the financial markets from 2000 through 2002 and improvements in the financial markets for both 2003 and 2004. Fluctuations in market returns impacted the funded status of the Plan at both December 31, 2004 and 2003, and will affect pension costs in future periods.
The following chart reflects the projected benefit obligation and cost sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption.
The discount rate is based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the plan and through periodic bond portfolio matching. Both of these factors contribute to management’s decision for selecting the discount rate.
In determining the expected long-term rate of return on plan assets, management considers past performance and economic forecasts for the types of investments held by the Plan as well as the target allocation for the investments over a 20-year time period. In 2004, management kept the expected long-term rate of return on plan assets at 8.4% as a result of the prevailing outlook for equity market returns. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for both 2004 and 2003.
At December 31, 2003, the Plan’s accumulated benefit obligation (ABO) exceeded Plan assets. The ABO represents the present value of benefits earned without considering future salary increases. Since the fair value of its Plan assets was less than the ABO, Boston Edison was required to record this difference as an additional minimum pension liability on the accompanying Consolidated Balance Sheets as of December 31, 2003.
In 2004, due to positive Plan investment performance and Company contributions over the last two years of $120 million, the fair value of the Plan’s assets exceeded the Plan’s ABO at December 31, 2004. As a result, the minimum liability has been reversed and the prepaid pension amount has been restored to the accompanying Consolidated Balance Sheet.
On October 31, 2003, the MDTE approved Boston Edison’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, Boston Edison is allowed to record a regulatory asset in lieu of taking a charge to OCI for the required additional minimum liability adjustment. As of December 31, 2003, Boston Edison recorded a regulatory asset of $172.9 million. At December 31, 2004, the regulatory asset was reversed and the prepaid pension asset of $298 million was reinstated in the accompanying Consolidated Balance Sheets.
The Plan currently meets the minimum funding requirements of the Employee Retirement Income Security Act of 1974. While not required to make contributions to the Plan, Boston Edison anticipates that it will contribute approximately $35 million to the Plan in 2005. Boston Edison believes it has adequate access to capital resources to support these contributions.
e. Decommissioning Cost Estimates
The accounting for decommissioning costs of nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Changes in these estimates will not affect Boston Edison’s results of operations or cash flows because these costs will be collected from customers through Boston Edison’s transition charge filings with the MDTE.
While Boston Edison no longer directly owns any operating nuclear power plants, Boston Edison owns, through its equity investments, 9.5% of Connecticut Yankee Atomic Power Company (CYAPC) and 9.5% of Yankee Atomic Electric Company (YAEC), (collectively the “Yankee Companies”). Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.
Based on estimates from the Yankee Companies’ management as of December 31, 2004, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $630.0 million for CY and $119.3 million for YA. Of these amounts, Boston Edison is obligated to pay $59.8 million towards the decommissioning of CY and $11.3 million toward YA. These amounts are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current results of operations and cash flows. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs.
The Yankee Companies have received approval from FERC for recovery of these costs and Boston Edison expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including Boston Edison. Boston Edison would recover its share of any allowed increases from customers through the transition charge.
CY’s estimated decommissioning costs increased significantly in 2003 and the increase reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). In July 2004, CY filed with FERC for recovery of these increased costs. In August 2004, FERC issued an order accepting the new rates, beginning in February 2005, subject to refund.
CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY’s real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the sponsors’ periodic payments, up to a total of $41.7 million, all of which the sponsors, which include Boston Edison, are scheduled to pay to CY through June 30, 2007. This
stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the ability of Bechtel to attach these assets. Discovery is underway and a trial has been scheduled for May 2006. Boston Edison cannot predict the timing or outcome of the litigation with Bechtel but does not expect a material impact on Boston Edison’s financial position, results of operations or cash flows.
Asset Retirement Obligations
On January 1, 2003, Boston Edison adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations under lease arrangements. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.
Boston Edison has identified certain immaterial long-lived assets, including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.
Boston Edison has also identified legal retirement obligations that are currently not material to its financial statements. The recognition of a potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, Boston Edison would establish regulatory assets or liabilities to defer any differences between the liabilities established for ratemaking purposes and those recorded as required under SFAS 143.
For Boston Edison, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $155.5 million and $123.2 million, respectively, based on the cost of removal component in current depreciation rates.
During 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”. The interpretation clarifies when an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability rather than the recognition of the liability. The interpretation would be effective for Boston Edison no later than the end of fiscal year 2005. Boston Edison is currently assessing the impact that the interpretation will have on its consolidated financial position, results of operations and cash flows.
Variable Interest Entities
In 2004, the FASB issued an exposure draft, “Consolidation of Variable Interest Entities”, as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.
Boston Edison has a wholly owned special purpose subsidiary, BEC Funding LLC, established to undertake the sale of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Boston Edison consolidates this entity. As part of Boston Edison’s assessment of FIN 46R and, for compliance at December 31, 2003, Boston Edison reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, Boston Edison has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by Boston Edison.
For the March 31, 2004 effective date of FIN 46R, Boston Edison evaluated, among other entities, the companies that supply power to Boston Edison through its purchase power agreements. Boston Edison determined that it is possible that two of these companies may be considered VIEs. These companies have power plants that have daily capacity output ranging from 230 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, Boston Edison purchased a total of approximately 2,364 megawatt-hours (MWH) and 2,730 MWH, respectively, under these agreements. These purchases approximate 14% and 15% of the total MWH purchased by Boston Edison for the years ended December 31, 2004 and 2003, respectively, and amounted to approximately $200 million and $209 million, respectively. In order to determine if these counterparties are VIEs and if Boston Edison is the primary beneficiary of these counterparties, Boston Edison concluded that it needed more information from the entities. Boston Edison attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since Boston Edison was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which Boston Edison has a purchase power agreement.
Additionally, during 2004, Boston Edison executed purchase power buy-out/restructuring agreements with both of the entities from which Boston Edison attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructuring agreements received regulatory approval in January 2005. Refer to Consolidated Financial Statements, Note L, for more detail on the purchase power buy-out/restructuring agreements. As a result, Boston Edison will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.
New Accounting Standards
No new accounting standards are applicable to the Company.
Rate and Regulatory Proceedings
a. Service Quality Indicators
Service quality indicators are established performance benchmarks for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. Boston Edison is required to report annually to the MDTE concerning its performance as to each measure and is subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks.
On March 1, 2004, Boston Edison filed its 2003 Service Quality Report with the MDTE that demonstrated the Company’s achieved levels of reliability and performance; the report indicates that no penalty was assessable for 2003. The MDTE concurred with Boston Edison’s determination in an order issued in October 2004. Boston Edison monitors its service quality continuously to determine its contingent liability, and if it’s probable that a liability has been incurred and is estimable, a liability would be accrued. Annually, Boston Edison makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability. Recently, the MDTE voted to initiate an investigation into potentially modifying the service quality indicators for all Massachusetts utilities. Until any such order is issued,
the current service quality indicators will remain in place. Boston Edison currently cannot predict the outcome of this investigation or its impact.
As of December 31, 2004, Boston Edison’s 2004 performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2004.
b. Retail Electric Rates
Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through either standard offer or default service for those who choose not to buy energy from a competitive energy supplier. Standard offer service will end on February 28, 2005. Therefore, effective March 1, 2005, all customers who have not chosen to receive service from a competitive supplier will be provided default service. Default service rates are reset every six months (every three months for large commercial and industrial customers). The price of default service is intended to reflect the average competitive market price for power. As of December 31, 2004, 2003 and 2002, customers of Boston Edison had approximately 25%, 27% and 28%, respectively, of their load requirements provided by competitive suppliers.
On December 21, 2004, the FERC issued an order approving Boston Edison’s October 2004 request to modify its Open Access Transmission Tariff. Effective January 1, 2005, Boston Edison is allowed to include 50 percent of construction work in progress in its rate base for transmission projects by including this amount in its local network service transmission rate formula, rather than capitalizing Allowance for Funds Used During Construction (AFUDC) charges on the entire construction expense balance. The order is subject to Boston Edison filing annual reports of its long-term transmission plan.
In December 2004, Boston Edison filed proposed transition rate adjustments for 2005, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2004. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2005. The filings are to be updated in February 2005 to reflect final 2004 costs and revenues that are subject to final reconciliation.
Effective January 1, 2005, Boston Edison’s Standard Offer Service Fuel Adjustment (SOSFA) rate was modified to 1.564 cents per kilowatt-hour with the approval of the MDTE.
Effective October 1, 2004, Boston Edison’s SOSFA rate was modified to 1.223 cents per kilowatt-hour from zero upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service customers. The SOSFA was zero cents per kilowatt-hour from April 1, 2002 through April 30, 2003. The rate was increased to 0.902 cents per kilowatt-hour from May 1, 2003 through September 1, 2003. The rate was adjusted to zero until October 1, 2004 than increased to 1.223 cent per kilowatt-hour. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.
In December 2003, Boston Edison filed proposed transition rate adjustments for 2004, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2003. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2004. The filing was updated in February 2004 to include final costs and revenues for 2003.
On December 1, 2003, Boston Edison filed its annual reconciliation report on the Company’s pension and PBOP rate adjustment mechanism. Hearings were held during 2004. Boston Edison anticipates an order by the first quarter of 2005. Boston Edison cannot predict the overall timing and result of this order on its financial position or results of operation.
c. Wholesale Market Rule Changes
Standard Market Design (SMD)
Pursuant to orders issued by the FERC, wholesale electric markets in New England have been operating under SMD since March 1, 2003. Under SMD, generators are dispatched on a least cost basis until the generation dispatched equals the amount of energy required. The clearing price is set at the price of the next available megawatt of generation and is paid to all dispatched generators. SMD provides an additional market in which wholesale power costs can be hedged a day in advance through binding financial commitments. Also, under SMD, wholesale power clearing prices vary by location, called load zones, with prices in load zones with less efficient generation being higher than in load zones with more efficient generation during periods when transmission constraints prevent the lower cost generation from moving from one load zone to another. This mechanism is known as Locational Marginal Pricing (LMP). Boston Edison’s service territory covers two of the eight load zones in New England: Northeastern MA (NEMA) and Southeastern MA (SEMA). NEMA is import- constrained and SEMA is export-constrained. The majority of Boston Edison’s customers are in the NEMA load zone. During periods of transmission constraints, NEMA has a higher LMP than SEMA. As part of SMD, load-serving entities, like Boston Edison, were granted proceeds from the auction of “financial transmission rights” that is conducted by ISO-NE. Boston Edison uses these proceeds to mitigate costs to customers.
Locational Installed Capacity (LICAP)
The ISO-NE has proposed a new market rule designed to compensate wholesale generators for their capacity, called LICAP. The proposed LICAP rules require electric load serving entities (LSE), like Boston Edison, to procure capacity within the zones where load is served. The current market structure allows capacity, located anywhere in New England, to count towards a LSE’s obligation, regardless of load zone. At this point, it appears likely that Boston Edison’s new 345kV transmission project will reduce transmission constraints causing capacity prices between NEMA and SEMA to converge, which could ultimately render this locational aspect of LICAP a non-factor for Boston Edison customers. However, since proposed market rules require that a certain amount of capacity be procured in the NEMA zone and, depending on how many market rules are finally adopted, these requirements could impact pricing for capacity in the NEMA zone. Additionally, much of the capacity in the NEMA zone has issued notice of its intent to file with the FERC for cost of service type agreements called Reliability Must Run agreements for the recovery of their costs prior to the implementation of LICAP. The proposed LICAP rules will impact overall capacity pricing levels in New England. Since the New England market as a whole is currently in a surplus position, capacity trades at a relatively low price. One of the goals of LICAP is to provide a higher level of compensation to generators than what is currently being earned in this surplus market. This will likely increase the price of power to Boston Edison’s customers. The proposed LICAP market rules are contentious and are currently being litigated at FERC and in the courts. A final FERC ruling on the issue is expected in 2005 and the current schedule calls for an implementation date of January 1, 2006. Until these rules are finalized and approved, Boston Edison cannot predict the actual impact these changes will have on Boston Edison and its customers.
Regional Transmission Organization (RTO)
On March 24, 2004, the FERC decided to schedule hearings for a joint return on equity (ROE) filing made by participating New England Transmission Owners, including Boston Edison. The filing requested an increase in the base ROE component of the regional and local transmission rates, to be provided under the Regional Transmission Organization for New England (RTO-NE) open access transmission tariff (OATT), to a single ROE of 12.8% for all regional and local transmission rates. Presently, transmission service in New England is provided under a two-tier structure, with the potential for the ROE for local service to be different than for regional service for the same transmission provider. FERC has previously approved other RTO filings for an ROE adder of 50 basis points in regional rates as an incentive for joining an RTO for regional service. In addition, FERC has also scheduled hearings to address the proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission facilities. The Transmission Owners maintain that
sufficient equity returns are needed to elicit the necessary investments in transmission within an RTO. Settlement negotiations occurred in April 2004 before a FERC administrative law judge and were unsuccessful. Hearings on the base ROE and 100 basis point adder began in January 2005.
The joint ROE filing among the Transmission Owners was made in connection with the proposed formation of RTO-NE by the Transmission Owners and ISO-NE, the present administrator of the New England Power Pool (NEPOOL) OATT, and is an important and integral component of the agreement to form an RTO for the New England region. On November 3, 2004, the FERC accepted a settlement agreement among NEPOOL, ISO-NE and the New England Transmission Owners, including Boston Edison, which resolved many issues left outstanding from FERC’s March 2004 Order conditionally approving the formation of RTO-NE. The November 3rd Order also provided clarification of certain aspects of the March 2004 Order regarding the Transmission Owners’ request for an increase in the base return on equity component of the regional and local transmission rates. This clarification narrowed the scope of issues to be addressed during the January 2005 hearings on the base ROE proposal and the Transmission Owner’s proposal for an additional 100 basis points in regional rates to provide an incentive to build new transmission. Finally, the November 3rd Order requires the satisfaction of several ministerial conditions before ISO-NE could begin to operate as an RTO. ISO-NE and the Transmission Owners have since satisfied such conditions and provided 30 days notice to FERC and NEPOOL that on February 1, 2005, ISO-NE would begin to operate as an RTO. Effective February 1, 2005, the ISO-NE is an independent entity, without a financial interest in the region’s marketplace, having operating authority over the New England transmission grid and the responsibility to make impartial decisions on the development and implementation of market rules. The ISO-NE operates under a series of contractual arrangements that define its functions and responsibilities, including a Transmission Operating Agreement, which governs the relationship between the owners of transmission facilities, such as Boston Edison, and the ISO-NE, as the operator of the New England transmission grid. Separate agreements govern the operation of the spot power and related markets, the ISO-NE’s interactions with market participants and merchant transmission facilities. Management cannot estimate the impact of the RTO on the Company.
Other Legal Matters
In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil litigation. Management is unable to fully determine a range of reasonably possible court-ordered damages, settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, Boston Edison does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.
Results of Operations
The following section of MD&A compares the results of operations for each of the two fiscal years ended December 31, 2004 and 2003 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included elsewhere in this report.
2004 compared to 2003
Earnings and operations overview
Net income was $134.1 million for 2004 compared to $130.9 million for 2003. Factors that contributed to the $3.2 million, or 2.4% increase in 2004 net income include higher electric distribution revenues due to higher rates, interest savings on the Company’s outstanding indebtedness and a reduction in operations and maintenance expense. In addition, 2004 results reflect the first full year of the Company’s pension and other postretirement benefit obligations other than pension (PBOP) rate mechanism. This mechanism was implemented in
September 2003 and at that time, the Company expensed $10.4 million of pension and PBOP costs, which were deferred during the first eight months of 2003. See “Critical Accounting Policies and Estimates,” Pension and Other Postretirement Benefits, in this MD&A for more information on the MDTE order. These increases in net income were partially offset by lower transmission revenues and higher depreciation and property tax expense.
Energy sales and weather
The following is a summary of retail electric energy sales for the years indicated:
In terms of customer sector characteristics, industrial sales are less sensitive to weather while residential and commercial sales are influenced by temperature extremes. Despite the overall milder weather in 2004, the increase in electric sales is attributable in part to the commercial sector where building expansion created the resulting additional energy use. Electric residential and commercial customers represented approximately 28% and 61%, respectively, of Boston Edison’s total sales mix for 2004 and provided 35% and 57% of distribution revenues, respectively. Refer to the “Operating revenues” section below for a more detailed discussion. Industrial sales are primarily influenced by local economic conditions, and sales to these customers reflect a sluggish economic environment and decreased manufacturing production.
Unit sales of electricity in 2005 are expected to grow at a rate of 2% to 3%. However, Boston Edison forecasts its electric sales based on normal weather conditions. Actual results may differ from those projected due to actual weather conditions above or below these normal weather levels and other factors. Refer to “Cautionary Statement” in this section.
Weather conditions impact electric sales in Boston Edison’s service area. The first quarter of 2004 was warmer than the same period in 2003, followed by continued warmer temperatures for the second quarter. The cooler than prior year third quarter resulted in reduced air conditioning demand that preceded a slightly colder fourth quarter of 2004. The comparative information above relates to heating and cooling degree-days for 2004 and 2003 and the number of degree-days in a “normal” year as represented by a 30-year average. A “degree-day” is a unit measuring how much the outdoor mean temperature falls below (heating degree-day) or rises above (cooling degree-day) a base of 65 degrees. Each degree below or above the base temperature is measured as one degree-day.
Operating revenues
Operating revenues for 2004 increased $6.6 million, or 0.4%, compared to 2003, and consisted of the following major components:
Electric retail distribution revenues primarily represent charges to customers for the Company’s recovery of its capital investment, including a return component, and operation and maintenance related to its electric distribution infrastructure. The transmission revenue component represents charges to customers for the recovery of costs to move the electricity over high voltage lines from the generator to the Company’s substations. Despite a 1.6% increase in retail MWH sales, substantially all in the residential and commercial sectors, the decrease in retail distribution and transmission revenue is primarily due to a decrease in the transmission rate.
Boston Edison’s largest earnings sources are the revenues derived from distribution rates approved by the MDTE. The level of distribution revenues is affected by weather conditions and the economy. Weather conditions affect sales to Boston Edison’s residential and small commercial customers. Economic conditions affect Boston Edison’s large commercial and industrial customers.
Energy, transition and other revenues primarily represent charges to customers for the recovery of costs incurred by the Company in order to acquire energy supply on behalf of its customers and a transition charge for recovery of the Company’s prior investments in generating plants and the costs related to long-term power contracts. The energy revenues relate to customers being provided energy supply under either standard offer or default service. The retail revenues related to standard offer and default services are fully reconciled to the costs incurred and have no impact on Boston Edison’s consolidated net income. Furthermore, energy and transition revenues are fully reconciled with the cost currently recognized by the Company and, as a result, do not have an effect on the Company’s earnings. The $18.1 million increase in energy, transition and other revenues is primarily attributable to higher rates for default service.
Wholesale revenues relate to services provided to municipalities and certain other governmental authorities. The decrease in 2004 wholesale revenues reflects the expiration of a wholesale power supply contract in 2003 and another contract in 2004. After October 2005, Boston Edison anticipates it will no longer have contracts for the supply of wholesale power. Amounts collected from wholesale customers are credited to retail customers through the transition charge. Therefore, the expiration of these contracts will have no impact on results of operations.
Other revenues were $90.6 million in 2004 compared to $84.9 million in 2003, an increase of $5.7 million, or 6.7%. Other revenues primarily relate to the increase in rental revenues from electric property.
Operating expenses
Purchased power costs were $882.8 million in 2004 compared to $874.4 million in 2003, an increase of $8.4 million, or 1.0%. The increase is primarily due to the higher cost of fuel, partially offset by the recognition of $45.6 million relating to the additional deferral of standard offer and default service supply costs. Boston Edison 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.
Operations and maintenance expense was $221.4 million in 2004 compared to $224.9 million in 2003, a decrease of $3.5 million, or 1.6%. This decrease primarily reflects the first full year of the Company’s pension and PBOP rate mechanism. The mechanism was implemented in September 2003 and, at that time, the Company expensed approximately $10.4 million of pension and PBOP costs, which were deferred during the first eight months of 2003. Also, expenses in 2004 reflect lower labor and labor-related costs.
Depreciation and amortization expense was $176.0 million in 2004 compared to $170.9 million in 2003, an increase of $5.1 million, or 3.0%. The increase primarily reflects higher depreciable distribution and transmission plant in service, an increase in the transmission depreciation rate and increased amortization related to software and merger costs to achieve amortization.
Demand side management (DSM) and renewable energy programs expense was $45.2 million in 2004 compared to $45.5 million in 2003. The levels of these expenses are consistent with the collection of conservation and renewable energy revenues. These costs are collected from customers on a fully reconciling basis plus a small incentive return.
Property and other taxes were $76.8 million in 2004 compared to $72.2 million in 2003, an increase of $4.6 million, or 6.4%. This increase was due to higher overall municipal property taxes of $4.3 million caused primarily by higher assessments. Higher property taxes are primarily due to increased plant investment and increased rates associated with legislation passed in Massachusetts allowing for the temporary shift of property tax burdens from residential to commercial property owners, in particular, in the City of Boston.
Income taxes attributable to operations were $88.5 million in 2004 compared to $90.0 million in 2003, a decrease of $1.5 million, or 1.7%, due to a lower effective tax rate in 2004 due to permanent tax benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). This tax benefit will not impact Boston Edison’s results of operations as these tax benefits are incorporated into the Company’s pension and PBOP rate adjustment mechanism.
Interest charges
Interest on long-term debt and transition property securitization certificates was $78.3 million in 2004 compared to $85.4 million in 2003, a decrease of $7.1 million, or 8.3%. The decrease in interest expense primarily reflects the absence of $2.1 million of interest expense in 2004 resulting from the retirement of Boston Edison’s $150 million 6.80% Debentures in March 2003, the retirement of Boston Edison’s $181 million 7.8% Debentures on March 15, 2004 that lowered expense by $11.2 million and the lower principal balance of transition property securitization certificates outstanding that resulted in reduced interest expense of $4.6 million. Securitization interest represents interest on debt of BEC Funding collateralized by the future income stream associated primarily with the stranded costs of the Pilgrim Unit divestiture. These certificates are non-recourse to Boston Edison. Partially offsetting these interest declines was additional interest expense of $10.3 million related to the $300 million, 4.875% Debenture, issued on April 16, 2004.
Short-term and other interest expense was $5.6 million in 2004 compared to $7.8 million in 2003, a decrease of $2.2 million, or 28.2%. The decrease in short-term and other interest expense relates to a reduction in bank service fees and other charges ($0.2 million) primarily resulting from a reduction in Boston Edison’s revolving credit, and a decrease in regulatory interest of $1.4 million due to lower deferral balances. In addition, the decrease in short-term and other expenses includes a lower average level of debt outstanding and lower borrowing rates of $90.1 million and 1.15%, as compared to $150.7 million and 1.18% for 2004 and 2003, respectively. Taken together, these factors decreased short-term borrowing costs by $598,000.
Allowance for funds used during construction was $0.6 million in 2004 compared to $1.2 million in 2003, a decrease of $0.6 million or 50%, primarily due to a lower average balance of construction work in progress during the year.
Other Events
Purchase Power Buy-out/Restructuring Agreements
In 2003, Boston Edison initiated a process to auction off certain purchase power agreements under which the Company had entitlements to approximately 780 megawatts (MW) of capacity under long-term contracts with non-utility generators. The auction was intended to further Boston Edison’s efforts to mitigate stranded costs, which continue to be recovered from customers. One contract in which Boston Edison had entitlements to approximately 265 MW of the 780 MW of capacity, originally included in the auction, expired on December 31, 2004. Also in 2004, Boston Edison executed agreements to buy-out or restructure five of its purchase power agreements. These buy-out/restructuring agreements provide no economic benefit to Boston Edison and, therefore, the agreements’ contract termination costs will be recorded on the accompanying Consolidated Financial Statements. These agreements constitute approximately 460 MW of the 780 MW of capacity, originally included in the auction and reduce the amount of Boston Edison’s future exposure to the above market costs that Boston Edison will collect from its customers through its transition charge. As of December 31, 2004, two of these agreements have received MDTE approval and have been recognized. These agreements require Boston Edison to make monthly payments through September 2011 totaling approximately $125 million.
On January 7, 2005, Boston Edison received approval from the MDTE for an additional two agreements that are anticipated to be completed by February 2005. These two agreements were binding as of December 31, 2004 but were contingent upon regulatory approval. Since the contingency was removed during February 2005, Boston Edison recorded the agreements’ contract termination costs as of December 31, 2004. One of the two agreements requires Boston Edison to make net monthly payments through September 2011 totaling approximately $416 million. The other agreement requires Boston Edison to make net monthly payments through September 2016 totaling approximately $215 million. Boston Edison anticipates making these cash payments from funds generated from operations and will be fully recovered through Boston Edison’s transition charge.
The total amount currently recognized for obligations relating to four of the five contracts is approximately $610.8 million (in present day dollars); approximately $104.9 million as a component of Current liability - power contract and $505.9 million as a component of Deferred credits - power contracts on the accompanying Consolidated Balance Sheets. Boston Edison has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.
Also in January 2005, the MDTE approved the remaining contract that reduced the overall amount of transition costs to be paid for the above-market contract. This contract is a buy-out arrangement whereby Boston Edison has committed to pay amounts for the full release of its obligation under a previous purchase power agreement. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that seeks approval for full recovery of these buy-out costs and the issuance of $674.5 million of transition property securitization bonds to provide the funds for this buy-out agreement. Boston Edison’s share of the transition property securitization bonds is $265.5 million. The MDTE approved the financing plan in January 2005. On February 15, 2005, these bonds were priced at a weighted average yield of 4.15%. Boston Edison expects the securitization financing to close in March 2005.
Borrowing Arrangements
As of September 28, 2004, Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. In addition, in November 2004,
Boston Edison restructured its $350 million revolving credit agreement that expired in November 2004 into a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first draw under the agreement. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreement. This credit facility serves as backup to Boston Edison’s $350 million commercial paper program that had a $46.5 million and $182.5 million balance at December 31, 2004 and 2003, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not greater than 60%. At December 31, 2004 and 2003, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.
Capital Spending
In the first quarter of 2005, Boston Edison expects to begin construction on a 345kV transmission line that would connect Stoughton, Massachusetts, a southern suburb of Boston, to South Boston. This transmission line is expected to assure continued reliability of electric service and improve power import capacity in the Northeast Massachusetts area. This project is expected to be placed in service during the summer of 2006. The cost of the project is expected to be shared by all of New England and will be recovered by Boston Edison through wholesale and retail transmission rates. As of December 31, 2004, Boston Edison has contractual commitments of approximately $6 million related to this project.
Performance Assurances from Electricity Agreements
Boston Edison has contracted with a third party supplier to provide 100% of its standard offer service supply obligations through February 28, 2005. In addition, Boston Edison has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation, other than large customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than large customers, for the second half of 2005. Boston Edison has entered into a number of short-term power purchase agreements to meet its entire default service supply obligation for large customers through March 2005. These agreements are for a term of three to twelve months. Boston Edison currently is recovering payments it is making to suppliers from its customers. Most of Boston Edison’s power suppliers are either investment grade companies or subsidiaries of larger companies with investment grade or better credit ratings. In accordance with Boston Edison’s Internal Credit Policy, and to minimize Boston Edison risk in the event the supplier encounters financial difficulties or otherwise fails to perform, Boston Edison has financial assurances and guarantees that include both Parental Guarantees and letters of credit in place with the parent company of the supplier. In addition, under these agreements, in the event that the supplier (or its parent guarantor) fails to maintain an investment grade credit rating, it is required to provide additional security for performance of its obligations. In view of current volatility in the energy supply industry, Boston Edison is unable to determine whether its suppliers (or their parent guarantors) will become subject to financial difficulties, or whether these financial assurances and guarantees are sufficient. In the event the supplier (or its guarantor) does not provide the required additional security within the required timeframes, Boston Edison may then terminate the agreement. In such event, Boston Edison may be required to secure alternative sources of supply at higher or lower prices than provided under the terminated agreements. Some of these agreements include a reciprocal provision, where in the event that Boston Edison receives a downgrade, the Company could be required to provide additional security for performance, such as a letter of credit.
Financial and Performance Guarantees
On a limited basis, Boston Edison may enter into agreements providing financial assurance to third parties. Such agreements include surety bonds and other guarantees.
At December 31, 2004, outstanding guarantees totaled $13.8 million as follows:
As of December 31, 2004, Boston Edison has purchased a total of $0.2 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, Boston Edison has purchased $6.4 million in workers’ compensation self-insurer bonds. These bonds support the guarantee by Boston Edison to the Commonwealth of Massachusetts required as part of the Company’s workers’ compensation self-insurance program.
Boston Edison has also issued $7.2 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.
Management believes the likelihood Boston Edison would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.
Contingencies
Environmental Matters
As of December 31, 2004, Boston Edison is involved in three state regulated properties (“Massachusetts Contingency Plan, or “MCP” sites”) where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.2 million are included for both December 31, 2004 and 2003 as liabilities in the accompanying Consolidated Balance Sheets.
In addition to the MCP sites, Boston Edison also faces possible liability as a result of involvement in ten multi-party disposal sites or third party claims associated with contamination remediation. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million are included for both December 31, 2004 and 2003 as liabilities in the accompanying Consolidated Balance Sheets.
The MCP and multi-party disposal site amounts have not been reduced by any potential rate recovery treatment of these costs or any potential recovery from Boston Edison’s insurance carriers. Prospectively, should Boston Edison be allowed to collect these specific costs from customers, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs.
Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs and as either additional sites are identified or Boston Edison’s responsibilities for such sites evolve or are resolved. Boston Edison’s ultimate liability for future environmental remediation costs may vary from these estimates. Based on Boston Edison’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, Boston Edison does not
believe that these environmental remediation costs will have a material adverse effect on Boston Edison’s consolidated financial position or results of operations for a reporting period.
Employees and Employee Relations
Boston Edison does not have any employees. All labor services are provided by employees of NSTAR Electric & Gas. As of December 31, 2004, NSTAR Electric & Gas had approximately 3,000 employees, including approximately 2,200, or 73%, who are represented by two units covered by separate collective bargaining contracts. NSTAR’s contract with Local 369 of the Utility Workers Union of America, AFL-CIO, which represents approximately 1,900 employees, expires on May 15, 2005. Management has begun discussions with union officials for a new labor contract. Approximately 250 employees, represented by Local 12004, United Steelworkers of America, AFL-CIO, have a contract that expires on March 31, 2006.
Management believes it has satisfactory relations with its employees.
Fair Value of Financial Instruments
Carrying amounts and fair values of long-term indebtedness (excluding notes payable, including current maturities) as of December 31, 2004 and 2003, were as follows:
As discussed in Item 7A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although Boston Edison has material commodity purchase contracts, these instruments are not subject to market risk. Boston Edison has rate-making mechanisms that allow for the recovery of energy supply costs from customers, who made commodity purchases from Boston Edison rather than from the competitive market. All energy supply costs incurred by Boston Edison to provide electricity for retail customers purchasing standard offer service (which expires on February 28, 2005) and default service customers are recovered on a fully reconciling basis.
In addition, Boston Edison’s exposure to financial market risk results primarily from fluctuations in interest rates. Boston Edison 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, including current maturities were 5.58% and 5.71% in 2004 and 2003, respectively.
On October 15, 2002, Boston Edison issued $100 million of 3-year floating rate debentures priced at LIBOR plus 50 basis points. An immediate change of one percent for these variable rate debentures would cause a change in interest expense of approximately $1 million per year.
Report of Independent Registered Public Accounting Firm
To Shareholder and Directors of Boston Edison Company:
In our opinion, the consolidated financial statements listed in the index appearing under 15(a)1 present fairly, in all material respects, the financial position of Boston Edison Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 15(a)2 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 Boston Edison’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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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
February 18, 2005
I tem 8. Financial Statements and Supplementary Data
Boston Edison Company
Consolidated Statements of Income
Per share data is not relevant because Boston Edison Company’s common stock is wholly owned by NSTAR.
The accompanying notes are an integral part of the consolidated financial statements.
Boston Edison Company
Consolidated Statements of Retained Earnings
The accompanying notes are an integral part of the consolidated financial statements.
Boston Edison Company
Consolidated Balance Sheets
The accompanying notes are an integral part of the consolidated financial statements.
Boston Edison Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of the consolidated financial statements.
Notes to Consolidated Financial Statements
Note A. Business Organization and Summary of Significant Accounting Policies
1. Nature of Operations
Boston Edison Company (“Boston Edison” or “the Company”) is a regulated public utility incorporated in 1886 under Massachusetts law and is a wholly owned subsidiary of NSTAR. Boston Edison serves approximately 700,000 electric distribution customers in the City of Boston and 39 surrounding communities. NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving approximately 1.4 million customers in Massachusetts, including approximately 1.1 million electric distribution customers in 81 communities and approximately 300,000 natural gas distribution customers in 51 communities. NSTAR was created in 1999 in connection with the merger of BEC Energy and Commonwealth energy System. NSTAR’s retail distribution utility subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR Gas). NSTAR’s three retail electric distribution companies collectively operate as “NSTAR Electric.” Reference in this report to “NSTAR” shall mean NSTAR or NSTAR and its subsidiaries as the context requires. Reference in this report to “NSTAR Electric” shall mean Boston Edison, ComElectric and Cambridge Electric together. NSTAR has a service company that provides management and support services to substantially all NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR Electric & Gas).
Boston Edison currently supplies electricity at retail to an area of 590 square miles. The population of the area served with electricity at retail is approximately 1.6 million. Boston Edison also supplies electricity at wholesale for resale to other utilities and municipal electric departments.
2. Basis of Consolidation and Accounting
The accompanying Consolidated Financial Statements reflect the results of operations, retained earnings, financial position and cash flows of Boston Edison and its subsidiaries, Harbor Electric Energy Company (HEEC) and BEC Funding LLC (BEC Funding). All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year amounts to conform to the current year’s presentation.
Boston Edison follows accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In addition, Boston Edison and its subsidiaries are subject to the accounting and reporting requirements of the Securities and Exchange Commission (SEC). The accompanying Consolidated Financial Statements conform to accounting principles generally accepted in the United States of America (GAAP). Boston Edison is subject to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). The application of SFAS 71 results in differences in the timing of recognition of certain expenses from those of other businesses and industries. The distribution and transmission businesses remain subject to rate-regulation and continue to meet the criteria for application of SFAS 71. Refer to Note C to these Consolidated Financial Statements for more information on regulatory assets.
The preparation of financial statements in conformity with GAAP requires management of Boston Edison 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 MDTE and FERC. Estimates of distribution and transition revenues for electricity delivered to customers but not yet billed are accrued at the end of each accounting period.
4. Utility Plant
Utility plant is stated at original cost. The cost 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, is charged to accumulated depreciation. The incurred related cost of removal is charged against the Regulatory liability - cost of removal.
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 composite rates are subject to the approval of the MDTE and FERC. The overall composite depreciation rates for utility property were 2.85%, 2.86% and 2.89% in 2004, 2003 and 2002, respectively. The rates include a cost of removal component, which is collected from customers.
6. Costs Associated with Issuance and Redemption of Debt and Preferred Stock
Consistent with the recovery in utility rates, discounts, redemption premiums and related costs associated with the issuance and redemption of long-term debt and preferred stock are deferred and amortized as an addition to interest expense over the life of the original or replacement debt. Costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.
7. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. Average AFUDC rates in 2004, 2003 and 2002 were 1.40%, 1.40% and 2.89%, respectively, and represented only the costs of short-term debt.
8. Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash are comprised of liquid securities with maturities of 90 days or less when purchased. Restricted cash primarily represents the funds held in reserve for a trust on behalf of Boston Edison’s wholly owned subsidiary, BEC Funding LLC. These funds are available to pay the principal and interest on the transition property securitization.
9. Equity Method of Accounting
Boston Edison uses the equity method of accounting for investments in corporate joint ventures in which it does not have a controlling interest. Under this method, it records as income or loss the proportionate share of the net earnings or losses of the joint ventures with a corresponding increase or decrease in the carrying value of the investment. The investment is reduced as cash dividends are received. Boston Edison participates in several corporate joint ventures in which it has investments, principally its 11.1% equity investment in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec System in Canada, and its equity investments of 9.5% in each of two regional nuclear facilities that are currently being decommissioned.
10. Related Party Transactions
The accompanying Consolidated Balance Sheets as of December 31, 2004 includes $150.6 million in Deferred credits - Payable to Affiliates. This amount is composed of payments received from affiliates as a result of the Company’s role as the sponsor of the NSTAR Pension Plan amounts received from affiliates related to Boston
Edison’s share of NSTAR’s postretirement benefits costs liability. In addition, Boston Edison’s goodwill amortization expense allocation payable to its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas was $42.5 million and $34.5 million for 2004 and 2003, respectively. These amounts were included in Deferred credits - other.
Additionally, the accompanying Consolidated Balance Sheets as of December 31, 2004 include an amount due from other NSTAR subsidiaries of approximately $39.4 million primarily related to their share of the prepaid pension asset offset by approximately $23.1 million due to NSTAR Electric & Gas for management and support services; a net receivable position of $16.3 million. As of December 31, 2003, the accompanying Consolidated Balance Sheet included a net payable of $29.0 million primarily related to NSTAR Electric & Gas for management and support services.
11. Goodwill and Costs to Achieve
The merger that created NSTAR was accounted for using the purchase method of accounting. In accordance with Accounting Principles Board (APB) No. 16 - “Business Combinations,” all goodwill was recorded on the books of the subsidiaries of COM/Energy. However, under the merger rate plan approved by the MDTE, all of NSTAR’s utility subsidiaries share in the recovery of goodwill in their rates. As a result, goodwill amortization expense is allocated to Boston Edison from ComElectric, Cambridge Electric and NSTAR Gas through an intercompany charge. The Company is currently recovering these amounts in its rates.
NSTAR recorded goodwill associated with the merger of BEC Energy and COM/Energy of approximately $490 million, resulting in an annual amortization of goodwill of approximately $12.2 million. Boston Edison was allocated $319 million of goodwill and is amortizing this amount. This amount is being recovered in Boston Edison’s rates and is treated as an intercompany charge among the Company and its affiliated companies, ComElectric, Cambridge Electric and NSTAR Gas. This treatment results in differences in equity balances between GAAP and equity balances used for regulatory purposes. For the year ended December 31, 2004, Boston Edison’s portion of goodwill amortization was $8.0 million. Cost to achieve (CTA) are the costs incurred to execute the merger including the employee costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These amounts are expected to be offset by ongoing costs savings from streamlined operations and avoidance of costs that would have otherwise been incurred by BEC and COM/Energy. The original CTA estimate was $111 million of which approximately $72 million was allocated to Boston Edison. CTA was being amortized at an annual rate of $7.2 million through the rate freeze period based on the original rate plan, as approved by the MDTE. Effective upon completion of the four-year rate freeze on August 25, 2003, the amortization expense was increased to reflect the actual CTA expenditures incurred. As a result, the total CTA amortization expense for 2004 and 2003 was approximately $10.7 million and $8.4 million, respectively. In 2003, NSTAR, as mandated by the MDTE, filed a Revised Savings Report which detailed the actual realized savings as a result of the merger that created NSTAR. The filing included an update on the actual CTA costs incurred. This report included a final accounting of the deductibility for income tax purposes of each component of CTA. In 2004, the MDTE determined that no further action was required on the Revised Savings Report. The total CTA is approximately $143 million of which approximately $93 million is allocated to Boston Edison. This increase from the original estimate is partially mitigated by the fact that the portion of CTA that is not deductible for income tax purposes is approximately $20 million lower than the original estimate. Boston Edison anticipates that these incremental costs are probable of recovery in future rates. The CTA and Goodwill amounts were filed and approved as part of the rate plan.
12. Other Income (deductions), net
Major components of other income, net were as follows:
Major components of other deductions, net were as follows:
13. New Accounting Standards
No new accounting standards are applicable to the Company.
14. Purchases and Sales Transactions with Independent System Operator - New England (ISO-NE)
As part of Boston Edison’s normal business operations in order to meet its energy obligation to its standard offer customers, Boston Edison entered into hourly transactions to purchase or sell energy supply to its ISO-NE. The Boston Edison transactions with the ISO-NE have been treated as the ISO-NE servicing the incremental needs of Boston Edison, that is, transactions with ISO-NE associated with the difference between Boston Edison’s resource needs compared to Boston Edison’s resource availability. Boston Edison records the net effect of transactions with the ISO-NE as an adjustment to purchased power expense.
During 2004 and 2003, Boston Edison entered into an agreement whereby all of its energy supply resource entitlements are transferred to an independent energy supplier, following which Boston Edison repurchases its energy resource needs from this independent energy supplier for Boston Edison’s ultimate sale to its standard offer customers. This transaction has been and will continue to be recorded as a net purchase of electricity.
Note B. Asset Retirement Obligations
On January 1, 2003, Boston Edison adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations under lease arrangements. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying
amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.
Boston Edison has identified certain immaterial long-lived assets, including obligations under lease and easement arrangements, and has determined that it is legally responsible to remove such property.
Boston Edison has also identified legal retirement obligations that are currently not material to its financial statements. The recognition of a potential asset retirement obligation will have no impact on its earnings. In accordance with SFAS 71, Boston Edison would establish regulatory assets or liabilities to defer any differences between the liabilities established for ratemaking purposes and those recorded as required under SFAS 143.
For Boston Edison, the ultimate cost to remove utility plant from service (cost of removal) is recognized as a component of depreciation expense in accordance with approved regulatory treatment. As of December 31, 2004 and 2003, the estimated amount of the cost of removal included in regulatory liabilities was approximately $155 million and $123 million, respectively, based on the cost of removal component in current depreciation rates.
During 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The interpretation clarifies when an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. Uncertainty surrounding the timing and method of settlement that may be conditional on events occurring in the future would be factored into the measurement of the liability rather than the recognition of the liability. The interpretation would be effective for Boston Edison no later than the end of fiscal year 2005. Boston Edison is currently assessing the impact that the interpretation will have on its consolidated financial position, results of operation and cash flows.
Note C. Regulatory Assets
Regulatory assets represent costs incurred that are expected to be collected from customers through future rates in accordance with agreements with regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses.
Regulatory assets consisted of the following:
Under the traditional revenue requirements model, electric rates are based on the cost of providing energy delivery service. Under this model, Boston Edison is subject to certain accounting standards that are not applicable to other businesses and industries in general. The application of SFAS 71 requires companies to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected. This is applicable to Boston Edison’s distribution and transmission operations.
Power contracts
The unamortized balance of the estimated costs to decommission the Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power plants was $71.2 million at December 31, 2004 and $80.5 million at December 31, 2003. Boston Edison’s liability for CY decommissioning and its recovery ends in 2010 and for YA in 2010. However, should the actual costs exceed current estimates and anticipated decommissioning dates, Boston Edison could have an obligation beyond these periods that would be fully recoverable. These costs are recovered through Boston Edison’s transition charge. Refer to Note N, “Commitments and Contingencies,” for more discussion.
In addition, at December 31, 2004 and 2003, $234.8 million and $271.2 million, respectively, represents the recognition of one purchase power contract as a derivative and its above-market value and future recovery through Boston Edison’s transition charge. Refer to Note D, “Derivative Instruments - Power Contracts” for further details.
The remaining balance at December 31, 2004 of $610.8 million represents the recognition of four purchase power contract buy-out agreements that Boston Edison executed in 2004 and their future recovery through Boston Edison’s transition charge. Refer to Note L, “Contracts for the Purchase of Energy” for further details.
Retiree benefit costs
The retiree benefit regulatory asset of $12.9 million is comprised of $9.6 million of carrying charges related to a 2003 MDTE order, which will be recovered from customers in 2005 and $1.2 million of pension and other postretirement benefit obligations other than pension (PBOP) costs deferred under the MDTE order in 2003 and 2004. Deferred pension and PBOP costs are amortized and collected from customers over three years. The remaining balance of $2.1 million relates to other pension and PBOP costs deferred in accordance with MDTE directives. These costs are being amortized over periods ranging from two to nine years. Refer to Note H of these Consolidated Financial Statements for further discussion on the MDTE order.
In 2003, the retiree benefit regulatory asset also included approximately $172.9 million, which represented the additional minimum pension liability charge required under SFAS 87. As of December 31, 2004, the Pension Plan did not incur an additional minimum pension liability. As a result, the liability was reversed. Refer to Note G, “Pension and Other Postretirement Benefits” for further details.
Generation-related plant, net
Plant and other regulatory assets related to the divestiture of Boston Edison’s generation business are recovered with a return through the transition charge. This recovery occurs through 2019 for Boston Edison and is subject to adjustment by the MDTE.
As of December 31, 2004, $357.2 million of these generation-related regulatory assets are collateralized with the Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding, LLC. The certificates are non-recourse to Boston Edison.
Merger costs to achieve
An integral part of the merger was the MDTE-approved rate plan of the retail utility subsidiaries of NSTAR. 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. Costs to achieve were the costs incurred to execute the merger including costs for a voluntary severance program, costs of financial advisors, legal costs and other transaction and systems integration costs. These costs are collected from Boston Edison’s distribution customers and exclude a return component. The amortization of these costs has been adjusted since the original recovery began to reflect the actual costs incurred.
Income taxes, net
Approximately $28.8 million of this regulatory asset balance reflects deferred tax reserve deficiencies that the MDTE has allowed recovery of from ratepayers over a 17-year period. In addition, approximately $38.4 million in additional Boston Edison deferred tax reserve deficiencies have been recorded in accordance with an MDTE-approved settlement agreement. Offsetting these amounts is approximately $10.4 million of a regulatory liability associated with unamortized investment tax credits.
Purchased power costs
The purchased power costs relate to deferred standard offer service and deferred default service costs. Customers have the option of continuing to buy power from Boston Edison at standard offer prices through February 2005. Since 1998, Boston Edison has been allowed to defer the difference between the standard offer and default service revenues and the cost to supply the power, plus carrying costs. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from standard offer service and has not chosen to receive service from a competitive supplier. The market price for standard offer and default service may fluctuate based on the average market price for power. Amounts collected through standard offer and default service are recovered on a fully reconciling basis.
Redemption premiums
These amounts reflect the unamortized balance of redemption premiums on Boston Edison Debentures that are amortized and recovered over the life of the respective debentures pursuant to MDTE approval. There is no return recognized on this balance.
Other
These amounts primarily consist of deferred transmission costs that are set to be recovered over a subsequent twelve-month period. The deferred costs represent the difference between the level of billed transmission revenues and the current period costs incurred to provide transmission-related services.
Note D. Derivative Instruments - Power Contracts
Boston Edison accounts for its power contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and DIG interpretations. Boston Edison, as of December 31, 2004 and 2003, recorded one purchase power contract at fair value on its accompanying Consolidated Balance Sheets. As a result, the recognition of a liability for the fair value of the above-market portion of this contract at December 31, 2004 and 2003 is approximately $234.8 million and $271.2 million, respectively, and is a component of Deferred credits - Power contracts on the accompanying Consolidated Balance Sheets. Boston Edison has recorded a corresponding regulatory asset to reflect the future recovery of the above-market component of this contract through its transition charge. Therefore, as a result of this regulatory treatment, the recording of this contract on its accompanying Consolidated Balance Sheets does not result in an earnings impact.
During the first quarter of 2005, Boston Edison expects to close on a securitization financing that will affect this one contract that is classified as a derivative instrument. Boston Edison has entered into a buy-out agreement for this contract and expects to finance the buy-out payments through a securitization financing. When this occurs, the fair value of this contract will be removed as a derivative instrument from the balance sheet and the securitization debt obligation will be recorded along with an offsetting regulatory asset.
Boston Edison has other purchase power contracts in which the contract value is significantly above-market. However, these contracts have met the criteria for the normal purchases and sales exception pursuant to SFAS 133 and DIG interpretations and have not been recorded on the accompanying Consolidated Balance Sheets. The
above-market portion of these contracts is currently being recovered through the transition charge. Therefore, Boston Edison does not account for these types of capacity and energy contracts or purchase orders for numerous supply arrangements as derivatives.
Note E. Variable Interest Entities
In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities”, as revised in December 2003 (FIN 46R), which addresses the consolidation of variable interest entities (VIE) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise with the majority of the risks or rewards associated with the VIE. This interpretation had two effective dates: December 31, 2003 and March 31, 2004.
Boston Edison has a wholly owned special purpose subsidiary, BEC Funding LLC, established to undertake the sale of $725 million in notes to a special purpose trust created by two Massachusetts state agencies. Boston Edison consolidates this entity. As part of Boston Edison’s assessment of FIN 46R, and for compliance at December 31, 2003, Boston Edison reviewed the substance of this entity to determine if it is still proper to consolidate this entity. Based on its review, Boston Edison has concluded that BEC Funding LLC is a VIE and should continue to be consolidated by Boston Edison.
For the March 31, 2004 effective date of FIN 46R, Boston Edison evaluated, among other entities, the companies that supply power to Boston Edison through its purchase power agreements. Boston Edison determined that it is possible that two of these companies may be considered VIEs. These companies have power plants that have daily capacity output ranging from 230 megawatts (MW) to 330 MW. Through December 31, 2004 and 2003, Boston Edison purchased a total of approximately 2,364 megawatt-hours (MWH) and 2,730 MWH, respectively, under these agreements. These purchases approximate 14% and 15% of the total MWH purchased by Boston Edison for the years ended December 31, 2004 and 2003, respectively, and amounted to approximately $200 million and $209 million, respectively. In order to determine if these counterparties are VIEs and if Boston Edison is the primary beneficiary of these counterparties, Boston Edison concluded that it needed more information from the entities. Boston Edison attempted to obtain the information required and requested, in writing, these entities provide the Company with the necessary information. However, each of the entities has indicated that they will not provide the requested information as they are not contractually obligated to provide such confidential information. Since Boston Edison was unable to obtain the necessary information and, as allowed under a scope exception in FIN 46R, the accompanying Consolidated Financial Statements do not reflect the consolidation of any entities with which Boston Edison has a purchase power agreement.
Additionally, during 2004, Boston Edison executed purchase power buy-out/restructuring agreements with both of the entities from which Boston Edison attempted to obtain additional information in order to determine if these entities are VIEs. These buy-out/restructuring agreements received regulatory approval in January 2005. Refer to Note L for more detail on the purchase power buy-out agreements. As a result, Boston Edison will no longer pursue obtaining the necessary information to determine whether it has a potential variable interest in these entities.
Note F. 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 71 and SFAS 109, net regulatory assets of $56.8 million and $58.6 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 2004 and 2003, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes and unamortized investment tax credits consisted of the following:
Previously deferred investment tax credits are amortized over the estimated remaining lives of the property which generated the credits.
Components of income tax expense were as follows:
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:
Note G. Pension and Other Postretirement Benefits
1. Pension
Boston Edison is the sponsor of the NSTAR Pension Plan (the Plan), which is a defined benefit funded retirement plan that covers substantially all employees of NSTAR Electric & Gas.
NSTAR maintains nonqualified retirement plans for certain management employees of NSTAR Electric & Gas. Boston Edison was allocated approximately $2.1 million and $2.3 million in 2004 and 2003, respectively, of the net nonqualified retirement plan costs.
The Plan uses December 31st for the measurement date to determine its projected benefit obligation, fair value of plan assets, and net periodic benefit costs for the following year.
The changes in benefit obligation and Plan assets were as follows:
The Plan’s funded status was as follows:
Amounts recognized in the accompanying Consolidated Balance Sheets consisted of:
The accumulated benefit obligation of the Plan as of December 31, 2004 and 2003 were $870,730,000 and $843,609,000, respectively.
Weighted average assumptions were as follows:
The Plan’s discount rate is based on rates of high quality corporate bonds of appropriate maturities as published by nationally recognized rating agencies consistent with the duration of the Plan and through periodic bond portfolio matching. The Plan’s long-term rate of return is based on past performance and economic forecasts for the types of investments held in the Plan as well as the target allocation of the investments over a 20-year time period. This rate is presented net of both administrative expenses and investment expenses, which have averaged approximately 0.6% for 2004 and 2003.
Components of net periodic benefit cost were as follows:
The Company, as a sponsor of the Plan, allocated net costs and was reimbursed by its affiliated companies a total of $14.1 million and $20.7 million in 2004 and 2003, respectively.
Certain postretirement health care benefits are eligible to certain active NSTAR Electric & Gas employees and certain retired non-union employees in conjunction with the Group Welfare Benefit Plan for Retirees of NSTAR. Pursuant to the Internal Revenue Code, the Company funds these benefits through a 401(h) subaccount of the Pension Plan, subject to certain conditions and limitations. Assets in the trust beyond those in the 401(h) subaccount must be used to pay pension benefits and cannot be used to pay postretirement health care benefits. Assets included in the 401(h) subaccount must only be used for postretirement health care benefits.
The following indicates the weighted average asset allocation percentages of the fair value of total Plan assets for each major type of Plan asset as of December 31st as well as the Plan’s target percentages and the permissible ranges:
In March 2003, the investment goals were revised and new target percentages and permissible ranges were identified. As a result, the 2003 asset allocation percentages may not fall within the revised permissible ranges.
The primary investment goal of the Plan is to achieve a total annualized return of 9% (before expenses) over the long-term and to minimize unsystematic risk so that no single security or class of securities will have a disproportionate impact on the Plan. Risk is regularly evaluated, compared and benchmarked to plans with a similar investment strategy. The Plan currently uses 18 asset managers to manage the Plan assets. Assets are diversified by both asset class (i.e., equities, bonds) and within these classes (i.e., economic sector, industry), such that, for each asset manager:
•
No more than 6% of an asset manager’s equity portfolio market value may be invested in one company.
•
Each portfolio should be invested in at least 20 different companies in different industries and
•
No more than 50% of each portfolio’s market value may be invested in one industry sector.
Each asset manager may invest in domestic and international fixed income investments and may include government obligations, corporate bonds, preferred stock, and asset-backed securities. In addition, no one asset manager may invest in more than 5% of an investment manager’s portfolio may be invested in any one security of an issuer, except the U.S. Government and its agencies.
Funded Status
At December 31, 2003, the accumulated benefit obligation of the qualified Plan exceeded Plan assets. Therefore, Boston Edison was required to recognize an additional minimum liability adjustment as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.”
As a result of the additional minimum pension liability adjustment, the prepaid pension balance was removed from the balance sheet and a liability was recorded for the difference between the ABO and the plan assets. The net effect of this entry would ordinarily be recorded, net of taxes, as a non-cash charge to Other Comprehensive Income (OCI) on the accompanying Consolidated Statements of Comprehensive Income and would not affect the results of operations.
On October 31, 2003, the MDTE approved Boston Edison’s request for a reconciliation rate adjustment mechanism related to pension and PBOP costs. As part of this ruling, Boston Edison is allowed to record a regulatory asset in lieu of taking a charge to OCI for the additional minimum liability adjustment. As of December 31, 2003, Boston Edison recorded a regulatory asset of $172.9 million. The regulatory asset is shown as part of Deferred debits in the accompanying Consolidated Balance Sheets. The fair value of Plan assets and the ABO are measured at each year-end balance sheet date. The minimum liability is to be adjusted each year to reflect this measurement. When Plan assets exceed the ABO, the minimum liability is reversed. In 2004, due to positive Plan investment performance and Company contributions over the last two years of approximately $120 million, the fair value of the Plan’s assets exceeded the Plan’s ABO at December 31, 2004. As a result, the minimum liability and regulatory asset have been removed and the prepaid pension balance has been restored to the Consolidated Balance Sheet.
Boston Edison anticipates contributing approximately $35 million to its Plan in 2005.
The estimated future benefit payments for the years after 2004 are as follows:
2. Other Postretirement Benefits
NSTAR also provides, through the Group Welfare Benefits Plan for Retirees of NSTAR, health care and other benefits to retired employees who meet certain age and years of service eligibility requirements. These benefits included health and life insurance coverage and until April 1, 2003 included reimbursement of certain Medicare premiums for certain retirees. Under certain circumstances, eligible retirees are required to make contributions for postretirement benefits.
To fund these postretirement benefits, NSTAR, on behalf of Boston Edison and other subsidiaries, makes contributions to various VEBA trusts that were established pursuant to section 501(c)(9) of the Internal Revenue Code.
The funded status of the Plan cannot be presented separately for Boston Edison since the Company participates in the Plan trusts with other subsidiaries. Plan assets are available to provide benefits for all Plan participants who are former employees of Boston Edison and other subsidiaries of NSTAR.
The net periodic postretirement benefits cost allocated to Boston Edison was $15.5 million, $22.1 million and $23.8 million in 2004, 2003 and 2002, respectively.
In December 2003, the FASB issued Staff Position (FSP) 106-1, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). The Act provides for drug benefits for retirees over the age of 65 under a new Medicare Part D program. For employers like NSTAR, who currently provide retiree medical programs for former employees over the age of 65, there are subsidies available that are inherent in the Act. The Act potentially entitles these employers to a direct tax-exempt federal subsidy. Pursuant to FSP 106-1, Boston Edison elected to defer recognition of the provisions of this Act until further accounting guidance became effective.
In May 2004, the FASB issued FSP 106-2 effective July 2004 (retroactive to January 1, 2004), to provide guidance on the accounting for the effects of the Act. The guidance requires that, when an employer initially accounts for the effects of the Act on the accumulated postretirement benefits obligation (APBO) should be accounted for as an actuarial gain (assuming, no plan amendments are made). In accordance with this provision, NSTAR’s APBO was reduced by $51 million. In addition, since the subsidy would affect the employer’s share of its plan’s costs, the subsidy is included in measuring the costs of benefits attributable to current service. Therefore, the subsidy reduces service cost when it is recognized as a component of net periodic postretirement benefits cost. NSTAR’s adoption of FSP 106-2 resulted in a reduction to the 2004 net periodic postretirement benefit cost of approximately $7 million. However, due to the Company’s pension and other postretirement benefits rate reconciliation adjustment mechanism that went into effect on September 1, 2003, this reduction in cost does not have a material impact on earnings.
3. Savings Plan
Boston Edison contributes proportionately into a defined contribution 401(k) plan for substantially all employees of NSTAR Electric & Gas. Matching contributions (which are equal to 50% of the employees’ deferral up to 8%
of compensation) included in the accompanying Consolidated Statements of Income amounted to $5 million in 2004, 2003 and 2002. Effective January 1, 2002, consistent with the Economic Growth and Tax Relief Reconciliation Act, the plan was amended to allow for increased maximum annual pre-tax contributions and additional “catch-up” pre-tax contributions for participants age 50 or older, acceptance of other types of “roll-over” pre-tax funds from other plans and the option of reinvesting dividends paid on the NSTAR Common Share Fund or receiving such dividends in cash. The election to reinvest dividends paid on the NSTAR Common Share Fund or receive the dividends in cash is subject to a freeze period beginning seven days prior to the date any dividend is paid. During this period, participants cannot change their election. Dividends are paid to this plan four times a year on February 1, May 1, August 1 and November 1.
Note H. Pension and Postretirement Benefits Other Than Pensions (PBOP) Adjustment Mechanism
On October 31, 2003, Boston Edison, along with NSTAR’s other utility subsidiaries, received an order from the MDTE regarding the request (filed on April 16, 2003) for the approval of a reconciliation rate adjustment mechanism (PAM) for recovery of costs associated with the Company’s obligation to provide its employees qualified pension and PBOP benefits. Prior to the PAM order, the Company had accounted for these obligations in accordance with an Accounting Order received from the MDTE in December 2002.
The PAM order authorizes Boston Edison to recover its qualified pension and PBOP expenses through a reconciling rate mechanism. This mechanism removes the volatility in earnings that may have resulted from requirements of existing accounting standards and provides for an annual filing and rate adjustment with the MDTE. This order effectuates the Accounting Order, which allowed Boston Edison to record a regulatory asset in lieu of taking a charge to OCI at December 31, 2002 for the additional minimum liability in accordance with SFAS 87. In addition, the order revised the effective date included in the Accounting Order on which the Company could begin to defer the difference between the level of qualified pension and PBOP expense included in rates and the amounts that are required to be recorded under the pension and PBOP accounting rules to September 1, 2003. This date coincides to the expiration of Boston Edison’s four-year distribution rate freeze. As a result, in 2003 Boston Edison recognized $10.4 million of expenses that had been deferred earlier in the year. In accordance with the PAM order, the Company recognized in 2003 $9.8 million of revenue related to carrying charges on the net prepaid balance. This carrying charge was collected from customers during 2004. In 2004, the Company recognized $8.9 million of revenue related to carrying charges on the net prepaid balance. This carrying charge will be collected from customers during 2005.
On November 20, 2003, both Boston Edison and the Massachusetts Attorney General filed motions with the MDTE for reconsideration of its PAM order. On November 19, 2004, the MDTE denied the request for reconsideration for both Boston Edison and the Massachusetts Attorney General.
Note I. Capital Stock
Cumulative Preferred Stock
Non-mandatory redeemable series:
Par value $100 per share, 2,660,000 shares authorized and 430,000 shares issued and outstanding:
Note J. Indebtedness
1. Long-Term Debt
Boston Edison’s long-term debt consisted of the following:
On March 16, 2004, Boston Edison redeemed the entire outstanding balance of $181 million aggregate principal amount of its 7.80% Debentures due March 15, 2023. The redemption also included payment of premium plus accrued interest of approximately $6.1 million. On April 16, 2004, Boston Edison issued $300 million of ten-year fixed rate (4.875%) Debentures. The net proceeds were used to repay outstanding short-term debt balances incurred, in part, to pay the redemption price of the 7.80% Debentures. The premium paid to redeem the 7.80% Debentures will be amortized over ten years, the term of the new 4.875% Debentures.
Sewage facility revenue bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. Scheduled redemptions of $1.65 million were made in 2004 and 2003. The interest rate of the bonds was 7.375% for both 2004 and 2003. A portion of the proceeds from the bonds is in a reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, Boston Edison would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 were 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.
The aggregate principal amounts of Boston Edison’s long-term debt (including securitization certificates and sinking fund requirements) due in the five years subsequent to 2004 are approximately $141.7 million in 2005, $70.3 million in 2006, $70.2 million in 2007, $70.1 million in 2008 and $70.2 million in 2009.
2. Financial Covenant Requirements
Boston Edison has no financial covenant requirements under its long-term debt arrangements.
The Transition Property Securitization Certificates held by Boston Edison’s subsidiary, BEC Funding LLC, are collaterized with a securitized regulatory asset with a balance of $357.2 million and $425.4 million as of December 31, 2004 and 2003, respectively. Boston Edison, as servicing agent for BEC Funding, collected $96.0 million in 2004. These Certificates are non-recourse to Boston Edison.
In December 2003, Boston Edison filed a shelf registration with the SEC to allow Boston Edison to issue up to $500 million in debt securities. The registration became effective on January 9, 2004. On April 1, 2004, the MDTE approved the issuance by Boston Edison of up to $500 million of debt securities from time to time on or before December 31, 2005. On April 16, 2004, Boston Edison sold $300 million of ten-year fixed rate (4.875%) Debentures under this shelf registration. The net proceeds were primarily used to repay outstanding short-term debt balances.
As of September 28, 2004, Boston Edison has approval from the FERC to issue short-term debt securities from time to time on or before December 31, 2006, with maturity dates no later than December 31, 2007, in amounts such that the aggregate principal does not exceed $450 million at any one time. In addition, in November 2004, Boston Edison restructured its $350 million revolving credit agreement that expired in November 2004 into a five-year, $350 million revolving credit agreement that expires in November 2009. However, unless Boston Edison receives necessary approvals from the MDTE, the credit agreement will expire 364 days from the date of the first draw under the agreement. At December 31, 2004 and 2003, there were no amounts outstanding under the current and previous revolving credit agreement. This credit facility serves as backup to Boston Edison’s $350 million commercial paper program that had a $46.5 million and $182.5 million balance at December 31, 2004 and 2003, respectively. Under the terms of the current agreement, Boston Edison is required to maintain a consolidated maximum total debt to capitalization ratio of not greater than 65% at all times, excluding Transition Property Securitization Certificates, and excluding Accumulated other comprehensive income (loss) from Common equity. The previous agreement required a total debt to capitalization ratio of not greater than 60%. At December 31, 2004 and 2003, Boston Edison was in full compliance with all of its covenants in connection with its short-term credit facilities.
Interest rates on the outstanding borrowings generally are money market rates and averaged 1.15% and 1.18% in 2004 and 2003, respectively. In aggregate, short-term borrowings totaled $46.5 million and $182.5 million at December 31, 2004 and 2003, respectively.
Note K. 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 $6.5 million and $8.4 million for 2004 and 2003, respectively, approximate fair value due to the short-term nature of these securities.
2. Indebtedness (Excluding Notes Payable)
The fair values of long-term indebtedness are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 2004 and 2003 were as follows:
Note L. Contracts for the Purchase of Energy
In accordance with the 1997 Massachusetts Electric Restructuring Act (the Act), Boston Edison divested of its generation facilities and replaced that load requirement through purchase power contracts, both with existing contracts and with newly executed contracts. As a result, Boston Edison has been required to enter into purchase power contracts of varying lengths to satisfy its electric load requirements. Boston Edison has limitations, as mandated by the MDTE, as to the length of these contracts. As a Massachusetts distribution company, Boston Edison is required to obtain and resell power to retail customers through either default or standard offer service for those who choose not to buy energy from a competitive energy supplier. Default service is provided to customers who have entered Boston Edison’s service territory after the effective date of the Act and whose rate is intended to reflect current market conditions. Standard offer service is provided to customers who were customers at the time of the Act and whose rate is determined by the MDTE to guarantee overall rate reductions. Standard offer service will expire on February 28, 2005. Boston Edison has entered into agreements ranging in length from three to twelve months for its default service power supply. For its standard offer service power supply, Boston Edison assigned its existing long-term contracts to meet this load requirement.
To a certain extent, Boston Edison supplements its load requirements through existing long-term contracts. Boston Edison, during 2003 and 2004, initiated a process to auction off certain purchase power agreements under which it had entitlements under long-term contracts. One contract in which Boston Edison had entitlements to approximately 265 MW of the 780 MW of capacity, originally included in the auction, expired on December 31, 2004. Also in 2004, Boston Edison executed agreements to buy-out or restructure five of its purchase power agreements. These buy-out/restructuring agreements provide no economic benefit to Boston Edison and, therefore, the agreements’ contract termination costs will be recorded on the accompanying Consolidated Financial Statements. These agreements constitute approximately 460 MW of the 780 MW of capacity originally auctioned and reduce the amount of above-market costs that Boston Edison will collect from its customers through its transition charge. As of December 31, 2004, two of these agreements have received MDTE approval and were recognized. These two agreements require Boston Edison to make monthly payments through September 2011 totaling approximately $125 million.
On January 7, 2005, Boston Edison received approval from the MDTE for an additional two agreements that are anticipated to be completed by February 2005. These two agreements were binding as of December 31, 2004 but were contingent upon regulatory approval. Since the contingency was removed during February 2005, Boston Edison recorded the contract termination cost as of December 31, 2004. One of the two agreements requires Boston Edison to make net monthly payments through September 2011 totaling approximately $416 million. The other agreement requires Boston Edison to make net monthly payments through September 2016 totaling approximately $215 million. Boston Edison anticipates making these cash payments from funds generated from operations and will be fully recovered through Boston Edison’s transition charge.
The total amount currently recognized for obligations relating to four of the five agreements is approximately $610.8 million (in present day dollars); approximately $104.9 million as a component of Current liability-power contract and $505.9 million as a component of Deferred credits - power contracts on the accompanying Consolidated Balance Sheets. Boston Edison has recorded a corresponding regulatory asset to reflect the full future recovery of these payments through its transition charge. This recognition represents a non-cash increase to assets and liabilities.
Also in January 2005, the MDTE approved the one remaining contract that reduced the overall amount of transition costs to be paid for above-market contracts. This contract is a buy-out arrangement whereby Boston Edison has committed to pay amounts for the full release of its obligation under a previous purchase power agreement. On August 31, 2004, NSTAR Electric filed with the MDTE a proposed financing plan that seeks approval for full recovery this buy-out and the issuance of $674.5 million of transition property securitization bonds to provide the funds for this buy-out agreement. Boston Edison’s share of the transition property securitization bonds is $265.5 million. The MDTE approved the financing plan in January 2005. On February 15, 2005, these bonds were priced at a weighted average yield of 4.15%. Boston Edison expects the securitization financing to close in March 2005.
Capacity costs
Capacity costs of long-term contracts reflect Boston Edison’s proportionate share of capital and fixed operating costs of certain generating units. In 2004, these costs were attributed to 329 MW of capacity purchased. Energy costs are paid to generators based on a price per kilowatt-hour actually received into Boston Edison’s distribution system and are included in the total cost. Total capacity purchased in 2004 was 809.3 MW.
Information related to long-term power contracts during 2004 was as follows:
Boston Edison’s total capacity and/or energy costs associated with these contracts in 2004, 2003 and 2002 were approximately $326 million, $339 million and $407 million, respectively. Boston Edison’s capacity charge obligation under these contracts for the years after 2004 is as follows:
As of December 31, 2004, Boston Edison had executed an agreement to divest a number of its purchase power agreements and expects additional divestitures to be executed in 2005. The remaining long-term purchase power agreements are primarily energy only, however, some agreements have minor capacity cost obligations.
Note M. Other Electric Utility Matters
Sale of Property
On April 7, 2004, Boston Edison completed the sale of a parcel of land in the City of Newton, Massachusetts for $15.1 million; the net proceeds from the sale were used to reduce Boston Edison’s transition charge. The sale and regulatory treatment of the proceeds were approved by the MDTE.
Service Quality Indicators
Service quality indicators are established performance benchmarks for certain identified measures of service quality relating to customer service and billing performance, customer satisfaction, and reliability and safety performance for all Massachusetts utilities. Boston Edison is required to report annually to the MDTE concerning its performance as to each measure and is subject to maximum penalties of up to two percent of transmission and distribution revenues should performance fail to meet the applicable benchmarks.
On March 1, 2004, Boston Edison filed its 2003 Service Quality Report with the MDTE that demonstrated the Company’s achieved levels of reliability and performance; the report indicates that no penalty was assessable for 2003. The MDTE concurred with Boston Edison’s determination in an order issued in October 2004. Boston Edison monitors its service quality continuously to determine its contingent liability, and if it’s probable that a liability has been incurred and is estimable, a liability would be accrued. Annually, Boston Edison makes a service quality performance filing with the MDTE. Any settlement or rate order that would result in a different liability level from what has been accrued would be adjusted in the period that the MDTE issues an order determining the amount of any such liability. Recently, the MDTE voted to initiate an investigation into potentially modifying the service quality indicators for all Massachusetts utilities. Until any such order is issued, the current service quality indicators will remain in place.
As of December 31, 2004, Boston Edison’s performance has exceeded the applicable established benchmarks such that no liability has been accrued for 2004.
Note N. Commitments and Contingencies
1. Contractual Commitments
Boston Edison also has leases for facilities and equipment. The estimated minimum rental commitments under non-cancellable operating leases for the years after 2004 are as follows:
The total expense for both lease and transmission agreements was $67.3 million in 2004, $58.6 million in 2003 and $58.1 million in 2002, net of capitalized expenses of $1.2 million in 2004, $1.6 million in 2003 and $1.9 million in 2002.
Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation, other than to large customers, for the period January 1, 2005 through June 30, 2005 and for 50% of its obligation, other than to large customers, for the second-half of 2005. Boston Edison has entered into a short-term power purchase agreement to meet its entire default service supply obligation for large customers through March 2005. A Request for Proposals will be issued quarterly in 2005 for the remainder of the obligation for large customers and semi-annually for non-large customers in accordance with MDTE regulations. Boston Edison entered into agreements ranging in length from three to twelve-months effective January 1, 2004 through December 31, 2004 with suppliers to provide full default service energy and ancillary service requirements at contract rates approved by the MDTE. Boston Edison is currently recovering payments it is making to suppliers from its customers and has financial and performance assurances and financial guarantees in place with those suppliers to protect Boston Edison from risk in the unlikely event any of its suppliers encounter financial difficulties or fail to maintain an investment grade credit rating. In connection with certain of these agreements, should, in the unlikely event, Boston Edison receive a credit rating below investment grade, it potentially could be required to obtain certain financial commitments, including but not limited to, letters of credit. Refer to Note L, “Contracts for the Purchase of Energy” for a further discussion.
In the first quarter of 2005, Boston Edison expects to begin construction on a 345kV transmission line that would connect Stoughton, Massachusetts, a southern suburb of Boston, to South Boston. This transmission line is
expected to assure continued reliability of electric service and improve power import capacity in the Northeast Massachusetts area. This project is expected to be placed in service during the summer of 2006. The cost of the project is expected to be shared by all of New England and will be recovered by Boston Edison through wholesale and retail transmission rates. As of December 31, 2004, Boston Edison has contractual commitments of approximately $6 million related to this project.
2. Electric Equity Investments and Joint Ownership Interest
Boston Edison has an equity investment of approximately 11.1% in two companies that own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant, Boston Edison is required to guarantee, in addition to its own share, the obligations of those participants who do not meet certain credit criteria. At December 31, 2004, Boston Edison’s portion of these guarantees amounted to $7.2 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 their best efforts obligations pursuant to the Equity Funding Agreement dated June 1, 1985, as amended, for NEH and NHH, in 2004, NEH repurchased a total of 275,000 of its outstanding shares from all equity holders and NHH repurchased a total of 1,500 outstanding shares from all equity holders. Through December 31, 2004, Boston Edison’s reduction of its equity ownership resulting from NEH buy-back of 30,389 shares and NHH buy-back of 166 shares was approximately $777,000.
Boston Edison has an equity ownership of 9.5% in both Connecticut Yankee Atomic Power Company (CYAPC) and Yankee Atomic Electric Company (YAEC) (collectively, the Yankee Companies). Periodically, Boston Edison obtains estimates from the management of the Yankee Companies on the cost of decommissioning the Connecticut Yankee nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These nuclear units are completely shut down and are currently conducting decommissioning activities.
Based on estimates from the Yankee Companies’ management as of December 31, 2004, the total remaining cost for decommissioning each nuclear unit is approximately as follows: $630.0 million for CY and $119.3 million for YA. Of these amounts, Boston Edison is obligated to pay $59.8 million towards the decommissioning of CY and $11.3 million toward YA. These estimates are recorded in the accompanying Consolidated Balance Sheets as Power contract liabilities with a corresponding regulatory asset and do not impact the current result of operations. These estimates may be revised from time to time based on information available to the Yankee Companies regarding future costs. The Yankee Companies have received approval from FERC for recovery of these costs and Boston Edison expects any additional increases to these costs to be included in future rate applications with the FERC, with any resulting adjustments being charged to their respective sponsors, including Boston Edison. Boston Edison would recover its share of any allowed increases from customers through the transition charge.
The various decommissioning trusts for which Boston Edison is responsible through its equity ownership are established pursuant to Federal regulations. The investment of decommissioning funds that have been established, are managed in accordance with these federal guidelines, state jurisdictions and with the applicable Internal Revenue Service requirements. Some of the requirements state that these investments be managed independently by a prudent fund manager and that funds are to be invested in conservative, minimum risk investment securities. Any gains or losses are anticipated to be refunded to or collected from customers, respectively.
CY’s estimated decommissioning costs increased significantly in 2003 and the increase reflects the fact that CY is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). In July 2004, CY filed with FERC for recovery of these increased costs. In August 2004, FERC issued an order accepting the new rates, beginning in February 2005, subject to refund.
CY is currently in litigation with Bechtel over the termination of its decommissioning contract. Additionally, Bechtel filed a complaint against CY asserting several claims as well as wrongful termination. Bechtel sought to garnish the decommissioning trust and related payments. In October 2004, Bechtel and CY entered into a stipulation under which Bechtel relinquished its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CY’s real property in Connecticut with a book value of $7.9 million and the escrowing of portions of the sponsors’ periodic payments, up to a total of $41.7 million, all of which the sponsors, which include Boston Edison, are scheduled to pay to CY through June 30, 2007. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CY intends to contest the ability of Bechtel to attach these assets. Discovery is underway and a trial has been scheduled for May 2006.
3. Financial and Performance Guarantees
On a limited basis, Boston Edison may enter into agreements providing financial assurance to third parties. Such agreements include surety bonds and other guarantees.
At December 31, 2004, outstanding guarantees totaled $13.8 million as follows:
As of December 31, 2004, Boston Edison has purchased a total of approximately $0.2 million of performance surety bonds for the purpose of obtaining licenses, permits and rights-of-way in various municipalities. In addition, Boston Edison has purchased $6.4 million in worker’s compensation self-insurer bonds. These bonds support the guarantee by Boston Edison to the Commonwealth of Massachusetts required as part of Boston Edison’s workers’ compensation self-insurance program.
Boston Edison has also issued $7.2 million of residual value guarantees related to its equity interest in the Hydro-Quebec transmission companies.
Management believes the likelihood Boston Edison would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.
4. Environmental Matters
As of December 31, 2004, Boston Edison is involved in three state regulated properties (“Massachusetts Contingency Plan, or “MCP” sites”) where oil or other hazardous materials were previously spilled or released. Boston Edison is required to clean up or otherwise remediate these properties in accordance with specific state regulations. There are sometimes uncertainties associated with total remediation costs due to the final selection of the specific cleanup technology and the particular characteristics of the different sites. Estimates of approximately $0.2 million are included for both December 31, 2004 and 2003, as liabilities in the accompanying Consolidated Balance Sheets.
In addition to the MCP sites, Boston Edison also faces possible liability as a result of involvement in ten multi-party disposal sites or third party claims associated with contamination remediation. Boston Edison generally expects to have only a small percentage of the total potential liability for these sites. Estimates of approximately $3.4 million for both December 31, 2004 and 2003 are included as liabilities in the accompanying Consolidated Balance Sheets.
The MCP and multi-party disposal site amounts have not been reduced by any potential rate recovery treatment of these costs or any potential recovery from Boston Edison’s insurance carriers. Prospectively, should Boston
Edison be allowed to collect these specific costs from customers, it would record an offsetting regulatory asset and record a credit to operating expenses equal to previously expensed costs.
Estimates related to environmental remediation costs are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs and as either additional sites are identified or Boston Edison’s responsibilities for such sites evolve or are resolved. Boston Edison’s ultimate liability for future environmental remediation costs may vary from these estimates. Based on Boston Edison’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, Boston Edison does not believe that these environmental remediation costs will have a material adverse effect on Boston Edison’s consolidated financial position, results of operations or cash flows for a reporting period.
5. Regulatory and Legal Proceedings
a. Regulatory proceedings
On December 21, 2004, the FERC issued an order approving Boston Edison’s October 2004 request for Boston Edison to modify its Open Access Transmission Tariff. Effective January 1, 2005, Boston Edison is allowed to include 50 percent of construction work in progress in its rate base for transmission projects by including this amount in its local network service transmission rate formula, rather than capitalizing Allowance for Funds Used During Construction (AFUDC) charges on the entire construction expense balance. The order is subject to Boston Edison filing annual reports of its long-term transmission plan.
In December 2004, Boston Edison filed proposed transition rate adjustments for 2005, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2004. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2005. The filings are to be updated in February 2005 to reflect final 2004 costs and revenues which are subject to final reconciliation.
Effective October 1, 2004, Boston Edison’s Standard Offer Service Fuel Adjustment (SOSFA) rate was modified to 1.223 cents per kilowatt-hour from zero upon approval by the MDTE. The MDTE has allowed companies to adjust prices to reduce deferred cost balances that arise due to rapidly changing market costs for the oil and natural gas used to generate electricity and the SOSFA is designed to collect the costs of fuel that companies incur for purchasing electricity from their suppliers to serve their standard offer service customers. The SOSFA was zero cents per kilowatt-hour from April 1, 2002 through April 30, 2003. The rate was increased to 0.902 cent per kilowatt-hour from May 1, 2003 through September 1, 2003. The rate was adjusted to zero until January 1, 2004 than increased to 1.223 cent per kilowatt-hour. The MDTE has ruled that these fuel index adjustments are excluded from the 15% rate reduction requirement under the Restructuring Act.
Effective January 1, 2005, Boston Edison’s SOSFA rate was modified to 1.564 cents per kilowatt-hour with the approval of the MDTE.
In December 2003, Boston Edison filed proposed transition rate adjustments for 2004, including a preliminary reconciliation of transition, transmission, standard offer and default service costs and revenues through 2003. The MDTE subsequently approved tariffs for Boston Edison effective January 1, 2004. The filing was updated in February 2004 to include final costs and revenues for 2003.
On December 1, 2003, Boston Edison filed its annual reconciliation report on its pension and PBOP rate adjustment mechanism. Hearings were held during 2004. Boston Edison anticipates an order during the first quarter of 2005. Boston Edison cannot predict the overall timing and result of this order on its financial position or results of operations.
b. Other Legal Matters
In the normal course of its business, Boston Edison and its subsidiaries are involved in certain legal matters, including civil litigations. Management is unable to fully determine a range of reasonably possible court-ordered
damages, settlement amounts, and related litigation costs (“legal liabilities”) that would be in excess of amounts accrued and amounts covered by insurance. Based on the information currently available, Boston Edison does not believe that it is probable that any such legal liabilities will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal liabilities that may result from changes in circumstances could have a material impact on its results of operations, cash flows and financial condition for a reporting period.
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 Boston Edison Company.
Item 9A.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report.
Item 9B.
Item 9B. Other Information
None
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this Form 10-K:
Incorporated by reference unless designated otherwise:
SCHEDULE II
BOSTON EDISON COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 and 2002
(Dollars in Thousands)
FORM 10-K
BOSTON EDISON COMPANY
DECEMBER 31, 2004
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Boston Edison Company
(Registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of the 18th day of February 2005.
Signature
Title
/s/ THOMAS J. MAY
Thomas J. May
Chairman, President, Chief Executive Officer and Director
/s/ JAMES J. JUDGE
James J. Judge
Senior Vice President, Treasurer, Chief Financial Officer and Director
/s/ DOUGLAS S. HORAN
Douglas S. Horan
Senior Vice President/Strategy, Law and Policy, Clerk, General Counsel and Director