Item 1. Business - - - - - - - - - - - - - - - - - -----------------
(a) General Development of Business - - - - - - - - - - - - - - - - - -----------------------------------
Boston Edison Company (Boston Edison), an investor-owned regulated public utility incorporated in 1886 under Massachusetts law, received final approval of its reorganization plan to form a holding company structure from the Securities and Exchange Commission (SEC) in May 1998. Effective May 20, 1998 the holding company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned subsidiary of BEC. Effective June 25, 1998, Boston Energy Technology Group (BETG) ceased being a subsidiary of Boston Edison and became a wholly owned subsidiary of BEC. Unregulated activities continue to be conducted through BETG.
Within its newly restructured industry, BEC has announced its intention to focus its utility operations on the transmission and distribution of energy. The sale of Boston Edison's fossil generating assets to Sithe Energies, Inc. (Sithe) was completed in May 1998. In November 1998, Boston Edison signed an agreement with Entergy Nuclear Generating Company (Entergy) to sell its wholly owned nuclear generating unit, Pilgrim Nuclear Power Station (Pilgrim). BEC signed a merger agreement with Commonwealth Energy System (CES) in December 1998 that will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities.
(b) Financial Information about Industry Segments - - - - - - - - - - - - - - - - - -------------------------------------------------
BEC's principal segment is the electric utility, Boston Edison. As noted above, unregulated activities are conducted through BETG. Such unregulated activities include telecommunications, construction management and district cooling. Refer to Note J to the Consolidated Financial Statements in Item 8 for specific financial information related to BEC's electric utility and unregulated segments.
(c) Narrative Description of Business - - - - - - - - - - - - - - - - - -------------------------------------
Principal Products and Services
Boston Edison currently supplies electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. The population of the area served with electricity at retail is approximately 1.5 million. In 1998 Boston Edison served an average of approximately 660,000 customers. It also supplies electricity at wholesale for resale to other utilities and municipalities. Electric operating revenues by class for the last three years consisted of the following:
Sources and Availability of Fuel
On May 15, 1998, Boston Edison completed the sale of its non-nuclear generating assets to Sithe Energies. In April 1998, Boston Edison began soliciting expressions of interest for the sale of its nuclear generating unit, Pilgrim as part of the previously announced strategy to exit the generation business. On November 19, 1998, Boston Edison announced that Entergy, a subsidiary of New Orleans-based Entergy Corporation, had been selected as the winning bidder for Pilgrim. A purchase and sale agreement has been signed and all required approvals are anticipated in the second quarter of 1999. Company generation by type of fuel for each of the last five years were as follows:
The decrease in company oil and gas generation resulting from the fossil divestiture was partially offset by higher purchased power in 1998 that included a six-month transitional power purchase contract with Sithe that began in May.
In order to obtain fuel for use at Pilgrim Station, Boston Edison must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. Boston Edison currently has contracts for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 2002, 2000, 2004 and 2012, respectively. Following the planned sale of Pilgrim, it is expected that each of these contracts will either be terminated or permitted to expire in accordance with their terms. Boston Edison may be subject to a penalty of approximately $10 million to terminate one of these contracts. Management anticipates any payment will be collected from customers under the terms of the Boston Edison settlement agreement.
Franchises
Through its charter, which is unlimited in time, Boston Edison has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act as agents for the state. In some cases the action of these authorities is subject to appeal to the Massachusetts Department of Telecommunications and Energy (DTE). The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature. Pursuant to the Massachusetts electric utility industry restructuring legislation enacted in November 1997, the DTE has defined the service territory of Boston Edison based on the territory actually served on July 1, 1997, and following, to the extent possible, municipal boundaries. The legislation further provided that, until terminated by effect of law or otherwise, Boston Edison shall have the exclusive obligation to provide distribution service to all retail customers within such service territory. No other entity shall provide distribution
service within this territory without the written consent of Boston Edison which consent must be filed with the DTE and the municipality so affected.
Seasonal Nature of Business
Kilowatt-hour (kWh) sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions. Refer to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8 for specific financial information by quarter for 1998 and 1997.
Competitive Conditions
The utility industry has continued to change in response to the marketplace demands for improved customer service and lower prices for energy. These pressures have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. On December 5, 1998, BEC and CES, headquartered in Cambridge, Massachusetts, entered into an Agreement and Plan of Merger (the Merger Agreement). Management's Discussion and Analysis ("Merger with COM/Energy") in Item 7 provides further details regarding the Merger Agreement.
BEC's electric utility subsidiary, Boston Edison has been anticipating and responding to changes in the electric energy business as a result of industry restructuring proceedings at both the federal and state levels. Management's Discussion and Analysis ("Retail Access") in Item 7 provides further details regarding Boston Edison's response to the industry climate, including details of its industry restructuring settlement agreement.
Environmental Matters
BEC and its subsidiaries are subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 1998 and 1997 were $0.6 million and $1.4 million, respectively. Management believes that its remaining operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur.
Number of Employees
As of March 26, 1999, BEC had 2,893 full-time and 48 part-time utility employees including 1,966 represented by two locals of the Utility Workers Union of America, AFL-CIO. The locals' labor contracts are effective through May of the year 2000. Management believes it has satisfactory employee relations.
Approximately 600 employees are expected to terminate employment with BEC as a result of the divestiture of Pilgrim Station in 1999. Refer to the Generating Assets Divestiture section of Item 7 for information regarding employees affected by the nuclear divestiture.
(d) Financial Information about Foreign and Domestic Operations and Export - - - - - - - - - - - - - - - - - -------------------------------------------------------------------------- Sales - - - - - - - - - - - - - - - - - -----
BEC's principal subsidiary, Boston Edison delivers electricity to retail and wholesale customers in the Boston area. Neither Boston Edison, nor BEC's other subsidiaries have any foreign operations or export sales.
(e) Additional Information - - - - - - - - - - - - - - - - - --------------------------
Regulation
BEC's electric utility subsidiary, Boston Edison and its wholly owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the DTE, whose jurisdiction includes supervision over retail rates for electricity and financing and investing activities. In addition, the Federal Energy Regulatory Commission (FERC) has jurisdiction over various phases of Boston Edison's business including rates for power sold at wholesale for resale, facilities used for the transmission or sale of that power, certain issuances of short-term debt and regulation of the system of accounts. BEC's subsidiary BETG and its subsidiaries are not subject to such regulation.
The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the siting, construction and operation of nuclear reactors with respect to public health and safety, environmental matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility in accordance with its terms. Boston Edison currently holds an operating license for Pilgrim Station which expires in 2012. Continuing NRC review of existing regulations and certain operating occurrences at other nuclear plants have periodically resulted in the imposition of additional requirements for all nuclear plants in the United States, including Pilgrim Station. NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties.
In addition, management could undertake certain actions regarding Pilgrim Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations, a voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants. Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests for various kinds of federal, state and local legislative or regulatory action, direct voter initiatives or referenda or litigation. Management cannot predict the extent, cost or timing of any modifications to Pilgrim which could be necessary as a result of additional regulatory or other requirements. As discussed in Sources and Availability of Fuel of this item, Boston Edison entered into a purchase and sale agreement with Entergy for the sale of Pilgrim Station. The DTE approved the sale of Pilgrim in March 1999. Other required approvals are anticipated in the second quarter of 1999. Such approvals are required for the completion of the Pilgrim sale. If the required approvals are not received as anticipated, the agreement with Entergy could be terminated. If Boston Edison is ultimately unable to sell Pilgrim, management expects it would recover all stranded Pilgrim costs, including decommissioning under the Boston Edison settlement agreement.
Capital Expenditures and Financings
The most recent estimates of capital expenditures (excluding nuclear fuel), allowance for funds used during construction (AFUDC), long-term debt maturities and preferred stock payment requirements for the years 1999 through 2003 are as follows:
Management continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.
Plant expenditures in 1998 were $120 million and consisted primarily of additions to Boston Edison's distribution and transmission systems and construction expenditures related to BEC's district cooling subsidiary, Northwind Boston, LLC. The majority of these expenditures were for system reliability and control improvements, customer service enhancements and capacity expansion to allow for long range growth in the Boston Edison service territory.
Refer to the Liquidity section of Item 7 for more information regarding capital resources to fund BEC's construction programs.
Item 2.
Item 2. Properties and Power Supply - - - - - - - - - - - - - - - - - ------------------------------------
Total electric generation capacity from facilities owned by Boston Edison consisted of the following:
Boston Edison's high-tension transmission lines are generally located on land either owned or subject to easements in its favor. Its low-tension distribution lines are located principally on public property under permission granted by municipal and other state authorities.
As of December 31, 1998, Boston Edison's transmission system consisted of 376 miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 171 miles of underground circuits operating at 115 and 345 kV. The substations supported by these lines are 45 transmission or combined transmission and distribution substations with transformer capacity of 11,053 megavolt amperes (MVA), 57 4 kV distribution substations with transformer capacity of 932 MVA and 16 primary network units with 79 MVA capacity. In addition, high tension service was delivered to 248 customers' substations. The overhead and underground distribution systems cover approximately 3,700 and 3,200 circuit miles, respectively. 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.
Purchased Power Contracts
Boston Edison entered into a 13-month agreement effective December 1, 1998 to transfer all of the unit output entitlements from its long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities, Inc. In return, Select will provide full energy service requirements to Boston Edison, including New England Power Pool (NEPOOL) capability responsibilities, at FERC approved tariff rates through December 31, 1999. For more information regarding these long-term contracts refer to Note L to the Consolidated Financial Statements in Item 8.
Sales Contracts
Boston Edison currently sells a percentage of Pilgrim Station's output to Commonwealth Electric Company (Commonwealth), Montaup Electric Company (Montaup) and various municipalities under long-term contracts. Under these contracts, the utilities and municipalities pay their proportionate share of the costs of operating the station and associated transmission facilities. The long-term power sales contracts with Commonwealth and Montaup will be terminated upon the closing of the sale of Pilgrim Station to Entergy. The contracts with the municipalities remain in place whereby Boston Edison will purchase power for resale to the municipalities under a purchase power agreement entered into with Entergy. Refer to Notes K and L to the Consolidated Financial Statements in Item 8 for more information regarding these contracts.
New England Power Pool
Boston Edison is a member of NEPOOL, a voluntary association of electric utilities and other electricity suppliers in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region. To obtain maximum benefits of power pooling, the electric facilities of all member companies are
directed by an Independent System Operator (ISO New England) as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest-priced generation and transmission equipment available at any given time. NEPOOL's goal is to ensure a reliable energy supply for the New England region at the lowest possible price.
During 1997, the power pool was restructured with changes taking effect to the membership and governance provisions of the power pooling agreement along with the transfer of operating responsibility of the integrated transmission and generation system in New England to ISO New England. Previously, NEPOOL dispatched generating units for operation based on the lowest operating costs of available generation and transmission. Under the new structure, generators will be required to provide ISO New England with market prices at which they will sell short-term energy supply. These prices will form the basis for dispatch anticipated to begin in the second quarter of 1999. As noted in the Purchased Power Contracts section above, Boston Edison will receive all of its power supply requirements from Select in 1999. Therefore, the change to NEPOOL's operations and pricing structure is expected to have no material impact on Boston Edison's costs for purchased electric energy.
Item 3.
Item 3. Legal Proceedings - - - - - - - - - - - - - - - - - --------------------------
Industry and corporate restructuring legal proceedings
The DTE order approving the Boston Edison settlement agreement and the DTE order approving the formation of BEC as a holding company were appealed by certain parties to the Massachusetts Supreme Judicial Court (SJC). In December 1998, the SJC dismissed the appeal of the order approving the holding company formation. One settlement agreement appeal remains pending, however there has to date been no briefing, hearing or other action taken with respect to this proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston Edison has been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional.
Management is currently unable to determine the outcome of these outstanding proceedings or the impact the proceedings may have on its consolidated results of operations.
A referendum seeking repeal of the Massachusetts electric industry restructuring legislation that was enacted in November 1997 was overwhelmingly defeated by a better than 70% to 30% margin in a state-wide general election held on November 3, 1998. This outcome allows the comprehensive framework established for the restructuring of the electric industry to continue as intended under the enacted legislation.
Regulatory proceedings
In October 1997, the DTE opened a proceeding to investigate Boston Edison's compliance with the 1993 order which permitted the formation of BETG and authorized Boston Edison to invest up to $45 million in unregulated activities. Hearings began in the fourth quarter of 1998 and are expected to be completed in the first half of 1999.
Each of the Reading Municipal Light Department, the Littleton Electric Light Department and the West Boylston Municipal Light Department have filed
separate claims for arbitration in Massachusetts alleging that the proposed transfer of Pilgrim Station constitutes a breach of their respective power sale agreements and seeking to terminate those agreements. The remaining municipal light departments have also indicated that they plan to file similar claims for arbitration. Boston Edison has requested the FERC to exercise its pre-emptive authority to consider the claims of the municipal light departments. In the event that either the FERC determines, or as a result of the arbitrations, that the contracts should be terminated, Boston Edison would continue to be obligated to purchase power from Entergy that it intended to resell to the municipal light departments. Boston Edison may not be able to resell such power in the short-term power exchange at a price equal to or greater than the price it is required to pay to Entergy. However, Boston Edison has filed at the DTE for recovery of any such shortfall as part of its Pilgrim divestiture filing through the transition charge.
Management is currently unable to determine the outcome of these proceedings or the impact these proceedings may have on its consolidated financial position or results of operations.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Station, filed suit against Boston Edison. The town claimed that Boston Edison wrongfully failed to execute an agreement with the town for payments in addition to taxes due to the town under the Massachusetts electric industry restructuring legislation. Boston Edison and the town agreed on a 15-year, $141 million property tax package in March 1999. Payments in each of the first four years are approximately $15 million after which payments gradually decline. All payments under this agreement will be recovered from customers through the transition charge.
In the normal course of its business BEC and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders - - - - - - - - - - - - - - - - - ------------------------------------------------------------
There were no matters submitted to a vote of security holders during the fourth quarter of 1998.
Executive Officers of the Registrant - - - - - - - - - - - - - - - - - ------------------------------------
The names, ages, positions and business experience during the past five years of all the executive officers of BEC Energy (Boston Edison, prior to May, 1998) as of March 1, 1999 are listed below. There are no family relationships between any of the officers, nor any arrangement or understanding between any officer and another person pursuant to which the position as officer is held. Officers hold office until the first meeting of the trustees following the next annual meeting of the stockholders and until their respective successors are chosen and qualified.
Part II -------
Item 5.
Item 5. Market for the Registrant's Common Stock and Related Stockholder - - - - - - - - - - - - - - - - - ------------------------------------------------------------------------- Matters - - - - - - - - - - - - - - - - - -------
(a) Market Information - - - - - - - - - - - - - - - - - ----------------------
BEC's common stock is listed on the New York and Boston Stock Exchanges.
The high and low market value per share of common stock as reported in the Wall Street Journal for each of the quarters in 1998 and 1997 was as follows. (Prior to May 1998, the information listed refers to Boston Edison common stock.)
(b) Holders - - - - - - - - - - - - - - - - - -----------
As of March 26, 1999, there were 29,234 holders of BEC common stock.
(c) Dividends - - - - - - - - - - - - - - - - - -------------
Dividends declared per share of common stock for each of the quarters in 1998 and 1997 were as follows. (Prior to May 1998, the information listed refers to Boston Edison common stock.)
Item 6.
Item 6. Selected Financial Data - - - - - - - - - - - - - - - - - --------------------------------
The following table summarizes five years of selected consolidated financial data (in thousands, except per share data).
Item 7.
Item 7. Management's Discussion and Analysis - - - - - - - - - - - - - - - - - ---------------------------------------------
Merger with COM/Energy
The utility industry has continued to change in response to the marketplace demands for improved customer service and lower prices for energy. These pressures have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. On December 5, 1998, BEC Energy (BEC) and Commonwealth Energy System (CES), headquartered in Cambridge, Massachusetts, entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, BEC and CES will be merged into a new holding company which has not yet been named (Newco). Holders of BEC common shares will receive one share of Newco common stock for each share held while CES common shareholders will receive 1.05 shares of Newco common stock for each share held. Alternatively, current BEC and CES common shareholders have the right to receive $44.10 of cash for each share held, up to an aggregate maximum of $300 million. At the close of the merger, BEC shareholders are expected to own approximately 68% of Newco common stock and CES shareholders are expected to own approximately 32%. The merger is expected to occur shortly after the satisfaction of certain conditions, including the receipt of certain regulatory approvals including that of the Massachusetts Department of Telecommunications and Energy (DTE). The regulatory approval process is expected to be completed during the second half of 1999.
The merger will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities.
The Merger Agreement may be terminated under certain circumstances, including by any party if the merger is not consummated by December 5, 1999, subject to an automatic extension of six months if the requisite regulatory approvals have not yet been obtained by such date. The merger will be accounted for using the purchase method of accounting.
Upon effectiveness of the merger, Thomas J. May, BEC's current Chairman, President and Chief Executive Officer (CEO), will become the Chairman and CEO of Newco. Russell D. Wright, CES' current President and CEO, will become the President and Chief Operating Officer of Newco and will serve on Newco's board of trustees. Also, upon the effective date of the merger, Newco's board of trustees will consist of BEC's and CES' current trustees.
Retail Access
BEC's electric utility subsidiary, Boston Edison Company (Boston Edison) has been anticipating and responding to the changes in the electric energy business as a result of industry restructuring proceedings at both federal and state levels. In January 1998, the DTE approved Boston Edison's restructuring settlement agreement. The DTE found that the settlement agreement substantially complied or was consistent with key provisions of a Massachusetts law enacted in November 1997 establishing a comprehensive framework for the restructuring of the electric utility industry. Prior to this settlement agreement, retail electric customers within Boston Edison's service territory received all services related to the provision of electricity from Boston Edison. This included the procurement of the electricity supply (either through purchase contracts or generation) and the transmission and distribution to customers' facilities. Major provisions of
the settlement agreement included the ability for retail electric customers to choose their electricity supplier (referred to as retail access) effective March 1, 1998 (the retail access date). Boston Edison will continue to provide all transmission and distribution of electricity services to all of its retail customers. Under its settlement agreement, Boston Edison provides standard offer service to all customers of record as of the retail access date. Customers continuing to buy electricity under the standard offer are receiving service at rates designed to give 10% savings from the rates in effect prior to the retail access date. These standard offer customers will realize an additional 5% average savings, after an adjustment for inflation, by September 1, 1999. Boston Edison expects to be able to meet this additional rate reduction as a result of the divestiture of the fossil generating assets which is discussed below. The proceeds from the divestiture are being utilized to reduce customer rates. New retail customers in the Boston Edison service territory and previously existing customers that are no longer eligible for the standard offer due to choosing a competitive supplier are on default service. Refer also to the Electric revenues section for more information.
Generating Assets Divestiture
The Boston Edison restructuring settlement agreement included a provision for the divestiture of its fossil generating assets no later than six months after the retail access date. On May 15, 1998, Boston Edison completed the sale of its non-nuclear generating assets to Sithe Energies, Inc. (Sithe). Boston Edison received proceeds from the sale of $655 million, including $121 million for a six-month transitional power purchase contract. The amount received above net book value on the sale of these assets is being returned to Boston Edison's customers over the settlement period. That amount is partially offset by certain costs recoverable from customers due to the support of standard offer service provided by Boston Edison's fossil generating assets prior to the divestiture.
In April 1998, Boston Edison began soliciting expressions of interest for the sale of its nuclear generating unit, Pilgrim Nuclear Power Station (Pilgrim) as part of the previously announced strategy to exit the generation business. On November 19, 1998, Boston Edison announced that Entergy Nuclear Generating Company (Entergy), a subsidiary of New Orleans-based Entergy Corporation, had been selected as the winning bidder for Pilgrim. In the nation's first competitive bid process for a nuclear power plant, Entergy is expected to purchase Pilgrim in a deal valued at an estimated $121 million. In addition, under the agreement Boston Edison will fully fund and transfer its decommissioning trust fund to Entergy and Entergy will then assume full liability and responsibility for decommissioning the Pilgrim site. A purchase and sale agreement has been signed and all required approvals are anticipated in the second quarter of 1999. The purchase price includes reimbursement for certain costs to be expended by Boston Edison in 1999. Therefore, the actual proceeds could be impacted by the ultimate timing of the transaction.
As part of a benefits package offered to employees affected by the nuclear divestiture, eligible non-represented nuclear and designated nuclear support employees were offered unreduced retirement and transition benefits under a voluntary early retirement program (VERP). Sixteen employees elected to participate in the VERP. A retention benefit program was offered to all non- represented nuclear and designated nuclear support employees that did not elect or were ineligible to retire under the VERP who continue to work through the sale closing date. It is anticipated that approximately 300 non- represented nuclear and designated nuclear support employees will receive one- time retention payments under this program. Costs associated with the VERP
and retention program are recoverable under Boston Edison's settlement agreement.
For more information on the nuclear divestiture refer to the November 23, 1998 BEC or Boston Edison Report on Form 8-K announcing the purchase and sale agreement with Entergy.
BEC Energy
Boston Edison received final approval of its reorganization plan to form a holding company structure from the Securities and Exchange Commission (SEC) in May 1998. Effective May 20, 1998, BEC was formed with Boston Edison as a wholly owned subsidiary of BEC. Effective June 25, 1998, Boston Energy Technology Group (BETG) ceased being a subsidiary of Boston Edison and became a wholly owned subsidiary of BEC. The holding company structure clearly separates the unregulated and regulated operations of BEC and provides management with greater organizational flexibility in order to take advantage of utility and nonutility business opportunities in a more timely manner, including the merger with CES.
Joint Ventures
Unregulated activities continue to be conducted through BETG. During 1997, BETG entered into two joint venture agreements. BETG's joint venture agreement with RCN Telecom Services, Inc. (RCN) established a limited liability company (LLC) that competes directly with local and long-distance telephone, video and Internet access companies for telecommunications-related services. BETG owns 49% of the LLC while RCN owns 51% and maintains day-to- day management responsibility. As part of the joint venture agreement, BETG has the option to exchange certain portions of its joint venture interest for shares of RCN Corporation common stock. During 1998, BETG exercised its option to convert a portion of its interest with a cost of $11 million. BETG expects to receive approximately 1.1 million RCN Corporation common shares during the first quarter of 1999.
BETG also established an energy marketing venture with Williams Energy Services Company (WESCO), a subsidiary of The Williams Companies, Inc. in 1997. In August 1998, BEC and WESCO entered into an agreement to transfer BETG's 50% interest in their joint venture to WESCO. This transaction did not have a material impact on BEC's consolidated financial position or results of operations.
Results of Operations
1998 versus 1997
Basic and diluted earnings per common share were $2.76 and $2.75, respectively in 1998 compared to $2.71 and $2.71 in 1997, a 1.8% increase in basic earnings as described below.
Operating revenues
Operating revenues decreased 8.8% from 1997 as follows:
Retail revenues reflect the impact of the mandated 10% retail rate reduction. A 2.0% increase in retail kilowatt-hour (kWh) sales in 1998 partially offset the impact of the rate reduction. Retail revenues also reflect a decrease due to the timing effect of fuel and purchased power cost recovery. Prior to its cessation as of March 1, 1998, the fuel clause charge was lower than the prior year as the 1997 charge reflected the recovery of substantial prior year undercollections. Fuel clause revenues were offset by fuel and purchased power expenses and, therefore, had no net effect on earnings.
The net decrease in short-term sales and other revenues reflects an 11% decrease in short-term kWh sales. This decrease is due to the expiration of certain short-term sales contracts. This decrease has no net impact on earnings as it is offset by a corresponding decrease in fuel and purchased power expenses. The decrease in short-term sales was partially offset by an increase in other revenues which reflects the recovery of certain costs through the transition charge due to the support of standard offer service provided by Boston Edison's fossil generating assets prior to divestiture.
Operating expenses
Fuel and purchased power expense decreased $111.3 million. This decrease is the result of significantly lower company fuel costs due to the fossil divestiture in May 1998. These costs were partially offset by a net increase in purchased power subsequent to the divestiture. Purchased power costs include the six-month transitional power purchase contract with Sithe Energies that began in May. The capacity portion of the Sithe purchased power costs is offset by the recognition of the payment from Sithe, resulting in a corresponding reduction to purchased power expense. The timing effect of the fuel and purchased power and standard offer cost collection mechanisms also contributed to the decrease in fuel and purchased power expense.
Operations and maintenance expense decreased approximately $37 million. The decrease is due to the impact of the fossil divestiture, lower employee benefit expenses and lower nuclear spending. The decrease in nuclear spending reflects the impact of the refueling outage in 1997. The comparison of 1998 and 1997 is also positively impacted by the severe April 1997 Boston area storm.
The increase in depreciation and amortization is due to an increase in the composite distribution depreciation rate and the timing of recovery of generation-related assets under the settlement agreement. These increases were partially offset by an $8.7 million nonrecurring charge recorded in 1997 to reflect the removal of specific nuclear-related intangible assets from the balance sheet. These intangible assets related to costs incurred for plant design and safety studies. These studies were superceded by updated studies.
The increase in demand side management (DSM) and renewable energy programs expense reflects an increase in the required spending for DSM programs in 1998. In addition, the renewable energy programs expense is the result of a new state mandate for the funding of renewable energy that became effective March 1, 1998. Renewable energy expenses are collected through a separate rate mechanism and, therefore, have no net effect on earnings.
The decrease in property and other taxes is due to the decrease in municipal property taxes resulting from the fossil divestiture.
The increase in operating income taxes is the result of a reduction in investment tax credit amortization due to the divestiture of the fossil generating assets and certain non-deductible expenses incurred at BETG. Refer
to Note C to the Consolidated Financial Statements for more information on income taxes.
Other income (expense), net
The increase in other expense, net reflects higher BETG equity losses as its joint venture with RCN began operations in the second quarter of 1997. 1998 also includes certain costs related to the fossil divestiture, net of the related tax benefits, offset by the recognition of previously deferred investment tax credits associated with the fossil generating stations. 1997 results reflect the charge of approximately $8 million, after tax, from the nuclear asset impairment which is further discussed in Note B to the Consolidated Financial Statements.
Interest charges
Interest charges on long-term debt decreased due to the maturing of $100 million of 5.95% debentures in March 1998 and the cessation of amortization of the associated redemption premiums and the redemption of a $100 million 6.662% bank loan in June 1998.
The decrease in short-term interest charges is due to the redemption of Boston Edison's outstanding short-term debt with proceeds from the fossil divestiture. This was partially offset by interest charges from BEC's line of credit entered into in 1998.
Preferred stock dividends
Preferred stock dividends decreased as a result of Boston Edison's redemption of 40,000 shares of 7.27% series cumulative preferred stock in May 1998 and 1997, the remaining 320,000 shares of the 7.27% series and 400,000 shares of 7.75% series cumulative preferred stock in July 1998 and 400,000 shares of 8.25% series in June 1997. Refer to Note G to the Consolidated Financial Statements.
1997 versus 1996
Basic and diluted earnings per common share were $2.71 in 1997 compared to $2.61 in 1996, a 3.8% increase as described below.
Operating revenues
Operating revenues increased 6.6% over 1996 as follows:
Retail base revenues, consistent with the 0.8% increase in kWh sales in 1997, were relatively flat compared to 1996. Increases due to warmer than normal temperatures in June and July, cooler temperatures in October and December and the stronger local economy were offset by milder than normal winter conditions during the first quarter of 1997 and lower industrial sales. Industrial sales continued to be adversely affected by the decline in manufacturing activity in the Boston Edison service territory. In addition, revenues in 1996 reflect one more day of sales due to the leap year. Total retail electric revenues increased $88.5 million primarily due to the timing effect of fuel and
purchased power cost recovery. The increase in fuel and purchased power clause revenues reflect the recovery of substantial prior year undercollections. These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect on earnings. Pilgrim performance revenues, which varied annually based on the operating performance of Pilgrim Station prior to the retail access date, decreased due to a lower annual capacity factor effective November 1996 reflecting the scheduled refueling and maintenance outage in the first quarter of 1997.
Short-term sales revenues increased approximately $16 million. This was due to the continued reduction in available nuclear energy supply in New England combined with a 42% increase in fossil generation allowing for increased sales to the power exchange. Revenues from these short-term sales resulted in a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, had no net effect on earnings.
Operating expenses
Fuel and purchased power expenses increased $90.2 million. This increase reflects $57 million related to the timing effect of fuel and purchased power cost recovery. In addition, company fuel expense increased $50 million primarily due to the 42% increase in fossil generation. These increases were partially offset by a $22 million decrease in power exchange purchases. These fuel and purchased power expenses are substantially recoverable through fuel and purchased power revenues.
Operations and maintenance expense increased $0.4 million from 1996. The incremental impact associated with service restoration efforts resulting from the severe snow storm in April 1997 that struck the greater Boston area offset the impact of lower spending from cost control efforts and significantly less overhaul activity at the fossil generating units.
The increase in depreciation and amortization expense is due to the net impact of two depreciation adjustments. An $8.7 million nonrecurring charge was recorded to depreciation expense in the third quarter of 1997 to reflect the removal of specific nuclear-related intangible assets from the balance sheet. These intangible assets related to costs incurred for plant design and safety studies. These studies were superceded by updated studies. In 1996 a $5.2 million adjustment was recorded to correct the accumulated depreciation balance of certain large computer equipment.
Income taxes increased as a result of higher net income offset by the impact of the favorable outcome of an Internal Revenue Service (IRS) appeal received in the third quarter related to investment tax credits (ITC). This also resulted in an increase in unamortized ITC which is being reflected as a reduction to income tax expense over the life of the related assets. Refer to Note C to the Consolidated Financial Statements for more information on income taxes.
Other income (expense), net
Other expense, net in 1997 reflects the charge of approximately $8 million, after tax, from the nuclear asset impairment which is further discussed in Note B to the Consolidated Financial Statements in addition to BETG equity losses. These decreases were partially offset by approximately $3 million, after tax, in interest income from the IRS appeal.
Interest charges
Total interest charges on long-term debt decreased due to the maturing of $100 million of 5.70% debentures in March 1997 and the cessation of amortization of the associated redemption premiums. This was partially offset by the March 1997 issuance of a $100 million 6.662% bank loan due in 1999. The decrease also reflects the maturity of $100 million of 5 1/8% debentures in March 1996.
Allowance for borrowed funds used during construction (AFUDC), which represents the financing costs of construction, decreased primarily due to a lower average construction work in progress (CWIP) balance in 1997. The 1996 average CWIP balance included nuclear fuel purchased in anticipation of Pilgrim Station's scheduled refueling outage in the first quarter of 1997.
Preferred stock dividends
The decrease in preferred stock dividends is the result of the redemption of 20,000 of mandatory and 20,000 of optional shares of 7.27% series cumulative preferred stock in May 1997 and 400,000 shares of 8.25% series in June 1997. Refer to Note G to the Consolidated Financial Statements.
Electric Sales and Revenues
Electric sales
Total kWh sales increased 2.3%. The 2.0% increase in 1998 retail kWh sales was primarily due to the positive impact of a continued strong local economy on commercial customers. The commercial sector represents approximately 50% of electric operating revenues. The Boston area commercial office vacancy rate is at a 17-year low. In addition, the Massachusetts employment rate increased 2.8% over 1997. These positive impacts associated with the economic conditions along with warmer than normal summer weather were partially offset by the mild winter weather conditions in the first quarter of 1998. Wholesale sales increased primarily due to a 32% increase in sales to Pilgrim contract customers. That increase reflects a 97% capacity factor in 1998, the plant's highest annual performance ever achieved. The lower level of sales in 1997 reflected that year's refueling outage. Short-term sales decreased due to lower sales to other contract customers.
Retail kWh sales increased 0.8% in 1997. This was primarily attributable to the commercial sector. The commercial increase reflects the impact of a continued strong economy in the Boston area and very warm temperatures in June and July and cooler than normal temperatures in the fourth quarter. Hotel occupancy rates and non-manufacturing employment continued to increase in 1997. Residential revenues were also positively impacted by the weather. These positive impacts were offset by milder winter weather in the first quarter of 1997 and declines in manufacturing employment affecting the industrial sector. In addition, revenues in 1996 reflect one more day of sales due to the leap year. Total kWh sales increased 3.1% as a result of the continued reduction in available nuclear energy supply in New England. This reduction, combined with an increase in fossil generation allowed for increased sales to the power exchange.
Electric revenues
Boston Edison's electric delivery business provides standard offer customers service at rates designed to give 10% savings from the rates in effect prior to the retail access date. As part of the Massachusetts restructuring legislation enacted in November 1997, these customers will realize an
additional 5% average savings, after an adjustment for inflation, by September 1, 1999. Boston Edison expects to meet this additional rate reduction as a result of the proceeds received from the divestiture of the fossil generating assets. All Boston Edison distribution customers must pay a transition charge as a component of distribution electric rates. The purpose of the transition charge is to allow Boston Edison to collect certain costs from customers which would not be collected in the competitive energy supply market. Such costs include the above market costs related to purchased power contracts and its own generating stations, as well as the cost to decommission Pilgrim Station. The plant and regulatory asset balances which will be recovered through the transition charge until 2009 were approved by the DTE. The other costs will be reviewed by the DTE on an annual basis. Under the settlement agreement, the aggregate amount of the transition charge is reduced by the net proceeds from fossil divestiture. The cost of providing standard offer service, which includes fuel and purchased power costs, is recovered from customers on a fully reconciling basis. The price of default service is intended to reflect the average competitive market price for power.
As part of the settlement agreement, the annual performance adjustment charge ceased and the cost recovery mechanism for Pilgrim Station changed effective March 1, 1998. Approximately 25% of the operations and capital costs, including a return on investment, continues to be collected under wholesale contracts with other utilities and municipalities. Boston Edison's long-term power sales contracts with the utilities, Commonwealth Electric Company and Montaup Electric Company, will be terminated upon the closing of the sale of Pilgrim Station to Entergy. Boston Edison's contracts with the various municipalities remain in place. However, upon the Pilgrim sale closing date, Boston Edison will purchase power for resale to the municipalities under a purchase power agreement entered into with Entergy. Through the sale closing date, Boston Edison will share 25% of any profit or loss from the sale of Pilgrim's output with distribution customers through the transition charge. In addition, Boston Edison will obtain transition payments up to a maximum of $23 million per year depending on the level of costs incurred for such items as property taxes, insurance, regulatory fees and security requirements.
Under its settlement agreement, Boston Edison's distribution rates will remain unchanged through December 31, 2000, subject to a minimum and maximum return on average common equity (ROE). The ROE is subject to a floor of 6% and a ceiling of 11.75%. If the ROE is below 6%, Boston Edison is authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE is above 11%, it is required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment is made if the ROE is between 6% and 11%. The cost of providing transmission service to distribution customers is recovered on a fully reconciling basis.
Boston Edison filed proposed adjustments to its standard offer and transition charges with the DTE in November 1998. The DTE approved these proposed adjustments to be effective January 1, 1999. The DTE is continuing to examine Boston Edison's cost recovery mechanisms. The rates provide an approximate 12% reduction from inflation-adjusted pre-retail access date rates.
Liquidity
Cash requirements for utility plant expenditures have been met in recent years with internally generated funds. These funds are cash flows from operating activities, adjusted to exclude changes in working capital and the payment of dividends. During 1998, 1997 and 1996 internal generation of cash provided 97%, 211% and 177%, respectively of plant expenditures. The capital spending
level, excluding nuclear fuel, forecasted for 1999 is $233 million which includes amounts for utility plant and the capital requirements of the nonutility ventures. This spending level also includes the 1999 portion of business system replacements discussed below. The capital spending level over the next five years is forecasted to be approximately $960 million. In addition to capital expenditures, debt and preferred stock payment requirements are $1.6 million in 1999, $166.6 million in 2000, $51.6 million in 2001, $1.6 million in 2002 and $151.65 million in 2003.
Boston Edison supplements internally generated funds as needed, primarily through the issuance of short-term commercial paper and bank borrowings. Boston Edison has authority from the Federal Energy Regulatory Commission (FERC) to issue up to $350 million of short-term debt. Boston Edison has a $200 million revolving credit agreement with a group of banks as well as other arrangements with several banks to provide additional short-term credit on an uncommitted and as available basis.
In December 1998, Boston Edison filed a securitization financing plan with the DTE. Under the plan, a special purpose entity (SPE) will be formed as a wholly owned subsidiary of Boston Edison. The SPE will pay Boston Edison an amount equal to certain generation-related regulatory assets by issuing debt securities. A portion of the net proceeds will be used to fund the nuclear decommissioning trust. In addition, Boston Edison may also utilize a portion of the proceeds to reduce capitalization and for general corporate purposes. Boston Edison will remit amounts to the SPE as these amounts are collected from customers through a separate component of the transition charge over the settlement period. A DTE order regarding the securitization plan is expected by the second quarter of 1999.
BEC established a $225 million revolving credit agreement with a group of banks effective through July 2001. The purpose of the credit agreement is to provide financing to the holding company for general corporate purposes, invest in its subsidiaries and fund the common share repurchase program discussed below. Approximately $78 million was outstanding under this agreement as of December 31, 1998.
In April 1998, Boston Edison announced a common share repurchase program under which it would repurchase up to four million of its common shares. BEC has assumed this program since the reorganization to a holding company structure. Through December 31, 1998, approximately 1.3 million shares have been repurchased. Under this program, shares are repurchased through open market, block or privately-negotiated transactions, or a combination. The timing and actual number of shares repurchased will be impacted by market conditions.
Year 2000 Computer Issue
The year 2000 issue is the result of computer programs that were written using two digits rather than four to define an applicable year. If computer programs with date-sensitive functions are not year 2000 compliant, they may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in system failures or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions and engage in other normal business activities. BEC has a year 2000 program in place to address the risk of non-compliant internal business software, internal non-business software and embedded chip technology and external noncompliance of third parties.
BEC is addressing the year 2000 issue on a coordinated basis. BEC has inventoried and assessed all date-sensitive information and transaction
processing computer systems and has determined that approximately one-third of business critical systems software need modification or replacement. BEC defines its business critical systems as those which are necessary for the delivery of and billing and accounting for electricity to its customers. Plans have been developed and are being implemented to correct and test all affected systems, with priorities assigned based on the importance of the supported activity. As systems are being remediated or replaced, they are tested for operational and year 2000 compliance in their own environment. After completion of implementation, the systems are then tested for their integration and compliance with other interactive systems. Management estimates that approximately 70% of the efforts necessary to implement and test its critical computer systems to alleviate the year 2000 issue are complete and expects to complete all efforts by the end of the second quarter of 1999. Management expects to complete the remediation, replacement and testing of all other computer systems during the third quarter of 1999.
BEC has also inventoried its non-information technology systems that may be date-sensitive and that use embedded technology such as micro-controllers or micro-processors. The three categories of systems are (1) telecommunications, (2) distribution system controls and (3) other distribution equipment. BEC is 55%, 100% and 80% complete, respectively, with its efforts to resolve and remediate the systems that have been identified as year 2000 non-compliant within each category. BEC expects completion of resolution and testing by the end of the second quarter of 1999.
Costs incurred to remediate non-compliant systems are expensed as incurred. In addition, a decision has been made to use this opportunity to upgrade some of BEC's inefficient centralized business systems. Systems' replacement costs will be capitalized and amortized over future periods. BEC expects the modification and testing of its information and transaction processing systems to cost $32 million. BEC has expended $19 million on this project through December 31, 1998. BEC has funded and plans on continuing to fund all costs related to year 2000 with internally generated cash flows.
In addition to its internal efforts, BEC has initiated formal communications with its significant suppliers, service providers and other vendors to determine the extent to which BEC may be vulnerable to their failure to correct their own year 2000 issues. BEC has received responses from all business critical vendors. All of these vendors have indicated that they will be year 2000 compliant by the end of the fourth quarter of 1999. Many third parties have indicated to BEC that they are already year 2000 compliant. In addition, BEC has contacted all of its significant power suppliers. Each has indicated that they either are or will be year 2000 compliant by the end of the fourth quarter of 1999. In addition to the risk faced from its dependence on third party suppliers for year 2000 compliance, BEC has a risk that power will not be available from the New England Power Pool (NEPOOL) for the purchase and distribution to Boston Edison's customers. Should NEPOOL fail to resolve its year 2000 issues as planned, there would be an adverse impact on Boston Edison and its customers. To mitigate this risk, efforts are being coordinated with NEPOOL to establish inter-utility testing guidelines to determine year 2000 readiness. Boston Edison is also a participant in the NEPOOL/ISO New England Year 2000 Joint Oversight Committee which has responsibility for the operational reliability of NEPOOL. Overall regional activities, including those of NEPOOL/ISO New England, will be coordinated by the Northeast Power Coordinating Council, whose activities will be incorporated into the interregional coordinating effort by the North American Electric Reliability Council. The target for the completion of this effort is mid-1999.
In addition, parts of the global infrastructure, including national banking systems, electrical power grids, gas pipelines, transportation facilities, communications and government activities, may not be fully functional after 1999 due to the year 2000 issue. Infrastructure failures could significantly reduce BEC's ability to acquire energy and its ability to serve its customers as effectively as they are now being served.
BEC believes that its efforts to address the year 2000 issue will allow it to successfully avoid any material adverse effect on its operations or financial condition. However, it recognizes that failing to resolve year 2000 issues on a timely basis would, in a most reasonable worst case scenario, significantly limit its ability to acquire and distribute energy or process its daily business transactions for a period of time, especially if such failure is coupled with third party or infrastructure failures. Similarly, BEC could be significantly affected by the failure of one or more significant suppliers, customers or components of the infrastructure to conduct their respective operations normally after 1999. Adverse effects on BEC could include, among other things, business disruption, increased costs, loss of business and other similar risks.
BEC's year 2000 program includes contingency plans. If required, these plans are intended to address both internal risks as well as potential external risks related to vendors, customers and energy suppliers. Plans have been developed in conjunction with available national and regional guidance and are based on system emergency plans that were developed and successfully tested over the past several years. Included within its contingency plans are procedures for the procurement of short-term power supplies and emergency distribution system restoration procedures.
The foregoing discussion regarding year 2000 project timing, effectiveness, implementation and costs includes forward-looking statements that are based on management's current evaluation using available information. Factors that might cause material changes include, but are not limited to, the availability of key year 2000 personnel, the readiness of third parties and BEC's ability to respond to unforeseen year 2000 complications.
Other Matters
Environmental
Boston Edison is an owner or operator of approximately 20 properties where oil or hazardous materials were spilled or released. Boston Edison also continues to face possible liability as a potentially responsible party in the cleanup of five multi-party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Refer to Note K.4. to the Consolidated Financial Statements for more information regarding hazardous waste issues.
Uncertainties continue to exist with respect to the disposal of both spent nuclear fuel and low-level radioactive waste resulting from the operation of nuclear generating facilities. The United States Department of Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel. However, uncertainties regarding the DOE's schedule of acceptance of spent fuel for disposal continue to exist. Under the purchase and sale agreement with Entergy, Entergy will assume full liability and responsibility for decommissioning and waste disposal at Pilgrim Station. Refer to Note D to the Consolidated Financial Statements for further discussion regarding nuclear decommissioning and waste disposal.
Public concern continues regarding electromagnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Such concerns have included the possibility of adverse health effects caused by EMF as well as perceived effects on property values. Some scientific reviews conducted to date have suggested associations between EMF and potential health effects, while other studies have not substantiated such associations. The National Research Council previously reported that there is no conclusive evidence that exposure to EMF from power lines and appliances presents a health hazard. The panel of scientists, working with the National Academy of Sciences, report that more than 500 studies over the last several years have produced no proof that EMF causes leukemia or other cancers or harms human health in other ways. Boston Edison continues to support research into the subject and participates in the funding of industry-sponsored studies. It is aware that public concern regarding EMF in some cases has resulted in litigation, in opposition to existing or proposed facilities in proceedings before regulators or in requests for legislation or regulatory standards concerning EMF levels. It has addressed issues relative to EMF in various legal and regulatory proceedings and in discussions with customers and other concerned persons; however, to date it has not been significantly affected by these developments. Boston Edison continues to monitor all aspects of the EMF issue.
Industry and corporate restructuring legal proceedings
The DTE order approving the Boston Edison settlement agreement and the DTE order approving the formation of BEC as a holding company were appealed by certain parties to the Massachusetts Supreme Judicial Court (SJC). In December 1998, the SJC dismissed the appeal of the order approving the holding company formation. One settlement agreement appeal remains pending, however there has to date been no briefing, hearing or other action taken with respect to this proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston Edison has been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional.
Management is currently unable to determine the outcome of these outstanding proceedings or the impact the proceedings may have on its consolidated results of operations.
Regulatory proceedings
In October 1997, the DTE opened a proceeding to investigate Boston Edison's compliance with the 1993 order which permitted the formation of BETG and authorized Boston Edison to invest up to $45 million in unregulated activities. Hearings began in the fourth quarter of 1998 and are expected to be completed in the first half of 1999.
Each of the Reading Municipal Light Department, the Littleton Electric Light Department and the West Boylston Municipal Light Department have filed separate claims for arbitration in Massachusetts alleging that the proposed transfer of Pilgrim Station constitutes a breach of their respective power sale agreements and seeking to terminate those agreements. The remaining municipal light departments have also indicated that they plan to file similar claims for arbitration. Boston Edison has requested the FERC to exercise its pre-emptive authority to consider the claims of the municipal light departments. In the event that either the FERC determines, or as a result of
the arbitrations, that the contracts should be terminated, Boston Edison would continue to be obligated to purchase power from Entergy that it intended to resell to the municipal light departments. Boston Edison may not be able to resell such power in the short-term power exchange at a price equal to or greater than the price it is required to pay to Entergy. However, Boston Edison has filed at the DTE for recovery of any such shortfall as part of its Pilgrim divestiture filing through the transition charge.
Management is currently unable to determine the outcome of these proceedings or the impact these proceedings may have on its consolidated financial position or results of operations.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Station, filed suit against Boston Edison. The town claims that Boston Edison has wrongfully failed to execute an agreement with the town for payments in addition to taxes due to the town under the Massachusetts electric industry restructuring legislation. Boston Edison has disputed the town's claim and will vigorously defend itself. In addition to this pending litigation, Boston Edison and the town of Plymouth are also parties in proceedings before the Appellate Tax Board and the DTE concerning substantially the same dispute. Management is unable to determine the ultimate outcome of these proceedings or the impact they may have on its consolidated financial position or results of operations.
In the normal course of its business BEC and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
Refer to Note K.6. to the Consolidated Financial Statements for more information on legal matters.
Interest rate risk
BEC is exposed to changes in interest rates. Carrying amounts and fair values of mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt as of December 31, 1998, are as follows:
Safe harbor cautionary statement
BEC occasionally makes forward-looking statements such as forecasts and projections of expected future performance or statements of its plans and objectives. These forward-looking statements may be contained in filings with
the SEC, press releases and oral statements. Actual results could potentially differ materially from these statements. Therefore, no assurances can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about the merger with CES, the divestiture of nuclear generating assets, operating results, year 2000 and environmental and legal issues.
The merger with CES could differ from current expectations. This could occur if the requisite approvals are delayed or not obtained.
The nuclear divestiture plan could differ from current expectations. The timing and a final closing of the sale may differ from management's expectations if required approvals are delayed or not obtained.
The impacts of continued cost control procedures on operating results could differ from current expectations. The effects of changes in economic conditions, tax rates, interest rates, technology and the prices and availability of operating supplies could materially affect the projected operating results.
The timing and total costs related to the year 2000 plan could differ from current expectations. Factors that may cause such differences include the ability to locate and correct all relevant computer codes and the availability of personnel trained in this area. In addition, BEC cannot predict the nature or impact on operations of third party noncompliance.
The impacts of various environmental and legal issues could differ from current expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than expected. The effects of changes in specific hazardous waste site conditions and cleanup technology could affect the estimated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect the estimated litigation costs.
Item 8.
Item 8. Financial Statements and Supplementary Financial Information - - - - - - - - - - - - - - - - - ---------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements
The accompanying notes are an integral part of the consolidated financial statements.
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
1. Nature of Operations
Boston Edison Company (Boston Edison) received final approval of its reorganization plan to form a holding company structure from the Securities and Exchange Commission (SEC) in May 1998. Effective May 20, 1998 the holding company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned subsidiary of BEC.
Within its newly restructured industry, BEC has announced its intention to focus its utility operations on the transmission and distribution of energy. The sale of Boston Edison's fossil generating assets to Sithe Energies, Inc. (Sithe) was completed in May 1998. In November 1998, Boston Edison signed an agreement with Entergy Nuclear Generating Company (Entergy) to sell its wholly owned nuclear generating unit, Pilgrim Nuclear Power Station (Pilgrim). BEC signed a merger agreement with Commonwealth Energy System (CES) in December 1998 that will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities.
Boston Edison currently supplies electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. It also supplies electricity at wholesale for resale to other utilities and municipalities. Electric operating revenues are approximately 90% retail and 10% wholesale. Unregulated activities continue to be conducted through Boston Energy Technology Group (BETG). Refer to Note J to these Consolidated Financial Statements for information on BEC's nonutility operations.
2. Basis of Consolidation and Accounting
Under the new holding company structure the owners of Boston Edison's common stock became BEC common shareholders. Existing debt and preferred stock of Boston Edison remained obligations of the regulated utility business. Effective June 25, 1998, BETG ceased being a subsidiary of Boston Edison and became a wholly owned subsidiary of BEC. The accompanying consolidated financial statements reflect the results of operations and cash flows of Boston Edison prior to the reorganization. The consolidated balance sheet at December 31, 1997 reflects the financial position of Boston Edison which also included BETG. The consolidated financial statements also include the activities of Boston Edison's wholly owned subsidiary, Harbor Electric Energy Company (HEEC). All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year data to conform with the current presentation.
Boston Edison follows accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (DTE). In addition, BEC and its subsidiaries are subject to the accounting and reporting requirements of the SEC. The consolidated financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company Boston Edison has been subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. As a result of the
Massachusetts electric industry restructuring legislation enacted in November 1997 and the DTE order regarding the related Boston Edison settlement agreement, as of December 31, 1997, the provisions of SFAS 71 are no longer being applied to the generation business. The distribution business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71. Refer to Note B to these Consolidated Financial Statements for more information on the accounting implications of the electric utility industry restructuring.
The preparation of financial statements in conformity with GAAP requires BEC 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
Estimates of retail base (transmission and distribution) revenues for electricity used by customers but not yet billed are recorded at the end of each accounting period.
4. Utility Plant
Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.
5. Depreciation and Nuclear Fuel Amortization
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. Excluding the effect of the adjustment discussed below, the overall composite depreciation rates were 3.28%, 3.30% and 3.33% in 1998, 1997 and 1996, respectively.
Upon the completion of a review of Boston Edison's electric generating units, management determined that the oldest and least efficient fossil units (Mystic 4, 5 and 6) were unlikely to provide competitively-priced power beyond the year 2000. Therefore the estimated remaining economic lives of these units was revised to five years in 1996. These units were sold in May 1998. Refer to Note B to these Consolidated Financial Statements.
The cost of decommissioning Pilgrim Station is excluded from depreciation rates. Refer to Note D to these Consolidated Financial Statements for a discussion of nuclear decommissioning. The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station generates. Nuclear fuel expense also includes an amount for the estimated costs of ultimately disposing of spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities.
6. Deferred Nuclear Outage Costs
The incremental costs associated with nuclear refueling and maintenance outages are deferred when incurred and amortized over Pilgrim Station's two- year operating cycle.
7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock
Consistent with the recovery in electric rates, discounts, redemption premiums and related costs associated with the issuance and redemption of long-term debt and preferred stock are deferred. The costs related to long-term debt are recognized as an addition to interest expense over the life of the original or replacement debt. Beginning in 1996, consistent with an accounting order received from the FERC, costs related to preferred stock issuances and redemptions are reflected as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.
8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense. AFUDC rates in 1998, 1997 and 1996 were 5.88%, 6.04% and 5.87%, respectively, and represented only the cost of short-term debt.
9. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased. BEC's banking arrangement does not require it to fund checks until they are presented for payment. Therefore, outstanding checks are included in cash and accounts payable until presented for payment.
10. Allowance for Doubtful Accounts
Accounts receivable are substantially recoverable. This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, a significant allowance for doubtful accounts balance has not been maintained.
11. Regulatory Assets
Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with agreements with regulators. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. Refer to Note B to these Consolidated Financial Statements for information regarding the recovery of regulatory assets related to the generation business.
Regulatory assets consisted of the following:
12. Earnings Per Common Share
Basic earnings per common share (EPS) is calculated by dividing net income, after deductions for preferred dividends, by the weighted average common shares outstanding during the year. Statement of Financial Accounting Standards No. 128, Earnings per Share, requires the disclosure of diluted EPS. Diluted EPS is similar to the computation of basic EPS except that the weighted average common shares is increased to include the number of dilutive potential common shares. Diluted EPS reflects the impact on shares outstanding of the deferred (nonvested) shares and stock options granted under the Stock Incentive Plan.
The following table summarizes the reconciling amounts between basic and diluted EPS:
13. RCN Joint Venture
BETG is a participant in a telecommunications venture with RCN Telecom Services, Inc. (RCN). As part of the joint venture agreement, BETG has the option to exchange certain portions of its joint venture interest for shares of RCN Corporation common stock. During 1998, BETG exercised its option to convert a portion of its interest with a cost of $11 million. BETG expects to receive approximately 1.1 million RCN Corporation common shares during the first quarter of 1999.
Note B. Electric Utility Industry Restructuring
1. Accounting Implications
Under the traditional revenue requirements model, electric rates have been based on the cost of providing electric service. Under this model, Boston Edison has been 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. As a result of the Massachusetts electric industry restructuring legislation enacted in November 1997 and the DTE order regarding Boston Edison's related settlement agreement, as of December 31, 1997, the provisions of SFAS 71 are no longer being applied to the generation business. Under the settlement agreement, approximately 75% of the net assets of Pilgrim Station are recoverable through the non-bypassable transition charge of the utility's distribution business. The distribution business continues to be subject to rate-regulation. The remaining 25% is collected under Pilgrim's wholesale power contracts. The 1998 consolidated balance sheet reflects a reclassification of the Pilgrim net assets recoverable through the transition charge from utility plant to regulatory asset. This Pilgrim regulatory asset, included in the generation- related regulatory asset on the consolidated balance sheet continues to be grouped with utility plant for financial statement presentation.
Completion of the sale of Boston Edison's fossil generating assets took place in May 1998. Boston Edison received proceeds from the sale of $655 million, including $121 million for a six-month transitional power purchase contract. The amount received above net book value on the sale of these assets is being returned to Boston Edison's customers over the settlement period. That amount is partially offset by certain costs recoverable through the transition charge due to the support of standard offer service provided by Boston Edison's fossil generating assets prior to the divestiture. The net deferred gain is included as a reduction to the generation-related regulatory asset on the 1998 consolidated balance sheet. In addition, Boston Edison received $19 million from Sithe for inventory and other closing adjustments.
The implementation of the Boston Edison settlement agreement had certain accounting implications. The highlights of these include:
Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation business, except for those related to Pilgrim's wholesale contracts, are recovered through the transition charge. This recovery, which includes a return, will occur over a twelve-year period that began on March 1, 1998 (the retail access date).
Depreciation
The composite depreciation rate for distribution utility plant increased from 2.38% to 2.98% as of the retail access date.
Fuel and purchased power charge
The fuel and purchased power charge ceased as of the retail access date. The net remaining overcollection of fuel and purchased power costs will be reflected in future customer billings. These over recovered costs are included as an offset to the settlement recovery mechanisms on the 1998 consolidated balance sheet.
Standard offer charge
Customers have the option of continuing to buy power from the electric delivery business at standard offer prices as of the retail access date. The standard offer charge began at 2.8 cents/kWh at the retail access date, increased to 3.2 cents/kWh on June 1, 1998, to 3.69 cents/kWh on January 1, 1999 and is scheduled to increase to 5.1 cents/kWh by 2004. The cost of providing standard offer service, which includes fuel and purchased power costs, is recovered from standard offer customers on a fully reconciling basis.
Distribution and transmission charges
Distribution rates are subject to a minimum and maximum return on average common equity (ROE) through December 31, 2000. The ROE is subject to a floor of 6% and a ceiling of 11.75%. If the ROE is below 6%, Boston Edison is authorized to add a surcharge to distribution rates in order to achieve the 6% floor. If the ROE is above 11%, it is required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment is made if the ROE is between 6% and 11%. In addition, distribution rates will be adjusted for any changes in tax laws or accounting principles that result in a change in costs of more than $1 million. The cost of providing transmission service to distribution customers is recovered on a fully reconciling basis.
Nuclear generation
Under the settlement agreement, the annual performance adjustment charge ceased and the cost recovery mechanism for Pilgrim Station changed effective March 1, 1998. Approximately 25% of the operations and capital costs, including a return on investment, continues to be collected under Pilgrim's wholesale contracts. Through Pilgrim's sale closing date, 25% of any profit or loss from the sale of Pilgrim's output will be shared with distribution customers through the transition charge. In addition, Boston Edison will obtain transition payments up to a maximum of $23 million per year depending on the level of costs incurred for such items as property taxes, insurance, regulatory fees and security requirements.
2. Generating Assets Divestiture
The Boston Edison restructuring settlement agreement included a provision for the divestiture of its fossil generating assets no later than six months after the retail access date. In December 1997, Boston Edison entered into a purchase and sale agreement with Sithe Energies, a privately-held company headquartered in New York, to purchase these non-nuclear generating assets. The sale of these assets was finalized on May 15, 1998.
In April 1998, Boston Edison began soliciting expressions of interest for the sale of its nuclear generating unit, Pilgrim Station as part of the previously announced strategy to exit the generation business. On November 19, 1998, Boston Edison announced the selection of Entergy, a subsidiary of New Orleans- based Entergy Corporation, as the winning bidder for the purchase of Pilgrim. Entergy is expected to purchase Pilgrim in a deal valued at an estimated $121 million. In addition, under the agreement Boston Edison will fully fund and transfer its decommissioning trust fund to Entergy and Entergy will then assume full liability and responsibility for decommissioning the Pilgrim site. A purchase and sale agreement has been signed and all required approvals are anticipated in the second quarter of 1999. The purchase price includes reimbursement for certain costs to be expended by Boston Edison in 1999.
Therefore, the actual proceeds could be impacted by the ultimate timing of the transaction.
As part of a benefits package offered to employees affected by the nuclear divestiture, eligible non-represented nuclear and designated nuclear support employees were offered unreduced retirement and transition benefits under a voluntary early retirement program (VERP). Sixteen employees elected to participate in the VERP. A retention benefit program was offered to all non- represented nuclear and designated nuclear support employees that did not elect or were ineligible to retire under the VERP who continue to work through the sale closing date. It is anticipated that approximately 300 non- represented nuclear and designated nuclear employees will receive one-time retention payments under this program. Costs associated with the VERP and retention program are recoverable under Boston Edison's settlement agreement.
3. Nuclear Asset Impairment
As part of the settlement agreement, the net investment in Pilgrim Station as of December 31, 1995 (adjusted for depreciation through 1997) is recovered through the distribution transition charge. Due to the market pressures in the industry, the ultimate recovery of investments made in Pilgrim since 1995 is not certain. Therefore, in 1997 the investment in Pilgrim was reduced by the $13 million invested in the plant since January 1, 1996 as an impairment loss under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. An after tax charge of approximately $8 million due to this reduction was recorded to non-operating expense on the consolidated statement of income in the fourth quarter of 1997.
Note C. Income Taxes
Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 net regulatory assets of $52.2 million and $51.1 million and corresponding net increases in accumulated deferred income taxes were recorded as of December 31, 1998 and 1997, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
No valuation allowances for deferred tax assets are deemed necessary.
Previously deferred investment tax credits are amortized over the estimated remaining lives of the property giving rise to the credits.
Components of income tax expense were as follows:
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:
The 1998 effective tax rate declined by 5.1% as a result of the recognition in net income of the remaining unamortized investment tax credits related to Boston Edison's fossil generating assets at the time of their sale. This shareholder benefit is included in other expense, net on the 1998 consolidated statement of income.
The 1997 effective tax rate declined by 0.8% as a result of the favorable outcome of an Internal Revenue Service appeal related to investment tax credits.
Note D. Nuclear Decommissioning and Nuclear Waste Disposal
1. Nuclear Decommissioning
As a nuclear generating facility, Pilgrim Station will be required to be decommissioned upon the expiration of its operating license. Decommissioning means to remove nuclear facilities from service safely and reduce residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission (NRC) license and release of the property for unrestricted use. Estimated decommissioning costs are recorded to depreciation expense on the consolidated statements of income over Pilgrim's expected service life. These costs are recovered through charges to retail and wholesale contract customers. In November 1998, Boston Edison filed an update of Pilgrim Station's decommissioning cost study with the DTE. The updated study includes an estimate of decommissioning and fuel storage costs of approximately $600 million in 1997 dollars.
2. Spent Nuclear Fuel
The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. Boston Edison has a license amendment from the NRC to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any further modifications are subject to review by the DTE.
Delays in identifying a permanent storage site have continually postponed plans for the United States Department of Energy's (DOE) long-term storage and disposal for spent nuclear fuel. The DOE's current estimate for an available site is no earlier than 2010. In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contract obligation to begin accepting spent nuclear fuel no later than January 31, 1998. This decision was in response to petitions filed by Boston Edison and other interested parties seeking declaratory rulings concerning enforcement and remedies for the DOE's failure to accept spent fuel in a timely manner. The court directed the plaintiffs to pursue relief under terms of their contracts with the DOE. Based on this ruling, the DOE may have to pay contract damages for not taking the spent nuclear fuel as scheduled. Under the Nuclear Waste Policy Act of 1982, it is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel. Boston Edison currently pays a fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE.
The DOE denied Boston Edison's petition to suspend payments to the Nuclear Waste Fund based on its interpretation of the U.S. Court of Appeal's decision made in November 1997. The DOE has, however, made an offer to consider amendments to existing contracts to address the hardships the anticipated delay in accepting spent fuel may cause individual contract holders.
3. Nuclear Divestiture
As discussed in Note B to these Consolidated Financial Statements, in November 1998 Boston Edison announced the selection of Entergy as the winning bidder for the purchase of Pilgrim. A purchase and sale agreement has been signed and all required approvals are anticipated in the second quarter of 1999. Under the agreement Boston Edison will fully fund and transfer its decommissioning trust fund to Entergy and Entergy will then assume full liability and responsibility for decommissioning and waste disposal at Pilgrim Station.
Note E. Pensions and Other Postretirement Benefits
The following information is presented in accordance with Statement of Financial Accounting Standards No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits, effective for fiscal years beginning after December 15, 1997.
1. Pensions
Boston Edison has a defined benefit funded retirement plan with certain contributory features that covers substantially all employees and an unfunded supplemental retirement plan for certain management employees.
The changes in the benefit obligation and plan assets were as follows:
The plans' funded status were as follows:
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the supplemental retirement plan with accumulated benefit obligations in excess of plan assets were $11,387,000, $9,856,000 and $0, respectively, as of December 31, 1998, and $11,076,000, $9,763,000 and $0, respectively, as of December 31, 1997.
Weighted average assumptions were as follows:
Components of net periodic benefit cost were as follows:
As a result of the fossil and nuclear divestitures discussed in Note B to these Consolidated Financial Statements, amounts recognized for curtailment, settlement and special termination benefit costs were $2,705,000, $0 and $665,000, respectively for 1998 and $1,300,000, $3,162,000 and $3,530,000, respectively for 1997. These amounts are recoverable under Boston Edison's settlement agreement.
Boston Edison experienced a high number of employee retirements from 1994 to 1996. A large number of these retirements were as a direct result of the 1995 corporate restructuring. In 1997, a review of the accounting for the pension expense related to the retirements revealed that an adjustment to the pension costs related to these employees was necessary. Therefore, pension regulatory asset was increased by $8.6 million in 1997 for the adjustment related to the period covered by the 1992 Boston Edison settlement agreement. Through 1995, in accordance with the 1992 settlement agreement, the difference between the net pension cost of the retirement plan and its annual funding amount was deferred. The remaining adjustment did not have a material impact on the consolidated results of operations or financial position.
Boston Edison also provides defined contribution 401(k) plans for substantially all employees. It matches a portion of employees' voluntary contributions to the plans. Matching contributions of $8 million were made in 1998, 1997 and 1996, respectively.
2. Other Postretirement Benefits
In addition to pension benefits, Boston Edison also provides health care and other benefits to retired employees who meet certain age and years of service liability requirements. These benefits are not available to management employees hired on or after January 1, 1995.
The changes in the benefit obligation and plan assets were as follows:
The plan's funded status and amount recognized in the consolidated balance sheets were as follows:
Weighted average assumptions were as follows:
For measurement purposes, a 5% annual rate of increase on the per capita cost of covered health care benefits was assumed. A 13% annual rate of increase on the per capita cost of covered prescription drug benefits was assumed, decreasing gradually to 5% in the year 2012 and remaining level thereafter. A 4% annual rate of increase on the per capita cost of covered dental benefits was assumed.
A 1% change in the assumed health care cost trend rate would have the following effects:
Components of net periodic benefit cost were as follows:
As a result of the fossil and nuclear divestitures discussed in Note B to these Consolidated Financial Statements, amounts recognized for curtailment and special termination benefit costs were $21,187,000 and $79,000, respectively for 1998 and $7,895,000 and $456,000, respectively for 1997. These amounts are recoverable under Boston Edison's settlement agreement.
Note F. Stock-Based Compensation
In 1997, Boston Edison initiated a Stock Incentive Plan (the Plan) which was adopted by the board of directors and approved by common stockholders. The Plan permits a variety of stock and stock-based awards, including stock options and deferred (nonvested) stock to be granted to certain key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of shares of common stock that may be delivered under the Plan is 2,000,000, including shares issued in lieu of or upon reinvestment of dividends arising from awards. During 1998, 19,150 shares of deferred stock and 419,200 ten-year non- qualified stock options were granted under the plan. During 1997, 73,820 shares of deferred stock and 298,400 ten-year non-qualified stock options were granted. The weighted average grant date fair value of the deferred stock issued during 1998 and 1997 is $39.75 and $27.26, respectively. The options were granted at the full market price of the stock on the date of the grant. Both awards vest ratably over a three-year period.
Compensation cost for stock-based awards is recognized under the provisions of Accounting Principals Board Opinion 25, which requires compensation cost to be measured by the quoted stock market price at the measurement date less the amount, if any, an employee is required to pay. The required fair value method disclosures are as follows:
Stock option activity of the Plan was as follows:
Summarized information regarding stock options outstanding at December 31, 1998:
There were 87,200 stock options exercisable at December 31, 1998 with a weighted average exercise price of $25.85.
The stock options granted during 1998 have a weighted average grant date fair value of $4.61. The fair value was estimated using the Black-Scholes option pricing model with the following weighted average assumptions:
Compensation cost recognized in the consolidated statements of income for stock-based compensation awards in 1998 and 1997 was $850,000 and $275,000, respectively.
Note G. Capital Stock
Dividends declared per share of common stock were $1.895 in 1998 and $1.88 in 1997 and 1996.
1. Common Stock
Common stock issuances and repurchases in 1996 through 1998 were as follows:
2. Cumulative Mandatory Redeemable Preferred Stock
Boston Edison redeemed the remaining 360,000 shares of 7.27% sinking fund series cumulative preferred stock during 1998. The stock was subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. Boston Edison also had the noncumulative option each May
to redeem additional shares, not to exceed 20,000, through the sinking fund at $100 per share plus accrued dividends. It redeemed, at par value, 40,000 shares in 1998, 1997 and 1996. In addition, 320,000 shares were redeemed in 1998 at $101.94 per share.
Boston Edison is not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share plus accrued dividends.
Note H. Indebtedness
1. Long-term Debt
The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity. There is no sinking fund requirement for any series of debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature
through 2015. Scheduled redemptions of $1.6 million were made in 1998, 1997 and 1996. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in 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 bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%. The redemption price decreases to 101% in February 2005 and to par in February 2006.
The aggregate principal amounts of Boston Edison's long-term debt (including HEEC sinking fund requirements) due through 2003 are $1.6 million in 1999, $166.6 million in 2000, $1.6 million in 2001 and 2002 and $151.6 million in 2003.
2. Short-term Debt
In 1998, BEC established a $225 million revolving credit agreement with a group of banks effective through July 2001. Under the terms of this agreement, it is required to maintain a consolidated common equity ratio of not less than 35% at all times and to maintain a ratio of consolidated earnings before interest and taxes to consolidated total interest expense of not less than 2 to 1 for each period of four consecutive fiscal quarters. Commitment fees must be paid on the total agreement amount. Approximately $78 million was outstanding under this agreement as of December 31, 1998.
Boston Edison currently has regulatory authority to issue up to $350 million of short-term debt. Boston Edison has a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement Boston Edison is required to maintain a common equity ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount. It also has arrangements with several banks to provide additional short-term credit on an uncommitted and as available basis.
Information regarding consolidated BEC short-term borrowings is as follows:
Note I. 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:
Nuclear decommissioning trust:
The cost of $173 million approximates fair value based on quoted market prices of securities held.
Cash and cash equivalents:
The carrying amount of $99 million approximates fair value due to the short-term nature of these securities.
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt:
The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31, 1998, are as follows:
Note J. Segment and Related Information
Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information, requires the disclosure of certain financial and descriptive information by operating segments. For the purpose of providing segment information, BEC's principal operating segment, or its traditional core business, is the electric utility that provides electric energy service, primarily in the city of Boston and 39 surrounding cities and towns. The utility also supplies electricity at wholesale for resale to other utilities and municipalities. The unregulated operating segment engages in certain nonutility business activities. Such activities include telecommunications, construction management and district energy primarily in the Boston area. Financial data for the operating segments are as follows (dollars in thousands):
Note K. Commitments and Contingencies
1. Contractual Commitments
At December 31, 1998, BEC and its subsidiaries had estimated contractual obligations for plant and equipment of approximately $28 million. This includes $13.5 million for nuclear fuel fabrication. Under the Pilgrim
purchase and sale agreement, Entergy will assume any unpaid portion of this obligation upon the sale closing date.
BEC and its subsidiaries also have leases for certain facilities and equipment. The estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1998 are as follows:
The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $146,125.
BEC and its subsidiaries will capitalize a portion of lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $29.6 million in 1998, $27.5 million in 1997 and $26.3 million in 1996, net of capitalized expenses of $1.6 million in 1998, $1.2 million in 1997 and $2.9 million in 1996.
Boston Edison had previously entered into various take or pay and throughput agreements, primarily to supply the New Boston fossil generating station with natural gas. As part of the fossil divestiture agreement, Sithe Energies assumed these obligations. The total expense under these agreements was $47.1 million in 1997 and $49.5 million in 1996.
2. Electric Company Investments
Boston Edison has an approximately 11% equity investment in two companies which 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 total obligations of those participants who do not meet certain credit criteria. At December 31, 1998, Boston Edison's portion of these guarantees was $15.2 million.
Boston Edison has a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee Atomic decided to discontinue operations of the Yankee Atomic nuclear generating station permanently and decommission the facility.
Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 2000, the period of the plant's operating license. The estimate of Boston Edison's share of Yankee Atomic's investment and costs of decommissioning is approximately $8 million as of December 31, 1998. This estimate is recorded on the consolidated balance sheet as a power contract liability and an offsetting regulatory asset.
Boston Edison also has a 9.5% equity investment in Connecticut Yankee Atomic Power Company (CYAPC) of approximately $10 million. In December 1996, the board of directors of CYAPC, which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of its operating license,
compared to the costs of closing the unit and incurring replacement power costs for the same period.
Boston Edison's share of Connecticut Yankee's remaining investment and estimated costs of decommissioning is approximately $51 million as of December 31, 1998. This estimate is recorded on the consolidated balance sheet as a power contract liability and an offsetting regulatory asset similar to Yankee Atomic.
In December 1996, CYAPC filed for rate relief at the FERC seeking to recover certain post-operating costs, including decommissioning. In August 1998, the FERC Administrative Law Judge (ALJ) released an initial decision regarding CYAPC's filing. This decision called for the disallowance of the common equity return on the CYAPC investment subsequent to the shutdown. The decision also stated that decommissioning collections should continue to be based on a previously approved estimate, with an adjustment for inflation, until a more reliable estimate is developed. In October 1998, both CYAPC and Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions to the ALJ decision. If the initial decision is upheld, CYAPC could be required to write off a portion of its investment in the generating unit and refund a portion of the previously collected return on investment. Management is currently unable to determine the ultimate outcome of this proceeding, however, the estimate of the effect of the ALJ's initial decision does not have a material impact on its consolidated financial position or results of operations.
3. Nuclear Insurance
The federal Price-Anderson Act currently provides $9.8 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to $9.6 billion is provided by a retrospective assessment of up to $88.1 million per incident levied on each of the 109 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year.
Boston Edison has purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage and the cost of repair, replacement, decontamination or decommissioning of utility property resulting from covered incidents at Pilgrim Station. Boston Edison's maximum potential total assessment for losses which occur during current policy years is $8.1 million under both the replacement power and excess property damage, decontamination and decommissioning policies.
4. Hazardous Waste
Boston Edison is an owner or operator of approximately 20 properties where oil or hazardous materials were spilled or released. As such, Boston Edison is required to clean up these remaining properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. Boston Edison also faces possible liability as a potentially responsible party in the cleanup of five multi-party hazardous waste sites in Massachusetts and other states where it is alleged to have generated, transported or disposed of hazardous waste at the sites. Boston
Edison is one of many potentially responsible parties and currently expects to have only a small percentage of the total potential liability for these sites. Through December 31, 1998, BEC had approximately $6 million accrued on its consolidated balance sheet related to these cleanup liabilities. Management is unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount. Based on its assessments of the specific site circumstances, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
5. Generating Unit Performance Program
Boston Edison's generating unit performance program ceased March 1, 1998. Under this program the recovery of incremental purchased power costs resulting from generating unit outages occurring through the retail access date is subject to review by the DTE. Proceedings relative to generating unit performance remain pending before the DTE. These proceedings will include the review of replacement power costs associated with the shutdown of the Connecticut Yankee nuclear electric generating unit which is discussed in item 2. Management is unable to fully determine a range of reasonably possible disallowance costs in excess of amounts accrued. Based on its assessment of the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional disallowance costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
6. Legal Proceedings
Industry and corporate restructuring legal proceedings
The DTE order approving the Boston Edison settlement agreement and the DTE order approving the formation of BEC as a holding company were appealed by certain parties to the Massachusetts Supreme Judicial Court (SJC). In December 1998, the SJC dismissed the appeal of the order approving the holding company formation. One settlement agreement appeal remains pending, however there has to date been no briefing, hearing or other action taken with respect to this proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston Edison has been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional.
Management is currently unable to determine the outcome of these outstanding proceedings or the impact the proceedings may have on its consolidated results of operations.
A referendum seeking repeal of the Massachusetts electric industry restructuring legislation that was enacted in November 1997 was overwhelmingly defeated by a better than 70% to 30% margin in a state-wide general election held on November 3, 1998. This outcome allows the comprehensive framework established for the restructuring of the electric industry to continue as intended under the enacted legislation.
Regulatory proceedings
In October 1997, the DTE opened a proceeding to investigate Boston Edison's compliance with the 1993 order which permitted the formation of BETG and authorized Boston Edison to invest up to $45 million in unregulated activities. Hearings began in the fourth quarter of 1998 and are expected to be completed in the first half of 1999.
Each of the Reading Municipal Light Department, the Littleton Electric Light Department and the West Boylston Municipal Light Department have filed separate claims for arbitration in Massachusetts alleging that the proposed transfer of Pilgrim Station constitutes a breach of their respective power sale agreements and seeking to terminate those agreements. The remaining municipal light departments have also indicated that they plan to file similar claims for arbitration. Boston Edison has requested the FERC to exercise its pre-emptive authority to consider the claims of the municipal light departments. In the event that either the FERC determines, or as a result of the arbitrations, that the contracts should be terminated, Boston Edison would continue to be obligated to purchase power from Entergy that it intended to resell to the municipal light departments. Boston Edison may not be able to resell such power in the short-term power exchange at a price equal to or greater than the price it is required to pay to Entergy. However, Boston Edison has filed at the DTE for recovery of any such shortfall as part of its Pilgrim divestiture filing through the transition charge.
Management is currently unable to determine the outcome of these proceedings or the impact these proceedings may have on its consolidated financial position or results of operations.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim Station, filed suit against Boston Edison. The town claims that Boston Edison has wrongfully failed to execute an agreement with the town for payments in addition to taxes due to the town under the Massachusetts electric industry restructuring legislation. Boston Edison has disputed the town's claim and will vigorously defend itself. In addition to this pending litigation, Boston Edison and the town of Plymouth are also parties in proceedings before the Appellate Tax Board and the DTE concerning substantially the same dispute. Management is unable to determine the ultimate outcome of these proceedings or the impact they may have on its consolidated financial position or results of operations.
In the normal course of its business BEC and its subsidiaries are also involved in certain other legal matters. Management is unable to fully determine a range of reasonably possible legal costs in excess of amounts accrued. Based on the information currently available, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated financial position. However, it is reasonably possible that additional legal costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
Note L. Long-Term Power Contracts
1. Long-Term Contracts for the Purchase of Electricity
Boston Edison entered into a 13-month agreement effective December 1, 1998 to transfer all of the unit output entitlements from its long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities, Inc. In return, Select will provide full energy service requirements to Boston Edison, including NEPOOL capability responsibilities, at FERC approved tariff rates through December 31, 1999.
Information relating to the contracts as of December 31, 1998 is as follows:
Boston Edison's total fixed and variable costs associated with these contracts in 1998, 1997 and 1996 were approximately $267 million, $288 million and $281 million, respectively. Boston Edison's minimum fixed payments under these contracts for the years after 1998 are as follows:
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and - - - - - - - - - - - - - - - - - ------------------------------------------------------------------------ Financial Disclosure - - - - - - - - - - - - - - - - - --------------------
Not applicable.
Part III --------
Item 10.
Item 10. Trustees and Executive Officers of the Registrant - - - - - - - - - - - - - - - - - -----------------------------------------------------------
(a) Identification of Trustees - - - - - - - - - - - - - - - - - -------------------------------
Information about Nominees and Incumbent Trustees
Throughout Item 10, there are references to Trustees/Directors of BEC Energy and Boston Edison. Note that prior to the reorganization into the holding company structure, Boston Edison Company was the parent company of the consolidated group.
The BEC Energy board has fixed the number of trustees at eleven as permitted under its bylaws. BEC Energy's declaration of trust provides for the classification of the BEC Energy board into three classes serving staggered three-year terms. The four persons named below have been nominated by the BEC Energy board for election as Class II trustees for a term expiring at the year 2002 annual meeting and until their successors are duly chosen and qualified. The remaining trustees will continue to serve as provided below, with the Class III trustees having terms expiring in 2000 and the Class I trustees having terms expiring in 2001. If any of the nominees shall be unavailable as a candidate at the BEC Energy annual meeting by reason of death, disability or resignation, votes exercised through the proxies will be cast for a substitute candidate as may be designated by the BEC Energy board, or in the absence of a designation, in a manner the trustees may determine in their discretion. Alternatively, in this situation, the BEC Energy board may take action to fix the number of trustees for the ensuing year at the number of nominees named herein who are then able to serve.
The BEC Energy board has adopted the following trustee retirement policy. Trustees who are employees of BEC Energy or Boston Edison Company, with the exception of the chief executive officer, retire from the BEC Energy board when they retire from employment with BEC Energy or Boston Edison Company. Under the BEC Energy board's current policy, trustees who are not employees of BEC Energy or Boston Edison Company or who have served as chief executive officer retire from the board at the annual shareholder meeting following their seventieth birthday.
The BEC Energy board, which held five regular meetings and two special meetings in 1998 since the establishment of BEC Energy on May 20, 1998, has an Executive Committee, an Audit, Finance and Risk Management Committee, an Executive Personnel Committee, and a Pricing Committee. During 1998, the Executive Committee met three times. The Executive Committee is authorized to act as a nominating committee and to review trustee compensation during the intervals between BEC Energy's board meetings. The Audit, Finance and Risk Management Committee met one time. Its responsibilities include recommendations as to the selection of independent auditors, review of the scope of the independent audit, annual financial statements, internal audit reports, and financial and accounting controls and procedures, and review of BEC Energy's financial requirements, insurance coverages, and legal compliance programs. The Executive Personnel Committee, which is responsible for reviewing executive officer compensation, personnel planning and performance, some company benefit programs, and human resources policies, also met one time. The Pricing Committee, which is authorized to approve the terms of debt and equity offerings, did not meet in 1998. All trustees attended at least 75% of the aggregate of the total number of meetings of the BEC Energy board and the total number of meetings held by all committees of the BEC Energy
board on which he or she served, with the exception of Mr. Egan, who attended 65% of these meetings.
(b) Identification of Executive Officers - - - - - - - - - - - - - - - - - -----------------------------------------
The information required by this item is included at the end of Part I of this Form 10-K under the caption Executive Officers of the Registrant.
(c) Identification of Certain Significant Employees - - - - - - - - - - - - - - - - - ----------------------------------------------------
Not applicable.
(d) Family Relationships - - - - - - - - - - - - - - - - - -------------------------
Not applicable.
(e) Business Experience - - - - - - - - - - - - - - - - - ------------------------
The names of the nominees as Class II trustees and the incumbent Class I and Class III trustees and selected information concerning them are shown in the table below. Unless a specific time period is indicated, each nominee and trustee has held the position first listed across from his or her name for at least five years.
(f) Involvement in Certain Legal Proceedings - - - - - - - - - - - - - - - - - ---------------------------------------------
Not applicable.
(g) Promoters and Control Persons - - - - - - - - - - - - - - - - - ----------------------------------
Not applicable.
Item 11.
Item 11. Executive Compensation - - - - - - - - - - - - - - - - - --------------------------------
Trustee Compensation
In 1998, the compensation programs for trustees were reviewed and revised with the assistance of an external compensation consultant. The review was initiated to assure that the level of compensation be appropriate in reference to comparable programs, the plan design supports BEC Energy's strategic objectives, and the interests of the trustees are aligned with those of shareholders.
Each trustee who is not an employee of BEC Energy receives an annual board retainer of $20,000 in cash. Each trustee also receives an annual retainer of $20,000 worth of BEC Energy common shares which is deferred until the trustee retires from the board. Each non-employee trustee who is a member of the Executive Committee receives an additional retainer of $3,000 and each trustee who chairs a BEC Energy board committee receives an additional retainer of
$3,000. All other retainers were discontinued as of October 1998. Each trustee who is not an employee of BEC Energy receives $1,000 for attendance in person at each meeting of the BEC Energy board or a committee and $500 for participating in a meeting by telephone. Trustees may elect to defer part or all of their trustees' fees under BEC Energy's deferred fee plan. Two programs were discontinued: the 1991 Director Stock Plan and the 1993 Directors' Retirement Benefit. An amount equal to the present value of the benefit each outside trustee accrued under the Directors' Retirement Benefit was deposited in deferred accounts. Receipt is deferred until the trustee's retirement from the BEC Energy board.
Report of the Executive Personnel Committee
Under the rules established by the SEC, BEC Energy is required to provide specified data and information with regard to the compensation and benefits provided to its executive officers, including BEC Energy's chief executive officer and the four other most highly compensated executive officers. The disclosure requirements for these officers (the "Named Executive Officers") include tables summarizing total compensation and a report explaining the rationale and considerations that led to fundamental executive compensation decisions affecting those individuals for the prior year.
The Executive Personnel Committee
BEC Energy's executive compensation program is administered by the Executive Personnel Committee, a committee of the BEC Energy board composed of the four non-employee trustees listed as signatories to this report. Except as discussed below, none of these non-employee trustees has any interlocking or other relationship with BEC Energy that would require disclosure to the SEC. Generally, all decisions of the Executive Personnel Committee regarding the compensation of the chief executive officer are subject to the approval of the non-employee trustees of BEC Energy, none of whom is eligible to participate in the incentive plans described below. The Executive Personnel Committee administers the 1997 Stock Incentive Plan discussed below.
The Named Executive Officers
The officers identified as the five most highly compensated executive officers of BEC Energy are all employees of Boston Edison Company, BEC Energy's principal subsidiary. Three of the Named Executive Officers, Messrs. May, Horan and Judge, also serve as officers of BEC Energy, in the following capacities: Mr. May as Chairman, President and Chief Executive Officer; Mr. Horan as Senior Vice President and General Counsel; and Mr. Judge as Senior Vice President and Treasurer. BEC Energy does not have any employees of its own.
Compensation Philosophy
The executive compensation philosophy of BEC Energy is to provide competitive levels of compensation that advance BEC Energy's annual and long-term performance objectives, reward corporate performance, and assist BEC Energy in attracting, retaining and motivating highly qualified executives. The framework for the compensation committee's executive compensation program is to establish base salaries which are competitive with electric utilities in general and to incentivize excellent performance by providing executives with the opportunity to earn additional remuneration under the annual and long-term incentive plans. The incentive plan goals are designed to improve the effectiveness and enhance the efficiency of BEC Energy's operations and to create value for shareholders. The committee also seeks to link executive and
shareholder interests through equity-based incentive plans. Accordingly, in 1997, upon the committee's recommendation, the Boston Edison board approved stock ownership guidelines of three times base salary for the chief executive officer and one to one-and one-half times base salary for the other executive officers of BEC Energy and Boston Edison Company. These guidelines allow the executives five years to acquire this amount of stock.
Components of Compensation
Compensation paid to the Named Executive Officers, as reflected in the following tables, consists of three primary elements: base salary, annual incentive awards, and long-term incentive awards. BEC Energy compares its compensation levels against those of other growth-oriented investor-owned electric utility companies. BEC Energy's strategy is to establish total compensation, i.e., base salary and annual incentives, at the 60th percentile of the utility industry, and to compare its long-term incentive plan to those of more aggressive utilities and general industry companies that focus on value creation.
During 1998, the committee thoroughly reviewed data collected by nationally recognized compensation experts as well as by Boston Edison's human resources group to determine whether BEC Energy's compensation strategy was being met. The review evaluated base salary and annual incentives of nearly all electric utility companies, and long-term incentives of a blend of utilities and general industry. The data demonstrated that BEC Energy was in conformity with its compensation strategy to the satisfaction of the committee.
The income tax deductions of publicly traded companies may be limited to the extent total compensation for particular executive officers exceeds one million dollars during any year. This deduction limit, however, does not apply to payments which qualify as "performance based". The committee has reviewed the regulations issued by the Internal Revenue Service and will continue to review the application of these rules to future compensation. However, the committee intends to continue basing its executive compensation decisions primarily upon performance achieved, both corporate and individual, while retaining the right to make subjective decisions and to award compensation that may or may not meet all of the Internal Revenue requirements for deductibility.
Annual Incentive Plan
Annual incentive payments to the Named Executive Officers, reported in the fourth column of the Summary Compensation Table below, are based on both corporate and business unit performance objectives which are derived from the corporate operating plan and approved by the committee. Corporate performance objectives include a comparison of target to actual earnings per share from operations. Business unit performance objectives include predetermined levels for operating and capital budgets, as well as key operating goals. The annual incentive plan award for Mr. May is based solely on BEC Energy's achieving the earnings per share objective. In 1998, basic earnings per share were $2.76, which exceeded the plan target. The annual incentive plan awards for Messrs. Gustin, Horan, Judge and Ledgett were based 50% on earnings per share and 50% on specific business unit performance objectives to achieve various budget and operating plan targets. All four officers exceeded the specified business unit performance levels.
Long-Term Compensation
Under the 1997 Stock Incentive Plan, executive officers and other key employees are eligible to receive grants from time to time of stock-related awards of seven general types: (i) stock options, (ii) stock appreciation rights, (iii) restricted stock awards, (iv) deferred stock awards, (v) performance unit awards, (vi) dividend equivalent awards, and (vii) other stock-based awards. The long-term grant in May of 1998 consisted of non- qualified stock options, deferred shares and dividend equivalents on the deferred shares, and was based upon the committee's evaluation of performance towards key strategic objectives, and competitive award data provided by an external consultant. The committee did not weight any of these factors. The options and the deferred shares vest at the rate of 33% per year over a three- year period from the date of grant, and the options may be exercised over a ten-year period.
Other Plans
At various times in the past, BEC Energy and Boston Edison Company have adopted various broad-based employee benefit plans in which officers are permitted to participate on the same terms as non-executive employees who meet applicable eligibility criteria. These plans include pension, life, and health insurance plans, as well as a section 401(k) savings plan which includes a company matching contribution equal to the first six percent of pay contributed by the employee up to a maximum excludable 401(k) contribution allowed by the Internal Revenue Code. In addition, Boston Edison Company has a deferred compensation plan in which officers and senior managers may elect to participate.
In 1996, the committee implemented a supplemental executive retirement plan which provides eligible participates with supplementary retirement income of up to 60% of final average cash compensation, depending upon each participant's years of service, reduced by 50% of the participant's social security benefit and further reduced by benefits the participant receives under Boston Edison's pension plan.
Mr. May's 1998 Compensation
The Executive Personnel Committee makes decisions regarding the compensation of the chief executive officer using the same philosophy and criteria described above. As with the compensation of all officers, BEC Energy compares compensation levels for the chief executive officer to those of all other investor-owned electric utility companies.
Each year BEC Energy approves the adjustment of salary ranges for the chief executive officer and other corporate officers based on studies conducted by external executive compensation consultants and Boston Edison Company's human resources group. The 1998 studies found BEC Energy's executive compensation levels to be within the approved 60th percentile position to market. Mr. May received a 5% increase to his base salary in 1998.
Mr. May's annual incentive award, shown in the fourth column of the Summary Compensation Table below, was in conformity with the provisions of the annual incentive plan described above, and was based on BEC Energy surpassing its operating plan targets. The committee's policy is to base individual long- term incentive awards on an annual study by the compensation consultant comparing the value of long-term incentive grants to salary levels for a blend of electric utility and general industry companies. The 6,000 deferred shares and 60,000 options granted Mr. May in 1998 reflect this policy.
Compensation Committee Interlocks and Insider Participation
Charles K. Gifford, who is a member of BEC Energy's Executive Personnel Committee, is Chairman and Chief Executive Officer of BankBoston Corporation and BankBoston, N.A. Thomas J. May, BEC Energy's Chairman, President and Chief Executive Officer, serves on the boards of directors of BankBoston Corporation and BankBoston, N.A.
Gary L. Countryman, who is the Chairman of BEC Energy's Executive Personnel Committee, is Chairman of the Board and Chief Executive Officer of Liberty Mutual Insurance Company and Liberty Mutual Fire Insurance Company and Chairman of the Board of Liberty Financial Companies, Inc. Mr. May serves on the boards of directors of Liberty Mutual Insurance Company, Liberty Mutual Fire Insurance Company, and Liberty Financial Companies, Inc.
By the Executive Personnel Committee,
Gary L. Countryman (Chairman) Richard J. Egan Charles K. Gifford Sherry H. Penney
Executive Compensation Tables
The following information is given regarding annual and long-term compensation earned by the chief executive officer and the four other most highly compensated executive officers of BEC Energy and Boston Edison Company with respect to the years 1996, 1997 and 1998.
Pension Plan Table
The following table shows the estimated annual retirement benefits payable to executive officers under the qualified pension plan and the supplemental executive retirement plan, assuming retirement at age 65. The supplemental executive retirement plan is a non-qualified pension plan providing a maximum benefit of 60% of compensation after the executive has accumulated 20 years of credited service and has reached age 60. The supplemental executive retirement plan provides the incremental benefits in excess of the benefits paid under the qualified plan necessary to reach the benefit shown in the table. Each of the officers named in the Summary Compensation Table participates in the supplemental executive retirement plan. The benefits presented are based on a straight life annuity and do not take into account a reduction in benefits of up to 50% of the participant's primary social security benefit.
For purposes of the retirement plans, Messrs. May, Ledgett, Gustin, Horan and Judge currently have 23, 18, 18, 21 and 21 years of credited service, respectively.
Final average compensation for purposes of calculating the benefits under the supplemental executive retirement plan is the highest average annual compensation of the participant during any consecutive 36-month period. Compensation taken into account in calculating the benefits described above includes salary and annual bonus, including any amounts deferred under the terms of the deferred compensation plan.
Mr. May can elect, and Mr. Ledgett receives, an alternative supplemental retirement benefit equal to 33% of final base salary annually for 15 years, which at the current level would provide Mr. Ledgett with approximately $7,000 in excess of the amounts shown in the table above.
Change of Control Agreements
BEC Energy, through its Boston Edison Company subsidiary has change of control agreements with various key employees, including those named in the Summary Compensation Table, which provide severance benefits in the event of specified terminations of employment following a change in control of Boston Edison. Events which constitute a change of control under these agreements are described below. If, following a change in control, the employee's employment is terminated without cause or the employee terminates employment for good reason, the employee receives severance pay in an amount equal to two times, three times in the case of Mr. May, the sum of annual base salary (at the rate in effect immediately prior to the date of termination or immediately before the change of control, whichever is higher) plus actual bonus paid in respect of the most recently completed fiscal year or target bonus for the fiscal year in which the termination occurs, whichever is higher. In addition, the change
of control agreements provide for a pro rated bonus payment for the year in which the termination occurs, the immediate vesting of bonus awards, immediate payment of deferred compensation amounts upon the termination and payments equal to the benefit the employee would have received under Boston Edison Company's retirement plan assuming the executive was vested and remained employed for an additional two years, three years in the case of Mr. May. For two years, three years in the case of Mr. May, following termination of employment, the employee would be entitled to continue to participate in all welfare plans provided by Boston Edison Company. The change of control agreements further provide for a "gross-up" payment under which, if amounts paid under these agreements would be effectively reduced a federal excise tax on "excess parachute payments," Boston Edison Company will pay the employee an additional amount of cash, so that, after payment of all parachute taxes by the employee, the employee will have received the amount the employee would have received in the absence of any such tax. A change of control under these agreements generally includes the following events: (i) a person or group becomes the beneficial owner of more than 30% of the voting power of Boston Edison Company's securities; (ii) continuing directors cease to be a majority of the Boston Edison Company board; (iii) a consolidation, merger or other reorganization or sale or other disposition of all or substantially all of the assets of Boston Edison Company, other than certain defined transactions; or (iv) approval by the stockholders of a complete liquidation or dissolution of Boston Edison Company.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management - - - - - - - - - - - - - - - - - ------------------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners - - - - - - - - - - - - - - - - - ----------------------------------------------------
To the knowledge of management, no person owns beneficially more than five percent of the BEC Energy common shares.
(b) Security Ownership of Management - - - - - - - - - - - - - - - - - -------------------------------------
The following table sets forth certain information regarding the beneficial ownership of BEC Energy common shares as of January 31, 1999, assuming the exercise of all options exercisable on, or within 60 days of, such date, by (i) each trustee, (ii) the chief executive officer and each of the other four most highly compensated executive officers of BEC Energy/Boston Edison Company, (iii) all executive officers and trustees as a group. None of the individual or collective holdings below exceeds 1% of the outstanding BEC Energy common shares. No member of the group is the beneficial owner of Boston Edison Company's cumulative preferred stock.
(c) Changes in Control - - - - - - - - - - - - - - - - - -----------------------
Not applicable.
Item 13.
Item 13. Certain Relationships and Related Transactions - - - - - - - - - - - - - - - - - --------------------------------------------------------
Not applicable.
Part IV -------
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - - - - - - - - - - - - - - - - - -------------------------------------------------------------------------
(a) The following documents are filed as part of this Form 10-K:
2. Financial Statement Schedules:
No financial statement schedules are included as they are either not required or not applicable.
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K:
A Form 8-K dated November 23, 1998, was filed during the fourth quarter of 1998 disclosing that Entergy Nuclear Generating Company was selected as the winning bidder for the purchase of Pilgrim Station. In addition, a Form 8-K dated December 10, 1998, was filed announcing that BEC and Commonwealth Energy System entered into an Agreement and Plan of Merger.
Management agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long-term debt whose authorization does not exceed 10% of total assets.
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.
BEC ENERGY
By: /s/ James J. Judge --------------------------------------- James J. Judge Senior Vice President and Treasurer (Principal Financial Officer)
Date: March 25, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 25th day of March 1999.
/s/ Thomas J. May Chairman of the Board, President - - - - - - - - - - - - - - - - - ------------------------------------ and Chief Executive Officer Thomas J. May
/s/ Robert J. Weafer, Jr. Vice President - Finance, - - - - - - - - - - - - - - - - - ------------------------------------ Controller and Chief Accounting Robert J. Weafer, Jr. Officer
/s/ Gary L. Countryman Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Gary L. Countryman
/s/ Thomas G. Dignan, Jr. Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Thomas G. Dignan, Jr.
- - - - - - - - - - - - - - - - - ------------------------------------ Trustee Richard J. Egan
- - - - - - - - - - - - - - - - - ------------------------------------ Trustee Charles K. Gifford
/s/ Nelson S. Gifford Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Nelson S. Gifford
/s/ Matina S. Horner Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Matina S. Horner
/s/ Paul A. LaCamera Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Paul A. LaCamera
/s/ Sherry H. Penney Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Sherry H. Penney
/s/ Herbert Roth, Jr. Trustee - - - - - - - - - - - - - - - - - ------------------------------------ Herbert Roth, Jr.
- - - - - - - - - - - - - - - - - ------------------------------------ Trustee Stephen J. Sweeney
Report of Independent Accountants
To the Shareholders and Trustees of BEC Energy:
In our opinion, the accompanying consolidated financial statements listed in Item 14(a) of this Form 10-K present fairly, in all material respects, the consolidated financial position of BEC Energy and its subsidiaries at December 31, 1998 and 1997 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. These financial statements are the responsibility of BEC's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Boston, Massachusetts January 28, 1999