Item 1. Business - ------- --------
(a) General -------
Commonwealth Electric Company (the Company) is engaged in the distribution and sale of electricity to approximately 329,000 retail customers (including 44,600 seasonal customers) in 40 communities located in southeastern Massachusetts, including Cape Cod and the island of Martha's Vineyard, having an approximate year-round population of 549,000 and a large influx of summer residents.
The Company, which was organized on April 4, 1850 pursuant to a special act of the legislature of the Commonwealth of Massachusetts, operates under the jurisdiction of the Massachusetts Department of Telecommunications and Energy (MDTE) that regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its wholesale rates with the Federal Energy Regulatory Commission (FERC). The Company is wholly-owned by Commonwealth Energy System (COM/Energy) which is a wholly-owned indirect subsidiary by NSTAR. NSTAR is the new holding company that was formed, effective August 25, 1999 after receipt of all necessary approvals and upon completion of a merger transaction between Commonwealth Energy System (COM/Energy, formerly the parent of the Company) and BEC Energy. The merger created an energy delivery company which includes the Company, serving approximately 1.3 million customers located in Massachusetts including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities. NSTAR is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 and, in addition to its investment in the Company, has interests in other utility and several nonregulated companies.
(b) Electric Industry Restructuring -------------------------------
On November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act (the Act). This legislation provided, among other things, that customers of retail electric utility companies who take standard offer service receive a 10 percent rate reduction and be allowed to choose their energy supplier, effective March 1, 1998. The Act also provides that utilities be allowed full recovery of transition costs subject to review and an audit process. The rate reduction mandated by the legislation increased to 15 percent effective September 1, 1999 for customers who continue to take standard offer service.
The Company, together with affiliates Cambridge Electric Light Company (Cambridge Electric) and Canal Electric Company (Canal Electric), had filed a comprehensive electric restructuring plan with the MDTE in November 1997 that was substantially approved by the MDTE in February 1998. The divestiture of the Company's non-nuclear generation assets was an integral part of COM/Energy's restructuring plan and is consistent with the Act.
On May 27, 1998, Canal Electric selected Southern Energy to buy Canal Units 1 and 2. The sale was conducted through an auction process that was outlined in a restructuring plan filed with the MDTE in November 1997 in conjunction with
the state's industry restructuring legislation enacted in 1997. The sale was approved by the MDTE on October 30, 1998 and by the FERC on November 12, 1998. Proceeds from the sale of Canal Electric's and the Company's non-nuclear generating assets amounted to approximately $395 million or 6 times their book value of approximately $65.4 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments, amounted to approximately $298 million and are being used to reduce transition costs of Cambridge Electric and the Company related to electric industry restructuring that otherwise would have been collected through a non-bypassable transition charge. An adjustment of $5.1 million was recorded in the first quarter of 1999 that reduced the book value to $60.3 million.
On December 23, 1998, the MDTE approved the divestiture filing and COM/Energy's proposal to establish a special purpose affiliate, Energy Investment Services, Inc. (EIS), that will administer the above-book value net proceeds from the sale of the Company's units with the goal of preserving capital and maximizing earnings for the benefit of retail customers. EIS will credit the proceeds and any return earned to the accounts of the Company and Cambridge Electric, resulting in a reduction in the transition costs to be billed to customers.
The electric industry has continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy. In response to the significant changes that have taken place in the electric utility industry, the Company sold all of its generating assets in late 1998 to focus on the distribution of energy and related services.
(c) Sources and Availability of Electric Power Supply -------------------------------------------------
NSTAR on behalf of its electric retail subsidiaries, the Company, Boston Edison and Cambridge Electric entered into a six-month agreement effective January 1, 2000 to transfer all of the unit output entitlements in long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In return, Select will provide full energy service requirements, including New England Power Pool (NEPOOL) capability responsibilities at FERC approved tariff rates through June 30, 2000.
During 1997, NEPOOL was restructured with changes taking effect to the membership and governance provisions of the power pooling agreement along with the transfer of operating responsibility of the integrated transmission and generation system in New England to ISO New England. Previously, NEPOOL dispatched generating units for operation based on the lowest operating costs of available generation and transmission. Under the new structure, generators are required to provide ISO New England with market prices at which they will sell short-term energy supply. These prices formed the basis for dispatch that began in the second quarter of 1999. As noted, the Company will receive all of its power supply requirements from Select through June 30, 2000. Therefore, the change to NEPOOL's operations and pricing structure is expected to have no material impact on the Company's costs for purchased electric energy through the second quarter of 2000.
(d) Franchises ----------
Through its charters, which is unlimited in time, the Company has the right to engage in the business of distributing and selling electricity 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 (MDTE). The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature. Pursuant to the Massachusetts Electric Restructuring Act enacted in November 1997, the MDTE has defined the service territory of the Company based on the territory actually served on July 1, 1997, and following, to the extent possible, municipal boundaries. The legislation further provided that, until terminated by effect of law or otherwise, these companies shall have the exclusive obligation to provide distribution service to all retail customers within such service territory. No other entity shall provide distribution service within this territory without the written consent of the Company which consent, must be filed with the MDTE and the municipality so affected.
(e) Retail Electric Rates ---------------------
As a result of electric industry restructuring, the Company unbundled its rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and has afforded customers the opportunity to purchase generation supply in the competitive market. The 10 percent rate reduction mandated by the legistation increased to 15 percent effective September 1, 1999 for customers who continue to take standard offer service. Unbundled delivery rates are composed of a distribution charge (to collect the costs of delivering and billing for electricity), a transition charge (to collect past costs for investments in generating plants and costs related to power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant), an energy conservation charge (to collect costs for demand- side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Electricity supply services provided by the Company include optional standard offer service and default service.
Standard offer service is the electricity that is supplied by the local retail electric subsidiaries until a competitive power supplier is chosen by the customer. It is designed as a seven-year transitional service to give the customer time to learn about competitive power suppliers. The price of standard offer service will increase over time. Default service is supplied by the local distribution company when a customer is not receiving power from either standard offer service or a competitive power supplier. The market price for default service will fluctuate based on the average market price for power. Amounts collected through these various charges will be reconciled to actual expenditures on an on-going basis.
Prior to the implementation of industry restructuring on March 1, 1998, the Company had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs.
(f) Demand-Side Management Programs -------------------------------
The Company has implemented a variety of DSM programs that are designed to reduce future energy use by its customers. Pursuant to the Restructuring Act, the Company has agreed to mandatory charges per KWH to fund energy efficiency and demand-side management activities.
(g) Capital Expendituring and Financing -----------------------------------
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 1999 were $21 million and consisted primarily of additions to the Company's distribution and transmission systems. The majority of these expenditures were for system reliability and control improvements, customer service enhancements and capacity expansion to allow for long-range growth in the Company service territory.
(h) Seasonal Nature of Business ---------------------------
Kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions.
(i) Competitive Conditions ----------------------
The electric industry has continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These pressures have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and its activities in the transmission and distribution of energy.
(j) Employees ---------
The total number of full-time employees for the Company declined 9.5% in 1999 to 629 from 695 employees at year-end 1998. The Company has 470 employees (74.7%) who are represented by the Utility Workers of New England, Inc. under three separate collective bargaining units with agreements that expire October 31, 2001, September 30, 2002 and April 30, 2003. Employee relations have generally been satisfactory.
Item 2.
Item 2. Properties - ------- ----------
The principal properties of the Company consist of an integrated system of transmission and distribution lines, substations, an office building in the Town of Wareham, MA and other structures such as garages and service buildings. On December 30, 1998, the Company sold to an affiliate of The Southern Company of Atlanta, GA, two diesel plants with a combined capability of 13.8 MW located on the island of Martha's Vineyard that were used for standby and emergency purposes. Also sold was the Company's 1.4% joint-ownership interest in Central Maine Power Company's Wyman Unit 4 with an entitlement of 8.8 MW.
At December 31, 1999, the electric transmission and distribution system consisted of 5,787 pole miles of overhead lines, 3,888 cable miles of underground line, 140 substations and 343,988 active customer meters.
Item 3.
Item 3. Legal Proceedings - ------- -----------------
Along with other Massachusetts investor-owned utilities, the Company has been named as a defendant in a class action suite 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 however, if an unfavorable outcome were to occur, there could be a material adverse impact on business operations, the consolidated financial position or results of operations for a reporting period.
Merger Rate Plan
An integral component of the merger which created NSTAR was a rate plan filed by its retail utility subsidiaries, including the Company. The MDTE issued an order approving most major elements of the rate plan on July 27, 1999. The highlights of the rate plan include a four-year distribution rate freeze for each of the NSTAR retail utility subsidiaries, including the Company, the collection from customers of recovery of transaction and integration costs initially estimated at approximately $111 million over 10 years. The Massachusetts Attorney General and a group of four interveners filed separate appeals of the MDTE order with the Massachusetts Supreme Judicial Court (SJC) regarding the rate plan. While management anticipates that the MDTE's decision to approve the rate plan will be upheld by the SJC, it cannot determine the ultimate outcome of these appeals or their impact on the rate plan.
Other Litigation
In the normal course of its business the Company is 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 avaiable, it does not believe that it is probable that any such additional costs will have a material impact on its consolidated finacnial 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.
PART II. --------
Item 5.
Item 5. Market for the Registrant's Common Stock and Related Stockholder - ------ ---------------------------------------------------------------- Matters -------
(a) Principal Market ----------------
Not applicable. The Company is wholly-owned by Commonwealth Energy Systems and is a wholly-owned indirect subsidiary of NSTAR.
(b) Number of Shareholders at December 31, 1999 -------------------------------------------
One
(c) Frequency and Amount of Dividends Declared in 1999 and 1998 -----------------------------------------------------------
1999 1998 ---------------------------- ----------------------------- Per Share Per Share Declaration Date Amount Declaration Date Amount ---------------- --------- ---------------- --------- January 27,1999 $ 1.00 May 11, 1998 $3.40 April 28, 1999 2.00 October 26, 1998 1.55 July 23, 1999 1.85 ----- October 28, 1999(1) 7.30 $4.95 ------ ===== $12.15 ======
(1) The dividend declared on October 28, 1999 constituted a return of capital.
Reference is made to Note 7 of the Notes to Financial Statements filed under Item 8 of this report for the restriction against the payment of cash dividends.
(d) Future dividends may vary depending upon the Company's earnings and capital requirements as well as financial and other conditions existing at that time.
Item 7.
Item 7. Management's Discussion and Analysis of Results of Operations - ------- -------------------------------------------------------------
The following is a discussion of certain significant factors that have affected operating revenues, expenses and net income during the periods included in the accompanying Statements of Income and is presented to facilitate an understanding of the results of operations. This discussion should be read in conjunction with Item 1 of this report and the Notes to Financial Statements filed under Item 8 of this report.
In the accompanying statements, the Company prior to the Merger is labeled as the "Predecessor" and after the Merger as the "Successor". The eight month (predecessor period) and the 4 month (successor period), ended August 25, 1999 and December 31, respectively, have been combined per the purpose of comparing the results of the twelve month period ended December 31, 1998 with the twelve month period ended December 31, 1999.
Unit Sales and Customers - ------------------------
The following is a summary of unit sales and customers for the periods indicated:
(a) Includes seasonal customers of 44,577 in 1999, 45,537 in 1998 and 46,147 in 1997. Service is considered to be "seasonal" when the kilowatthours used in the billing months ending between June 1 and September 30 exceed the kilowatthours used in the preceding eight months.
Retail unit sales increased in 1999 due to higher than normal summer temperatures and a continuing strong local economy.
The Company's residential customer segment provides approximately 48% of its total retail sales and approximately 8% of those customers rely on electricity for space heating.
Operating Revenues - ------------------
Operating revenues for 1999 increased $1 million (0.2%) due to higher retail unit sales, somewhat offset by the 10 percent rate reduction (increased to 15 percent effective September 1, 1999) (further discussed below),
and a net decrease in electricity purchased for resale, fuel and transmission charges of $16.1 million (6%). The decline in these costs reflects a cost deferral of $19.6 million in conjunction with the Company's restructuring plan as approved by the Massachusetts Department of Telecommunications and Energy (MDTE). As a result of Electric Industry Restructuring Act, the Company has unbundled its rates and currently provides its standard offer customers service at inflation adjusted rates that are 15% lower than rates in effect prior to March 1, 1998. The Company has also afforded customers the opportunity to purchase generation supply in the competitive market. Delivery rates are composed of a customer charge, a distribution charge, a transition charge (to collect stranded costs), a transmission charge, an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge. Electricity supply services provided by the Company include optional standard offer service and default service. Amounts collected through these various charges will be reconciled to actual expenditures on an on-going basis.
Wholesale revenues were $20.3 million, $27.9 million, and $27.8 million in 1999, 1998 and 1997, respectively.
Electricity Purchased for Resale, Transmission and Fuel - -------------------------------------------------------
To satisfy demand requirements and provide required reserve capacity, the Company purchased power on a long and short-term basis through entitlements pursuant to power contracts with other New England and Canadian utilities. The Company supplemented these sources with its own generating capacity that was sold on December 30, 1998.
The cost of electricity purchased for resale, fuel and transmission constituted 59.6% in 1999 of electric operating revenues. These costs reflect higher unit sales and in addition, a cost deferral of $19.6 million in 1999 that resulted primarily from providing the required 10% rate reduction, which was adjusted to 15% in September 1999, for retail customers.
NSTAR on behalf of its electric retail subsidiaries of the Company, Boston Edison and Cambridge Electric, entered into a six-month agreement effective January 1,
2000 to transfer all of the unit output entitlements in long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In return, Select will provides full energy service requirements, including NEPOOL capability responsibilities, at FERC approved tariff rates through June 30, 2000.
Other Operating Expenses - ------------------------
Other operation increased $25.7 million (36.5%) in 1999 primarily due to the recognition of costs allocated to the Company that relate to various compensation plans whose benefits have vested as a result of a change in control at the NSTAR level including $8.3 million in pension costs that were previously deferred that were expensed during 1999. In addition, other factors that impacted other operation in 1999 were costs related to Hurricane Floyd ($2 million) and an increase in the provision for bad debts ($1.4 million).
In 1999, maintenance increased $5.1 million (44.1%) due to costs associated with transmission and distribution to repair overhead conductors ($1.2 million) and storm damage repairs of $3.3 million.
Depreciation and amortization expense declined $1.1 million in 1999 despite reflecting merger-related amortization of $2.1 million. These costs were somewhat offset by a reduction in other amortized costs from those in 1998 and included certain prior-period deferred costs, including costs associated with DSM programs, purchased power, certain postretirement benefits, and litigation costs related to the Pilgrim nuclear power unit.
Federal and state income taxes declined $5.6 million (61.2%) in 1999 and due mainly to the change in pretax income.
Local property and other taxes in 1999 increased primarily due to higher property tax assessments and rates. Payroll and other taxes increased $165,000 in 1999.
Other Income (Expense) - ----------------------
Other income increased in 1999 due to interest accrued on deferred transition costs associated with electric industry restructuring.
Interest Charges - ----------------
Total interest charges increased in 1999 due primarily to interest on customer refunds ($4.7 million).
Merger with BEC Energy - ----------------------
NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on August 25, 1999 as an exempt public utility holding company. NSTAR's utility subsidiaries are Boston Edison Company (Boston Edison), Commonwealth Electric Company (the Company), Cambridge Electric Light Company (Cambridge Electric), Canal Electric Company (Canal Electric) and Commonwealth Gas Company (ComGas). Utility operations accounted for more than 98% of revenues in both 1999 and 1998. NSTAR's nonutility operations include telecommunications, district heating and cooling operations and liquefied natural gas services.
As a result of the merger, the fourth quarter dividend amounting to approximately $15 million was reflected as a return of capital and, as a result, reduced paid-in capital. As of August 25, 1999, approximately $34 million of retained earnings was reclassified as additional paid-in capital.
The electric and natural gas industries have continued to change in response to legislative, regulatory and marketplace demands for improved customer service at lower prices. These demands have resulted in an increasing trend in the industry to seek competitive advantages and other benefits through business combinations. NSTAR was created to operate in this new marketplace by combining the resources of its utility subsidiaries and concentrating its activities in the transmission and distribution of energy. This is illustrated by the sale of Boston Edison's fossil generating facilities in 1998 and its nuclear generating facility in 1999. Substantially all of COM/Energy's generating facilities were sold in 1998.
The utility companies of NSTAR form an energy delivery company serving approximately 1.3 million customers located in Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities.
The merger became effective after receipt of various regulatory approvals. The Federal Energy Regulatory Commission approved the merger on June 24, 1999. The Nuclear Regulatory Commission approved the transfer of control of subsidiary Canal Electric's interest in the Seabrook nuclear plant from COM/Energy to NSTAR on August 11, 1999. The Securities and Exchange Commission issued its approval on August 24, 1999.
An integral part of the merger is the rate plan that was filed by the retail utility subsidiaries of BEC and COM/Energy in February 1999 and approved by the MDTE on July 27, 1999. Significant elements of the rate plan include a four- year distribution rate freeze (after an adjustment to the distribution rates of affiliate Cambridge Electric and the Company to collect the appropriate level of distribution costs that is offset by a reduction in the transition charge that was previously approved by the MDTE), recovery of the acquisition premium (goodwill) over 40 years and recovery of transaction and integration costs (costs to achieve) over 10 years.
The merger was accounted for by BEC as an acquisition of COM/Energy under the purchase method of accounting. The total goodwill associated with the acquisition was approximately $486 million on a consolidated basis, while the original estimate of costs to achieve the merger was $111 million on a consolidated basis. Costs to achieve which have been allocated to the Company were approximately $18.6 million as of December 31, 1999, and are included as merger costs in regulatory assets on the Company's balance sheet (Note 2(c)). Costs to achieve will be recovered over the amortization period of 10 years. The amount of goodwill allocated to the Company as of the merger date was approximately $235 million, and is being amortized over a period of 40 years. A portion of the goodwill amortization will be allocated to Boston Edison Company (an NSTAR subsidiary) on an anuual basis in accordance with the MDTE rate order approving the merger.
A group of four intervenors and the Massachusetts Attorney General filed two separate appeals of the MDTE's rate plan order with the Massachusetts Supreme Judicial Court (SJC) in August 1999. While management anticipates that the MDTE's decision to approve the rate plan will be upheld by the SJC, it is unable to determine the ultimate outcome of these appeals or their impact on the rate plan.
Provisions of Statement of Financial Accounting Standards No. 71 - ----------------------------------------------------------------
As described in Note 2(b) of the Notes to Financial Statements, the Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In the event the Company is somehow unable to meet the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations in an amount that could be material. Conditions that could give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition restricting the Company's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators. The Company monitors these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its utility operations remain subject to SFAS No. 71 and its regulatory assets.
Year 2000 - ---------
NSTAR's mission critical systems and other important business systems were considered ready for the year 2000 prior to December 31, 1999. The North American Electric Reliability Council defined mission critical systems as those whose mis-operation could result in loss of electric generation, transmission or load interruption. To date, NSTAR has not experienced any significant year 2000 problems. NSTAR will continue to monitor systems in order to address any potential continuing risk of non-compliant internal business software, internal non-business software and embedded chip technology and external noncompliance of third parties.
Under its year 2000 program NSTAR inventoried mission critical systems that were date-sensitive and that used embedded technology such as micro-controllers or microprocessors. Approximately 27% and 20% of BEC's and COM/Energy's systems, respectively, required modification or replacement.
NSTAR also inventoried important business systems that were date-sensitive and determined that approximately one-third of BEC's systems and approximately 90% of COM/Energy's systems needed modification or replacement. Plans were developed and implemented to correct and test all affected systems, with priorities based on the importance of the supported activity. As systems were remediated, they were tested for operational and year 2000 readiness in their own environment. After implementation, the systems were then tested for their integration and compatibility with other interactive systems.
In addition, all non-critical internal productivity systems were inventoried and assessed as part of the year 2000 program. Approximately one-third of BEC's systems and approximately 90% of COM/Energy's systems required modification or replacement. All of these systems were declared ready by September 30, 1999.
Costs incurred to upgrade or remediate systems have been expensed as incurred. In addition, a decision was made to replace some of the less efficient centralized business systems. Systems replacement costs are being capitalized and amortized over future periods. NSTAR has expended a total of approximately $39 million on this project through December 31, 1999. Future costs are anticipated to be immaterial.
In addition to its internal efforts, BEC and COM/Energy initiated formal communications with their significant suppliers, service providers and other vendors to determine the extent to which they may be vulnerable to these parties' failure to correct their own year 2000 issues. To date, NSTAR has not experienced any significant year 2000 problems associated with its reliance on third parties.
NSTAR's year 2000 program included contingency plans. If required, these plans were intended to address both internal risks as well as potential external risks related to vendors, customers and energy suppliers. Plans were developed in conjunction with available national and regional guidance and were based on system emergency plans that were developed and successfully tested over the past several years. Included within its contingency plans were procedures for the procurement of short-term power supplies and emergency distribution system restoration procedures. In the event that a problem is to arise in 2000 (or beyond), these contingency plans would become effective in order to remediate the problem.
Environmental Matters - ---------------------
The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installation of expensive air and water pollution control equipment. These regulations have had an impact on the Company's operations in the past, however their impact on future operations, capital costs and construction schedules is not expected to be significant since all of the Company's non-nuclear generating assets were sold in 1998.
New Accounting Principles - -------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed-price fuel supply and power contracts) be recorded on the Consolidated Balance Sheets as either an asset or liability measured at its fair value, SFAS 133, as amended by SFAS 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No 133", is effective for fiscal years beginning after June 15, 2000 (January 1, 2001 for calendar year companies). Initial application shall be as of the beginning of an entity's fiscal quarter.
The Company will adopt SFAS 133 as of January 1, 2001. The impact of adoption cannot be currently estimated and will be dependent upon the fair value, nature and purpose of the derivative instruments held, if any, as of January 1, 2001.
Safe Harbor Cautionary Statement - --------------------------------
Management 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 Securities and Exchange Commission (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 operating results, year 2000 and environmental and legal issues.
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, management 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 estimated litigation costs.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk - -------- ----------------------------------------------------------
Although the Company has material commodity purchase contracts and financial instruments (debt), these instruments are not subject to market risk. The Company has a standard offer service mechanism which allows for the recovery of fuel costs from customers. The fuel adjustment mechanism allows the Company to pass all costs related to the purchase of commodities to the customer, thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's prudently incurred debt obligations realized by the Company would be borne by customers through future rates.
Item 8.
Item 8. Financial Statements and Supplementary Data - ------- -------------------------------------------
The Company's financial statements required by this item are filed herewith on pages 23 through 43 of this report.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting - ------- ----------------------------------------------------------- and Financial Disclosure ------------------------
None.
Item 8. Financial Statements and Supplementary Data - ------- -------------------------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------
To the Board of Directors of Commonwealth Electric Company:
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on page 34, present fairly, in all material respects, the financial position of Commonwealth Electric Company at December 31, 1999, and the results of its operations and its cash flows for the period from January 1, 1999 through August 24, 1999 and for the period from August 25, 1999 through December 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 14(a)(2) on page 34, present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States, 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 audit provides a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP Boston, Massachusetts January 26, 2000
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Commonwealth Electric Company:
We have audited the accompanying balance sheets of COMMONWEALTH ELECTRIC COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Commonwealth Energy System) as of December 31, 1998, and the related statements of income, retained earnings and cash flows for each of the two years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Commonwealth Electric Company as of December 31, 1998, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP Boston, Massachusetts February 18, 1999
COMMONWEALTH ELECTRIC COMPANY ----------------------------- INDEX TO FINANCIAL STATEMENTS AND SCHEDULES ------------------------------------------- PART II. --------
ITEM 8
FINANCIAL STATEMENTS
Report of Independent Public Accountants.......................... 15
Balance Sheets at December 31, 1999 and 1998...................... 18
Statements of Income for the 1999 periods August 25 to December 31 and January 1 to August 24 and for the Years Ended December 31, 1998 and 1997........................................ 20
Statements of Retained Earnings for the Years Ended December 31, 1999, 1998 and 1997.................................. 21
Statements of Cash Flows for the 1999 periods August 25 to December 31 and January 1 to August 24 and for the Years Ended December 31, 1998 and 1997........................................ 22
Notes to Financial Statements..................................... 23
PART IV. --------
SCHEDULES
Valuation and Qualifying Accounts - Years Ended December 31, 1999, 1998 and 1997
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or not required or because the required information is included in the financial statements or notes thereto.
Financial statements of 50% or less owned companies accounted for by the equity method have been omitted because they do not, considered individually, constitute a significant subsidiary.
COMMONWEALTH ELECTRIC COMPANY ----------------------------- BALANCE SHEETS -------------- DECEMBER 31, 1999 AND 1998 -------------------------- ASSETS ------
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY ----------------------------- BALANCE SHEETS -------------- DECEMBER 31, 1999 AND 1998 -------------------------- CAPITALIZATION AND LIABILITIES ------------------------------
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY ----------------------------- STATEMENTS OF INCOME --------------------
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY ----------------------------- STATEMENTS OF RETAINED EARNINGS ------------------------------- FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 ----------------------------------------------------
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS -----------------------------
(1) General Information -------------------
Commonwealth Electric Company (the Company) is a wholly-owned subsidiary of NSTAR. NSTAR is the new holding company that was formed, effective August 25, 1999, after receipt of all necessary approvals and upon completion of a merger transaction between Commonwealth Energy System (COM/Energy, formerly the parent of the Company) and BEC Energy formerly the parent company of Boston Edison Company). The merger creates and energy delivery company that includes the Company, serving approximately 1.3 million customers located in Massachusetts including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities. NSTAR is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 and, in addition to its investment in the Company, has interests in various other utility and nonregulated companies. The Company's operations have been involved in the production, distribution and sale of electricity to 327,000 customers (including 45,500 seasonal) in 40 communities located in southeastern Massachusetts, including Cape Cod and the island of Martha's Vineyard, having an approximate year-round population of 549,000 and a large influx of summer residents.
The Company has 629 regular employees including 470 (74.7%) represented by three collective bargaining units covered by separate contracts with expiration dates of October 2001 , September 2002 and April 2003. Employee relations have generally been satisfactory.
In response to the significant changes that have taken place in the utility industry, the Company sold all of its non-nuclear generating assets in 1998 to focus on the transmission and distribution of energy and related services.
(2) Significant Accounting Policies -------------------------------
(a) Principles of Accounting ------------------------
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure 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 those estimates.
Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements.
(b) Merger and Financial Statement Presentation -------------------------------------------
On August 25, 1999 BEC Energy (BEC) and COM/Energy merged to form NSTAR as an exempt public utility holding company. NSTAR's utility subsidiaries include the Company. The merger was accounted for by NSTAR as an acquisition by BEC of COM/Energy and all of its subsidiaries including the Company come under the purchase method of accounting.
In the accompanying statements, the Company prior to the merger is labeled as the "Predecessor" and after the merger as the "Successor."
As a result of this merger, the fourth quarter dividend amounting to approximately $15 million was reflected as a return of capital and, as a result, reduced paid-in capital. As of August 25, 1999, approximately $34 million of retained earnings was reclassified as additional paid-in capital.
The merger was accounted for by BEC as an acquisition of COM/Energy under the purchase method of accounting. The total goodwill associated with the acquisition was approximately $486 million on a consolidated basis, while the original estimate of costs to achieve the merger was $111 million on a consolidated basis. Costs to achieve which have been allocated to the Company were approximately $18.6 million as of December 31, 1999, and are included as merger costs in regulatory assets on the Company's balance sheet (Note 2(c)). Costs to achieve will be recovered over the amortization period of 10 years. The amount of goodwill allocated to the Company as of the merger date was approximately $235 million, and is being amortized over a period of 40 years. A portion of the goodwill amortization will be allocated to the Boston Edison Company (an NSTAR subsidiary) on an annual basis in accordance with the MDTE rate order approving the merger.
(c) Regulatory Assets and Liabilities ---------------------------------
The Company is regulated as to rates, accounting and other matters by various authorities, including the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, the Company accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." The Company has established various regulatory assets in cases where the DTE and/or the FERC have permitted or are expected to permit recovery of specific costs over time. Similarly, the regulatory liabilities established by the Company are required to be refunded to customers over time. In the event the criteria for applying SFAS No. 71 are no longer met, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts the Company's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators from cost based regulation to another form of regulation. These criteria are reviewed on a regular basis to ensure the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its regulatory assets, including those related to generation, are probable of future recovery.
The principal regulatory assets included in deferred charges were as follows:
The regulatory liability of $293.2 million was established pursuant to the Company's divestiture filing that was approved by the MDTE in which the
Company agreed to use its share of the net proceeds from affiliate Canal Electric Company's (Canal Electric) sale of generation assets and the sale of its own generating assets to reduce transition costs that are billed to its retail electric customers over the next several years as a result of electric industry restructuring. COM/Energy established Energy Investment Services, Inc. as the vehicle to invest the net proceeds from the sale of Canal Electric's generating assets. These proceeds are invested in a conservative portfolio of securities that is designed to maintain principal and earn a reasonable return. Both the principal amount and income earned will be used to reduce the transition costs that would otherwise be billed to customers of the Company and Cambridge Electric. The Company's share of the net proceeds from the sale of Canal Electric's generating assets has been classified as a long-term receivable-affiliate on the accompanying Balance Sheets.
The Company's regulatory assets, including the costs associated with an existing power contract with the Yankee Atomic nuclear power plant that was shut down permanently (see Note 3(d)), and all of its regulatory liabilities are reflected in rates charged to customers. Regulatory assets are to be recovered over the next 11 years pursuant to the legislation discussed below.
In November 1997, the Commonwealth of Massachusetts enacted a comprehensive Electric Utility Restructuring Act. On November 19, 1997, the Company, together with affiliates Cambridge Electric Light Company (Cambridge Electric) and Canal Electric, filed a restructuring plan with the MDTE. The plan, approved by the MDTE on February 27, 1998, provides that the Company and Cambridge Electric, beginning March 1, 1998, initiate a ten percent rate reduction for all customer classes and allow customers to choose their energy supplier. As part of the plan, the MDTE authorized the recovery of certain strandable costs and provides that certain future costs may be deferred to achieve or maintain the rate reductions that the restructuring bill mandates. The legislation gives the MDTE the authority to determine the amount of strandable costs that will be eligible for recovery. Costs that will qualify as strandable costs and be eligible for recovery include, but are not limited to, certain above market costs associated with generating facilities, costs associated with long-term commitments to purchase power at above market prices from independent power producers and regulatory assets and associated liabilities related to the generation portion of the electric business.
(c) Transactions with Affiliates ----------------------------
Transactions between the Company and other NSTAR companies include purchases and sales of electricity, including purchases from Canal Electric, an affiliated wholesale electric generating company. Other Canal transactions include costs relating to the abandonment of Seabrook 2 (in 1997) and the recovery of a portion of Seabrook 1 pre-commercial operation costs. In addition, payments for management, accounting, data processing and other services are made to an affiliate, COM/Energy Services Company. Transactions with other COM/Energy companies are subject to review by the MDTE.
The Company's operating expenses include the following major intercompany transactions for the periods indicated:
The costs for the Canal and Seabrook 1 units are included in the long-term obligation table listed in Note 3(b). The Company sold electricity to other affiliates, primarily station service for Canal, totaling $0, $1,026,000, and $1,290,000 in 1999, 1998 and 1997, respectively.
(d) Operating Revenues ------------------
Customers are billed for their use of electricity on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month.
The Company is generally permitted to bill customers for costs associated with purchased power and transmission, fuel used in electric production and conservation and load management (C&LM) costs. The amount of such costs incurred by the Company but not yet reflected in customers' bills is recorded as unbilled revenues.
(e) Depreciation ------------
Depreciation is provided using the straight-line method at rates intended to amortize the original cost and the estimated cost of removal less salvage of properties over their estimated economic lives. The average composite depreciation rates were 3.53% in 1999, 3.33% in 1998 and 3.32% in 1997.
(f) Maintenance -----------
Expenditures for repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expense. Additions, replacements and renewals of property considered to be units of property are charged to the appropriate plant accounts. Upon retirement, accumulated depreciation is charged with the original cost of property units and the cost of removal less salvage.
(g) Allowance for Funds Used During Construction --------------------------------------------
Under applicable rate-making practices, the Company is permitted to include an allowance for funds used during construction (AFUDC) as an element of its depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which the Company earns a return. An amount equal to the AFUDC capitalized in the current period is reflected in other interest charges in the Company's Statements of Income and amounted to $162,000, $163,000 and $145,000 in 1999, 1998 and 1997, respectively.
While AFUDC does not provide funds currently, these amounts are recoverable in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 5.25% in 1999, 5.75% in 1998 and 6.25% in 1997.
(3) Commitments and Contingencies -----------------------------
(a) Financing and Construction Programs -----------------------------------
The Company is engaged in a continuous construction program presently estimated at $139.8 million for the five-year period 2000 through 2004. Of that amount, $32 million is estimated for 2000. The program is subject to periodic review and revision because of factors such as changes in business conditions, rates of customer growth, effects of inflation, maintenance of reliable and safe service, equipment delivery schedules, licensing delays, availability and cost of capital and environmental factors. The Company expects to finance these expenditures on an interim basis with internally generated funds and short-term borrowings that are ultimately expected to be repaid with the proceeds from sales of long-term debt and equity securities.
(b) Long-Term Contracts for the Purchase of Electricty --------------------------------------------------
The Company has long-term contracts to purchase capacity from various generating facilities. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. In addition, the Company pays its share of decommissioning expenses under its nuclear contracts.
NSTAR on behalf of the Company, entered into a six-month agreement effective January 1, 2000 to transfer all of the unit output entitlements in long-term power purchase contracts to Select Energy (Select), a subsidiary of Northeast Utilities, In return, Select will provide full energy service requirements, including NEPOOL capability responsibilities, at FERC approved tariff rates through June 30 2000.
Information relating to the contracts as of December 31, 1999 is as follows:
Energy is paid for based on a price per kWh actually received. In 1999, the Company's did not pay a proportionate share of capital and fixed operating costs for 229.4 MW purchased.
The Company's total fixed and variable costs associated with these contracts in 1999, 1998 and 1997 were approximately $251 million, $267 million and $288 million, respectively. The Company's capacity charge obligation under these contracts for the years after 1999 are as follows:
Capacity Charge (in thousands) Obligation - -------------------------------------------------------- 2000 $ 80,182 2001 56,722 2002 56,673 2003 51,095 2004 50,963 Years thereafter 657,660 - -------------------------------------------------------- Total $ 953,295 ========================================================
(c) Pilgrim Power Contract ----------------------
The Company had an 11% (73.6 megawatts) contract entitlement in the output of the Pilgrim nuclear power plant, located in Plymouth, MA, which was sold by Boston Edison Company (Boston Edison) on July 13, 1999 to Entergy Nuclear Generating Company (Entergy). On April 29, 1999, the Nuclear Regulatory Commission issued an order approving the transfer of the operating license for the plant from Boston Edison to Entergy. In conjunction with this sale, the Company reached an agreement with Boston Edison to buy out of this life-of-the-unit contract, terminating the Company's rights and obligations under the contract regarding the power output of the plant. Pursuant to the buy-out agreement, the Company paid approximately $105 million in July 1999 to terminate this contract with Boston Edison. The buy-out was paid with funds held by affiliate EIS (see Note 2(b)) that were provided from the Company's share of the net proceeds from Canal Electric's sale of its generating assets. The DTE approved the buy-out transaction as a mitigation measure and approved inclusion of the buy-out payment as a transition cost for purposes of cost recovery by the Company. In a transaction related to the sale of the Pilgrim plant, the Company will buy power generated by the Pilgrim plant from Entergy on a declining basis through 2004.
(d) Environmental Matters ---------------------
The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installation of expensive air and water pollution control equipment. These regulations have had an impact on the Company's operations in the past and will continue to have an impact on future operations, capital costs and construc- tion schedules of major transmission and distribution facilities.
(4) Income Taxes ------------
For financial reporting purposes, the Company provides federal and state income taxes on a separate-return basis. However, for federal income tax purposes, the Company's taxable income and deductions are included in the consolidated income tax return of NSTAR (COM/Energy prior to the merger), the Parent and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations.
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.
Accumulated deferred income taxes consisted of the following:
The effective income tax rates reflected in the accompanying financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
The following is a summary of the Company's provisions for income taxes for the years ended December 31, 1999, 1998 and 1997:
The significant change in the current and deferred provisions for income taxes in 1998 reflects the current tax related to the sale of the company's non- nuclear generating assets and the related deferred tax benefit.
(5) Employee Benefit Plans ----------------------
Effective December 31, 1999, the pension and other postretirment benefit plans of BEC and COM/Energy were combined under NSTAR.
(a) Pension -------
NSTAR has a defined benefit funded retirement plan with certain contribution features that covers substantially all employees, including employees of the Company. NSTAR also maintains an unfunded supplemental retirement plan for certain management employees. Effective January 1, 2000, the defined benefit plan was amended to provide management employees lump sum benefits under a final average pay pension equity formula. Prior to January 1, 2000 these pension benefits were provide under a traditional final average pay formula. This amendment is reflected in the December 31, 1999 benefit obligation.
The periodic costs allocated to the Company was $2,639,000, $3,324,000 and $3,702,000 in 1999, 1998 and 1997, respectively. The accrued pension cost in the Company's statement of financial position was $10,470,000 and $7,427,000 in 1999 and 1998, respectively.
As a result of the merger-related separation packages, amounts recognized for curtailment and special termination benefit costs were $4,928,000 and $3,605,000, respectively, for 1999. These amounts are recoverable as part of the approved rate plans of the retail utility subsidiaries of NSTAR.
(b) Other Postretirement Benefits -----------------------------
Certain employees are eligible for postretirement benefits if they meet specific requirements. These benefits could include health and life insurance coverage and reimbursement of Medicare Part B premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits.
To fund postretirement benefits, the Company makes contributions to various voluntary employees; beneficiary association (VEBA) trusts that were established pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The Company also makes contributions to a subaccount of the COM/Energy pension plan and its successor pursuant to section 401(h) of the Code to fund a portion of its postretirement benefit obligation.
The funded status of the Plan cannot be presented separately for the Company since the Company participates in the Plan trusts and subaccount with other subsidiaries of NSTAR. Plan assets are available to provide benefits for all Plan participants who are former employees of the Company and of other subsidiaries of NSTAR.
The net periodic postretirement benefit cost allocated to the Company was $4,883,000, $5,418,000 and $5,654,000 in 1999, 1998 and 1997, respectively. The accrued benefit cost in the Company's statement of financial position was $32,157,000 and $0 at December 31, 1999 and 1998, respectively.
(c) Savings Plan ------------
The Company has an Employees Savings Plan that provides for Company contributions to eligible employees. The total Company contribution was $1,441,000 in 1999, $1,435,000 in 1998 and $1,672,000 in 1997.
(6) Long-Term Debt and Interim Financing ------------------------------------
(a) Long-Term Debt Maturities and Retirements -----------------------------------------
Long-term debt outstanding, exclusive of current maturities, current sinking fund requirements and related premiums, is as follows:
The Company, under favorable conditions, may purchase its outstanding notes in advance; however, an early payment premium may be incurred. Certain of these agreements require the Company to make periodic sinking fund payments for retirement of outstanding long-term debt.
The required sinking fund payments for the five years subsequent to December 31, 1998 are as follows:
(b) Notes Payable to Banks ----------------------
The Company and other NSTAR companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs and other corporate purposes. As of December 31, 1999, NSTAR had
$115 million of committed lines of credit that will expire at varying intervals in 2000. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1998, the uncommitted lines of credit totaled $10 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 5.8% in 1999 and 1998, respectively. The Company had notes payable to banks of $20,600,000 at December 31, 1999 and no notes outstanding at December 31, 1998.
(c) Advances from Affiliates ------------------------
The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among affiliates whereby short-term cash surpluses are used to help meet the short-term borrowing needs of the utility subsidiaries. In general, lenders to the Pool receive a higher rate of return than they otherwise would on such investments, while borrowers pay a lower interest rate than those available from banks. Interest rates on the outstanding borrowings are based on the monthly average rate the Company would otherwise have to pay banks, less one- half the difference between that rate and the monthly average U.S. Treasury Bill weekly auction rate. The borrowings are for a period of less than one year and are payable upon demand. Rates on these borrowings averaged 5.1% and 5.3% in 1999 and 1998, respectively. Notes payable to the Pool totaled $6,455,000 and $40,350,000 at December 31, 1999 and 1998, respectively.
The Company had no notes payable to the Parent at December 31, 1999 or December 31, 1998. However, this source of financing may be utilized by the Company and notes are written for a term of up to 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in that rate during the term of the notes. The rate averaged 8% and 8.3% in 1999 and 1998, respectively.
(d) Disclosures About Fair Value of Financial Instruments -----------------------------------------------------
The fair value of certain financial instruments included in the accompanying Balance Sheets as of December 31, 1999 and 1998 are as follows:
The carrying amount of cash, notes payable to banks and advances to/from affiliates approximates the fair value because of the short maturity of these financial instruments.
The estimated fair value of long-term debt is based on quoted market prices of the same or similar issues or on the current rates offered for debt with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled.
(7) Dividend Restriction --------------------
At December 31, 1999, there was no common equity restricted against the payment of cash dividends pursuant to the Company's term loans and note agreements securing long-term debt.
(8) Lease Obligations -----------------
The Company leases equipment and office space under arrangements that are classified as operating leases. These lease agreements are for terms of one year or longer. Leases currently in effect contain no provisions that prohibit the Company from entering into future lease agreements or obligations.
Future minimum lease payments, by period and in the aggregate, of non-cancelable operating leases consisted of the following at December 31, 1998:
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $2,766,000 in 1999, $2,718,000 in 1998 and $3,174,000 in 1997. There were no contingent rentals and no sublease rentals for the years 1999, 1998 and 1997.
PART IV. --------
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - ------------------------------------------------------------------------
(a) 1. Index to Financial Statements -----------------------------
Financial statements and notes thereto of the Company together with the Report of Independent Public Accountants, are filed under Item 8 of this report and listed on the Index to Financial Statements and Schedules (page 17).
(a) 2. Index to Financial Statement Schedules --------------------------------------
Filed herewith at page(s) indicated -
Schedule II - Valuation and Qualifying Accounts - Years Ended December ----------- 31, 1999, 1998 and 1997 (page 43).
(a) 3. Exhibits: -------- Notes to Exhibits - -------------------
a. Unless otherwise designated, the exhibits listed below are incorporated by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses.
b. During 1981, the Company sold its gas business and properties to Commonwealth Gas and changed its corporate name from New Bedford Gas and Edison Light Company to Commonwealth Electric Company.
c. The following is a glossary of NSTAR and subsidiary companies' acronyms that are used throughout the following Exhibit Index:
CES ...................... Commonwealth Energy System CEL ...................... Cambridge Electric Light Company CEC ...................... Canal Electric Company CG ....................... Commonwealth Gas Company NBGEL .................... New Bedford Gas and Edison Light Co.
EXHIBIT INDEX:
Exhibit 3. Articles of incorporation and by-laws - ---------- -------------------------------------
3.1.1 By-laws of the Company as amended, (Refiled as Exhibit 1 to the CE 1991 Form 10-K, File No. 2-7749).
3.1.2 Articles of Incorporation, as amended, of NBGEL, including certification of name change to Commonwealth Electric Company as filed with the Massachusetts Secretary of State on March 1, 1981 (Refiled as Exhibit 1 to the CE 1990 Form 10-K, File No. 2-7749).
Exhibit 10. Material Contracts. - ----------- -------------------
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the CE 1991 Form 10-K, File No. 2-7749).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE Form 10-Q (June 1988), File No. 2-7749).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989), File No. 2-7749).
10.1.3 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated August 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.3.1 Service Agreement between NBGEL and BECO for purchase of stand-by power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.3.2 System Power Sales Agreement by and between CE and BECO dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2- 7749).
10.1.3.3 Power Exchange Agreement by and between BECO and CE dated December 1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.4 Agreement for Joint-Ownership, Construction and Operation of New Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1 dated October 1973, File No. 2-49013), and as amended below:
10.1.5 Purchase and Sale Agreement together with an implementing Addendum dated December 31, 1981, between CE and CEC, for the purchase and sale of the CE 3.52% joint-ownership interest in the Seabrook units, dated January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File No. 2-7749).
10.1.5.1 Agreement to transfer ownership, construction and operational interest in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981 (Refiled as Exhibit 3 to the CE 1991 Form 10-K, File No. 2-7749).
10.1.6 Power Contract, as amended to February 28, 1990, superseding the Power Contract dated September 1, 1986 and amendment dated June 1, 1988, between CEC (seller) and CE and CEL (purchasers) for seller's entire share of the Net Unit Capability of Seabrook 1 and related energy (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-30057).
10.1.7 Capacity Acquisition Agreement between CEC,CEL and CE dated September 25, 1980 (Exhibit 1 to the CEC 1991 Form 10-K, File No. 2-30057).
10.1.7.1 Supplement to 10.1.7 consisting of three Capacity Acquisition Commitments each dated May 7, 1987, concerning Phases I and II of the Hydro-Quebec Project and electricity acquired from Connecticut Light and Power Company CL&P) (Exhibit 1 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.7.2 Amendment to 10.1.7 as amended and restated June 1, 1993, henceforth referred to as the Capacity Acquisition and Disposition Agreement, whereby CEC, as agent, in addition to acquiring power may also sell bulk electric power which CEL and/or the Company owns or otherwise has the right to sell (Exhibit 1 to the CEC Form 10-Q (September 1993), File No. 2-30057).
10.1.8 Phase 1 Vermont Transmission Line Support Agreement and Amendment No. 1 thereto between Vermont Electric Transmission Company, Inc. and certain other New England utilities, dated December 1, 1981 and June 1, 1982, respectively (Refiled as Exhibits 5 and 6 to the 1992 CE Form 10-K, File No. 2-7749).
10.1.8.1 Amendment No. 2 to 10.1.8 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.8.2 Amendment No. 3 to 10.1.8 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749).
10.1.9 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for the purchase of available hydro-electric energy produced by a facility located in Ware, Massachusetts, dated September 1, 1983 (Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.10 Power Purchase Agreement between Corporation Investments, Inc. (CI), and CE for the purchase of available hydro-electric energy produced by a facility located in Lowell, Massachusetts, dated January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.10.1 Amendment to 10.1.12 between CI and Boott Hydropower, Inc., an assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.11 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corporation (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.11.1 Amendment No. 3 to 10.1.11 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749).
10.1.12 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amendment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.13 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.13.1 Amendatory Agreement No. 3 to 10.1.13 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.14 Phase I New Hampshire Transmission Line Support Agreement between NEET and certain other New England Utilities dated December 1, 1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.15 Agreement, dated September 1, 1985, with Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain NEPOOL utilities to include Phase II facilities in the definition of "Project" (Exhibit 1 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.16 Preliminary Quebec Interconnection Support Agreement - Phase II among certain New England electric utilities dated June 1, 1984 (Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.1 First, Second and Third Amendments to 10.1.16 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.16.2 Fifth, Sixth and Seventh Amendments to 10.1.16 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.16.3 Fourth and Eighth Amendments to 10.1.16 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057).
10.1.16.4 Ninth and Tenth Amendments to 10.1.16 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.16.5 Eleventh Amendment to 10.1.16 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.16.6 Twelfth Amendment to 10.1.16 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.17 Phase II Equity Funding Agreement for New England Hydro-Transmission Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.18 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.19 Phase II New Hampshire Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 8 dated May 1, 1986 through January 1, 1990, respectively, between New England Hydro-Transmission Corporation (New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.20 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June 1, 1985, between New Hampshire Hydro and certain NEPOOL util- ities (Ex. 3 to the CEC Form 10-Q (Sept. 1985), File No. 2-30057).
10.1.20.1 Amendment No. 1 to 10.1.20 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.20.2 Amendment No. 2 to 10.1.20 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.21 Phase II New England Power AC Facilities Support Agreement, dated June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.21.1 Amendments Nos. 1 and 2 to 10.1.21 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.21.2 Amendments Nos. 3 and 4 to 10.1.21 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.22 Phase II Boston Edison AC Facilities Support Agreement, dated June 1, 1985, between BECO and certain NEPOOL utilities (Exhibit 7 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.22.1 Amendments Nos. 1 and 2 to 10.1.22 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.22.2 Amendments Nos. 3 and 4 to 10.1.22 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.23 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Agreements by and between Swift River Company and CE for the purchase of available hydro-electric energy to be produced by units located in Chicopee and North Willbraham, Massachusetts, both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.24.1 Transmission Service Agreement between Northeast Utilities' companies (NU) - The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO), and CE for NU companies to transmit power purchased from Swift River Company's Chicopee Units to CE, dated October 1, 1984 (Exhibit 14 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.24.2 Transformation Agreement between WMECO and CE whereby WMECO is to transform power to CE from the Chicopee Units, dated December 1, 1984 (Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.25 Power Purchase Agreement by and between SEMASS Partnership, as seller, to construct, operate and own a solid waste disposal facility at its site in Rochester, Massachusetts and CE, as buyer of electric energy and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.25.1 Power Sales Agreement to 10.1.25 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749).
10.1.25.2 Amendment to 10.1.25 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-7749).
10.1.25.3 Second Amendment to 10.1.25.2 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated May 24, 1991 (Exhibit 1 to the CE Form 10-Q (June 1991), File No. 2-7749).
10.1.26 Power Sale Agreement by and between CE (buyer) and Northeast Energy Associates, Ltd. (NEA) (seller) of electric energy and capacity, dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File No. 2-7749).
10.1.26.1 First Amendment to 10.1.26 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.26.2 Second Amendment to 10.1.26 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.26.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the purchase of 21 MW of electricity (Exhibit 2 to the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.26.4 Amendment to 10.1.26.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.27 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between CE (buyer) and Dartmouth Power Associates Limited Partnership (seller), whereby buyer will purchase all of the energy (67.6 MW) produced by a single gas turbine unit (Exhibit 1 to the CE Form 10-Q (June 1992), File No. 2- 7749).
10.1.27.1 Second Amendment, dated June 23, 1994, to 10.1.27 (Exhibit 4 to the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.28 Power Purchase Agreement by and between Masspower (seller) and the Company (buyer) for a 11.11% entitlement to the electric capacity and related energy of a 240 MW gas-fired cogeneration facility, dated February 14, 1992 (Exhibit 1 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.29 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller) and the Company (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 2 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.29.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., CEL, the Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.29.2 First Amendment, dated November 7, 1994, to 10.1.29 by and between the Company and Altresco Pittsfield, L.P. dated February 20, 1992
10.2 Other agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to the CES Form 10-Q (Sept. 1993), File No. 1-7316).
10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies as amended and restated as of January 1, 1993 (Ex-hibit 2 to the CES Form 10-Q (September 1993), File No. 1-7316).
10.2.2.1 First Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1-7316).
10.2.2.2 Second Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective April 1, 1996. (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.2.2.3 Third Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective January 1, 1997. (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
10.2.2.4 Fourth Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective January 1, 1998. (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1998), File No. 1-7316).
10.2.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980 (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731).
10.2.3.1 Thirteenth Amendment to 10.2.3 as amended September 1, 1981 (Refiled as Exhibit 3 to the CES 1991 Form 10-K, File No. 1-7316).
10.2.3.2 Fourteenth through Twentieth Amendments to 10.2.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (Sept. 1985), File No. 1-7316).
10.2.3.3 Twenty-first Amendment to 10.2.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316).
10.2.3.4 Twenty-second Amendment to 10.2.3 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (Sept. 1986), File No. 1-7316).
10.2.3.5 Twenty-third Amendment to 10.2.3 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316).
10.2.3.6 Twenty-fourth Amendment to 10.2.3 as amended March 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.2.3.7 Twenty-fifth Amendment to 10.2.3. as amended to May 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316).
10.2.3.8 Twenty-sixth Agreement to 10.2.3 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.2.3.9 Twenty-seventh Agreement to 10.2.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316).
10.2.3.10 Twenty-eighth Agreement to 10.2.3 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.2.3.11 Twenty-ninth Agreement to 10.2.3 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316).
(b) Reports on Form 8-K -------------------
No reports on Form 8-K were filed during the three months ended December 31, 1998.
Exhibit 27. Financial Data Schedule - -----------------------------------
Filed herewith as Exhibit 1 is the Financial Data Schedule for the year ended December 31, 1999.
SCHEDULE II
COMMONWEALTH ELECTRIC COMPANY ----------------------------- VALUATION AND QUALIFYING ACCOUNTS --------------------------------- FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 and 1997 ----------------------------------------------------
(Dollars in thousands)
(a) includes $354,000 adjustment to provision.
FORM 10-K DECEMBER 31, 1999 --------- -----------------
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.
COMMONWEALTH ELECTRIC COMPANY ----------------------------- (Registrant)
By: /s/ THOMAS J. MAY ------------------------------ Thomas J. May, Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Principal Executive Officers:
/s/THOMAS J. MAY March 30, 2000 - --------------------------------------------- Thomas J. May Chairman of the Board and Chief Executive Officer
/s/R. D. WRIGHT March 30, 2000 - --------------------------------------------- R. D. Wright, President and Chief Operating Officer
Principal Financial and Accounting Officer:
/s/ROBERT J. WEAFER, JR March 30, 2000 - --------------------------------------------- Robert J. Weafer, Jr., Vice President, Controller and Chief Accounting Officer
A majority of the Board of Directors:
/s/THOMAS J. MAY March 30, 2000 - --------------------------------------------- Thomas J. May, Director
/s/R. D. WRIGHT March 30, 2000 - --------------------------------------------- Russell D. Wright, Director
/s/JAMES J. JUDGE March 30, 2000 - --------------------------------------------- James J. Judge, Director