Item 1. Business
General
Commonwealth Electric Company (the Company) is engaged in the generation, transmission, distribution and sale of electricity to approximately 322,300 retail customers (including 46,100 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 results of the 1990 federal census taken in the Company's service area indicated a population increase of 18.1% since 1980. The Company also sells power to the Independent System Operator (ISO) - New England (formerly the New England Power Pool that operates a centralized facility to ensure reliability of service and dispatch of economically available generating units throughout New England), and is actively marketing sales of certain available capacity to other utilities in and outside the New England region. In early 1997, the Company received approval to participate as a broker in the purchase and sale of electricity.
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 (DTE) (formerly the Massachusetts Department of Public Utilities) 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). Since the date of its organization, the Company has from time to time acquired or disposed of the property and franchises of or merged with various gas or electric companies. The Company is a wholly- owned subsidiary of Commonwealth Energy System (System), which, together with its subsidiaries, is collectively referred to as "the system."
By virtue of its charter, which is unlimited in time, the Company purchases, distributes and sells electricity without direct competition in kind from any privately or municipally-owned utilities. Alternate sources of energy are available to customers within the service territory, but competi- tion from these sources has not been significant. However, on November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act that subjects the generation element of traditional electric utility operations to competition, effective March 1, 1998. For further details, refer to the "Industry Restructuring" section of Management's Discussion and Analysis of Results of Operations in Item 7 of this report. Of the Company's 1997 retail electric unit sales (74.9% of total sales), 47.4% was sold to residential customers, 41.7% to commercial customers, 10.5% to industrial and 0.4% to streetlighting and similar types of customers.
Electric Power Supply
The Company relies almost entirely on purchased power to meet its electric energy requirements. The Company owns generating facilities with a total capacity of 13.8 megawatts (MW) that are principally used for emergency and peaking purposes. The Company also has a joint-ownership interest of 8.8 MW in Central Maine Power Company's oil-fired Wyman Unit 4.
The Company's non-nuclear generating assets together with capacity
COMMONWEALTH ELECTRIC COMPANY
entitlements associated with power contracts that are further discussed later in this section are part of an ongoing auction process initiated during 1997 in response to electric industry restructuring legislation enacted in Massa- chusetts in November 1997. The auction process is expected to be completed in 1998. For further information refer to the "Industry Restructuring" section of Management's Discussion and Analysis and Results of Operations in Item 7 of this report.
Power purchases for the Company and Cambridge Electric Light Company (Cam- bridge Electric), the other wholly-owned electric distribution subsidiary of the System, are arranged in accordance with their requirements. These arrangements include purchases from Canal Electric Company (Canal), another wholly-owned subsidiary of the System. Canal is a wholesale electric generat- ing company located in Sandwich, Massachusetts and an important source of purchased power for the Company and Cambridge Electric. These generating facilities are also part of the aforementioned auction. Under long-term contracts, system entitlements include one-quarter (141.5 MW) of the capacity and energy of Canal Unit 1 and one-half (275.7 MW) of the capacity and energy of Canal Unit 2. The Company's entitlements in these units are 113.3 MW and 220.7 MW, respectively.
Pursuant to a Capacity Acquisition and Disposition Agreement (CADA), Canal seeks to secure bulk electric power on a single system basis to provide cost savings for the customers of the Company and Cambridge Electric. The CADA has been accepted for filing as an amendment to Canal's FERC rate schedule and allows Canal to act on behalf of the Company and Cambridge Electric in the procurement of additional capacity for one or both companies, or, to sell capacity and/or energy from each company's entitlements. The CADA is in effect for Seabrook 1, Phases I and II of Hydro-Quebec and (through April 1997) the New England Power Company (Bear Swamp Units). Exchange agreements are in place with these utilities whereby, in certain circumstances, it is possible to exchange capacity so that the mix of power improves the pricing for dispatch for both the seller and the purchaser. Power contracts are in place whereby Canal bills or credits the Company and Cambridge Electric for the costs or revenues associated with these facilities. The Company and Cambridge Electric, in turn, have billed or are billing these charges (net of revenues from sales) to their customers through rates subject to DTE approval.
The Company has other long-term contracts for the purchase of electricity from various other sources including a 73.5 MW entitlement from a nuclear unit in Plymouth, Massachusetts (Pilgrim) under a life-of-the-unit contract with Boston Edison Company. Also, through Canal's equity ownership in Hydro-Quebec Phase II and its 3.52% interest in the Seabrook nuclear power plant, the Company has entitlements of 48.2 MW and 32.7 MW, respectively.
Pursuant to other long-term contracts, several non-utility generating (NUG) sources provided a substantial portion of the Company's power entitle- ments in 1997 as follows: 180.7 MW from four (4) natural gas-fired units; 67 MW from a waste-to-energy unit (including an expansion unit); and 23.9 MW from four (4) hydro-electric suppliers.
On June 5, 1996, the DTE approved a power sale termination agreement between the Company and Altresco Lynn, Inc. (Altresco) that related to a purchase power obligation under which the Company would have been required to purchase approximately 25 MW from Altresco beginning January 1, 1997. Under
COMMONWEALTH ELECTRIC COMPANY
the terms of the termination agreement, the Company returned to Altresco $550,000 of the $750,000 power sale agreement security deposit held by the Company since April 1992. The remaining $200,000, plus accumulated interest, was credited to the Company's fuel charge stabilization account. Consistent with DTE precedent regarding provision of least-cost electric service, the termination of the power sale agreement, coupled with providing replacement power when necessary, will save the Company's customers approximately $34 million over the twenty-year life of the initial power sale agreement.
In early 1995, the Company restructured a NUG power sale agreement with Lowell Cogeneration Company L.P. (23 MW) that defers the purchase of capacity and energy until December 31, 2000 and, when called back into service, power will be dispatched only when needed at the discretion of the Company. Also, the Company terminated a NUG power sale agreement with Pepperell Power Associates L.P. (38 MW) effective January 27, 1995. This buy-out is expected to save the Company's customers approximately $37 million over the next 20 years. In June 1995, the Company signed an agreement with another New England utility (Northeast Utilities) to purchase peaking-unit capacity at rates lower than that available from ISO - New England or other regional utilities. In 1993, the Company extended a commitment to April 1997 to exchange 50 MW of Canal's oil-fired generation with 50 MW of pumped storage energy and capacity from non-affiliate New England Power Company's Bear Swamp Units (an initial, smaller exchange of 25 MW began in 1992). The Bear Swamp Units are pumped storage hydroelectric generating facilities. These contracts were designed to reduce the system's reliance on oil.
In addition to power purchases, the Company has aggressively pursued the opportunity to market excess energy and capacity at rates greater than it would receive from sales to ISO - New England. This competitive business developed for the Company in the early 1990's when it began to formally respond to requests for proposals to supply short-term energy and associated capacity to other utilities. Increased emphasis on the marketing of excess energy and capacity as well as increased emphasis on reducing production cost expenses through aggressively seeking least-cost energy and capacity on the market has resulted in approximate savings of $3.1 million, $3.8 million and $2.0 million in 1997, 1996 and 1995, respectively.
ISO - New England
The Company, together with other electric utility companies in the New England area, is a member of ISO - New England, which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England.
ISO - New England operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of the member companies to fulfill the region's energy requirement. This concept is accomplished by use of computers to monitor and forecast load requirements.
The Company and the System's other electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization that includes the major power systems in New England and New York plus the provinces of Ontario and New Brunswick in Canada. NPCC establishes criteria and standards for reliability and serves as a vehicle for coordination in the
COMMONWEALTH ELECTRIC COMPANY
planning and operation of these systems.
The reserve requirements used by the ISO - New England participants in planning future additions are determined by ISO - New England to meet the reliability criteria recommended by NPCC. The system estimates that, during the next ten years, reserve requirements so determined will be approximately 20% of peak load.
Energy Mix
The Company's energy mix, which includes purchased power, is shown below:
1997 1996 1995 Natural gas 33% 39% 42% Oil 37 21 15 Nuclear 13 20 22 Waste-to-energy 11 12 13 Hydro 6 8 5 Coal - - 3 Total 100% 100% 100%
The Company's energy mix reflects the use of natural gas and other fuels due to the requirement to purchase capacity from NUG facilities. The higher oil component in 1997 reflects the greater availability of Canal Units 1 and 2 as compared to 1996 and 1995 when significant scheduled and unscheduled maintenance resulted in reduced output.
Rates, Regulation and Legislation
The Company operates under the jurisdiction of the DTE, which regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its wholesale rates with the FERC.
(a) Restructuring Legislation
As more fully discussed in the "Industry Restructuring" section of Management's Discussion and Analysis of Results of Operations in Item 7 of this report, the Company began to implement the provisions of the Electric Industry Restructuring Act on March 1, 1998 as signed into law on November 25, 1997 following the Company's filing of its proposed restructuring plan with the DTE on November 19, 1997. A modified plan was approved by the DTE on February 27, 1998 prior to implementation on March 1, 1998.
(b) Unbundled Rates
The Company has restructured its operations to provide customers with unbundled rates that provide a ten percent rate reduction as of March 1, 1998 and the opportunity to purchase generation supply on the competitive market pursuant to the electric industry restructuring legislation enacted in November 1997. Delivery rates are composed of distribution charges, transi- tion charges (to collect stranded costs) and transmission charges. Electrici- ty supply services include optional standard offer service and default service. Distribution charges consist of customer demand and energy charges as appropriate to recover distribution costs, including costs formerly recovered under the Conservation Charge, and is based on the separation of
COMMONWEALTH ELECTRIC COMPANY
distribution and transmission facilities. Transmission charges are itemized separately and are subject to the Company's Transmission Cost Adjustment. Transition charges are designed to recover on a reconciling basis all of the Company's stranded costs.
Prior to March 1, 1998, the Company had Fuel Charge (FC) rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. These schedules required a quarterly computation and DTE approval of an FC decimal based upon forecasts of fuel, purchased power, transmission costs and billed unit sales for each period. To the extent that collections under the rate schedules did not match actual costs for that period, an appropriate adjust- ment was reflected in the calculation of the next subsequent calendar quarter decimal.
Also prior to March 1, 1998, the Company collected a portion of capacity- related purchased power costs associated with certain long-term power arrange- ments through base rates. The recovery mechanism for these costs used a per kilowatthour (KWH) factor that was calculated using historical (test-period) capacity costs and unit sales. This factor was then applied to current monthly KWH sales. When current period capacity costs and/or unit sales varied from test-period levels, the Company experienced a revenue excess or shortfall that had a significant impact on net income. However, as part of the settlement agreements approved by the DTE in May 1995, the Company was allowed to defer these costs (within certain limits - $16 million in any given calendar year and $40 million over the life of the mechanism) which neutral- ized their sometimes volatile effect on net income.
The Company also had separately stated Conservation Charge rate schedules that allowed for current recovery, from retail customers, of conservation and load management (C&LM) costs.
Conservation and Load Management Programs The Company has implemented a variety of cost-effective C&LM programs that are designed to reduce future energy use by its customers. In 1993, the DTE began allowing the recovery by the Company of its "lost base revenues" from customers as a rate component employed by the DTE to encourage effective implementation of C&LM programs. These and other C&LM costs were recovered through a Conservation Charge decimal. The KWH savings that were realized as a result of the successful implementation of C&LM programs served as the basis for determining lost base revenues. Pursuant to the Restructuring Act, the Company has agreed to mandatory charges per KWH to fund energy efficiency and demand-side management activities.
(c) Wholesale Rate Proceedings
The Company provides power supply and transmission services to its FERC- jurisdictional wholesale customers and requires FERC approval to change its wholesale rates.
On March 29, 1995, the FERC issued two notices of proposed rulemaking concerning 1) open access transmission and 2) stranded costs. The FERC's notices proposed to remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower cost power to electric consumers. On April 24, 1996 the FERC issued Order No. 888, a set of three
COMMONWEALTH ELECTRIC COMPANY
interrelated rules resolving the above rulemakings. The FERC required all public utilities that own, control or operate transmission facilities in interstate commerce to have on file wholesale open access transmission tariffs that conform to the FERC pro-forma tariff contained in Order No. 888. On July 9, 1996, the Company filed tariffs that conform to the FERC's pro-forma tariffs. On November 13, 1996, the FERC accepted the non-rate terms and conditions of these tariffs effective July 9, 1996, subject to a revision of one section dealing with the scheduling of services. On March 4, 1997, the FERC issued Order No. 888-A which, required revisions to the tariffs filed in compliance with Order No. 888. The Company filed its revised tariffs on July 14, 1997. On November 25, 1997, the FERC issued Order No. 888-B requiring minor changes that did not require an additional filing.
On December 31, 1996, the Company filed market-based power sales tariffs with the FERC with the intent to make wholesale power sales at fully negotiat- ed rates. FERC approved the tariffs on February 27, 1997. In addition, the Company requested and received authorization to participate as brokers in the sale and purchase of electricity.
(d) Retail Choice Pilot Program
Prior to March 1, 1998, the date retail choice was available for all customers, the Company had designed a program to allow a limited number of customers the opportunity to possibly reduce their electric bills while the Company learned more about real-time pricing and the administrative require- ments associated with open-market competition. Through the program, the Company developed internal procedures for billing and allocating the costs for providing an alternative supply to its retail customers, and developed methods for educating customers regarding retail choice. The program was available to the Company's 18 commercial and industrial customers that took service under one of the Company's economic development rates. This program was discon- tinued on February 28, 1998.
Competition
Prior to March 1, 1998, the Company developed and implemented strategies that dealt with the increasingly competitive environment then facing the electric utility business. The inherently high cost of providing energy services in the Northeast had placed the region at a competitive disadvantage as more customers began to explore alternative energy supply options. Pursuant to preliminary electric industry restructuring rules issued in late 1996, the DTE proposed to implement programs under which utility and non- utility generators could sell electricity to customers of other utilities without regard to previously closed franchise service areas. The DTE initial- ly began an inquiry into incentive ratemaking in 1994. The Company had developed innovative pricing mechanisms designed to retain existing customers, add new retail and wholesale customers and expand beyond current markets.
On February 6, 1997, due to the dramatically changing nature of the electric and gas industries, the System announced the consolidation of management personnel of the Company and affiliates Cambridge Electric, Commonwealth Gas Company and COM/Energy Services Company effective on that date. The Company and these affiliates continue to operate under their existing company names. The consolidation process for these companies involved the merging of similar functions and activities to eliminate
COMMONWEALTH ELECTRIC COMPANY
duplication in order to create the most efficient and cost-effective operation possible. As part of this consolidation effort, the Company initiated a voluntary Personnel Reduction Program that ultimately resulted in a decrease of 127 regular employees (15.1%) in 1997.
Some of the more specific details of the innovative measures taken in response to competition include the following:
Rate Stabilization Plan The Company implemented a FC rate settlement on April 1, 1994, amended in May 1995, that stabilized its quarterly FC rate during the years 1994 through 1996 at 6.5 cents per KWH and no greater than 6.7 cents per KWH during 1997. However, the Company decided to maintain a FC of 6.5 cents per KWH in 1997 and defer, for later recovery, the difference between the 6.5 and 6.7 cents per KWH FC. The rate stabilization is achieved through the use of a cost deferral mechanism that was sponsored jointly by the Company and the Massachusetts Attorney General and approved by the DTE. The deferred costs are reflected as a regulatory asset to be recovered, with carrying charges, over the subsequent six-year period beginning in 1998 pursuant to a recovery schedule yet to be determined and subject to DTE approval. The deferred amount, excluding carrying charges, was restricted to a maximum of $40 million during the settlement period (1994 through 1997) and was further limited to an annual amount of $16 million. The deferred balance increased by $5,543,000 in 1997 primarily due to cost increases. In 1996, the Company reduced the deferred balance by $2,372,000, somewhat reversing the prior year deferral of $3,447,000.
The rate stabilization mechanism was part of a long-term plan to control the Company's retail rates. This plan helped to eliminate the disincentive for economic development resulting from a volatile and unpredictable FC rate. The stabilized FC rate had enabled current and prospective customers to better plan their business and personal finances in a more efficient and effective manner. In addition to the Massachusetts Attorney General, this proposal was widely supported by various business and customer groups and other political interests.
Economic Development Realizing a healthy regional economy benefits not only businesses but all area residents, the Company actively encourages economic growth by working in partnership with communities and businesses, providing resources and incentives to help the region's economy. The Company also funded the development of a business plan that focused on improving infrastructure, regulation, access to capital, marketing and promotion, cooperation and leadership on Cape Cod.
In an effort to foster industrial development in its service area, the Company began offering an Economic Development Rate in October 1991 to new or existing industrial customers with an electric demand of 500 kilowatts or more and meet specific financial and other criteria. The number of commercial and industrial customers that participated in this special rate were 21, 31 and 27 at December 31, 1997, 1996 and 1995, respectively. The rate was available for a six-year term that terminated on March 1, 1998. The Company also offered a Vacant Space Rate that was available to qualifying small commercial and industrial customers who established loads in previously unoccupied building space. These rates were terminated on March 1, 1998 as retail choice was introduced to provide consumers with the opportunity to purchase power from a competitive supplier or remain with the Company through standard offer
COMMONWEALTH ELECTRIC COMPANY
service. However, the DTE encourages the Company to pursue all necessary solutions to meet the energy needs of their customers and will support properly designed economic development rates that can be provided to customers by distribution companies in the future.
Construction and Financing
Information concerning the Company's financing and construction programs is contained in Note 3(a) of Notes to Financial Statements filed under Item 8 of this report.
Employees
The total number of full-time employees for the Company declined 15.1% in 1997 to 716 from 843 employees at year-end 1996. The Company has 467 employ- ees (65.2%) who are represented by the Brotherhood of Utility Workers of New England, Inc. under three separate collective bargaining units with agreements that expire April 30, 1998, October 31, 2001 and September 30, 2002. 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, Massachusetts and other structures such as garages and service buildings. In addition, the Company owns and operates, for standby and emergency purposes only, two diesel plants with a combined capability of 13.8 MW located on the island of Martha's Vineyard. The Company also has a 1.4% joint-ownership interest in Central Maine Power Company's Wyman Unit 4 with an entitlement of 8.8 MW.
At December 31, 1997, the electric transmission and distribution system consisted of 5,740 pole miles of overhead lines, 3,747 cable miles of under- ground line, 138 substations and 335,739 active customer meters.
Item 3.
Item 3. Legal Proceedings
The Company is not a party to any pending material legal proceeding.
COMMONWEALTH ELECTRIC COMPANY
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 a wholly-owned subsidiary of Common- wealth Energy System.
(b) Number of Shareholders at December 31, 1997
One
(c) Frequency and Amount of Dividends Declared in 1997 and 1996
1997 1996 Per Share Per Share Declaration Date Amount Declaration Date Amount
April 25, 1997 $1.65 January 24, 1996 $4.30 July 21, 1997 1.85 April 29, 1996 .75 October 27, 1997 1.25 November 4, 1996 1.30 December 22, 1997 1.25 $6.35 $6.00
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.
COMMONWEALTH ELECTRIC COMPANY
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 facili- tate 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
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed here- with on pages 20 through 39 of this report.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
COMMONWEALTH ELECTRIC COMPANY
Item 8. Financial Statements and Supplementary Data
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 Common- wealth Energy System) as of December 31, 1997 and 1996, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1997. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting princi- ples.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 19, 1998 (except with respect to certain matters discussed in Note 2, as to which the date is March 2, 1998).
COMMONWEALTH ELECTRIC COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULES PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1997 and 1996
Statements of Income for the Years Ended December 31, 1997, 1996 and 1995
Statements of Retained Earnings for the Years Ended December 31, 1997, 1996 and 1995
Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and
Notes to Financial Statements
PART IV.
SCHEDULES
I Investments in, Equity in Earnings of, and Dividends Received from Related Parties - Years Ended December 31, 1997, 1996 and 1995
II Valuation and Qualifying Accounts - Years Ended December 31, 1997, 1996 and 1995
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, 1997 AND 1996 ASSETS
1997 1996 (Dollars in thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $550,449 $535,004 Less - Accumulated depreciation 174,488 163,397 375,961 371,607 Add - Construction work in progress 4,010 2,315 379,971 373,922
INVESTMENTS Equity in nuclear electric power company 519 643 Other 14 14 533 657
CURRENT ASSETS Cash 1,496 358 Accounts receivable - Affiliates 1,753 2,662 Customers, less reserves of $2,044 in 1997 and $1,792 in 1996 45,199 42,644 Unbilled revenues 9,162 6,741 Inventories, at average cost - Materials and supplies 2,418 2,830 Electric production fuel oil 160 141 Prepaid property taxes 3,043 3,024 Other 1,771 1,609 65,002 60,009
DEFERRED CHARGES Regulatory assets 70,112 68,129 Other 3,601 3,282 73,713 71,411
$519,219 $505,999
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY BALANCE SHEETS DECEMBER 31, 1997 AND 1996 CAPITALIZATION AND LIABILITIES
1997 1996 (Dollars in thousands)
CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 2,043,972 shares wholly-owned by Commonwealth Energy System (Parent) $ 51,099 $ 51,099 Amounts paid in excess of par value 97,112 97,112 Retained earnings 31,993 27,334 180,204 175,545 Long-term debt, less current sinking fund requirements 147,192 150,734 327,396 326,279
CURRENT LIABILITIES Interim Financing - Notes payable to banks 14,900 15,000 Advances from affiliates 5,315 3,070 20,215 18,070
Other Current Liabilities - Current sinking fund requirements 3,553 3,553 Accounts payable - Affiliates 12,007 10,213 Other 32,826 28,137 Accrued taxes - Local property and other 3,299 3,025 Income 19,114 15,462 Accrued interest 3,811 3,894 Other 12,717 12,380 87,327 76,664 107,542 94,734
DEFERRED CREDITS Accumulated deferred income taxes 50,283 47,716 Unamortized investment tax credits 6,696 7,126 Other 27,302 30,144 84,281 84,986 COMMITMENTS AND CONTINGENCIES $519,219 $505,999
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 (Dollars in thousands)
ELECTRIC OPERATING REVENUES $471,449 $453,780 $434,578
OPERATING EXPENSES Electricity purchased for resale and fuel 304,782 290,163 281,130 Transmission 5,266 4,036 4,653 Other operation 79,324 72,259 69,541 Maintenance 12,871 12,849 10,569 Depreciation 17,554 17,041 16,377 Taxes - Income 10,398 12,951 11,041 Local property 5,980 5,485 5,137 Payroll and other 2,762 2,645 2,750 438,937 417,429 401,198
OPERATING INCOME 32,512 36,351 33,380
OTHER INCOME (EXPENSE) (206) (477) (1,276)
INCOME BEFORE INTEREST CHARGES 32,306 35,874 32,104
INTEREST CHARGES Long-term debt 13,586 13,968 14,081 Other interest charges 1,797 2,301 2,854 15,383 16,269 16,935
NET INCOME $ 16,923 $ 19,605 $ 15,169
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 (Dollars in thousands)
Balance at beginning of year $27,334 $20,708 $15,350
Add (Deduct): Net income 16,923 19,605 15,169 Cash dividends on common stock (12,264) (12,979) (9,811)
Balance at end of year $31,993 $27,334 $20,708
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995 (Dollars in thousands) OPERATING ACTIVITIES Net income $ 16,923 $ 19,605 $ 15,169 Effects of noncash items - Depreciation and amortization 23,961 21,815 20,087 Deferred income taxes 3,720 569 11,782 Investment tax credits (430) (433) (435) Change in working capital, exclusive of cash and interim financing - Accounts receivable and unbilled revenues (4,067) (713) (827) Income taxes, net 3,652 (3,259) 10,672 Local property and other taxes, net 255 (224) (757) Accounts payable and other 6,968 860 4,365 Fuel charge stabilization deferral (5,543) 2,372 (3,447) Deferred postretirement benefits and pension costs (179) 191 (1,067) Power contract buy-out - - (25,500) All other operating items (8,061) (3,979) (4,041)
Net cash provided by operating activities 37,199 36,804 26,001
INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (22,255) (20,483) (24,788) Allowance for borrowed funds used during construction (145) (98) (312)
Net cash used for investing activities (22,400) (20,581) (25,100)
FINANCING ACTIVITIES Payment of dividends (12,264) (12,979) (9,811) Proceeds from (payment of) short-term borrowings (100) (2,300) 10,900 Advances from affiliates 2,245 1,525 1,345 Retirement of long-term debt through sinking funds (3,542) (3,541) (3,542)
Net cash used for financing activities (13,661) (17,295) (1,108)
Net increase (decrease) in cash 1,138 (1,072) (207) Cash at beginning of period 358 1,430 1,637 Cash at end of period $ 1,496 $ 358 $ 1,430
Cash paid (received) during the periods for: Interest (net of capitalized amounts) $ 14,948 $ 15,436 $ 15,685 Income taxes paid (refunded) $ 5,019 $ 13,424 $ (1,119)
The accompanying notes are an integral part of these financial statements.
COMMONWEALTH ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
(1) General Information
Commonwealth Electric Company (the Company) is a wholly-owned subsidiary of Commonwealth Energy System (the System). The System is the parent company and, together with its subsidiaries, is collectively referred to as "the system." The System is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 with investments in four operating public utility companies located in central, eastern and southeastern Massachusetts and several non-regulated companies. The Company's operations are involved in the production, distribution and sale of electrici- ty to 322,300 customers (including 46,100 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 716 regular employees including 467 (65%) who are repre- sented by three collective bargaining units. During 1998, a collective bargaining contract representing approximately 11% of regular employees is scheduled to expire in April. Agreements were reached in early 1996 with two other bargaining units (representing approximately 54% of regular employees) that were scheduled to expire on October 1, 1996 and November 1, 1997. These agreements will remain in effect until 2002 and 2001, respectively. Employee relations have generally been satisfactory.
During the second quarter of 1997, the Company initiated a voluntary personnel reduction program. As a result of this program, the total number of regular employees has declined by approximately 15% in 1997.
(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) 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), formerly the Massachusetts Department of Public Utilities.
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 regula- tory assets in cases where the DTE and/or the FERC have permitted or are
COMMONWEALTH ELECTRIC COMPANY
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 extra-ordinary, 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.
As a result of electric industry restructuring, the Company discontinued application of accounting principles applied to its investment in electric generation facilities effective March 1, 1998. The Company will not be required to write off any of its generation-related assets, including regula- tory assets. These assets will be retained on the Company's Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through a non-bypassable transition charge.
Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. SFAS No. 121 did not have an impact on the Company's financial position or results of operations upon adoption.
The principal regulatory assets included in deferred charges at December 31, 1997 and 1996 were as follows: 1997 1996 (Dollars in thousands)
Power contract buy-out $17,609 $20,794 Fuel charge stabilization 29,655 21,504 Postretirement benefit costs 12,271 12,092 Yankee Atomic unrecovered plant and decommissioning costs 3,436 4,333 Pilgrim nuclear plant litigation costs 5,929 6,286 Conservation and load management costs 314 2,322 Other 898 789 $70,112 $68,129
The regulatory liabilities, reflected in the accompanying Balance Sheets in deferred credits at December 31, 1997 and 1996 were as follows: 1997 1996 (Dollars in thousands)
Excess Seabrook-related deferred income taxes $ 698 $ 2,792 Other deferred income taxes 1,875 2,086 Excess replacement power refunds 246 982 $ 2,819 $ 5,860
COMMONWEALTH ELECTRIC COMPANY
As of December 31, 1997, $40.1 million of the Company's regulatory assets, including the costs associated with an existing power contract with the Yankee Atomic nuclear power plant that has been shut down permanently, and all of its regulatory liabilities are reflected in rates charged to customers. Regulato- ry assets are currently being recovered over a weighted average period of approximately 12 years. The fuel charge stabilization deferral was expected to be recovered over a six-year period beginning in April 1998, pursuant to a yet to be determined recovery schedule and subject to final DTE approval.
In November 1997, the Commonwealth of Massachusetts enacted a comprehen- sive electric utility industry restructuring bill. On November 19, 1997 the System's electric subsidiaries, including the Company, filed a restructuring plan with the DTE. The plan, approved by the DTE on February 27, 1998, describes the process by which the Company and Cambridge Electric will, 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 DTE authorized the recovery of certain strandable costs. The legislation gives the DTE 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 liabili- ties related to the generation portion of the electric business.
The cost of transitioning to competition will be mitigated, in part, through the divestiture of the Company's non-nuclear generating assets in an auction process that is expected to be completed in 1998. Any net proceeds in excess of book value received from the divestiture of these assets will be used to mitigate stranded costs.
The Company's ability to recover its stranded costs will depend on several factors, including the aggregate amount of stranded costs the Company will be allowed to recover and the market price of electricity. Management believes that the Company will recover its stranded costs. A change in any of the above listed factors or in the current legislation could affect the recovery of stranded costs and may result in a loss to the Company. For additional information relating to industry restructuring, see the "Electric Industry Restructuring" section under Management's Discussion and Analysis and Results of Operations.
(c) Transactions with Affiliates
Transactions between the Company and other system companies include purchases and sales of electricity, including purchases from Canal Electric Company (Canal), an affiliated wholesale electric generating company. Other Canal transactions include costs relating to the abandonment of Seabrook 2 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 system companies are subject to review by the DTE.
COMMONWEALTH ELECTRIC COMPANY
The Company's operating expenses include the following major intercompany transactions for the periods indicated: Purchased Power Purchased Power and Transmission Period Ended Purchased Power and Transmission From Canal December 31, Canal Units Seabrook 1 as Agent (Dollars in thousands)
1997 $61,087 $31,417 $ 6,524 1996 40,733 31,848 9,096 1995 29,469 26,905 17,240
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 $1,290,000, $1,453,000 and $2,047,000 in 1997, 1996 and 1995, 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 3.32% in 1997 and 1996, and 3.31% in 1995.
(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 $145,000, $98,000 and $312,000 in 1997, 1996 and 1995, respectively.
COMMONWEALTH ELECTRIC COMPANY
While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 6.25% in 1997 and 1996, and 7.25% in 1995.
(3) Commitments and Contingencies
(a) Financing and Construction Programs
The Company is engaged in a continuous construction program presently estimated at $105.5 million for the five-year period 1998 through 2002. Of that amount, $23.8 million is estimated for 1998. 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 with internally generated funds and short-term borrowings.
(b) Power Contracts
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.
Information relative to these long-term contracts is as follows:
Range of Contract Expiration Entitlement Cost Dates % MW 1997 1996 1995 (Dollars in thousands) Type of Unit Natural Gas 2008-2017 (a) 180.7 $114,773 $111,007 $106,957 Oil 2000-2009 (b) 266.0 58,187 36,060 29,468 Nuclear 2012-2026 (c) 106.1 68,381 68,716 71,953 Waste-to-energy 2015 100 67.0 43,038 39,622 37,526 Hydro 2014-2023 100 23.9 10,952 12,537 9,933 Total 643.7 $295,331 $267,942 $255,837
(a) Includes contracts to purchase power from various non-utility genera- ting facilities with capacity entitlements ranging from 11.1% to 100%. (b) Includes entitlements in Canal Unit 1 (20%) and Canal Unit 2 (40%). (c) Includes entitlements in Seabrook 1 (2.8%) and Pilgrim (11%).
Costs pursuant to these contracts are included in electricity purchased for resale in the Company's Statements of Income and are recoverable in revenues. The costs associated with these power contract obligations are a significant component of the Company's stranded costs that are included in the Company's restructuring plan approved by the DTE.
The estimated aggregate obligations for capacity under the life-of-the- unit contracts, including the Canal and Seabrook 1 units, and other long-term
COMMONWEALTH ELECTRIC COMPANY
purchased power contracts in effect for the five years subsequent to 1997 are as follows: Long-Term Purchased Power (Dollars in thousands)
1998 $304,805 1999 301,659 2000 309,993 2001 316,524 2002 323,693
(c) 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 installa- tion of expensive air and water pollution control equipment. These regula- tions have had an impact on the Company's operations in the past and would continue to have an impact on future operations, capital costs and construc- tion schedules of major facilities; however, the electric generating facili- ties are likely to be sold at auction in 1998 pursuant to the restructuring plan filed with the DTE.
(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 the System and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations.
The following is a summary of the Company's provisions for income taxes for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995 (Dollars in thousands) Federal Current $ 5,852 $10,818 $(2,036) Deferred 3,174 374 10,014 Investment tax credits, net (430) (433) (435) 8,596 10,759 7,543 State Current 1,254 1,997 (39) Deferred 548 195 1,768 1,802 2,192 1,729 $10,398 $12,951 $ 9,272 Federal and state income taxes charged to: Operating expense $10,398 $12,951 $11,041 Other income - (1,769) $10,398 $12,951 $ 9,272
COMMONWEALTH ELECTRIC COMPANY
Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse.
Accumulated deferred income taxes consisted of the following in 1997 and 1996: 1997 1996 (Dollars in thousands) Liabilities Property-related $54,605 $52,316 Power contract buy-out 6,853 10,002 Fuel charge stabilization 12,241 8,124 All other 8,647 9,720 82,346 80,162 Assets Investment tax credit 4,322 4,599 All other 9,120 10,791 13,442 15,390 Accumulated deferred income taxes, net $68,904 $64,772
The net year-end deferred income tax liability above includes a current deferred tax liability of $18,621,000 and $17,056,000 1997 and 1996, respec- tively, which are included in accrued income taxes in the Company's Balance Sheets.
The total income tax provision set forth previously represents 38% in 1997, 40% in 1996 and 38% in 1995 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages:
1997 1996 1995 (Dollars in thousands)
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory levels $ 9,562 $11,395 $8,554 Increase (Decrease) from statutory levels: State tax net of federal tax benefit 1,171 1,425 1,124 Tax versus book depreciation 105 103 139 Amortization of investment tax credits (430) (433) (435) Reversals of capitalized expenses (63) (64) (64) Additional reserves for tax deficiencies - 431 - Other 53 94 (46) $10,398 $12,951 $9,272
Effective federal income tax rate 38% 40% 38%
(5) Employee Benefit Plans
(a) Pension
The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The Company makes monthly contributions to the plan consistent
COMMONWEALTH ELECTRIC COMPANY
with the funding requirements of the Employee Retirement Income Security Act of 1974.
Components of pension expense and related assumptions to develop pension expense were as follows:
1997 1996 1995 (Dollars in thousands)
Service cost $ 3,245 $ 3,405 $ 2,839 Interest cost 11,306 11,300 10,983 Return on plan assets - (gain)/loss (27,678) (20,771) (28,360) Net amortization and deferral 16,829 10,912 19,180 Total pension expense 3,702 4,846 4,642 Transfers (to) from affiliated companies, net (231) (191) (157) Less: Amounts capitalized and deferred 1,714 1,369 1,064 Net pension expense $ 1,757 $ 3,286 $ 3,421
Discount rate 7.50% 7.25% 8.50% Assumed rate of return 8.75 8.75 9.00 Rate of increase in future compensation 4.25 4.25 5.00
Pension expense reflects the use of the projected unit credit method that is also the actuarial cost method used in determining future funding of the plan. The Company, in accordance with current ratemaking, is deferring the difference between pension contribution, which is reflected in base rates, and pension expense. The funded status of the plan (using a measurement date of December 31) is as follows:
1997 1996 (Dollars in thousands) Accumulated benefit obligation: Vested $(152,967) $(118,464) Nonvested (17,183) (13,687) $(170,150) $(132,151)
Projected benefit obligation $(184,290) $(157,604) Plan assets at fair market value 177,112 155,650 Projected benefit obligation greater than plan assets (7,178) (1,954) Unamortized transition obligation 2,574 3,217 Unrecognized prior service cost 4,594 5,157 Unrecognized gain (6,560) (13,087) Accrued pension liability $ (6,570) $ (6,667)
The following actuarial assumptions were used in determining the plan's year-end funded status: 1997 1996
Discount rate 7.00% 7.50% Rate of increase in future compensation 3.75 4.25
Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect pension expense in future years.
COMMONWEALTH ELECTRIC COMPANY
(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 its postretirement benefits, the Company makes contributions to various voluntary employees' beneficiary association trusts that were estab- lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The Company also makes contributions to a subaccount of its pension plan pursuant to section 401(h) of the Code to fund a portion of its postretirement benefit obligation. The Company contributed approximately $5,654,000, $6,342,000, and $6,440,000 to these trusts during 1997, 1996 and 1995, respec- tively.
The net periodic postretirement benefit cost for the years ended December 31, 1997, 1996 and 1995 include the following components and related assumptions:
1997 1996 1995 (Dollars in thousands)
Service cost $ 980 $ 1,132 $ 921 Interest cost 4,355 4,383 4,158 Return on plan assets (4,383) (2,576) (2,956) Amortization of transition obligation over 20 years 2,417 2,417 2,417 Net amortization and deferral 2,289 1,011 1,918 Total postretirement benefit cost 5,658 6,367 6,458 Transfer from affiliated companies, net (645) (500) (516) Less: Amounts capitalized and deferred (82) (164) 1,733 Net postretirement benefit cost $ 4,931 $ 5,703 $ 4,209
Discount rate 7.50% 7.25% 8.50% Assumed rate of return 8.75 8.75 9.00 Rate of increase in future compensation 4.25 4.25 5.00
The funded status of the plan using a measurement date of December 31, 1997 and 1996 is as follows:
1997 1996 (Dollars in thousands)
Accumulated postretirement benefit obligation: Retirees $(46,906) $ (32,500) Fully eligible active plan participants (8,576) (4,609) Other active plan participants (13,215) (21,819) (68,697) (58,928) Plan assets at fair market value 30,229 22,635 Accumulated postretirement benefit obligation greater than plan assets (38,468) (36,293) Unamortized transition obligation 36,250 38,666 Unrecognized (gain) loss (2,218) (2,373) $ - $ -
COMMONWEALTH ELECTRIC COMPANY
The following actuarial assumptions were used in determining the plan's estimated accumulated postretirement benefit obligation (APBO) and funded status for 1997 and 1996: 1997 1996
Discount rate 7.00% 7.50% Rate of increase in future compensation 3.75 4.25 Medicare Part B premiums 3.10 9.50 Medical care 6.75 7.00 Dental care 4.50 5.00
The above dental rate remains constant through the year 2007. Rates for Medicare Part B premiums and medical care decrease to 3.1% and 4.5%, respec- tively, by 2007 and remain at that level thereafter. A one percent change in the medical trend rate would have a $780,000 impact on the Company's annual expense and would change the APBO by approximately $8.6 million.
Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect postretire- ment benefits expense in future years.
Effective May 1, 1995 the DTE approved a settlement proposal sponsored jointly by the Company and the Attorney General of Massachusetts that allows the Company to fully recover costs relating to postretirement benefits and to amortize its $8.6 million deferred balance over a ten-year period. At December 31, 1997 and 1996, the Company's deferral amounted to approximately $6.3 million and $7.1 million, respectively.
(c) Savings Plan
The Company has an Employees Savings Plan that provides for Company contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate and up to five percent for those employees no longer eligible for postretirement health benefits. The total Company contribution was $1,672,000 in 1997, $1,788,000 in 1996, and $1,813,000 in 1995.
COMMONWEALTH ELECTRIC COMPANY
(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:
Original Balance December 31, Issue 1997 1996 (Dollars in thousands)
15-Year Term Loan, 9.30%, due 2002 $30,000 $ 30,000 $ 30,000 25-Year Term Loan, 9.37%, due 2012 20,000 14,737 15,789 10-Year Notes, 7.43%, due 2003 15,000 15,000 15,000 15-Year Notes, 9.50%, due 2004 15,000 7,500 10,000 15-Year Notes, 7.70%, due 2008 10,000 10,000 10,000 18-Year Notes, 9.55%, due 2007 10,000 10,000 10,000 20-Year Notes, 7.98%, due 2013 25,000 25,000 25,000 25-Year Notes, 9.53%, due 2014 10,000 10,000 10,000 30-Year Notes, 9.60%, due 2019 10,000 10,000 10,000 30-Year Notes, 8.47%, due 2023 15,000 15,000 15,000 $147,237 $150,789
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, 1997 are as follows:
Year Sinking Funds (Dollars in thousands)
1998 $3,553 1999 3,553 2000 3,553 2001 3,481 2002 3,481
(b) Notes Payable to Banks
The Company and other system 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, 1997, system companies had $145 million of committed lines of credit that will expire at varying intervals in 1998. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1997, 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% and 5.6% in 1997 and 1996, respectively. Notes payable to banks totaled $14.9 million and $15 million at December 31, 1997 and 1996, respectively.
COMMONWEALTH ELECTRIC COMPANY
(c) Advances from Affiliates
The Company had no notes payable to the System at December 31, 1997 compared to $2,240,000 at December 31, 1996. These 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 8.5% and 8.3% in 1997 and 1996, respectively.
The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among the subsidiaries of the System, 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 out- standing 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 borrow- ings are for a period of less than one year and are payable upon demand. Rates on these borrowings averaged 5.4% and 5.3% in 1997 and 1996, respective- ly. Notes payable to the Pool totaled $5,315,000 and $830,000 at December 31, 1997 and 1996, respectively.
(d) Disclosures About Fair Value of Financial Instruments
The fair value of certain financial instruments included in the accompany- ing Balance Sheets as of December 31, 1997 and 1996 is as follows:
1997 1996 (Dollars in thousands)
Carrying Fair Carrying Fair Value Value Value Value
Long-term debt $150,745 $171,787 $154,287 $171,219
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, 1997, approximately $2,533,000 of retained earnings was 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
COMMONWEALTH ELECTRIC COMPANY
prohibit the Company from entering into future lease agreements or obliga- tions.
Future minimum lease payments, by period and in the aggregate, of noncan- celable operating leases consisted of the following at December 31, 1997:
Operating Leases (Dollars in thousands)
1998 $ 3,458 1999 2,971 2000 1,501 2001 853 2002 853 Beyond 2002 2,444 Total future minimum lease payments $12,080
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $3,174,000 in 1997, $2,814,000 in 1996 and $3,164,000 in 1995. There were no contingent rentals and no sublease rentals for the years 1997, 1996 and 1995.
COMMONWEALTH ELECTRIC COMPANY 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 21).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page(s) indicated -
Schedule I - Investments in, Equity in Earnings of, and Dividends Received from Related Parties - Years Ended December 31, 1995, 1996 and 1997 (page 49).
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1997, 1996 and 1995 (page 50).
(a) 3. Exhibits: Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incorporat- ed 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 Commonwealth Energy System and subsid- iary 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 certif- ication of name change to Commonwealth Electric Company as filed with the Massachusetts Secretary of State on March 1, 1981 (Re- filed as Exhibit 1 to the CE 1990 Form 10-K, File No. 2-7749).
COMMONWEALTH ELECTRIC COMPANY
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 (Septem- ber 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 Aug- ust 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 Janu- ary 2, 1981 (Refiled as Exhibit 3 to the CE 1991 Form 10-K, File No. 2-7749).
COMMONWEALTH ELECTRIC COMPANY
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 sell- er'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 Agreement between NBGEL and Central Maine Power Company (CMP), for the joint-ownership, construction and operation of William F. Wyman Unit No. 4 dated November 1, 1974 together with Amendment No. 1 dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No. 2-54955).
10.1.7.1 Amendments No. 2 and 3 to 10.1.7 as amended August 16, 1976 and December 31, 1978 (Exhibit 5(a) 14 to the System's Form S-16 (June 1979), File No. 2-64731).
10.1.8 Contract between CEC and NBGEL and CEL, affiliated companies, for the sale of specified amounts of electricity from Canal Unit 2 dated January 12, 1976 (Exhibit 7 to the System's 1985 Form 10-K, File No. 1-7316).
10.1.9 Capacity Acquisition Agreement between CEC,CEL and CE dated Sep- tember 25, 1980 (Exhibit 1 to the CEC 1991 Form 10-K, File No. 2- 30057).
10.1.9.1 Supplement to 10.1.9 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).
10.1.9.2 Amendment to 10.1.9 as amended and restated June 1, 1993, hence- forth 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).
10.1.10 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).
10.1.10.1 Amendment No. 2 to 10.1.10 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.10.2 Amendment No. 3 to 10.1.10 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749).
10.1.11 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).
COMMONWEALTH ELECTRIC COMPANY
10.1.12 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).
10.1.12.1 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).
10.1.13 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 Corpo- ration (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.13.1 Amendment No. 3 to 10.1.13 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749).
10.1.14 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, Amend- ment 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).
10.1.15 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 (Ex- hibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.15.1 Amendatory Agreement No. 3 to 10.1.15 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.16 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).
10.1.17 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).
10.1.18 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).
10.1.18.1 First, Second and Third Amendments to 10.1.18 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).
10.1.18.2 Fifth, Sixth and Seventh Amendments to 10.1.18 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Ex- hibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
COMMONWEALTH ELECTRIC COMPANY
10.1.18.3 Fourth and Eighth Amendments to 10.1.18 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057).
10.1.18.4 Ninth and Tenth Amendments to 10.1.18 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.18.5 Eleventh Amendment to 10.1.18 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.18.6 Twelfth Amendment to 10.1.18 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.19 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion 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).
10.1.20 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 utili- ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2- 30057).
10.1.21 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).
10.1.22 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).
10.1.22.1 Amendment No. 1 to 10.1.22 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.22.2 Amendment No. 2 to 10.1.22 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.23 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).
10.1.23.1 Amendments Nos. 1 and 2 to 10.1.23 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.23.2 Amendments Nos. 3 and 4 to 10.1.23 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057).
COMMONWEALTH ELECTRIC COMPANY
10.1.24 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).
10.1.24.1 Amendments Nos. 1 and 2 to 10.1.24 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.24.2 Amendments Nos. 3 and 4 to 10.1.24 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.25 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 (Ex- hibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.26 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).
10.1.26.1 Transmission Service Agreement between Northeast Utilities' compa- nies (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).
10.1.26.2 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).
10.1.27 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).
10.1.27.1 Power Sales Agreement to 10.1.27 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749).
10.1.27.2 Amendment to 10.1.27 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).
10.1.27.3 Second Amendment to 10.1.27.2 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).
COMMONWEALTH ELECTRIC COMPANY
10.1.28 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).
10.1.28.1 First Amendment to 10.1.28 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.28.2 Second Amendment to 10.1.28 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.28.3 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).
10.1.28.4 Amendment to 10.1.28.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.29 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).
10.1.29.1 Second Amendment, dated June 23, 1994, to 10.1.29 (Exhibit 4 to the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.30 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).
10.1.31 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 cogen- eration facility, dated February 20, 1992 (Exhibit 2 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.31.1 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).
10.1.31.2 First Amendment, dated November 7, 1994, to 10.1.31 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).
COMMONWEALTH ELECTRIC COMPANY
10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsid- iary 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).
10.2.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corpora- tion, 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 (Re- filed 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, respective- ly (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 (Exhib- it 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 (Ex- hibit 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 (Exhib- it 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).
COMMONWEALTH ELECTRIC COMPANY
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, 1997.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for the twelve months ended December 31, 1997.
SCHEDULE I
COMMONWEALTH ELECTRIC COMPANY INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES
FOR THE YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
(Dollars in thousands)
Name of Issuer and Description of Investment
Common Stock - Yankee Atomic Electric Company
Balance, December 31, 1994
Number of Shares: 3,835
Amount $654
Add: Equity in Earnings (18)
Less: Dividends Received 46
Balance, December 31, 1995 590
Add: Equity in Earnings 53
Less: Dividends Received -
Balance, December 31, 1996 643
Add: Equity in Earnings (74)
Less: Dividends Received 50
Balance, December 31, 1997 $519
There were no changes in the number of shares held during the years 1995, 1996 or 1997.
Under terms of the capital funds agreements and power contracts, no stock may be sold or transferred except to another stockholder; however, no market exists for these securities.
SCHEDULE II
COMMONWEALTH ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 and 1995
(Dollars in thousands)
Additions Balance Provision Deductions Balance Beginning Charged to Accounts End Description of Year Operations Recoveries Written Off of Year
Allowance for Doubtful Accounts Year Ended December 31, 1997
$1,792 $2,415 $703 $2,866 $2,044
Year Ended December 31, 1996
$2,379 $1,661 $601 $2,849 $1,792
Year Ended December 31, 1995
$2,841 $2,243 $704 $3,409 $2,379
COMMONWEALTH ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1997
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: WILLIAM G. POIST William G. Poist, Chairman of the Board
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:
WILLIAM G. POIST March 31, 1998 William G. Poist, Chairman of the Board
R. D. WRIGHT March 31, 1998 Russell D. Wright, Vice Chairman and Chief Executive Officer
DEBORAH A. MCLAUGHLIN March 31, 1998 Deborah A. McLaughlin, President and Chief Operating Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 31, 1998 James D. Rappoli, Financial Vice President and Treasurer
A majority of the Board of Directors:
WILLIAM G. POIST March 31, 1998 William G. Poist, Director
DEBORAH A. MCLAUGHLIN March 31, 1998 Deborah A. McLaughlin, Director
JAMES D. RAPPOLI March 31, 1998 James D. Rappoli, Director
R. D. WRIGHT March 31, 1998 Russell D. Wright, Director