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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 2-7749
COMMONWEALTH ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1659070
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Main Street, Cambridge, Massachusetts 02142-9150
(Address of principal executive offices) (Zip Code)
(617) 225-4000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to
such filing requirements for the past 90 days. YES [x] NO [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Outstanding at
Class of Common Stock March 16, 1998
Common Stock, $25 par value 2,043,972 shares
The Company meets the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K as a wholly-owned subsidiary and is filing this Form with the
reduced disclosure format.
Documents Incorporated by Reference Part in Form 10-K
None Not Applicable
List of Exhibits begins on page 40 of this report.
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COMMONWEALTH ELECTRIC COMPANY
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business........................................ 3
General....................................... 3
Electric Power Supply......................... 3
ISO - New England............................. 5
Energy Mix.................................... 6
Rates, Regulation and Legislation............. 6
(a) Restructuring Legislation............... 6
(b) Unbundled Rates......................... 6
(c) Wholesale Rate Proceedings.............. 8
(d) Retail Choice Pilot Program............. 9
Competition................................... 9
Construction and Financing.................... 10
Employees..................................... 10
Item 2. Properties...................................... 10
Item 3. Legal Proceedings............................... 10
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 11
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 12
Item 8. Financial Statements and Supplementary Data..... 19
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 19
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 40
Signatures.................................................. 51
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COMMONWEALTH ELECTRIC COMPANY
PART I.
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
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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
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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
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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
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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
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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
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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
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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. 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. Legal Proceedings
The Company is not a party to any pending material legal proceeding.
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COMMONWEALTH ELECTRIC COMPANY
PART II.
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.
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COMMONWEALTH ELECTRIC COMPANY
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 of this report.
A summary of the period to period changes in the principal items included
in the accompanying Statements of Income for the years ended December 31, 1997
and 1996 and unit sales for these periods is shown below:
Years Ended Years Ended
December 31, December 31,
1997 and 1996 1996 and 1995
Increase (Decrease)
(Dollars in thousands)
Electric Operating Revenues $ 17,669 3.9% $ 19,202 4.4%
Operating Expenses -
Electricity purchased for resale
and fuel 14,619 5.0 9,033 3.2
Transmission 1,230 30.5 (617) (13.3)
Other operation 7,065 9.8 2,718 3.9
Maintenance 22 0.2 2,280 21.6
Depreciation 513 3.0 664 4.1
Taxes -
Federal and state income (2,553) (19.7) 1,910 17.3
Local property and other 612 7.5 243 3.1
21,508 5.2 16,231 4.0
Operating Income (3,839) (10.6) 2,971 8.9
Other Income 271 56.8 799 62.6
Income Before Interest Charges (3,568) (9.9) 3,770 11.7
Interest Charges (886) (5.4) (666) (3.9)
Net Income $ (2,682) (13.7) $ 4,436 29.2
Unit Sales (Megawatthours or MWH)
Retail 88,213 2.6 96,581 2.9
Wholesale 325,054 38.1 (3,976) (0.5)
Total unit sales 413,267 9.6 92,605 2.2
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COMMONWEALTH ELECTRIC COMPANY
Unit Sales and Customers
The following is a summary of unit sales and customers for the periods
indicated:
Years Ended December 31,
1997 1996 1995
% %
Unit Sales (MWH): Change Change
Residential 1,668,193 1.4 1,645,011 3.1 1,595,161
Commercial 1,470,179 3.7 1,417,790 2.4 1,384,301
Industrial 368,509 3.5 356,009 3.8 343,004
Streetlighting 16,180 0.9 16,039 1.5 15,802
Total retail 3,523,061 2.6 3,434,849 2.9 3,338,268
Wholesale 1,177,993 38.1 852,938 (0.5) 856,914
Total 4,701,054 9.6 4,287,787 2.2 4,195,182
Customers - 12 Month Average:
Residential (a) 281,927 1.2 278,653 1.2 275,409
Commercial (a) 39,044 1.1 38,609 1.4 38,080
Industrial 296 (1.0) 299 (4.8) 314
Streetlighting 1,081 (1.7) 1,100 4.1 1,057
Total 322,348 1.2 318,661 1.2 314,860
(a) Includes seasonal customers of 46,147 in 1997, 46,862 in 1996 and 47,497
in 1995. 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.
The increase in retail unit sales in 1997 and 1996 was due to approximate-
ly 3,700 and 3,800 additional customers, respectively, the majority of which
are permanent year-round residential customers. The increase in the level of
wholesale sales for 1997 reflected greater sales to 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). In 1996,
the slight decrease in the level of wholesale unit sales reflected a 3.5%
decline in sales to ISO - New England.
The Company's residential customer segment provides approximately 47% of
its total retail sales and approximately 9% of those customers rely on
electricity for space heating. The Company expects that its retail unit sales
compound annual growth rate over the next five years will average 1.7%.
Operating Revenues
Operating revenues for 1997 increased $17.7 million (3.9%) due to a
greater level of wholesale sales ($9.7 million) reflecting the changing
capacity needs of ISO - New England. Fluctuations in the level of wholesale
electric sales have no impact on net income. Also contributing to the
increase in revenues were higher retail unit sales ($4.2 million), higher
revenues related to the recovery of electricity purchased for resale, trans-
mission and fuel to retail customers ($4.6 million), and the recovery of costs
associated with conservation and load management programs (C&LM) ($1 million).
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COMMONWEALTH ELECTRIC COMPANY
Offsetting these factors was the absence of a $4 million refund associated
with a 1996 power contract settlement agreement.
Operating revenues for 1996 increased by $19.2 million (4.4%) due mainly
to higher electricity purchased for resale and fuel costs of $7.7 million, the
impact of higher retail unit sales ($6.1 million), the $4 million refund
described above, and the recovery of costs associated with C&LM programs
($700,000). The remainder of the change mainly reflects increased wholesale
revenues. In total, wholesale revenues were $27.8 million, $18.2 million and
$16.7 million in 1997, 1996 and 1995, respectively.
The recovery of lost base revenues through the operation of a Conservation
Charge decimal was allowed by the DTE to encourage effective implementation of
C&LM programs. To the extent that current costs associated with C&LM programs
increase or decrease from period to period based on customer participation, a
corresponding change will occur in revenues. Lost base revenues declined $2.4
million and $400,000 in 1997 and 1996, respectively.
Pursuant to a 1995 settlement agreement with the DTE that limited the
Company's return on equity through 1997, revenues in 1997, 1996 and 1995
reflect a customer refund of $1.7 million, $1.8 million and $400,000, respec-
tively.
As a result of a DTE mandated recovery mechanism implemented in July 1991
for capacity-related costs associated with certain long-term purchased power
contracts, the Company had experienced a revenue excess or shortfall when unit
sales and/or the costs recoverable in base rates varied from test-period
levels. This issue, which had a significant impact on net income, was
addressed in a settlement agreement approved by the DTE in May 1995 (refer to
the "Rates, Regulation and Legislation" section in Item 1 of this report for
additional details). The Company was able to defer these costs (within
certain limits) to neutralize the sometimes volatile effect on net income.
During 1997 and 1996, there was an overcollection of approximately $1.9
million and $400,000, respectively, that reduced the deferred balance in the
fuel charge stabilization account pursuant to the May 1995 settlement agree-
ment. During 1995, there was an undercollection of approximately $2.1 million
of which $1.1 million was deferred resulting in $970,000 of capacity-related
costs not recovered in revenues. This recovery mechanism reduced net income
by approximately $600,000 in 1995. There was no net income impact in 1997 and
1996.
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COMMONWEALTH ELECTRIC COMPANY
The following is an analysis of revenue components for the years 1997,
1996 and 1995:
Years Ended December 31,
1997 1996 1995
(Dollars in thousands)
% %
Change Change
Costs recovered in Fuel,
Purchased Power, or
Conservation Charges $239,690 4.0 $230,462 4.1 $221,367
Certain power and other costs
recovered in base rates 52,438 (0.3) 52,607 (1.2) 53,268
Other (a) 151,496 (0.7) 152,561 6.5 143,197
Total retail revenue 443,624 1.8 435,630 4.3 417,832
Total wholesale revenue 27,825 53.3 18,150 8.4 16,746
Total revenues $471,449 3.9 $453,780 4.4 $434,578
(a) Includes other base rate and miscellaneous revenues.
In the May 1995 settlement, the Company implemented a $2.7 million annual
retail base rate decrease effective May 1, 1995 and included its share of
excess deferred tax reserves related to Seabrook Unit 1 refunded in May 1995
to the Company by Canal. Further, the settlement imposed a moratorium on
retail rate filings until October 1998 and limited the Company's return on
equity through 1997.
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,
Qualifying Facilities and other non-utility generators through a competitive
bidding process that was regulated by the DTE. The Company supplemented these
sources with its own generating capacity.
The cost of electricity purchased for resale, fuel and transmission
constituted 65.8%, 64.8% and 65.8% in 1997, 1996 and 1995, respectively, of
electric operating revenues. These costs increased in 1997 and 1996 due to
the impact of higher unit sales offset, in part, by a lower average per unit
cost of power. Power purchased from the Canal units increased by $20.4
million (50%) and $11.3 million (38.2%) in 1997 and 1996, respectively.
Other Operating Expenses
Other operation in 1997 increased $7.1 million or 9.8% due to a one-time
charge related to a Personnel Reduction Program (PRP) ($8.4 million) (as
further discussed below), an increase in the provision for bad debts
($750,000) that reflected higher reserve requirements, and an increase in
costs associated with C&LM programs ($2.3 million). The impact of these
factors was offset, in part, by lower pension costs ($1.5 million) and lower
operating costs ($2.9 million) that resulted, in part, from the PRP.
The Company initially announced the details of the system-wide voluntary
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COMMONWEALTH ELECTRIC COMPANY
PRP in May 1997. The goal of the PRP was to achieve a reduced, more efficient
and more productive workforce in response to the significant regulatory
changes facing the Company. In 1997, 15.1% of the Company's employees volun-
tarily terminated employment as a result of the PRP. The one-time charge of
$8.4 million referred to above excludes generation-related costs, the recovery
of which is being addressed as part of the industry restructuring process.
The payback period for the cost of the PRP is expected to be about one year.
This action followed the consolidation of the system's electric and gas
operations earlier in 1997.
In 1996, other operation increased $2.7 million (3.9%) due to higher gen-
eral liability insurance costs ($3 million) and higher costs for postretire-
ment benefits ($1.5 million). Somewhat offsetting these higher costs was a
lower provision for bad debts ($600,000) and the absence of legal fees
($500,000) associated with the cancellation of a power contract in 1995.
Included in other operation are certain costs, including amortization of
prior period amounts, associated with C&LM programs that amounted to $5.4
million, $3.1 million and $2.6 million in 1997, 1996 and 1995, respectively.
Maintenance was virtually unchanged in 1997. Costs associated with a
severe spring snowstorm ($1.9 million) was offset by the absence of storm
damage costs that resulted from Hurricane Edouard ($2.1 million) in 1996 and
reduced maintenance in 1997 primarily on transmission and distribution facili-
ties. In 1996, expense increased $2.3 million (21.6%) primarily due to costs
for Hurricane Edouard.
Depreciation expense increased $500,000 and $700,000 in 1997 and 1996,
respectively, and reflected the Company's additions to property, plant and
equipment.
Federal and state income taxes declined $2.6 million (19.7%) in 1997 and
increased $1.9 million (17.3%) in 1996 due mainly to the change in pre-tax
income.
Other Income (Expense)
Other income increased in 1997 primarily due to the absence of a $300,000
settlement paid in 1996 by the Company related to costs associated with energy
conservation management services provided by an outside vendor.
The $800,000 increase in 1996 was mainly due to the absence of a 1995
reserve for the Cannon Street generating station ($2.7 million, net of tax)
and the absence of a reversal of a $1.4 million reserve in 1995 that related
to certain costs associated with the Company's energy conservation program,
the recovery of which was subsequently approved by the DTE.
Interest Charges
Total interest charges declined in 1997 reflecting scheduled sinking fund
payments and lower interest on potential federal and state income tax defi-
ciencies ($361,000).
Interest on short-term borrowings also declined due to a lower average level
of borrowings despite a slightly higher average interest rate (5.8%) for the
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COMMONWEALTH ELECTRIC COMPANY
year. Total interest charges declined in 1996 by 3.9% due to a lower average
level of short-term borrowings and interest rates that averaged 5.6% versus
6.1% in 1995. The decrease in interest charges was offset somewhat in 1996 by
a decline ($214,000) in the allowance for borrowed funds used during construc-
tion.
Forward-Looking Statements
This discussion contains statements which, to the extent it is not a
recitation of historical fact, constitute "forward-looking statements" and is
intended to be subject to the safe harbor protection provided by the Private
Securities Litigation Reform Act of 1995. A number of important factors
affecting the Company's business and financial results could cause actual
results to differ materially from those stated in the forward-looking state-
ments or projected amounts. Those factors include developments in the
legislative, regulatory and competitive environment, certain environmental
matters, demands for capital expenditures and the availability of cash from
various sources.
Industry Restructuring
On November 25, 1997, the Governor of Massachusetts signed into law the
Electric Industry Restructuring Act (the Act). Provisions of this legislation
include, among other things, a 10 percent discount on standard offer service
and retail choice of energy supplier effective March 1, 1998, with a subse-
quent increase in the discount on standard offer service to 15 percent upon
completion of divestiture of non-nuclear generating assets and securitization
of net non-mitigable stranded costs (which, for the Company, are primarily the
result of above-market purchased power contracts with non-utility generators);
and, recovery of stranded costs subject to review and an audit process.
The Company, together with Cambridge Electric and Canal, filed a compre-
hensive electric restructuring plan with the DTE on November 19, 1997 that was
thoroughly reviewed in five separate hearings that solicited public comment,
and seven days of evidentiary hearings that were completed in February 1998.
Consistent with the Act, the Company's plan provides, as of March 1,
1998, a rate reduction of 10 percent for customers choosing the standard
service transition rate from the average of undiscounted rates in effect
during August 1997, divestiture of non-nuclear generating assets and a
restructured electric generation market that is able to offer retail access to
all customers. The Company's plan also includes the following provisions:
1) an estimate and detailed accounting of total transition costs eligible for
recovery through a non-bypassable access or transition charge; 2) a descrip-
tion of the Company's strategies to mitigate transition costs; 3) unbundled
rates for generation, distribution, transmission and other services;
4) proposed charges for the recovery of transition costs through the non-
bypassable transition charge; 5) proposed programs to provide universal
service to all customers; 6) proposed programs and mandatory charges to
promote energy conservation and demand-side management; 7) procedures for
ensuring direct retail access to all electric generation suppliers;
8) discussions of the impact of the plan on the Company's employees and the
communities served by the Company; and (9) a mandatory charge per kwh for all
consumers to support the development and promotion of renewable energy
projects.
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COMMONWEALTH ELECTRIC COMPANY
On February 27, 1998, the DTE approved the Company's restructuring plan
stating that the plan complies with the Act. While the Company is encouraged
with the treatment afforded stranded or transition cost recovery by the
legislation and the DTE, the mandated customer discount could have a signifi-
cant impact on future cash flows.
Auction Process On March 31, 1997, the Company, together with Cambridge
Electric and Canal (the Companies), submitted a report to the DTE that de-
tailed the proposed auction process for selling their electric generation
assets and entitlements. The process included a standard, sealed-bid auction
for generation assets and purchased power contracts. The auction process
provides a market based approach to maximizing stranded cost mitigation and
minimizing the transition charges that ratepayers will have to pay for
stranded cost recovery. A request for bids from interested parties was issued
during August, and an Offering Memorandum was issued in October. Potential
bidders examined all pertinent information related to the Companies' generat-
ing facilities and purchased power agreements in order to prepare and submit
their first round of bids in mid-December. In January 1998, the Companies
selected a short list of potential bidders, each of whom are expected to
submit a final binding bid in the second quarter of 1998. The entire process,
including regulatory approvals, is expected to be completed in 1998.
Provisions of Statement of Financial Accounting Standards No. 71 As
described in Note 2(b) of the Notes to Consolidated 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,
excluding generation-related assets, remain subject to SFAS No. 71 and its
regulatory assets, including those related to electric generation, remain
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 the non-bypassable
transition charge.
Environmental Matters
The Company is subject to laws and regulations administered by feder-
al,state and local authorities relating to the quality of the environment.
These laws and regulations affect, among other things, the siting and opera-
tion of electric generating and transmission facilities and can require the
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<PAGE 19>
COMMONWEALTH ELECTRIC COMPANY
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
construction schedules of major facilities.
On January 1, 1997, the Company adopted the provisions of Statement of
Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1
provides authoritative guidance for recognition, measurement, display and
disclosure of environmental remediation liabilities in financial statements.
The Company has recorded environmental remediation liabilities net of amounts
paid of $700,000 at December 31, 1997. The adoption of SOP 96-1 did not have
a material adverse effect on the Company's results of operations or financial
position.
Year 2000
The Company has been involved in the Year 2000 compliancy since 1996. A
complete inventory and review of software, information processing and delivery
systems has been completed, and work continues on computer systems wherever
necessary. While some computer systems have already been updated, tested and
placed in production, the Company expects to complete the balance of the
modifications by early 1999.
Expenditures incurred by the system through 1997 to review existing
computer systems and to modify existing software and applications amounted to
nearly $900,000, and it is estimated that approximately $2.6 million will be
incurred in 1998 and 1999.
Management believes that with appropriate modifications, the Company will
be fully compliant regarding all Year 2000 issues and will continue to provide
its products and services uninterrupted through the millennium change.
Failure to become fully compliant could have a significant impact on the
Company's operations.
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. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure
None.
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<PAGE 20>
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).
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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
1995
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.
<PAGE>
<PAGE 22>
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.
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<PAGE 23>
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.
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<PAGE 24>
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.
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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.
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<PAGE 26>
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.
<PAGE>
<PAGE 27>
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
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<PAGE 28>
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
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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.
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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.
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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
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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
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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
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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.
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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)
$ - $ -
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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.
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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.
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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
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<PAGE 39>
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.
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COMMONWEALTH ELECTRIC COMPANY
PART IV.
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).
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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).
<PAGE>
<PAGE 42>
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).
<PAGE>
<PAGE 43>
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).
<PAGE>
<PAGE 44>
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).
<PAGE>
<PAGE 45>
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).
<PAGE>
<PAGE 46>
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).
<PAGE>
<PAGE 47>
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).
<PAGE>
<PAGE 48>
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.
<PAGE>
<PAGE 49>
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
1995
Add: Equity in Earnings (18)
Less: Dividends Received 46
Balance, December 31, 1995 590
1996
Add: Equity in Earnings 53
Less: Dividends Received -
Balance, December 31, 1996 643
1997
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.
<PAGE>
<PAGE 50>
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
<PAGE>
<PAGE 51>
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
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
balance sheet, statement of income, statement of retained earnings and
statement of cash flows contained in Form 10-K of Commonwealth Electric
Company for the fiscal year ended December 31, 1997 and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<CIK> 0000071222
<NAME> COMMONWEALTH ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 379,971
<OTHER-PROPERTY-AND-INVEST> 533
<TOTAL-CURRENT-ASSETS> 65,002
<TOTAL-DEFERRED-CHARGES> 73,713
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 519,219
<COMMON> 51,099
<CAPITAL-SURPLUS-PAID-IN> 97,112
<RETAINED-EARNINGS> 31,993
<TOTAL-COMMON-STOCKHOLDERS-EQ> 180,204
0
0
<LONG-TERM-DEBT-NET> 147,192
<SHORT-TERM-NOTES> 20,215
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 3,553
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 168,055
<TOT-CAPITALIZATION-AND-LIAB> 519,219
<GROSS-OPERATING-REVENUE> 471,449
<INCOME-TAX-EXPENSE> 10,398
<OTHER-OPERATING-EXPENSES> 428,539
<TOTAL-OPERATING-EXPENSES> 438,937
<OPERATING-INCOME-LOSS> 32,512
<OTHER-INCOME-NET> (206)
<INCOME-BEFORE-INTEREST-EXPEN> 32,306
<TOTAL-INTEREST-EXPENSE> 15,383
<NET-INCOME> 16,923
0
<EARNINGS-AVAILABLE-FOR-COMM> 16,923
<COMMON-STOCK-DIVIDENDS> 12,264
<TOTAL-INTEREST-ON-BONDS> 13,586
<CASH-FLOW-OPERATIONS> 37,199
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
