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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, 1998
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, 1999
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 therefore 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 44 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......................... 4
ISO - New England............................. 5
Energy Mix.................................... 6
Rates, Regulation and Legislation............. 6
(a) Restructuring Legislation............... 6
(b) Unbundled Rates......................... 8
(c) Conservation and Load Management........ 9
(f) Retail Choice Pilot Program............. 9
(d) Transmission Rate Matters............... 9
(e) Energy Rate Matters..................... 10
Competition................................... 10
Construction and Financing.................... 12
Employees..................................... 12
Item 2. Properties...................................... 12
Item 3. Legal Proceedings............................... 12
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 13
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 14
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk............................... 22
Item 8. Financial Statements and Supplementary Data..... 22
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 22
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 44
Signatures.................................................. 54
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COMMONWEALTH ELECTRIC COMPANY
PART I.
Item 1. Business
General
Commonwealth Electric Company (the Company) has been engaged in the
generation, transmission, distribution and sale of electricity to approximate-
ly 327,000 retail customers (including 45,500 seasonal) in 40 communities
located in southeastern Massachusetts, including Cape Cod and the island of
Martha's Vineyard, having an approximate year-round population of 549,000 and
a large influx of summer residents. The 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 (the agency 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) 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 (the
Parent), which, together with its subsidiaries, is collectively referred to as
"COM/Energy."
In response to the significant changes that have taken place in the
electric utility industry, the Company sold all of its generating assets in
late 1998 to focus on the transmission and distribution of energy and related
services. For additional information, refer to the "Restructuring Legisla-
tion" section under the "Rates, Regulation and Legislation" section of this
Item 1.
In December 1998, the Parent signed an Agreement and Plan of Merger with
BEC Energy, the parent company of Boston Edison Company, that will create an
energy delivery company serving approximately 1.3 million customers located
entirely within Massachusetts including more than one million electric
customers in 81 communities and 240,000 gas customers in 51 communities. The
merger is expected to occur shortly after the satisfaction of certain condi-
tions, including receipt of certain regulatory approvals. The regulatory
approval process is expected to be completed during the second half of 1999.
By virtue of its charter, which is unlimited in time, the Company has been
involved in the production, purchase, distribution and sale of 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 competition from these sources has not been signifi-
cant. However, on November 25, 1997, the Governor of Massachusetts signed
into law the Electric Industry Restructuring Act that subjects the generation
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COMMONWEALTH ELECTRIC COMPANY
element of traditional electric utility operations to competition effective
March 1, 1998, and further allows consumers for the first time to choose their
electric energy supplier. While competition to provide electric supply has
not yet achieved the starting point for residential customers in Massachu-
setts, several of the Company's commercial and industrial customers (as of
March 1999) are already buying power in the competitive market. For addition-
al information, refer to the "Unbundled Rates" section under the "Rates,
Regulation and Legislation" section of this Item 1. Of the Company's 1998
retail electric unit sales (70.6% of total sales), 47.1% was sold to residen-
tial customers, 42.0% to commercial customers, 10.4% to industrial and 0.5% to
streetlighting and similar types of customers.
Electric Power Supply
The Company sold its generating assets that consisted of five diesel
generators (13.8 megawatts (MW)) in Oak Bluffs and West Tisbury on the island
of Martha's Vineyard that were principally used for emergency and peaking
purposes and a 1.4 percent joint-ownership interest (8.9 MW) in Central Maine
Power's Wyman Unit No. 4 located in Yarmouth, ME, to an affiliate of The
Southern Company of Atlanta, Georgia effective December 30, 1998. The Company
now relies entirely on purchased power to meet its electric energy require-
ments. The sale was the result of an auction process initiated during 1997 in
response to electric industry restructuring legislation enacted in Massachu-
setts in November 1997. For additional information, refer to the "Restructur-
ing Legislation" section under the "Rates, Regulation and Legislation" section
of this Item 1.
Power purchases for the Company and Cambridge Electric Light Company (Cam-
bridge Electric), the other wholly-owned electric distribution subsidiary of
the Parent, are arranged in accordance with their requirements. These
arrangements have included purchases from Canal Electric Company (Canal
Electric), another wholly-owned subsidiary of the Parent. These purchases
included power generated at Canal Electric's generating facilities located in
Sandwich, MA, which were also part of the aforementioned auction and sale.
However, Cambridge Electric and the Company continue to purchase energy and
capacity under a series of long-term contracts, and these entitlements include
one-quarter (139.8 MW) of the capacity and energy of Canal Unit 1, which is
now purchased from the new plant owner, Southern Energy Canal, L.L.C. (South-
ern). The Company's entitlement in Unit 1 is 111.1 MW. The Company's and
Cambridge Electric's cost of service agreements with Canal Electric for one-
half (275.7 MW) of the capacity and energy purchased from Canal Unit 2 were
terminated as part of the generating asset sale on December 30, 1998. The
Company's entitlement in this unit was 220.7 MW. The former Unit 2 agreement
was replaced by a new agreement under which Southern sells energy and capacity
to the Company to support its customer load obligation, at fixed rates that
are equivalent to the Company's standard offer (wholesale) rates.
Pursuant to a Capacity Acquisition and Disposition Agreement (CADA), Canal
Electric 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 Electric's FERC
rate schedule and allows Canal Electric 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 entitle-
ments. The CADA is in effect for Seabrook 1 and Phases I and II of Hydro-
Quebec. 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.
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COMMONWEALTH ELECTRIC COMPANY
Power contracts are in place whereby Canal Electric 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 73.1 MW entitlement from a nuclear unit
in Plymouth, MA (Pilgrim) under a life-of-the-unit contract with Boston Edison
Company. The Pilgrim unit is expected to be sold by Boston Edison Company in
1999 to Entergy Nuclear Generating Company. In conjunction with this sale,
the Company has reached an agreement to buy out of this contract, but will
continue to buy power on a declining basis through 2004. Also, through Canal
Electric'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
32.8 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 1998 as follows: 180.5 MW from four (4) natural gas-fired units; 67
MW from a waste-to-energy unit (including an expansion unit); and 23.4 MW from
four (4) hydro-electric suppliers.
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 that terminates in 1999
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 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. There has been 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.
ISO - New England
The Company, together with other electric utility companies in the New
England area, is a member of ISO - New England (formerly the New England Power
Pool (NEPOOL)), 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
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COMMONWEALTH ELECTRIC COMPANY
requirement. This concept is accomplished by use of computers to monitor and
forecast load requirements.
The Company and the Parent'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
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. COM/Energy 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:
1998 1997 1996
Natural gas 33% 33% 39%
Oil 42 37 21
Nuclear 14 13 20
Waste-to-energy 9 11 12
Hydro 2 6 8
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 1998 and 1997 reflects the greater availability of Canal
Units 1 and 2 as compared to 1996 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
On November 25, 1997, the Governor of Massachusetts signed into law the
Electric Industry Restructuring Act (the Act). This legislation provided,
among other things, that customers of retail electric utility companies who
take standard offer service receive a 10 percent rate reduction and be allowed
to choose their energy supplier, effective March 1, 1998. The Act also
provides that utilities be allowed full recovery of transition costs subject
to review and an audit process. The rate reduction mandated by the legisla-
tion increases to 15 percent effective September 1, 1999 for customers who
continue to take standard offer service. A statewide ballot referendum that
sought to repeal the legislation was defeated by a wide margin on November 3,
1998.
The Company, together with Cambridge Electric and Canal Electric, had
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COMMONWEALTH ELECTRIC COMPANY
filed a comprehensive electric restructuring plan with the DTE in November
1997, that was substantially approved by the DTE in February 1998. The
divestiture of COM/Energy's generation assets and the entitlements associated
with purchased power contracts through an auction process was an integral part
of the restructuring plan and is consistent with the Act. While the Company
is encouraged with the treatment afforded net non-mitigable transition costs
(which, for the Company, are primarily the result of above-market purchased
power contracts with non-utility generators) by the legislation and the DTE,
the mandated rate reduction has had a significant impact on cash flows of the
Company. However, the successful sale of the generating assets, as discussed
below, will reduce the negative impact that the rate reductions will have on
future cash flows.
On May 27, 1998, COM/Energy selected affiliates of Southern Energy New
England, L.L.C., an affiliate of The Southern Company of Atlanta, Georgia, to
buy substantially all of its non-nuclear electric generating assets. As a
result of construction-related adjustments at the closing on December 30,
1998, the final amount of proceeds from the sale was approximately $454
million. These facilities represented 984 MW of electric capacity and had a
book value of $74 million. The plants sold include: Canal Unit 1 (566 MW) and
a one-half interest in Canal Unit 2 (282.5 MW) located in Sandwich, MA and
owned by Canal Electric; the Kendall Station facility (67 MW) and the adjacent
Kendall Jets (46 MW), located in Cambridge, MA and owned by Cambridge Elec-
tric; five diesel generators (13.8 MW) in Oak Bluffs and West Tisbury on the
island of Martha's Vineyard that are owned by the Company, and a 1.4 percent
joint-ownership interest (8.9 MW) in Wyman Unit No. 4 located in Yarmouth, ME,
also owned by the Company.
The Company continues to evaluate bids related to its purchased power
contracts.
On July 31, 1998, a divestiture filing was submitted to the FERC and the
DTE that requested approval of the sale of the generating assets to Southern
Energy and further proposed (subject to completion of the sale) that the
current 10 percent rate reduction increase, effective January 1, 1999. On
October 30, 1998, the DTE approved COM/Energy's sale of assets to Southern
Energy. However, at that time, the DTE deferred ruling on the allocation of
the net proceeds from the sale of Canal Units 1 and 2 between the Company and
Cambridge Electric and on the rate of return to be paid to customers on the
net proceeds from the sale over an eleven-year period. The FERC approved the
sale on November 12, 1998.
On December 23, 1998, the DTE approved COM/Energy's proposal to establish
a special purpose affiliate, Energy Investment Services, Inc. (EIS), that will
administer the above-book value net proceeds from the sale of the Canal units
with the goal of preserving capital and maximizing earnings for the benefit of
retail customers. EIS will credit the proceeds and any return earned to the
accounts of the Company and Cambridge Electric, resulting in a reduction in
the transition costs to be billed to customers. In addition, COM/Energy
agreed to pursue the buyout of above-market purchased power contracts,
including the Pilgrim nuclear unit in which the Company has an 11% entitle-
ment. This transaction is expected to occur in the second quarter of 1999.
On December 23, 1998, the DTE approved the divestiture filing that was
submitted to the FERC and the DTE on July 31, 1998 that requested approval of
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COMMONWEALTH ELECTRIC COMPANY
the sale of the generating assets to Southern Energy and further proposed
(subject to completion of the sale which occurred on December 30, 1998) that
the 10 percent rate reduction increase, effective January 1, 1999, to approxi-
mately 12 percent. In addition, the Company proposed to increase the retail
price of standard offer service, starting January 1, 1999, from 2.8 cents per
kilowatthour (kwh) to 3.5 cents. At the same time, the transition charge for
the Company's customers declined from 4.08 cents per kwh to 3.159 cents.
These changes are intended to further reduce the cost of electricity to
customers, to make the market increasingly more attractive for independent
power suppliers to sell electricity directly to consumers, and to reduce the
Company's cost deferrals associated with the pricing of standard offer
service.
(b) Unbundled Rates
As a result of electric industry restructuring, the Company has unbundled
its rates, provided customers with a 10 percent rate reduction as of March 1,
1998 and has afforded customers the opportunity to purchase generation supply
in the competitive market. Unbundled delivery rates are composed of a
customer charge (to collect metering and billing costs), a distribution charge
(to collect the costs of delivering electricity), a transition charge (to
collect past costs for investments in generating plants and costs related to
power contracts), a transmission charge (to collect the cost of moving the
electricity over high voltage lines from a generating plant), an energy
conservation charge (to collect costs for demand-side management programs) and
a renewable energy charge (to collect the cost to support the development and
promotion of renewable energy projects). Electricity supply services provided
by the Company include optional standard offer service and default service.
Standard offer service is the electricity that is supplied by the local
distribution company (such as the Company) until a competitive power supplier
is chosen by the customer. It is designed as a seven-year transitional
service to give the customer time to learn about competitive power suppliers.
The price of standard offer service will increase over time. Default service
is supplied by the local distribution company when a customer is not receiving
power from either standard offer service or a competitive power supplier. The
market price for default service will fluctuate based on the average market
price for power. Amounts collected through these various charges will be
reconciled to actual expenditures on an on-going basis.
Prior to the implementation of industry restructuring on March 1, 1998,
the Company had a Fuel Charge rate schedule that generally allowed for current
recovery, from retail customers, of fuel used in electric production, pur-
chased power and transmission costs. This schedule required a quarterly
computation and DTE approval of a Fuel Charge 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 schedule did not match
actual costs for that period, an appropriate adjustment was reflected in the
calculation of the next subsequent calendar quarter decimal. This rate
schedule is no longer in effect.
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
kwh factor that was calculated using historical (test-period) capacity costs
and unit sales. This factor was then applied to current monthly kwh sales.
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COMMONWEALTH ELECTRIC COMPANY
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 agree-
ments approved by the DTE in May 1995, the Company was allowed to defer these
costs (within certain limits) which neutralized their sometimes volatile
effect on net income. The Company also had separately stated Conservation
Charge rate schedules that allowed for current recovery, from retail custom-
ers, of conservation and load management costs. These rate schedules are no
longer in effect.
(c) 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.
(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 18 commercial and industrial customers that took service under one of the
Company's economic development rates. This program was discontinued on
February 28, 1998.
(e) Transmission Rate Matters
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 open access transmission and stranded costs. The FERC's notices
proposed to remove impediments to competition in the wholesale bulk power mar-
ketplace 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 interre-
lated 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 (OATTs)
that conform to the FERC pro-forma tariff contained in Order No. 888. On July
9, 1996, the Company filed OATTs that conform to the FERC's pro-forma tariffs.
On November 13, 1996, the FERC accepted the non-rate terms and conditions of
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COMMONWEALTH ELECTRIC COMPANY
these tariffs effective July 9, 1996, subject to a revision of one section
dealing with the scheduling of services.
On January 21, 1997, the Company filed revised OATTs to be consistent with
the most recently filed NEPOOL OATT. 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 OATTs on July 14, 1997. On July
31, 1997, the FERC issued an order on the July 9, 1996 filings, approving the
rates, pending the outcome of any outstanding proceedings. On November 25,
1997, the FERC issued Order No. 888-B requiring minor changes that did not
require an additional filing. On September 31, 1998, following the filing of
NEPOOL's revised OATT, the Company filed revised OATTs for consistency with
NEPOOL. Currently, the Company is awaiting decisions by FERC on the OATTs
filed after 1996.
(f) Energy Rate Matters
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.
Competition
The Company continues to develop and implement strategies that deal with
the restructured utility industry. The planned merger with BEC Energy and the
sale of its generating assets are actions that are indicative of the Company's
commitment to seeking competitive advantages and other benefits by taking
advantage of its strengths. For a more detailed discussion of the pending
merger with BEC Energy, refer to the "Merger with BEC Energy" section of
Management's Discussion and Analysis of Results of Operations filed under Item
7 of this report.
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, COM/Energy 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 duplica-
tion in order to create the most efficient and cost-effective operation
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COMMONWEALTH ELECTRIC COMPANY
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. In 1998, there was a further net
reduction of 21 regular employees.
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 was 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. 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 at December
31, 1998 amounted to $26.7 million. Effective March 1, 1998, this and other
regulatory assets are reflected in rates charged to customers to be recovered
over the next 11 years pursuant to the restructuring legislation discussed
previously.
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 and 31 at
December 31, 1997 and 1996, 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 service. However,
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COMMONWEALTH ELECTRIC COMPANY
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 2.9% in
1998 to 695 from 716 employees at year-end 1997. The Company has 485 employ-
ees (69.8%) who are represented by the Brotherhood of Utility Workers of New
England, Inc. under three separate collective bargaining units with agreements
that expire October 31, 2001, September 30, 2002 and April 30, 2003. Employee
relations have generally been satisfactory.
Item 2. Properties
The principal properties of the Company consist of an integrated system of
transmission and distribution lines, substations, an office building in the
Town of Wareham, MA and other structures such as garages and service build-
ings. The Company sold to an affiliate of The Southern Company of Atlanta,
GA, two diesel plants with a combined capability of 13.8 MW located on the
island of Martha's Vineyard that were used for standby and emergency purposes.
Also sold was the Company's 1.4% joint-ownership interest in Central Maine
Power Company's Wyman Unit 4 with an entitlement of 8.8 MW.
At December 31, 1998, the electric transmission and distribution system
consisted of 5,768 pole miles of overhead lines, 3,803 cable miles of under-
ground line, 139 substations and 339,925 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, 1998
One
(c) Frequency and Amount of Dividends Declared in 1998 and 1997
1998 1997
Per Share Per Share
Declaration Date Amount Declaration Date Amount
May 11, 1998 $3.40 April 25, 1997 $1.65
October 26, 1998 1.55 July 21, 1997 1.85
$4.95 October 27, 1997 1.25
December 22, 1997 1.25
$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, 1998
and 1997 and unit sales for these periods is shown below:
Years Ended Years Ended
December 31, December 31,
1998 and 1997 1997 and 1996
Increase (Decrease)
(Dollars in thousands)
Electric Operating Revenues $(46,450) (9.9)% $ 17,669 3.9%
Operating Expenses -
Electricity purchased for resale
and fuel (41,695) (13.7) 14,619 5.0
Transmission 1,661 31.5 1,230 30.5
Other operation (3,114) (3.9) 7,065 9.8
Maintenance (1,413) (11.0) 22 0.2
Depreciation 455 2.6 513 3.0
Taxes -
Federal and state income (1,242) (11.9) (2,553) (19.7)
Local property and other 62 0.7 612 7.5
(45,286) (10.3) 21,508 5.2
Operating Income (1,164) (3.6) (3,839) (10.6)
Other Income 270 131.1 271 56.8
Income Before Interest Charges (894) (2.8) (3,568) (9.9)
Interest Charges 920 6.0 (886) (5.4)
Net Income $ (1,814) (10.7) $ (2,682) (13.7)
Unit Sales (Megawatthours or MWH)
Retail (17,129) (0.5) 88,213 2.6
Wholesale 282,177 24.0 325,054 38.1
Total unit sales 265,048 5.6 413,267 9.6
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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,
1998 1997 1996
% %
Unit Sales (MWH): Change Change
Residential 1,652,797 (0.9) 1,668,193 1.4 1,645,011
Commercial 1,473,761 0.2 1,470,179 3.7 1,417,790
Industrial 363,559 (1.3) 368,509 3.5 356,009
Streetlighting 15,815 (2.3) 16,180 0.9 16,039
Total retail 3,505,932 (0.5) 3,523,061 2.6 3,434,849
Wholesale 1,460,170 24.0 1,177,993 38.1 852,938
Total 4,966,102 5.6 4,701,054 9.6 4,287,787
Customers - 12 Month Average:
Residential (a) 285,659 1.3 281,927 1.2 278,653
Commercial (a) 39,978 2.4 39,044 1.1 38,609
Industrial 292 (1.4) 296 (1.0) 299
Streetlighting 1,106 2.3 1,081 (1.7) 1,100
Total 327,035 1.5 322,348 1.2 318,661
(a) Includes seasonal customers of 45,537 in 1998, 46,147 in 1997 and 46,862
in 1996. 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.
Total unit sales for 1998 and 1997 increased primarily as a result of
greater sales to Independent System Operator (ISO) - New England (the agency
that operates a centralized facility to ensure reliability of service and
dispatch of economically available generating units throughout New England).
The Company's residential customer segment provides approximately 47% of
its total retail sales and approximately 8% 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 2.1%.
Operating Revenues
Operating revenues for 1998 declined $46.5 million (9.9%) despite higher
unit sales, primarily due to the 10 percent rate reduction (further discussed
below), and a net decrease in electricity purchased for resale, fuel and
transmission charges of $40 million (12.9%). The decline in these costs
reflects a cost deferral of $35.3 million in conjunction with the Company's
restructuring plan as approved by the Massachusetts Department of Telecommuni-
cations and Energy (DTE). As a result of electric industry restructuring, the
Company has unbundled its rates, provided customers with a 10 percent rate
reduction as of March 1, 1998 and has afforded customers the opportunity to
purchase generation supply in the competitive market. Delivery rates are
composed of a customer charge (to collect metering and billing costs), a
distribution charge, a transition charge (to collect stranded costs), a
transmission charge, an energy conservation charge (to collect costs for
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COMMONWEALTH ELECTRIC COMPANY
demand-side management programs) and a renewable energy charge. Electricity
supply services provided by the Company include optional standard offer
service and default service. Amounts collected through these various charges
will be reconciled to actual expenditures on an on-going basis. For addition-
al information concerning electric industry restructuring, refer to the
"Rates, Regulation and Legislation" section filed under Item 1 of this report.
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).
Offsetting these factors was the absence of a $4 million refund associated
with a 1996 power contract settlement agreement.
Wholesale revenues have increased in each of the past three years and
amounted to $27.9 million, $27.8 million and $18.2 million in 1998, 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 and 1996 reflect a
customer refund of $1.7 million and $1.8 million, respectively.
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. The
Company was able to defer these costs (within certain limits) to neutralize
the sometimes volatile effect on net income. For the first two months of 1998
and in 1997 and 1996, there was an overcollection of approximately $764,000,
$1.9 million and $400,000, respectively, that reduced the deferred balance in
the fuel charge stabilization account pursuant to the May 1995 settlement
agreement. There was no net income impact in these periods. The deferred
balance at December 31, 1998 amounted to $26.7 million. Effective March 1,
1998, this regulatory asset is reflected in rates charged to customers to be
recovered over the next 11 years pursuant to the restructuring legislation.
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 that was sold on December 30, 1998.
The cost of electricity purchased for resale, fuel and transmission
constituted 63.5%, 65.8% and 64.8% in 1998, 1997 and 1996, respectively, of
electric operating revenues. These costs reflect higher unit sales in each
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COMMONWEALTH ELECTRIC COMPANY
succeeding year and in addition, a cost deferral of $35.3 million in 1998 that
resulted primarily from providing the required 10% rate reduction for retail
customers.
Other Operating Expenses
Other operation declined $3.1 million (3.9%) in 1998 and primarily
reflects the absence of a one-time charge ($8.4 million) related to a person-
nel reduction program (PRP) initiated in the second quarter of 1997. Also
contributing to the decrease were labor savings realized from the aforemen-
tioned PRP ($2.4 million), a reduction in the provision for bad debts ($1.5
million), and a reduction in insurance and employee benefits costs ($2.1
million). The impact of these factors was offset, in part, by higher costs
relating to the outsourcing of the information technology, telecommunications
and network services function ($6.1 million) including costs associated with
Year 2000 compliance, higher costs related to conservation and load management
programs ($2.9 million) and costs related to supporting the industry restruc-
turing referendum question on the November 1998 ballot ($735,000).
Other operation in 1997 increased $7.1 million (9.8%) due to the aforemen-
tioned PRP charge, 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.
Included in other operation is amortization of certain prior-period
deferred costs, including costs associated with C&LM programs, purchased
power, certain postretirement benefits, and litigation costs related to the
Pilgrim nuclear power unit that in total amounted to $6 million, $6.4 million
and $4.8 million in 1998, 1997 and 1996, respectively.
In 1998, maintenance declined $1.4 million (11%) due to the absence of
storm damage costs related to an April 1997 blizzard ($1.8 million). Mainte-
nance was virtually unchanged in 1997 but included costs associated with
reduced maintenance primarily on transmission and distribution facilities and
the aforementioned blizzard that was offset by the absence of storm damage
costs that resulted from Hurricane Edouard ($2.1 million) in 1996.
Depreciation expense increased $455,000 and $500,000 in 1998 and 1997,
respectively, and reflected additions to property, plant and equipment.
Federal and state income taxes declined $1.2 million (11.9%) in 1998 and
$2.6 million (19.7%) in 1997 due mainly to the change in pretax income.
Local property and other taxes in 1998 and in 1997 increased primarily due
to higher property tax assessments and rates. Payroll and other taxes
declined $371,000 in 1998 due to the PRP and increased by $117,000 in 1997.
Other Income (Expense)
Other income increased in 1998 due to interest accrued on the deferred
transition costs associated with electric industry restructuring ($1.3
million) effective March 1, 1998.
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COMMONWEALTH ELECTRIC COMPANY
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.
Interest Charges
Total interest charges increased in 1998 reflecting a greater level of
short-term borrowings, offset somewhat by slightly lower short-term rates and
scheduled sinking fund payments on long-term debt.
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 year.
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.
Merger with BEC Energy
The electric utility industry has continued to change in response to
legislative and regulatory mandates that are aimed at lowering prices for
energy by creating a more competitive marketplace. These pressures have
resulted in an increasing trend in the electric industry to seek competitive
advantages and other benefits through business combinations. On December 5,
1998, the Parent and BEC Energy (BEC), headquartered in Boston, Massachusetts,
entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant
to the Merger Agreement, COM/Energy and BEC will be merged into a new holding
company to be known as NSTAR. The merger is expected to occur shortly after
the satisfaction of certain conditions, including the receipt of certain
regulatory approvals including that of the DTE. The regulatory approval
process is expected to be completed during the second half of 1999.
The merger will create an energy delivery company serving approximately
1.3 million customers located entirely within Massachusetts, including more
than one million electric customers in 81 communities and 240,000 gas custom-
ers in 51 communities.
Shareholder votes on the merger will be held as part of each of
COM/Energy's and BEC's annual shareholder meetings scheduled for the second
quarter of 1999. The Merger Agreement may be terminated under certain
circumstances, including by any party if the merger is not consummated by
December 5, 1999, subject to an automatic extension of six months if the
requisite regulatory approvals have not yet been obtained by such date. The
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COMMONWEALTH ELECTRIC COMPANY
merger will be accounted for using the purchase method of accounting.
Upon effectiveness of the merger, Thomas J. May, BEC's current Chairman,
President and Chief Executive Officer (CEO), will become the Chairman and CEO
of NSTAR. Russell D. Wright, COM/Energy's current President and CEO, will
become the President and Chief Operating Officer of NSTAR and will serve on
NSTAR's board of directors. Also, upon effectiveness of the merger, NSTAR's
board of directors will consist of COM/Energy's and BEC's current trustees.
Provisions of Statement of Financial Accounting Standards No. 71
As described in Note 2(b) of the Notes to Financial Statements, the
Company follows the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."
In the event the Company is somehow unable to meet the criteria for following
SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge
to operations in an amount that could be material. Conditions that could give
rise to the discontinuance of SFAS No. 71 include: 1) increasing competition
restricting the Company's ability to establish prices to recover specific
costs, and 2) a significant change in the current manner in which rates are
set by regulators. The Company monitors these criteria to ensure that the
continuing application of SFAS No. 71 is appropriate. Based on the current
evaluation of the various factors and conditions that are expected to impact
future cost recovery, the Company believes that its utility operations,
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 electric generation
facilities effective March 1, 1998. The Company will not be required to write
off any of its generation-related assets, including regulatory assets. These
assets will be retained on the Company's Balance Sheets because the legisla-
tion and the DTE's plan for a restructured electric industry specifically
provide for their recovery through the non-bypassable transition charge.
Year 2000
The Year 2000 issue is the result of computer programs being written using
two digits rather than four to define the applicable year. Any computer
program that has date sensitive software may recognize a date using "00" as
the year 1900 rather than the year 2000. This could result in a temporary
inability to process transactions or engage in normal business activities.
COM/Energy has been involved in Year 2000 compliancy since 1996.
COM/Energy, on a coordinated basis and with the assistance of RCG Informa-
tion Technologies and other consultants, is addressing the Year 2000 issue.
COM/Energy has followed a five-phase process in its Year 2000 compliance
efforts, as follows: Awareness (through a series of internal announcements to
employees and through contacts with vendors); Inventory (all computers,
applications and embedded systems that could potentially be affected by the
Year 2000 problem); Assessment (all applications or components and the impact
on overall business operations and a plan to correct deficiencies and the cost
to do so); Remediation (the modification, upgrade or replacement of deficient
hardware and software applications and infrastructure modifications); and
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COMMONWEALTH ELECTRIC COMPANY
Testing (a detailed, comprehensive testing program for the modified critical
component, system or software that involves the planning, execution and
analysis of results).
COM/Energy's inventory phase required an assessment of all date sensitive
information and transaction processing computer systems and determined that
approximately 90% of its software systems needed some modifications or
replacement. Plans were developed and are being implemented to correct and
test all affected systems, with priorities assigned based on the importance of
the activity. COM/Energy has identified the software and hardware installa-
tions that are necessary. All installations are expected to be completed and
tested by mid-1999.
COM/Energy has also inventoried its non-information technology systems
that may be date sensitive (facilities, electric and gas operations, energy
supply/production and distribution) that use embedded technology such as
micro-controllers and micro-processors. COM/Energy is approximately 86%
complete in its efforts to resolve non-compliance with Year 2000 requirements
related to its non-information technology systems. COM/Energy anticipates
that these systems will be updated or replaced as necessary and tested by mid-
1999.
At present, the remediation phase for information technology as it applies
to hardware and non-technology issues is scheduled for completion by June 1,
1999. The testing phase for Year 2000 compliance is approximately 70%
complete and is scheduled to be concluded by June 30, 1999. All other phases
are complete.
Modifying and testing COM/Energy's information and transaction processing
systems from 1996 through 2000 is currently expected to cost approximately $7
million, including approximately $900,000 incurred through 1997 and $3.1
million spent in 1998. Approximately $3 million is expected to be spent in
1999 and 2000. Year 2000 costs have been expensed as incurred and will
continue to be funded from operations.
In addition to its internal efforts, COM/Energy has initiated formal
communications with its significant suppliers to determine the extent to which
COM/Energy may be vulnerable to its suppliers' failure to correct their own
Year 2000 issues. As of February 1, 1999, COM/Energy has received responses
from approximately 75% of those entities contacted, and nearly all have
indicated that they are or will be Year 2000 compliant. Failure of
COM/Energy's significant suppliers to address Year 2000 issues could have a
material adverse effect on COM/Energy's operations, although it is not
possible at this time to quantify the amount of business that might be lost or
the costs that could be incurred by COM/Energy. Contact with significant
vendors is continuing and inadequate or marginal responses are being pursued
by COM/Energy. COM/Energy is prepared to replace certain suppliers or to
initiate other contingency plans should these vendors not respond to
COM/Energy's satisfaction by July 1, 1999.
In addition, parts of the global infrastructure, including national
banking systems, electrical power grids, gas pipelines, transportation
facilities, communications and governmental activities, may not be fully
functional after 1999. Infrastructure failures could significantly reduce
COM/Energy's ability to acquire energy and its ability to serve its customers
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COMMONWEALTH ELECTRIC COMPANY
as effectively as they are now being served. COM/Energy is identifying
elements of the infrastructure that are critical to its operations and is
obtaining information as to the expected Year 2000 readiness of these ele-
ments.
COM/Energy has started its contingency planning for critical operational
areas that might be effected by the Year 2000 issue if compliance by
COM/Energy is delayed. COM/Energy gas and electric operations currently have
emergency operating plans as well as information technology disaster recovery
plans as components of its standard operating procedures. These plans will be
enhanced to identify potential Year 2000 risks to normal operations and the
appropriate reaction to these potential failures including contingency plans
that may be required for any third parties that fail to achieve Year 2000
compliance. All necessary contingency plans are expected to be completed by
June 30, 1999, although in certain cases, especially infrastructure failures,
there may be no practical alternative course of action available to
COM/Energy.
COM/Energy is working with other energy industry entities, both regionally
and nationally with respect to Year 2000 readiness and is cooperating in the
development of local and wide-scale contingency planning.
While COM/Energy believes its efforts to address the Year 2000 issue will
allow it to be successful in avoiding any material adverse effect on
COM/Energy's operations or financial condition, it recognizes that failing to
resolve Year 2000 issues on a timely basis would, in a "most reasonably likely
worst case scenario," significantly limit its ability to acquire and distrib-
ute energy and process its daily business transactions for a period of time,
especially if such failure is coupled with third party or infrastructure
failures. Similarly, COM/Energy could be significantly effected by the
failure of one or more significant suppliers, customers or components of the
infrastructure to conduct their respective operations after 1999. Adverse
affects on COM/Energy could include, among other things, business disruption,
increased costs, loss of business and other similar risks.
The foregoing discussion regarding Year 2000 project timing, effective-
ness, implementation and costs includes forward-looking statements that are
based on management's current evaluation using available information. Factors
that might cause material changes include, but are not limited to, the
availability of key Year 2000 personnel, the readiness of third parties, and
COM/Energy's ability to respond to unforeseen Year 2000 complications.
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 will
continue to have an impact on future operations, capital costs and construc-
tion schedules of major facilities.
On January 1, 1997, COM/Energy adopted the provisions of Statement of
Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1
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COMMONWEALTH ELECTRIC COMPANY
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 $849,000 at December 31, 1998. The adoption of SOP 96-1 did not have
a material adverse effect on COM/Energy's results of operations or financial
position.
New Accounting Principles
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts possibly including fixed-price fuel supply and power con-
tracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999
and may be implemented as of the beginning of any fiscal quarter after
issuance but cannot be applied retroactively. SFAS No. 133 must be applied to
derivative instruments and certain derivative instruments embedded in hybrid
contracts that were issued, acquired or substantively modified after December
31, 1997 and, at the Company's election, before January 1, 1998.
The adoption of SFAS No. 133 is not expected to have a material impact on
the Company's results of operations or financial condition.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although the Company has material commodity purchase contracts and
financial instruments (debt), these instruments are not subject to market
risk. The Company has a rate making mechanism which allows for the recovery
of fuel costs from customers. The fuel adjustment mechanism allows the
Company to pass all costs related to the purchase of commodities to the
customer, thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's prudently
incurred debt obligations realized by the Company would be borne by customers
through future rates.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed here-
with on pages 23 through 43 of this report.
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure
None.
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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, 1998 and 1997, and the related
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended Decem-
ber 31, 1998, in conformity with generally accepted accounting principles.
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 18, 1999
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COMMONWEALTH ELECTRIC COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1998 and 1997
Statements of Income for the Years Ended December 31, 1998, 1997 and 1996
Statements of Retained Earnings for the Years Ended December 31, 1998,
1997 and 1996
Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and
1996
Notes to Financial Statements
PART IV.
SCHEDULES
I Investments in, Equity in Earnings of, and Dividends Received from
Related Parties - Years Ended December 31, 1998, 1997 and 1996
II Valuation and Qualifying Accounts - Years Ended December 31, 1998,
1997 and 1996
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.
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COMMONWEALTH ELECTRIC COMPANY
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
ASSETS
1998 1997
(Dollars in thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $566,477 $550,449
Less - Accumulated depreciation 182,345 174,488
384,132 375,961
Add - Construction work in progress 2,544 4,010
386,676 379,971
INVESTMENTS
Equity in nuclear electric power company 485 519
Other 14 14
499 533
LONG-TERM RECEIVABLE - AFFILIATE 184,343 -
CURRENT ASSETS
Cash 3,584 1,496
Accounts receivable -
Affiliates 1,483 1,753
Customers, less reserves of $1,069 in 1998
and $2,044 in 1997 40,114 45,199
Unbilled revenues 6,096 9,162
Inventories, at average cost 2,669 2,578
Prepaid taxes -
Property 3,153 3,043
Income 5,195 -
Other 1,192 1,771
63,486 65,002
DEFERRED CHARGES
Regulatory assets 101,895 70,112
Deferred tax asset 30,838 -
Other 1,618 3,601
134,351 73,713
$769,355 $519,219
The accompanying notes are an integral part of these financial statements.
<PAGE>
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COMMONWEALTH ELECTRIC COMPANY
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
CAPITALIZATION AND LIABILITIES
1998 1997
(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 36,984 31,993
185,195 180,204
Long-term debt, less current
sinking fund requirements 143,651 147,192
328,846 327,396
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks - 14,900
Advances from affiliates 40,350 5,315
40,350 20,215
Other Current Liabilities -
Current sinking fund requirements 3,553 3,553
Accounts payable -
Affiliates 14,159 12,007
Other 26,370 32,826
Accrued taxes -
Local property and other 3,343 3,299
Income - 19,114
Accrued interest 3,751 3,811
Other 22,690 12,717
73,866 87,327
114,216 107,542
DEFERRED CREDITS
Regulatory liabilities 297,693 -
Accumulated deferred income taxes - 50,283
Unamortized investment tax credits 6,224 6,696
Other 22,376 27,302
326,293 84,281
COMMITMENTS AND CONTINGENCIES
$769,355 $519,219
The accompanying notes are an integral part of these financial statements.
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<PAGE 27>
COMMONWEALTH ELECTRIC COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
ELECTRIC OPERATING REVENUES $424,999 $471,449 $453,780
OPERATING EXPENSES
Electricity purchased for resale
and fuel 263,087 304,782 290,163
Transmission 6,927 5,266 4,036
Other operation 76,210 79,324 72,259
Maintenance 11,458 12,871 12,849
Depreciation 18,009 17,554 17,041
Taxes -
Income 9,156 10,398 12,951
Local property 6,413 5,980 5,485
Payroll and other 2,391 2,762 2,645
393,651 438,937 417,429
OPERATING INCOME 31,348 32,512 36,351
OTHER INCOME (EXPENSE) 64 (206) (477)
INCOME BEFORE INTEREST CHARGES 31,412 32,306 35,874
INTEREST CHARGES
Long-term debt 13,253 13,586 13,968
Other interest charges 3,050 1,797 2,301
16,303 15,383 16,269
NET INCOME $ 15,109 $ 16,923 $ 19,605
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, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
Balance at beginning of year $31,993 $27,334 $20,708
Add (Deduct):
Net income 15,109 16,923 19,605
Cash dividends on common stock (10,118) (12,264) (12,979)
Balance at end of year $36,984 $31,993 $27,334
The accompanying notes are an integral part of these financial statements.
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COMMONWEALTH ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
(Dollars in thousands)
OPERATING ACTIVITIES
Net income $ 15,109 $ 16,923 $ 19,605
Effects of noncash items -
Depreciation and amortization 24,024 23,961 21,815
Deferred income taxes, net 14,285 3,720 569
Investment tax credits, net (472) (430) (433)
Change in working capital, exclusive of
cash and interim financing -
Accounts receivable and
unbilled revenues 8,421 (4,067) (713)
Income taxes, net (24,309) 3,652 (3,259)
Local property and other taxes, net (66) 255 (224)
Accounts payable and other 6,097 6,968 860
Transition costs deferral (35,254) - -
Fuel charge stabilization deferral, net 1,465 (5,543) 2,372
All other operating items 10,182 (8,240) (3,788)
Net cash provided by operating activities 19,482 37,199 36,804
INVESTING ACTIVITIES
Proceeds from sale of generating assets 709 - -
Additions to property, plant and
equipment (exclusive of AFUDC) (24,416) (22,255) (20,483)
Allowance for borrowed funds used
during construction (163) (145) (98)
Net cash used for investing activities (23,870) (22,400) (20,581)
FINANCING ACTIVITIES
Payment of dividends (10,118) (12,264) (12,979)
Payment of short-term borrowings (14,900) (100) (2,300)
Advances from affiliates 35,035 2,245 1,525
Retirement of long-term debt
through sinking funds (3,541) (3,542) (3,541)
Net cash used for financing activities 6,476 (13,661) (17,295)
Net increase (decrease) in cash 2,088 1,138 (1,072)
Cash at beginning of period 1,496 358 1,430
Cash at end of period $ 3,584 $ 1,496 $ 358
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the periods for:
Interest (net of capitalized amounts) $ 15,168 $ 14,948 $ 15,436
Income taxes $ 1,680 $ 5,019 $ 13,424
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 30>
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 Parent). The Parent, together with its
subsidiaries, is collectively referred to as "COM/Energy." The Parent 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 have been
involved in the production, distribution and sale of electricity to 327,000
customers (including 45,500 seasonal) in 40 communities located in south-
eastern 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. In December 1998, the Parent signed an Agreement and Plan
of Merger with BEC Energy, the parent company of Boston Edison Company, that
will create an energy delivery company, that includes the Company, serving
approximately 1.3 million customers located entirely within Massachusetts
including more than one million electric customers in 81 communities and
240,000 gas customers in 51 communities.
The Company has 695 regular employees including 485 (70%) represented by
three collective bargaining units covered by separate contracts with expira-
tion dates ranging from October 2001 through April 2003. Employee relations
have generally been satisfactory.
In response to the significant changes that have taken place in the
utility industry, the Company sold all of its non-nuclear generating assets in
1998 to focus on the transmission and distribution of energy and related
services.
(2) Significant Accounting Policies
(a) Principles of Accounting
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by
various authorities, including the Federal Energy Regulatory Commission (FERC)
and the Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, the Company accounts for the
economic effects of regulation in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." The Company has established various regula-
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<PAGE 31>
COMMONWEALTH ELECTRIC COMPANY
tory assets in cases where the DTE and/or the FERC have permitted or are
expected to permit recovery of specific costs over time. Similarly, the
regulatory liabilities established by the Company are required to be refunded
to customers over time. In the event the criteria for applying SFAS No. 71
are no longer met, the accounting impact would be an extraordinary, non-cash
charge to operations of an amount that could be material. Criteria that give
rise to the discontinuance of SFAS No. 71 include: 1) increasing competition
that restricts the Company's ability to establish prices to recover specific
costs, and 2) a significant change in the current manner in which rates are
set by regulators from cost based regulation to another form of regulation.
These criteria are reviewed on a regular basis to ensure the continuing
application of SFAS No. 71 is appropriate. Based on the current evaluation of
the various factors and conditions that are expected to impact future cost
recovery, the Company believes that its regulatory assets, including those
related to generation, are probable of future recovery.
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.
The principal regulatory assets included in deferred charges were as
follows:
1998 1997
(Dollars in thousands)
Transition costs $ 38,622 $ -
Power contract buy-out 15,717 17,609
Fuel charge stabilization 26,682 29,655
Postretirement benefit costs 12,269 12,271
Yankee Atomic unrecovered plant
and decommissioning costs 2,042 3,436
Pilgrim nuclear plant litigation costs 5,417 5,929
Other 1,146 1,212
$101,895 $70,112
The regulatory liabilities, reflected in the accompanying Balance Sheets
were as follows:
1998 1997
(Dollars in thousands)
Regulatory liability related to
sale of generating assets $293,186 $ -
Demand-side management deferral 2,274 -
Excess Seabrook-related deferred income taxes 319 698
Other deferred income taxes 1,782 1,875
Excess replacement power refunds 132 246
$297,693 $ 2,819
The regulatory liability of $293.2 million was established pursuant to the
Company's divestiture filing that was approved by the DTE in which the Company
agreed to use its share of the net proceeds from affiliate Canal Electric
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COMMONWEALTH ELECTRIC COMPANY
Company's (Canal Electric) sale of generation assets and the sale of its own
generating assets to reduce transition costs that are billed to its retail
electric customers over the next several years as a result of electric
industry restructuring. COM/Energy established Energy Investment Services,
Inc. as the vehicle to invest the net proceeds from the sale of Canal
Electric's generating assets. These proceeds will be invested in a conserva-
tive portfolio of securities that is designed to maintain principal and earn a
reasonable return. Both the principal amount and income earned will be used
to reduce the transition costs that would otherwise be billed to customers of
the Company and Cambridge Electric. The Company's share of the net proceeds
from the sale of Canal Electric's generating assets has been classified as a
long-term receivable - affiliate on the accompanying Balance Sheets.
The Company's regulatory assets, including the costs associated with an
existing power contract with the Yankee Atomic nuclear power plant that was
shut down permanently (see Note 3(d)), and all of its regulatory liabilities
are reflected in rates charged to customers. Regulatory assets are to be
recovered over the next 11 years pursuant to the legislation discussed below.
In November 1997, the Commonwealth of Massachusetts enacted a comprehen-
sive electric utility industry restructuring bill. On November 19, 1997, the
Company, together with affiliates Cambridge Electric Light Company (Cambridge
Electric) and Canal Electric, filed a restructuring plan with the DTE. The
plan, approved by the DTE on February 27, 1998, provides that the Company and
Cambridge Electric, beginning March 1, 1998, initiate a ten percent rate
reduction for all customer classes and allow customers to choose their energy
supplier. As part of the plan, the DTE authorized the recovery of certain
strandable costs and provides that certain future costs may be deferred to
achieve or maintain the rate reductions that the restructuring bill mandates.
The legislation gives the 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.
(c) Transactions with Affiliates
Transactions between the Company and other COM/Energy companies include
purchases and sales of electricity, including purchases from Canal Electric,
an affiliated wholesale electric generating company. Other Canal transactions
include costs relating to the abandonment of Seabrook 2 and the recovery of a
portion of Seabrook 1 pre-commercial operation costs. In addition, payments
for management, accounting, data processing and other services are made to an
affiliate, COM/Energy Services Company. Transactions with other COM/Energy
companies are subject to review by the DTE.
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<PAGE 33>
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)
1998 $56,269 $29,403 $ 2,605
1997 61,087 31,417 6,524
1996 40,733 31,848 9,096
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 $1,026,000,
$1,290,000 and $1,453,000 in 1998, 1997 and 1996, 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 3.33% in 1998 and 3.32% in 1997 and 1996.
(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 $163,000, $145,000 and $98,000 in 1998,
1997 and 1996, 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 5.75% in 1998 and
6.25% in 1997 and 1996.
(3) Commitments and Contingencies
(a) Financing and Construction Programs
The Company is engaged in a continuous construction program presently
estimated at $135.8 million for the five-year period 1999 through 2003. Of
that amount, $30.5 million is estimated for 1999. The program is subject to
periodic review and revision because of factors such as changes in business
conditions, rates of customer growth, effects of inflation, maintenance of
reliable and safe service, equipment delivery schedules, licensing delays,
availability and cost of capital and environmental factors. The Company
expects to finance these expenditures on an interim basis with internally
generated funds and short-term borrowings that are ultimately expected to be
repaid with the proceeds from sales of long-term debt and equity securities.
(b) 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 1998 1997 1996
(Dollars in thousands)
Type of Unit
Natural Gas 2008-2017 (a) 184.1 $107,118 $114,773 $111,007
Oil 2002 (b) 266.0 54,957 58,187 36,060
Nuclear 2004-2026 (c) 106.1 66,775 68,381 68,716
Waste-to-energy 2015 100 67.0 44,423 43,038 39,622
Hydro 2014-2023 100 23.9 11,359 10,952 12,537
Total 647.1 $284,632 $295,331 $267,942
(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%).
On May 27, 1998, COM/Energy selected affiliates of Southern Energy New
England, L.L.C., an affiliate of The Southern Company of Atlanta,
Georgia, to buy substantially all of its non-nuclear electric generat-
ing assets, including Canal Units 1 and 2. Under long-term contracts,
the Company's entitlement in Unit 1 is 111.1 MW. However, the Company
continues to purchase energy and capacity under a series of long-term
contracts, and this entitlement includes its share of one-quarter of
the capacity and energy of Canal Unit 1, which is now purchased from
the new plant owner, Southern Energy Canal, L.L.C. (Southern). The
Company's cost of service agreement with Canal Electric for its share
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<PAGE 35>
COMMONWEALTH ELECTRIC COMPANY
of the capacity and energy purchased from Canal Unit 2 was terminated
as part of the generating asset sale on December 30, 1998. The former
Unit 2 agreement was replaced by a new agreement under which Southern
sells energy and capacity to the Company to support its customer load
obligation, at fixed rates that are equivalent to the Company's
standard offer (wholesale) rates.
(c) Includes entitlements in Seabrook 1 (2.8%) and Pilgrim (11% through
2001, 8.8% in 2002, and 5.5% for 2003 through 2004). The Pilgrim unit
is expected to be sold in 1999 to Entergy Nuclear Generating Company.
In conjunction with the sale, the Company has reached an agreement to
buy out of this contract, but will continue to buy power on a declin-
ing basis through 2004.
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 being recovered
through a transition charge pursuant to DTE approval.
The estimated aggregate obligations for capacity under the long-term
purchased power contracts and a life-of-the-unit contract from the Seabrook 1
unit in effect for the five years subsequent to 1998 is as follows:
Long-Term
Purchased
Power
(Dollars in thousands)
1999 $286,019
2000 284,006
2001 340,921
2002 329,744
2003 289,270
(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 will
continue to have an impact on future operations, capital costs and construc-
tion schedules of major transmission and distribution facilities.
(4) Income Taxes
For financial reporting purposes, the Company provides federal and state
income taxes on a separate-return basis. However, for federal income tax
purposes, the Company's taxable income and deductions are included in the
consolidated income tax return of the Parent and it makes tax payments or
receives refunds on the basis of its tax attributes in the tax return in
accordance with applicable regulations.
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<PAGE 36>
COMMONWEALTH ELECTRIC COMPANY
The following is a summary of the Company's provisions for income taxes
for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
(Dollars in thousands)
Federal
Current $ (3,824) $ 5,852 $10,818
Deferred 11,843 3,174 374
Investment tax credits, net (472) (430) (433)
7,547 8,596 10,759
State
Current (833) 1,254 1,997
Deferred 2,442 548 195
1,609 1,802 2,192
$ 9,156 $10,398 $12,951
The significant change in the current and deferred provisions for income
taxes in 1998 reflects the current tax related to the sale of the company's
non-nuclear generating assets and the related deferred tax benefit.
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 1998 and
1997:
1998 1997
(Dollars in thousands)
Liabilities
Property-related $ 55,342 $54,605
Transition costs 14,778 -
Fuel charge stabilization 11,300 12,241
Power contract buy-out 6,135 6,853
All other 9,447 8,647
97,002 82,346
Assets
Deferred tax asset 114,340 -
Investment tax credit 4,046 4,322
All other 9,454 9,120
127,840 13,442
Accumulated deferred income taxes
(deferred tax asset), net $(30,838) $68,904
The net deferred tax asset for 1998 is included in other deferred charges
in the accompanying Balance Sheets. The net year-end deferred income tax
liability for 1997 includes a current deferred tax liability of $18,621,000
that is included in accrued income taxes.
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COMMONWEALTH ELECTRIC COMPANY
The total income tax provision set forth previously represents 38% in 1998
and 1997 and 40% in 1996 of income before such taxes. The following table
reconciles the statutory federal income tax rate to these percentages:
1998 1997 1996
(Dollars in thousands)
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory levels $ 8,493 $ 9,562 $11,395
Increase (Decrease) from statutory levels:
State tax net of federal tax benefit 1,046 1,171 1,425
Tax versus book depreciation 198 105 103
Amortization of investment tax credits (472) (430) (433)
Reversals of capitalized expenses (76) (63) (64)
Additional reserves for tax deficiencies - - 431
Other (33) 53 94
$ 9,156 $10,398 $12,951
Effective federal income tax rate 38% 38% 40%
(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
with the funding requirements of the Employee Retirement Income Security Act
of 1974.
The following tables set forth the change in the pension benefit obliga-
tion and plan assets as well as the plan's funded status reconciled to the
amount included in the financial statements:
1998 1997
(Dollars in thousands)
Change in benefit obligation
Obligation at beginning of year $ 184,290 $ 157,604
Service cost 2,954 3,245
Interest cost 12,702 11,306
Actuarial loss 17,760 22,150
Benefits paid (11,539) (10,015)
Obligation at end of year $ 206,167 $ 184,290
1998 1997
(Dollars in thousands)
Change in plan assets
Fair value of plan assets at
beginning of year $ 177,112 $ 155,650
Actual return on plan assets 13,692 27,678
Employer contributions 2,469 3,799
Transfers to affiliated companies (74) -
Benefits paid (11,539) (10,015)
Fair value of plan assets at
end of year $ 181,660 $ 177,112
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<PAGE 38>
COMMONWEALTH ELECTRIC COMPANY
1998 1997
(Dollars in thousands)
Funded status $ (24,507) $ (7,178)
Unrecognized transition obligation 1,930 2,574
Unrecognized prior service cost 4,030 4,594
Unrecognized net actuarial (gain) loss 11,120 (6,560)
Prepaid (accrued) benefit cost $ (7,427) $ (6,570)
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00%
Expected return on plan assets 9.00 8.75
Rate of increase in future compensation 3.75 3.75
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.
Components of net periodic pension cost were as follows:
1998 1997 1996
(Dollars in thousands)
Service cost $ 2,954 $ 3,245 $ 3,405
Interest cost 12,702 11,306 11,300
Expected return on plan assets (13,537) (12,055) (11,065)
Amortization of transition obligation 643 643 643
Amortization of prior service cost 562 563 563
Total 3,324 3,702 4,846
Transfer from (to) affiliated
companies, net 76 (231) (191)
Less: Amounts capitalized and deferred 1,454 1,714 1,369
Net periodic pension cost $ 1,946 $ 1,757 $ 3,286
The net periodic pension cost reflects the use of the projected unit
credit method which 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 the pension contribution that
is reflected in base rates, and pension expense.
(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.
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COMMONWEALTH ELECTRIC COMPANY
The following tables set forth the change in the postretirement benefit
obligation and plan assets as well as the plan's funded status reconciled to
the amount included in the financial statements:
1998 1997
(Dollars in thousands)
Change in benefit obligation
Obligation at beginning of year $ 68,697 $ 58,928
Service cost 1,046 980
Interest cost 4,751 4,355
Actuarial loss 7,060 6,863
Participant contributions 47 28
Benefits paid (3,705) (2,457)
Obligation at end of year $ 77,896 $ 68,697
1998 1997
(Dollars in thousands)
Change in plan assets
Fair value of plan assets at
beginning of year $ 30,229 $ 22,635
Actual return on plan assets 2,092 4,369
Employer contributions 5,418 5,654
Participant contributions 47 28
Benefits paid (3,705) (2,457)
Fair value of plan assets at
end of year $ 34,080 $ 30,229
Funded status $ (43,816) $ (38,468)
Unrecognized transition obligation 33,832 36,250
Unrecognized net actuarial loss 9,984 2,218
Prepaid (accrued) benefit cost $ - $ -
Weighted-average assumptions as of December 31 were as follows:
1998 1997
Discount rate 6.50% 7.00%
Expected return on plan assets 9.00 8.75
Rate of increase in future compensation 3.75 3.75
For measurement purposes, a 6.50% annual rate of increase in the per
capita cost of covered medical claims was assumed for 1999. The rates were
assumed to decrease gradually to 4.5% for 2007 and remain at that level
thereafter. Dental claims and Medicare Part B premiums are expected to
increase at 4.5% and 3.1%, respectively.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect the periodic
postretirement benefit cost in future years.
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COMMONWEALTH ELECTRIC COMPANY
Components of net periodic postretirement benefit cost were as follows:
1998 1997 1996
(Dollars in thousands)
Service cost $ 1,046 $ 980 $ 1,132
Interest cost 4,751 4,355 4,382
Expected return on plan assets (2,796) (2,098) (1,564)
Amortization of transition obligation 2,417 2,417 2,417
Total 5,418 5,654 6,367
Transfers from affiliates, net (211) (645) (500)
Add: Net amortization of deferrals 858 858 858
Less: Amounts capitalized and deferred 807 936 1,022
Net periodic postretirement
benefit cost $ 5,258 $ 4,931 $ 5,703
Assumed healthcare cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage point change in
assumed healthcare cost trend rates would have the following effects:
One-Percentage-Point
Increase Decrease
(Dollars in thousands)
Effect on total of service and
interest cost components $ 903 $ (723)
Effect on postretirement
benefit obligation $10,217 $ (9,550)
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, 1998 and 1997, the Company's deferral amounted to approximately
$5.4 million and $6.3 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 $1,435,000 in 1998, $1,672,000 in 1997, and
$1,788,000 in 1996.
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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 1998 1997
(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 13,684 14,737
10-Year Notes, 7.43%, due 2003 15,000 15,000 15,000
15-Year Notes, 9.50%, due 2004 15,000 5,000 7,500
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
$143,684 $147,237
The Company, under favorable conditions, may purchase its outstanding
notes in advance; however, an early payment premium may be incurred. Certain
of these agreements require the Company to make periodic sinking fund payments
for retirement of outstanding long-term debt.
The required sinking fund payments for the five years subsequent to
December 31, 1998 are as follows:
Sinking Fund Maturing
Year Payments Debt Issues Total
(Dollars in thousands)
1999 $3,553 $ - $ 3,553
2000 3,553 - 3,553
2001 3,481 - 3,481
2002 3,481 30,000 33,481
2003 3,481 15,000 18,481
(b) Notes Payable to Banks
The Company and other COM/Energy 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, 1998, COM/Energy
had $122 million of committed lines of credit that will expire at varying
intervals in 1999. These lines are normally renewed upon expiration and
require annual fees of up to .1875% of the individual line. At December 31,
1998, the uncommitted lines of credit totaled $10 million. Interest rates on
the outstanding borrowings generally are at an adjusted money market rate and
averaged 5.7% and 5.8% in 1998 and 1997, respectively. At December 31, 1998,
the Company had no notes payable to banks. Notes payable to banks totaled
$14.9 million at December 31, 1997.
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COMMONWEALTH ELECTRIC COMPANY
(c) Advances from Affiliates
The Company is a member of the COM/Energy Money Pool (the Pool), an
arrangement among the subsidiaries of the Parent, 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 5.3% and 5.4% in 1998 and 1997, respective-
ly. Notes payable to the Pool totaled $40,350,000 and $5,315,000 at December
31, 1998 and 1997, respectively.
The Company had no notes payable to the Parent at December 31, 1998 or
December 31, 1997. However, this source of financing may be utilized by the
Company and notes are written for a term of up to 11 months and 29 days.
Interest is at the prime rate and is adjusted for changes in that rate during
the term of the notes. The rate averaged 8.3% and 8.5% in 1998 and 1997,
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, 1998 and 1997 are as follows:
1998 1997
(Dollars in thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $147,204 $171,667 $150,745 $171,787
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, 1998, there were no retained earnings 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
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COMMONWEALTH ELECTRIC COMPANY
year or longer. Leases currently in effect contain no provisions that
prohibit the Company from entering into future lease agreements or obliga-
tions.
Future minimum lease payments, by period and in the aggregate, of non-can-
celable operating leases consisted of the following at December 31, 1998:
Operating Leases
(Dollars in thousands)
1999 $ 2,857
2000 1,384
2001 794
2002 794
2003 450
Beyond 2003 1,840
Total future minimum lease payments $ 8,119
Total rent expense for all operating leases, except those with terms of a
month or less, amounted to $2,718,000 in 1998, $3,174,000 in 1997 and
$2,814,000 in 1996. There were no contingent rentals and no sublease rentals
for the years 1998, 1997 and 1996.
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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 24).
(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, 1996, 1997
and 1998 (page 52).
Schedule II - Valuation and Qualifying Accounts - Years Ended
December 31, 1998, 1997 and 1996 (page 53).
(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).
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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 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).
10.1.7.1 Supplement to 10.1.7 consisting of three Capacity Acquisition
Commitments each dated May 7, 1987, concerning Phases I and II of
the Hydro-Quebec Project and electricity acquired from Connecticut
Light and Power Company CL&P) (Exhibit 1 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.7.2 Amendment to 10.1.7 as amended and restated June 1, 1993, 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).
10.1.8 Phase 1 Vermont Transmission Line Support Agreement and Amendment
No. 1 thereto between Vermont Electric Transmission Company, Inc.
and certain other New England utilities, dated December 1, 1981
and June 1, 1982, respectively (Refiled as Exhibits 5 and 6 to the
1992 CE Form 10-K, File No. 2-7749).
10.1.8.1 Amendment No. 2 to 10.1.8 as amended November 1, 1982 (Exhibit 5
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.8.2 Amendment No. 3 to 10.1.8 as amended January 1, 1986 (Exhibit 2 to
the CE 1986 Form 10-K, File No. 2-7749).
10.1.9 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE
for the purchase of available hydro-electric energy produced by a
facility located in Ware, Massachusetts, dated September 1, 1983
(Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.10 Power Purchase Agreement between Corporation Investments, Inc.
(CI), and CE for the purchase of available hydro-electric energy
produced by a facility located in Lowell, Massachusetts, dated
January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K,
File No. 2-7749).
10.1.10.1 Amendment to 10.1.12 between CI and Boott Hydropower, Inc., an
assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to
the CE 1984 Form 10-K, File No. 2-7749).
10.1.11 Phase 1 Terminal Facility Support Agreement dated December 1,
1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated
November 1, 1982, between New England Electric Transmission Corpo-
ration (NEET), other New England utilities and CE (Exhibit 1 to
the CE Form 10-Q (June 1984), File No. 2-7749).
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COMMONWEALTH ELECTRIC COMPANY
10.1.11.1 Amendment No. 3 to 10.1.11 (Exhibit 2 to the CE Form 10-Q (June
1986), File No. 2-7749).
10.1.12 Preliminary Quebec Interconnection Support Agreement dated May 1,
1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2
dated June 1, 1982, Amendment No. 3 dated November 1, 1982, 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).
10.1.13 Agreement with Respect to Use of Quebec Interconnection dated
December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment
No. 2 dated November 1, 1982 among certain NEPOOL utilities (Ex-
hibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.13.1 Amendatory Agreement No. 3 to 10.1.13 as amended June 1, 1990,
among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q
(September 1990), File No. 2-30057).
10.1.14 Phase I New Hampshire Transmission Line Support Agreement between
NEET and certain other New England Utilities dated December 1,
1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.15 Agreement, dated September 1, 1985, with Respect To Amendment of
Agreement With Respect To Use Of Quebec Interconnection, dated
December 1, 1981, among certain NEPOOL utilities to include Phase
II facilities in the definition of "Project" (Exhibit 1 to the CEC
Form 10-Q (September 1985), File No. 2-30057).
10.1.16 Preliminary Quebec Interconnection Support Agreement - Phase II
among certain New England electric utilities dated June 1, 1984
(Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.1 First, Second and Third Amendments to 10.1.16 as amended March 1,
1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1
to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.16.2 Fifth, Sixth and Seventh Amendments to 10.1.16 as amended October
15, 1987, December 15, 1987 and March 1, 1988, respectively (Ex-
hibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.16.3 Fourth and Eighth Amendments to 10.1.16 as amended July 1, 1987
and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.16.4 Ninth and Tenth Amendments to 10.1.16 as amended November 1, 1988
and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form
10-K, File No. 2-30057).
10.1.16.5 Eleventh Amendment to 10.1.16 as amended November 1, 1989 (Exhibit
4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.16.6 Twelfth Amendment to 10.1.16 as amended April 1, 1990 (Exhibit 1
to the CEC Form 10-Q (June 1990), File No. 2-30057).
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COMMONWEALTH ELECTRIC COMPANY
10.1.17 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).
10.1.18 Phase II Massachusetts Transmission Facilities Support Agreement
dated June 1, 1985, refiled as a single agreement incorporating
Amendments 1 through 7 dated May 1, 1986 through January 1, 1989,
respectively, between New England Hydro and certain NEPOOL utili-
ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2-
30057).
10.1.19 Phase II New Hampshire Transmission Facilities Support Agreement
dated June 1, 1985, refiled as a single agreement incorporating
Amendments 1 through 8 dated May 1, 1986 through January 1, 1990,
respectively, between New England Hydro-Transmission Corporation
(New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to
the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.20 Phase II Equity Funding Agreement for New Hampshire Hydro, dated
June 1, 1985, between New Hampshire Hydro and certain NEPOOL util-
ities (Ex. 3 to the CEC Form 10-Q (Sept. 1985), File No. 2-30057).
10.1.20.1 Amendment No. 1 to 10.1.20 dated May 1, 1986 (Exhibit 6 to the CEC
Form 10-Q (March 1987), File No. 2-30057).
10.1.20.2 Amendment No. 2 to 10.1.20 as amended September 1, 1987 (Exhibit 3
to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.21 Phase II New England Power AC Facilities Support Agreement, dated
June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6
to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.21.1 Amendments Nos. 1 and 2 to 10.1.21 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.21.2 Amendments Nos. 3 and 4 to 10.1.21 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.22 Phase II Boston Edison AC Facilities Support Agreement, dated June
1, 1985, between BECO and certain NEPOOL utilities (Exhibit 7 to
the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.22.1 Amendments Nos. 1 and 2 to 10.1.22 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.22.2 Amendments Nos. 3 and 4 to 10.1.22 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
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COMMONWEALTH ELECTRIC COMPANY
10.1.23 Agreement Authorizing Execution of Phase II Firm Energy Contract,
dated September 1, 1985, among certain NEPOOL utilities in regard
to participation in the purchase of power from Hydro-Quebec (Ex-
hibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Agreements by and between Swift River Company and CE for the
purchase of available hydro-electric energy to be produced by
units located in Chicopee and North Willbraham, Massachusetts,
both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984
Form 10-K, File No. 2-7749).
10.1.24.1 Transmission Service Agreement between Northeast Utilities' 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).
10.1.24.2 Transformation Agreement between WMECO and CE whereby WMECO is to
transform power to CE from the Chicopee Units, dated December 1,
1984 (Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.25 Power Purchase Agreement by and between SEMASS Partnership, as
seller, to construct, operate and own a solid waste disposal
facility at its site in Rochester, Massachusetts and CE, as buyer
of electric energy and capacity, dated September 8, 1981 (Exhibit
17 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.25.1 Power Sales Agreement to 10.1.25 for all capacity and related
energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985
Form 10-K, File No. 2-7749).
10.1.25.2 Amendment to 10.1.25 for all additional electric capacity and
related energy to be produced by an addition to the Original Unit,
dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990),
File No. 2-7749).
10.1.25.3 Second Amendment to 10.1.25.2 for all additional electric capacity
and related energy to be produced by an addition to the Original
Unit, dated May 24, 1991 (Exhibit 1 to the CE Form 10-Q (June
1991), File No. 2-7749).
10.1.26 Power Sale Agreement by and between CE (buyer) and Northeast
Energy Associates, Ltd. (NEA) (seller) of electric energy and
capacity, dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q
(March 1987), File No. 2-7749).
10.1.26.1 First Amendment to 10.1.26 as amended August 15, 1988 (Exhibit 1
to the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.26.2 Second Amendment to 10.1.26 as amended January 1, 1989 (Exhibit 2
to the CE 1988 Form 10-K, File No. 2-7749).
10.1.26.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for
the purchase of 21 MW of electricity (Exhibit 2 to the CE Form
10-Q (September 1988), File No. 2-7749).
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COMMONWEALTH ELECTRIC COMPANY
10.1.26.4 Amendment to 10.1.26.3 as amended January 1, 1989 (Exhibit 3 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.27 Power Purchase Agreement and First Amendment, dated September 5,
1989 and August 3, 1990, respectively, by and between CE (buyer)
and Dartmouth Power Associates Limited Partnership (seller),
whereby buyer will purchase all of the energy (67.6 MW) produced
by a single gas turbine unit (Exhibit 1 to the CE Form 10-Q (June
1992), File No. 2-7749).
10.1.27.1 Second Amendment, dated June 23, 1994, to 10.1.27 (Exhibit 4 to
the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.28 Power Purchase Agreement by and between Masspower (seller)
and the Company (buyer) for a 11.11% entitlement to the electric
capacity and related energy of a 240 MW gas-fired cogeneration
facility, dated February 14, 1992 (Exhibit 1 to the CE Form 10-Q
(September 1993), File No. 2-7749).
10.1.29 Power Sale Agreement by and between Altresco Pittsfield, L.P.
(seller) and the Company (buyer) for a 17.2% entitlement to the
electric capacity and related energy of a 160 MW gas-fired cogen-
eration facility, dated February 20, 1992 (Exhibit 2 to the CE
Form 10-Q (September 1993), File No. 2-7749).
10.1.29.1 System Exchange Agreement by and among Altresco Pittsfield, L.P.,
CEL, the Company and New England Power Company, dated July 2, 1993
(Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.29.2 First Amendment, dated November 7, 1994, to 10.1.29 by and between
the Company and Altresco Pittsfield, L.P. dated February 20, 1992
10.2 Other agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993
(Exhibit 1 to the CES Form 10-Q (Sept. 1993), File No. 1-7316).
10.2.2 Employees Savings Plan of Commonwealth Energy System and 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).
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COMMONWEALTH ELECTRIC COMPANY
10.2.2.4 Fourth Amendment to the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies, as amended and restated as
of January 1, 1993, effective January 1, 1998. (Exhibit 1 to CES
Form 10-K/A Amendment No. 1 (April 29, 1998), File No. 1-7316).
10.2.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971
as amended through August 1, 1977, between NEGEA Service 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).
10.2.3.10 Twenty-eighth Agreement to 10.2.3 as amended September 15, 1992
(Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-
7316).
10.2.3.11 Twenty-ninth Agreement to 10.2.3 as amended May 1, 1993 (Exhibit 2
to the CES Form 10-Q (September 1994), File No. 1-7316).
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
December 31, 1998.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 1 is the Financial Data Schedule for the
twelve months ended December 31, 1998.
<PAGE>
<PAGE 52>
SCHEDULE I
COMMONWEALTH ELECTRIC COMPANY
INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED
FROM RELATED PARTIES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
(Dollars in thousands)
Name of Issuer and
Description of Investment
Common Stock - Yankee Atomic Electric Company
Balance, December 31, 1995
Number of Shares: 3,835
Amount $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
1998
Add: Equity in Earnings 141
Less: Dividends Received 175
Balance, December 31, 1998 $485
There were no changes in the number of shares held during the years 1996, 1997
or 1998.
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 53>
SCHEDULE II
COMMONWEALTH ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 and 1996
(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, 1998
$2,044 $ 917 $638 $2,530 $1,069
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
<PAGE>
<PAGE 54>
COMMONWEALTH ELECTRIC COMPANY
FORM 10-K DECEMBER 31, 1998
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: R. D. WRIGHT
Russell D. Wright,
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Principal Executive Officers:
R. D. WRIGHT March 31, 1999
Russell D. Wright
Chairman of the Board and
Chief Executive Officer
DEBORAH A. MCLAUGHLIN March 31, 1999
Deborah A. McLaughlin,
President and Chief Operating Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 31, 1999
James D. Rappoli,
Financial Vice President and Treasurer
A majority of the Board of Directors:
R. D. WRIGHT March 31, 1999
Russell D. Wright, Director
DEBORAH A. MCLAUGHLIN March 31, 1999
Deborah A. McLaughlin, Director
JAMES D. RAPPOLI March 31, 1999
James D. Rappoli, 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, 1998 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-31-1998
<PERIOD-END> DEC-31-1998
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 386,676
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<TOTAL-DEFERRED-CHARGES> 134,351
<OTHER-ASSETS> 184,343
<TOTAL-ASSETS> 769,355
<COMMON> 51,099
<CAPITAL-SURPLUS-PAID-IN> 97,112
<RETAINED-EARNINGS> 36,984
<TOTAL-COMMON-STOCKHOLDERS-EQ> 185,195
0
0
<LONG-TERM-DEBT-NET> 143,651
<SHORT-TERM-NOTES> 40,350
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<TOTAL-OPERATING-EXPENSES> 393,651
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<NET-INCOME> 15,109
0
<EARNINGS-AVAILABLE-FOR-COMM> 15,109
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