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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K/A
Amendment No. 2
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 1-7316
COMMONWEALTH ENERGY SYSTEM
(Exact name of registrant as specified in its Declaration of Trust)
Massachusetts 04-1662010
(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
Common Shares of Beneficial New York Stock Exchange, Inc.
Interest $2 par value Pacific Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [ x ]
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 [ ]
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 16, 1998: $801,039,203
Common Shares outstanding at March 16, 1999: 21,540,550 shares
Document Incorporated by Reference Part in Form 10-K
None Not applicable
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COMMONWEALTH ENERGY SYSTEM
Item 1. Business
General
Commonwealth Energy System, a Massachusetts trust, is an unincorporated
business organization with transferable shares. It is organized under a
Declaration of Trust dated December 31, 1926, as amended, pursuant to the laws
of Massachusetts. It is an exempt public utility holding company under the
provisions of the Public Utility Holding Company Act of 1935, holding all of
the stock of four operating public utility companies. Commonwealth Energy
System, the parent company, is referred to in this report as the "Parent" and,
together with its subsidiaries, is collectively referred to as "COM/Energy."
The operating utility subsidiaries of the Parent have been engaged in the
generation, transmission and distribution of electricity and the dis-tribution
of natural gas, all within Massachusetts. These subsidiaries are:
Electric Gas
Cambridge Electric Light Company Commonwealth Gas Company
Canal Electric Company
Commonwealth Electric Company
In addition to the utility companies, the Parent also owns all of the
stock of a company that operates a total energy plant serving the Longwood
Medical Area of Boston (Advanced Energy Systems, Inc.), a steam distribution
company (COM/Energy Steam Company), a liquefied natural gas (LNG) and
vaporization facility (Hopkinton LNG Corp.), a subsidiary that is pursuing
energy-related business opportunities (COM/Energy Technologies, Inc.), and
five real estate trusts. An energy marketing subsidiary, COM/Energy
Marketing, Inc., sold its assets to Reliant Energy in February 1999.
Subsidiaries of the Parent receive technical assistance as well as financial,
data processing, accounting, legal and other services from a wholly-owned
services company subsidiary (COM/Energy Services Company).
The five real estate subsidiaries are: Darvel Realty Trust, which is a
joint-owner of the Riverfront Office Park complex in Cambridge; COM/Energy
Acushnet Realty, which leases land to Hopkinton LNG Corp. (Hopkinton);
COM/Energy Research Park Realty, which was organized to develop a research
building in Cambridge; COM/Energy Cambridge Realty, which was organized to
hold various properties; and COM/Energy Freetown Realty (Freetown), which
holds 596 acres of land in Freetown, Massachusetts.
Each of the operating utility subsidiaries serves retail customers
except for Canal Electric Company (Canal Electric). Canal Electric operated
an electric generating station located in Sandwich, Massachusetts until
December 30, 1998 when it was sold pursuant to COM/Energy's electric industry
restructuring plan that was approved by the Massachusetts Department of
Telecommunications and Energy (DTE) and is consistent with the Electric
Industry Restructuring Act passed by the Massachusetts legislature in 1997.
The station consisted of Canal Unit 1, an oil-fired steam electric generating
unit that was wholly-owned by Canal Electric with a rated capacity of 569
megawatts (MW), and Canal Unit 2, a steam electric generating unit with dual-
fuel capability (oil and natural gas) that was jointly-owned by Canal Electric
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COMMONWEALTH ENERGY SYSTEM
and Montaup Electric Company (Montaup) (an unaffiliated company) with a rated
capacity of 580 MW. Canal Unit 2 was operated under an agreement with Montaup
which provides for the equal sharing of output, fixed charges and operating
expenses.
Electric service is furnished by Cambridge Electric Light Company (Cam-
bridge Electric) and Commonwealth Electric Company (Commonwealth Electric) at
retail to approximately 327,000 year-round and 45,500 seasonal customers in 41
communities in eastern and southeastern Massachusetts covering 1,112 square
miles and having an aggregate population of 645,000. The territory served
includes the communities of Cambridge, New Bedford and Plymouth and the
geographic area comprising Cape Cod and Martha's Vineyard. Cambridge Electric
also sells power at wholesale to the Town of Belmont, Massachusetts.
Natural gas is distributed by Commonwealth Gas Company (Commonwealth
Gas) to approximately 239,000 customers in 51 communities in central and
eastern Massachusetts covering 1,067 square miles and having an aggregate
population of 1,128,000. Twelve of these communities are also served by
Cambridge Electric or Commonwealth Electric with electricity. Some of the
larger communities served by Commonwealth Gas include Cambridge, Somerville,
New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of
Boston.
Advanced Energy Systems, Inc.'s principal assets include a total energy
plant (MATEP) and related contracts that were acquired on June 1, 1998 from
Harvard University. MATEP provides steam, electricity and chilled water
services to several hospitals and professional schools in the Longwood Medical
Area of Boston under long-term contracts that will remain in place until at
least September 2015. Its major customers are Brigham and Women's Hospital,
Beth Israel Deaconess Hospital, Dana-Farber Cancer Institute, the Joslin
Diabetes Center, Children's Hospital and Harvard's medical, dental and public
health schools. For additional information concerning MATEP, refer to Note
3(e) of Notes to Consolidated Financial Statements filed under Item 8 of this
report.
Steam, which was produced by Cambridge Electric in connection with the
generation of electricity, was purchased by COM/Energy Steam and, together
with its own production, is distributed to 19 customers in Cambridge and two
customers (including Massachusetts General Hospital) in Boston. Steam is used
for space heating and other purposes.
Industry in the territories served by COM/Energy companies is highly
diversified. The larger industrial customers include high-technology firms
and manufacturers of such products as photographic equipment and supplies,
computer diskettes, rubber products, textiles, wire and other fastening
devices, abrasives and grinding wheels, candy, copper and alloys, and
chemicals.
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
NSTAR, 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
conditions, including receipt of certain regulatory approvals. The regulatory
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COMMONWEALTH ENERGY SYSTEM
approval process is expected to be completed during the second half of 1999.
Electric Power Supply
On May 27, 1998, COM/Energy agreed to sell substantially all of its non-
nuclear generating assets (984 MW) to affiliates of The Southern Company of
Atlanta, Georgia. The sale was conducted through an auction process that was
outlined in a restructuring plan filed with the DTE in November 1997 in
conjunction with the state's industry restructuring legislation enacted in
1997. The sale was approved by the DTE on October 30, 1998 and by the FERC on
November 12, 1998. Proceeds from the sale of these assets, after
construction-related adjustments at the closing that occurred on December 30,
1998, amounted to approximately $453.9 million or 6.1 times their book value
of approximately $74.2 million. The proceeds from the sale, net of book
value, transaction costs and certain other adjustments, amounted to $358.6
million and will be used to reduce transition costs related to electric
industry restructuring that otherwise would have been collected through a non-
bypassable transition charge.
Prior to December 30, 1998, COM/Energy owned generating facilities with
a net capability at the time of peak load (1,004.7 MW on July 23, 1998)
totaling 1,010.6 MW including 559.2 MW provided by Canal Electric Unit 1, of
which three-quarters (419.4 MW) was sold to neighboring utilities under long-
term contracts, and 275.7 MW was provided by Canal Unit 2. Another 126.1 MW
was provided by various smaller units. Of the 541.6 MW available to
COM/Energy, 63.1 MW was used principally for peaking purposes. Central Maine
Power Company's Wyman Unit 4, an oil-fired facility in which COM/Energy had a
1.4% joint-ownership interest, provided 8.8 MW.
A 3.52% ownership interest in the Seabrook 1 nuclear power plant
provides 40.9 MW of capability to COM/Energy. In addition, through Canal
Electric's equity ownership in Hydro-Quebec Phase II, COM/Energy has an
entitlement of 67.8 MW. Purchase power arrangements were also in place with
four natural gas-fired cogenerating units in Massachusetts totaling 204.7 MW.
COM/Energy also receives 67 MW from a waste-to-energy plant and has
entitlements totaling 23.4 MW through contracts with four hydroelectric sup-
pliers.
To satisfy demand requirements and provide required reserve capacity,
COM/Energy supplemented its generating capacity by purchasing power on a long
and short-term basis through capacity entitlements under power contracts with
other New England and Canadian utilities and with Qualifying Facilities and
other non-utility generators through a competitive bidding process that is
regulated by the DTE.
Pursuant to a restructured Power Sale Agreement (PSA), effective January
1, 1995, a non-utility generator (NUG) ceased supplying capacity and energy to
Commonwealth Electric. The restructured PSA defers Commonwealth Electric's
obligation to purchase the NUG's capacity and energy for a maximum of six
years.
COM/Energy also has available 84.8 MW from two operating nuclear units
in which its distribution companies have life-of-the-unit contracts for power.
Information with respect to these units is as follows:
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COMMONWEALTH ENERGY SYSTEM
Vermont
Yankee Pilgrim
Year of Initial Operation 1972 1972
Contract Expiration Date 2012 2004
Equity Ownership (%) 2.50 -
Plant Entitlement (%) 2.25 11.0
Plant Capability (MW) 531.0 668.9
COM/Energy Entitlement (MW) 11.2 73.6
Commonwealth Electric has an 11% contract entitlement in the output of
the Pilgrim nuclear power plant, which is expected to be sold by Boston Edison
Company (Boston Edison) in 1999 to Entergy Nuclear Generating Company
(Entergy). In conjunction with this sale, Commonwealth Electric has reached
an agreement with Boston Edison to buy out of this life-of-the-unit contract,
terminating Commonwealth Electric's rights and obligations under the contract
regarding the power output of the plant. Pursuant to the buy out agreement,
Commonwealth Electric will pay between $100 million and $115 million to
terminate this contract with Boston Edison, subject to adjustment at closing.
The buy out is expected to be completed in the second quarter of 1999. In a
transaction related to the sale of the Pilgrim plant, Commonwealth Electric
will buy power generated by the Pilgrim plant from Entergy on a declining
basis through 2004. Cambridge Electric has a 2.5% equity ownership in the
Vermont Yankee nuclear power plant. Vermont Yankee has granted AmerGen Energy
Co. an exclusive right to negotiate an agreement to buy the plant.
Information relative to nuclear units that are no longer operating in
which COM/Energy has an equity ownership is as follows:
Connecticut Maine Yankee
Yankee Yankee Atomic
(Dollars in thousands)
Year of Shutdown 1996 1997 1992
Equity Ownership (%) 4.50 4.00 4.50
Equity Ownership Balance $4,713 $3,476 $395
For additional information, refer to Note 3(d) of the Notes to Consolidated
Financial Statements filed under Item 8 of this report.
Cambridge Electric, Canal Electric and Commonwealth Electric, together
with other electric utility companies in the New England area, are members of
Independent System Operator (ISO) - New England (formerly the New England
Power Pool or 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 requirements. This
concept is accomplished by use of computers to monitor and forecast load
requirements.
ISO - New England, on behalf of its members entered into an
Interconnection Agreement with Hydro-Quebec, a Canadian utility operating in
the Province of Quebec. The agreement provided for construction of an
interconnection (referred to as the Hydro-Quebec Project-Phase I and Phase II)
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COMMONWEALTH ENERGY SYSTEM
between the electrical systems of New England and Quebec. The parties also
entered into an Energy Contract and an Energy Banking Agreement; the former
which obligated Hydro-Quebec to offer ISO - New England participants up to 33
million MWH of surplus energy during an eleven-year term that began September
1, 1986 has since expired, and the latter provided for energy transfers
between the two systems. ISO - New England also entered into Phase II
agreements for an additional purchase from Hydro-Quebec of 7 million MWH per
year for a twenty-five year period that began in late 1990.
Canal Electric is obligated to pay its share of operating and capital
costs for Phase II over a 25 year period ending in 2015. Future minimum lease
payments for Phase II have an estimated present value of $11.1 million at
December 31, 1998. In addition, Canal has an equity interest in Phase II
which amounted to $2.8 million in 1998 and $3.1 million in 1997.
COM/Energy's 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 the NPCC. COM/Energy estimates that,
during the next ten years, reserve requirements so determined will be
approximately 20% of peak load.
Power Supply Commitments and Support Agreements
Cambridge Electric and Commonwealth Electric, through Canal Electric,
secure cost savings for their respective customers by planning for bulk power
supply on a single system basis. Additionally, Cambridge Electric and
Commonwealth Electric have long-term contracts for the purchase of electricity
from various sources. 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. For additional information concerning
commitments under long-term power contracts, refer to Note 3(d) of Notes to
Consolidated Financial Statements filed under Item 8 of this report.
COM/Energy's 3.52% interest in the Seabrook nuclear power plant is
owned by Canal Electric to provide for a portion of the capacity and energy
needs of Cambridge Electric and Commonwealth Electric. For additional
information concerning Seabrook 1, refer to Note 3(b) of Notes to Consolidated
Financial Statements filed under Item 8 of this report.
Commonwealth Electric and Cambridge Electric continue to evaluate bids
related to capacity entitlements associated with power contracts in response
to electric industry restructuring legislation enacted in Massachusetts in
November 1997.
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COMMONWEALTH ENERGY SYSTEM
Electric Fuel Supply
(a) Oil and Natural Gas
Of COM/Energy's total energy requirement for 1998, approximately 48%
was generated using imported residual oil and approximately 30% was generated
using natural gas.
Effective March 15, 1998, Canal Electric executed a one-year contract
with Coastal Refining and Marketing, Inc. (Coastal) for the purchase of 1%
sulfur residual fuel oil. The contract provided for delivery of a set
percentage of Canal Electric's fuel requirement, the balance (a maximum of
50%) to be met by spot purchases or by Coastal at the discretion of Canal
Electric.
Energy Supply & Credit Corporation (ESCO Massachusetts, Inc.) operated
Canal's fuel oil terminal and managed the receipt of and payment for fuel oil
under assignment of Canal Electric's supply contracts to ESCO Massachusetts,
Inc. Residual fuel oil in the terminal's shore tanks was held in inventory by
ESCO Massachusetts, Inc. and delivered upon demand to Canal Electric's two day
tanks.
During 1996, Unit 2 was converted to dual-fuel capability, residual
fuel oil and natural gas. Canal Electric anticipated that dual-fuel
capability would result in future savings as the least expensive fuel was
utilized.
(b) Nuclear Fuel Supply and Disposal
Approximately 13% of COM/Energy's total energy requirement for 1998 was
generated by nuclear plants. The nuclear fuel contract and inventory
information for Seabrook 1 has been furnished to COM/Energy by North Atlantic
Energy Services Corporation (NAESCO), the managing agent responsible for
operation of the unit. Seabrook's requirement for nuclear fuel components are
100% covered through 2002 by existing contracts.
There are no spent fuel reprocessing or disposal facilities currently
operating in the United States. Instead, commercial nuclear electric gener-
ating units operating in the United States are required to retain spent fuel
on-site. As required by the Nuclear Waste Policy Act of 1982 (the Act), as
amended, the joint-owners entered into a contract with the Department of
Energy for the transportation and disposal of spent fuel and high level
radioactive waste at a national nuclear waste repository or Monitored
Retrievable Storage (MRS) facility. Owners or generators of spent nuclear
fuel or its associated wastes are required to bear the costs for such
transportation and disposal through payment of a fee of approximately 1
mill/KWH based on net electric generation to the Nuclear Waste Fund. Under
the Act, a storage or disposal facility for nuclear waste was anticipated to
be in operation by 1998; a reassessment of the project's schedule requires
extending the completion date of the permanent facility until at least 2010.
Seabrook 1 is currently licensed for enough on-site storage to accommodate
spent fuel expected to be accumulated through at least the year 2010.
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COMMONWEALTH ENERGY SYSTEM
Gas Supply
Commonwealth Gas purchases transportation, storage and balancing
services from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas
Transmission Company (and other upstream pipelines that bring gas from the
supply wells to the final transporting pipelines) and purchases all of its gas
supplies from third-party vendors, utilizing firm contracts with terms of less
than one year. The vendors vary from small independent marketers to major gas
and oil companies.
In addition to firm transportation and gas supplies mentioned above,
Commonwealth Gas utilizes contracts for underground storage and LNG facilities
to meet its winter peaking demands. The underground storage contracts are a
combination of existing and new agreements which are the result of Federal
Energy Regulatory Commission (FERC) Order 636 service unbundling. The LNG
facilities, described below, are used to liquefy and store pipeline gas during
the warmer months for use during the heating season.
Commonwealth Gas entered into a multi-party agreement in 1992 to assume
a portion of Boston Gas Company's contracts to purchase Canadian gas supplies
from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois
Gas Transmission System and Tennessee pipelines. The ANE gas supply contract
was filed with the DTE and hearings were completed in April 1993. The DTE
approved the ANE gas supply contract in November 1995. Commonwealth Gas is
presently in negotiations with the parties to allow for final execution of all
pertinent agreements and contracts.
Commonwealth Gas began transporting gas on its distribution system in
1990 for end-users. As of December 31, 1998, there were 593 customers using
this transportation service, accounting for 11,146 BBTU or approximately 24%
of total throughput.
Hopkinton LNG Facility
A portion of the gas supply for Commonwealth Gas during the heating
season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned
subsidiary of the Parent. The facility consists of a liquefaction and
vaporization plant and three above-ground cryogenic storage tanks having an
aggregate capacity of 3 million MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and two
above-ground cryogenic storage tanks located in Acushnet, Massachusetts with
an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG
trucked from Hopkinton.
Commonwealth Gas has contracts for LNG service with Hopkinton extending
on a year to year basis with notice of termination required five years in
advance of the anticipated termination date. Current contract payments
include a demand charge sufficient to cover Hopkinton's fixed charges and an
operating charge which covers liquefaction and vaporization expenses.
Commonwealth Gas furnishes pipeline gas during the period April 15 to November
15 each year for liquefaction and storage. As the need arises, LNG is
vaporized and placed in the distribution system of Commonwealth Gas.
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COMMONWEALTH ENERGY SYSTEM
Based upon information presently available regarding projected growth
in demand and estimates of availability of future supplies of pipeline gas,
Commonwealth Gas believes that its present sources of gas supply are adequate
to meet existing load and allow for future growth in sales.
Rates, Regulation and Legislation
Certain of COM/Energy's utility subsidiaries operate under the
jurisdiction of the DTE which regulates retail rates, accounting, issuance of
securities and other matters. In addition, Canal, Cambridge Electric and
Commonwealth Electric file their respective wholesale rates with the FERC.
Electric Industry
(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.
COM/Energy had 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 non-nuclear generation assets
and the entitlements associated with its purchased power contracts through an
auction process was an integral part of COM/Energy's restructuring plan and is
consistent with the Act. While COM/Energy is encouraged with the treatment
afforded transition costs (which, for COM/Energy, are primarily the result of
above-market purchased power contracts with NUGs that have not yet been sold)
by the legislation and the DTE, the mandated rate reduction has had a
significant impact on cash flows of COM/Energy. 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. (Southern Energy), 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. COM/Energy did not agree to retain any material
liabilities related to pre-closing occurrences. Southern Energy has assumed
all material future liabilities associated with the generating assets that
were sold. These facilities represented 984 megawatts (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 Electric; five diesel generators (13.8 MW) in Oak Bluffs and West
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COMMONWEALTH ENERGY SYSTEM
Tisbury on the island of Martha's Vineyard that are owned by Commonwealth
Electric, and a 1.4 percent joint-ownership interest (8.9 MW) in Wyman Unit
No. 4 located in Yarmouth, ME, also owned by Commonwealth Electric.
COM/Energy continues to evaluate bids related to its purchased power
contracts with NUGs. COM/Energy is also evaluating the disposition of the
Blackstone Station generating unit (15.3 MW) owned by Cambridge Electric and
located in Cambridge, MA that is subject to a right of first offer held by
Harvard University on any divestiture of the facility.
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 Cambridge
Electric and Commonwealth 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 Commonwealth Electric 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 Commonwealth
Electric has an 11% entitlement. 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
the sale of the generating assets to Southern Energy and further proposed
(subject to completion of the sale which occurred December 30, 1998) that the
10 percent rate reduction increase, effective January 1, 1999, to
approximately 12 percent for Commonwealth Electric and to approximately 16
percent for Cambridge Electric. In addition, the companies 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 Commonwealth Electric's customers declined from 4.08
cents per kwh to 3.159 cents and for Cambridge Electric's customers from 2.73
cents per kwh to 1.447 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 cost deferrals associated with the pricing of
standard offer service.
No gain was recorded on the sale of the generating assets on a consoli-
dated basis as COM/Energy is obligated to reduce Cambridge Electric's and
Commonwealth Electric's transition costs by the net proceeds of the sale.
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COMMONWEALTH ENERGY SYSTEM
(b) Unbundled Rates
As a result of electric industry restructuring, both Commonwealth
Electric and Cambridge Electric have unbundled their rates, provided customers
with a 10 percent rate reduction as of March 1, 1998 and have afforded custom-
ers 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
COM/Energy include optional standard offer service and default service.
Standard offer service is the electricity that is supplied by the local
distribution company (such as Cambridge Electric and Commonwealth Electric)
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 the electricity that 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. As of December 31, 1998,
approximately 90% of retail customers received standard offer service and
approximately 10% of retail customers received default service. No retail
customers received electricity supply services from competitive power
suppliers during 1998.
Prior to the implementation of industry restructuring on March 1, 1998,
Commonwealth Electric and Cambridge Electric had Fuel Charge rate schedules
that generally allowed for current recovery, from retail customers, of fuel
used in electric production, purchased power and transmission costs. These
schedules 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 schedules did not match actual costs for that period, an appropriate
adjustment was reflected in the calculation of the next subsequent calendar
quarter decimal. These rate schedules are no longer in effect.
Also prior to March 1, 1998, Cambridge Electric and Commonwealth Elec-
tric collected a portion of capacity-related purchased power costs associated
with certain long-term power arrangements 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. When current period capacity costs
and/or unit sales varied from test-period levels, Cambridge Electric and
Commonwealth Electric 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, Cambridge Electric and Commonwealth
Electric were allowed to defer these costs (within certain limits) which
neutralized their sometimes volatile effect on net income. Both companies
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COMMONWEALTH ENERGY SYSTEM
also had separately stated Conservation Charge rate schedules that allowed for
current recovery, from retail customers, of conservation and load management
costs. These rate schedules are no longer in effect.
(c) Retail Choice Pilot Program
Prior to March 1, 1998, the date retail choice was available for all
customers, Commonwealth Electric had designed a program to allow a limited
number of customers the opportunity to possibly reduce their electric bills
while Commonwealth Electric learned more about real-time pricing and the
administrative requirements associated with open-market competition. Through
the program, Commonwealth Electric 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 18 commercial and industrial customers
of Commonwealth Electric that took service under one of Commonwealth
Electric's economic development rates. This program was discontinued on
February 28, 1998.
(d) Customer Transition Charge
In September 1995, the DTE issued a ruling largely approving four rate
tariffs, including a Customer Transition Charge (CTC), that were filed by
Cambridge Electric on March 15, 1995. The CTC was intended to protect
remaining customers from paying certain stranded costs that were incurred in
the event that Cambridge Electric's largest customers discontinued full
service, yet still remain connected for back-up and other services. These
costs included long-term power contracts entered into to meet projected energy
requirements, investments in substations, underground and overhead lines and
current and future decommissioning costs associated with nuclear plants. This
ruling is believed to be the first retail stranded cost charge approved
nationally and follows the DTE's initial restructuring order which endorsed,
in principle, the recovery of stranded costs.
Through the CTC, Cambridge Electric recovered 75% of net stranded costs
as calculated in its proposal. Cambridge Electric's other rates include a
Supplemental Service Rate, a Standby Service Rate and a Maintenance Service
Rate each of which were approved with only minor changes.
Cambridge Electric was an intervenor in an appeal at the Massachusetts
Supreme Judicial Court (SJC) filed by the Massachusetts Institute of
Technology (MIT) involving this DTE decision approving the CTC for the
recovery of stranded investment costs. By its terms, the CTC was terminated
on March 1, 1998, coincident with the retail access date established by the
Massachusetts Legislature in the Electric Industry Restructuring Act. On
September 18, 1997, the SJC remanded the CTC matter to the DTE for further
consideration. The SJC stated that, although recovery of prudent and
verifiable stranded costs by utility companies is in the public interest and
consistent with the Public Utility Regulatory Policies Act, the
insufficiencies of the DTE's subsidiary findings precluded the SJC from
undertaking a meaningful review of the DTE's calculations that formed the
basis of the CTC. The DTE is in the process of determining whether to hear
additional evidence in the remand or to rely on the record and pleadings
already filed.
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COMMONWEALTH ENERGY SYSTEM
(e) Wholesale Rate Proceedings
The Town of Belmont Massachusetts Municipal Light Department (Belmont)
is a municipally-owned utility that provides electric service to approximately
25,000 residential customers as well as commercial customers. Belmont
purchases approximately 80 percent of its electric requirements from Cambridge
Electric under a Net Requirements Power Supply Agreement (NRA). The balance
of its electric requirements are currently purchased from the New York Power
Authority (NYPA) and Boston Edison Company and transmitted to Belmont under a
Transmission Services Agreement with Cambridge Electric. Belmont provides
approximately 1% of consolidated electric revenue.
Net Requirements Power Supply Agreement
Cambridge Electric has provided electric service to Belmont for nearly
a century. Historically, Belmont was a full-requirements customer of
Cambridge Electric, purchasing a "bundled" power supply and transmission
service. In 1985, however, when Belmont received an allocation of
approximately two megawatts of low-cost "preference" power from NYPA,
Cambridge Electric agreed to provide transmission service for Belmont's NYPA
power under its firm transmission tariff, and to provide "bundled" power
supply and transmission service for the remainder of Belmont's power needs
under a "partial requirements" tariff.
On March 8, 1993, Cambridge Electric filed, with the concurrence of
Belmont, the NRA which was approved by FERC's June 18, 1993 letter order.
Prior to approving the NRA however, FERC Staff advised Cambridge
Electric that the cost-of-service formula in the NRA needed to be clarified
and that Cambridge Electric should file such clarification at least sixty days
prior to the April 1, 1998 date upon which the formula rate would become
applicable under the NRA. In compliance with this requirement, on January 21,
1998, Cambridge Electric submitted a supplemental filing containing the
clarification to the formula rate set forth in the NRA. On February 19, 1998,
Belmont filed with the FERC a protest claiming that Cambridge Electric's
November 1997 announcement of its intention to leave the power supply business
would have profound implications for Belmont as they were served from
Cambridge Electric's general mix of electric power and that the divestiture
will result in unjust and unreasonable charges.
On March 30, 1998, the FERC issued its order approving Cambridge
Electric's filing to become effective April 1, 1998 subject to the outcome of
the pending proceeding.
On April 29, 1998 Belmont filed a request for rehearing alleging the
FERC erred in its March 30 Order by accepting Cambridge Electric's proposed
modifications to the NRA without hearing or suspension, and without requiring
that Cambridge Electric explain the basis for its deletion of certain
protective standards. On May 29, 1998, the FERC issued its order denying
rehearing.
Subsequently, Cambridge Electric and Belmont entered into negotiations
to settle certain outstanding issues. An amendment to the NRA has been signed
by both parties and a joint offer of settlement (Joint Offer) was filed
January 15, 1999. Material terms of the settlement include: (i) a new fixed
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COMMONWEALTH ENERGY SYSTEM
monthly Customer Charge and an Energy Charge that varies by calendar year to
replace the existing rates and charges section of the NRA; (ii) resolution of
a billing reconciliation issue under the NRA; (iii) satisfaction of the "hold
harmless" commitment Cambridge Electric made to Belmont in the divestiture
proceeding related to the sale of its generating assets; and (iv) a
termination date of March 31, 2003. Cambridge Electric awaits FERC action on
the Joint Offer.
Transmission Services Agreement
Cambridge Electric and Belmont entered into discussions in early 1993
to negotiate a transmission services agreement (TSA). However, there were
significant differences between the parties and final negotiations were held
in late February 1994.
As Cambridge Electric and Belmont were unable to agree on the terms of
a TSA, Cambridge Electric filed a proposed TSA with the FERC on June 29, 1994.
Belmont intervened in the proceeding. The FERC set the TSA for hearing to
determine whether or not it was consistent with a previous memorandum of
understanding (MOU) and whether the transmission rates were just and
reasonable. Cambridge Electric and Belmont settled on the rate of return
before hearings started.
After the hearing and filing of initial and reply briefs, on September
14, 1995, the presiding administrative law judge (ALJ) issued an initial
decision.
The ALJ found that: (i) the proposed transmission agreement rates were
not just and reasonable and directed Cambridge Electric to revise the rates
based on directly assigned facilities and further that use rights should be
based on the same direct assigned facilities; (ii) the proposed transmission
agreement, revised in accordance with the findings made in the decision, are
consistent with the parties' MOU and; (iii) that Cambridge Electric's pre-
existing firm transmission tariff rate is just and reasonable.
On October 16, 1995, Belmont filed a motion for expedited review and
issuance of decision. On July 2, 1998, Belmont renewed its motion for
issuance of a decision. On July 20, 1998, the FERC issued its opinion and
order and affirmed certain parts and reversed other parts of the initial
decision.
On August 19, 1998, both Cambridge Electric and Belmont filed requests
for rehearing of the July 20, 1998 order each citing issues on which they felt
the FERC had erred.
On November 4, 1998, the FERC issued its opinion and order by granting
a rehearing for certain issues and denying a rehearing for others.
In the order on rehearing the FERC granted Cambridge Electric's
rehearing request on the limited rate issue regarding the method for
allocating operating and maintenance costs. The rehearing order resulted in
Cambridge Electric being able to increase its transmission rate to Belmont.
In addition to Cambridge Electric receiving increased transmission revenues in
the future, the decision substantially reduced Cambridge Electric's refund
obligation to Belmont. The FERC's rehearing order denied all of Belmont's
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COMMONWEALTH ENERGY SYSTEM
rehearing requests including when Belmont has the ability to purchase rights-
of-use from Cambridge Electric.
The Order obligated Cambridge Electric to make a compliance filing to
include the necessary revisions to the TSA. Once the FERC approved and
accepted the compliance filing, Cambridge Electric would have 30 days to make
refunds to Belmont, with interest, back to the refund effective date of
January 29, 1995.
On December 4, 1998, Cambridge Electric made its compliance filing. On
December 28, 1998, Belmont filed its protest claiming Cambridge Electric's
compliance filing contains proposed revisions to the TSA which were not
directed by the FERC and therefore should be rejected.
On January 4, 1999, Belmont filed with the United States Court of
Appeals for the District of Columbia Circuit a petition for review of the July
20, 1998 and November 4, 1998 FERC orders.
On January 12, 1999, Cambridge Electric filed its response to Belmont's
December 28, 1998 protest. Cambridge Electric awaits FERC action on Belmont's
protest.
The uncontested material terms of the TSA provide that Cambridge
Electric will offer both firm and non-firm transmission service over a defined
contract period on its system to Belmont. Cambridge Electric will charge
Belmont a FERC-approved rate for these services. Belmont also has the option
to purchase rights-of-use under the TSA. The charges for these rights-of-use
will be determined through the application of a FERC-approved methodology.
Belmont is also responsible for monthly operation and maintenance expenses
with respect to these rights-of-use. Billing under the TSA will occur
monthly. The initial term of the TSA is through March 31, 2007. Belmont may
terminate within this initial term upon three-years' notice. The initial term
may be extended for up to five years if Belmont exercises its right to
purchase rights-of-use over Cambridge Electric's system on or after April 1,
2003. Upon three-years' notice either party shall have the right to terminate
the TSA after expiration of the initial term.
The only remaining contested provisions of the TSA are those provisions
at issue in a pending appeal filed by Belmont on January 4, 1999 before the
United States Court of Appeals for the D.C. Circuit and those at issue in a
pending request for rehearing filed by Cambridge Electric before the FERC.
Belmont's appeal to the Court of Appeals for the D.C. Circuit involves the
FERC's ruling that Cambridge Electric has the right to terminate any rights-
of-use purchased by Belmont on three-years' notice. The FERC held that
Cambridge Electric has the right to terminate the TSA, and with it the rights-
of-use, on three-years' notice, finding that any rights-of-use purchased by
Belmont are not property rights of Belmont. This appeal has not yet reached
the briefing stage. Cambridge Electric has requested rehearing by the FERC of
its decision that certain operating and maintenance expenses associated with a
particular plant may not be directly assigned to Belmont but instead must be
allocated using a plant ratio methodology. Different assignment methodologies
result in different rates charged to Belmont. The request for rehearing is
currently pending.
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COMMONWEALTH ENERGY SYSTEM
(f) Transmission Rate Matters
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
marketplace and to bring more efficient, lower-cost power to electric
consumers. On March 29, 1996, Cambridge Electric filed transmission tariffs
that implemented the FERC's requirements for non-discriminatory open access
transmission for both point-to-point and network service. The tariffs were
accepted on May 17, 1996 to be effective on May 28, 1996, but the rates are
subject to an investigation initiated by the FERC itself. A settlement with
the FERC regarding this investigation was filed on February 6, 1997.
On April 24, 1996, the FERC issued Order No. 888, a set of three inter-
related 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, Cambridge Electric and Commonwealth Electric 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 these tariffs effective July 9, 1996, subject
to a revision of one section dealing with the scheduling of services.
On January 21, 1997, Cambridge Electric and Commonwealth Electric filed
revised OATTs to be consistent with the 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. Cambridge Electric and
Commonwealth Electric filed their 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 July 31, 1998, Cambridge Electric filed a Settlement Agreement with
FERC regarding the outstanding proceeding referred to in the Order. On
September 31, 1998, following the filing of ISO - New England's revised OATT,
Cambridge Electric and Commonwealth Electric filed revised OATTs for
consistency with ISO - New England. On January 28, 1999. FERC approved the
July 31, 1998 Settlement Agreement which applied to Cambridge Electric's July
9, 1996 OATT.
Currently, Cambridge Electric and Commonwealth Electric are awaiting
decisions by FERC on the OATTs filed after 1996.
Gas Industry
(a) Industry Restructuring
Commonwealth Gas and eight other gas utilities initiated the Massachu-
setts Gas Unbundling Collaborative (the Collaborative) on September 15, 1997,
to explore and develop generic principles to achieve the goals set forth by
the DTE. Collaborative participants represented a broad array of stakeholder
interests including the utilities, natural gas marketers, interstate pipe-
lines, producers, energy consultants, labor unions, consumer advocates and
representatives for the DTE, the Massachusetts Attorney General's Office, and
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COMMONWEALTH ENERGY SYSTEM
the Massachusetts Division of Energy Resources.
On March 18, 1998, the Collaborative filed a report to the DTE that
summarized its progress. The Collaborative reported that it had made substan-
tial progress in the areas of rate unbundling and terms and conditions for
unbundled services. The report also described at least two policy issues,
capacity disposition and cost responsibility, on which the Collaborative's
participants require specific regulatory guidance before completing a compre-
hensive framework for the transition to a more competitive market structure.
In response to this report, the DTE issued a Notice of Inquiry (NOI) to
address the Collaborative's unresolved issues. On May 1, 1998, Commonwealth
Gas filed initial written comments in the proceeding arguing in favor of a
mandatory capacity assignment proposal. On June 8, 1998, the DTE, as part of
the aforementioned NOI, received final comments regarding the feasibility of
implementing comprehensive unbundling for all local distribution companies
(LDCs) by November 1, 1998. On June 29, 1998, Commonwealth Gas and three
other Massachusetts LDCs submitted unbundled rate settlements to the DTE for
consideration.
The DTE issued a procedural order regarding the NOI on July 2, 1998
which stated that the introduction of comprehensive unbundling for all classes
of customers for all LDCs is not feasible by November 1, 1998. The DTE stated
that unbundled rates for the four LDCs that filed settlements on June 29, 1998
(including Commonwealth Gas) shall be in place by November 1, 1998 and that
comprehensive unbundling shall be implemented no later than April 1, 1999.
Also, as part of the July 2, 1998 procedural order, the DTE ordered that a set
of proposed Model Terms and Conditions be submitted by the Collaborative no
later than July 15, 1998. A partial set of Model Terms and Conditions were
submitted on July 10, 1998 that excluded provisions for capacity assignment as
well as those related sections of the terms and conditions that required
further development by the Collaborative once the issues being addressed in
the NOI were resolved by the DTE.
On August 15, 1998, the DTE approved the unbundled rate settlement
submitted by Commonwealth Gas. Commonwealth Gas submitted compliance rates
consistent with the settlement agreement on September 11, 1998, and unbundled
rates became effective on November 1, 1998.
On November 30, 1998 the DTE issued an order approving the partial set
of Model Terms and Conditions that were submitted by the Collaborative on July
10, 1998. In response to that order, however, the ten gas companies partici-
pating in the Collaborative informed the DTE that an April 1, 1999 implementa-
tion date for comprehensive gas unbundling was no longer feasible due to the
significant time required by the Collaborative to complete the Model Terms and
Conditions once the unresolved issues in the aforementioned NOI were answered
by the DTE, as well as the additional time required by the gas companies to
develop the systems necessary to implement unbundling consistent with these
provisions.
On February 1, 1999, the DTE issued an order in the NOI with regard to
capacity assignment and cost responsibility. The DTE found in favor of
mandatory capacity assignment, where gas marketers would be required to accept
the full cost and contractual obligations of the capacity that the gas
companies had historically procured to serve their common customers. In
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COMMONWEALTH ENERGY SYSTEM
support of its decision, the DTE determined that the capacity market in
Massachusetts was not yet workably competitive to allow it to remove tradi-
tional regulatory controls that were designed to ensure the reliability of gas
service to customers. The DTE further reaffirmed that the LDCs must continue
with their obligation to plan for and procure sufficient upstream capacity.
Finally, the DTE found that alternative approaches to mandatory capacity
assignment would result in transition costs that would conflict with the
well-established policy on cost allocation.
On February 17, 1999, the Collaborative reconvened to continue its work
in completing the Model Terms and Conditions consistent with the DTE's order
on capacity assignment with a goal to begin the implementation of comprehen-
sive unbundling for all LDCs beginning in 1999.
(b) Unbundled Rates
New unbundled rates for Commonwealth Gas went into effect on November
1, 1998. The unbundled rates were developed in accordance with a Settlement
Agreement reached by participants in the Massachusetts Gas Unbundling
Collaborative (MGUC) that was filed with the Massachusetts Department of
Telecommunications and Energy on June 29, 1998 and approved on August 15,
1998. The new unbundled rates reflect the separation of the Company's gas
supply function from its local distribution function.
Commencing with the billing month of November 1998, Commonwealth Gas
has a Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution
Adjustment Clause (LDAC) that provide for the recovery, from firm customers or
Default Service customers, of certain costs previously recovered through base
rates. The CGAC provides for rates that must be approved semi-annually by the
DTE. The LDAC provides for rates that require annual approval.
As part of its new unbundled rates, Commonwealth Gas modified its
existing CGAC to allow for the following changes: (a) the addition of
provisions that allow for the recovery of certain bad-debt expenses; (b) new
formulas that no longer adjust the Gas Adjustment Factors for the seasonal
embedded gas costs that were in existing sales rates; (c) updated language
reflecting the ratemaking requirements for non-core revenue margins; and (d)
the removal of provisions for the recovery of environmental remediation costs
and FERC Order 636 transition costs, which will instead be recovered through
the LDAC.
Commonwealth Gas' new LDAC recovers conservation charges, environmental
remediation costs, balancing penalty revenue credits, and costs associated
with the its participation in the MGUC.
Competition
COM/Energy continues to develop and implement strategies that deal with
the restructured utility industry. The planned merger with BEC Energy, the
sale of substantially all its non-nuclear generating assets and the purchase
of MATEP are actions that are indicative of COM/Energy'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 Financial Condition and Results of Operations filed
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COMMONWEALTH ENERGY SYSTEM
under Item 7 of this report. For additional information concerning the
purchase of MATEP, refer to Note 3(e) of Notes to Consolidated Financial
Statements filed under Item 8 of this report.
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 Commonwealth Electric, Commonwealth Gas and COM/Energy
Services Company effective on that date. The companies continue to operate
under their existing company names. The consolidation process for these
companies involved the merging of similar functions and activities to
eliminate duplication in order to create the most efficient and cost-effective
operation possible. In addition, COM/Energy initiated a voluntary personnel
reduction program during the second quarter of 1997 which reduced the total
number of regular employees by approximately 13%. COM/Energy has reduced its
full-time work force approximately 37% since 1990. Also, the introduction of
advanced technologies in the workplace continues to improve customer service
and COM/Energy's competitive position.
Segment Information
COM/Energy companies provide electric, gas and steam services to retail
customers in service territories located in central, eastern and southeastern
Massachusetts and, in addition, sell electricity at wholesale to Massachusetts
customers and own and operate a cogeneration plant that provides the Longwood
Medical Area of Boston with heating, chilled water service and electricity.
Other operations of COM/Energy include the pursuit of new business
opportunities and the operation of rental properties and other investment
activities which do not presently contribute significantly to either revenues
or operating income.
Reference is made to additional industry segment information in Note 11
of Notes to Consolidated Financial Statements filed under Item 8 of this re-
port.
Environmental Matters
COM/Energy is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment.
COM/Energy's compliance with these laws and regulations will require capital
expenditures of $585,000 from 1999 through 2003 for the electric and gas
divisions.
For additional information concerning environmental issues, refer to
the "Environmental Matters" section of "Management's Discussion and Analysis
of Financial Condition and Results of Operations" filed under Item 7 of this
report.
Construction and Financing
For information concerning COM/Energy's financing and construction
programs refer to Management's Discussion and Analysis of Financial Condition
and Results of Operations filed under Item 7 and Note 3(a) of the Notes to
Consolidated Financial Statements filed under Item 8 of this report.
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COMMONWEALTH ENERGY SYSTEM
Employees
The total number of full-time employees for COM/Energy declined by
approximately 5% to 1,638 in 1998 from 1,727 employees at year-end 1997. Of
the current total, 1,029 (63%) are represented by various collective
bargaining units covered by separate contracts with expiration dates ranging
from March 2001 through April 2003. Although a labor dispute with one
collective bargaining unit occurred during 1996, employee relations have
generally been satisfactory since the dispute was resolved in September 1996.
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COMMONWEALTH ENERGY SYSTEM
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations
Earnings and Dividends
Earnings and earnings per common share by organizational element for the
three-year period were as follows:
1998 1997 1996
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in thousands except per share amounts)
Electric........... $34,234 $1.59 $34,811 $1.62 $39,667 $1.85
Gas................ 12,214 .57 14,681 .68 16,229 .75
Other.............. 7,026 .32 (579) (.03) 2,229 .10
Total.......... $53,474 $2.48 $48,913 $2.27 $58,125 $2.70
Parent company earnings and dividends on preferred shares were allocated
among the electric, gas and other operations of COM/Energy based on the
Parent's equity investment in each segment.
1998 versus 1997
Earnings per share for the year 1998 were $2.48 compared to the $2.27
achieved in 1997 and include a one-time gain of 50 cents per share from the
sale of real estate. Earnings for 1997 include a one-time after-tax charge of
50 cents per share that related to a voluntary Personnel Reduction Program
(PRP). Excluding these one-time items, the decline in earnings for the year
was due to an increase in other operation expense (19 cents) reflecting costs
associated with outsourcing the information technology, telecommunications and
network services function (including costs related to Year 2000 compliance)
net of PRP savings. Other factors that negatively impacted earnings were a
17% decline in firm gas sales (27 cents), a revenue shortfall related to
demand-side management activity (25 cents), higher interest costs (10 cents),
costs associated with new business development (4 cents) and costs related to
supporting the industry restructuring referendum question on the November 1998
ballot (2 cents). Factors that had a positive impact on earnings were the
labor savings realized from the PRP, a decline in the provision for bad debts
(6 cents) and an increase in retail electric sales (2 cents).
1997 versus 1996
Earnings per share for the year 1997 were $2.27 compared to the record
level of $2.70 achieved in 1996. Excluding the aforementioned PRP, factors
that had a positive impact on earnings for the year were lower operating and
maintenance expenses (25 cents) that resulted, in part, from the PRP, an
increase in electric unit sales (11 cents) and the absence in 1997 of costs
associated with a labor dispute in 1996 (13 cents). Earnings for 1997 were
negatively affected by the absence of a 1996 refund associated with a power
contract settlement agreement (11 cents), lower firm gas unit sales (8 cents),
costs associated with new business development (12 cents), the absence of a
1996 recognition of the recoverability of costs associated with Canal Electric
Company's postretirement benefits costs that were subsequently recovered in
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COMMONWEALTH ENERGY SYSTEM
wholesale rates (5 cents) and a lower investment base on generation assets
(6 cents).
In March 1998, the Parent's Board of Trustees increased the quarterly
dividend rate per share 2.5% from 39 1/2 cents to 40 1/2 cents ($1.62 on an
annualized basis). This was the third consecutive year and the fourth time in
five years that the Board had voted to increase the quarterly dividend rate.
Dividends paid to common shareholders in 1998 were $34.9 million, representing
a payout ratio of 65% of 1998 earnings per share.
Electric Operations
Operating revenues from regulated operations for 1998 were $75.7 million
(11%) lower than in 1997 due primarily to a 10 percent rate reduction (further
discussed below) and decreases in electricity purchased for resale and fuel
charges ($58.8 million). The decline in these costs reflects a cost deferral
of $42.5 million in conjunction with COM/Energy's restructuring plan as
approved by the Massachusetts Department of Telecommunications and Energy
(DTE). As a result of electric industry restructuring, COM/Energy has unbun-
dled its rates, provided customers with a 10 percent rate reduction as of
March 1, 1998 and has afforded customers the opportunity to purchase genera-
tion 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 demand-side
management programs) and a renewable energy charge. Electricity supply
services provided by COM/Energy 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 additional
information concerning electric industry restructuring, refer to the Rates,
Regulation and Legislation section filed under Item 1 of this report.
Operating revenues from two non-regulated subsidiaries increased $23.8
million.
Electric operating revenues from regulated operations for 1997 increased
$38.8 million (6%) due to greater wholesale sales reflecting the changing
capacity needs of non-affiliated utilities ($11.7 million) and 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) ($11 million) and higher
retail unit sales ($2.4 million). Offsetting these factors was the absence of
a $4 million refund associated with a 1996 power contract settlement agreement
and lower revenues ($2.1 million) due to the return allowed on Canal
Electric's declining investment base.
Unit sales (in Megawatthours or MWH) were as follows:
% %
1998 Change 1997 Change 1996
Residential.......... 1,814,258 (0.9) 1,830,793 1.5 1,802,973
Commercial........... 2,560,433 2.2 2,506,215 3.1 2,430,188
Industrial and other. 458,877 (0.5) 459,104 2.1 449,844
Total retail..... 4,833,568 0.8 4,796,112 2.4 4,683,005
Wholesale............ 4,030,454 2.9 3,916,974 43.9 2,721,623
Total............ 8,864,022 1.7 8,713,086 17.7 7,404,628
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COMMONWEALTH ENERGY SYSTEM
In 1998 and 1997, retail unit sales increased due to strong commercial
sector sales and approximately 5,700 (1.5%) and 4,200 (1.2%) additional
customers, respectively, most of which are permanent year-round residential
and commercial customers. In 1998, the increase in the level of wholesale
sales primarily reflected increased sales to non-associated utilities, and to
a lesser extent, increased sales to the Town of Belmont and to ISO - New
England. The change in wholesale sales in 1997 reflected the increased
availability of Canal Unit 1 and greater sales to ISO - New England. The
changes in wholesale unit sales have little, if any, impact on net income.
The $38.1 million increase (10.7%) in fuel and purchased power costs in
1997 was due primarily to higher wholesale unit sales and higher costs for
replacement power due to the shutdown for repairs of both Connecticut Yankee
and Maine Yankee in mid- and late-1996, respectively. These units remained
out of service until their permanent shutdown in December 1996 and August
1997, respectively.
Gas Operations
Operating revenues from regulated operations decreased $41.9 million
(12.7%) during 1998 due primarily to the considerable decline in firm unit
sales. Operating revenues from an unregulated subsidiary increased $14.1
million. Also affecting revenues in both periods was a lower average cost of
gas.
In 1997, operating revenues from regulated operations decreased $11
million (3.2%) primarily due to a 5.6% decline in firm unit sales ($11.1
million) and lower conservation and load management (C&LM) costs ($1.8
million), offset by an increase in transportation revenues of $1.8 million and
revenues from sales of gas to third parties of $3.9 million. Operating
revenues from an unregulated subsidiary increased $3.1 million.
Unit sales and transportation volume (in billions of British thermal
units or BBTU) were as follows:
% %
1998 Change 1997 Change 1996
Residential......... 19,514 (11.5) 22,043 (3.1) 22,759
Commercial.......... 8,965 (19.1) 11,077 (4.2) 11,558
Industrial and other 3,524 (37.0) 5,594 (16.2) 6,676
Total firm....... 32,003 (17.3) 38,714 (5.6) 40,993
Off-system.......... 4,429 65.7 2,673 10.5 2,420
Interruptible and other 1,658 (14.2) 1,933 (34.5) 2,949
Total sales...... 38,090 (12.1) 43,320 (6.6) 46,362
Transportation...... 9,230 41.9 6,506 34.1 4,852
Total............ 47,320 (5.0) 49,826 (2.7) 51,214
The decrease in unit sales to firm customers in 1998 reflects the impact
of the milder weather conditions experienced during the year on all customer
segments. The fluctuation in interruptible and other sales reflects the
competitive market that exists today in the natural gas industry. A portion
of the margin realized on these sales reduced the cost of gas sold to firm
customers. Degree days for the current year totaled 5,754, 11% lower than
last year and 12.1% below the normal level of 6,541.
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COMMONWEALTH ENERGY SYSTEM
The decline in firm unit sales in 1997 was due to decreases to all
customer segments that reflected milder weather experienced in the region
during the first quarter as compared to a colder period in 1996. Degree days
for 1997 totaled 6,463, 3.6% lower than 1996 and 1.2% below normal.
Other Operating Expenses
In 1998, other operation increased $9.8 million (4.3%), despite reflecting
the absence of a one-time charge ($17.7 million) related to the aforementioned
PRP, due to higher costs related to the outsourcing of the information tech-
nology, telecommunications and network services function ($13.3 million) that
includes costs associated with Year 2000 compliance, costs associated with new
business development ($13.3 million), increased C&LM costs ($5 million) and
higher costs associated with real estate operations ($1.3 million). These
increases were offset, in part, by a decline in insurance and employee
benefits costs ($1.1 million) and labor savings from the PRP, the absence of
storm damage costs related to an April 1997 blizzard ($2 million) and a
decline in the provision for bad debts ($2.1 million).
Other operation in 1997 increased $10.3 million (4.8%) due to a one-time
charge related to the aforementioned PRP, costs associated with new business
development ($3.6 million), and an increase in the provision for bad debts
($1.4 million) that reflected higher reserve requirements. The impact of
these factors was offset, in part, by lower operating costs ($5 million) that
resulted, in part, from the PRP, lower pension costs ($2.7 million) and the
absence of costs related to the 1996 labor dispute ($4.6 million).
Maintenance increased $3 million (8.2%) in 1998 due to the addition of the
Medical Area Total Energy Plant (MATEP) facility ($1.9 million) and greater
expenses related to Canal Unit 1 boiler plant and related equipment. In 1997,
maintenance declined $4.1 million (10%) and resulted from a reduction in
transmission and distribution-related projects and, to a lesser extent, the
PRP.
Depreciation increased $7.6 million (14.2%) during 1998 and reflects the
treatment allowed for certain production plant pursuant to the electric
industry restructuring legislation as well as a higher level of depreciable
plant including the newly acquired MATEP facility. Depreciation increased
$1.6 million (3.1%) in 1997 due to additions to property, plant and equipment,
that included the costs associated with the conversion of Canal Unit 2 in mid-
1996 to burn natural gas as well as oil.
Federal and state income taxes decreased $4.8 million (15.4%) during 1998
reflecting the level of pre-tax income related to normal operations. The tax
impact from the sale of real estate ($6.3 million) was reflected as an offset
to the gain from the sale in Other Income on the Consolidated Statements of
Income. Federal and state income taxes decreased $4.8 million (13.4%) during
1997 due mainly to the lower level of pre-tax income.
The increase of $823,000 (2.9%) in local property and other taxes for 1998
was due primarily to real estate taxes associated with MATEP and higher real
estate tax rates and assessments offset, in part, by a decline in payroll
taxes attributable to savings realized from the aforementioned PRP. Local
property and other taxes were higher during 1997 due to higher property tax
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COMMONWEALTH ENERGY SYSTEM
rates and assessments within COM/Energy's service territory and an increase in
payroll-related taxes due to a 1996 labor dispute.
Other Income
In 1998, other income increased $9.9 million due to the gain from the
aforementioned sale of real estate ($10.8 million net of taxes). In 1997,
other income decreased $2 million due primarily to the absence of a 1996
recognition of the recoverability of costs associated with Canal Electric's
postretirement benefits ($1.8 million) following Federal Energy Regulatory
Commission (FERC) approval, and the absence of a gain from the sale of real
estate ($402,000 net of taxes) in 1996.
Interest Charges
The $6.6 million (16.3%) increase in total interest charges for 1998
resulted from higher levels of short-term borrowings, the full impact from the
issuance of two series of long-term debt in September 1997 and the issuance of
new long-term debt in the third quarter of 1998, partially offset by maturing
long-term debt and scheduled sinking fund payments. The $2 million decline in
total interest charges for 1997 was due to maturing long-term debt and
scheduled sinking fund payments partially offset by a slightly higher average
level of short-term borrowings.
Liquidity and Capital Resources
Financial Condition
COM/Energy's cash requirements are essentially met through the generation
of cash flows from the sale of electricity, natural gas (including liquefied
natural gas), steam and chilled water. Cash requirements for current opera-
tions, construction programs, debt service and other capital requirements are
maintained through internal generation and short-term borrowings made avail-
able through COM/Energy's credit lines with banks which totaled $132 million
at December 31, 1998. Interest rates on short-term borrowings generally are
at an adjusted money market rate. (See Note 6(a) of Notes to Consolidated
Financial Statements for additional information.) Long-term debt issues are
used to permanently finance short-term debt when deemed appropriate by
management.
The Parent, through its Advanced Energy Systems, Inc. subsidiary (AES),
purchased the MATEP total energy plant, that was formerly owned and operated
by Harvard University and is located in the Longwood Medical Area of Boston,
and related contracts, for $146.3 million on June 1, 1998. This acquisition
was ultimately financed with a $40 million equity contribution from the Parent
to AES (financed with a 2-year variable rate term note issued by the Parent)
and $112.5 million in 23-year term notes at a rate of 6.924% with quarterly
sinking fund payments scheduled to begin September 30, 2003 that escalate from
$790,000 to $2.7 million at the end of the term. The 2-year term note will be
repaid in two installments of $20 million each on July 1, 1999 and July 1,
2000. The variable interest rate averaged 5.673% for 1998. The 23-year term
notes are secured by long-term contracts between MATEP and its customers.
This new venture increased revenues by approximately $34 million in 1998 and
it is projected that annual revenues from this facility will average approxi-
mately $60 million in the years 1999 through 2003.
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COMMONWEALTH ENERGY SYSTEM
COM/Energy's 1998 net cash flow from operating activities ($81.9 million)
exceeded funds required to support normal additions to property, plant and
equipment. The improved cash flow position also reflects proceeds from the
sale of COM/Energy's generating assets and real estate ($466.6 million). No
gain was recorded on the sale of the generating assets on a consolidated basis
as COM/Energy is obligated to reduce Cambridge Electric's and Commonwealth
Electric's transition costs by the net proceeds of the sale.
The year's cash requirements for the payment of preferred and common divi-
dends ($35.9 million), the payment of maturing long-term debt and sinking fund
requirements ($102.1 million) and the repayment of short-term borrowings
($92.1 million) were provided from operations and proceeds from the issuance
of long-term debt ($152.5 million) and the sale of assets. Other information
on the sources and uses of cash for the past three years is included in the
Consolidated Statements of Cash Flows.
On February 12, 1999, the holders of the Parent's Cumulative Preferred
Shares (Series A 4.80%, Series B 8.10% and Series C 7.75%) were notified that
each series will be redeemed in full effective April 1, 1999. The redemption
price of $102 for Series A and $101 for each of Series B and C, plus accrued
dividends will be paid upon redemption.
Capital Requirements
-------------------------------------------------------------------
Bar graph illustration of
comparative two-year (1997-1998) actual
and five-year (1999-2003) forecast of
capital requirements based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1997 1998 1999 2000 2001 2002 2003
(Dollars in millions)
Construction-
Electric $ 35 $ 38 $ 38 $ 38 $ 41 $ 41 $ 44
Gas 18 19 19 18 19 19 19
Other 4 3 6 10 5 5 5
Maturing Debt 23 102 48 27 5 37 20
Purchase of MATEP - 146 - - - - -
Retirement of
Preferred Shares - - 11 - - - -
$ 80 $308 $122 $ 93 $ 70 $102 $ 88
Capital Requirements and Resources
COM/Energy's projected capital expenditures for the years 1999 through
2003 are $475.8 million, including $122.1 million for 1999 that consists of
$63.4 million for construction expenditures and $58.7 million for maturing
debt, sinking fund payments and the redemption of the preferred shares. These
1999 expenditures will be met through a combination of long and short-term
debt issues and internally-generated funds.
COM/Energy's goal is to maintain a capital structure that preserves an
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<PAGE 27>
COMMONWEALTH ENERGY SYSTEM
appropriate balance between debt and equity. Management believes its capital
resources and liquidity are sufficient to meet its current and projected
requirements.
COM/Energy's capitalization structure is presented below:
1998 1997
(Dollars in thousands)
Long-term debt $434,602 48.4% $383,311 41.7%
Preferred shares 11,380 1.3 12,200 1.3
Common equity 449,592 50.1 430,770 46.8
Short-term debt 2,000 0.2 94,075 10.2
Total capitalization $897,574 100.0% $920,356 100.0%
Capitalization
-------------------------------------------------------------------
Bar graph illustration of
comparative five-year (1999-2003) forecast of
capitalization components based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1999 2000 2001 2002 2003
(Dollars in millions)
Common
Equity $ 474 45% $ 488 46% $ 509 47% $ 537 49% $ 566 51%
Long-term
Debt 480 46 454 43 447 42 435 40 540 48
Short-term
Debt 92 9 120 11 121 11 114 11 7 1
$1,046 100% $1,062 100% $1,077 100% $1,086 100% $1,113 100%
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 Parent's business and financial results could cause actual
results to differ materially from those reflected in the forward-looking
statements or projected amounts. Those factors include developments in the
legislative, regulatory and competitive environment, certain environmental
matters, demands for capital and new business development expenditures and the
availability of cash from various sources.
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COMMONWEALTH ENERGY SYSTEM
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, the Parent and BEC will be merged into a new holding
company to be known as NSTAR. Holders of Parent common shares will receive
1.05 shares of NSTAR common stock for each share held while BEC common
shareholders will receive one share of NSTAR common stock for each share held.
In addition, current Parent and BEC common shareholders have the right to
receive cash rather than NSTAR common stock in the amount of $44.10 for each
share held, up to an aggregate maximum of $300 million. At the close of the
merger, Parent shareholders will own approximately 32% of NSTAR common stock
and BEC shareholders will own approximately 68%. 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 the
Parent'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
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, the Parent'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 the Parent'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 Consolidated Financial State-
ments, COM/Energy follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." In the event COM/Energy 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) increas-
ing competition restricting COM/Energy's ability to establish prices to
recover specific costs, and 2) a significant change in the current manner in
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<PAGE 29>
COMMONWEALTH ENERGY SYSTEM
which rates are set by regulators. COM/Energy 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, COM/Energy believes that its retail
electric 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, COM/Energy's retail
electric companies discontinued application of accounting principles applied
to their investment in electric generation facilities effective March 1, 1998.
COM/Energy will not be required to write off any of its generation-related
assets, including regulatory assets. These assets have been retained on the
Consolidated Balance Sheets because the legislation and the DTE's plan for a
restructured electric industry specifically provide for their recovery through
the non-bypassable transition charge.
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
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 has completed its assess-
ment of these non-information technology systems and determined that 20% of
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<PAGE 30>
COMMONWEALTH ENERGY SYSTEM
these systems required remediation or replacement. COM/Energy is approxi-
mately 86% complete in its efforts to resolve non-compliance with Year 2000
requirements related to these systems and 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
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,
<PAGE>
<PAGE 31>
COMMONWEALTH ENERGY SYSTEM
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
Commonwealth Gas is participating in the assessment of a number of former
manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to
determine if and to what extent such sites have been contaminated and whether
Commonwealth Gas may be responsible for remedial actions. In April 1998,
Commonwealth Gas recorded an additional liability and corresponding regulatory
asset of $500,000 due to an increase in the site clean-up cost estimate for an
MGP site for which Commonwealth Gas was previously cited as a Potentially
Responsible Party. The DTE has approved recovery of costs associated with MGP
sites.
Commonwealth Gas and certain other COM/Energy subsidiaries are also
involved in other known or potentially contaminated sites where the associated
costs may not be recoverable in rates and have recorded in prior years an
estimated liability (and a charge to operations) of $1.8 million to cover the
expected costs associated with assessment and remediation activities. These
estimates are reviewed and adjusted periodically as further investigation and
assignment of responsibility occurs. COM/Energy is unable to estimate its
ultimate liability for future environmental remediation costs. However, in
view of COM/Energy's current assessment of its environmental responsibilities,
existing legal requirements and regulatory policies, management does not
believe that these matters will have a material adverse effect on COM/Energy's
results of operations or financial position.
On January 1, 1997, COM/Energy adopted the provisions of Statement of
Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro-
vides authoritative guidance for recognition, measurement, display and
<PAGE>
<PAGE 32>
COMMONWEALTH ENERGY SYSTEM
disclosure of environmental remediation liabilities in financial statements.
COM/Energy has recorded environmental remediation liabilities net of amounts
paid of $2.9 million 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.
In April 1998, the American Institute of Certified Public Accountants
issued SOP 98-5, "Reporting on the Costs of Start-Up Activities" (SOP 98-5).
SOP 98-5 provides guidance on the financial reporting of start-up and organi-
zation costs and requires that these costs be expensed as incurred.
The adoption of SFAS No. 133 and SOP 98-5 is not expected to have a
material impact on COM/Energy's results of operations or financial condition.
<PAGE>
<PAGE 33>
COMMONWEALTH ENERGY SYSTEM
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this amendment to be signed on its behalf by
the undersigned, thereunto duly authorized.
COMMONWEALTH ENERGY SYSTEM
(Registrant)
By JAMES D. RAPPOLI
James D. Rappoli,
Financial Vice President
and Treasurer
Date: May 12, 1999
