<PAGE 1>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________
Commission file number 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: $789,947,326
Common Shares outstanding at March 16, 1998: 21,531,784 shares
Document Incorporated by Reference Part in Form 10-K
Notice of 1998 Annual Meeting and
Proxy Statement, dated March 30, 1998
(pages as specified herein) Part III
List of Exhibits begins on page 55 of this report.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business............................................... 3
General............................................. 3
Electric Power Supply............................... 4
Power Supply Commitments and Support Agreements..... 7
Electric Fuel Supply................................ 7
Nuclear Fuel Supply and Disposal.................... 8
Gas Supply.......................................... 8
Rates, Regulation and Legislation................... 9
Competition......................................... 14
Segment Information................................. 14
Environmental Matters............................... 14
Construction and Financing.......................... 15
Employees........................................... 15
Item 2. Properties............................................. 15
Item 3. Legal Proceedings...................................... 16
Item 4. Submission of Matters to a Vote of Security Holders.... 16
PART II
Item 5. Market for the Registrant's Securities and Related
Stockholder Matters.................................... 17
Item 6. Selected Financial Data................................ 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 19
Item 8. Financial Statements and Supplementary Data............ 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 28
PART III
Item 10. Trustees and Executive Officers of the Registrant...... 52
Item 11. Executive Compensation................................. 53
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 53
Item 13. Certain Relationships and Related Transactions......... 54
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................ 54
Signatures........................................................ 72
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PART I.
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 "System" and,
together with its subsidiaries, is collectively referred to as "the system."
The operating utility subsidiaries of the System are engaged in the
generation, transmission and distribution of electricity and the distribution
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 System also owns all of the
stock of a steam distribution company (COM/Energy Steam Company), five real
estate trusts, a liquefied natural gas (LNG) and vaporization facility
(Hopkinton LNG Corp.) and three new subsidiaries that are pursuing energy-
related business opportunities. Subsidiaries of the System 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. Advanced Energy Systems,
Inc. (formerly COM/Energy Enterprises, Inc.), together with two new
subsidiaries formed during 1997, COM/Energy Marketing, Inc. and COM/Energy
Technologies, Inc., were established to pursue business opportunities created
by the restructuring of the electric and gas industries and the emergence of
new energy technologies.
Each of the operating utility subsidiaries serves retail customers
except for Canal Electric Company (Canal) which operates an electric
generating station located in Sandwich, Massachusetts. The station consists
of Canal Unit 1, an oil-fired steam electric generating unit that is wholly-
owned by Canal and has a rated capacity of 569 MW, and Canal Unit 2, a steam
electric generating unit that was converted to dual-fuel capability (oil and
natural gas) in 1996 that is jointly-owned by Canal and Montaup Electric
Company (Montaup) (an unaffiliated company) and has a rated capacity of
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
580 MW. Canal Unit 2 is 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 321,000 year-round and 46,100 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. In early 1997,
Cambridge Electric and Commonwealth Electric received approval to participate
as a broker in the purchase and sale of electricity. 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 237,000 customers in 49 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
system companies 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.
Steam, which is produced by Cambridge Electric in connection with the
generation of electricity, is 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 system 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.
Electric Power Supply
To satisfy demand requirements and provide required reserve capacity,
the system supplements 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 Massachusetts Department of Telecommunications and Energy
(DTE) (formerly the Massachusetts Department of Public Utilities (DPU)).
System companies own generating facilities with a net capability at the
time of peak load (974 MW on July 18, 1997) totaling 1,017.7 MW including 569
MW provided by Canal Unit 1, of which three-quarters (426.8 MW) is sold to
neighboring utilities under long-term contracts, and 290 MW provided by Canal
Unit 2. Another 126.3 MW is provided by various smaller system units. Of the
558.5 MW available to the system, 63.3 MW are used principally for peaking
purposes. A 3.52% ownership interest in the Seabrook 1 nuclear power plant
provides 40.5 MW of capability to the system and Central Maine Power Company's
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Wyman Unit 4, an oil-fired facility in which the system has a 1.4% joint-
ownership interest, provides 8.8 MW. Additionally, in 1993, Canal extended an
agreement with New England Power Company (NEP) whereby 50 MW of Canal Unit 2
(previously 20 MW) is exchanged for 50 MW of Bear Swamp Unit Nos. 1 and 2
through April 1997. The Bear Swamp Units are pumped storage hydroelectric
generating facilities. These contracts are designed to reduce the system's
reliance on oil.
In addition, through Canal's equity ownership in Hydro-Quebec Phase II,
the system has an entitlement of 67.8 MW. Purchase power arrangements were
also in place with four natural gas-fired cogenerating units in Massachusetts
totaling 205.2 MW. The system also receives 67 MW from a waste-to-energy
plant and has entitlements totaling 23.9 MW through contracts with four
hydroelectric suppliers.
Pursuant to a restructured Power Sale Agreement (PSA), effective January
1, 1995, a non-utility generator (NUG) ceased supplying capacity and energy to
the system. The restructured PSA defers the system's obligation to purchase
the NUG's capacity and energy for a maximum of six years. In addition, on
January 27, 1995, the DTE approved the buy-out of a PSA between Commonwealth
Electric and another NUG, effective April 12, 1995. This buy-out is expected
to save Commonwealth Electric's customers approximately $37 million over the
next 20 years. A purchased power obligation with another NUG was terminated
in June 1996 and is expected to save Commonwealth Electric's customers an
additional $34 million over the twenty-year life of the original agreement.
The system also has available 84.4 MW from two operating nuclear units
in which system distribution companies have life-of-the-unit contracts for
power. Information with respect to these units is as follows:
Vermont
Yankee Pilgrim
Year of Initial Operation 1972 1972
Contract Expiration Date 2012 2012
Equity Ownership (%) 2.50 -
Plant Entitlement (%) 2.25 11.0
Plant Capability (MW) 496.0 664.7
System Entitlement (MW) 11.2 73.2
Information relative to nuclear units that are no longer operating in
which the system 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 $5,007 $3,121 $405
For additional information, refer to Note 3(d) of the Notes to Consolidated
Financial Statements filed under Item 8 of this report.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The system's non-nuclear generating assets together with capacity
entitlements associated with power contracts previously discussed and as
further discussed later in this section are part of an ongoing auction process
initiated during 1997 in response to electric industry restructuring
legislation enacted in Massachusetts in November 1997. The auction process is
expected to be completed in 1998. For further information refer to the
"Industry Restructuring" section of Management's Discussion and Analysis of
Financial Condition and Results of Operations filed under Item 7 of this
report.
Cambridge Electric, Canal 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)
between the electrical systems of New England and Quebec. The parties have
also entered into an Energy Contract and an Energy Banking Agreement; the
former obligates 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 and the latter provides for energy transfers between the two systems.
ISO - New England has 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 which began in late 1990.
Canal 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 $11.8 million at December 31,
1997. In addition, Canal has an equity interest in Phase II which amounted to
$3.1 million in 1997 and $3.3 million in 1996.
The System'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. The system estimates that,
during the next ten years, reserve requirements so determined will be
approximately 20% of peak load.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Power Supply Commitments and Support Agreements
Cambridge Electric and Commonwealth Electric, through Canal, 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 system commitments
under long-term power contracts, refer to Note 3(d) of Notes to Consolidated
Financial Statements filed under Item 8 of this report.
The system's 3.52% interest in the Seabrook nuclear power plant is
owned by Canal 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.
Electric Fuel Supply
(a) Oil and Natural Gas
Of the system's total energy requirement for 1997, approximately 42%
was generated using imported residual oil and approximately 32% was generated
using natural gas.
Effective March 15, 1998, Canal executed a one-year contract with
Coastal Refining and Marketing, Inc. (Coastal) for the purchase of 1% sulfur
residual fuel oil. The contract provides for delivery of a set percentage of
Canal's fuel requirement, the balance (a maximum of 50%) to be met by spot
purchases or by Coastal at the discretion of Canal.
Energy Supply & Credit Corporation (ESCO Massachusetts, Inc.) operates
Canal's fuel oil terminal and manages the receipt of and payment for fuel oil
under assignment of Canal's supply contracts to ESCO Massachusetts, Inc.
Residual fuel oil in the terminal's shore tanks is held in inventory by ESCO
Massachusetts, Inc. and delivered upon demand to Canal's two day tanks.
Fuel oil storage facilities at the Canal site have a capacity of
1,199,000 barrels, representing approximately 60 days of normal operation of
the two units. During 1997, ESCO Massachusetts, Inc. maintained an average
daily inventory of 395,000 barrels of fuel oil which represents 18 days of
normal operation of the two units. This supply is maintained by tanker
deliveries.
During 1996, Unit 2 was converted to dual-fuel capability, residual
fuel oil and natural gas. Unit 2 has burned approximately 2.5 million MMBTU's
of natural gas since the conversion was completed during periods when the use
of natural gas was the most economical choice. Canal anticipates that its
dual-fuel capability will result in future savings as the least expensive fuel
is utilized.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Canal has a gas supply contract with PGE Energy Trading Corporation to
provide 100% of the natural gas requirements of Unit 2 through October 31,
1998. Canal's original gas supply contract with Duke/Louis Dreyfus, L.L.C.
expired on December 31, 1997.
(b) Nuclear Fuel Supply and Disposal
Approximately 13% of the system's total energy requirement for 1997 was
generated by nuclear plants. The nuclear fuel contract and inventory
information for Seabrook 1 has been furnished to the system by North Atlantic
Energy Services Corporation (NAESCO), the plant manager responsible for
operation of the unit. Seabrook's requirement for nuclear fuel components are
100% covered through 1999 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.
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
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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, 1997, there were 218 customers using
this transportation service, accounting for 8,462 BBTU or approximately 16% 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 System. 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. Commonwealth Gas and Hopkinton
are currently evaluating the contracts to determine if amendments to the
contracts should be negotiated in light of the ongoing deregulation of the
natural gas industry. 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.
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 the System'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.
(a) Restructuring Legislation
As more fully discussed in the "Industry Restructuring" section of
Management's Discussion and Analysis of Results of Operations in Item 7 of
this report, the system began to implement the provisions of the Electric
Industry Restructuring Act on March 1, 1998 as signed into law on November 25,
1997 following the Company's filing of its proposed restructuring plan with
the DTE on November 19, 1997. A modified plan was approved by the DTE on
February 27, 1998 prior to implementation on March 1, 1998. Also discussed is
the movement initiated by the DTE in July 1997 to unbundle rates and services
for all gas customers.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(b) Wholesale Rate Proceedings
Cambridge Electric provides power supply and transmission services to
its FERC-jurisdictional wholesale customers. Cambridge Electric requires FERC
approval to change its wholesale rates, including those to the Municipal Light
Department of the Town of Belmont, Massachusetts (Belmont), a "partial
requirements" customer since 1986. Since February 1993, Belmont has taken
power supply service pursuant to a FERC approved Net Requirements Power Supply
Agreement.
In 1993, Cambridge Electric and Belmont began negotiations for a new
transmission service agreement. The negotiations were not successful. On
June 29, 1994, Cambridge Electric filed for FERC approval of a new
transmission service agreement with Belmont. The FERC accepted the rates
effective January 25, 1995, subject to refund. At the same time, an
investigation was opened by the FERC to determine the reasonableness of both
the existing transmission tariff rates to Belmont and the proposed trans-
mission service agreement with Belmont. Both Belmont and FERC staff
intervened in the investigation. Cambridge Electric filed its case with the
FERC on October 25, 1994 and evidentiary hearings were held in March 1995.
An Initial Decision (ID) of the Presiding Administrative Law Judge was
issued on September 14, 1995. In the ID, the Administrative Law Judge found
that Cambridge Electric's existing transmission tariff rates were just and
reasonable. The Administrative Law Judge identified a number of revisions to
the filed transmission service agreement which effectively reduced the rates
to Belmont. In October 1995, the parties filed briefs on exceptions to the
Administrative Law Judge's ID. Cambridge Electric awaits final FERC action on
this investigation.
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
interrelated rules resolving the above rulemakings. The FERC required all
public utilities that own, control or operate transmission facilities in
interstate commerce to have on file wholesale open access transmission tariffs
that conform to the FERC pro-forma tariff contained in Order No. 888. On July
9, 1996, Cambridge Electric and Commonwealth Electric filed tariffs that
conform to the FERC's pro-forma tariffs. On November 13, 1996, the FERC
accepted the non-rate terms and conditions of these tariffs effective July 9,
1996, subject to a revision of one section dealing with the scheduling of
services. On March 4, 1997, the FERC issued Order No. 888-A which required
revisions to the tariffs filed in compliance with Order No. 888. Cambridge
Electric and Commonwealth Electric both filed their revised tariffs on July
14, 1997. On November 25, 1997, the FERC issued Order No. 888-B requiring
minor changes that did not require an additional filing.
<PAGE 11>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
On December 31, 1996, Cambridge Electric and Commonwealth Electric
filed market-based power sales tariffs with the FERC that received FERC
approval on February 27, 1997. The Companies seek authorization to make
wholesale power sales at fully negotiated rates. In addition, the Companies
requested and received authorization to participate as brokers in the sale and
purchase of electricity.
(c) Unbundled Rates
Electric
Both Commonwealth Electric and Cambridge Electric have restructured
their operations to provide customers with unbundled rates that provide a ten
percent rate reduction as of March 1, 1998 and the opportunity to purchase
generation supply on the competitive market pursuant to the electric industry
restructuring legislation enacted in November 1997. Delivery rates are
composed of distribution charges, transition charges (to collect stranded
costs) and transmission charges. Electricity supply services include optional
standard offer service and default service. Distribution charges consist of
customer demand and energy charges as appropriate to recover distribution
costs, including costs formerly recovered under the Conservation Charge, and
is based on the separation of distribution and transmission facilities.
Transmission charges are itemized separately and are subject to each company's
Transmission Cost Adjustment. Transition charges are designed to recover on a
reconciling basis all of each company's stranded costs.
Prior to 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.
Also prior to March 1, 1998, Cambridge Electric and Commonwealth
Electric 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 kilowatthour (KWH) factor that
was calculated using historical (test-period) capacity costs and unit sales.
This factor was then applied to current monthly KWH sales. When current
period capacity costs and/or unit sales varied from test-period levels,
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 agreements 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 Commonwealth Electric and Cambridge Electric also had separately
stated Conservation Charge rate schedules that allowed for current recovery,
from retail customers, of conservation and load management costs.
<PAGE 12>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Gas
Commonwealth Gas has a Standard Seasonal Cost of Gas Adjustment rate
schedule (CGA) that provides for the recovery, from firm customers, of
purchased gas and conservation and load management costs not recovered through
base rates. These schedules, which require DTE approval, are estimated semi-
annually and include credits for gas pipeline refunds and profit margins
applicable to capacity release, off-system sales and interruptible sales.
Actual gas costs are reconciled annually as of October 31, and any difference
is included as an adjustment in the calculation of the decimals for the two
subsequent six-month periods.
Periodically, Commonwealth Gas is required to file a long-range
forecast of the energy needs and requirements of its market area and annual
supplements thereto with the DTE. To approve this long-range forecast and
resource plans, the DTE must find, among other things, that Commonwealth Gas'
projected firm load is reasonable and based on proven and verifiable
forecasting methods and data, and that Commonwealth Gas assembles its supply
portfolio based on a prudent resource planning process that can be reasonably
expected to meet projected demands on a cost efficient basis. Commonwealth
Gas filed its forecast, covering the period November 1996 through October
2001, with the DTE on December 20, 1996.
(d) Gas Demand and Transition Costs
Commonwealth Gas is obligated, as part of its pipeline transportation
contracts, storage contracts and gas purchase contracts, to pay monthly demand
charges which are recovered from customers through the CGA.
As a direct result of implementation of FERC Order 636, most pipeline
companies are incurring transition costs which include the cost of
restructuring gas supply contracts, the value of facilities that were
supporting the gas sales function and are no longer used and useful for
transportation only services, the cost of contracts with upstream pipeline
companies and various miscellaneous costs. These costs are billed to
Commonwealth Gas and other local distribution companies.
Commonwealth Gas is collecting all contract restructuring costs from
its customers through the CGA as permitted by the DTE.
(e) 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.
<PAGE 13>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(f) 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 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. Pursuant to its
terms, the CTC will terminate as of March 1, 1998, which is the retail access
date established by the Massachusetts Legislature in its Electric Industry
Restructuring Act.
The Massachusetts Institute of Technology (MIT) appealed the DTE's
ruling approving the CTC to the Massachusetts Supreme Judicial Court (the
SJC), contending, in part, that the DTE lacked authority to approve the CTC,
the DTE's ruling was not supported by subsidiary findings, imposition of the
CTC on MIT constitutes inequitable retroactive ratemaking, and the CTC
violates the Public Utility Regulatory Policies Act (PURPA). On September 18,
1997, the SJC announced its decision remanding the matter to the DTE for
further consideration. The SJC did find that recovery of prudent and
verifiable stranded costs by utility companies is in the public interest and
consistent with PURPA. However, the SJC stated that 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 customer
transition charge. Among the issues that the SJC directed the DTE to consider
further are: the methodology for calculation of stranded costs, why 75% of
stranded costs were allocated to MIT rather than 100%, the prudence of the
stranded costs incurred by Cambridge Electric, and whether Cambridge Electric
took the necessary mitigation efforts to reduce stranded costs. The DTE is in
the process of determining whether to take additional evidence in the remand
or to rely on the record and pleadings already filed. At this time,
management is unable to predict the outcome of this proceeding.
In an earlier legal proceeding involving the CTC, on August 27, 1996,
the United States District Court for the District of Massachusetts (District
Court) granted the motions for summary judgement of Cambridge Electric and the
DTE and dismissed the May 1996 complaint filed by MIT. In its complaint, MIT
had alleged that the CTC approved by the DTE and implemented by Cambridge
Electric violated PURPA. In dismissing MIT's complaint, the District Court
found that MIT's complaint involved an allegation relating to the DTE's
application of PURPA, which is not within the District Court's jurisdiction.
<PAGE 14>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Competition
The system continues to develop and implement strategies that deal with
the increasingly competitive environment facing the electric business. The
system's actions in response to the competitive challenges brought on by
electric and gas industry restructuring have been well received by regulators,
business groups and customers. For a more detailed discussion of the DTE's
restructuring order and gas service unbundling efforts, refer to the "Industry
Restructuring" section of Management's Discussion and Analysis of Financial
Condition and Results of Operations filed under Item 7 of this report.
On February 6, 1997, due to the dramatically changing nature of the
electric and gas industries, the System announced the consolidation of
management personnel of Commonwealth Electric, Commonwealth Gas and COM/Energy
Services Company effective on that date. These companies will 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, the system initiated a voluntary personnel
reduction program during the second quarter of 1997 which reduced the total
number of regular employees by approximately 13%. Through this and prior work
force reductions and attrition, the system has reduced its full-time work
force approximately 33% since 1990. Also, the introduction of advanced
technologies in the workplace continues to improve customer service and the
system's competitive position. The system has yet to be significantly
impacted by the increase in competition and believes that its current business
strategy and entrance into unregulated markets will have a positive impact in
the near-term.
Segment Information
System 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. Other operations of the system 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
The system is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment.
System compliance with these laws and regulations will require capital
expenditures of $68.2 million from 1998 through 2002 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.
<PAGE 15>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Construction and Financing
For information concerning the system'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.
Employees
The total number of full-time employees for the system declined by
approximately 13% to 1,727 in 1997 from 1,991 employees at year-end 1996 due
primarily to the initiation of a voluntary personnel reduction program during
the second quarter of 1997. Of the current total, 1,037 (60%) are represented
by various collective bargaining units. Agreements with three units
representing approximately 12% of regular employees are scheduled to expire in
1998. Upon expiration of one of these contracts, representing 6% of regular
employees, a new contract (already ratified) will become effective through
March 1, 2001. 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.
Item 2. Properties
The system's principal electric properties consist of Canal Unit 1, a
569 MW oil-fired steam electric generating unit, and its one-half ownership in
Canal Unit 2, a 580 MW steam electric generating unit with the ability to burn
both oil and natural gas, both located at Canal Electric's facility in
Sandwich, Massachusetts.
Cambridge Electric owns and operates two steam electric generating
stations and two gas turbine units located in Cambridge, Massachusetts with a
total capability of 112.5 MW and Commonwealth Electric has an interest in
smaller generating units totaling 13.8 MW. Of these 126.3 MW, 63.3 MW is used
primarily for peaking and emergency purposes. In addition, the system has a
3.52% interest (40.5 MW of capacity) in Seabrook 1 and a 1.4% (8.8 MW) joint-
ownership interest in Central Maine Power Company's Wyman Unit 4.
Other electric properties include an integrated system of distribution
lines and substations. In addition, the system's other principal properties
consist of an electric division office building in Wareham, Massachusetts and
other structures such as garages and service buildings.
At December 31, 1997, the electric transmission and distribution system
consisted of 5,833 pole miles of overhead lines, 4,461 cable miles of
underground line, 371 substations and 381,159 active customer meters.
The principal natural gas properties consist of distribution mains,
services and meters necessary to maintain reliable service to customers. At
December 31, 1997, the gas system included 2,811 miles of gas distribution
lines, 167,777 services and 245,246 customer meters together with the
necessary measuring and regulating equipment. In addition, the system owns a
liquefaction and vaporization plant, a satellite vaporization plant and above-
ground cryogenic storage tanks having an aggregate storage capacity equivalent
<PAGE 16>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
to 3.5 million MCF of natural gas. The system's gas division owns a central
headquarters and service building in Southborough, Massachusetts, five
district office buildings and several natural gas receiving and take stations.
Item 3. Legal Proceedings
Cambridge Electric is an intervenor in an appeal at the Massachusetts
Supreme Judicial Court (SJC) filed by MIT of a decision by the DTE approving a
customer transition charge that allows Cambridge Electric to recover certain
stranded costs. For additional information refer to the "Customer Transition
Charge" section in Item 1 of this report.
Item 4. Submission of Matters to a Vote of Security Holders
None
<PAGE 17>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PART II.
Item 5. Market for the Registrant's Securities and Related Stockholder
Matters
(a) Principal Markets
The System's common shares are listed on the New York and Pacific
stock exchanges. The table below sets forth the high and low closing
prices as reported on the New York Stock Exchange composite
transactions tape.
1997 by Quarter
First Second Third Fourth
High $24 1/2 $24 $27 $34 9/16
Low 20 7/8 19 23 3/4 25 11/16
1996 by Quarter
First Second Third Fourth
High $25 $25 3/4 $25 5/8 $24 7/8
Low 21 15/16 22 3/4 21 1/2 22 1/2
(b) Number of Shareholders at December 31, 1997
12,708 shareholders
(c) Frequency and Amount of Dividends Declared in 1997 and 1996
1997 1996
Per Per
Share Share
Declaration Date Amount Declaration Date Amount
March 27, 1997 $ .395 March 28, 1996 $ .385
June 26, 1997 .395 June 27, 1996 .385
September 25, 1997 .395 September 26, 1996 .385
December 18, 1997 .395 December 19, 1996 .385
$1.580 $1.540
(d) Future dividends may vary depending upon the System's earnings and
capital requirements as well as financial and other conditions
existing at that time.
<PAGE 18>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 6. Selected Financial Data
1997 1996 1995 1994 1993
(Dollars In Thousands Except Common Share Data)
Operating Revenues
Electric $ 688,508 $ 649,678 $ 604,980 $ 638,150 $ 622,039
Gas 333,977 341,867 306,953 323,568 302,644
Steam and other 19,250 19,360 17,355 15,867 14,035
Total $1,041,744 $1,010,905 $ 929,288 $ 977,585 $ 938,718
Net Income $ 49,901 $ 59,175 $ 51,396 $ 48,968 $ 45,834
Common Share Data-
Earnings per share $2.27 $2.70 $2.36 $2.29 $2.18
Dividends declared
per share $1.58 $1.54 $1.50 $1.50 $1.46
Average shares
outstanding 21,531,784 21,529,676 21,311,836 20,827,562 20,431,228
Total Assets $1,485,050 $1,428,955 $1,392,342 $1,345,032 $1,318,940
Long-term debt $ 364,311 $ 355,305 $ 377,181 $ 418,307 $ 448,893
Redeemable preferred
share investment 12,200 13,020 13,840 14,660 15,480
Common share
investment 430,770 415,694 390,785 362,997 337,070
Total Capitalization $ 807,281 $ 784,019 $ 781,806 $ 795,964 $ 801,443
1997 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $316,190 $221,944 $222,115 $281,495
Operating Income 35,892 7,793 16,887 27,078
Income Before Interest Charges 36,541 8,774 17,227 27,709
Net Income 26,400 (1,334) 7,147 17,688
Earnings per Common Share 1.21 (.07) .32 .81
Dividends Declared per
Common Share .395 .395 .395 .395
Closing Price of Common Shares-
High 24 1/2 24 27 34 9/16
Low 20 7/8 19 23 3/4 25 11/16
1996 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $298,614 $222,667 $226,909 $262,715
Operating Income 36,131 18,608 17,601 24,325
Income Before Interest Charges 38,622 19,863 18,838 24,220
Net Income 27,907 9,463 8,360 13,445
Earnings per Common Share 1.28 .43 .37 .62
Dividends Declared per
Common Share .385 .385 .385 .385
Closing Price of Common Shares-
High 25 25 3/4 25 5/8 24 7/8
Low 21 15/16 22 3/4 21 1/2 22 1/2
<PAGE 19>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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:
1997 1996 1995
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in thousands except per share amounts)
Electric........... $34,811 $1.62 $39,667 $1.85 $32,247 $1.52
Gas................ 14,681 .68 16,229 .75 15,352 .72
Other.............. (579) (.03) 2,229 .10 2,687 .12
Total.......... $48,913 $2.27 $58,125 $2.70 $50,286 $2.36
Parent company earnings and dividends on preferred shares were allocated
among the electric, gas and other operations of the system based on the
Parent's equity investment in each segment.
1997 versus 1996
Earnings per share for the year 1997 were $2.27 compared to the record
level of $2.70 achieved last year. The decline for the year was due to a one-
time after-tax charge of $10.7 million, or 50 cents per share, that related to
a voluntary personnel reduction program (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 postretire-
ment benefits costs that were subsequently recovered in wholesale rates
(5 cents) and a lower investment base on generation assets (6 cents).
1996 versus 1995
In 1996, earnings per share increased 34 cents to $2.70. Significant
factors that contributed to the improved earnings included higher firm gas
(18 cents) and retail electric (14 cents) unit sales, the refund associated
with the power contract settlement agreement (11 cents), lower interest costs
(9 cents), and the recognition of Canal's recovery of postretirement benefits
costs (5 cents). Partially offsetting these factors were costs related to the
labor dispute (13 cents), storm damage from Hurricane Edouard (6 cents), a
customer refund (5 cents in 1996 versus 1 cent in 1995) pursuant to a 1995
settlement agreement with the Massachusetts Department of Telecommunications
and Energy (DTE) (formerly the Massachusetts Department of Public Utilities)
that limited Commonwealth Electric Company's return on equity, as defined in a
settlement that expired in 1997, and the reversal in 1995 of a reserve (4
cents) related to a conservation program settlement in 1995.
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
In March 1997, the System's Board of Trustees increased the quarterly
dividend rate per share 2.6% from 38 1/2 cents to 39 1/2 cents ($1.58 on an
annualized basis). This was the second consecutive year and the third time in
four years that the Board had voted to increase the quarterly dividend rate.
Dividends paid to common shareholders in 1997 were $34.1 million, representing
a payout ratio of 69% of 1997 earnings per share.
Electric Operations
Electric operating revenues for 1997 increased $38.8 million (6%) due to
greater wholesale sales reflecting the changing capacity needs of non-affili-
ated utilities ($11.7 million) and the Independent System Operator (ISO) - New
England (formerly the New England Power Pool that operates a centralized
facility to ensure reliability of service and dispatch of economically
available generating units throughout New England) ($11 million) and higher
retail unit sales ($2.4 million). Offsetting these factors was the absence of
a $4 million refund associated with the 1996 power contract settlement agree-
ment and lower revenues ($2.1 million) due to the return allowed on Canal's
declining investment base.
In 1996, electric operating revenues increased $44.7 million (7.4%) due
mainly to higher fuel costs of $33.9 million reflecting the increased avail-
ability of Canal's Unit 1 generating facility that was out of service during
the first seven months of 1995 for scheduled maintenance and repairs. The
remainder of the change reflects the $4 million refund associated with the
power contract settlement, the impact of higher retail unit sales ($3.9
million), and the recovery in rates of $1.8 million for Canal's previously
deferred postretirement benefits costs.
Unit sales (in Megawatthours or MWH) were as follows:
% %
1997 Change 1996 Change 1995
Residential.......... 1,830,793 1.5 1,802,973 2.9 1,752,430
Commercial........... 2,506,215 3.1 2,430,188 (0.8) 2,450,390
Industrial and other. 459,104 2.1 449,844 1.1 445,020
Total retail..... 4,796,112 2.4 4,683,005 0.8 4,647,840
Wholesale............ 3,916,974 43.9 2,721,623 37.9 1,973,543
Total............ 8,713,086 17.7 7,404,628 11.8 6,621,383
In 1997 and 1996, retail unit sales increased due to approximately 4,200
(1.2%) and 3,700 (1.0%) additional customers, the significant majority of
which are permanent year-round residential customers. The increase in the
level of wholesale sales reflected the increased availability of Canal Unit 1
(by 53%) and greater sales to ISO - New England (by nearly 43%). The changes
in wholesale unit sales have little, if any, impact on net income.
The $38.1 million increase in fuel and purchased power costs in 1997 was
due primarily to higher wholesale unit sales and higher costs for replacement
power reflecting the permanent shutdown of both Connecticut Yankee during 1996
and Maine Yankee in 1997, the latter of which was taken out of service in
December 1996. In 1996, the cost of fuel increased by $33.9 million due
primarily to the availability of Canal Unit 1, while the cost of purchased
power decreased by $9.8 million reflecting the availability of Canal Unit 1
and the reduced requirement for other more costly sources of capacity.
<PAGE 21>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Gas Operations
In 1997, gas operating revenues decreased $7.9 million (2.3%) primarily
due to a 5.6% decline in firm unit sales ($11.1 million) and lower conserva-
tion 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. In 1996, operating revenues increased approxi-
mately $34.9 million or 11.4% due to higher gas costs of $28.7 million
reflecting both higher prices from suppliers and increased unit sales to
customers. The increased firm sales, including transportation, equated to
$6.9 million due to colder weather during 1996.
Commonwealth Gas Company also utilizes the off-system sales and capacity
release markets as a means to sell excess resources. A margin-sharing
agreement for these sales was approved by the DTE on January 15, 1997 that
allowed Commonwealth Gas to retain 25% of the gross margins realized above a
certain threshold amount as set from year to year with the remaining margins
credited to firm customers through the Cost of Gas Adjustment clause. As a
result of this margin-sharing agreement, Commonwealth Gas realized revenues of
approximately $644,000 in 1997.
Unit sales and transportation volume (in billions of British thermal
units or BBTU) were as follows:
% %
1997 Change 1996 Change 1995
Residential......... 22,043 (3.1) 22,759 6.7 21,336
Commercial.......... 11,077 (4.2) 11,558 7.9 10,710
Industrial and other 5,594 (16.2) 6,676 4.1 6,412
Total firm....... 38,714 (5.6) 40,993 6.6 38,458
Off-system.......... 2,673 10.5 2,420 (40.1) 4,043
Quasi-firm.......... 51 (95.2) 1,066 (44.1) 1,906
Interruptible....... 1,882 (0.1) 1,883 55.0 1,215
Total sales...... 43,320 (6.6) 46,362 1.6 45,622
Transportation...... 6,506 34.1 4,852 20.6 4,024
Total............ 49,826 (2.7) 51,214 3.2 49,646
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 the current year totaled 6,463, 3.6% lower than last year and 1.2% below
the normal level of 6,541. The significant fluctuations in non-firm sales
reflected the competitive environment that exists in the natural gas industry.
A portion of the margin realized on these sales reduced the cost of gas sold
to firm customers.
The increase in unit sales to firm customers during 1996 (6.6%) reflected
significant improvements for all customer segments consistent with colder than
normal weather experienced during the year, as compared to milder weather in
1995 that was 1.4% above normal. Heating degree days were nearly 3.8% higher
during 1996 as compared to 1995 and 2.3% above normal. A growing customer
base, including customers formerly receiving quasi-firm sales service,
somewhat offset the decline in firm sales in 1997 and contributed to the
increase in firm unit sales in 1996.
<PAGE 22>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Other Operating Expenses
Other operation in 1997 increased $10.3 million or 4.8% due to a one-time
charge related to the PRP ($17.7 million) as further discussed below, 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).
The system initially announced the details of the system-wide voluntary
PRP in May 1997. The goal of the PRP was to achieve a reduced, more efficient
and more productive workforce in response to the significant regulatory
changes facing the system. In 1997, approximately 13% of system employees
voluntarily terminated employment as a result of the PRP. The one-time charge
of $17.7 million referred to above excludes generation-related costs, the
recovery of which is being addressed as part of the electric industry restruc-
turing process. The payback period for the cost of the PRP is expected to be
about one year. This action followed the consolidation of the system's
electric and gas operations earlier in 1997. In furtherance of this consoli-
dation effort, the system, in March 1998, reached agreement with IBM Global
Services, Inc. to offer employment to 40 system employees and to provide all
of the system's information technology, telecommunications and network
services.
In 1996, other operation increased approximately $9 million or 4.4% and
reflected the impact of higher general liability insurance costs ($6.3
million), higher postretirement benefits costs ($4 million), and the net
impact of the labor dispute. These expenses were offset somewhat by lower
C&LM costs ($2.4 million), a $1.6 million decline in health benefits costs, a
decline in the provision for bad debts ($1.1 million) that reflected improved
collection experience, and the absence of legal fees ($800,000) associated
with the cancellation of a power contract in 1995.
Maintenance declined in 1997 by $4.1 million or 10% and resulted from a
reduction in transmission and distribution-related projects and, to a lesser
extent, the PRP. Maintenance increased in 1996 by $2.5 million or 6.5%
primarily due to storm damage costs related to Hurricane Edouard ($2.1
million), partially offset by reductions primarily associated with Canal Unit
1 ($1.5 million).
Depreciation increased $1.6 million and $3.6 million in 1997 and 1996,
respectively, and reflected the system's additions to property, plant and
equipment, that included the costs associated with the completed conversion of
Canal Unit 2 in mid-1996 to burn natural gas as well as oil.
Federal and state income taxes decreased by $5.1 million during 1997 due
mainly to the lower level of pre-tax income. Local property and other taxes
were higher during 1997 due to higher property tax rates and assessments
within the system's service territory and an increase in payroll-related taxes
due to the 1996 labor dispute.
<PAGE 23>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Other Income
In 1997, other income decreased $2.3 million due primarily to the absence
of a 1996 recognition of the recoverability of costs associated with Canal's
postretirement benefits ($1.8 million) following Federal Energy Regulatory
Commission approval, and the absence of a 1996 gain that related to the sale
of parcels of land ($700,000). These two factors were also the primary causes
for the change for 1996 versus 1995.
Interest Charges
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. The decline of
$2.2 million, or 5%, in 1996 also reflected maturing debt and sinking fund
payments.
Liquidity and Capital Resources
Financial Condition
The system's cash requirements are essentially met through the generation
of cash flows from the sale of electricity, natural gas (including liquefied
natural gas) and steam. Cash requirements for current operations, construc-
tion programs, debt service and other capital requirements are maintained
through internal generation and short-term borrowings made available through
the system's credit lines with banks. Long-term debt issues are used to
permanently finance short-term debt when deemed appropriate by management.
The system's 1997 net cash flow from operating activities exceeded funds
required to support additions to property, plant and equipment by $50 million
or 86.9%. Plant additions continued to be funded entirely with internally-
generated funds. The year's cash requirements for the payment of preferred
and common dividends ($35.1 million), the funding of maturing long-term debt
and sinking fund requirements ($22.7 million) and the re-payment of short-term
borrowings ($24.4 million) were provided from operations and proceeds from the
issuance of long-term debt ($35 million). Other information on the sources
and uses of cash for the past three years is included in the Consolidated
Statements of Cash Flows.
<PAGE 24>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Capitalization
-------------------------------------------------------------------
Bar graph illustration of
comparative five-year (1998-2002) forecast of
capitalization components based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1998 1999 2000 2001 2002
(Dollars in Millions)
Common
Equity $ 459 42% $ 478 46% $ 512 48% $ 563 51% $ 620 54%
Total
Debt 621 57 551 53 539 51 520 48 507 45
Preferred
Stock 11 1 10 1 10 1 9 1 8 1
$1,091 100% $1,039 100% $1,061 100% $1,092 100% $1,135 100%
Capital Requirements and Resources
The system's projected capital expenditures for the years 1998 through
2002 are $627.8 million, including $254.7 million for 1998 that consists of
approximately $150 million for Advanced Energy Systems, Inc.'s pending
purchase of a total energy plant that serves the Longwood Medical Area in
Boston (as further discussed below), $60.3 million in construction expendi-
tures, $28.8 million for debt and sinking fund payments, and $15.6 million
related to new business development. These 1998 expenditures will be met
primarily through a combination of long and short-term debt issues ($186.8
million) and internally-generated funds of $67.9 million.
Advanced Energy has reached agreement to purchase the total energy plant
that is owned and operated by Harvard University (MATEP) and provides the
steam, cooling and electric requirements of Harvard's professional schools and
five affiliated teaching hospitals in Boston. The closing for this transac-
tion is expected to occur during the second quarter of 1998. It is projected
that this new venture will increase system revenues by approximately $45
million in 1998 and, on average, by approximately $65 million in the years
1999 through 2002.
The System could also raise capital through the issuance of additional
Common Shares, a new series of Preferred Shares, or through its Dividend
Reinvestment and Common Share Purchase Plan. The System's goal is to maintain
a capital structure that preserves an appropriate balance between debt and
equity. Management believes its capital resources and liquidity are suffi-
cient to meet its current and projected requirements.
<PAGE 25>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The system's capitalization structure is presented below:
1996 1997
(Dollars in thousands)
Long-term debt.... $369,565 40.3% $383,311 41.7%
Preferred shares.. 13,020 1.4 12,200 1.3
Common equity..... 415,694 45.4 430,770 46.8
Short-term debt... 118,475 12.9 94,075 10.2
Total capitalization $916,754 100.0% $920,356 100.0%
Capital Requirements
-------------------------------------------------------------------
Bar graph illustration of
comparative two-year (1996-1997) actual
and five-year (1998-2002) forecast of
capital requirements based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1996 1997 1998 1999 2000 2001 2002
(Dollars in Millions)
Construction-
Electric $ 38 $ 34 $ 41 $ 29 $ 28 $ 25 $ 25
Gas 12 18 18 18 18 19 19
Other 3 5 1 1 1 1 1
Maturing Debt 42 23 29 115 10 11 39
Purchase of MATEP - - 150 - - - -
New Business - - 16 3 3 3 3
$ 95 $ 80 $255 $166 $ 60 $ 59 $ 88
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 System'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.
Industry Restructuring
Electric
On November 25, 1997, the Governor of Massachusetts signed into law the
Electric Industry Restructuring Act (the Act). Provisions of this legislation
include, among other things, a 10 percent discount on standard offer service
<PAGE 26>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
and retail choice of energy supplier effective March 1, 1998, with a subse-
quent increase in the discount on standard offer service of up to 15 percent
upon completion of divestiture of non-nuclear generating assets and securiti-
zation of net non-mitigable stranded costs (which, for the system, are
primarily the result of above-market purchased power contracts with non-
utility generators) and, recovery of stranded costs subject to review and an
audit process.
The system filed a comprehensive electric restructuring plan with the DTE
on November 19, 1997 that was thoroughly reviewed in five separate hearings
that solicited public comment, and seven days of evidentiary hearings that
were completed in February 1998.
Consistent with the Act, the system's plan provides, as of March 1, 1998,
a rate reduction of 10 percent for customers choosing the standard service
transition rate from the average of undiscounted rates in effect during August
1997, divestiture of non-nuclear generating assets and a restructured electric
generation market that is able to offer retail access to all customers. The
system's plan also includes the following provisions: 1) an estimate and
detailed accounting of total transition costs eligible for recovery through a
non-bypassable access or transition charge; 2) a description of the system's
strategies to mitigate transition costs; 3) unbundled rates for generation,
distribution, transmission and other services; 4) proposed charges for the
recovery of transition costs through the non-bypassable transition charge;
5) proposed programs to provide universal service to all customers; 6)
proposed programs and mandatory charges to promote energy conservation and
demand-side management; 7) procedures for ensuring direct retail access to all
electric generation suppliers; 8) discussions of the impact of the plan on the
system's employees and the communities served by the system; and (9) a
mandatory charge per kwh for all consumers to support the development and
promotion of renewable energy projects.
On February 27, 1998, the DTE approved the system's restructuring plan
stating that the plan complies with the Act. While the system is encouraged
with the treatment afforded stranded or transition cost recovery by the
legislation and the DTE, the mandated customer discount could have a signifi-
cant impact on future cash flows.
Auction Process
On March 31, 1997, the system submitted a report to the DTE that detailed
the proposed auction process for selling its electric generation assets and
entitlements. The process included a standard, sealed-bid auction for
generation assets and purchased power contracts. The auction process provides
a market-based approach to maximizing stranded cost mitigation and minimizing
the access charges that ratepayers will have to pay for stranded cost recov-
ery. A request for bids from interested parties was issued during August, and
an Offering Memorandum was issued in October. Potential bidders examined all
pertinent information related to the system's generating facilities and
purchased power agreements in order to prepare and submit their first round of
bids in mid-December. In January 1998, the system selected a short list of
potential bidders, each of whom are expected to submit a final binding bid in
the second quarter of 1998. The entire process, including regulatory approv-
als, is expected to be completed in 1998.
<PAGE 27>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Gas
On July 18, 1997, the DTE directed the ten Massachusetts gas utilities,
including Commonwealth Gas, to initiate a collaborative process that will
establish guiding principles and specific procedures for unbundling rates and
services for all customers.
The DTE listed six principles that it considers important to the success
of a competitive natural gas market that will provide safe and reliable
service at the lowest possible cost to customers. The natural gas market
would: (1) provide the broadest possible choice; (2) provide all customers
with an opportunity to share in the benefits of increased competition; (3)
ensure full and fair competition in the gas supply market; (4) functionally
separate supply from local distribution services; (5) support and further the
goals of environmental regulation; and lastly (6) rely on incentive regulation
where a fully competitive market cannot or presently does not exist.
In addition, the DTE outlined several specific issues that it expects the
collaborative to address: (1) services that can be offered on a competitive
basis; (2) terms and conditions of service; (3) consumer protections and
social programs; (4) mitigation of gas related and non-gas related transition
costs; (5) third-party supplier qualifications; and (6) curtailment princi-
ples. The DTE also suggested that the collaborative reconsider the pricing
and provision of interruptible transportation services.
On August 18, 1997, the DTE noted that the development of unbundling
principles and procedures constitutes only a part of the effort necessary to
develop full customer choice for gas service. The DTE recognized that each
local distribution company will be filing a comprehensive unbundling proposal
at some later date. In the interim, the DTE directed those companies that do
not currently have unbundled rates, including Commonwealth Gas, to have such
rates in effect no later than November 1, 1998.
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, unions, consumer advocates and represen-
tatives for the DTE, the Massachusetts Attorney General, and the Massachusetts
Division of Energy Resources.
On November 15, 1997, the Collaborative filed a status report with the DTE
that outlined its progress in moving the gas industry to a more competitive
structure that provides all customers with meaningful access to competitive
markets consistent with public-policy objectives. The status report summa-
rized the substantive issues that had been the subject of Collaborative
discussion, including: (1) the disposition of interstate pipeline capacity;
(2) the unbundling of rates; (3) customer enrollment, billing, termination,
and information exchange procedures; and, (4) consumer protections, low-income
discounts, and competitive supplier registration. The status report also
established a schedule to implement a final unbundling plan by November 1,
1998.
In accordance with that schedule, the Collaborative submitted with the DTE
<PAGE 28>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
a Rate Unbundling Status Report on January 16, 1998. The report detailed an
overall process for developing unbundled rates consistent with the DTE's rate
structure goals of efficiency, fairness, simplicity, continuity and earnings
stability. In response to the Collaborative's proposal, the DTE ordered
Commonwealth Gas to submit, no later than April 15, 1998, a consensus-based
settlement, or partial settlement, of unbundled rate tariffs designed accord-
ing to the general concepts set forth in the report.
Provisions of Statement of Financial Accounting Standards No. 71
As described in Note 2(b) of the Notes to Consolidated Financial State-
ments, the system follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." In the event the system 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 the system's ability to establish prices to
recover specific costs, and 2) a significant change in the current manner in
which rates are set by regulators. The system monitors these criteria to
ensure that the continuing application of SFAS No. 71 is appropriate. Based
on the current evaluation of the various factors and conditions that are
expected to impact future cost recovery, the system 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, the system's retail
electric companies discontinued application of accounting principles applied
to their investment in electric generation facilities effective March 1, 1998.
The system will not be required to write off any of its generation-related
assets, including regulatory assets. These assets will be 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.
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 1997,
Commonwealth Gas recorded an additional liability and corresponding regulatory
asset of $1.2 million due to an increase in the site clean-up cost estimate
for an MGP site for which Commonwealth Gas was previously cited as a Poten-
tially Responsible Party. The DTE has approved recovery of costs associated
with MGP sites.
Commonwealth Gas and certain other system 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 $2 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. The system is unable to estimate its ultimate
<PAGE 29>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
liability for future environmental remediation costs. However, in view of the
system'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 the system's results of
operations or financial position.
On January 1, 1997, the system 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
disclosure of environmental remediation liabilities in financial statements.
The system has recorded environmental remediation liabilities net of amounts
paid of $2.3 million at December 31, 1997. The adoption of SOP 96-1 did not
have a material adverse effect on the system's results of operations or
financial position.
Year 2000
The system has been involved in the Year 2000 compliancy since 1996. A
complete inventory and review of software, information processing and delivery
systems has been completed, and work continues on computer systems wherever
necessary. While some computer systems have already been updated, tested and
placed in production, the system expects to complete the balance of the
modifications by early 1999.
Expenditures incurred by the system through 1997 to review existing
computer systems and to modify existing software and applications amounted to
nearly $900,000, and it is estimated that approximately $2.6 million will be
incurred in 1998 and 1999.
Management believes that, with appropriate modifications, the system will
be fully compliant regarding all Year 2000 issues and will continue to provide
its products and services uninterrupted through the millennium change.
Failure to become fully compliant could have a significant impact on the
system's operations.
New Accounting Principles
During 1997, the Financial Accounting Standards Board issued two new
accounting standards that the system will adopt in 1998. SFAS No. 130,
"Reporting Comprehensive Income" will require disclosure on comprehensive
income and its components. SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information" will require disclosure of financial and
descriptive information on reportable operating segments. The adoption of
these standards is not expected to have a material impact on the system's
results of operations or financial position.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed
herewith on pages 30 through 52 of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
<PAGE 30>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT
The consolidated financial statements presented herein are representa-
tions of the management of Commonwealth Energy System. Management recognizes
its responsibility for the preparation and presentation of financial state-
ments in conformity with generally accepted accounting principles. To fulfill
this responsibility, management maintains a system of internal accounting
controls, including established policies and procedures and a comprehensive
internal auditing program to evaluate the adequacy and effectiveness of
accounting and operating controls, compliance with system policies and
procedures and the safeguarding of system assets.
The responsibility of our independent auditors' examination is limited
to the expression of an opinion as to the fairness of the consolidated
financial statements presented. The independent auditors are selected by the
Board of Trustees and report their findings thereto through the Audit Commit-
tee, which is comprised of three outside Trustees. The Board of Trustees is
responsible for ensuring that both the independent auditors and management
fulfill their respective responsibilities as they pertain to these consolidat-
ed financial statements.
James D. Rappoli,
Financial Vice President
and Treasurer
March 2, 1998.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees of Commonwealth Energy System:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of COMMONWEALTH ENERGY SYSTEM (the
System) (a Massachusetts trust) and subsidiary companies as of December 31,
1997 and 1996, and the related consolidated statements of income, cash flows,
changes in common shareholders' investment and changes in redeemable preferred
shares for each of the three years in the period ended December 31, 1997.
These consolidated financial statements are the responsibility of the System
and subsidiary companies' management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Common-
wealth Energy System and subsidiary companies as of December 31, 1997 and
1996, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1997, in conformity with general-
ly accepted accounting principles.
Arthur Andersen LLP
Boston, Massachusetts
February 19, 1998 (except with respect to certain matters discussed in Note 2,
as to which the date is March 2, 1998).
<PAGE 31>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Consolidated Statements of Income for the Years Ended December 31, 1997,
1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Balance Sheets at December 31, 1997 and 1996
Consolidated Statements of Capitalization for the Years Ended December
31, 1997, 1996 and 1995
Consolidated Statements of Changes in Common Shareholders' Investment
for the Years Ended December 31, 1997, 1996 and 1995
Consolidated Statements of Changes in Redeemable Preferred Shares for
the Years Ended December 31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements
PART IV.
SCHEDULES
I Investments in, Equity in Earnings of, and Dividends Received
from Related Parties for the Years Ended December 31, 1997, 1996
and 1995
II Valuation and Qualifying Accounts for the Years Ended December 31,
1997, 1996 and 1995
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or
not required or because the required information is included in the
financial statements or notes thereto.
<PAGE 32>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(Dollars in thousands except per share amounts)
1997 1996 1995
Operating Revenues
Electric $ 688,508 $ 649,678 $604,980
Gas 333,977 341,867 306,953
Steam and other 19,259 19,360 17,355
1,041,744 1,010,905 929,288
Operating Expenses
Fuel used in electric production,
principally oil 129,021 91,690 57,820
Electricity purchased for resale 265,805 265,019 274,795
Cost of gas sold 184,122 187,530 158,835
Other operation 225,658 215,319 206,280
Maintenance 36,838 40,913 38,414
Depreciation 53,405 51,782 48,170
Taxes-
Local property 19,130 18,049 17,573
Income 31,040 36,099 24,574
Payroll and other 9,075 7,839 8,284
954,094 914,240 834,745
Operating Income 87,650 96,665 94,543
Other Income 2,601 4,878 1,461
Income Before Interest Charges 90,251 101,543 96,004
Interest Charges
Long-term debt 33,572 35,586 38,581
Other interest charges 6,778 6,782 6,027
40,350 42,368 44,608
Net Income 49,901 59,175 51,396
Dividends on preferred shares 988 1,050 1,110
Earnings Applicable to Common Shares $ 48,913 $ 58,125 $ 50,286
Average Number of Common Shares
Outstanding 21,531,433 21,529,676 21,311,836
Earnings Per Common Share $2.27 $2.70 $2.36
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 33>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(Dollars in thousands)
1997 1996
Assets
Property, Plant and Equipment, at original cost
Electric $1,173,797 $1,150,818
Gas 373,541 357,403
Other 72,475 66,365
1,619,813 1,574,586
Less-Accumulated depreciation and amortization 577,962 536,041
1,041,851 1,038,545
Construction work in progress 7,864 5,485
Nuclear fuel in process 193 1,597
1,049,908 1,045,627
Equity in Corporate Joint Ventures
Nuclear electric power companies (2.5% to 4.5%) 10,368 10,046
Other investments 3,399 3,349
13,767 13,395
Current Assets
Cash 4,299 1,495
Accounts receivable, less reserves of $9,408 in
1997 and $8,324 in 1996 128,946 117,008
Unbilled revenues 32,029 31,698
Inventories, at average cost-
Electric production fuel oil 1,902 2,221
Natural gas 23,301 23,084
Materials and supplies 7,441 6,220
Prepaid taxes 9,282 9,079
Other 5,786 5,686
212,986 196,491
Deferred Charges
Regulatory assets 178,864 154,291
Other 29,525 19,151
208,389 173,442
$1,485,050 $1,428,955
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 34>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(Dollars in thousands)
1997 1996
Capitalization and Liabilities
Capitalization (See separate statement)
Common share investment $ 430,770 $ 415,694
Redeemable preferred shares, less current
sinking fund requirements 12,200 13,020
Long-term debt, less current sinking fund
requirements and maturing debt 364,311 355,305
807,281 784,019
Capital Lease Obligations 12,272 12,346
Current Liabilities
Interim Financing-
Notes payable to banks 94,075 118,475
Maturing long-term debt 19,000 14,260
113,075 132,735
Other Current Liabilities-
Current sinking fund requirements 8,473 8,473
Accounts payable 107,157 90,269
Accrued taxes-
Local property and other 9,795 9,060
Income 14,410 7,910
Accrued interest 6,778 6,267
Dividends declared 8,517 8,289
Other 43,627 39,279
198,757 169,547
311,832 302,282
Deferred Credits
Accumulated deferred income taxes 176,354 174,877
Nuclear units' purchased power contracts 69,659 43,677
Unamortized investment tax credits 25,340 26,618
Other 82,312 85,136
353,665 330,308
Commitments and Contingencies
$1,485,050 $1,428,955
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 35>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(Dollars in thousands)
1997 1996 1995
Operating Activities
Net income $ 49,901 $ 59,175 $ 51,396
Effects of noncash items-
Depreciation and amortization 65,646 63,331 60,555
Deferred income taxes, net 2,542 3,515 4,182
Investment tax credits, net (1,278) (1,285) (1,401)
Earnings from corporate joint ventures (1,348) (1,557) (1,633)
Dividends from corporate joint ventures 1,272 1,376 2,067
Change in working capital, exclusive of cash-
Accounts receivable and unbilled revenues (12,269) (9,446) (13,626)
Prepaid (accrued) income taxes 6,500 (14,097) 14,353
Prepaid (accrued) local property and
other taxes 532 (555) (950)
Accounts payable and other 20,756 (33,956) 25,199
Power contract buy-out - - (25,500)
Fuel charge stabilization deferral, net (5,543) 2,372 (3,447)
Deferred postretirement benefits costs (2,126) (2,157) (4,479)
FERC Order 636 transition costs, net - - 11,390
All other operating items (17,034) (3,391) 6,565
Net cash provided by operating activities 107,551 63,325 124,671
Investing Activities
Additions to property, plant and
equipment (inclusive of AFUDC)-
Electric (34,524) (38,844) (61,643)
Gas (18,230) (11,611) (16,198)
Other (4,804) (2,730) (3,659)
Net cash used for investing activities (57,558) (53,185) (81,500)
Financing Activities
Sale of common shares - 32 9,534
Payment of dividends (35,056) (34,205) (33,142)
Proceeds from (payment of) short-term
borrowings, net (24,400) 62,875 10,750
Long-term debt issues 35,000 - -
Retirement of long-term debt and preferred
shares through sinking funds (8,473) (8,436) (8,716)
Long-term debt issues refunded (14,260) (33,230) (25,000)
Net cash used for financing activities (47,189) (12,964) (46,574)
Net increase (decrease) in cash 2,804 (2,824) (3,403)
Cash at beginning of period 1,495 4,319 7,722
Cash at end of period $ 4,299 $ 1,495 $ 4,319
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of capitalized amounts) $ 38,201 $ 41,294 $ 42,051
Income taxes $ 24,436 $ 46,563 $ 12,918
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 36>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1997 AND 1996
(Dollars in thousands)
1997 1996
Common Share Investment
Common shares, $2 par value-
Authorized-50,000,000 shares
Outstanding-21,531,784 shares in 1997
and 21,529,676 shares in 1996 $ 43,063 $ 43,059
Amounts paid in excess of par value 111,912 111,685
Retained earnings 275,795 260,950
Total common share investment 430,770 415,694
Redeemable Preferred Shares,
Cumulative, $100 Par Value
Series A, 4.80% 2,520 2,640
Series B, 8.10% 3,840 4,000
Series C, 7.75% 6,660 7,200
Less-Current sinking fund requirements (820) (820)
Total redeemable preferred shares 12,200 13,020
Long-term Debt
System
Senior Notes due-
1997, 10.48% - 10,000
1998, 10.45% 10,000 10,000
1999, 10.58% 10,000 10,000
Less-Maturing long-term debt (10,000) (10,000)
Total System long-term debt 10,000 20,000
Subsidiary companies
Mortgage Bonds, collateralized by property of
operating subsidiaries, due-
2001, 8.99% 14,450 18,100
2006, 8.85% 34,300 34,650
2007, 6.54% 10,000 -
2017, 7.04% 25,000 -
2020, 7 3/8% 10,000 10,000
2020, 9 7/8% 40,000 40,000
2020, 9.95% 25,000 25,000
2033, 7.11% 35,000 35,000
Notes due-
1997, 6 1/4% - 4,260
1998, variable rate (6.391% in 1997 and
6.125% in 1996) 9,000 9,000
1999, 8.04% 10,000 10,000
2002, 7 3/4% 2,500 2,600
2002, 9.30% 30,000 30,000
2003, 7.43% 15,000 15,000
2004, 9.50% 10,000 12,500
2007, 8.70% 5,000 5,000
2007, 9.55% 10,000 10,000
2008, 7.70% 10,000 10,000
2012, 9.37% 15,789 16,842
2013, 7.98% 25,000 25,000
2014, 9.53% 10,000 10,000
2019, 9.60% 10,000 10,000
2023, 8.47% 15,000 15,000
Less-Maturing long-term debt (9,000) (4,260)
Current sinking fund requirements (7,653) (7,653)
Unamortized discount, net (75) (734)
Total subsidiary companies' long-term debt 354,311 335,305
Total long-term debt 364,311 355,305
Total capitalization $807,281 $784,019
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 37>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' INVESTMENT
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Amounts
Par Paid in
Value Excess
$2 Per of Par Retained
Shares Share Value Earnings Total
(Dollars in thousands)
Balance December 31, 1994 21,051,794 $42,103 $103,168 $217,726 $362,997
Add (Deduct)-
Net income - - - 51,396 51,396
Sale of shares 476,474 953 8,581 - 9,534
Cash dividends declared-
Common shares-$1.50 per share - - - (32,032) (32,032)
Preferred shares - - - (1,110) (1,110)
Balance December 31, 1995 21,528,268 43,056 111,749 235,980 390,785
Add (Deduct)-
Net income - - - 59,175 59,175
Sale of shares 1,408 3 29 - 32
Cost of stock split - - (93) - (93)
Cash dividends declared-
Common shares-$1.54 per share - - - (33,155) (33,155)
Preferred shares - - - (1,050) (1,050)
Balance December 31, 1996 21,529,676 43,059 111,685 260,950 415,694
Add (Deduct)-
Net income - - - 49,901 49,901
Shares issued pursuant to
Long-Term Incentive
Compensation Plan 2,108 4 43 - 47
Amortization of deferred
compensation - - 184 - 184
Cash dividends declared-
Common shares-$1.58 per share - - - (34,068) (34,068)
Preferred shares - - - (988) (988)
Balance December 31, 1997 21,531,784 $43,063 $111,912 $275,795 $430,770
Consolidated Statements of Changes in Redeemable Preferred Shares
Commonwealth Energy System and Subsidiary Companies
For the Years Ended December 31, 1997, 1996 and 1995
Authorized and Outstanding
Cumulative Preferred Shares-$100 Par Value
Series A Series B Series C Total
4.80% 8.10% 7.75% Shares
Balance December 31, 1994 28,800 43,200 82,800 154,800
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1995 27,600 41,600 77,400 146,600
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1996 26,400 40,000 72,000 138,400
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1997 25,200 38,400 66,600 130,200
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 38>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) General Information
Commonwealth Energy System (the System) is an exempt public utility
holding company with investments in four operating public utility companies
located in central, eastern and southeastern Massachusetts. The System is the
parent company and, together with its subsidiaries, is collectively referred
to as "the system." System electric operations are involved in the produc-
tion, distribution and sale of electricity to 367,000 customers in 41 communi-
ties including New Bedford, Plymouth, Cambridge and the geographic area
comprising Cape Cod. Gas operations serve 237,000 customers in 49 communities
including New Bedford, Cambridge, Plymouth and Worcester. In addition to the
utility companies, the system includes a steam distribution company, five real
estate trusts, a company engaged in the operation of LNG facilities and three
new subsidiaries that are pursuing energy-related business opportunities.
The system has 1,727 regular employees including 1,037 (60%) represented
by various collective bargaining units. A contract with a collective bargain-
ing unit representing approximately 5% of regular employees that was scheduled
to expire in May 1997 was ratified in April 1997 and is effective through May
31, 2001. In April 1998, a collective bargaining contract representing
approximately 5% of regular employees is scheduled to expire and two addition-
al contracts (together representing approximately 7% of regular employees) are
scheduled to expire in September 1998.
During the second quarter of 1997, the system initiated a voluntary
personnel reduction program. As a result of this program, the total number of
regular employees has declined by approximately 13% in 1997.
(2) Significant Accounting Policies
(a) Principles of Consolidation and Accounting
The consolidated financial statements include the accounts of the System
and all of its subsidiary companies. All significant intercompany accounts
and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
The system's operating utility companies are regulated as to rates,
accounting and other matters by various authorities, including the Federal
Energy Regulatory Commission (FERC) and the Massachusetts Department of
Telecommunications and Energy (DTE), formerly the Massachusetts Department of
Public Utilities.
Based on the current regulatory framework, the system accounts for the
economic effects of regulation in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." Regulated subsidiaries of the System have
established various regulatory assets in cases where the DTE and/or the FERC
have permitted or are expected to permit recovery of specific costs over time.
Similarly, the regulatory liabilities established by the system are required
to be refunded to customers over time. In the event the criteria for applying
SFAS No. 71 are no longer met, the accounting impact would be an extra-
ordinary, non-cash charge to operations of an amount that could be material.
<PAGE 39>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Criteria that give rise to the discontinuance of SFAS No. 71 include: 1)
increasing competition that restricts the system's ability to establish prices
to recover specific costs, and 2) a significant change in the current manner
in which rates are set by regulators from cost based regulation to another
form of regulation. These criteria are reviewed on a regular basis to ensure
the continuing application of SFAS No. 71 is appropriate. Based on the
current evaluation of the various factors and conditions that are expected to
impact future cost recovery, the system believes that its regulatory assets,
including those related to generation, are probable of future recovery.
As a result of electric industry restructuring, the system's retail
electric companies discontinued application of accounting principles applied
to their investment in electric generation facilities effective March 1, 1998.
The system will not be required to write off any of its generation-related
assets, including regulatory assets. These assets will be 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
a non-bypassable transition charge.
Effective January 1, 1996, the system adopted SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." SFAS No. 121 imposes stricter criteria for regulatory assets by
requiring that such assets be probable of future recovery at each balance
sheet date. SFAS No. 121 did not have an impact on the system's financial
position or results of operations upon adoption.
The principal regulatory assets included in deferred charges at December
31, 1997 and 1996 were as follows:
1997 1996
(Dollars in thousands)
Postretirement benefit costs $ 25,475 $ 25,051
Power contract buy-out 17,609 20,794
Fuel charge stabilization 29,655 21,504
Deferred income taxes 13,089 13,597
FERC Order 636 transition costs 7,336 9,680
Maine Yankee unrecovered plant and
decommissioning costs 34,908 -
Connecticut Yankee unrecovered plant and
decommissioning costs 28,566 35,879
Yankee Atomic unrecovered plant and
decommissioning costs 6,184 7,798
Seabrook related costs 4,324 6,262
Other 11,718 13,726
$178,864 $154,291
The regulatory liabilities, reflected in the accompanying Consolidated
Balance Sheets and related primarily to deferred income taxes, were $14.1
million and $17.7 million at December 31, 1997 and 1996, respectively.
As of December 31, 1997, $143.1 million of the system's regulatory
assets, including the costs associated with existing power contracts with
three Yankee nuclear power plants that have shut down permanently (see Note
3(d)), and all of its regulatory liabilities are reflected in rates charged to
customers. Regulatory assets are currently being recovered over a weighted
average period of approximately 11 years. The fuel charge stabilization
deferral was expected to be recovered over a six-year period beginning in
April 1998, pursuant to a yet to be determined recovery schedule and subject
to final DTE approval.
In November 1997, the Commonwealth of Massachusetts enacted a comprehen-
sive electric utility industry restructuring bill. On November 19, 1997, the
System's electric subsidiaries filed a restructuring plan with the DTE. The
plan, approved by the DTE on February 27, 1998, describes the process by which
the System's retail electric subsidiaries will, beginning March 1, 1998,
initiate a ten percent rate reduction for all customer classes and allow
<PAGE 40>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
customers to choose their energy supplier. As part of the plan, the DTE
authorized the recovery of certain strandable costs. The legislation gives
the DTE the authority to determine the amount of strandable costs that will be
eligible for recovery. Costs that will qualify as strandable costs and be
eligible for recovery include, but are not limited to, certain above market
costs associated with generating facilities, costs associated with long-term
commitments to purchase power at above market prices from independent power
producers and regulatory assets and associated liabilities related to the
generation portion of the electric business.
The cost of transitioning to competition will be mitigated, in part,
through the divestiture of the system's non-nuclear generating assets in an
auction process that is expected to be completed in 1998. Any net proceeds in
excess of book value received from the divestiture of these assets will be
used to mitigate stranded costs.
The system's ability to recover its stranded costs will depend on
several factors, including the aggregate amount of stranded costs the system
will be allowed to recover and the market price of electricity. Management
believes that the system will recover its stranded costs. A change in any of
the above listed factors or in the current legislation could affect the
recovery of stranded costs and may result in a loss to the system. For
additional information relating to industry restructuring, see the "Industry
Restructuring - Electric" section under Management's Discussion and Analysis
of Financial Condition and Results of Operations.
(c) Equity Method of Accounting
The system uses the equity method of accounting for investments in
corporate joint ventures due, in part, to its ability to exercise significant
influence over operating and financial policies of these entities. Under this
method, it records as income the proportionate share of the net earnings of
the joint ventures with a corresponding increase in the carrying value of the
investment. The investment is reduced as cash dividends are received. The
system conducts business with the corporate joint ventures in which it has
investments, principally four nuclear generating facilities located in New
England and a 3.8% interest in Hydro-Quebec Phase II.
(d) Operating Revenues
Customers are billed for their use of electricity and gas on a cycle
basis throughout the month. To reflect revenues in the proper period, the
estimated amount of unbilled sales revenue is recorded each month.
System utility companies are generally permitted to bill customers for
costs associated with purchased power and transmission, fuel used in electric
production, gas, conservation and load management and environmental costs.
The amount of such costs incurred but not yet reflected in customers' bills is
recorded as unbilled revenues.
(e) Depreciation
Depreciation is provided using the straight-line method at rates
intended to amortize the original cost and the estimated cost of removal less
salvage of properties over their estimated economic lives. The average
composite depreciation rates were as follows:
1997 1996 1995
Electric 3.66% 3.65% 3.52%
Gas 2.95 2.94 2.90
Steam 3.80 3.89 3.91
LNG 3.65 3.59 3.20
<PAGE 41>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(f) Allowance for Funds Used During Construction
Under applicable rate-making practices, system companies are permitted
to include an allowance for funds used during construction (AFUDC) as an
element of their depreciable property costs. This allowance is based on the
amount of construction work in progress that is not included in the rate base
on which utility companies earn a return. An amount equal to the AFUDC
capitalized in the current period is reflected in other interest charges in
the accompanying Consolidated Statements of Income and amounted to $368,000,
$257,000 and $857,000 in 1997, 1996 and 1995, respectively.
While AFUDC does not provide funds currently, these amounts are recover-
able in revenues over the service life of the constructed property. The
amount of AFUDC recorded was at a weighted average rate of 6.1% in 1997, 6.2%
in 1996 and 7.1% in 1995.
(g) Earnings Per Share
The System adopted SFAS No. 128 "Earnings Per Share" for the year ended
December 31, 1997. SFAS No. 128 requires the presentation of both basic and
diluted earnings per share (EPS). Diluted EPS reflect the possible impact on
EPS that could occur if securities or other contracts to issue common stock
were exercised or converted into common stock or resulted in the issuance of
common stock that then shared in the earnings of the entity. The System
granted potential awards in the form of common shares to certain key employees
pursuant to its Long Term Incentive Compensation Plan (see Note 5(d)) during
the first quarter of 1997. The adoption of SFAS No. 128 did not have a
material impact on the System's EPS.
(3) Commitments and Contingencies
(a) Capital Expenditures
The system is engaged in a continuous construction program presently
estimated at $248.6 million for the five-year period 1998 through 2002. Of
that amount, $60.7 million is estimated for 1998. The program is subject to
periodic review and revision.
The system, through its Advanced Energy Systems, Inc. subsidiary,
tentatively agreed to purchase a total energy plant located in the Longwood
Medical Area of Boston for $146.3 million. This transaction is expected to be
closed in the second quarter of 1998. Revenues for fiscal years ended June
30, 1997 and 1996 were $58 million and $53.9 million, respectively.
(b) Seabrook Nuclear Power Plant
The system's 3.52% interest in the Seabrook nuclear power plant is owned
by Canal Electric Company (Canal Electric), a wholesale electric generating
subsidiary, to provide for a portion of the capacity and energy needs of
affiliates Cambridge Electric Light Company (Cambridge Electric) and Common-
wealth Electric Company (Commonwealth Electric). Canal Electric is recovering
100% of its Seabrook 1 investment through a power contract with Cambridge
Electric and Commonwealth Electric pursuant to FERC and DTE approval.
<PAGE 42>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Pertinent information with respect to Canal Electric's joint-ownership
interest in Seabrook 1 and information relating to operating expenses that are
included in the accompanying financial statements are as follows:
1997 1996
(Dollars in thousands)
Utility plant-in-
service $232,471 $232,183 Plant capacity (MW) 1,150
Nuclear fuel 22,207 21,613 Canal Electric's share:
Accumulated depreciation Percent interest 3.52%
and amortization (64,379) (57,359) Entitlement (MW) 40.5
Construction work in In-service date 1990
progress 1,036 844 Operating license
$191,335 $197,281 expiration date 2026
1997 1996 1995
(Dollars in thousands)
Operating expenses:
Fuel $ 1,471 $ 1,727 $ 2,353
Other operation 4,206 4,091 4,292
Maintenance 2,364 990 1,376
Depreciation 6,314 6,544 6,542
Amortization 1,319 1,319 1,319
$15,674 $14,671 $15,882
Canal Electric and the other joint owners have established a decommis-
sioning fund to cover decommissioning costs. The estimated cost to decommis-
sion the plant is $469.1 million in current dollars. Canal Electric's share
of this liability (approximately $16.5 million), less its share of the market
value of the assets held in a decommissioning trust (approximately $2.5
million), is approximately $14 million at December 31, 1997.
(c) Price-Anderson Act
Under the Price-Anderson Act (the Act), owners of nuclear power plants
have the benefit of approximately $8.9 billion of public liability coverage
which would compensate the public for valid bodily injury and property loss on
a no fault basis in the event of an accident at a commercial nuclear power
plant. Under the provisions of the Act, each nuclear reactor with an operat-
ing license can be assessed up to $79.3 million per nuclear incident with a
maximum assessment of $10 million per incident within one calendar year.
Nuclear plant owners have initiated insurance programs designed to help cover
liability claims relating to property damage, decontamination, replacement
power and business interruption costs for participating utilities arising from
a nuclear incident.
The system has an equity ownership interest in four nuclear generating
facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The
operators of these units maintain nuclear insurance coverage (on behalf of the
owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II)
and the combined American Nuclear Insurers/Mutual Atomic Energy Liability
Underwriters (ANI). NEIL II provides $2.25 billion of property, boiler,
machinery and decontamination insurance coverage, including accidental
premature decommissioning insurance in the amount of the shortfall in the
Decommissioning Trust Fund, in excess of the underlying $500 million policy.
All companies insured with NEIL II are subject to retroactive assessments if
losses exceed the accumulated funds available. ANI provides $500 million of
"all risk" property damage, boiler, machinery and decontamination insurance.
An additional $200 million of primary financial protection coverage is
provided for off-site bodily injury or property damage caused by a nuclear
incident. ANI also provides secondary financial protection liability insur-
ance which currently provides $8.7 billion of retrospective insurance premium
benefits in accordance with the provisions of the Act. Additional coverage
($200 million) provided by ANI includes tort liability protection arising out
<PAGE 43>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
of radiation injury claims by nuclear workers and injury or property damage
caused by the transportation or shipment of nuclear materials or waste.
Based on its various ownership interests in the five nuclear generating
facilities, the system's retrospective premium could be as high as $1.9
million annually or a cumulative total of $15.1 million, exclusive of the
effect of inflation indexing (at five-year intervals) and a 5% surcharge ($4
million) in the event that total public liability claims from a nuclear
incident exceed the funds available to pay such claims.
(d) Power Contracts
The system has long-term contracts to purchase capacity from various
generating facilities. Generally, these contracts are for fixed periods and
require payment of a demand charge for the capacity entitlement and an energy
charge to cover the cost of fuel. Information relative to these contracts is
as follows:
Range of
Contract
Expiration Entitlement Cost
Dates % MW 1997 1996 1995
(Dollars in thousands)
Type of Unit
Natural gas 2008-2017 (a) 208.6 $127,580 $120,842 $121,636
Nuclear 2012 (b) 85.1 41,058 41,280 44,379
Waste-to-energy 2015 100.0 67.0 43,038 39,622 37,526
Hydro 2014-2023 100.0 23.9 10,952 12,537 9,933
Total 384.6 $222,628 $214,281 $213,474
(a) Includes contracts to purchase power from various non-utility generators
with capacity entitlements ranging from 11.1% to 100%.
(b) The system has an 11% entitlement in the Pilgrim nuclear power plant and
a 2.5% ownership interest in the Vermont Yankee nuclear power plant.
The estimated cost to decommission this plant is $385.9 million in
current dollars. The system's share of this liability (approximately
$8.7 million), less its share of the market value of the assets held in
a decommissioning trust (approximately $4.4 million), is approximately
$4.3 million at December 31, 1997.
Pertinent information with respect to life-of-the-unit contracts with
nuclear units that are no longer operating in which the system has an equity
ownership is as follows:
Connecticut Maine Yankee
Yankee Yankee Atomic
(Dollars in thousands)
Equity Ownership (%) 4.50 4.00 4.50
Plant Entitlement (%) 4.50 3.59 4.50
Contract Expiration Date 2007 2008 2000
Year of Shutdown 1996 1997 1992
1995 Actual Cost ($) 9,498 7,376 2,023
1996 Actual Cost ($) 9,259 6,511 2,260
1997 Actual Cost ($) 5,760 8,928 2,238
Decommissioning cost estimate (100%) ($) 437,270 386,046 137,428
System's decommissioning cost ($) 19,677 13,859 6,184
Market value of assets (100%) ($) 209,448 199,457 134,143
System's market value of assets ($) 9,425 7,161 6,036
Based upon regulatory precedent, the operators of the Yankee units
believe they will be permitted to continue to collect from power purchasers
(including system companies) decommissioning costs, unrecovered plant invest-
ment and other costs associated with the permanent closure of these plants
over the remaining period of each plant's operating license. The system does
<PAGE 44>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
not believe that the ultimate outcome of the early closing of these plants
will have a material adverse effect on its operations and believes that
recovery of these FERC-approved costs would continue to be allowed in its
rates at the retail level.
Costs pursuant to these power contracts are included in electricity
purchased for resale in the accompanying Consolidated Statements of Income and
are recoverable in revenues.
The estimated aggregate obligations for capacity under the long-term
purchased power contracts and a life-of-the-unit contract from the one
remaining operating Yankee nuclear unit (Vermont Yankee) in effect for the
five years subsequent to 1997 is as follows:
Long-Term
Purchased Equity Owned
Power Nuclear Unit Total
(Dollars in thousands)
1998 $219,909 $4,957 $224,866
1999 223,490 5,001 228,491
2000 225,513 4,311 229,824
2001 233,576 4,806 238,382
2002 235,228 4,996 240,224
Due to changing conditions within the nuclear industry, it is possible
that the remaining operating nuclear plant in which the system has an equity
ownership interest could be shut down prior to the expiration of that unit's
operating license.
The costs associated with these power contract obligations are a
significant component of the system's stranded costs that are included in the
system's restructuring plan approved by the DTE.
(e) Environmental Matters
The system is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment. These
laws and regulations affect, among other things, the siting and operation of
electric generating and transmission facilities and can require the installa-
tion of expensive air and water pollution control equipment. These regula-
tions have had an impact on the system's operations in the past and would
continue to have an impact on future operations, capital costs and construc-
tion schedules of major facilities; however, the electric generating facili-
ties are likely to be sold at auction in 1998 pursuant to the restructuring
plan filed with the DTE. For additional environmental information, see
"Environmental Matters" in Management's Discussion and Analysis of Financial
Condition and Results of Operations.
(4) Income Taxes
The system files a consolidated federal income tax return. For finan-
cial reporting purposes, the System and its subsidiaries provide taxes on a
separate return basis.
<PAGE 45>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The following is a summary of the consolidated provisions for income
taxes for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995
(Dollars in thousands)
Federal
Current $24,396 $28,375 $15,954
Deferred 2,612 2,784 8,231
Investment tax credits, net (1,278) (1,285) (1,401)
25,730 29,874 22,784
State
Current 5,389 5,542 4,176
Deferred 316 890 1,115
5,705 6,432 5,291
31,435 36,306 28,075
Amortization of regulatory liability
relating to deferred income taxes (386) (159) (5,164)
$31,049 $36,147 $22,911
Federal and state income taxes
charged to:
Operating expense $31,040 $36,099 $24,574
Other (income) expense 9 48 (1,663)
$31,049 $36,147 $22,911
Deferred tax liabilities and assets are determined based on the differ-
ence between the financial statement and tax bases of assets and liabilities
using enacted tax rates in effect in the year in which the differences are
expected to reverse.
In May 1995, Canal Electric refunded certain unprotected excess deferred
taxes to Commonwealth Electric and Cambridge Electric resulting in a reduction
to the 1995 tax provision.
Accumulated deferred income taxes consisted of the following in 1997 and
1996:
1997 1996
(Dollars in thousands)
Liabilities
Property-related $198,183 $195,810
Power contract buy-out 6,853 10,002
Fuel charge stabilization 12,241 8,124
Postretirement benefits plan 7,742 7,442
Seabrook nonconstruction 707 1,183
All other 16,140 20,018
241,866 242,579
Assets
Investment tax credits 16,058 17,205
Pension plan 6,409 8,528
Regulatory liability 6,103 6,352
Personnel reduction program 1,540 -
All other 20,960 22,239
51,070 54,324
Accumulated deferred income taxes, net $190,796 $188,255
The net year-end deferred income tax liability above includes a current
deferred tax liability of $14,442,000 and $13,378,000 in 1997 and 1996,
respectively, which are included in accrued income taxes in the accompanying
Consolidated Balance Sheets.
The total income tax provision set forth previously represents 38% in
1997 and 1996 and 31% in 1995 of income before such taxes. The following
table reconciles the statutory federal income tax rate to these percentages:
<PAGE 46>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
1997 1996 1995
(Dollars in thousands)
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory
levels $28,332 $33,363 $26,007
Increase (Decrease) from statutory levels:
State tax net of federal tax benefit 3,708 4,181 3,439
Tax versus book depreciation 1,714 1,553 1,369
Amortization of investment tax credits (1,278) (1,285) (1,368)
Reversals of capitalized expenses (654) (654) (652)
Dividend received deduction (366) (381) (389)
Amortization of excess deferred reserves (386) (159) (5,164)
Other (21) (471) (331)
$31,049 $36,147 $22,911
Effective federal income tax rate 38% 38% 31%
(5) Employee Benefit Plans
(a) Pension
The system has a noncontributory pension plan covering substantially all
regular employees who have attained the age of 21 and have completed a year of
service. Pension benefits are based on an employee's years of service and
compensation. The system makes monthly contributions to the plan consistent
with the funding requirements of the Employee Retirement Income Security Act
of 1974.
Components of pension expense and related assumptions to develop pension
expense were as follows:
1997 1996 1995
(Dollars in thousands)
Service cost $ 7,565 $ 7,663 $ 6,386
Interest cost 24,824 24,462 23,949
Return on plan assets-(gain)/loss (61,094) (45,961) (62,933)
Net amortization and deferral 37,540 24,520 42,928
Total pension expense 8,835 10,684 10,330
Less: Amounts capitalized
and deferred 3,017 2,203 1,842
Net pension expense $ 5,818 $ 8,481 $ 8,488
Discount rate 7.50% 7.25% 8.50%
Assumed rate of return 8.75 8.75 9.00
Rate of increase in future
compensation 4.25 4.25 5.00
Pension expense reflects the use of the projected unit credit method
which is also the actuarial cost method used in determining future funding of
the plan. Commonwealth Electric and Cambridge Electric, in accordance with
current ratemaking, are deferring the difference between pension contribution
which is reflected in base rates, and pension expense. The funded status of
the system's pension plan (using a measurement date of December 31) is as
follows:
<PAGE 47>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
1997 1996
(Dollars in thousands)
Accumulated benefit obligation:
Vested $(331,170) $(254,888)
Nonvested (40,822) (30,604)
$(371,992) $(285,492)
Projected benefit obligation $(409,039) $(340,850)
Plan assets at fair market value 390,625 343,884
Projected benefit obligation less
or (greater) than plan assets (18,414) 3,034
Unamortized transition obligation 6,429 8,036
Unrecognized prior service cost 11,922 13,357
Unrecognized gain (20,480) (43,918)
Accrued pension liability $ (20,543) $ (19,491)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1997 1996
Discount rate 7.00% 7.50%
Rate of increase in future compensation 3.75 4.25
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years.
(b) Other Postretirement Benefits
Certain employees are eligible for postretirement benefits if they meet
specific requirements. These benefits could include health and life insurance
coverage and reimbursement of Medicare Part B premiums. Under certain
circumstances, eligible employees are required to make contributions for
postretirement benefits.
To fund its postretirement benefits, the system makes contributions to
various voluntary employees' beneficiary association trusts that were estab-
lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code).
The system also makes contributions to a subaccount of its pension plan
pursuant to section 401(h) of the Code to fund a portion of its postretirement
benefit obligation. The system contributed approximately $12.2 million, $13.7
million and $14 million to these trusts during 1997, 1996 and 1995, respec-
tively.
The net periodic postretirement benefit cost for the years ended
December 31, 1997, 1996 and 1995 includes the following components and related
assumptions:
1997 1996 1995
(Dollars in thousands)
Service cost $ 1,919 $ 2,211 $ 1,774
Interest cost 9,223 9,352 9,022
Return on plan assets (9,483) (5,176) (5,796)
Amortization of transition obligation
over 20 years 5,336 5,336 5,336
Net amortization and deferral 5,236 2,038 3,692
Total postretirement benefit cost 12,231 13,761 14,028
Less: Amounts capitalized and deferred 466 1,614 5,898
Net postretirement benefit cost $11,765 $12,147 $ 8,130
Discount rate 7.50% 7.25% 8.50%
Assumed rate of return 8.75 8.75 9.00
Rate of increase in future compensation 4.25 4.25 5.00
<PAGE 48>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The funded status of the system's postretirement benefit plan using a
measurement date of December 31, 1997 and 1996 is as follows:
1997 1996
(Dollars in thousands)
Accumulated postretirement benefit obligation:
Retirees $(102,485) $ (72,827)
Fully eligible active plan participants (18,123) (11,468)
Other active plan participants (28,756) (41,352)
(149,364) (125,647)
Plan assets at fair market value 61,632 45,967
Accumulated postretirement benefit obligation
greater than plan assets (87,732) (79,680)
Unamortized transition obligation 80,033 85,368
Unrecognized (gain) loss 7,699 (5,688)
$ - $ -
The following actuarial assumptions were used in determining the plan's
estimated accumulated postretirement benefit obligation (APBO) and funded
status for 1997 and 1996:
1997 1996
Discount rate 7.00% 7.50%
Rate of increase in future compensation 3.75 4.25
Medicare Part B premiums 3.10 9.50
Medical care 6.75 7.00
Dental care 4.50 5.00
The above dental rate remains constant through the year 2007. Rates for
Medicare Part B premiums and medical care decrease to 3.1% and 4.5%, respec-
tively, by 2007 and remain at that level thereafter. A one percent change in
the medical trend rate would have a $1.5 million impact on the system's annual
expense and would change the APBO by approximately $18.2 million.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect postretire-
ment benefit expense in future years.
Effective May 1, 1995 the DTE approved a settlement proposal sponsored
jointly by Commonwealth Electric and the Attorney General of Massachusetts
that allows Commonwealth Electric to fully recover costs relating to postreti-
rement benefits and to amortize its $8.6 million deferred balance over a ten-
year period. In February 1996, FERC accepted for filing rate schedules that
provided for the recovery of Canal Electric's expense effective with its March
1996 contract billings including the recovery of previously deferred costs
over a six-month period. On April 15, 1997, the DTE issued an accounting
ruling allowing Commonwealth Gas Company to include postretirement benefits
costs in cost-of-service and to amortize the deferred balance of $10.5 million
at March 31, 1997 associated with these costs over a period not to exceed ten
years that began in April 1997.
(c) Savings Plan
The system has an Employees Savings Plan that provides for system
contributions equal to contributions by eligible employees of up to four
percent of each employee's compensation rate and up to five percent for those
employees no longer eligible for postretirement health benefits. The total
system contribution was $4,173,000 in 1997, $4,053,000 in 1996 and $4,393,000
in 1995.
<PAGE 49>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(d) Long-Term Incentive Compensation Plan
The Long-Term Incentive Compensation Plan (the Plan), approved by
shareholders in 1994, was established to advance the interests of the System
by providing long-term financial incentives, primarily common shares of the
System, to selected key employees of the system for achieving specified
objectives. The System, in encouraging such share ownership, seeks to
attract, retain and motivate employees who hold positions of significant
responsibility. Eligible employees are chosen by the Executive Compensation
Committee of the Board of Trustees and are presented grant share awards which
mature after a three-year vesting period. Shares are issued to participants
in March following the close of the third plan year. All shares are subject
to forfeiture if specified performance measures are not met. During the
applicable vesting period, participants have all the voting, dividend and
other related rights of a record holder except that the shares are nontrans-
ferable. Common shares granted under the Plan can not exceed 1% of the total
shares issued and outstanding. In 1997, 31,606 common shares, valued at
approximately $707,000, were granted to system officers. Compensation costs
of approximately $231,000 were recorded in 1997 with the remainder to be
recognized over the remaining vesting period of 26 months. Common shares
granted pursuant to the Plan had no material impact on earnings per share.
(6) Interim Financing and Long-Term Debt
(a) Notes Payable to Banks
System companies maintain both committed and uncommitted lines of credit
for the short-term financing of their construction programs and other cor-
porate purposes. As of December 31, 1997, system companies had $145 million
of committed lines of credit that will expire at varying intervals in 1998.
These lines are normally renewed upon expiration and require annual fees of up
to .1875% of the individual line. At December 31, 1997, the uncommitted lines
of credit totaled $10 million. Interest rates on the outstanding borrowings
generally are at an adjusted money market rate and averaged 5.8% and 5.6% in
1997 and 1996, respectively. Notes payable to banks totaled $94,075,000 and
$118,475,000 at December 31, 1997 and 1996, respectively.
(b) Long-term Debt Maturities and Retirements
Under terms of various indentures and loan agreements, the System and
certain subsidiary companies are required to make periodic sinking fund
payments for retirement of outstanding long-term debt. These payments and
balances of maturing debt issues for the five years subsequent to December 31,
1997 are as follows:
Sinking Funds Maturing Debt Issues
Year Subsidiaries System Subsidiaries Total
(Dollars in thousands)
1998 $7,653 $10,000 $ 9,000 $26,653
1999 7,653 10,000 10,000 27,653
2000 7,653 - - 7,653
2001 9,010 - 3,500 12,510
2002 5,360 - 32,000 37,360
(7) Redeemable Preferred Shares
Each series of the System's preferred shares was issued at par value,
$100 per share, and is subject to periodic, mandatory sinking fund payments.
The System can make additional voluntary redemptions, not exceeding the requi-
red redemption, at par, on a non-cumulative basis, on each sinking fund date.
<PAGE 50>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Preferred shares may also be called for redemption, in whole or in
part, in excess of the required and voluntary sinking fund redemptions. The
obligation to make mandatory redemptions is cumulative and the System is not
allowed to pay dividends to common shareholders or make optional sinking fund
payments if mandatory redemptions are in arrears. Details of redemptions for
each series are contained in the following table:
Sinking Funds Optional
Dividend 1998-2002 Redemption
Rate Mandatory Optional Call Prices
(Dollars in thousands)
Series A 4.80% $120 $120 $102
Series B 8.10 160 160 101
Series C 7.75 540 540 101
Preferred shareholders have no voting rights except in the event that
six full quarterly dividends have not been paid. In this circumstance, the
preferred shareholders are entitled, voting as a class, to elect two of the
nine Trustees of the System.
The preference of these shares in involuntary liquidation is equal to
par value. The shares are of equal rank and are entitled to cumulative
dividends at the annual rate established for each series. No dividend can be
declared on any series unless proportionate dividends are concurrently
declared on the other outstanding series and in the event that dividend
payments are in arrears, the System may not redeem any shares unless all
shares of all preferred series are redeemed.
(8) Disclosures About Fair Value of Financial Instruments
The fair value of certain financial instruments included in the accom-
panying Consolidated Balance Sheets as of December 31, 1997 and 1996 are as
follows:
1997 1996
Carrying Fair Carrying Fair
Value Value Value Value
(Dollars in thousands)
Long-term debt $390,964 $444,970 $377,218 $417,411
Preferred shares 13,020 14,708 13,840 14,601
The carrying amount of cash and notes payable to banks approximates the
fair value because of the short maturity of these financial instruments.
The estimated fair value of long-term debt and preferred stock are based
on quoted market prices of the same or similar issues or on the current rates
offered for debt or preferred shares with the same remaining maturity. The
fair values shown above do not purport to represent the amounts at which those
obligations would be settled.
(9) Lease Obligations
System companies lease property, transmission facilities and equipment
under agreements, some of which are capital leases. Several subsidiaries
renegotiate certain lease agreements annually. These new agreements are for a
term of one year and are renewable monthly thereafter. COM/Energy Services
Company has agreements in effect for office furniture, computer and transpor-
tation equipment. Generally, these agreements require the lessee to pay
related taxes, maintenance and other costs of operation. Leases currently in
effect contain no provisions which prohibit system companies from entering
into future lease agreements or obligations.
<PAGE 51>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The following is a breakdown, by major class, of property under capital
lease at December 31, 1997 and 1996:
1997 1996
(Dollars in thousands)
Transmission facilities $11,801 $12,454
Office furniture, computer equipment and other 1,753 1,500
13,554 13,954
Less: Accumulated amortization 53 77
$13,501 $13,877
Future minimum lease payments, by period and in the aggregate, of
capital leases and non cancelable operating leases consisted of the following
at December 31, 1997:
Capital Operating
Leases Leases
(Dollars in thousands)
1998 $ 2,603 $11,000
1999 2,456 9,218
2000 2,159 5,012
2001 1,660 3,581
2002 1,598 3,581
Beyond 2002 17,128 11,672
Total future minimum lease payments 27,604 $44,064
Less: Estimated interest element
included therein 14,103
Estimated present value of future minimum
lease payments $13,501
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $11,181,000 in 1997, $12,922,000 in 1996 and
$13,867,000 in 1995. There were no contingent rentals and no sublease rentals
for the years 1997, 1996 and 1995.
(10) Dividend Restriction
At December 31, 1997, approximately $111,729,000 of consolidated
retained earnings was restricted against the payment of cash dividends by
terms of indentures and note agreements securing long-term debt.
(11) Segment Information
System companies provide electric, gas and steam services to retail
customers in communities located in central, eastern and southeastern Massa-
chusetts and, in addition, sell electricity at wholesale to Massachusetts
customers. Other operations of the system include the development and
operation of rental properties and other activities which do not presently
contribute significantly to either revenues or operating income.
Operating income of the various industry segments includes income from
transactions with affiliates and is exclusive of interest expense, income
taxes and equity in earnings of unconsolidated corporate joint ventures.
The amount of identifiable assets represented by the system's investment
in corporate joint ventures consists principally of a percentage ownership in
the assets of four regional electric generating plants and a 3.8% interest in
Hydro-Quebec Phase II.
<PAGE 52>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
1997 1996 1995
(Dollars in thousands)
Revenues from
Unaffiliated Customers
Electric $ 688,508 $ 649,678 $ 604,980
Gas 333,977 341,867 306,953
Steam and other 19,259 19,360 17,355
Total Revenues $1,041,744 $1,010,905 $ 929,288
Capital Expenditures (including AFUDC)
Electric $ 34,524 $ 38,844 $ 61,643
Gas 18,230 11,611 16,198
Other 4,804 2,730 3,659
$ 57,558 $ 53,185 $ 81,500
Operating Income
Before Income Taxes
Electric $ 84,828 $ 92,374 $ 78,817
Gas 34,918 36,984 36,611
Steam and other (1,056) 3,406 3,689
Total Operating Income Before
Income Taxes $ 118,690 $ 132,764 $ 119,117
Identifiable Assets
Electric $1,049,094 $1,011,306 $ 982,384
Gas 395,966 388,930 374,615
Steam and other 74,298 58,081 57,269
1,519,358 1,458,317 1,414,268
Intercompany eliminations (48,075) (42,757) (35,140)
Investment in corporate joint
ventures 13,767 13,395 13,214
Total Identifiable Assets $1,485,050 $1,428,955 $1,392,342
Depreciation Expense
Electric $ 41,103 $ 39,977 $ 36,977
Gas 10,482 10,061 9,656
Steam and other 1,820 1,744 1,537
Total Depreciation $ 53,405 $ 51,782 $ 48,170
<PAGE 53>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PART III.
Item 10. Trustees and Executive Officers of the Registrant
a. Trustees of the Registrant:
Information required by this item is incorporated herein by reference to
the Notice of 1998 Annual Meeting and Proxy Statement dated
March 30, 1998, pages 3-4.
b. Executive Officers of the Registrant:
Age at
December
Name of Officer Position and Business Experience 31, 1997
William G. Poist President, Chief Executive Officer and 64
Trustee of the System and Chairman and
Chief Executive Officer of its principal
subsidiary companies since January 1,
1992; Vice President of the System and
COM/Energy Services Company* effective
September 1, 1991; President and Chief
Operating Officer of Commonwealth Gas
Company* from 1983 to 1991 and Hopkinton
LNG Corp.* from 1985 to 1991.
Russell D. Wright Vice Chairman and Chief Executive Officer of 51
Utility Operations effective March 1, 1998;
President and Chief Operating Officer of
Commonwealth Gas Company* effective
February 6, 1997 and President and
Chief Operating Officer of Cambridge
Electric Light Company*, Canal Electric
Company*, COM/Energy Steam Company*,
and Commonwealth Electric Company* effective
March 1, 1993; Financial Vice President and
Treasurer of the System and Financial Vice
President of its subsidiary companies
from 1987 to 1993.
Deborah A. McLaughlin President and Chief Operating Officer of 39
Utility Operations effective March 1, 1998;
Vice President of Customer Service for
Utility Operations from 1997 to 1998;
Vice President of Customer Service for
Cambridge Electric Light Company*, Canal
Electric Company*, COM/Energy Steam
Company*, and Commonwealth Electric
Company* from 1993 to 1997; Audit Manager
for COM/Energy Services Company* from
1987 to 1993.
* Subsidiary of the System.
<PAGE 54>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
b. Executive officers of the Registrant (Continued):
Age at
December
Name of Officer Position and Business Experience 31, 1997
James D. Rappoli Financial Vice President and Treasurer of 46
the System and its subsidiary companies
effective March 1, 1993; Treasurer of System
subsidiary companies from 1990 to 1993;
Assistant Treasurer of System subsidiary
companies from 1989 to 1990.
Michael P. Sullivan Vice President, Secretary, and 49
General Counsel of the System
and subsidiary companies (effective
June 1993); Vice President, Secretary,
and General Attorney of the System and
subsidiary companies since 1981.
John R. Williams Vice President of Corporate Services of 54
COM/Energy Services Company* (effective
December 2, 1996); Vice President of
Operations at Commonwealth Electric*
from 1993 to 1996; Vice President of
Human Resources and Communications at
COM/Energy Services Company* from 1990 to
1993; Vice President of Corporate Human
Resources at COM/Energy Services Company*
from 1987 to 1990.
* Subsidiary of the System.
The term of office for System officers expires May 7, 1998, the date of
the next Annual Organizational Meeting.
There are no family relationships between any trustee and executive
officer and any other trustee or executive of the System. There were no
arrangements or understandings between any officer or trustee and any other
person pursuant to which he was or is to be selected as an officer, trustee or
nominee.
There have been no events under any bankruptcy act, no criminal pro-
ceedings and no judgments or injunctions material to the evaluation of the
ability and integrity of any trustee or executive officer during the past five
years.
Item 11. Executive Compensation
Information required by this item is incorporated herein by reference to
the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998,
pages 5-9.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this item is incorporated herein by reference to
the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998,
pages 2-4.
<PAGE 55>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by reference to
the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998,
pages 2-4.
PART IV.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Index to Financial Statements
Consolidated financial statements and notes thereto of Commonwealth
Energy System and Subsidiary Companies, together with the Report of
Independent Public Accountants, are filed under Item 8 of this Form 10-K
and listed on the Index to Financial Statements (page 31).
(a) 2. Index to Financial Statement Schedules
Commonwealth Energy System and Subsidiary Companies
Filed herewith at page(s) indicated -
Report of Independent Public Accountants on Schedules (page 68).
Schedule I - Investments in, Equity in Earnings of, and Dividends Re-
ceived from Related Parties - Years Ended December 31, 1997, 1996 and
1995 (pages 69-71).
Schedule II - Valuation and Qualifying Accounts - Years Ended December
31, 1997, 1996 and 1995 (page 72).
All other schedules have been omitted because they are not applicable,
not required or because the required information is included in the
financial statements or notes thereto.
Subsidiaries not Consolidated and Fifty-Percent or Less Owned Persons
Financial statements of 50% or less owned persons accounted for by the
equity method have been omitted because they do not, considered individ-
ually or in the aggregate, constitute a significant subsidiary.
Form 11-K, Annual Reports of Employee Stock Purchases, Savings and
Similar Plans
Pursuant to Rule 15(d)-21 of the Securities and Exchange Act of 1934, the
information, financial statements and exhibits required by Form 11-K with
respect to the Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies will be filed as an amendment to this report under
cover of Form 10-K/A no later than April 30, 1998.
<PAGE 56>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incorporated
by reference to the appropriate exhibit numbers and the Securities and
Exchange Commission file numbers indicated in parentheses.
b. During 1981, New Bedford Gas and Edison Light Company sold its gas
business and properties to Commonwealth Gas Company and changed its
corporate name to Commonwealth Electric Company.
c. The following is a glossary of Commonwealth Energy System and subsid-
iary companies' acronyms that are used throughout the following Exhibit
Index:
CES ...................... Commonwealth Energy System
CE ....................... Commonwealth Electric Company
CEL ...................... Cambridge Electric Light Company
CEC ...................... Canal Electric Company
CG ....................... Commonwealth Gas Company
NBGEL .................... New Bedford Gas and Edison Light
Company
HOPCO .................... Hopkinton LNG Corp.
Exhibit Index
Exhibit 3. Declaration of Trust
Commonwealth Energy System (Registrant)
3.1.1 Declaration of Trust of CES dated December 31, 1926, as amended by
vote of the shareholders and trustees May 4, 1995 (Exhibit 1 to the
CES Form 10-Q (September 1995), File No. 1-7316).
Exhibit 4. Instruments defining the rights of security holders, including
indentures
Commonwealth Energy System (Registrant)
Debt Securities -
4.1.1 CES Note Agreement ($40 Million Privately Placed Senior Notes)
dated June 28, 1989 (Exhibit 1 to the CES Form 10-Q (September
1989), File No. 1-7316).
Cambridge Electric Light Company
Indenture of Trust or Supplemental Indenture of Trust -
4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit 7(a), File
No. 2-7909).
4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-
7909).
<PAGE 57>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-
7909).
4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2-
7909).
Subsidiary Companies of the Registrant
4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit 1, File No
2-7909).
Canal Electric Company
Indenture of Trust and First Mortgage or Supplemental Indenture of Trust and
First Mortgage -
4.3.1 Indenture of Trust and First Mortgage with State Street Bank and
Trust Company, Trustee, dated October 1, 1968 (Exhibit 4(b) to Form
S-1, File No. 2-30057).
4.3.2 First and General Mortgage Indenture with Citibank, N.A., Trustee,
dated September 1, 1976 (Exhibit 4(b)2 to Form S-1, File No. 2-
56915).
4.3.3 First Supplemental dated October 1, 1968 with State Street Bank and
Trust Company, Trustee, dated September 1, 1976 (Exhibit 4(b)3 to
Form S-1, File No. 2-56915).
4.3.4 Third Supplemental dated September 1, 1976 with Citibank, N.A., New
York, NY, Trustee, dated December 1, 1990 (Exhibit 3 to 1990 Form
10-K, File No. 2-30057).
4.3.5 Fourth Supplemental dated September 1, 1976 with Citibank, N.A., New
York, NY, Trustee, dated December 1, 1990 (Exhibit 4 to 1990 Form
10-K, File No. 2-30057).
Commonwealth Gas Company
Indenture of Trust or Supplemental Indenture of Trust -
4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No.
2-7820).
4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2-
1647).
4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No.
2-1647).
4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994) (Exhibit 1, File
No. 2-1647).
4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No. 2-
1647).
<PAGE 58>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Exhibit 10. Material Contracts
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated
December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No.
2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and
CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as
Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the
CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and
July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (Septem-
ber 1989), File No. 2-7909).
10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as
amended April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form
10-K, File No. 2-7749).
10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the
CE Form 10-Q (June 1988), File No. 2-7749).
10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and
July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September
1989), File No. 2-7749).
10.1.4 Power Contract between Connecticut Yankee Atomic Power Company
(CYAPC) and CEL dated July 1, 1964 (Exhibit 13-K1 to the System's
Form S-1, (April 1967) File No. 2-25597).
10.1.4.1 Additional Power Contract providing for extension on contract term
between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL
Form 10-Q (June 1984), File No. 2-7909).
10.1.4.2 Second Supplementary Power Contract providing for decommissioning
financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to
the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation
(VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984
Form 10-K, File No. 2-7909).
10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment
dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits
1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2-
7909).
<PAGE 59>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment dated June
1, 1985 to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form
10-Q (June 1986), File No. 2-7909).
10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1, 1968, both as
amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988),
File No. 2-7909).
10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June
15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No.
2-7909).
10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and
VYNPC providing for decommissioning financing and contract extension
(Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909).
10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and
CEL dated May 20, 1968 (Exhibit 5 to the System's Form S-7, File No.
2-38372).
10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and
Second Amendment dated January 1, 1984 (supplementary payments) to
10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No.
2-7909).
10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the
CEL Form 10-Q (September 1984), File No. 2-7909).
10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the
purchase of electricity from BECO's Pilgrim Unit No. 1 dated Au-
gust 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by
power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July
12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No.
2-7749).
10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December
1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.4 Service Agreement for Non-Firm Transmission Service between BECO and
CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File
No. 2-7909).
10.1.8 Agreement for Joint-Ownership, Construction and Operation of New
Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N)
to the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as
amended below:
10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974,
June 21, 1974, September 25, 1974, October 25, 1974 and January 31,
1975, respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7,
1975), File No. 2-54995).
10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18,
1979, April 25, 1979, June 8, 1979, October 11, 1979 and December
15, 1979, respectively (Refiled as Exhibit 1 to the CEC 1989 Form
10-K, File No. 2-30057).
<PAGE 60>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16,
1980, December 31, 1980 and June 1, 1982, respectively (Filed as
Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749).
10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27,
1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-
Q (June 1984), File No. 2-30057).
10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1
to the CEC Form 10-Q (March 1985), File No. 2-30057).
10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1
to the CEC Form 10-Q (March 1986), File No. 2-30057).
10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to
the CEC Form 10-Q (June 1986), File No. 2-30057).
10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhib-
it 1 to the CEC 1986 Form 10-K, File No. 2-30057).
10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987
(Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-30057).
10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both
dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File
No. 2-30057).
10.1.9 Purchase and Sale Agreement together with an implementing Addendum
dated December 31, 1981, between CE and CEC, for the purchase and
sale of the CE 3.52% joint-ownership interest in the Seabrook
units, dated January 2, 1981 (Refiled as Exhibit 4 to the CE 1992
Form 10-K, File No. 2-7749).
10.1.10 Agreement to transfer ownership, construction and operational
interest in the Seabrook Units 1 and 2 from CE to CEC dated January
2, 1981 (Refiled as Exhibit 3 to the 1991 CE Form 10-K, File No. 2-
7749).
10.1.11 Power Contract, as amended to February 28, 1990, superseding the
Power Contract dated September 1, 1986 and amendment dated June 1,
1988, between CEC (seller) and CE and CEL (purchasers) for seller's
entire share of the Net Unit Capability of Seabrook 1 and related
energy (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-
30057).
10.1.12 Agreement between NBGEL and Central Maine Power Company (CMP), for
the joint-ownership, construction and operation of William F. Wyman
Unit No. 4 dated November 1, 1974 together with Amendment No. 1
dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No.
2-54955).
<PAGE 61>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.12.1 Amendments No. 2 and 3 to 10.1.12 as amended August 16, 1976 and
December 31, 1978 (Exhibit 5(a) 14 to the System's Form S-16 (June
1979), File No. 2-64731).
10.1.13 Agreement between the registrant and Montaup Electric Company (MEC)
for use of common facilities at Canal Units I and II and for
allocation of related costs, executed October 14, 1975 (Exhibit 1
to the CEC 1985 Form 10-K, File No. 2-30057).
10.1.13.1 Agreement between the registrant and MEC for joint-ownership of
Canal Unit II, executed October 14, 1975 (Exhibit 2 to the CEC 1985
Form 10-K, File No. 2-30057).
10.1.13.2 Agreement between the registrant and MEC for lease relating to
Canal Unit II, executed October 14, 1975 (Exhibit 3 to the CEC 1985
Form 10-K, File No. 2-30057).
10.1.14 Contract between CEC and NBGEL and CEL, affiliated companies, for
the sale of specified amounts of electricity from Canal Unit 2
dated January 12, 1976 (Exhibit 7 to the System's 1985 Form 10-K,
File No. 1-7316).
10.1.15 Capacity Acquisition Agreement between CEC,CEL and CE dated Septem-
ber 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File
No. 2-30057).
10.1.15.1 Amendment to 10.1.15 as amended and restated June 1, 1993, hence-
forth referred to as the Capacity Acquisition and Disposition
Agreement, whereby Canal Electric Company, as agent, in addition to
acquiring power may also sell bulk electric power which Cambridge
Electric Light Company and/or Commonwealth Electric Company owns or
otherwise has the right to sell (Exhibit 1 to Canal Electric's Form
10-Q (September 1993), File No. 2-30057).
10.1.16 Phase 1 Vermont Transmission Line Support Agreement and Amendment
No. 1 thereto between Vermont Electric Transmission Company, Inc.
and certain other New England utilities, dated December 1, 1981 and
June 1, 1982, respectively (Exhibits 5 and 6 to the CE 1992 Form
10-K, File No. 2-7749).
10.1.16.1 Amendment No. 2 to 10.1.16 as amended November 1, 1982 (Exhibit 5
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.2 Amendment No. 3 to 10.1.16 as amended January 1, 1986 (Exhibit 2 to
the CE 1986 Form 10-K, File No. 2-7749).
10.1.17 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE
for the purchase of available hydro-electric energy produced by a
facility located in Ware, Massachusetts, dated September 1, 1983
(Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
<PAGE 62>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.18 Power Purchase Agreement between Corporation Investments, Inc.
(CI), and CE for the purchase of available hydro-electric energy
produced by a facility located in Lowell, Massachusetts, dated
January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K,
File No. 2-7749).
10.1.18.1 Amendment to 10.1.18 between CI and Boott Hydropower, Inc., an
assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to
the CE 1984 Form 10-K, File No. 2-7749).
10.1.19 Phase 1 Terminal Facility Support Agreement dated December 1, 1981,
Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated
November 1, 1982, between New England Electric Transmission Corpo-
ration (NEET), other New England utilities and CE (Exhibit 1 to the
CE Form 10-Q (June 1984), File No. 2-7749).
10.1.19.1 Amendment No. 3 to 10.1.19 (Exhibit 2 to the CE Form 10-Q (June
1986), File No. 2-7749).
10.1.20 Preliminary Quebec Interconnection Support Agreement dated May 1,
1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2
dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amend-
ment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1,
1983 among certain New England Power Pool (NEPOOL) utilities
(Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.21 Agreement with Respect to Use of Quebec Interconnection dated
December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment
No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhib-
it 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.21.1 Amendatory Agreement No. 3 to 10.1.21 as amended June 1, 1990,
among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q
(September 1990), File No. 2-30057).
10.1.22 Phase I New Hampshire Transmission Line Support Agreement between
NEET and certain other New England Utilities dated December 1, 1981
(Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.23 Agreement, dated September 1, 1985, with Respect To Amendment of
Agreement With Respect To Use Of Quebec Interconnection, dated
December 1, 1981, among certain NEPOOL utilities to include Phase
II facilities in the definition of "Project" (Exhibit 1 to the CEC
Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Agreement to Preliminary Quebec Interconnection Support Agreement -
Phase II among Public Service Company of New Hampshire (PSNH), New
England Power Co. (NEP), BECO and CEC whereby PSNH assigns a
portion of its interests under the original Agreement to the other
three parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987
Form 10-K, File No. 2-30057).
<PAGE 63>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.25 Preliminary Quebec Interconnection Support Agreement - Phase II
among certain New England electric utilities dated June 1, 1984
(Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.25.1 First, Second and Third Amendments to 10.1.25 as amended March 1,
1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to
the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.25.2 Fifth, Sixth and Seventh Amendments to 10.1.25 as amended October
15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhib-
it 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.25.3 Fourth and Eighth Amendments to 10.1.25 as amended July 1, 1987 and
August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.25.4 Ninth and Tenth Amendments to 10.1.25 as amended November 1, 1988
and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form
10-K, File No. 2-30057).
10.1.25.5 Eleventh Amendment to 10.1.25 as amended November 1, 1989 (Exhibit
4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.25.6 Twelfth Amendment to 10.1.25 as amended April 1, 1990 (Exhibit 1 to
the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.26 Phase II Equity Funding Agreement for New England Hydro-Transmis-
sion Electric Company, Inc. (New England Hydro) (Massachusetts),
dated June 1, 1985, between New England Hydro and certain NEPOOL
utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File
No. 2-30057).
10.1.27 Phase II Massachusetts Transmission Facilities Support Agreement
dated June 1, 1985, refiled as a single agreement incorporating
Amendments 1 through 7 dated May 1, 1986 through January 1, 1989,
respectively, between New England Hydro and certain NEPOOL utili-
ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2-
30057).
10.1.28 Phase II New Hampshire Transmission Facilities Support Agreement
dated June 1, 1985, refiled as a single agreement incorporating
Amendments 1 through 8 dated May 1, 1986 through January 1, 1990,
respectively, between New England Hydro-Transmission Corporation
(New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to
the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.29 Phase II Equity Funding Agreement for New Hampshire Hydro, dated
June 1, 1985, between New Hampshire Hydro and certain NEPOOL
utilities (Exhibit 3 to the CEC Form 10-Q (September 1985), File
No. 2-30057).
10.1.29.1 Amendment No. 1 to 10.1.29 dated May 1, 1986 (Exhibit 6 to the CEC
Form 10-Q (March 1987), File No. 2-30057).
<PAGE 64>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.29.2 Amendment No. 2 to 10.1.29 as amended September 1, 1987 (Exhibit 3
to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.30 Phase II New England Power AC Facilities Support Agreement, dated
June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6
to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.30.1 Amendments Nos. 1 and 2 to 10.1.30 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.30.2 Amendments Nos. 3 and 4 to 10.1.30 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.31 Agreement Authorizing Execution of Phase II Firm Energy Contract,
dated September 1, 1985, among certain NEPOOL utilities in regard
to participation in the purchase of power from Hydro-Quebec (Exhib-
it 8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.32 Agreements by and between Swift River Company and CE for the
purchase of available hydro-electric energy to be produced by units
located in Chicopee and North Willbraham, Massachusetts, both dated
September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K,
File No. 2-7749).
10.1.33 Power Purchase Agreement by and between SEMASS Partnership, as
seller, to construct, operate and own a solid waste disposal
facility at its site in Rochester, Massachusetts and CE, as buyer
of electric energy and capacity, dated September 8, 1981 (Exhibit
17 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.33.1 Power Sales Agreement to 10.1.33 for all capacity and related
energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985
Form 10-K, File No. 2-7749).
10.1.33.2 Amendment to 10.1.33 for all additional electric capacity and
related energy to be produced by an addition to the Original Unit,
dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990),
File No. 2-7749).
10.1.33.3 Amendment to 10.1.33 for all additional electric capacity and
related energy to be produced by an addition to the Original Unit,
dated May 24, 1991 (Exhibit 1 to CE Form 10-Q (June 1991), File No.
2-7749).
10.1.34 Power Sale Agreement by and between CE (buyer) and Northeast Energy
Associated, Ltd. (NEA) (seller) of electric energy and capacity,
dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March
1987), File No. 2-7749).
10.1.34.1 First Amendment to 10.1.34 as amended August 15, 1988 (Exhibit 1 to
the CE Form 10-Q (September 1988), File No. 2-7749).
<PAGE 65>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.34.2 Second Amendment to 10.1.34 as amended January 1, 1989 (Exhibit 2
to the CE 1988 Form 10-K, File No. 2-7749).
10.1.34.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for
the purchase of 21 MW of electricity (Exhibit 2 to the CE Form
10-Q (September 1988), File No. 2-7749).
10.1.34.4 Amendment to 10.1.34.3 as amended January 1, 1989 (Exhibit 3 to the
CE 1988 Form 10-K, File No. 2-7749).
10.1.35 Power Purchase Agreement and First Amendment, dated September 5,
1989 and August 3, 1990, respectively, by and between Commonwealth
Electric (buyer) and Dartmouth Power Associates Limited Partnership
(seller), whereby buyer will purchase all of the energy (67.6 MW)
produced by a single gas turbine unit (Exhibit 1 to the CE Form 10-
Q (June 1992), File No. 2-7749).
10.1.35.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and between
Commonwealth Electric Company and Dartmouth Power Associates, L.P.
dated September 5, 1989 (Exhibit 4 to the CE Form 10-Q (June 1995),
File No. 2-7749).
10.1.36 Power Purchase Agreement by and between Masspower (seller) and Com-
monwealth Electric Company (buyer) for a 11.11% entitlement to the
electric capacity and related energy of a 240 MW gas-fired cogen-
eration facility, dated February 14, 1992 (Exhibit 1 to Common-
wealth Electric's Form 10-Q (September 1993), File No. 2-7749).
10.1.37 Power Sale Agreement by and between Altresco Pittsfield, L.P.
(seller) and Commonwealth Electric Company (buyer) for a 17.2%
entitlement to the electric capacity and related energy of a 160 MW
gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 2
to Commonwealth Electric's Form 10-Q (September 1993), File No. 2-
7749).
10.1.37.1 System Exchange Agreement by and among Altresco Pittsfield, L.P.,
Cambridge Electric Light Company, Commonwealth Electric Company and
New England Power Company, dated July 2, 1993 (Exhibit 3 to Common-
wealth Electric's Form 10-Q (September 1993), File No 2-7749).
10.1.37.2 Power Sale Agreement by and between Altresco Pittsfield, L. P.
(seller) and Cambridge Electric Light Company (Cambridge Electric)
(buyer) for a 17.2% entitlement to the electric capacity and
related energy of a 160 MW gas-fired cogeneration facility, dated
February 20, 1992 (Exhibit 1 to Cambridge Electric's Form 10-Q
(September 1993), File No. 2-7909).
10.1.37.3 First Amendment, dated November 7, 1994, to 10.1.37 by and between
Commonwealth Electric Company and Altresco Pittsfield, L.P. dated
February 20, 1992 (Filed as Exhibit 3 to Commonwealth Electric
Company's Form 10-Q (June 1995), File 2-7749).
<PAGE 66>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.37.4 First Amendment, dated November 7, 1994, to 10.1.37.2 by and
between Cambridge Electric Light Company and Altresco Pittsfield,
L.P. dated February 20, 1992 (Filed as Exhibit 2 to Cambridge
Electric Light Company's Form 10-Q (June 1995), File 2-7909).
10.2 Natural gas purchase contracts.
10.2.1 Transportation Agreement between CNG and CG to provide for trans-
portation of natural gas on a daily basis from Steuben Gas Storage
Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No. 2-
1647).
10.3 Other agreements.
10.3.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993
(Exhibit 1 to CES Form 10-Q (September 1993), File No. 1-7316).
10.3.2 Employees Savings Plan of Commonwealth Energy System and Subsid-
iary Companies as amended and restated January 1, 1993.(Exhibit 2
to CES Form 10-Q (September 1993), File No. 1-7316).
10.3.2.1 First Amendment to 10.3.2, effective October 1, 1994. (Exhibit 1 to
CES Form S-8 (January 1995), File No. 1-7316).
10.3.2.2 Second Amendment to 10.3.2, effective April 1, 1996 (Exhibit 1 to
CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.3.2.3 Third Amendment to 10.3.2, effective January 1, 1997 (Exhibit 1 to
CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971
as amended through August 1, 1977, between NEGEA Service Corpora-
tion, as agent for CEL, CEC, NBGEL, and various other electric
utilities operating in New England together with amendments dated
August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit
5(c)13 to New England Gas and Electric Association's Form S-16
(April 1980), File No. 2-64731).
10.3.3.1 Thirteenth Amendment to 10.3.3 as amended September 1, 1981 (Re-
filed as Exhibit 3 to the System's 1991 Form 10-K, File No.
1-7316).
10.3.3.2 Fourteenth through Twentieth Amendments to 10.3.3 as amended
December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983,
August 1, 1985, August 15, 1985 and September 1, 1985, respectively
(Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316).
10.3.3.3 Twenty-first Amendment to 10.3.3 as amended to January 1, 1986
(Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316).
10.3.3.4 Twenty-second Amendment to 10.3.3 as amended to September 1, 1986
(Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316).
<PAGE 67>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.3.3.5 Twenty-third Amendment to 10.3.3 as amended to April 30, 1987
(Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316).
10.3.3.6 Twenty-fourth Amendment to 10.3.3 as amended March 1, 1988 (Exhibit
1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.7 Twenty-fifth Amendment to 10.3.3. as amended to May 1, 1988 (Exhib-
it 1 to the CES Form 10-Q (March 1988), File No. 1-7316).
10.3.3.8 Twenty-sixth Agreement to 10.3.3 as amended March 15, 1989 (Exhibit
1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.9 Twenty-seventh Agreement to 10.3.3 as amended October 1, 1990
(Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316).
10.3.3.10 Twenty-eighth Agreement to 10.3.3 as amended September 15, 1992
(Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.3.11 Twenty-ninth Agreement to 10.3.3 as amended May 1, 1993 (Exhibit 2
to the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as
initial lender) covering the unconditional guarantee of a portion
of the payment obligations of Maine Yankee Atomic Power Company
under a loan agreement and note initially between Maine Yankee and
MYA Fuel Company (Exhibit 3 to the CEL Form 10-K for 1985, File No.
2-7909).
Exhibit 21. Subsidiaries of the Registrant
Filed herewith as Exhibit 1 is a list of subsidiaries of Common-
wealth Energy System, all of which are wholly-owned, as of Decem-
ber 31, 1997.
Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security
Holders.
Filed herewith as Exhibit 2 is the Notice of 1998 Annual Meeting
and Proxy Statement dated March 30, 1998.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 3 is the Financial Data Schedule for
the twelve months ended December 31, 1997.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
December 31, 1997.
<PAGE 68>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees of Commonwealth Energy System:
We have audited, in accordance with generally accepted auditing standards,
the consolidated financial statements of Commonwealth Energy System included
in this Form 10-K and have issued our report thereon dated February 19, 1998
(except with respect to certain matters discussed in Note 2, as to which the
date is March 2, 1998). Our audits were made for the purpose of forming an
opinion on those consolidated financial statements taken as a whole. The
schedules listed in Part IV, Item 14 of this Form 10-K are presented for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 19, 1998.
<PAGE 69>
<TABLE> SCHEDULE I
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES
FOR THE YEAR ENDED DECEMBER 31, 1997
(Dollars in Thousands)
<CAPTION> Balance at Balance at
Beginning of Year Additions Deductions End of Year Notes
Number Equity Number Receive-
of in Other Distribution Other of able
<S> Shares Investment Earnings (A) of Earnings (B) Shares Investment (C)
SUBSIDIARIES CONSOLIDATED: <C> <C> <C> <C> <C> <C> <C> <C> <C>
(All issues are common stock)
Cambridge Electric Light Co. 346,600 $ 45,851 $ 5,216 $ - $ 2,842 $ - 346,600 $ 48,225 $ 7,500
COM/Energy Steam Co. 25,500 3,194 1,265 - 951 - 25,500 3,508 375
Canal Electric Co. 1,523,200 99,021 14,828 - 14,318 - 1,523,200 99,531 -
Commonwealth Gas Co. 2,857,000 110,020 15,443 - 9,428 - 2,857,000 116,035 -
Darvel Realty Trust 26 1,001 52 - - - 26 1,053 -
COM/Energy Freetown Rlty. 1 5,031 (347) - - - 1 4,684 1,730
COM/Energy Research Park Rlty. 1 877 582 - 528 - 1 931 -
COM/Energy Cambridge Rlty. 1 43 (5) - - - 1 38 -
COM/Energy Acushnet Rlty. 1 694 62 - 55 - 1 701 -
COM/Energy Services Co. 3,250 262 22 - - - 3,250 284 -
Commonwealth Electric Co. 2,043,972 175,545 16,923 - 12,264 - 2,043,972 180,204 -
Hopkinton LNG Corp. 5,000 3,881 549 - 548 - 5,000 3,882 650
Advanced Energy Systems, Inc. - - (904) 1,921 - - 100 1,017 -
COM/Energy Resources, Inc. - - (60) 101 - - 100 41 -
COM/Energy Marketing, Inc. - - (758) 1,200 - - 100 442 -
COM/Energy Technologies, Inc. - - (916) 3,300 - - 100 2,384 -
$445,420 $51,952 $6,522 $40,934 $ - $462,960 $ 9,795
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52,454 $10,046 $ 1,045 - $ 723 $ - 52,454 $ 10,368
Hydro-Quebec Phase II 137,329 3,321 233 - 248 231 127,034 3,075
Other Investments - 28 - 296 - - - 324
<FN> $ 13,395 $ 1,278 296 $ 971 $231 $ 13,767
NOTES:
(A) Additional investment.
(B) In 1997, New England Hydro-Transmission Company, Inc. repurchased 7.5% (10.249.2 shares) of its outstanding
shares. Canal Electric Company received proceeds of $145,539 ($14.20 per share) and has included this amount
with dividends. Also in 1997, New England Hydro-Transmission Corporation repurchased 6.85% (46.124 shares) of
its outstanding shares. Canal Electric Company received proceeds of $85,207 (41,847.46 per share) and has
included this amount with dividends.
(C) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the
rate during the term of the notes.
</TABLE>
<PAGE 70>
<TABLE>
SCHEDULE I
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES
FOR THE YEAR ENDED DECEMBER 31, 1996
(Dollars in Thousands)
<CAPTION>
Balance at Balance at
Beginning of Year Additions Deductions End of Year
Number Equity Number Notes
of in Distribution Other of Receivable
Shares Investment Earnings of Earnings (B) Shares Investment (A)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SUBSIDIARIES CONSOLIDATED:
(All issues are common stock)
Cambridge Electric Light Company 346,600 $ 44,179 $ 5,120 $ 3,448 $ - 346,600 $ 45,851 $ 4,665
COM/Energy Steam Company 25,500 3,539 1,583 1,928 - 25,500 3,194 2,155
Canal Electric Company 1,523,200 98,471 16,574 16,024 - 1,523,200 99,021 5,620
Commonwealth Gas Company 2,857,000 109,659 16,789 16,428 - 2,857,000 110,020 5,495
Darvel Realty Trust 26 1,055 75 129 - 26 1,001 -
COM/Energy Freetown Realty 1 5,477 (446) - - 1 5,031 1,305
COM/Energy Research Park Realty 1 739 461 323 - 1 877 -
COM/Energy Cambridge Realty 1 48 (5) - - 1 43 -
COM/Energy Acushnet Realty 1 575 119 - - 1 694 -
COM/Energy Services Company 3,250 337 (27) 48 - 3,250 262 -
Commonwealth Electric Company 2,043,972 168,919 19,605 12,979 - 2,043,972 175,545 2,240
Hopkinton LNG Corp. 5,000 3,893 548 560 - 5,000 3,881 1,015
$436,891 $60,396 $51,867 $ - $445,420 $22,495
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52,454 $ 9,814 $ 1,059 $ 827 $ - 52,454 $ 10,046
Hydro-Quebec Phase II 137,391 3,372 498 436 113 137,329 3,321
Other Investments - 28 - - - - 28
$ 13,214 $ 1,557 $ 1,263 $113 $ 13,395
<FN>
NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the
rate during the term of the notes.
(B) In 1996, New England Hydro-Transmission Corporation repurchased 6.52% of their outstanding shares at $1,831.30
per share. Canal Electric Company received $112,616 for the repurchase of 61.495 shares, and has included this
amount with dividends.
</TABLE>
<PAGE 71>
<TABLE> SCHEDULE I
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES
FOR THE YEAR ENDED DECEMBER 31, 1995
(Dollars in Thousands)
<CAPTION>
Balance at Balance at
Beginning of Year Additions Deductions End of Year
Number Equity Number Notes
of in Distribution Other of Receivable
Shares Investment Earnings of Earnings (B) Shares Investment (A)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
SUBSIDIARIES CONSOLIDATED:
(All issues are common stock)
Cambridge Electric Light Company 346,600 $ 43,784 $ 5,438 $ 5,043 $- 346,600 $ 44,179 $ 2,425
COM/Energy Steam Company 25,500 4,110 2,093 2,664 - 25,500 3,539 500
Canal Electric Company 1,523,200 98,048 14,132 13,709 - 1,523,200 98,471 555
Commonwealth Gas Company 2,857,000 106,001 16,229 12,571 - 2,857,000 109,659 1,425
Darvel Realty Trust 26 870 185 - - 26 1,055 -
COM/Energy Freetown Realty 1 5,833 (356) - - 1 5,477 1,085
COM/Energy Research Park Realty 1 886 239 386 - 1 739 -
COM/Energy Cambridge Realty 1 57 (9) - - 1 48 -
COM/Energy Acushnet Realty 1 524 67 16 - 1 575 -
COM/Energy Services Company 3,250 337 49 49 - 3,250 337 -
Commonwealth Electric Company 2,043,972 163,561 15,169 9,811 - 2,043,972 168,919 -
Hopkinton LNG Corp. 5,000 3,893 548 548 - 5,000 3,893 -
$427,904 $53,784 $44,797 $- $436,891 $6,610
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52,454 $ 9,818 $ 1,093 $ 1,097 $- 52,454 $ 9,814
Hydro-Quebec Phase II 137,442 3,802 540 876 94 137,391 3,372
Other Investments - 28 - - - - 28
$ 13,648 $ 1,633 $ 1,973 $94 $ 13,214
<FN>
NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the
rate during the term of the notes.
(B) In 1995, New England Hydro-Transmission Corporation repurchased 6.52% of their outstanding shares at $1,834.62
per share. Canal Electric Company received $94,017 for the repurchase of 51.246 shares, and has included this
amount with dividends.
</TABLE>
<PAGE 72>
SCHEDULE II
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(Dollars in Thousands)
Additions
Balance at Provision Deductions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off of Year
Year Ended December 31, 1997
Allowance for
Doubtful Accounts $8,324 $8,638 $2,085 $ 9,639 $9,408
Year Ended December 31, 1996
Allowance for
Doubtful Accounts $8,040 $7,152 $1,866 $ 8,734 $8,324
Year Ended December 31, 1995
Allowance for
Doubtful Accounts $7,956 $8,089 $2,180 $10,185 $8,040
<PAGE 73>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1997
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
COMMONWEALTH ENERGY SYSTEM
(Registrant)
By: WILLIAM G. POIST
William G. Poist, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Principal Executive Officer:
WILLIAM G. POIST March 26, 1998
William G. Poist,
President and Chief Executive Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 26, 1998
James D. Rappoli,
Financial Vice President and Treasurer
A majority of the Board of Trustees:
SHELDON A. BUCKLER March 26, 1998
Sheldon A. Buckler, Chairman of
the Board
KEVIN C. BRYANT March 26, 1998
Kevin C. Bryant, Trustee
PETER H. CRESSY March 26, 1998
Peter H. Cressy, Trustee
B. L. FRANCIS March 26, 1998
Betty L. Francis, Trustee
FRANKLIN M. HUNDLEY March 26, 1998
Franklin M. Hundley, Trustee
<PAGE 74>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1997
SIGNATURES
(Continued)
WILLIAM J. O'BRIEN March 26, 1998
William J. O'Brien, Trustee
WILLIAM G. POIST March 26, 1998
William G. Poist, Trustee
MICHAEL C. RUETTGERS March 26, 1998
Michael C. Ruettgers, Trustee
G. L. WILSON March 26, 1998
Gerald L. Wilson, Trustee
<PAGE 75>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our reports included in this Form 10-K into the System's
previously filed Registration Statements on Form S-8 File No. 33-57467 and on
Form S-3 File No. 33-55593. It should be noted that we have not audited any
financial statements of the System subsequent to December 31, 1997 or per-
formed any audit procedures subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
March 31, 1998.
Exhibit 1
COMMONWEALTH ENERGY SYSTEM
LIST OF SUBSIDIARIES
DECEMBER 31, 1997
Advanced Energy Systems, Inc.
Cambridge Electric Light Company
Canal Electric Company
COM/Energy Acushnet Realty
COM/Energy Cambridge Realty
COM/Energy Freetown Realty
COM/Energy Marketing, Inc.
COM/Energy Research Park Realty
COM/Energy Resources, Inc.
COM/Energy Services Company
COM/Energy Steam Company
COM/Energy Technologies, Inc.
Commonwealth Electric Company
Commonwealth Gas Company
Darvel Realty Trust
Hopkinton LNG Corp.
<PAGE 1>
Commonwealth
Energy System
Notice of 1998
Annual Meeting and
Proxy Statement
Please sign and return your
proxy promptly
<PAGE>
<PAGE 2>
COMMONWEALTH ENERGY SYSTEM
Cambridge, Massachusetts
Notice of Annual Meeting of Shareholders
May 7, 1998
To the Shareholders of
COMMONWEALTH ENERGY SYSTEM:
Notice is hereby given that the Annual Meeting of Shareholders of
Commonwealth Energy System will be held at the office of the System, One Main
Street, P.O. Box 9150, Cambridge, Massachusetts 02142-9150, on Thursday,
May 7, 1998, at 10:30 o'clock A.M., Eastern Daylight Time, for the following
purposes:
1. To elect three Trustees to hold office for a three-year term and
until the election and qualification of their respective successors.
2. To take action on a proposal by the Board of Trustees to amend
Section 22 of the System's Declaration of Trust, as
amended, to revise the conditions under which presently
authorized but unissued Common Shares of the System might
be issued.
3. To approve the Restricted Common Share Plan for Trustees of
Commonwealth Energy System.
4. To consider and vote upon a shareholder proposal, if presented
at the meeting, as described herein.
5. To transact such other business as may properly come before the
meeting or any adjournment or adjournments thereof.
Common Shareholders of record at the close of business on March 17,
1998 are entitled to notice of, and to vote at, the meeting.
By order of the Trustees,
Michael P. Sullivan
Vice President, Secretary
and General Counsel
March 30, 1998
IMPORTANT
We cordially invite you to attend the Annual Meeting of Shareholders,
but IF YOU DO NOT EXPECT TO BE PRESENT, PLEASE MAIL YOUR PROXY IN ORDER THAT
THE PRESENCE OF A QUORUM MAY BE ASSURED. Because our shares are widely
distributed over a large number of holders, it is both necessary and desirable
that all Shareholders send in their proxies. Failure to secure a quorum on
the date set would necessitate an adjournment which would cause the System
considerable and needless expense. To avoid this, please SIGN AND DATE the
accompanying proxy and mail it promptly in the enclosed envelope to
Commonwealth Energy System, P.O. Box 9150, Cambridge, Massachusetts
02142-9150.
<PAGE>
<PAGE 3>
PROXY STATEMENT
This statement is furnished in connection with the solicitation of
proxies by the Board of Trustees of Commonwealth Energy System (hereinafter
called the "System") to be used at the Annual Meeting of Shareholders of the
System to be held on Thursday, May 7, 1998, at the principal executive office
of the System, One Main Street, P.O. Box 9150, Cambridge, Massachusetts
02142-9150, of which due notice has been given in accordance with the System's
Declaration of Trust dated December 31, 1926, as amended. If the enclosed
form of proxy is executed and returned, it may nevertheless be revoked at any
time insofar as it has not been exercised. A properly executed and returned
proxy will be voted in accordance with the directions contained thereon.
Abstentions shall be voted neither "for" nor "against," but shall be counted
in the determination of a quorum. Broker non-votes shall not be counted
either in calculating the number of shares present for the purpose of
determination of a quorum or for the purpose of determining whether a matter
has received the required number of votes. The giving of a later-dated proxy
revokes all proxies previously given. The approximate date on which this
Proxy Statement and the accompanying proxy card will first be mailed to
Shareholders is March 30, 1998.
FINANCIAL STATEMENTS
The audited financial statements of Commonwealth Energy System and
Subsidiary Companies, which include comparative Consolidated Balance Sheets as
of December 31, 1997 and 1996, Consolidated Statements of Income and
Consolidated Statements of Cash Flows for the three years ended December 31,
1997 and the Report of Independent Public Accountants are set forth in the
Annual Report to Shareholders.
VOTING SECURITIES
Each Common Share is entitled to one vote. Only Shareholders of record
at the close of business on March 17, 1998 are qualified to vote at the
meeting. There were outstanding as of the record date 21,561,282 Common
Shares.
The Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies owned beneficially 2,617,000 Common Shares representing 12% of the
outstanding Common Shares as of February 28, 1998. Members of the Plan are
entitled to give voting instructions with respect to their interests.
OWNERSHIP BY MANAGEMENT OF VOTING SECURITIES
The following table shows the beneficial ownership, reported to the
System as of February 28, 1998, of Common Shares of the System owned by the
Chief Executive Officer and the four other most highly paid Executive Officers
and, as a group, all Trustees and Executive Officers of the System.
Total
Common Percent of
Name Shares (1) Class
William G. Poist 20,472 0.1%
Russell D. Wright 12,055 0.1%
James D. Rappoli 8,257 0.1%
Michael P. Sullivan 6,946 0.1%
John R. Williams 6,013 0.1%
All Trustees and Executive Officers
as a group (13 persons) 71,967 0.3%
<PAGE>
<PAGE 4>
(1) Beneficial ownership set forth in this Proxy Statement includes, where
applicable, shares with respect to which voting or investment power is
attributed to an Executive Officer or Trustee because of joint fiduciary
ownership of the shares or relationship of the Executive Officer or
Trustee to the record owner, such as a spouse, together with shares held
under the Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies.
MATTERS TO BE BROUGHT BEFORE THE MEETING
1-ELECTION OF TRUSTEES
Three Trustees will be elected at the Annual Meeting of Shareholders to
hold office for the ensuing three years in accordance with the Declaration of
Trust which provides for staggered terms of Trustees of three years each. The
three Trustees elected at this meeting will hold office for a three-year term
and until the election and qualification of their respective successors.
Under the terms of the Declaration of Trust, Trustees are required to be
elected by a plurality vote of the Shareholders.
The Shares represented by the enclosed form of proxy will be voted, and
the persons named in such form of proxy will, unless otherwise directed in the
proxy, vote shares represented by proxies received for the election of the
following nominees:
Sheldon A. Buckler
Betty L. Francis
Michael C. Ruettgers
It is not contemplated that any of the three nominees will be unable to
serve. Should any of the nominees be unable to serve, your proxy will be
voted for the election of a nominee acceptable to the remaining Trustees.
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a February 28,
Name, Principal Occupation and Term of Office Trustee Age 1998
(A) KEVIN C. BRYANT, Regional President,
(D) BankBoston - South Region, Fall River,
Massachusetts
TERM EXPIRES IN 2000................. (1997) 37 200
(C) SHELDON A. BUCKLER, Chairman of the Board
of Commonwealth Energy System; Retired
Vice Chairman of the Board and a
Director, Polaroid Corporation,
Cambridge, Massachusetts (Manufacturer
of photographic equipment and supplies);
Director, Aseco Corp.; Cerion Technologies,
Inc.; Nashua Corporation; Parlex Corp.
and Spectrum Information Technologies, Inc.
TERM EXPIRES IN 1998 (NOMINEE)....... (1991) 66 6,260
<PAGE>
<PAGE 5>
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a February 28,
Name, Principal Occupation and Term of Office Trustee Age 1998
(A) PETER H. CRESSY, Chancellor, University of
(E) Massachusetts Dartmouth, North Dartmouth,
Massachusetts; Retired Rear Admiral,
United States Navy
TERM EXPIRES IN 1999 ............... (1994) 56 337
(A) BETTY L. FRANCIS, Executive Vice President
(D) and Chief Credit Officer, HomeSide
Lending, Inc., Jacksonville, Florida
TERM EXPIRES IN 1998(NOMINEE) ...... (1991) 51 200
(C) FRANKLIN M. HUNDLEY, Of Counsel,
(D) Rich, May, Bilodeau & Flaherty,
P.C., Boston, Massachusetts (Attorneys);
Director, The Berkshire Gas Company
TERM EXPIRES IN 2000................ (1985) 63 5,108
(B) WILLIAM J. O'BRIEN, Partner, Centre For
(C) Generative Leadership L.L.C., Hamilton,
Massachusetts (Consulting); Retired
President and CEO, The Hanover Insurance
Company
TERM EXPIRES IN 1999 .................. (1994) 65 3,500
WILLIAM G. POIST, President and Chief
Executive Officer of Commonwealth Energy
System and Chairman and a Director of
its subsidiary companies
TERM EXPIRES IN 1999 ................... (1992) 64 20,472
(B) MICHAEL C. RUETTGERS, President, Chief
(E) Executive Officer and a Director, EMC
Corporation, Hopkinton, Massachusetts
(Data storage technology); Director,
EG&G Inc.
TERM EXPIRES IN 1998(NOMINEE) ......... (1995) 55 1,000
(B) GERALD L. WILSON, Vannevar Bush Professor of
(E) Engineering, Massachusetts Institute of
Technology, Cambridge, Massachusetts;
Director, Analogic Corp. and Aseco Corp.
TERM EXPIRES IN 2000.................... (1985) 58 1,619
Each of the persons named above has held his or her present position (or
another executive position with the same employer) for more than the past five
years.
During 1997, fees of $308,174 were incurred for legal services rendered
by the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr. Hundley is
Of Counsel. The firm has been employed in the last fiscal year and the current
fiscal year.
<PAGE>
<PAGE 6>
Each Trustee, including nominees, owned beneficially less than one-third
of one percent of the outstanding Common Shares.
(A) Member of Audit Committee.
(B) Member of Executive Compensation Committee.
(C) Member of Nominating Committee.
(D) Member of Benefit Review Committee.
(E) Member of Strategic Planning Committee.
<PAGE>
<PAGE 7>
COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1997
The following table shows compensation paid by the System and its
subsidiaries to the System's President and Chief Executive Officer and the
four other highest paid Executive Officers of the System whose total
compensation in 1997 exceeded $100,000.
<TABLE>
SUMMARY COMPENSATION TABLE
<CAPTION>
Long-Term Compensation
Annual Compensation Awards Payouts
Long-
Term
Options Incen-
Other Restr- /Stock tive All
Annual icted Apprec- Plan Other
Compen- Stock iation (LTIP) Compen-
Name and Salary sation Awards Rights Payouts sation
Principal Position Year (1) Bonus (2) (3) (SARS) (4) (5)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
William G. Poist 1997 $388,200 $160,290 - - - $134,900 $15,528
President and Chief 1996 380,000 142,142 - $160,000 - - 15,204
Executive Officer of 1995 350,000 95,645 - - - 14,004
the System and Chair-
man of its subsidiary
companies
Russell D. Wright 1997 $276,333 $118,825 - - - $100,800 $10,977
Chief Executive 1996 250,000 97,427 - $100,000 - - 10,020
Officer of Utility 1995 231,667 66,060 - - - - 9,269
Operations
James D. Rappoli 1997 $194,967 $ 75,370 - - - $ 53,040 $ 7,797
Financial Vice 1996 178,167 60,740 - $ 54,800 - - 7,126
President and 1995 164,583 46,624 - - - - 6,586
Treasurer of the
System and its
subsidiary companies
Michael P. Sullivan 1997 $173,667 $ 66,154 - - - $ 48,360 $ 6,944
Vice President, 1996 161,666 55,121 - $ 54,000 - - 6,229
Secretary and General 1995 151,000 43,278 - - - - 6,044
Counsel of the System
and its subsidiary
companies
John R. Williams 1997 $154,858 $ 58,219 - - - $ 51,991 $ 6,191
Vice President - 1996 149,883 50,790 - $ 58,000 - - 5,796
Corporate Services 1995 149,400 35,812 - - - - 5,976
of COM/Energy
Services Company
</TABLE>
- --------------------
<PAGE>
<PAGE 8>
(1) The amounts in this column represent the aggregate total of cash
compensation received and compensation deferred by the
above-named individuals. Compensation is deferred pursuant to
the provisions of the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies and the Executive Salary
Continuation and Excess Benefit Plan for Employees of
Commonwealth Energy System and Subsidiary Companies.
(2) The dollar value of perquisites and other personal benefits,
securities or property totaling either $50,000 or 10% of total
annual salary and bonus, together with various other earnings,
amounts reimbursed for the payment of taxes and the dollar value
of any stock discounts not generally available are required to be
disclosed in this column. In 1997, there were no such
perquisites, earnings, reimbursements or discounts paid or made.
(3) The amounts in this column represent the value of the restricted
stock award made in 1997 which was calculated by multiplying the
average closing market price of the System's Common Shares at the
time of the grant by the number of Common Shares awarded. The
restrictions on these shares shall lapse three years from the
date of grant provided that the individual is still in the employ
of the System. Dividends are paid on the restricted Common
Shares to the same extent as they are paid on the System's Common
Shares. The aggregate number of restricted Common Share holdings
for the above-named Executive Officers as of February 28, 1998 is
17,952 Common Shares, having an aggregate value of $647,394.
(4) The amounts in this column represent the cash awards made in 1998
under the terms of the 1996-1997 Strategic Plan Compensation
Program. The Program measured System Common Share performance,
(requiring System Common Share total return of at least 95% of
industry average for award consideration), together with both the
Executive Officer's contributions to the System's Strategic Plan
over the two-year period and each Executive Officer's general
performance.
(5) The amounts in this column represent the aggregate contributions or
account credits made by the System and certain subsidiary companies
during 1997 on behalf of the above-named individuals to the Employees
Savings Plan of Commonwealth Energy System and Subsidiary Companies and
the Executive Salary Continuation and Excess Benefit Plan for Employees
of Commonwealth Energy System and Subsidiary Companies. The Employees
Savings Plan of Commonwealth Energy System and Subsidiary Companies is
a defined contribution plan. The Plan incorporates salary deferral
provisions pursuant to Section 401(k) of the Internal Revenue Code for
all employees who have elected to participate on that basis. The
Executive Salary Continuation and Excess Benefit Plan for Employees of
Commonwealth Energy System and Subsidiary Companies is a defined
contribution/defined benefit plan. Unlike the Employees Savings Plan,
this Plan is not a qualified plan under Section 401(a) of the Internal
Revenue Code. The Plan was established to provide an additional
benefit to eligible participants in the Employees Savings Plan whose
benefit under that Plan would be curtailed by limits in effect under
the Internal Revenue Code for qualified plans. Of the amounts set
forth in the "All Other Compensation" column, $6,333, $2,375, $2,374,
$2,375 and $4,692 represent the contributions made on behalf of Messrs.
Poist, Wright, Rappoli, Sullivan and Williams, respectively, by the
Employees Savings Plan. Amounts credited to the accounts of Messrs.
Poist, Wright, Rappoli, Sullivan and Williams by the Executive Salary
Continuation and Excess Benefit Plan in 1997 equaled $9,195, $8,602,
$5,423, $4,569 and $1,499, respectively.
<PAGE>
<PAGE 9>
PENSION PLAN TABLE
The following table shows annual retirement benefits payable to
employees, including Executive Officers, upon retirement at age 65, in various
compensation and years of service classifications, assuming the election of a
retirement allowance payable as a life annuity from the Pension Plan for
Employees of Commonwealth Energy System and Subsidiary Companies and the
Executive Salary Continuation and Excess Benefit Plan for Employees of
Commonwealth Energy System and Subsidiary Companies, as of December 31, 1997.
<TABLE>
<CAPTION>
Highest Annual
Consecutive 3-Year
Average Base
Salary of Last Annual Benefit for Years of Service (1)
10 Years 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years
<S> <C> <C> <C> <C> <C> <C>
$ 90,000 .... $ 15,673 $ 23,509 $ 31,345 $ 39,181 $ 47,018 $ 51,104
120,000 .... 21,173 31,759 42,345 52,931 63,518 69,104
150,000 .... 26,673 40,009 53,345 66,681 80,018 87,104
180,000 .... 32,173 48,259 64,345 80,431 96,518 105,104
210,000 .... 37,673 56,509 75,345 94,181 113,018 123,104
240,000 .... 43,173 64,759 86,345 107,931 129,518 141,104
270,000 .... 48,673 73,009 97,345 121,681 146,018 159,104
300,000 .... 54,173 81,259 108,345 135,431 162,518 177,104
330,000 .... 59,672 89,509 119,345 149,181 179,018 195,104
360,000 .... 65,172 97,759 130,345 162,931 195,518 213,104
390,000 .... 70,672 106,009 141,345 176,681 212,018 231,104
420,000 .... 76,172 114,259 152,345 190,431 228,518 249,104
450,000 .... 81,672 122,509 163,345 204,181 245,018 267,104
- -------------
<FN>
(1) Federal law places certain limits on the amount of benefits which can be
paid from qualified pension plans. Payments made by the System in
excess of the applicable limitations are made pursuant to the terms of
the Executive Salary Continuation and Excess Benefit Plan for Employees
of Commonwealth Energy System and Subsidiary Companies. For 1997, the
maximum annual compensation limit under the Pension Plan for Employees
of Commonwealth Energy System and Subsidiary Companies was $160,000, and
the maximum annual benefit under that Plan was $125,000.
</TABLE>
The Pension Plan is a non-contributory defined benefit plan. The Plan
is a final average earnings type plan under which benefits reflect the
employee's years of credited service. The employee receives the higher of
either a Social Security integrated or non-integrated formula to realize the
maximum retirement benefit applicable to his or her employment history. Both
of the formulae are based on the average of the three highest consecutive
January 1 base salaries during the ten-year period preceding the employee's
retirement or termination. Retirement benefits are available to employees on
or after age fifty-five provided the sum of their age and years of service is
at least seventy-five. Messrs. Poist, Wright, Rappoli, Sullivan and Williams
have 33, 30, 23, 22 and 23 credited years of service respectively. For the
purposes of calculating the annual retirement benefits of Messrs. Poist,
Wright, Rappoli, Sullivan and Williams pursuant to the Plan, only the amounts
set forth in the summary compensation table as "Salary" are utilized to
determine each Executive Officer's three highest consecutive January 1 base
salaries during the ten-year period preceding the Executive Officer's
retirement or termination.
<PAGE>
<PAGE 10>
Each Executive Officer of the System has elected certain pre-retirement
death benefits and supplemental retirement benefits in exchange for waiving
certain standard life insurance benefits (in excess of $50,000), and the
survivor income benefits generally available to all eligible employees. The
alternative program for Executive Officers provides a pre-retirement death
benefit of either: (i) a lump-sum payment of three times annual base salary
or (ii) fifty percent of monthly base salary for one hundred and eighty
months. The supplemental retirement benefit provides that an Executive
Officer may retire after the attainment of age fifty-five and completion of
ten years of service. Normal retirement at age sixty-five provides an annual
payment equal to thirty-five percent of final base salary per year for life or
for a period of one hundred and eighty months, whichever is longer. Benefits
are reduced for retirement prior to age sixty-five. The supplemental
retirement benefits are in addition to the amounts shown in the table above
and are not subject to limitation. If termination of employment occurs
following a change in control of the System after the Executive Officer's
completion of ten years of service with the System but before the attainment
of age fifty-five, the Executive Officer shall be entitled to receive upon
attainment of age fifty-five a retirement benefit equal to the amounts that
would have been payable had the Executive Officer remained in the employment
of the System until the date of the Executive Officer's fifty-fifth birthday
and retired on that date. Should the employment of the Executive Officer
terminate for any other reason (other than death) and before completion of ten
years of service and attainment of age fifty-five, there are no benefits
payable under this alternative program for Executive Officers.
The System has entered into Severance Agreements with its Executive
Officers, including Messrs. Poist, Wright, Rappoli, Sullivan and Williams.
The Severance Agreements provide that in the event of termination of
employment following a change of control of the System, as defined in the
Severance Agreements, the System shall pay to the Executive Officer a lump sum
severance benefit together with certain other benefits. The severance benefit
payable to Mr. Poist is up to three times his annual salary and annual
incentive compensation, and to Messrs. Wright, Rappoli, Sullivan and Williams
up to two times annual salary and annual incentive compensation. No benefit
would be paid if the effect of any payment would be to provide benefits above
those normally payable beyond age sixty-five.
<PAGE>
<PAGE 11>
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended,
requires Trustees, Executive Officers and persons who beneficially own more
than ten percent (10%) of the System's Common Shares to file initial reports
of ownership on Form 3 and reports of changes in ownership on Form 4 and/or
Form 5 with the Securities and Exchange Commission (the "Commission") and any
national securities exchange on which the System's securities are registered.
Trustees, Executive Officers and greater than ten percent (10%) beneficial
owners are required by the Commission's regulations to furnish the System with
copies of all Section 16(a) forms they file.
Based on a review of the copies of such forms furnished to the System
and written representations from the Trustees and Executive Officers, the
System believes that all Section 16(a) filing requirements applicable to its
Trustees, Executive Officers and greater than ten percent (10%) beneficial
owners were complied with for 1997.
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Executive Compensation Committee of the Board of Trustees (the
"Committee") is composed of three independent, non-employee Trustees. The
Committee reviews and approves compensation levels for the System's Chief
Executive Officer and oversees the System's executive compensation programs
affecting all Executive Officers. These programs have been designed in order
to attract, retain, motivate and reward those individuals who are most
responsible for the System's growth and profitability. The programs reflect
the Committee's objectives of tying a substantial portion of each Executive
Officer's compensation to both the System's and the individual's success in
meeting designated goals and objectives and in realizing increases in total
shareholder return.
Compensation for Executive Officers consists of base salary and awards
of cash incentive compensation under the System's Annual Incentive Plan and
1996-1997 Strategic Plan Compensation Program. Long-term incentive awards in
the form of restricted stock awards of Common Shares are made under the terms
of the System's Long Term Incentive Plan. Executive Officers also participate
in the Pension Plan and the Employees Savings Plan and receive benefits under
medical and other benefit plans which are available to employees generally.
Base Salary
In setting the base salaries for the Chief Executive Officer and all
other Executive Officers, the Committee evaluates the general responsibilities
of the particular position and the individual's experience in that position
and also applies the data and criteria described in the next paragraph.
The Chief Executive Officer's base salary target is designed generally to
match the market median for the utility reference group described in the next
paragraph. The Committee adjusts the Chief Executive Officer's salary in
relation to the salary range target through the evaluation of the same
objective criteria used to determine the Chief Executive Officer's annual
incentive award set forth below. Less emphasis is placed on base salary
adjustments than on incentive compensation, consistent with the Committee's
objectives of placing increasingly greater emphasis on performance based,
at-risk incentive compensation.
<PAGE>
<PAGE 12>
In setting the Chief Executive Officer's base salary for 1997, the
Committee surveyed and reviewed compensation levels and the reference criteria
relating to such compensation levels within the gas and electric utility
industry. Compensation data and comparisons were provided to the Committee by
independent sources and were used by the Committee together with market
compensation data provided by the System's human resources department,
compensation reports contained in proxy materials for companies considered by
the Committee to be similar to the System in size, responsibility and
complexity and utility industry references such as those provided by the
Edison Electric Institute. Among the reference criteria reviewed by the
Committee in developing external market pay norms were business type
(investor-owned utilities), scope (utilities with revenues of approximately
$500 million to $2 billion) and location (utilities headquartered in the
northeast region of the U.S.). This market reference group of companies
represents a subset of Value Line, Inc.'s utility sample.
Annual Incentive Compensation
The Chief Executive Officer is eligible to receive annual cash bonus
compensation under the System's Annual Incentive Plan. In 1997, the Annual
Incentive Plan provided for awards to the Chief Executive Officer of up to a
maximum of 43.5% of annual base salary. Both individual and System
performance goals and objectives were set. The Chief Executive Officer's
award for 1997 was determined on a weighted basis, with two-thirds of the
award potential attributable to the attainment of System goals and objectives
and one-third of the award potential attributable to individual goals and
objectives. For 1997, the System criteria forming the goals and objectives
applicable to the Annual Incentive Plan were: 1) meeting pre-established
targets comparing System actual net income to budgeted net income for 1997; 2)
success in implementing budgetary constraints in the interest of controlling
costs; and 3) meeting certain pre-established benchmark measures of operation
and maintenance expenses per customer, as compared to a peer group of 18
utility companies recommended by the System's independent compensation
consultant. Each of the three System goals and objectives are equally
weighted, and awards are made based on meeting, exceeding or reaching maximum
attainment of targets.
The goal established for actual net income was to meet or exceed the
approved budgeted amounts. The System's 1997 net income exceeded targeted net
income by 9.8%, just below the 10% maximum award standard. The goal
established for cost control was for operation and maintenance expenses in
1997 to be below the approved budgeted amounts. This goal was exceeded by the
System having reduced actual operation and maintenance expenses to 3.8% below
established budgets. The goal of maintaining operation and maintenance
expenses per customer within the top 50% of the 18 company industry peer group
was also exceeded, as the System was rated the fifth most effective of the 18
companies in controlling operation and maintenance expenses. In the
aggregate, the goals and objectives applicable to the System component of the
Annual Incentive Plan were rated as 96% achieved.
The individual goals of the Chief Executive Officer for 1997 under the
Annual Incentive Plan included: the Chief Executive Officer's contributions in
creating a value-added organization; implementation of the System's Strategic
Plan; oversight of the consolidation of gas and electric operations; and the
effective continuance and expansion of the System's investor relations
program. Performance relative to achieving individual goals was rated as 85%
achieved, resulting in an aggregate performance rating of 92% achievement.
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Long-Term Compensation
The System has in place two long term incentive compensation plans, one
which provides for the potential of awards of restricted Common Shares of the
System and the other providing for the potential of cash awards.
The Long-Term Incentive Plan, approved by shareholders in 1994, measures
performance and provides for the potential for awards of Common Shares over a
three-year Plan Period. The Plan provides for awards to the Chief Executive
Officer of up to a maximum of 50% of annual base salary, awarded in the form
of restricted Common Shares. Awards of Common Shares under the Plan are made
if the System's average three-year total return (share appreciation and
dividends), as compared to the peer group index of utility companies as
established by Value Line, Inc., meets or exceeds the achievement standards
set by the Committee at the beginning of a Plan Period. In this way, the
interests of Executive Officers and Shareholders continue to be aligned.
Under the terms of the Plan, no three-year Plan Period was in effect for
1995-1997, and as a result no award was made.
The 1996-1997 Strategic Plan Compensation Program ("Program") provided
Executive Officers the opportunity to receive cash awards up to an amount
which is equivalent to the amount which would be awarded in Grant Shares under
the terms of the Long Term Incentive Plan as if a three-year Plan Period
ending in 1997 was in effect. Unlike the Long Term Incentive Plan, which uses
Shareholder total return as the sole criterion, the Program rated System
Common Share performance, the Executive Officer's specific contributions to
achieving results in implementing the System's Strategic Plan, and the Chief
Executive Officer's general and overall performance. For the two-year Program
period, commencing in 1996, the Threshold, Program Target and Maximum
Shareholder Return achievement standards were 95% of Index Average, Index
Average, and 120% of Index Average, respectively. During the Program period,
the System's average annual total return was equal to 219% of the Value Line
peer group's total return, which under the terms of the Program provided for a
maximum potential award to the Chief Executive Officer of up to 50% of 1996
annual base salary. The individual performance of the Chief Executive Officer
under the Plan was rated at 71% achieved, resulting in a cash award pursuant
to the terms of the Program of 35.5% of his 1996 annual base salary.
Other Executive Officers
The Chief Executive Officer, in conjunction with the System's human
resources department and an independent consultant, established salary ranges
for each Executive Officer. The salary ranges were based in part upon
salaries provided to executive officers in the System's industry peer group,
as reported by the Edison Electric Institute and from regional salary surveys,
so as to establish salary ranges generally in the median of the peer group.
Specific salary levels were then established through an evaluation of the
responsibilities of the position, the individual's experience in that position
and the Executive Officer's achievement of goals and performance of duties.
The base salary levels, as recommended by the Chief Executive Officer, were
also reviewed and approved by the Executive Compensation Committee.
In addition to base salary, the named Executive Officers are also
eligible to receive compensation under the Annual Incentive Plan, the Long
Term Incentive Plan and the 1996-1997 Strategic Plan Compensation Program.
The named Executive Officers are eligible to receive compensation of up to a
maximum of 38% (for Vice Presidents) to 43.5% (for the Operating Companies'
President) of annual base salary under the Annual Incentive Plan and of up to
40% (for Vice Presidents) to 50% (for the Operating Companies' President) of
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<PAGE 14>
annual base salary in restricted Common Shares under the Long Term Incentive
Plan and in cash awards under the 1996-1997 Strategic Plan Compensation
Program. In 1997, the System goals and objectives constituting the annual
performance criteria and the corresponding weightings which determined
eligibility for awards to the named Executive Officers under the Annual
Incentive Plan were the same as those applicable to the Chief Executive
Officer. The individual goals and objectives of the other Executive Officer
Annual Incentive Plan participants included: negotiating critical contracts
relating to System electric generation plants; overseeing important state
legislation affecting the System's electric operations; and continuing and
expanding the System's investor relations program.
The performance criteria applicable to the named Executive Officers
under the Long Term Incentive Plan and the 1996-1997 Strategic Plan
Compensation Program are the same as those applicable to the Chief Executive
Officer.
Policy on Deductibility of Compensation
Pursuant to Section 162(m) of the Internal Revenue Code, the ability of
the System to deduct the compensation paid to any of the five most highly paid
officers in excess of $1 million is limited by Federal Law. The compensation
of each of the System's Executive Officers, however, is lower than the $1
million threshold at which tax deductions are limited. It is therefore not
necessary that the Committee formulate a policy with respect to qualifying
compensation for deductibility under the Internal Revenue Code.
Conclusion
The Committee continues to take action to link executive compensation
directly to corporate performance and shareholder total return. A substantial
portion of each Executive Officer's compensation is now dependent upon
measurable individual performance and System Common Share appreciation.
THE EXECUTIVE COMPENSATION COMMITTEE
Michael C. Ruettgers, Chairperson
William J. O'Brien
Gerald L. Wilson
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COMPARATIVE TOTAL SHAREHOLDER RETURN
The line graph below compares the cumulative total shareholder return
for the System's Common Shares to the cumulative total return of the S&P 500
Stock Index and a Peer Group Index which is comprised of 87 utility companies
(including the System) which are followed by Value Line, Inc. The entities
which comprise the Peer Group are also set forth hereinafter.
Comparative Five-Year Total Returns
Commonwealth Energy System, S&P 500 and Value Line Peer Group
(Performance results through 12/31/97)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1993-1997) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1992 1993 1994 1995 1996 1997
COM/Energy $100 $116 $ 98 $130 $145 $220
S&P 500 100 110 112 154 190 253
Peer Group 100 112 98 129 130 166
Assumes $100 invested at the close of trading on the last trading day of
1992 in COM/Energy Common Shares, S&P 500 and the Peer Group. Also
assumes reinvestment of dividends.
Source: Value Line, Inc.
PEER GROUP
Allegheny Power System, Inc. MDU Resources Group, Inc.
Ameren Corp. MidAmerican Energy Holdings Company
American Electric Power Co., Inc. Minnesota Power & Light Co.
Atlantic Energy Inc. Montana Power Co.
Baltimore Gas and Electric Company Nevada Power Co.
Boston Edison Company New Century Energies, Inc.
Carolina Power & Light Co. New England Electric System
Central Hudson Gas & Electric Corp. New York State Electric & Gas Corp.
Central Louisiana Electric Company Inc. Niagara Mohawk Power Corporation
Central Maine Power Co. NIPSCO Industries, Inc.
Central & South West Corp. Northeast Utilities
Central Vermont Public Service Corp. Northern States Power Co.
CILCORP Inc. Northwestern Public Service Co.
CINergy Corp. OGE Energy, Inc
CMS Energy Corp. Orange and Rockland Utilities, Inc.
Commonwealth Energy System Otter Tail Power Co.
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<PAGE 16>
Consolidated Edison Co. of New York, Inc. PG&E Corporation
DPL, Inc. PacifiCorp.
Delmarva Power & Light Co. PECO Energy Company
Dominion Resources, Inc. Pinnacle West Capital Corp.
DQE Potomac Electric Power Co.
DTE Energy Corporation PP&L Resources, Inc.
Duke Power Co. Public Service Co. of New Mexico
Eastern Utilities Associates Public Service Enterprise Group Inc.
Edison International Puget Sound Power & Light Co.
Empire District Electric Company Rochester Gas and Electric Corp.
Enova Corporation St. Joseph Light & Power Co.
Entergy Corporation SCANA Corp.
FirstEnergy Corp. Sierra Pacific Resources
Florida Progress Corp. SIGCORP
FPL Group, Inc. The Southern Company
GPU, Inc. TECO Energy, Inc.
Green Mountain Power Corp. Texas Utilities Company
Hawaiian Electric Industries, Inc. TNP Enterprises, Inc.
Houston Industries, Incorporated Unicom Corp.
Idaho Power Co. Unisource Energy Corp.
IES Industries United Illuminating Co.
Illinova Corp. UtiliCorp. United Inc.
Interstate Power Co. Washington Water Power Co.
IPALCO Enterprises, Inc. Western Resources, Inc.
Kansas City Power & Light Co. Wisconsin Energy Corp.
KU Energy Corporation WPL Holdings, Inc.
LG&E Energy Corp. WPS Resources Corporation
Long Island Lighting Co.
MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES
The System's Board of Trustees held thirteen meetings throughout 1997.
The Board has an Audit Committee, an Executive Compensation Committee, a
Nominating Committee, a Benefit Review Committee and a Strategic Planning
Committee.
The Audit Committee is composed of Betty L. Francis, Chairperson, Kevin
C. Bryant and Peter H. Cressy. The Committee held four meetings in 1997. The
Committee's functions are to recommend the selection of an independent public
accountant, to review the scope of and approach to audit work, to review
non-audit services provided by the independent public accountants and to
review accounting principles and practices and the adequacy of internal
controls.
The Executive Compensation Committee is composed of Michael C.
Ruettgers, Chairperson, William J. O'Brien and Gerald L. Wilson. During 1997,
the Committee held five meetings. This Committee reviews and recommends
compensation and promotional adjustments for certain of the System's personnel
and also reviews and recommends adjustments to the compensation of Trustees.
The Nominating Committee is composed of Sheldon A. Buckler, Chairperson,
Franklin M. Hundley and William J. O'Brien. The Committee held four meetings
in 1997. The functions of the Committee are to coordinate suggestions or
searches for potential nominees for the position of Trustee, to review and
evaluate qualifications of potential nominees and to recommend to the Board of
Trustees nominees for vacancies occurring from time to time on the Board of
Trustees. The Committee will consider nominees recommended by Shareholders
upon the timely submission of the names of such nominees with their
qualifications and biographical information forwarded to the Nominating
Committee of the Board of Trustees.
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<PAGE 17>
The Benefit Review Committee is composed of Franklin M. Hundley,
Chairperson, Kevin C. Bryant and Betty L. Francis. During 1997, the Committee
held one meeting. The Committee was organized to consider and recommend to
the Board of Trustees matters associated with the System's major funded
benefit plans. Functions of the Committee include recommending the
composition of benefit plan boards and reviewing investment policy,
objectives, performance or proposed changes related to the plans.
The Strategic Planning Committee is composed of Gerald L. Wilson,
Chairperson, Peter H. Cressy and Michael C. Ruettgers. The Committee held
seven meetings during 1997. The functions of this Committee are to attend
strategic planning sessions, provide support and insight to management and
coordinate management planning activities with the Board of Trustees.
Effective January 1, 1998, each Trustee who was not an employee of the
System is compensated for his or her services as Trustee at the rate of
$17,500 per year, plus $1,000 for each Trustee and Committee meeting attended.
The Chairpersons of the Audit, Executive Compensation, Benefit Review and
Strategic Planning Committees each receive an additional $1,500 during the
year. In addition, the Chairman of the Board receives a retainer of $20,000
per year for his services as Chairman of the Board and of the Nominating
Committee.
Trustees are entitled to defer all or a specified portion of their
compensation pursuant to the terms of the Deferred Compensation Plan for
Trustees of Commonwealth Energy System. An account is established for each
Trustee electing to participate in the Plan, which account is credited with
the amount which would otherwise be payable to the Trustee as compensation for
the Trustee's services. At the end of each month, interest is credited at an
annual rate equivalent to the weighted average prime lending rate. Upon the
Trustee's retirement, the account balance is paid either in a lump sum or in
annual installments according to the election made by the Trustee. The rights
of the Trustee in the account are not assignable and constitute an unsecured
claim against the general assets of the System.
The Retirement Plan for Trustees of Commonwealth Energy System was
adopted to provide retirement benefits to non-management members of the Board
of Trustees in recognition of their services to the System. Members of the
Board of Trustees who have served as Trustees for at least five years are
eligible to participate in the Plan. Each eligible Trustee qualifies for an
annual retirement benefit payment equal to fifty percent of the annual
retainer fee in effect at retirement (excluding retainers for chairing
committees), plus 10% of the annual retainer fee for each year in addition to
five years served, up to 100% of such fee. The annual retirement benefit
payment is adjusted to reflect the first subsequent increase, if any, in the
annual retainer fee for service on the Board following the Trustee's
retirement. The annual retirement benefit payment becomes vested at the time
of eligibility and is payable to Trustees for a period equal to the greater of
ten years or the number of years of service as a Trustee. Provided that
Common Shareholders approve the Restricted Common Share Plan for Trustees of
Commonwealth Energy System, the Board will take action to amend the Plan by
limiting the number of years following retirement during which benefits are
paid to a Trustee to the Trustee's number of years of service on the Board as
of June 1, 1998.
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<PAGE 18>
2-AMENDMENT TO SECTION 22 OF THE DECLARATION OF TRUST
There will be presented to Shareholders by the Board of Trustees a
proposal to consent to an amendment to Section 22 of the System's Declaration
of Trust, which Section sets forth the conditions under which presently
authorized but unissued Common Shares of the System may be issued by the
Trustees without the vote or written consent of a majority of the Common
Shares outstanding at the time. The purposes of the amendment are to expand
the conditions under which such presently authorized but unissued Common
Shares may be issued without such vote or written consent of a majority of the
Common Shares outstanding at the time. The text of the proposed amendment to
Section 22 is annexed as Appendix A to this Proxy Statement.
The proposed amendment to Section 22 would allow for the issuance of
Common Shares to fund the Restricted Common Share Plan for Trustees of
Commonwealth Energy System, which Shareholders are being requested to approve
at the 1998 Annual Meeting of Shareholders. The Trustees believe that such
amendment will be in the interest of Shareholders, as it will both enable the
System to continue to attract and retain qualified Trustees and will provide
further incentive to Trustees to maximize shareholder value for the benefit of
Shareholders. The annual Common Share payment amount is projected to be most
representative of the value of retirement benefits which will no longer be
provided under the terms of the Retirement Program for Trustees of
Commonwealth Energy System if the Restricted Common Share Plan is approved.
The Board of Trustees believes that the Restricted Common Share Plan will
provide greater incentives for Trustees and will better align the interests of
Trustees with the interests of Shareholders.
The required approval by Shareholders to the proposed amendment and the
subsequent enactment of the Restricted Common Share Plan for Trustees of
Commonwealth Energy System will allow the System to continue to attract and
maintain valuable Trustees who will continue to advance the interests of
Shareholders.
Upon the consent of the holders of a majority of the outstanding Common
Shares present at the meeting and entitled to vote on the proposed amendment,
the Trustees of the System will on May 7, 1998 vote to amend the Declaration
of Trust and will file said Declaration of Trust, as amended, as required by
the terms of the Declaration of Trust and the laws of the Commonwealth
of Massachusetts.
THE BOARD OF TRUSTEES RECOMMENDS A VOTE "FOR" APPROVAL OF THE AMENDMENT.
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<PAGE 19>
3-RESTRICTED COMMON SHARE PLAN FOR TRUSTEES
OF COMMONWEALTH ENERGY SYSTEM
On February 26, 1998, the Board of Trustees approved and adopted,
effective as of June 1, 1998, the Restricted Common Share Plan for Trustees of
Commonwealth Energy System (the "Plan"). Since Plan payments are to be made
in the form of System Common Shares, the Board of Trustees is seeking
Shareholder approval of the Plan and has conditioned the adoption of the Plan
on Shareholder approval.
The purpose of the Plan is to increase non-employee Trustee ownership
interest in the System by providing compensation for service on the Board of
Trustees in the form of Common Shares, thus further aligning the interests of
the members of the Board with those of Shareholders of the System. A summary
description of the Plan follows. This description is qualified in its
entirety by reference to the full text of the Plan, which is attached to this
proxy statement as Appendix B.
Eligible participants under the Plan are members of the Board of
Trustees who are not full time employees of the System or any of its
subsidiaries. The Plan provides for issuance annually of a number of Common
Shares equal in value to $7,000 in payment of a portion of the annual Trustee
retainer fee for services on the Board of Trustees. The number of Common
Shares issuable is determined by dividing the dollar amount of $7,000 to be
distributed in the form of Common Shares by the fair market value of a share
of the Common Shares on the date the fee is payable. For this purpose fair
market value means the average closing price of the Common Shares in
consolidated trading on the first five trading days of the month that the
Common Shares are issued, as reported by the New York Stock Exchange.
Pro-rata partial issuances of Common Shares will be made whenever a Trustee
has served on the Board for a portion of a calendar year.
The annual amount of $7,000 to be paid in Common Shares is equivalent to
the projected additional average retirement benefit which would otherwise be
provided to Trustees under the terms of the Retirement Program for Trustees of
Commonwealth Energy System. Upon the approval of the Plan, the Board intends
to limit the number of years during which benefits will be paid to a Trustee
upon the Trustee's retirement to the Trustee's number of years of service on
the Board as of June 1, 1998. As a result, no increase in overall Trustee
compensation shall result. Common Shares issued under the Plan are subject to
restrictions that they may not be sold or transferred until the restrictions
lapse. Restrictions lapse upon (a) death, (b) disability, (c) retirement in
accordance with the policy on retirement of non-employee Trustees, (d)
termination of service with the consent of a majority of the members of the
Board of Trustees, other than the participant, (e) five years passing from the
date of issuance of the Common Shares, or (f) a change in control, as defined
in the Plan. If a participant ceases to be a Trustee for any other reason,
the restricted unvested shares are forfeited and revert to the System. The
certificates representing restricted Common Shares are to be held by the
System until the lapse of restrictions, but the participant is entitled to all
voting, dividend and distribution rights of such Common Shares.
On March 17, 1998 the closing price per share of the Common Shares on
the New York Stock Exchange was $36 5/8.
The adoption of the Plan will require the affirmative votes of the
holders of a majority of the Shares present at the meeting and entitled to
vote.
THE BOARD OF TRUSTEES RECOMMENDS A VOTE "FOR" APPROVAL OF THE RESTRICTED
COMMON SHARE PLAN FOR TRUSTEES OF COMMONWEALTH ENERGY SYSTEM.
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<PAGE 20>
4-SHAREHOLDER PROPOSAL
The System has been advised that Mr. John Jennings Crapo, Porter Square
Branch, P.O. Box 151, Cambridge, Massachusetts, 02140-0002, holder of 450
Common Shares, proposes to submit the following proposal at the 1998 Annual
Meeting:
RESOLVED: That the shareholders of Commonwealth Energy System assembled
in Annual Meeting of Shareholders balloting in person and by proxy hereby
request that the Board of Trustees present to shareholders at the next Annual
Meeting of Shareholders an appropriate amendment to the Declaration of Trust
dated December 31, 1926, as amended, to provide that any elections following
the adoption of the said amendment, Trustees whose terms have expired be
elected annually and not by classes as is now provided. But this amendment
shall not apply to any person holding the office of Trustee when this
amendment is presented to stockholders for ratification at the Annual Meeting
of Shareholders in question.
SUPPORTING STATEMENT: This proposal to de-classify the Board of
Trustees has received considerable support. Proponent believes the proposal
will receive more support now that he has modified it to have the amendment to
the Declaration of Trust not go into effect until Trustees who serve at time
as Trustees no longer serve as Trustee/Trustees. The Trustees make
commitments to serve three years each term as is presently allowed and this
dedication is to be acknowledged by not rudely terminating devoted service to
the Commonwealth Energy System.
BOARD OF TRUSTEES RECOMMENDATION:
The Board of Trustees recommends a vote AGAINST this proposal for the
following reasons:
This proposal has been submitted at various Annual Meetings since 1991.
It requests that the Board of Trustees submit a proposal to Shareholders at
the 1999 Annual Meeting, calling for the repeal of the classified Board, so
that all Trustees would be elected on an annual basis. The classified board
was adopted at the 1987 Annual Meeting, when Shareholders voted to amend the
System's Declaration of Trust to create three classes of Trustees with an
equal number of Trustees in each class, and to provide that the Trustees would
serve three-year staggered terms, such that three Trustees are eligible for
election each year. The classified board is intended to help to ensure
continued familiarity of Board members with the business, management and
policies of the System, since a majority of the Trustees at any given time
would have prior experience as Board members. These amendments are also
designed to encourage persons seeking to acquire control of the System to
initiate an acquisition through arms-length negotiations with the System's
Board of Trustees and management, by making it more difficult to change the
composition of the Board. Also, the amendments may allow the System's
management to obtain more time and information for evaluating a takeover
proposal, in order to fully protect the interests of the System and its
Shareholders.
The Board continues to believe that each Trustee is fully accountable to
Shareholders throughout each term of office, whether that term is three years
or one year. The Board further notes that the classified board system was
determined to be of sufficient merit such that the Massachusetts legislature
has codified that system in its 1990 amendments to the laws pertaining to
Massachusetts business corporations (however, the System, as a Massachusetts
Trust, is not affected by this legislation).
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Repeal of the classified Board (which, if the present proposal is
adopted, would actually be pursuant to the acceptance of a proposed Amendment
to the Declaration of Trust to be offered at the 1999 Annual Meeting of
Shareholders) requires the affirmative vote or written consent of
three-quarters of the shares entitled to vote, in accordance with the terms of
the System's Declaration of Trust.
ACCORDINGLY, A VOTE "AGAINST" THE PROPOSAL IS RECOMMENDED.
5-OTHER BUSINESS
The Board of Trustees of the System knows of no matters other than those
set forth in the Notice of the Annual Meeting which are likely to be brought
before the meeting. If any other matters of which the Board of Trustees is
not aware are appropriately presented for action, however, it is the intention
of the persons named in the proxy to vote in accordance with their judgment on
such matters.
MISCELLANEOUS
The independent public accounting firm selected by the Trustees as
Auditor of the System is Arthur Andersen LLP. It is expected that
representatives of Arthur Andersen LLP will be present at the Annual Meeting
with the opportunity to make a statement if they desire to do so and to
respond to appropriate questions.
The cost of soliciting proxies will be borne by the System. A limited
number of regular employees may solicit proxies by telephone or in person
subsequent to the initial solicitation by mail. In addition, the System has
retained the firm of D. F. King to aid in such solicitation of proxies. The
System expects to pay such firm a fee of $5,500 plus expenses. The System
will reimburse banks, brokerage firms and other custodians, nominees and
fiduciaries for reasonable expenses incurred in sending proxy material to
security owners.
The proxy card for a participant in the System's Dividend Reinvestment
and Common Share Purchase Plan includes the number of shares which are
registered in the participant's name and the number of shares beneficially
owned by the participant that are held in the name of the nominee of the
System for the Plan. A participant's vote with respect to the shares
registered in the participant's name is also an instruction by the participant
to the nominee to vote the shares credited to the participant's account under
the Plan.
In order for Shareholder proposals for the 1999 Annual Meeting of
Shareholders to be eligible for inclusion in the System's Proxy Statement,
they must be received by the System at its principal office in Cambridge,
Massachusetts, prior to December 3, 1998.
It is important that proxies be returned promptly to avoid unnecessary
expense. Therefore, Shareholders are urged, regardless of the number of
shares owned, to SIGN, DATE and RETURN the enclosed proxy promptly.
Michael P. Sullivan
Vice President, Secretary
and General Counsel
Cambridge, Massachusetts 02142-9150
March 30, 1998
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<PAGE 22>
APPENDIX A
PROPOSED AMENDMENT TO
SECTION 22 OF THE DECLARATION OF TRUST
Section 22 of the System's Declaration of Trust would be amended by
adding the words "and to fund compensation plans applicable to the Board of
Trustees for services as a Trustee" in subparagraph (c) of Section 22,
so that the third paragraph of Section 22 reads in its entirety, as
follows:
(A) To provide the System with Funds
(1) To acquire additional stock of any subsidiary of the System
which is authorized for its proper corporate purposes;
(2) To acquire common stock of any Massachusetts gas or
electric company if as a result of such transaction the System will own
51% or more of such stock;
(3) To acquire debt securities maturing more than one year from
the date of issue thereof of any subsidiary of the System;
(4) To retire temporary indebtedness of the System incurred by it
for the purchase of such stock or debt securities;
(5) To make temporary advances to any subsidiary of the System; or
(B) In Exchange
(1) For publicly held stock of any subsidiary of the System;
or
(2) For stock of any Massachusetts gas or electric company if as a
result of such exchange the System will own 51% or more of such stock;
or
(C) To provide shares to fund long-term incentive compensation plans
that may be adopted from time to time and to fund compensation plans
applicable to the Board of Trustees for services as a Trustee.
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APPENDIX B
COMMONWEALTH ENERGY SYSTEM
RESTRICTED COMMON SHARE PLAN FOR TRUSTEES
1. Name of Plan. This plan shall be known as the "Commonwealth Energy
System Restricted Common Share Plan for Trustees" and is hereinafter referred
to as the "Plan".
2. Purpose. The purpose of the Plan is to advance the interests of
Commonwealth Energy System (the "System") by providing long-term financial
incentives to Trustees in the form of System Common Shares. By encouraging
such share ownership, the System seeks to attract, retain and motivate
Trustees of experience, ability and quality and to strengthen the mutuality of
interests between the Board of Trustees and the System's Common Shareholders.
3. Effective Date and Term. The Plan was adopted on February 26, 1998, to
be effective as of June 1, 1998, provided the Plan is approved by the System's
Common Shareholders at the next Annual Meeting of Shareholders of the System
following adoption. The Plan shall remain in effect until amended or
terminated by action of the Board of Trustees of the System.
4. Eligible Participants. Each member of the Board of Trustees from time
to time who is not a full time employee of the System or any of its
subsidiaries shall be eligible to participate in the Plan (the
"Participants").
5. Automatic Receipt of Restricted Shares. In accordance with the votes
taken by the Board of Trustees on February 26, 1998, until further action by
the Board of Trustees and commencing with the month following approval of the
Plan by the System's Common Shareholders, in addition to the cash retainer fee
compensation established by the Board of Trustees, each Participant shall be
paid annual retainer fees at the rate of $7,000 for service on the Board of
Trustees, payable in Common Shares, par value $2 per share of the System,
subject to the restrictions set forth in Section 6 hereof. Such fee shall be
payable annually on the date of the Board of Trustees' first regularly
scheduled meeting in a calendar year. The number of Common Shares to be issued
to each Participant on each payment date shall be determined by dividing the
annual retainer fee which is to be paid in Common Shares by the Fair Market
Value of such Common Shares, as hereinafter defined. A pro-rata issuance of
Common Shares will be made for 1998 and for any period during which a
Participant is entitled to payment for less than a full year. The Board of
Trustees shall have the authority to revise the amount of annual retainer fees
for service on the Board of Trustees payable in Common Shares under this
Section 5 not more frequently than annually.
6. Restrictions on Shares. The Common Shares issued under Section 5 shall
be restricted and may not be sold or transferred (including, without
limitation, transfer by gift or donation), except that such restrictions shall
lapse upon:
(a) Death of the Participant;
(b) Disability of the Participant preventing continued service on the
Board;
(c) Retirement of the Participant from service as a Trustee of the
System in accordance with the policy on retirement of non-employee
Trustees then in effect;
(d) Termination of service as a Trustee with the consent of a majority
of the members of the Board other than the Participant;
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(e) The passage of five years from the date of issue of any such
Common Shares; or
(f) A Change in Control, as hereinafter defined.
If a Participant ceases to be a Trustee of the System for any other
reason, the unvested Common Shares issued to such Trustee subject to this
Section shall be forfeited and shall revert to the System.
The certificates for Common Shares which are subject to this Section
shall be held by the System until the lapse of restrictions as provided in
this Section; provided, however, the Participant shall be entitled to all
voting, dividend and distribution rights for such Common Shares.
Participants shall have the right to direct in writing, on forms
provided by the System, that upon the lapse of restrictions in accordance with
subsections (a) through (f) above, the Common Shares held by such Participant
under the Plan shall be transferred and delivered by the System to the
individuals or entities as specified by the Participant on such form.
7. Fair Market Value. The term "Fair Market Value" shall mean the average
closing price of the Common Shares in consolidated trading on the first five
trading days of the month that the Common Shares are issued, as reported on
the principal national securities exchange on which the Common Shares are
listed or admitted to trading.
8. Fractions of Shares. Whenever under the terms of the Plan a fractional
share would be required to be issued, the number of shares shall be rounded up
to the next highest whole number of shares.
9. Change in Control. For the purposes of this Plan, a "change in control"
shall mean the occurrence of any of the following:
(1) The System receives a report on Schedule 13D filed with the
Securities and Exchange Commission disclosing that any person (as
such term is defined in Section 13(d) of the Exchange Act),group,
partnership, association, corporation or other entity is the
beneficial owner, directly or indirectly, of 20% or more of the
outstanding voting Common Shares of the System (other than: 1) a
registered investment company which has expressly stated that it
has no intention to acquire control of the System or which the
Board of Trustees has determined that such registered investment
company has no intention to acquire control of the System and 2)
the Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies); provided that if the Board of Trustees
subsequently determines that such registered investment company
does intend to acquire control of the System or the registered
investment company expresses this intent, the beneficial ownership
of 20% or more of the outstanding voting Common Shares of the
System shall be considered to be a "change in control" event
described in this clause (1);
(2) Any person (as such term is defined in Section 13(d) of the
Exchange Act), group, partnership, association, corporation or
other entity other than the System or a wholly-owned subsidiary of
the System, purchases shares pursuant to a tender offer or
exchange offer to acquire voting shares (or securities convertible
into shares) for cash, securities or any other consideration,
provided that after consummation of the offer, the person, group,
partnership, association, corporation or other entity in question
is the beneficial owner (as defined in Rule 13(d)-3 under the
Exchange Act) directly or indirectly, of 20% or more of the then
<PAGE>
<PAGE 25>
outstanding voting Common Shares of the System (calculated as
directed in paragraph (d) of Rule 13(d)-3 under the Exchange Act
in the case of rights to acquire Common Shares);
(3) The Board of Trustees of the System approves: (a) any
consolidation or merger of the System in which the System is not
the continuing or surviving entity or pursuant to which Common
Shares of the System would be converted into cash, securities or
other property; or (b) any transaction or series of related
transactions the result of which all or substantially all the
assets of the System are sold;
(4) The System ceases to be a reporting company pursuant to Section
13(a) of the Securities Exchange Act of 1934 or any similar
successor provision; or
(5) During any period of two consecutive years (24-month period),
individuals who at the beginning of such period constituted the
Board of Trustees of the System cease for any reason (other than
retirements or resignations in the normal course of business) to
constitute a majority thereof; provided, however, that any Trustee
who is not in office at the beginning of such 24-month period, but
whose election by the Board of Trustees or whose nomination for
election by the System's Common Shareholders was to fill a vacancy
caused by death or retirement and was approved by a vote of at
least two-thirds of the Trustees then still in office and who
either were Trustees at the beginning of such period or whose
election or nomination for election was previously so approved,
shall be deemed to have been in office at the beginning of such
period for purposes of this definition.
10. Information Reporting. At the time the interest of a Participant in the
Common Shares vests, the System will deliver a certificate for such Common
Shares to the Participant and will, in accordance with Internal Revenue
Service regulations, provide to the Participant a Form 1099, reporting the
taxable value of the vested Common Shares, which value shall be based upon the
fair market value of the Common Shares on the date they vest. If the
Participant shall elect under Section 83 of the Internal Revenue Code of 1986,
as amended, to accelerate the recognition of income attributable to the
receipt of Common Shares, the Participant shall furnish the System with a copy
of such election concurrently with its filing with the Internal Revenue
Service, in which case the System will provide a Form 1099 reporting the
taxable value of the granted Common Shares as of the grant date.
11. General Restriction. The issuance of Common Shares or the delivery of
certificates for such Common Shares to Participants hereunder shall be subject
to the requirement that, if at any time the Chief Financial Officer of the
System shall reasonably determine, in his discretion, that the listing,
registration or qualification of such Common Shares upon any securities
exchange or under any state or federal law, or the consent or approval of any
government regulatory body, is necessary or desirable as a condition of, or in
connection with, such issuance or delivery thereunder, such issuance or
delivery shall not take place unless such listing, registration,
qualification, consent or approval shall have been effected or obtained free
of any conditions not reasonably acceptable to the Chief Financial Officer.
12. Rule 16b-3. It is the intention that the Plan and the operation thereof
qualify for the exemption provisions contained in Rule 16b-3 adopted by the
Securities and Exchange Commission under the Securities Exchange Act of 1934,
as amended, as in effect from time to time or any successor rule ("Rule"). To
the extent that the implementation or operation of any provision hereof does
not comply with the requirements of the Rule as applicable to the Plan, such
<PAGE>
<PAGE 26>
provision shall be inoperative or shall be interpreted, to the extent
practicable, to apply in a manner not inconsistent with the requirements of
the Rule.
13. Share Dividends; Share Splits; Share Combinations; Recapitalization.
The Board of Trustees of the System may make appropriate adjustments in the
maximum number of Common Shares subject to the Plan to give effect to any
share dividends, share splits, share combinations, recapitalizations and other
similar changes in the capital structure of the System. The provisions
contained in the Plan shall apply to any other capital shares of the System,
and any other securities which may be acquired by the Participant as a result
of a share dividend, share split, share combination, or exchange for other
securities resulting from any recapitalization, reorganization or any other
transaction affecting the Common Shares subject to the Plan.
14. Termination or Amendment of Plan.
(a) Except as provided in paragraph 14(b), the Board of Trustees may
at any time suspend, reinstate, or terminate the Plan or make such
changes in or additions to the Plan as it deems advisable without
further action on the part of the Common shareholders of the
System, provided;
(i) that no such termination or amendment shall adversely affect
or impair any then issued and outstanding Common Shares
without the consent f the Participant holding such Common
Shares; and
(ii) that no such amendment which (a) materially increases the
maximum number of Common Shares subject to this Plan; (b)
materially increases the benefits accruing to Participants
under the Plan (except as is provided in Section 5); or (c)
materially modifies the requirement as to eligibility for
participation in the Plan may be made without first
obtaining shareholder approval, if independent legal counsel
advises that such approval is necessary.
(b) In the event of a change in control (as defined in Section 9), the
System may neither terminate the Plan nor reduce benefits under
the Plan with respect to those individuals who are Participants as
of the date of the change in control.
15. Shares Subject to the Plan. The maximum number of Common Shares which
may be cumulatively granted under the Plan, subject to adjustment as provided
in Paragraph 13 of the Plan, shall be one percent (1%) of the total issued and
outstanding Common Shares of the System. Any Common Shares which are
forfeited pursuant to Section 6 shall again be eligible for issuance.
16. Governing Law. This Plan shall be subject to and construed in
accordance with the laws of the Commonwealth of Massachusetts.
<PAGE>
<PAGE 27>
COMMONWEALTH ENERGY SYSTEM
Proxy-Annual Meeting of Shareholders-May 7, 1998
This Proxy is Solicited on Behalf of the Board of Trustees
The undersigned hereby appoints Sheldon A. Buckler, Franklin M. Hundley
and William G. Poist, and each or any of them, with power of substitution, as
proxies to attend the Annual Meeting of Shareholders of the System to be held
on Thursday, May 7, 1998 and at any adjournment thereof and to vote the number
of shares which the shareholder(s) would be entitled to vote if personally
present:
To vote your shares for all Trustee nominees, mark the "FOR" box on
item 1. To withhold voting for all nominees, mark the "WITHHELD" box. If you
do not wish your shares voted "FOR" a particular nominee, mark the "EXCEPTION"
box and enter name(s) of the exception(s) in the space provided.
_____________________________________________________________________________
The Trustees recommend a vote "FOR" #1, 2 and #3
1. Election of Trustees
Nominees: S. A. Buckler, B. L. Francis, M. C. Ruettgers
[ ] FOR [ ] WITHHELD [ ] EXCEPTION(S)
EXCEPTION(S): ____________________
2. Amendment to Declaration of Trust
[ ] FOR [ ] AGAINST [ ] ABSTAIN
3. Restricted Common Share Plan for Trustees
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
The Trustees recommend a vote "AGAINST" #4
4. Shareholder Proposal
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
5. Upon any other business that may properly come before the meeting.
_____________________________________________________________________________
This Proxy will be voted as directed above. If no other indication
is made, this proxy will be voted FOR proposals #1, 2 AND 3,
and AGAINST proposal #4.
Any proxy or proxies to vote such shares at said meeting
heretofore given by the shareholder(s) are hereby revoked.
PLEASE SIGN AND DATE ON REVERSE SIDE
____________________________________________________
____________________________________________________
Signature(s) should agree with name(s) printed below
(When signing as attorney, executor or administrator, trustee or
guardian, etc., please indicate your full title as such.)
Acct. No. No. of Shares
Dated_______________________, 1998
PLEASE SIGN, DATE AND RETURN IN ENCLOSED PREPAID ENVELOPE
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
balance sheet, statement of income and statement of cash flows contained in
Form 10-K of Commonwealth Energy System for the fiscal year ended December 31,
1997 and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<CIK> 0000071304
<NAME> COMMONWEALTH ENERGY SYSTEM
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,049,908
<OTHER-PROPERTY-AND-INVEST> 13,767
<TOTAL-CURRENT-ASSETS> 212,986
<TOTAL-DEFERRED-CHARGES> 208,389
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,485,050
<COMMON> 43,063
<CAPITAL-SURPLUS-PAID-IN> 111,912
<RETAINED-EARNINGS> 275,795
<TOTAL-COMMON-STOCKHOLDERS-EQ> 430,770
12,200
0
<LONG-TERM-DEBT-NET> 364,311
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 94,075
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 26,653
820
<CAPITAL-LEASE-OBLIGATIONS> 12,272
<LEASES-CURRENT> 1,229
<OTHER-ITEMS-CAPITAL-AND-LIAB> 542,720
<TOT-CAPITALIZATION-AND-LIAB> 1,485,050
<GROSS-OPERATING-REVENUE> 1,041,744
<INCOME-TAX-EXPENSE> 31,040
<OTHER-OPERATING-EXPENSES> 923,054
<TOTAL-OPERATING-EXPENSES> 954,094
<OPERATING-INCOME-LOSS> 87,650
<OTHER-INCOME-NET> 2,601
<INCOME-BEFORE-INTEREST-EXPEN> 90,251
<TOTAL-INTEREST-EXPENSE> 40,350
<NET-INCOME> 49,901
988
<EARNINGS-AVAILABLE-FOR-COMM> 48,913
<COMMON-STOCK-DIVIDENDS> 34,068
<TOTAL-INTEREST-ON-BONDS> 33,572
<CASH-FLOW-OPERATIONS> 107,551
<EPS-PRIMARY> 2.27
<EPS-DILUTED> 2.27
</TABLE>
