<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 [FEE REQUIRED]
For the fiscal year ended December 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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 Stock 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 17, 1997: $473,652,872
Common Shares outstanding at March 17, 1997: 21,529,676 shares
Document Incorporated by Reference Part in Form 10-K
Notice of 1997 Annual Meeting and
Proxy Statement, dated March 28, 1997
(pages as specified herein) Part III
List of Exhibits begins on page 53 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.......................................... 9
Rates, Regulation and Legislation................... 10
Competition......................................... 14
Segment Information................................. 15
Environmental Matters............................... 15
Construction and Financing.......................... 15
Employees........................................... 15
Item 2. Properties............................................. 16
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............ 27
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 27
PART III
Item 10. Trustees and Executive Officers of the Registrant...... 50
Item 11. Executive Compensation................................. 51
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 51
Item 13. Certain Relationships and Related Transactions......... 52
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................ 52
Signatures........................................................ 76
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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 two new subsidiaries that are pursuing energy-
related business opportunities. Subsidiaries of the System have common
executive and financial management and 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. Two new subsidiaries,
COM/Energy Enterprises, Inc. and COM/Energy Resources, 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 566 MW, and Canal Unit 2, a steam
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 575.8
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 316,000 year-round and 46,900 seasonal customers in 41
communities in eastern Massachusetts covering 1,112 square miles and having an
aggregate population of 645,000. The territory served includes the
communities of Cambridge, New Bedford and Plymouth and the geographic area
comprising Cape Cod and Martha's Vineyard. Cambridge Electric also sells
power at wholesale to the Town of Belmont, Massachusetts.
Natural gas is distributed by Commonwealth Gas Company (Commonwealth
Gas) to approximately 234,000 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,
rubber products, textiles, wire and other fastening devices, abrasives and
grinding wheels, candy, copper and alloys, and chemicals. Among customers
served is a major educational institution, Harvard University (Harvard). In
March 1994, Cambridge Electric was successful in negotiating a seven-year
service agreement with Harvard whose sales in 1996, 1995 and 1994 accounted
for approximately 2.0%, 2.1% and 1.6%, respectively, of the system's total
unit sales.
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 Public Utilities (DPU).
System companies own generating facilities with a net capability at the
time of peak load totaling 1,029.8 MW including 566 MW provided by Canal Unit
1, of which three-quarters (424.5 MW) is sold to neighboring utilities under
long-term contracts, and 287.9 MW provided by Canal Unit 2. Another 126.3 MW
is provided by various smaller system units. Of the 555.7 MW available to the
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
system, 63.3 MW are used principally for peaking purposes. A 3.52% ownership
interest in the Seabrook 1 nuclear power plant provides 40.8 MW of capability
to the system and Central Maine Power Company's 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 204.7 MW. The system also receives 67 MW from a waste-to-energy
plant and has entitlements totaling 23.8 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 DPU 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.
The system anticipates providing for future peak load plus reserve
requirements through existing system generation, including purchasing
available capacity from neighboring utilities, non-utility generators, power
marketers and power brokers.
The system also has available 115.6 MW from three 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:
Maine Vermont
Yankee Yankee Pilgrim
Year of Initial Operation 1972 1972 1972
Contract Expiration Date 2008 2012 2012
Equity Ownership (%) 4.00 2.50 -
Plant Entitlement (%) 3.59 2.25 11.0
Plant Capability (MW) 870.0 496.0 664.7
System Entitlement (MW) 31.2 11.2 73.2
In July 1996, Connecticut Yankee Atomic Power Company (Connecticut
Yankee), which operates the Connecticut Yankee nuclear power plant, took the
unit out of service in connection with certain safety-related issues and
refueling. On December 4, 1996, the plant's Board of Directors, following an
economic evaluation of continuing to operate the plant over the remaining ten
years of its current license life compared to closing the plant and incurring
replacement power for the same period, voted to permanently shutdown the
plant. In 1992, Yankee Atomic Electric Company (Yankee Atomic) permanently
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
discontinued power operation and began decommissioning the Yankee Nuclear
Power Station located in Rowe, Massachusetts. For additional information,
refer to Note 4(e) of the Notes to Consolidated Financial Statements filed
under Item 8 of this report.
One of the operating nuclear generating facilities, located in
Wiscasset, Maine and operated by Maine Yankee Atomic Power Company (Maine
Yankee), experienced two outages due to design and regulatory issues during
1996. On July 20, 1996 the unit came off line to address a design issue on
the primary component cooling system. The unit remained off-line until
September 2, 1996 to also address issues related to compliance with the
Nuclear Regulatory Commissions (NRC) General Letter 96-01 that addresses
surveillance testing of safety system components.
The second outage for Maine Yankee began on December 5, 1996 to correct
technical issues associated with a Confirmatory Action Letter issued by the
NRC. Maine Yankee used this outage as an opportunity to breach the reactor
and identify the specific fuel assemblies which were detected leaking earlier
in the operating cycle. They identified eight assemblies with a total of
seventy-five fuel rods leaking, and found the most recent load of fuel
unacceptable for continued operation of the plant. Additional cable
separation issues were also identified and the NRC has expanded the
requirements of the Confirmatory Action Letter that Maine Yankee must meet
prior to restart. The restart date of the unit has not yet been determined.
Cambridge Electric, Canal and Commonwealth Electric, together with other
electric utility companies in the New England area, are members of NEPOOL,
which was formed in 1971 to provide for the joint planning and operation of
electric systems throughout New England.
NEPOOL 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.
NEPOOL, on behalf of its members entered into an Interconnection Agree-
ment 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 NEPOOL 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. NEPOOL 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 $12.5 million at December 31,
1996. In addition, Canal has an equity interest in Phase II which amounted to
$3.3 million in 1996 and $3.4 million in 1995.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 NEPOOL participants in planning
future additions are determined by NEPOOL 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.
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 4(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 Cam-
bridge Electric and Commonwealth Electric. For additional information
concerning Seabrook 1, refer to Note 4(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 1996, approximately 21% was
generated using imported residual oil and approximately 38% was generated
using natural gas.
Effective October 1, 1996, Canal executed a fifteen-month contract with
Enron Liquid Fuels, Inc. (Enron) 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 35%) to be met by spot purchases or by
Enron at the discretion of Canal. Through December 31, 1996, 17.6% of Canal's
total requirements have been met by lower-cost, spot purchases resulting in
savings to its customers.
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.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 1996, ESCO Massachusetts, Inc. maintained an average
daily inventory of 421,000 barrels of fuel oil, which represents approximately
thirty-four 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. During September and October 1996, Unit 2 burned
approximately 1.6 million MMBTU's of natural gas, saving customers
approximately $1.1 million. Natural gas was not burned at Unit 2 during
November and December as the cost of residual fuel oil was more economical
during that period. Canal anticipates that its dual fuel capability will
result in future savings as the least expensive fuel is utilized.
Canal has entered into a contract with Duke/Louis Dreyfus, L.L.C. to
provide 100% of the natural gas requirements of Unit 2 through December 31,
1997.
(b) Nuclear Fuel Supply and Disposal
Approximately 24% of the system's total energy requirement for 1996 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 high level
wastes and 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 all of 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 temporary storage 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 all
spent fuel expected to be accumulated through at least the year 2010.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 ranging
from less than one year to three or more years. The vendors vary from
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 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 DPU and hearings were completed in April 1993. The DPU
approved the ANE gas supply contract in November 1995. Commonwealth Gas is
presently in negotiations with the parties to allow for final execution of all
pertinent agreements and contracts.
Commonwealth Gas began transporting gas on its distribution system in
1990 for end-users. As of December 31, 1996, there were 66 customers using
this transportation service, accounting for 6,192 BBTU or approximately 11.8%
of system throughput.
Hopkinton LNG Facility
A portion of Commonwealth Gas' supply 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 and 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
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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 and Regulation and Legislation
Certain of the System's utility subsidiaries operate under the
jurisdiction of the DPU, 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.
However, on August 16, 1995, the DPU issued an order calling for the
restructuring of the electric utility industry in Massachusetts. For further
information pertaining to the effects of this restructuring order on the
System's utility companies' rates, regulation and legislation, refer to the
"Electric Industry Restructuring" section of Management's Discussion and
Analysis of Financial Condition and Results of Operations filed under Item 7
of this report.
(a) 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 under 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.
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
On March 29, 1995, the FERC issued two notices of proposed rulemaking
concerning open access transmission (RM95-8-000) and stranded costs (RM94-7-
001). 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 a Section 206 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 December 31, 1996, Cambridge Electric and Commonwealth Electric filed
market-based power sales tariffs with the FERC which 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
authorization to participate as brokers in the sale and purchase of
electricity.
(b) Automatic Adjustment Clauses
Electric
Both Commonwealth Electric and Cambridge Electric have Fuel Charge rate
schedules which generally allow for current recovery, from retail customers,
of fuel used in electric production, purchased power and transmission costs.
These schedules require a quarterly computation and DPU 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 do not match actual costs for that period, an
appropriate adjustment is reflected in the calculation of the next subsequent
calendar quarter decimal.
Cambridge Electric and Commonwealth Electric collect a portion of
capacity-related purchased power costs associated with certain long-term power
arrangements through base rates. The recovery mechanism for these costs uses
a per kilowatthour (KWH) factor that is calculated using historical (test-
period) capacity costs and unit sales. This factor is then applied to current
monthly KWH sales. When current period capacity costs and/or unit sales vary
from test-period levels, Cambridge Electric and Commonwealth Electric have
experienced a revenue excess or shortfall that has had a significant impact on
net income. However, as part of the settlement agreements approved by the DPU
in May 1995, Cambridge Electric and Commonwealth Electric can now defer these
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
costs (within certain limits) which neutralizes their sometimes volatile
effect on net income.
Both Commonwealth Electric and Cambridge Electric have separately stated
Conservation Charge rate schedules which allow for current recovery, from
retail customers, of conservation and load management costs.
Gas
Commonwealth Gas has a Standard Seasonal Cost of Gas Adjustment rate
schedule (CGA) which provides for the recovery, from firm customers, of
purchased gas and conservation and load management costs not collected through
base rates. These schedules, which require DPU approval, are estimated semi-
annually and include credits for gas pipeline refunds and profit margins
applicable to interruptible and other non-firm 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 DPU. To approve this long-range forecast and resource plan,
the DPU 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 DPU
on December 20, 1996.
(c) Gas Demand and Transition Costs
Commonwealth Gas is obligated, as part of its pipeline transportation
and supplier gas purchase contracts, to pay monthly demand charges which are
recovered through the CGA.
As a direct result of implementation of 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 DPU.
(d) Retail Choice Pilot Program
On September 3, 1996, the DPU approved Commonwealth Electric's retail
choice pilot program. The program is comprised of two components: under
Subscription A, eligible customers have the opportunity to buy their power
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
from a supplier other than Commonwealth Electric (an alternative supplier);
under Subscription B, eligible customers continue to buy their power from
Commonwealth Electric, but at prices posted by Commonwealth Electric one day
ahead. All participating customers will pay Commonwealth Electric a customer
charge, transmission and distribution charges, and an access charge.
The program is available to Commonwealth Electric's 18 commercial and
industrial customers taking service under one of Commonwealth Electric's
economic development rates. Subscription A has been filled by 5 customers
having an aggregate load of approximately 15 megawatts. However, because this
portion of the program is temporarily suspended pending re-bidding of the
power supply, Commonwealth Electric is assisting these customers to qualify
them on Subscription B. The remaining customers are eligible to participate
in Subscription B.
The program is designed to allow a limited number of customers the
opportunity to possibly reduce their electric bills while Commonwealth
Electric learns more about real-time pricing and the administrative require-
ments associated with open-market competition. Through the program,
Commonwealth Electric expects to develop internal procedures for billing and
allocating the costs for providing an alternative supply to its retail
customers, and to develop methods for educating customers regarding retail
choice. The program is scheduled to continue until December 31, 1997.
Those customers that find that their selection is not right for them
will be able to return to Commonwealth Electric service at their prior rate.
(e) Customer Transition Charge
In September 1995, the DPU 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 will protect remaining
customers from paying certain costs, often referred to as stranded investment
costs, that were incurred in the event that Cambridge Electric's largest
customers discontinue full service, yet still remain connected for back-up and
other services. These costs include 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 DPU restructuring order which
endorsed, in principle, the recovery of stranded investment costs.
Through the CTC, Cambridge Electric will initially recover 75% of net
stranded investment costs as calculated in its proposal. Cambridge Electric's
other rates include a Supplemental Service Rate, a Standby Service Rate and a
Maintenance Service Rate each of which were approved with only minor changes.
Cambridge Electric is encouraged by the DPU's position on recovery of stranded
investment costs and expects to address recovery of the remaining 25% in its
restructuring filing.
<PAGE 14>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The Massachusetts Institute of Technology (MIT) appealed the DPU's deci-
sion to the Massachusetts Supreme Judicial Court (the SJC). Cambridge
Electric is an intervenor in this proceeding. While no schedule is set for a
decision from the SJC, Cambridge Electric anticipates a decision sometime in
the second quarter of 1997. At this time, Cambridge Electric is unable to
predict the outcome of this proceeding. In addition, on February 29, 1996,
the FERC denied a petition filed in January 1996 by MIT, which sought relief
from paying the CTC, on the premise that stranded costs are to be resolved at
the state level. Cambridge Electric believes that the FERC's action will be
an important factor that the SJC will consider in the appeal process.
In a previous legal proceeding, 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 DPU and dismissed
the May 1996 complaint filed by MIT. In its complaint, MIT had alleged that
the CTC approved by the DPU and implemented by Cambridge Electric violated the
Public Utility Regulatory Policies Act of 1978 (PURPA). In dismissing MIT's
complaint, the District Court found that MIT's complaint involved an
allegation relating to the DPU's application of PURPA, which is not within the
District Court's jurisdiction.
Competition
The system continues to develop and implement strategies that deal with
the increasingly competitive environment facing the electric business. The
inherently high cost of providing energy services in the Northeast has placed
the region at a competitive disadvantage as more customers begin to explore
alternative energy supply options. Pursuant to its aforementioned Model
Rules, the DPU is proposing to implement programs under which utility and non-
utility generators can sell electricity to customers of other utilities
without regard to previously closed franchise service areas. In 1994, the DPU
began an inquiry into incentive ratemaking.
The system's actions in response to the new competitive challenges have
been well received by regulators, business groups and customers. The system
has developed and will continue to develop innovative pricing mechanisms
designed to retain existing customers, add new retail and wholesale customers
and expand beyond current markets. For a more detailed discussion of the
DPU's restructuring order, refer to the "Electric 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. COM/Electric and COM/Gas will
continue to operate under their existing company names. The consolidation
process for these companies will involve the merging of similar functions and
activities to eliminate duplication in order to create the most efficient and
cost-effective operation possible and will ultimately result in the reduction
of up to 300 positions (15%) system-wide. Through prior work force reductions
and attrition, the system has reduced its full-time work force approximately
23.1% since 1990. Also, the introduction of advanced technologies in the
<PAGE 15>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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, absent a major shift in regulation at the state level,
believes its current business strategy 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 development and
management of new real estate ventures, the operation of rental properties and
other investment activities and the pursuit of new business opportunities
which do not presently contribute significantly to either revenues or
operating income.
Reference is made to additional industry segment information in Note 12
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 $68.8 million from 1997 through 2001 for the electric and gas
divisions.
For additional information concerning environmental issues, refer to the
"Environmental Matters" section of "Management's Discussion and Analysis of
Financial Condition and Results of Operations" filed under Item 7 of this
report.
Construction and Financing
For information concerning 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 4(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 5% to
1,991 in 1996 from 2,096 employees at year-end 1995. Of the current total,
1,182 (59%) are represented by various collective bargaining units.
Agreements with two units representing approximately 5% of regular employees
are scheduled to expire in 1997. Refer to Note 1 of Notes to Consolidated
Financial Statements filed under Item 8 of this report for additional
information regarding employee relations.
<PAGE 16>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 2. Properties
The system's principal electric properties consist of Canal Unit 1, a
566 MW oil-fired steam electric generating unit, and its one-half ownership in
Canal Unit 2, a 575.8 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. In addition, the system has a 3.52% interest
(40.5 MW of capacity) in Seabrook 1 and a 1.4% or 8.8 MW joint-ownership
interest in Central Maine Power Company's Wyman Unit 4. The system also has
an interest in smaller generating units totaling 77.6 MW used primarily for
peaking and emergency purposes.
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, 1996, the electric transmission and distribution system
consisted of 5,803 pole miles of overhead lines, 4,371 cable miles of
underground line, 355 substations and 378,088 active customer meters.
The principal natural gas properties consist of distribution mains,
services and meters necessary to maintain reliable service to customers. At
the end of 1996, the gas system included 2,791 miles of gas distribution
lines, 165,926 services and 243,083 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
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 DPU approving a
customer transition charge that allows Cambridge Electric to recover certain
stranded investment 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.
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
1995 by Quarter
First Second Third Fourth
High $20 15/16 $20 3/4 $21 11/16 $23 9/16
Low 17 13/16 18 7/8 17 11/16 20 1/2
(b) Number of Shareholders at December 31, 1996
13,676 shareholders
(c) Frequency and Amount of Dividends Declared in 1996 and 1995
1996 1995
Per Per
Share Share
Declaration Date Amount Declaration Date Amount
March 28, 1996 $ .385 March 23, 1995 $ .375
June 27, 1996 .385 June 22, 1995 .375
September 26, 1996 .385 September 28, 1995 .375
December 19, 1996 .385 December 14, 1995 .375
$1.540 $1.500
(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
1996 1995 1994 1993 1992
(Dollars In Thousands Except Common Share Data)
Operating Revenues
Electric $ 649,678 $ 604,980 $ 638,150 $ 622,039 $ 595,112
Gas 341,867 306,953 323,568 302,644 294,874
Steam and other 19,360 17,355 15,867 14,035 14,307
Total $1,010,905 $ 929,288 $ 977,585 $ 938,718 $ 904,293
Net Income $ 59,175 $ 51,396 $ 48,968 $ 45,834 $ 39,897
Common Share Data-
Earnings per share $2.70 $2.36 $2.29 $2.18 $1.91
Dividends declared
per share $1.54 $1.50 $1.50 $1.46 $1.46
Average shares
outstanding 21,529,676 21,311,836 20,827,562 20,431,228 20,163,736
Total Assets $1,428,955 $1,392,342 $1,345,032 $1,318,940 $1,273,475
Long-term debt $ 355,305 $ 377,181 $ 418,307 $ 448,893 $ 361,092
Redeemable preferred
share investment 13,020 13,840 14,660 15,480 16,300
Common share
investment 415,694 390,785 362,997 337,070 315,219
Total Capitalization $ 784,019 $ 781,806 $ 795,964 $ 801,443 $ 692,611
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
1995 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $265,225 $208,776 $206,542 $248,745
Operating Income 30,011 17,237 17,253 30,042
Income Before Interest Charges 31,913 17,738 17,945 28,408
Net Income 20,933 6,430 7,116 16,917
Earnings per Common Share .98 .29 .32 .77
Dividends Declared per
Common Share .375 .375 .375 .375
Closing Price of Common Shares-
High 20 15/16 20 3/4 21 11/16 23 9/16
Low 17 13/16 18 7/8 17 11/16 20 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:
1996 1995 1994
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in Thousands Except Per Share Amounts)
Electric........... $39,667 $1.85 $32,247 $1.52 $32,952 $1.58
Gas................ 16,229 .75 15,352 .72 12,346 .59
Other.............. 2,229 .10 2,687 .12 2,500 .12
Total.......... $58,125 $2.70 $50,286 $2.36 $47,798 $2.29
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. Common share data for 1995 and
1994 has been restated throughout this discussion to reflect the two-for-one
stock split that became effective June 5, 1996.
1996 versus 1995
In 1996, earnings applicable to common shares increased $7.8 million
(15.6%) to $58.1 million. Earnings per share increased $.34 to $2.70. Return
on average common equity, among the highest in the utility industry, improved
to 14.4% from 13.3% in 1995. Significant factors that contributed to the
improved earnings included higher firm gas ($.18) and retail electric ($.14)
unit sales, a refund ($.11) associated with a power contract settlement
agreement, lower interest costs ($.09), and the reversal of a reserve for
Canal Electric Company's (Canal) recovery of postretirement benefits costs
($.07). Partially offsetting these factors were costs related to a five and
one-half month labor dispute ($.11) resolved in September, storm damage from
Hurricane Edouard ($.06), a customer refund ($.05 in 1996 versus $.01 in 1995)
pursuant to a 1995 settlement agreement with the Massachusetts Department of
Public Utilities (DPU) that limits Commonwealth Electric Company's
(Commonwealth Electric) return on equity, as defined in a settlement that
expires in 1997, and the reversal in 1995 of a reserve ($.04) related to a
conservation program settlement in 1995.
In March 1996, the System's Board of Trustees increased the quarterly
dividend rate per share 2.7% from $.375 to $.385, an annual rate of $1.54.
Dividends paid to common shareholders in 1996 were $33.2 million, representing
a payout ratio of 57% of 1996 earnings.
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
1995 versus 1994
In 1995, earnings applicable to common shares increased $2.5 million or
5.2% to $50.3 million. Earnings per share increased $.07 to $2.36. Factors
that contributed to the improved earnings were a $3.8 million reduction ($.11)
in other operation expense, the reversal of a reserve related to the system's
energy conservation programs ($.04), and higher steam unit sales ($.01).
Partially offsetting these factors was an increase in interest charges ($.07)
primarily related to deferred gas costs and, to a lesser extent, higher short-
term interest rates.
Electric Operations
In 1996, electric operating revenues increased $44.7 million or 7.4% due
mainly to higher fuel costs of $33.9 million reflecting the increased
availability 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 a $4 million refund associated with a
power contract settlement approved by the Federal Energy Regulatory Commission
(FERC) relative to billing issues in prior years, 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.
Electric operating revenues in 1995 decreased $32.8 million (5.1%) due
mainly to lower fuel oil costs ($32.6 million) caused by a combination of
scheduled maintenance and other repairs to Canal's Unit 1. Also contributing
to the decline in revenues were lower conservation and load management (C&LM)
costs ($3.3 million). Offsetting these declines were increases related to the
recovery of costs associated with a power contract buyout ($3.9 million
including $1.9 million in carrying charges) and the recognition in revenues of
$2 million in carrying charges associated with Commonwealth Electric's fuel
charge stabilization deferral.
Unit sales (in Megawatthours or MWH) were as follows:
% %
1996 Change 1995 Change 1994
Residential.......... 1,802,973 2.9 1,752,430 (1.0) 1,770,095
Commercial........... 2,430,188 (0.8) 2,450,390 1.8 2,406,077
Industrial and Other. 449,844 1.1 445,020 - 445,037
Total Retail..... 4,683,005 0.8 4,647,840 0.6 4,621,209
Wholesale............ 2,721,623 37.9 1,973,543 (48.1) 3,803,786
Total............ 7,404,628 11.8 6,621,383 (21.4) 8,424,995
In 1996 retail unit sales increased slightly due to approximately 3,700
(1.0%) additional customers, the 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 as explained above. The changes in
wholesale unit sales have little, if any, impact on net income. Retail unit
sales increased in 1995 due to a modest growth in customers (approximately
2,500 or 0.6%) mainly in the residential and commercial sectors and, to a
<PAGE 21>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
lesser extent, additional weather-related load attributable to greater air-
conditioning and heating use. The decrease in total unit sales in 1995 was
mainly due to a lower level of wholesale sales reflecting the decreased
availability of Canal Unit 1.
The cost of fuel increased in 1996 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 power. In 1995, the 36% decline
in fuel costs was due to reduced consumption at Canal Unit 1. The cost of
purchased power increased just 2% in 1995.
Gas Operations
In 1996, gas operating revenues increased approximately $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 higher degree
days during 1996.
Gas operating revenues decreased in 1995 by $16.6 million or 5.1% due
mainly to an $18.3 million (10.3%) decline in the cost of gas sold that
reflects a 3.7% reduction in total sales.
Quasi-firm sales are designed for customers who receive interruptible
service in peak months as negotiated in each contract and firm service in all
other months. Fluctuations in quasi-firm sales had minimal impact on net
income in 1996 and 1995. On January 17, 1997, the DPU approved a margin-
sharing proposal filed by Commonwealth Gas Company (COM/Gas) for sales and
transportation to quasi-firm customers. This proposal allows COM/Gas to
retain 25% of the margins on these sales over a certain threshold amount as
set from year to year. The remaining margins reduce the cost of gas sold to
firm customers.
Unit sales and transportation volume (in billions of British thermal
units or BBTU) were as follows:
% %
1996 Change 1995 Change 1994
Residential......... 22,759 6.7 21,336 (0.8) 21,515
Commercial.......... 11,558 7.9 10,710 (0.2) 10,728
Industrial and other 6,676 4.1 6,412 1.8 6,296
Total firm....... 40,993 6.6 38,458 (0.2) 38,539
Off-system.......... 2,420 (40.1) 4,043 (36.8) 6,401
Quasi-firm.......... 1,066 (44.1) 1,906 291.4 487
Interruptible....... 1,883 55.0 1,215 (36.9) 1,927
Total sales...... 46,362 1.6 45,622 (3.7) 47,354
Transportation...... 4,852 20.6 4,024 82.2 2,208
Total............ 51,214 3.2 49,646 0.2 49,562
The increase in unit sales to firm customers during 1996 (6.6%) reflects
significant improvements for all customer classes consistent with colder than
<PAGE 22>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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, also
contributed to the increase in firm unit sales in 1996. During 1995 firm unit
sales were virtually unchanged compared to 1994.
Other Operating Expenses
In 1996, other operation increased approximately $9 million or 4.4%
reflecting the net impact of higher general liability insurance costs ($6.3
million), higher postretirement benefits costs ($4 million), and the net
impact of COM/Gas' labor dispute ($3.8 million). These expenses were offset
somewhat by lower C&LM costs ($2.4 million), a $1.6 million decline in medical
costs, a decline in the provision for bad debts ($1.1 million) reflecting
improved collection experience, and the absence of legal fees ($.8 million)
associated with the cancellation of a power contract in 1995. Other operation
in 1995 declined $7.1 million or 3.3% due primarily to a decline in liability
insurance ($5.4 million) caused by accrual adjustments that reflected better
than anticipated experience, lower C&LM costs ($3.3 million) and a decline in
the provision for bad debts ($1 million). This was offset, in part, by higher
labor costs ($3.5 million) and postretirement benefits costs ($2.6 million).
Maintenance increased in 1996 by $2.5 million or 6.5% primarily due to
storm damage costs related to Hurricane Edouard ($2.1 million). These
increases were partially offset by reductions in maintenance costs, primarily
associated with Canal Unit 1 ($1.5 million). During 1995, maintenance
increased $1.9 million (5.2%) reflecting scheduled maintenance and other
repair costs to several system generating units ($1.5 million).
Depreciation expense increased $3.6 million and $4 million in 1996 and
1995, respectively, consistent with the System's additions to and upgrading of
its property, plant and equipment.
Other Income
The $3.4 million increase in 1996 was due mainly to the recording of a
regulatory asset by Canal for costs associated with postretirement benefits
that were recovered in 1996 wholesale rates ($1.8 million) and a gain
recognized on the sale of a parcel of non-utility land by Cambridge Electric
($.7 million). The increase in 1995 was due to a decline in the expense
component of other income due primarily to the reversal of a reserve ($1.4
million) that had been established by Commonwealth Electric that related to
certain costs associated with its conservation program, offset by the
recognition of a reserve ($2.7 million, net of tax) related to a system
generating station that discontinued operations and, to a lesser extent, the
absence of the equity component of allowance for funds used during
construction (AFUDC) ($.3 million).
<PAGE 23>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Interest Charges
Total interest charges declined $2.2 million, or 5%, in 1996 reflecting
maturing long-term debt and scheduled sinking fund payments. Interest charges
for 1995 increased $1.1 million or 2.6% due primarily to a higher level of
interest on deferred gas costs ($2 million) and higher short-term interest
rates, offset, in part, by lower long-term interest costs ($.9 million) that
reflected maturing long-term debt and scheduled 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. Daily cash requirements for current operations,
construction 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
financings are used to refinance short-term debt when deemed appropriate by
management.
The system's 1996 net cash flow from operating activities exceeded funds
used for investing activities for additions to property, plant and equipment
by $10.2 million or 19.2%. These types of investing activities continue to be
funded entirely with internally-generated funds. Cash required in 1996 for
financing activities was primarily for the payment of preferred and common
dividends ($34.2 million) and the funding of maturing long-term debt and
sinking fund requirements ($41.7 million). Proceeds from short-term borrow-
ings ($62.9 million) helped to meet the year's cash requirements. Other
information on the sources and uses of cash for the past three years is
included in the Consolidated Statements of Cash Flows in this report.
Capital Requirements
-------------------------------------------------------------------
Bar graph illustration of
comparative two-year (1995-1996) actual
and five-year (1997-2001) forecast of
capital requirements based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1995 1996 1997 1998 1999 2000 2001
(Dollars in Millions)
Construction-
Electric $ 61 $ 39 $ 49 $ 60 $ 34 $ 31 $ 27
Gas 16 11 18 18 19 19 19
Other 3 3 1 1 1 1 1
Maturing Debt 34 42 23 28 28 7 8
$114 $ 95 $ 91 $107 $ 82 $ 58 $ 55
<PAGE 24>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Capital Requirements and Resources
The system's projected capital expenditures for the years 1997 through
2001 are $392.2 million, including $90.9 million for 1997 that consists of
$68.2 million in construction expenditures and $22.7 million for debt and
sinking fund payments. These 1997 requirements will be met primarily through
internally-generated funds of $78.8 million with the balance of $12.1 million
supplemented by long and short-term debt financings. The System could also
raise capital through the issuance of additional series of preferred shares or
additional Common Shares or through changing its Dividend Reinvestment and
Common Share Purchase Plan from a market purchase plan to direct issue of
shares. 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 sufficient to meet its current and
projected requirements.
The system's capitalization structure, including short-term debt, is
presented below:
1995 1996
(Dollars in Thousands)
Long-term debt.... $410,411 47.1% $369,565 40.3%
Preferred shares.. 13,840 1.6 13,020 1.4
Common equity..... 390,785 44.9 415,694 45.4
Short-term debt... 55,600 6.4 118,475 12.9
Total capitalization $870,636 100.0% $916,754 100.0%
Capitalization
-------------------------------------------------------------------
Bar graph illustration of
comparative five-year (1997-2001) forecast of
capitalization components based on values
listed in chart below.
-------------------------------------------------------------------
Forecast
1997 1998 1999 2000 2001
(Dollars in Millions)
Common
Equity $438 46% $458 48% $477 51% $495 54% $515 58%
Total
Debt 493 53 480 51 444 48 407 45 368 41
Preferred
Stock 12 1 11 1 11 1 10 1 9 1
$943 100% $949 100% $932 100% $912 100% $892 100%
Forward-Looking Statements
This report contains statements which, to the extent they are not recita-
tions of historical fact, constitute "forward-looking statements" and are
intended to be subject to the safe harbor protection provided by the Private
Securities Litigation Reform Act of 1995. A number of important factors
<PAGE 25>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
affecting the System's business and financial results could cause actual
results to differ materially from those stated in the forward-looking state-
ments. Those factors include developments in the legislative, regulatory and
competitive environment, certain environmental matters, demands for capital
expenditures and the availability of cash from various sources, and uncertain-
ty as to regulatory approval of the full recovery of regulatory assets and
other stranded costs.
Electric Industry Restructuring
In August 1995, the DPU issued an order calling for the restructuring of
the electric utility industry in Massachusetts. On May 1, 1996, the DPU
issued a second order containing proposed rules for implementing electric
industry restructuring that were the subject of public comment and hearings
during June and July 1996. Subsequently, on December 30, 1996, the DPU issued
another order announcing its "Model Rules and Legislative Proposal" as a guide
in the creation of a competitive market for electric generation in
Massachusetts that would provide customers with the opportunity to achieve
lower electric bills beginning January 1, 1998. The order also required
electric utilities to file by March 3, 1997, revenue-neutral, unbundled rates
and model bills showing a breakdown of the bill into generation, transmission,
distribution and access charge categories.
In its "Model Rules," the DPU has proposed that the minimum structural
reorganization needed to create a competitive market is the functional
separation of generation, transmission and distribution within one integrated
company, and the establishment of a separate marketing affiliate if a company
retains generation assets. The Massachusetts Legislature, which will render
the final passage of any restructuring law, is now considering the DPU's
proposed legislation.
Other elements of the DPU's Model Rules provide that electric customers
will be able to buy their power on the open market; distribution services will
remain a monopoly service offered exclusively by the existing local
distribution companies in clearly defined service territories; and customers
will have three types of electric generation choices. First, customers may
enter into unregulated agreements with a competitive supplier for the
provision of generation. Second, customers may continue to buy power directly
from their electric distribution company at a price regulated by the DPU.
Third, customers who have received generation from a competitive supplier but
who, for any reason, have stopped receiving such generation will be able to
receive default generation service, provided by distribution companies at spot
market price.
Changes in the electric industry may reduce the opportunity that currently
exists for electric companies to recover their investment in generating plant
and other expenditures previously approved by the DPU and included in current
rates. The potential losses, which may result from subjecting electric
company generation to the pressures of a competitive market, are typically
referred to as "stranded costs." The single largest component of stranded
costs which are significant to the system relates to above market purchased
power contracts that Commonwealth Electric and Cambridge Electric have with
non-utility generators. However, the DPU has concluded that it is in the
public interest to provide electric companies a reasonable opportunity to
<PAGE 26>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
collect net, non-mitigable stranded costs. The DPU has proposed that stranded
costs associated with owned generation facilities, regulatory assets, and
minimum purchased power obligations be collected over the expected economic
life of the generating facility, the current amortization schedule of the
regulatory asset, or the contractual term of the purchased power obligation,
respectively. The DPU's proposal requires that any stranded cost recovery for
an electric utility be subject to mitigation efforts to reduce embedded costs
over time. The Model Rules specify that mitigation should include such
measures as sales of capacity and energy from owned generation, renegotiation
or buy-out of purchased power contracts, and sales and voluntary writedowns of
assets. Further, the DPU will conduct stranded cost charge reconciliations at
years two, five and ten following the date of retail access.
During the last several months, three Massachusetts electric utilities
have announced negotiated settlement agreements with the Massachusetts
Attorney General's Office (Attorney General) that include divestiture of
generating assets, provision for a ten percent reduction in customers' charges
and recovery of stranded costs through a non-bypassable access charge. One
settlement agreement has already been approved by the DPU. Implementation of
any restructuring settlement may be affected by actions of the Massachusetts
Legislature.
The system is engaged in preliminary settlement discussions with the
Attorney General, and expects to reach a comprehensive settlement during the
first half of 1997. In the unlikely event it is unable to complete a
settlement, the system would file a full restructuring plan with the DPU.
As described in Note 2(b) to the Consolidated Financial Statements, the
system complies with 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 determined that it no longer met 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. Criteria that give rise to the discontinuance of SFAS No. 71
include: 1) increasing 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 periodically
reviews 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 regulatory assets, including those related to generation,
are probable of future recovery.
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.
The costs associated with the assessment and clean-up of these sites are
recoverable in rates through the cost of gas adjustment clause over a seven-
year amortization period without carrying costs pursuant to a 1990 DPU order.
Commonwealth Gas has recorded an estimated $2.5 million liability that
<PAGE 27>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
reflects its best estimate (based on current information) of the costs to be
incurred in connection with assessment and remediation activities identified
to this point. Commonwealth Gas has also recorded a regulatory asset in
anticipation of recovery of these costs. Commonwealth Gas is unable to
predict the total cost to ultimately resolve these matters, due to significant
uncertainty as to the actual site conditions and the extent of any associated
remediation activities and the assignment of responsibility. However, it is
expected that all such costs will continue to be recovered in rates as
described above.
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 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
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.
Effective January 1, 1997, the system will adopt the provisions of
Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities."
This Statement provides 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 $4.2 million at December 31, 1996. Upon adoption of SOP
96-1, the system's estimated liability will not incrementally change and
further, management does not believe that SOP 96-1 will have a material
adverse effect 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 28 through 49 of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
<PAGE 28>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT
The consolidated financial statements presented herein are
representations of the management of Commonwealth Energy System. Management
recognizes its responsibility for the preparation and presentation of
financial statements 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
Committee, 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
consolidated financial statements.
James D. Rappoli,
Financial Vice President
February 19, 1997.
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 (a
Massachusetts trust) and subsidiary companies as of December 31, 1996 and
1995, 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, 1996. 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
Commonwealth Energy System and subsidiary companies as of December 31, 1996
and 1995, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 19, 1997.
<PAGE 29>
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, 1996,
1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31,
1996, 1995 and 1994
Consolidated Balance Sheets at December 31, 1996 and 1995
Consolidated Statements of Capitalization for the Years Ended December
31, 1996, 1995 and 1994
Consolidated Statements of Changes in Common Shareholders' Investment
for the Years Ended December 31, 1996, 1995 and 1994
Consolidated Statements of Changes in Redeemable Preferred Shares for
the Years Ended December 31, 1996, 1995 and 1994
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, 1996, 1995
and 1994
II Valuation and Qualifying Accounts for the Years Ended December 31,
1996, 1995 and 1994
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 30>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994
(Dollars in Thousands - Except Per Share Amounts)
1996 1995 1994
Operating Revenues
Electric $ 649,678 $604,980 $638,150
Gas 341,867 306,953 323,568
Steam and other 19,360 17,355 15,867
1,010,905 929,288 977,585
Operating Expenses
Fuel used in electric production,
principally oil 91,690 57,820 90,414
Electricity purchased for resale 265,019 274,795 269,418
Cost of gas sold 187,530 158,835 177,150
Other operation 215,319 206,280 213,370
Maintenance 40,913 38,414 36,522
Depreciation 51,782 48,170 44,188
Taxes-
Local property 18,049 17,573 17,467
Income 36,099 24,574 29,154
Payroll and other 7,839 8,284 8,087
914,240 834,745 885,770
Operating Income 96,665 94,543 91,815
Other Income 4,878 1,461 627
Income Before Interest Charges 101,543 96,004 92,442
Interest Charges
Long-term debt 35,586 38,581 39,442
Other interest charges 7,039 6,884 4,475
Allowance for borrowed funds used during
construction (257) (857) (443)
42,368 44,608 43,474
Net Income 59,175 51,396 48,968
Dividends on preferred shares 1,050 1,110 1,170
Earnings Applicable to Common Shares $ 58,125 $ 50,286 $ 47,798
Average Number of Common Shares
Outstanding 21,529,676 21,311,836 20,827,562
Earnings Per Common Share $2.70 $2.36 $2.29
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 31>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994
(Dollars in Thousands)
1996 1995 1994
Operating Activities
Net income $ 59,175 $ 51,396 $ 48,968
Effects of noncash items-
Depreciation and amortization 63,331 60,555 53,727
Deferred income taxes, net 3,515 4,182 14,846
Investment tax credits, net (1,285) (1,401) (1,470)
Earnings from corporate joint ventures (1,557) (1,633) (1,750)
Dividends from corporate joint ventures 1,376 2,067 1,651
Change in working capital, exclusive of cash-
Accounts receivable and unbilled revenues (9,446) (13,626) 15,085
Income taxes (14,097) 14,353 8,016
Local property and other taxes (555) (950) 616
Accounts payable and other (33,956) 25,199 28,976
Power contract buy-out - (25,500) -
Fuel charge stabilization deferral, net 2,372 (3,447) (15,964)
Deferred postretirement benefits and
pension costs (2,157) (4,479) (8,536)
FERC Order 636 transition costs, net - 11,390 (2,585)
All other operating items (3,391) 6,565 (15,017)
Net cash provided by operating activities 63,325 124,671 126,563
Investing Activities
Additions to property, plant and
equipment (exclusive of AFUDC)-
Electric (38,607) (60,841) (37,997)
Gas (11,591) (16,143) (17,993)
Other (2,730) (3,659) (1,843)
Allowance for borrowed funds used during
construction (257) (857) (443)
Net cash used for investing activities (53,185) (81,500) (58,276)
Financing Activities
Sale of common shares 32 9,534 9,434
Payment of dividends (34,205) (33,142) (32,475)
Proceeds from (payment of) short-term
borrowings, net 62,875 10,750 (27,125)
Retirement of long-term debt and preferred
shares through sinking funds (8,436) (8,716) (6,406)
Long-term debt issues refunded (33,230) (25,000) (10,000)
Net cash used for financing activities (12,964) (46,574) (66,572)
Net increase (decrease) in cash (2,824) (3,403) 1,715
Cash at beginning of period 4,319 7,722 6,007
Cash at end of period $ 1,495 $ 4,319 $ 7,722
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of capitalized amounts) $ 41,294 $ 42,051 $ 41,022
Income taxes $ 46,563 $ 12,918 $ 17,563
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 32>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 and 1995
(Dollars in Thousands)
1996 1995
Assets
Property, Plant and Equipment, at original cost
Electric $1,150,818 $1,118,630
Gas 357,403 346,990
Other 66,365 65,020
1,574,586 1,530,640
Less-Accumulated depreciation and amortization 536,041 497,712
1,038,545 1,032,928
Construction work in progress 5,485 10,154
Nuclear fuel in process 1,597 122
1,045,627 1,043,204
Equity in Corporate Joint Ventures
Nuclear electric power companies (2.5% to 4.5%) 10,046 9,814
Other investments 3,349 3,400
13,395 13,214
Current Assets
Cash 1,495 4,319
Accounts receivable, less reserves of $8,324,000
in 1996 and $8,040,000 in 1995 117,008 105,377
Unbilled revenues 31,698 33,883
Inventories, at average cost-
Electric production fuel oil 2,221 1,683
Natural gas 23,084 17,339
Materials and supplies 6,220 6,516
Prepaid taxes 9,079 9,044
Other 5,686 6,799
196,491 184,960
Deferred Charges
Regulatory assets 154,291 130,672
Other 19,151 20,292
173,442 150,964
$1,428,955 $1,392,342
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, 1996 and 1995
(Dollars in Thousands)
1996 1995
Capitalization and Liabilities
Capitalization (See separate statement)
Common share investment $ 415,694 $ 390,785
Redeemable preferred shares, less current
sinking fund requirements 13,020 13,840
Long-term debt, less current sinking fund
requirements and maturing debt 355,305 377,181
784,019 781,806
Capital Lease Obligations 12,346 13,291
Current Liabilities
Interim Financing-
Notes payable to banks 118,475 55,600
Maturing long-term debt 14,260 33,230
132,735 88,830
Other Current Liabilities-
Current sinking fund requirements 8,473 9,103
Accounts payable 90,269 100,715
Accrued taxes-
Local property and other 9,060 9,580
Income 7,910 22,007
Accrued interest 6,267 8,389
Dividends declared 8,289 8,073
Other 39,279 55,379
169,547 213,246
302,282 302,076
Deferred Credits
Accumulated deferred income taxes 174,877 170,182
Unamortized investment tax credits 26,618 27,903
Other 128,813 97,084
330,308 295,169
Commitments and Contingencies
$1,428,955 $1,392,342
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 34>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1996 and 1995
(Dollars in Thousands)
1996 1995
Common Share Investment
Common shares, $2 par value-
Authorized-50,000,000 shares
Outstanding-21,529,676 shares in 1996
and 21,528,268 shares in 1995 $ 43,059 $ 43,056
Amounts paid in excess of par value 111,685 111,749
Retained earnings 260,950 235,980
Total common share investment 415,694 390,785
Redeemable Preferred Shares,
Cumulative, $100 Par Value
Series A, 4.80% 2,640 2,760
Series B, 8.10% 4,000 4,160
Series C, 7.75% 7,200 7,740
Less-Current sinking fund requirements (820) (820)
Total redeemable preferred shares 13,020 13,840
Long-term Debt
System
Senior Notes due-
1997, 10.48% 10,000 10,000
1998, 10.45% 10,000 10,000
1999, 10.58% 10,000 10,000
Less-Maturing long-term debt (10,000) -
Total System long-term debt 20,000 30,000
Subsidiary companies
Mortgage Bonds, collateralized by property of
operating subsidiaries, due-
1996, 7% - 3,800
1996, 8.99% - 10,000
2001, 8.99% 18,100 21,750
2006, 8.85% 34,650 35,000
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-
1996, 9.97% - 20,000
1997, 6 1/4% 4,260 4,320
1998, variable rate (6.125% in 1996 and
6.5625% in 1995) 9,000 9,000
1999, 8.04% 10,000 10,000
2002, 7 3/4% 2,600 2,700
2002, 9.30% 30,000 30,000
2003, 7.43% 15,000 15,000
2004, 9.50% 12,500 15,000
2007, 8.70% 5,000 5,000
2007, 9.55% 10,000 10,000
2008, 7.70% 10,000 10,000
2012, 9.37% 16,842 17,895
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 (4,260) (33,230)
Current sinking fund requirements (7,653) (8,283)
Unamortized discount, net (734) (771)
Total subsidiary companies' long-term debt 335,305 347,181
Total long-term debt 355,305 377,181
Total capitalization $784,019 $781,806
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 35>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' INVESTMENT
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994
Amounts
Par Paid in
Value Excess
$2 Per of Par Retained
Shares Share Value Earnings Total
(Dollars in Thousands)
Balance December 31, 1993 20,590,154 $41,180 $ 94,657 $201,233 $337,070
Add (Deduct)-
Net income - - - 48,968 48,968
Sale of shares 461,640 923 8,511 - 9,434
Cash dividends declared-
Common shares-$1.50 per share - - - (31,305) (31,305)
Preferred shares - - - (1,170) (1,170)
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
CONSOLIDATED STATEMENTS OF CHANGES IN REDEEMABLE PREFERRED SHARES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994
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, 1993 30,000 44,800 88,200 163,000
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
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
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE 36>
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 production
and sale of electricity to 363,000 customers in 41 communities including New
Bedford, Plymouth, Cambridge and the geographic area comprising Cape Cod. Gas
operations serve 234,000 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 two new subsidiaries
that are pursuing energy-related business opportunities.
The system has 1,991 regular employees including 1,182 (59%) represented
by various collective bargaining units. On September 8, 1996, a contract was
ratified, following a five and one-half month labor dispute, with a collective
bargaining unit that represents approximately 17% of regular employees. The
new six-year agreement will remain in effect through March 31, 2002. New
agreements were reached earlier this year with two other bargaining units
(representing approximately 23% of regular employees) that were scheduled to
expire on October 1, 1996 and November 1, 1997. These new agreements will
remain in effect until 2002 and 2001, respectively. Additional contracts with
two bargaining units representing approximately 5% of regular employees are
scheduled to expire 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 Public
Utilities (DPU).
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 DPU 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. 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
<PAGE 37>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
impact on the system's financial position or results of operations upon
adoption. This result may change as modifications are made to the current
regulatory framework due to ongoing electric industry restructuring efforts in
Massachusetts. If all or a separable portion of the system's operations
becomes no longer subject to the provisions of SFAS No. 71, a write-off of
related regulatory assets and liabilities would be required, unless some form
of transition cost recovery continues through rates established and collected
for the system's remaining regulated operations. In addition, the system
would be required to determine any impairment to the carrying costs of
deregulated plant and inventory assets. However, on December 30, 1996, the
DPU issued an order containing "model rules" for industry restructuring that
management believes would essentially allow full recovery of stranded costs.
For additional information relating to industry restructuring, see the
"Electric Industry Restructuring" section under Management's Discussion and
Analysis of Financial Condition and Results of Operations.
The principal regulatory assets included in deferred charges at December
31, 1996 and 1995 were as follows:
1996 1995
(Dollars in Thousands)
Postretirement benefit costs including
pensions $ 25,051 $ 24,608
Power contract buy-out 20,794 23,838
Fuel charge stabilization 21,504 22,063
Deferred income taxes 13,597 14,106
FERC Order 636 transition costs 9,680 11,711
Connecticut Yankee unrecovered plant and
decommissioning costs 35,879 -
Yankee Atomic unrecovered plant and
decommissioning costs 7,798 10,135
Seabrook related costs 6,262 9,511
Other 13,726 14,700
$154,291 $130,672
The regulatory liabilities, reflected in the accompanying Consolidated
Balance Sheets and related primarily to deferred income taxes, were $17.7
million and $14 million at December 31, 1996 and 1995, respectively.
As of December 31, 1996, $120.5 million of the system's regulatory
assets, including the Connecticut Yankee costs associated with an existing
power contract (see Note 4(e)), and all of its regulatory liabilities are
reflected in rates charged to customers. Regulatory assets are being
recovered over a weighted average period of approximately 11 years. The fuel
charge stabilization deferral is 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 DPU approval. Requests for recovery of the
remaining regulatory assets (primarily postretirement benefits costs) are in
process and DPU approval is expected during 1997.
(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.
<PAGE 38>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(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:
1996 1995 1994
Electric 3.65% 3.52% 3.30%
Gas 2.94 2.90 2.98
Steam 3.89 3.91 3.94
LNG 3.59 3.20 3.12
(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 the accompanying
Consolidated Statements of Income.
While AFUDC does not provide funds currently, these amounts are
recoverable in revenues over the service life of the constructed property.
The amount of AFUDC recorded was at a weighted average rate of 6.2% in 1996,
7.1% in 1995 and 9.1% in 1994.
(3) Common Shares Outstanding
On June 5, 1996, the System effected a two-for-one stock split of its
outstanding common shares as proposed by the System's Board of Trustees on
March 28, 1996 and subsequently approved by the System's shareholders on May
2, 1996. The record date for the stock split was May 15, 1996. The split
resulted in the issuance of an additional 10.8 million common shares and
accompanied an increase in the number of authorized common shares from 18
million to 50 million and included a change in the par value from four dollars
to two dollars per common share. Prior year amounts for the average number of
common shares outstanding, earnings per common share, dividends declared per
common share and common share investment information in the accompanying
consolidated financial statements and in the table of selected financial data
have been restated to reflect the stock split.
(4) Commitments and Contingencies
(a) Construction
The system is engaged in a continuous construction program presently
estimated at $302 million for the five-year period 1997 through 2001. Of that
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COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
amount, $68.7 million is estimated for 1997. The program is subject to
periodic review and revision.
(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
Commonwealth 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 DPU
approval.
Pertinent information with respect to Canal Electric's joint-ownership
interest in Seabrook 1 and information relating to operating expenses which
are included in the accompanying financial statements are as follows:
1996 1995
(Dollars in Thousands)
Utility plant-in-
service $232,183 $232,547 Plant capacity (MW) 1,150
Nuclear fuel 21,613 20,138 Canal Electric's share:
Accumulated depreciation Percent interest 3.52%
and amortization (57,359) (50,230) Entitlement (MW) 40.5
Construction work in In-service date 1990
progress 844 946 Operating license
$197,281 $203,401 expiration date 2026
1996 1995 1994
(Dollars in Thousands)
Operating expenses:
Fuel $ 1,727 $ 2,353 $ 1,939
Other operation 4,091 4,292 4,340
Maintenance 990 1,376 1,688
Depreciation 6,544 6,542 6,531
Amortization 1,319 1,319 1,320
$14,671 $15,882 $15,818
Canal Electric and the other joint owners have established a
decommissioning fund to cover decommissioning costs. The estimated cost to
decommission the plant is $449.9 million in current dollars. Canal Electric's
share of this liability (approximately $15.8 million), less its share of the
market value of the assets held in a decommissioning trust (approximately $1.9
million), is approximately $13.9 million at December 31, 1996.
(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
operating 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
<PAGE 40>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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
insurance 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 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 yearly or a cumulative total of $15.1 million, exclusive of the effect
of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million)
in the event that total public liability claims from a nuclear incident exceed
the funds available to pay such claims.
(d) Power Contracts
Cambridge Electric and Commonwealth Electric have long-term contracts
for the purchase of electricity from various sources. Generally, these
contracts are for fixed periods and require payment of a demand charge for the
capacity entitlement and an energy charge to cover the cost of fuel.
Pertinent information with respect to life-of-the-unit contracts for power
from nuclear units that operated in 1996 in which the system has an equity
ownership (Yankee Nuclear Units) is as follows:
Connecticut Maine Vermont
Yankee* Yankee Yankee
(Dollars in Thousands)
Equity Ownership (%) 4.50 4.00 2.50
Plant Entitlement (%) 4.50 3.59 2.25
Plant Capability (MW) 560.0 870.0 496.0
System Entitlement (MW) 25.2 31.2 11.2
Contract Expiration Date 2007 2008 2012
1994 Actual Cost ($) 8,902 6,250 3,660
1995 Actual Cost ($) 9,498 7,376 4,003
1996 Actual Cost ($) 9,259 6,511 4,208
Decommissioning cost estimate (100%) ($) 410,582 380,718 366,142
System's decommissioning cost ($) 18,476 13,668 8,238
Market value of assets (100%) ($) 209,448 163,536 159,613
System's market value of assets ($) 9,425 5,871 3,591
* Refer to section (e) for further information on Connecticut Yankee.
Cambridge Electric pays its share of the decommissioning expense to
each of the operators of these nuclear facilities as a cost of electricity
purchased for resale.
<PAGE 41>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
The system also has long-term contracts to purchase capacity from other
generating facilities. Information relative to these contracts is as follows:
Range of
Contract
Expiration Entitlement 1996 1995 1994
Dates % MW Cost Cost Cost
(Dollars in Thousands)
Type of Unit
Natural gas 2008-2017 * 204.7$120,842 $121,636 $137,304
Nuclear 2012 11 73.6 37,072 40,376 41,475
Waste-to-energy 2015 100 67.0 39,622 37,526 38,107
Hydro 2014-2023 100 23.7 12,537 9,933 7,521
Total 369.0 $210,073 $209,471 $224,407
* Includes contracts to purchase power from various non-utility generators
with capacity entitlements ranging from 11.1% to 100%.
Costs pursuant to these 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 life-of-the-
unit contracts from the operating Yankee Nuclear Units and other long-term
purchased power contracts in effect for the five years subsequent to 1996 are
as follows:
Long-Term
Equity Owned Purchased
Nuclear Units Power Total
(Dollars in Thousands)
1997 $11,474 $216,032 $227,506
1998 11,003 219,702 230,705
1999 12,768 224,508 237,276
2000 12,779 229,992 242,771
2001 11,908 239,253 251,161
(e) Yankee Nuclear Power Plants
On July 22, 1996, Connecticut Yankee Atomic Power Company (Connecticut
Yankee), which operates the Connecticut Yankee nuclear power plant (the
Connecticut plant), took the unit out of service in connection with certain
safety-related issues and refueling. During the outage, Connecticut Yankee's
owners evaluated the economics of continuing to operate the plant over the
remaining ten years of its current license life, compared to the costs of
closing the plant and incurring replacement power for the same period. As a
result of this evaluation, on December 4, 1996, Connecticut Yankee's Board of
Directors voted to permanently shut down the plant.
Cambridge Electric has an equity ownership interest in Connecticut
Yankee of 4.5% which, at December 31, 1996, amounted to approximately $4.7
million. Cambridge Electric, through its ownership interest, has a
corresponding capacity entitlement and power purchase obligation.
The preliminary estimate of the sum of future payments for the closing,
decommissioning and recovery of the remaining investment in the plant is
approximately $797 million. Cambridge Electric's share of these remaining
estimated costs is approximately $36 million. Based upon regulatory
precedent, Connecticut Yankee believes that it would continue to collect from
its power purchasers (including Cambridge Electric) its decommissioning costs,
unrecovered plant investment and other costs associated with the permanent
closure of the plant over the remaining period of the plant's operating
license that expires in 2007. Cambridge Electric does not believe the
<PAGE 42>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
ultimate outcome of the early closing of this plant will have a material
adverse effect on its operations and believes that recovery of these FERC-
approved costs will continue to be allowed in its rates at the retail level.
This action follows the permanent shutdown of the Yankee Atomic plant in
Rowe, Massachusetts in 1992. Due to changing conditions within the nuclear
industry, it is possible that the remaining two operating nuclear plants in
which the system has an equity ownership interest could be shut down sometime
in the future prior to the expiration of each unit's operating license.
(f) 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
installation of expensive air and water pollution control equipment. These
regulations have had an impact on the system's operations in the past and will
continue to have an impact on future operations, capital costs and
construction schedules of major facilities. For additional information, see
"Environmental Matters" in Management's Discussion and Analysis of Financial
Condition and Results of Operations.
(5) Income Taxes
The system files a consolidated federal income tax return. For
financial reporting purposes, the System and its subsidiaries provide taxes on
a separate return basis.
The following is a summary of the consolidated provisions for income
taxes for the years ended December 31, 1996, 1995 and 1994:
1996 1995 1994
(Dollars in Thousands)
Federal
Current $28,375 $15,954 $12,789
Deferred 2,784 8,231 12,617
Investment tax credits, net (1,285) (1,401) (1,470)
29,874 22,784 23,936
State
Current 5,542 4,176 3,171
Deferred 890 1,115 2,403
6,432 5,291 5,574
36,306 28,075 29,510
Amortization of regulatory liability
relating to deferred income taxes (159) (5,164) (174)
$36,147 $22,911 $29,336
Federal and state income taxes
charged to:
Operating expense $36,099 $24,574 $29,154
Other (income) expense 48 (1,663) 182
$36,147 $22,911 $29,336
Deferred tax liabilities and assets are determined based on the
difference between the financial statement and tax bases of assets and
liabilities using enacted tax rates in effect in the year in which the
differences are expected to reverse.
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.
<PAGE 43>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Accumulated deferred income taxes consisted of the following in 1996 and
1995:
1996 1995
(Dollars in Thousands)
Liabilities
Property-related $195,810 $190,763
Power contract buy-out 10,002 10,002
Fuel charge stabilization 8,124 8,149
Postretirement benefits plan 7,442 6,767
Seabrook nonconstruction 1,183 3,089
All other 20,018 20,006
242,579 238,776
Assets
Investment tax credits 17,205 18,035
Pension plan 8,528 7,457
Regulatory liability 6,352 6,455
All other 22,239 21,570
54,324 53,517
Accumulated deferred income taxes, net $188,255 $185,259
The net year-end deferred income tax liability above includes a current
deferred tax liability of $13,378,000 and $15,077,000 in 1996 and 1995,
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
1996, 31% in 1995 and 37% in 1994 of income before such taxes. The following
table reconciles the statutory federal income tax rate to these percentages:
1996 1995 1994
(Dollars in Thousands)
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory
levels $33,363 $26,007 $27,406
Increase (Decrease) from statutory levels:
State tax net of federal tax benefit 4,181 3,439 3,623
Tax versus book depreciation 1,553 1,369 1,471
Amortization of investment tax credits (1,285) (1,368) (1,457)
Reversals of capitalized expenses (654) (652) (654)
Dividend received deduction (381) (389) (428)
Amortization of excess deferred reserves (159) (5,164) (174)
Other (471) (331) (451)
$36,147 $22,911 $29,336
Effective federal income tax rate 38% 31% 37%
(6) 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.
<PAGE 44>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Components of pension expense and related assumptions to develop pension
expense were as follows:
1996 1995 1994
(Dollars in Thousands)
Service cost $ 7,663 $ 6,386 $ 7,316
Interest cost 24,462 23,949 21,452
Return on plan assets-(gain)/loss (45,961) (62,933) 4,544
Net amortization and deferral 24,520 42,928 (21,990)
Total pension expense 10,684 10,330 11,322
Less: Amounts capitalized
and deferred 2,203 1,842 2,823
Net pension expense $ 8,481 $ 8,488 $ 8,499
Discount rate 7.25% 8.50% 7.25%
Assumed rate of return 8.75 9.00 8.50
Rate of increase in future
compensation 4.25 5.00 4.50
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:
1996 1995
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(254,888) $(240,585)
Nonvested (30,604) (26,772)
$(285,492) $(267,357)
Projected benefit obligation $(340,850) $(323,652)
Plan assets at fair market value 343,884 308,969
Projected benefit obligation less
or (greater) than plan assets 3,034 (14,683)
Unamortized transition obligation 8,036 9,643
Unrecognized prior service cost 13,357 14,792
Unrecognized gain (43,918) (27,349)
Accrued pension liability $ (19,491) $ (17,597)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1996 1995
Discount rate 7.50% 7.25%
Rate of increase in future compensation 4.25 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.
<PAGE 45>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
To fund its postretirement benefits, the system makes contributions to
various voluntary employees' beneficiary association trusts that were
established 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 $13.7
million, $14 million and $14.5 million to these trusts during 1996, 1995 and
1994, respectively.
The net periodic postretirement benefit cost for the years ended
December 31, 1996, 1995 and 1994 include the following components and related
assumptions:
1996 1995 1994
(Dollars in Thousands)
Service cost $ 2,211 $ 1,774 $ 2,198
Interest cost 9,352 9,022 8,299
Return on plan assets (5,176) (5,796) (186)
Amortization of transition obligation
over 20 years 5,336 5,336 5,336
Net amortization and deferral 2,038 3,692 (1,118)
Total postretirement benefit cost 13,761 14,028 14,529
Less: Amounts capitalized and deferred 1,614 5,898 8,811
Net postretirement benefit cost $12,147 $ 8,130 $ 5,718
Discount rate 7.25% 8.50% 7.25%
Assumed rate of return 8.75 9.00 8.50
Rate of increase in future compensation 4.25 5.00 4.50
The funded status of the system's postretirement benefit plan using a
measurement date of December 31, 1996 and 1995 is as follows:
1996 1995
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (72,827) $ (71,270)
Fully eligible active plan participants (11,468) (12,860)
Other active plan participants (41,352) (41,814)
(125,647) (125,944)
Plan assets at fair market value 45,967 33,324
Accumulated postretirement benefit obligation
greater than plan assets (79,680) (92,620)
Unamortized transition obligation 85,368 90,703
Unrecognized (gain) loss (5,688) 1,917
$ - $ -
The following actuarial assumptions were used in determining the plan's
estimated accumulated postretirement benefit obligation (APBO) and funded
status for 1996 and 1995:
1996 1995
Discount rate 7.50% 7.25%
Rate of increase in future compensation 4.25 4.25
Medicare Part B premiums 9.50 12.20
Medical care 7.00 8.00
Dental care 5.00 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 5%,
respectively, by 2007 and remain at that level thereafter. A one percent
<PAGE 46>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
change in the medical trend rate would have a $1.7 million impact on the
system's annual expense and would change the APBO by approximately $16.1
million.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect
postretirement benefit expense in future years.
Effective May 1, 1995 the DPU approved a settlement proposal sponsored
jointly by Commonwealth Electric and the Attorney General of Massachusetts
which allows Commonwealth Electric to fully recover costs relating to
postretirement 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. Commonwealth Gas has recently requested a
ruling from the DPU as it seeks to fully recover its costs. In addition,
Commonwealth Gas has requested to amortize its deferred balance of $10 million
over a period not to exceed ten years. While the system is unable to predict
the ultimate outcome of its request, it believes that the DPU will authorize
similar treatment as provided to Commonwealth Electric.
(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 $4,053,000 in 1996, $4,393,000 in 1995 and $4,302,000
in 1994.
(7) 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, 1996, system companies had $135 million
of committed lines of credit that will expire at varying intervals in 1997.
These lines are normally renewed upon expiration and require annual fees of up
to .1875% of the individual line. At December 31, 1996, the uncommitted lines
of credit totaled $20 million. Interest rates on the outstanding borrowings
generally are at an adjusted money market rate and averaged 5.6% and 6.1% in
1996 and 1995, respectively. Notes payable to banks totaled $118,475,000 and
$55,600,000 at December 31, 1996 and 1995, 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,
1996 are as follows:
Sinking Funds Maturing Debt Issues
Year Subsidiaries System Subsidiaries Total
(Dollars in Thousands)
1997 $7,653 $10,000 $ 4,260 $21,913
1998 7,653 10,000 9,000 26,653
1999 7,653 10,000 10,000 27,653
2000 6,153 - - 6,153
2001 7,581 - 3,500 11,081
<PAGE 47>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(8) 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
required redemption, at par, on a non-cumulative basis, on each sinking fund
date.
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 1997-2001 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.
(9) Disclosures About Fair Value of Financial Instruments
The fair value of certain financial instruments included in the
accompanying Consolidated Balance Sheets as of December 31, 1996 and 1995 is
as follows:
1996 1995
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $377,218 $417,411 $418,694 $475,661
Preferred stock 13,840 14,601 14,660 16,847
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.
<PAGE 48>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
(10) 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
transportation 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.
The following is a breakdown, by major class, of property under capital
lease at December 31, 1996 and 1995:
1996 1995
(Dollars in Thousands)
Transmission facilities $12,454 $13,128
Office furniture, computer equipment and other 1,500 1,888
13,954 15,016
Less: Accumulated amortization 77 85
$13,877 $14,931
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, 1996:
Capital Operating
Leases Leases
(Dollars in Thousands)
1997 $ 2,941 $13,791
1998 2,319 12,182
1999 1,810 11,369
2000 1,732 5,032
2001 1,669 3,058
Beyond 2001 18,845 12,159
Total future minimum lease payments 29,316 $57,591
Less: Estimated interest element
included therein 15,439
Estimated present value of future minimum
lease payments $13,877
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $12,922,000 in 1996, $13,867,000 in 1995 and
$13,052,000 in 1994. There were no contingent rentals and no sublease rentals
for the years 1996, 1995 and 1994.
(11) Dividend Restriction
At December 31, 1996, approximately $112,717,000 of consolidated
retained earnings was restricted against the payment of cash dividends by
terms of indentures and note agreements securing long-term debt.
(12) Segment Information
System companies provide electric, gas and steam services to retail
customers in communities located in central, eastern and southeastern
Massachusetts 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.
<PAGE 49>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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.
1996 1995 1994
(Dollars in Thousands)
Revenues from
Unaffiliated Customers
Electric $ 649,678 $ 604,980 $ 638,150
Gas 341,867 306,953 323,568
Steam and other 19,360 17,355 15,867
Total Revenues $1,010,905 $ 929,288 $ 977,585
Capital Expenditures (including AFUDC)
Electric $ 38,844 $ 61,643 $ 38,754
Gas 11,611 16,198 18,020
Other 2,730 3,659 1,843
$ 53,185 $ 81,500 $ 58,617
Operating Income
Before Income Taxes
Electric $ 92,374 $ 78,817 $ 85,823
Gas 36,984 36,611 31,664
Steam and other 3,406 3,689 3,482
Total Operating Income Before
Income Taxes $ 132,764 $ 119,117 $ 120,969
Identifiable Assets
Electric $1,011,306 $ 982,384 $ 931,168
Gas 388,930 374,615 380,805
Steam and other 58,081 57,269 53,914
1,458,317 1,414,268 1,365,887
Intercompany eliminations (42,757) (35,140) (34,503)
Investment in corporate joint
ventures 13,395 13,214 13,648
Total Identifiable Assets $1,428,955 $1,392,342 $1,345,032
Depreciation Expense
Electric $ 39,977 $ 36,977 $ 33,188
Gas 10,061 9,656 9,559
Steam and other 1,744 1,537 1,441
Total Depreciation $ 51,782 $ 48,170 $ 44,188
<PAGE 50>
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 1997 Annual Meeting and Proxy Statement dated
March 28, 1997, pages 3-4.
b. Executive Officers of the Registrant:
Age at
December
Name of Officer Position and Business Experience 31, 1996
William G. Poist President, Chief Executive Officer and 63
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.
James D. Rappoli Financial Vice President and Treasurer of 45
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.
Russell D. Wright President and Chief Operating Officer of 50
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
(July 1987 to March 1993); Treasurer of
System subsidiary companies (December 1989
to December 1990); Assistant Vice President-
Finance of System subsidiary companies 1986.
* Subsidiary of the System.
<PAGE 51>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
b. Executive officers of the Registrant (Continued):
Age at
December
Name of Officer Position and Business Experience 31, 1996
Michael P. Sullivan Vice President, Secretary, and 48
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.
Robert A. Paul Senior Vice President of Corporate 52
Planning of COM/Energy Services
Company* (effective February 10, 1997);
Vice President of Commonwealth
Edison Co. (a subsidiary of Unicom Corp.)
from 1994 to 1997; senior manager at
Digital Equipment Corp. from 1977 to 1994.
John R. Williams Vice President of Corporate Services of 53
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 1, 1997, 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 1997 Annual Meeting and Proxy Statement dated March 28, 1997,
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 1997 Annual Meeting of Shareholders dated March 28, 1997,
pages 2-4.
<PAGE 52>
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 1997 Annual Meeting and Proxy Statement dated March 28, 1997,
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 29).
(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 71).
Schedule I - Investments in, Equity in Earnings of, and Dividends
Received from Related Parties - Years Ended December 31, 1996, 1995 and
1994 (pages 72-74).
Schedule II - Valuation and Qualifying Accounts - Years Ended December
31, 1996, 1995 and 1994 (page 75).
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, 1997.
<PAGE 53>
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 54>
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).
<PAGE 55>
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
(September 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 56>
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
August 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 Power Exchange Agreement by and between BECO and CEL dated
December 1, 1984 (Exhibit 5 to the CEL 1984 Form 10-K, File No. 2-
7909).
10.1.7.5 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).
<PAGE 57>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
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).
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
(Exhibit 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 Agreement to Share Certain Costs Associated with the Tewksbury-
Seabrook Transmission Line dated May 8, 1986 (Exhibit 2 to the CEC
1986 Form 10-K, File No. 2-30057).
10.1.10 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).
10.1.11 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).
10.1.12 Termination Supplement between CEC, CE and CEL for Seabrook Unit 2,
dated December 8, 1986 (Exhibit 3 to the CEC 1986 Form 10-K, File
No. 2-30057).
<PAGE 58>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.13 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).
10.1.14 Agreement between NBGEL and Central Maine Power Company (CMP), for
the joint-ownership, construction and operation of William F. Wyman
Unit No. 4 dated November 1, 1974 together with Amendment No. 1
dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No.
2-54955).
10.1.14.1 Amendments No. 2 and 3 to 10.1.17 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).
10.1.15 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).
10.1.15.1 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).
10.1.15.2 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).
10.1.16 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).
10.1.17 Capacity Acquisition Agreement between CEC,CEL and CE dated
September 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K,
File No. 2-30057).
10.1.17.1 Supplement to 10.1.20 consisting of three Capacity Acquisition
Commitments each dated May 7, 1987, concerning Phases I and II of
the Hydro-Quebec Project and electricity acquired from Connecticut
Light and Power Company (CL&P) (Exhibit 1 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.17.2 Supplements to 10.1.20 consisting of two Capacity Acquisition
Commitments each dated October 31, 1988, concerning electricity
acquired from Western Massachusetts Electric Company and/or CL&P
for periods ranging from November 1, 1988 to October 31, 1994
(Exhibit 2 to the CEC Form 10-Q (September 1989), File No. 2-
30057).
<PAGE 59>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.17.3 Amendment to 10.1.20 as amended and restated June 1, 1993,
henceforth 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).
10.1.17.4 Capacity Disposition Commitment dated June 25, 1993 by and between
Canal Electric Company (Unit 2) and Commonwealth Electric Company
for the sale of a portion of Commonwealth Electric's entitlement in
Unit 2 to Green Mountain Power Corporation (Exhibit 2 to Canal
Electric's Form 10-Q (September 1993), File No. 2-30057).
10.1.18 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).
10.1.18.1 Amendment No. 2 to 10.1.21 as amended November 1, 1982 (Exhibit 5
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.18.2 Amendment No. 3 to 10.1.21 as amended January 1, 1986 (Exhibit 2 to
the CE 1986 Form 10-K, File No. 2-7749).
10.1.19 Participation Agreement between MEPCO and CEL and/or NBGEL dated
June 20, 1969 for construction of a 345 KV transmission line
between Wiscasset, Maine and Mactaquac, New Brunswick, Canada and
for the purchase of base and peaking capacity from the NBEPC
(Exhibit 13 to the CES 1984 Form 10-K, File No. 1-7316).
10.1.19.1 Supplement Amending 10.1.22 as amended June 24, 1970 (Exhibit 8 to
the CES Form S-7, Amendment No. 1, File No. 2-38372).
10.1.20 Power Purchase Agreement between Weweantic Hydro Associates and CE
for the purchase of available hydro-electric energy produced by a
facility located in Wareham, Massachusetts, dated December 13, 1982
(Exhibit 1 to the CE 1983 Form 10-K, File No. 2-7749).
10.1.20.1 Power Purchase Agreement (Revised) between Weweantic Hydro Associ-
ates and Commonwealth Electric Company for the purchase of
available hydro-electric energy produced by a facility located in
Wareham, MA, originally dated December 13, 1982, revised and dated
March 12, 1993 (Exhibit 1 to the CE Form 10-Q (June 1993), File No.
2-7749).
10.1.21 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 60>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.22 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).
10.1.22.1 Amendment to 10.1.25 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).
10.1.23 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
Corporation (NEET), other New England utilities and CE (Exhibit 1
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.23.1 Amendment No. 3 to 10.1.26 (Exhibit 2 to the CE Form 10-Q (June
1986), File No. 2-7749).
10.1.24 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,
Amendment 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).
10.1.25 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
(Exhibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.25.1 Amendatory Agreement No. 3 to 10.1.28 as amended June 1, 1990,
among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q
(September 1990), File No. 2-30057).
10.1.26 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).
10.1.27 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).
10.1.28 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 61>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.29 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).
10.1.29.1 First, Second and Third Amendments to 10.1.32 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).
10.1.29.2 Fifth, Sixth and Seventh Amendments to 10.1.32 as amended October
15, 1987, December 15, 1987 and March 1, 1988, respectively
(Exhibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.29.3 Fourth and Eighth Amendments to 10.1.32 as amended July 1, 1987 and
August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.29.4 Ninth and Tenth Amendments to 10.1.32 as amended November 1, 1988
and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form
10-K, File No. 2-30057).
10.1.29.5 Eleventh Amendment to 10.1.32 as amended November 1, 1989 (Exhibit
4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.29.6 Twelfth Amendment to 10.1.32 as amended April 1, 1990 (Exhibit 1 to
the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.30 Phase II Equity Funding Agreement for New England Hydro-
Transmission 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).
10.1.31 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
utilities (Exhibit 2 to the CEC Form 10-Q (September 1990), File
No. 2-30057).
10.1.32 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).
10.1.33 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).
10.1.33.1 Amendment No. 1 to 10.1.36 dated May 1, 1986 (Exhibit 6 to the CEC
Form 10-Q (March 1987), File No. 2-30057).
<PAGE 62>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.33.2 Amendment No. 2 to 10.1.36 as amended September 1, 1987 (Exhibit 3
to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.34 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).
10.1.34.1 Amendments Nos. 1 and 2 to 10.1.37 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.34.2 Amendments Nos. 3 and 4 to 10.1.37 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.35 Phase II Boston Edison AC Facilities Support Agreement, dated June
1, 1985, between BECO and certain NEPOOL utilities (Exhibit 7 to
the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.35.1 Amendments Nos. 1 and 2 to 10.1.38 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.35.2 Amendments Nos. 3 and 4 to 10.1.38 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.36 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
(Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2-
30057).
10.1.37 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).
10.1.37.1 Transmission Service Agreement between Northeast Utilities'
companies (NU) - The Connecticut Light and Power Company (CL&P) and
Western Massachusetts Electric Company (WMECO), and CE for NU
companies to transmit power purchased from Swift River Company's
Chicopee Units to CE, dated October 1, 1984 (Exhibit 14 to the CE
1984 Form 10-K, File No. 2-7749).
10.1.37.2 Transformation Agreement between WMECO and CE whereby WMECO is to
transform power to CE from the Chicopee Units, dated December 1,
1984 (Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.38 System Power Sales Agreement by and between CL&P and WMECO, as
buyers, and CE, as seller, dated January 13, 1984 (Exhibit 13 to
the CE 1984 Form 10-K, File No. 2-7749).
<PAGE 63>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.39 System Power Sales Agreement by and between CL&P, WMECO, as
sellers, and CEL, as buyer, of power in excess of firm power
customer requirements from the electric systems of the NU
Companies, dated June 1, 1984, as effective October 25, 1985
(Exhibit 1 to CEL 1985 Form 10-K, File No. 2-7909).
10.1.39.1 System Power Sales Agreement by and between CL&P, WMECO, and PSNH,
as sellers, and Commonwealth Electric Company, as buyer, of power
for peaking capacity and related energy, dated January 13, 1995, as
effective June 1, 1995 and extending to October 31, 2000 (Exhibit 2
to the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.40 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).
10.1.40.1 Power Sales Agreement to 10.1.44 for all capacity and related
energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985
Form 10-K, File No. 2-7749).
10.1.40.2 Amendment to 10.1.44 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).
10.1.40.3 Amendment to 10.1.44 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).
10.1.41 System Power Sales Agreement by and between CE (seller) and NEP
(buyer), dated January 6, 1984 (Exhibit 1 to the CE Form 10-Q (June
1985), File No. 2-7749).
10.1.42 Service Agreement by and between CE and NEP dated March 24, 1984,
whereas CE agrees to purchase short-term power applicable to NEP'S
FERC Electric Tariff Number 5 (Exhibit 1 to the CE Form 10-Q (June
1987), File No. 2-7749).
10.1.43 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).
10.1.43.1 First Amendment to 10.1.47 as amended August 15, 1988 (Exhibit 1 to
the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.43.2 Second Amendment to 10.1.47 as amended January 1, 1989 (Exhibit 2
to the CE 1988 Form 10-K, File No. 2-7749).
<PAGE 64>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.43.3 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).
10.1.43.4 Amendment to 10.1.47.3 as amended January 1, 1989 (Exhibit 3 to the
CE 1988 Form 10-K, File No. 2-7749).
10.1.44 Exchange of Power Agreement between Montaup Electric Company and CE
dated January 17, 1991 (Exhibit 2 to CE Form 10-Q (September 1991)
File No. 2-7749).
10.1.44.1 First Amendment, dated November 24, 1992, to Exchange of Power
Agreement between Montaup Electric Company and Commonwealth
Electric Company dated January 17, 1991 (Exhibit 1 to CE Form 10-Q
(March 1993) File No. 2-7749).
10.1.45 System Power Exchange Agreement by and between Commonwealth
Electric Company and New England Power Company dated January 16,
1992 (Exhibit 1 to CE Form 10-Q (March 1992), File No. 2-7749).
10.1.45.1 First Amendment, dated September 8, 1992, to 10.1.49 by and between
Commonwealth Electric Company and New England Power Company dated
January 16, 1992 (Exhibit 1 to CE Form 10-Q (September 1992), File
No. 2-7749).
10.1.45.2 Second Amendment, dated March 2, 1993, to 10.1.49 by and between CE
and New England Power Company (NEP) dated January 16, 1992 (Exhibit
2 to CE Form 10-Q (March 1993) File No. 2-7749).
10.1.46 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).
10.1.46.1 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).
10.1.47 Power Exchange Contract, dated March 24, 1993, between NEP and
Canal Electric Company (Canal) for an exchange of unit capacity in
which NEP will purchase 20 MW of Canal Unit 2 capacity in exchange
for Canal's purchase of 20 MW of NEP's Bear Swamp Units 1 and 2 (10
MW per unit) commencing May 31, 1993 through April 28, 1997 and NEP
will purchase 50 MW of Canal's Unit 2 capacity in exchange for
Canal's purchase of 50 MW of NEP's Bear Swamp Units 1 and 2 (25 MW
per unit) commencing November 1, 1993 through April 28, 1997
(Exhibit 1 to Canal's Form 10-Q (March 1993) File No. 2-30057).
<PAGE 65>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.1.48 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).
10.1.49 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).
10.1.49.1 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
Commonwealth Electric's Form 10-Q (September 1993), File No 2-
7749).
10.1.49.2 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).
10.1.49.3 First Amendment, dated November 7, 1994, to 10.1.53 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).
10.1.49.4 First Amendment, dated November 7, 1994, to 10.1.53.2 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 Service Agreement Applicable to Rate Schedule F-1 between AGT and
CG for Firm natural gas services, dated January 28, 1981 (Exhibit 1
to the CG Form 10-Q (March 1987), File No. 2-1647).
10.2.2 Gas Service Contract between HOPCO and NBGEL for the performance of
liquefaction, storage and vaporization service and the operation
and maintenance of an LNG facility located at Acushnet, MA dated
September 1, 1971 (Exhibit 8 to the CG 1984 Form 10-K, File No. 2-
1647).
10.2.2.1 Gas Service Contract between HOPCO and CG for the performance of
liquefaction, storage and vaporization services and the operation
of LNG facilities located in Hopkinton, MA dated September 1, 1971
(Exhibit 9 to the CG 1984 Form 10-K, File No. 2-1647).
<PAGE 66>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.2.2.2 Amendments to 10.2.2 and 10.2.2.1 as amended December 1, 1976
(Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647).
10.2.2.3 Supplement 1 to Gas Service Contract between HOPCO and NBGEL dated
September 1, 1973 and September 14, 1977 (Exhibit 5(c)5 to the CES
Form S-16 (June 1979), File No. 2-64731).
10.2.2.4 Supplement 1 to 10.2.2.1 dated September 14, 1977 (Exhibit 5(c)6 to
the CG Form S-16 (June 1979), File No. 2-64731).
10.2.2.5 Supplement 2 to 10.2.2.1 dated September 30, 1982 (Refiled as
Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647).
10.2.2.6 1986 Consolidating Supplement to CG Service Contract and NBGEL
Service Contract by and between CG and HOPCO dated December 31,
1986 amending and consolidating the CG Service Contract and the
NBGEL Service Contract both as amended December 1, 1976 and
supplemented September 14, 1977 (Exhibit 2 to CG Form 10-Q (March
1988), File No. 2-1647).
10.2.3 Operating Agreement between Air Products and Chemicals, Inc., (APC)
and HOPCO, dated as of September 1, 1971, as supplemented by
Supplements No. 1, No. 2 and No. 3 dated as of July 1, 1974,
August 1, 1975 and January 1, 1985, respectively, with respect to
the operation and maintenance by APC of HOPCO's liquefied natural
gas facilities located at Hopkinton, MA (Exhibit 11 to the CES 1984
Form 10-K, File No. 1-7316).
10.2.3.1 Engineering and Prime Contracting Agreement between APC and HOPCO
for performance of engineering services and capital project
construction at LNG facility in Hopkinton, MA (Exhibit 12 to the
CES 1984 Form 10-K, File No. 1-7316).
10.2.4 Firm Storage Service Transportation Contract by and between TGP and
CG providing for firm transportation of natural gas from CGT, dated
December 15, 1985 (Exhibit 1 to the CG 1985 Form 10-K, File No. 2-
1647).
10.2.5 Gas Sales Agreement by and between Enron Gas Marketing, Inc. and CG
relating to the sale and purchase of natural gas on an
interruptible basis, dated June 17, 1986 (Exhibit 3 to the CG Form
10-Q (June 1986), File No. 2-1647).
10.2.6 Service Agreement dated December 14, 1985 and an amendment thereto
dated May 15, 1986 by and between Texas Eastern Transmission
Corporation (TET) and CG to receive, transport and deliver to
points of delivery natural gas for the account of CG, dated
December 14, 1985 (Exhibit 5 to the CG Form 10-Q (June 1986), File
No. 2-1647).
10.2.7 Gas Transportation Agreement by and between TET and CG to receive,
transport and deliver on an interruptible basis, certain quantities
of natural gas for the account of CG, dated January 31, 1986
(Exhibit 6 to the CG Form 10-Q (June 1986), File No. 2-1647).
<PAGE 67>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.2.8 Service Agreement dated May 19, 1988, by and between TET and CG,
whereby TET agrees to receive, transport and deliver natural gas to
CG (Exhibit 1 to the CG Form 10-Q (September 1988), File No. 2-
1647).
10.2.9 Gas Transportation Agreement by and between AGT and CG to receive,
transport and deliver certain quantities of natural gas on a firm
basis for the account of CG dated December 1, 1988 (Exhibit 2 to
the CG 1988 Form 10-K, File No. 2-1647).
10.2.10 Gas Sales Agreement between Tejas Power Corporation (seller) and CG
(purchaser) for the purchase of spot market gas, dated February 21,
1989 with a contract term of at least one year (Exhibit 2 to the CG
Form 10-Q (March 1989), File No. 2-1647).
10.2.11 Gas Sales Agreement between Vitol (seller) and CG (purchaser) for
the purchase of spot market gas, dated April 5, 1988, with a
contract term of at least one year (Exhibit 1 to the CG Form 10-Q
(June 1989), File No. 2-1647).
10.2.12 Gas Sales Agreement between Fina Oil and Chemical Company (seller)
and CG (purchaser) for the purchase of spot market gas, dated July
10, 1989, with a contract term of at least one year (Exhibit 3 to
the CG Form 10-Q (September 1989), File No. 2-1647).
10.2.13 Gas Sales Agreement between Panenergy (seller) and CG (purchaser)
for the purchase of spot market gas, dated August 14, 1989, with a
contract term of at least one year (Exhibit 4 to the CG Form 10-Q
(September 1989), File No. 2-1647).
10.2.14 Gas Storage Agreement between Steuben Gas Storage Company (Steuben)
and CG (customer) for the storage and delivery of customer's
natural gas to and from underground gas storage facilities, dated
May 23, 1989, with a contract term of at least one year (Exhibit 4
to the CG Form 10-Q (June 1989), File No. 2-1647).
10.2.14.1 Amendment, dated August 28, 1989, to 10.2.14 dated May 23, 1989
(Exhibit 5 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.2.15 Gas Sales Agreement between LGN&E (seller) and CG (purchaser) for
the purchase of firm gas, dated August 15, 1990, with a contract
term of at least six years (Exhibit 1 to the CG Form 10-Q
(September 1990), File No. 2-1647).
10.2.16 Transportation Agreement between AGT and CG to provide for firm
transportation of natural gas on a daily basis, dated December 1,
1988 (Exhibit 3 to the CG 1991 Form 10-K, File No. 2-1647).
10.2.17 Gas Sales Agreement between AFT and CG to reduce the volume of Rate
Schedule F-1, dated October 15, 1990 (Exhibit 5 to the CG 1991 Form
10-K, File No. 2-1647).
<PAGE 68>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
10.2.18 Transportation Agreement between AFT and CG for Rate Schedule AFT-
1, dated November 1, Agreement No. 90103, 1990 (Exhibit 6 to the CG
1991 Form 10-K, File No. 2-1647).
10.2.19 Transportation Agreement between TGP and CG dated September 1, 1991
(Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647).
10.2.20 Transportation Agreement between CNG and CG to provide for
transportation 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).
10.2.21 Service Line Agreement by and between Commonwealth Gas Company (CG)
and Milford Power Limited Partnership dated March 12, 1992 for a
term ending January 1, 2013. (Exhibit 1 to the CG Form 10-Q (March
1992), 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 the Employees Savings Plan of Commonwealth
Energy System and Subsidiary Companies, as amended and restated as
of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES
Form S-8 (January 1995), File No. 1-7316).
10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971
as amended through August 1, 1977, between NEGEA Service
Corporation, 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
(Refiled 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 69>
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
(Exhibit 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 Fuel Supply, Facilities Lease and Operating Contract by and
between, on the one side, ESCO (Massachusetts), Inc. and Energy
Supply and Credit Corporation, and on the other side, CEC, dated as
of February 1, 1985 (Exhibit 1 to the CEC 1984 Form 10-K, File No.
2-30057.
10.3.4.1 Amendments Nos. 1 and 2 to 10.3.5 as amended July 1, 1986 and
November 15, 1989, respectively (Exhibit 3 to the CEC 1989 Form 10-
K, File No. 2-30057).
10.3.5 Assignment and Sublease Agreement and Canal's Consent of Assignment
thereto whereby ESCO-Mass assigns its rights and obligations under
Part II of the Resupply Agreement dated February 1, 1985 to ESCO
Terminals Inc., dated June 4, 1985 (Exhibit 4 to CEC Form 10-Q
(June 1985), File No. 2-30057).
10.3.6 Oil Supply Contract by and between CEC (buyer) and Coastal Oil New
England, Inc. (seller) for a portion of CEC's requirements of No. 6
residual fuel oil, dated July 1, 1991 (Exhibit 3 to CEC Form
10-Q (June 1991), File No. 2-30057).
10.3.6.1 Assignment Agreement between CEC and ESCO (Massachusetts), Inc.
(ESCO-Mass) and Energy Supply and Credit Corporation whereby CEC
assigns to ESCO-Mass rights and obligations under 10.3.7 (above)
dated July 1, 1991 (Exhibit 4 to CEC Form 10-Q (June 1991), File
No. 2-30057).
10.3.7 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).
<PAGE 70>
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
Exhibit 21. Subsidiaries of the Registrant
Filed herewith as Exhibit 1 is a list of subsidiaries of
Commonwealth Energy System, all of which are wholly-owned, as of
December 31, 1996.
Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security
Holders.
Filed herewith as Exhibit 2 is the Notice of 1997 Annual Meeting
and Proxy Statement dated March 28, 1997.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 3 is the Financial Data Schedule for
the twelve months ended December 31, 1996.
Filed herewith as Exhibit 4 is the restated Financial Data Sched-
ule for the twelve months ended December 31, 1995.
Filed herewith as Exhibit 5 is the restated Financial Data Sched-
ule for the twelve months ended December 31, 1994.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
December 31, 1996.
<PAGE 71>
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, 1997.
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, 1997.
<PAGE 72>
<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 73>
<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 3,893 620
$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 74>
<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, 1994
(Dollars in Thousands)
<CAPTION>
Balance at Balance at
Beginning of Year Additions Deductions End of Year
Number Equity Number Notes
of in Other Distribution of Receivable
Shares Investment Earnings (B) of Earnings 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 $ 43,674 $ 6,242 $ - $ 6,132 346,600 $ 43,784 $ 410
COM/Energy Steam Company 25,500 3,321 1,976 - 1,187 25,500 4,110 105
Canal Electric Company 1,523,200 94,552 14,158 - 10,662 1,523,200 98,048 9,350
Commonwealth Gas Company 2,857,000 107,004 13,568 - 14,571 2,857,000 106,001 2,935
Darvel Realty Trust 26 759 111 - - 26 870 -
COM/Energy Freetown Realty 1 (18,832) (335) 25,000 - 1 5,833 360
COM/Energy Research Park Realty 1 1,045 296 - 455 1 886 -
COM/Energy Cambridge Realty 1 74 (17) - - 1 57 -
COM/Energy Acushnet Realty 1 558 66 - 100 1 524 -
COM/Energy Services Company 3,250 337 49 - 49 3,250 337 -
Commonwealth Electric Company 2,043,972 163,329 16,073 - 15,841 2,043,972 163,561 200
Hopkinton LNG Corp. 5,000 4,019 548 - 674 5,000 3,893 -
$399,840 $52,735 $25,000 $49,671 $427,904 $13,360
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52,454 $ 9,660 $ 1,242 $ - $ 1,084 52,454 $ 9,818
Hydro-Quebec Phase II 137,442 3,861 508 - 567 137,442 3,802
Other Investments - 28 - - - - 28
$ 13,549 $ 1,750 $ - $ 1,651 $ 13,648
<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) Additional investment.
</TABLE>
<PAGE 75>
SCHEDULE II
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(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, 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
Year Ended December 31, 1994
Allowance for
Doubtful Accounts $7,761 $9,396 $2,138 $11,339 $7,956
<PAGE 76>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1996
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 27, 1997
William G. Poist,
President and Chief Executive Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 27, 1997
James D. Rappoli,
Financial Vice President and Treasurer
A majority of the Board of Trustees:
SHELDON A. BUCKLER March 27, 1997
Sheldon A. Buckler, Chairman of
the Board
PETER H. CRESSY March 27, 1997
Peter H. Cressy, Trustee
March , 1997
Henry Dormitzer, Trustee
B. L. FRANCIS March 27, 1997
Betty L. Francis, Trustee
FRANKLIN M. HUNDLEY March 27, 1997
Franklin M. Hundley, Trustee
<PAGE 77>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1996
SIGNATURES
(Continued)
WILLIAM J. O'BRIEN March 27, 1997
William J. O'Brien, Trustee
WILLIAM G. POIST March 27, 1997
William G. Poist, Trustee
MICHAEL C. RUETTGERS March 27, 1997
Michael C. Ruettgers, Trustee
G. L. WILSON March 27, 1997
Gerald L. Wilson, Trustee
<PAGE 78>
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, 1996 or
performed any audit procedures subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
March 28, 1997.
Exhibit 1
COMMONWEALTH ENERGY SYSTEM
LIST OF SUBSIDIARIES
DECEMBER 31, 1996
Cambridge Electric Light Company
Canal Electric Company
COM/Energy Acushnet Realty
COM/Energy Cambridge Realty
COM/Energy Enterprises, Inc.
COM/Energy Freetown Realty
COM/Energy Research Park Realty
COM/Energy Resources, Inc.
COM/Energy Services Company
COM/Energy Steam Company
Commonwealth Electric Company
Commonwealth Gas Company
Darvel Realty Trust
Hopkinton LNG Corp.
<PAGE 1>
Commonwealth
Energy System
Notice of 1997
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 1, 1997
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 1, 1997, 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 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, 1997
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 28, 1997
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 1, 1997, 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 28, 1997.
FINANCIAL STATEMENTS
The audited financial statements of Commonwealth Energy System and
Subsidiary Companies, which include comparative Balance Sheets as of
December 31, 1996 and 1995, Statements of Income and Statements of Cash Flows
for the three years ended December 31, 1996 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, 1997 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 3,178,045 Common Shares representing 14.7% of the
outstanding Common Shares as of March 17, 1997. 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 March 17, 1997, of Common Shares of the System owned by the Chief
Executive Officer and the four other most highly compensated 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 19,608 0.1%
Russell D. Wright 11,772 0.1%
James D. Rappoli 6,577 0.1%
Leonard R. Devanna 6,478 0.1%
Michael P. Sullivan 6,315 0.1%
All Trustees and Executive Officers
as a group (14 persons) 73,732 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 or
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:
Kevin C. Bryant
Franklin M. Hundley
Gerald L. Wilson
Of the three nominees, Mr. Hundley and Dr. Wilson are presently
Trustees. Mr. Bryant was nominated by the Board on February 27, 1997 to fill
the position which will be occasioned by the retirement of Mr. Henry
Dormitzer, who is retiring from the Board of Trustees at the conclusion of his
term effective May 1, 1997.
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
Year First Beneficially
Became a Owned as of
Name, Principal Occupation and Term of Office Trustee Age March 17, 1997
KEVIN C. BRYANT, Regional President,
BankBoston - Southeastern Region,
Fall River, Massachusetts
(NOMINEE)........................... - 36 200
(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 ............... (1991) 65 4,432
<PAGE>
<PAGE 5>
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Year First Beneficially
Became a Owned as of
Name, Principal Occupation and Term of Office Trustee Age March 17, 1997
(A) PETER H. CRESSY, Chancellor, University of
(E) Massachusetts Dartmouth, North Dartmouth,
Massachusetts; Retired Rear Admiral,
United States Navy
TERM EXPIRES IN 1999 ............... (1994) 55 228
(A) BETTY L. FRANCIS, Executive Vice President
(D) and Chief Credit Officer, HomeSide
Lending, Inc., Jacksonville, Florida
TERM EXPIRES IN 1998 ................... (1991) 50 200
(C) FRANKLIN M. HUNDLEY, Member and a Managing
(D) Director, Rich, May, Bilodeau & Flaherty,
P.C., Boston, Massachusetts (Attorneys);
Director, The Berkshire Gas Company
TERM EXPIRES IN 1997 (NOMINEE)......... (1985) 62 5,056
(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) 64 3,500
WILLIAM G. POIST, President and Chief
Executive Officer of Commonwealth Energy
System and Chairman, Chief Executive Officer
and a Director of its subsidiary companies
TERM EXPIRES IN 1999 ................... (1992) 63 19,608
(B) MICHAEL C. RUETTGERS, President, Chief
(E) Executive Officer and a Director, EMC
Corporation, Hopkinton, Massachusetts
(Data storage technology); Director,
CrossComm Corporation
TERM EXPIRES IN 1998 ................... (1995) 54 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 1997 (NOMINEE)......... (1985) 57 1,304
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 except for Dr. Wilson, who served as Vice President-Corporate Technology
and Manufacturing at Carrier Corporation during 1991-1992 while on a leave of
absence from Massachusetts Institute of Technology.
During 1996, fees of $329,819 were incurred for legal services rendered
by the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr. Hundley is a
Member and a Managing Director. The firm has been employed in the last fiscal
year and the current fiscal year.
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 6>
COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1996
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 1996 exceeded $100,000.
<TABLE>
SUMMARY COMPENSATION TABLE
<CAPTION>
Long-Term Compensation
Annual Compensation Awards Payouts
Long-
Options Term
Other Restr- /Stock Incen- All
Annual icted Apprec- tive Other
Compen- Stock iation Plan Compen-
Name and Salary sation Awards Rights (LTIP) sation
Principal Position Year (1) Bonus (2) (3) (SARS) Payouts (4)
<S> <C> <C> <C> <C><C> <C> <C> <C>
William G. Poist 1996 $380,000 $142,142 - $160,000 - - $15,204
President and Chief 1995 350,000 95,645 - - - - 14,004
Executive Officer of 1994 320,000 98,721 - - - - 12,804
the System and Chair-
man and Chief Exec-
utive Officer of its
subsidiary companies
Russell D. Wright 1996 $250,000 $ 97,427 - $100,000 - - $10,020
President and Chief 1995 231,667 66,060 - - - - 9,269
Operating Officer 1994 215,897 60,964 - - - - 8,400
of Cambridge
Electric Light
Company, Canal
Electric Company,
COM/Energy Steam
Company and
Commonwealth
Electric Company
Kenneth M. Margossian(5)1996 $209,330 $ 81,182 - - - - $ 8,375
President and 1995 194,583 56,040 - - - - 7,786
Chief Operating 1994 179,917 52,005 - - - - 7,140
Officer of Common-
wealth Gas Company
and Hopkinton LNG Corp.
James D. Rappoli 1996 $178,167 $60,740 - $ 54,800 - - $ 7,126
Financial Vice 1995 164,583 46,624 - - - - 6,586
President and 1994 151,686 43,196 - - - - 5,880
Treasurer of the
System and its
subsidiary companies
</TABLE>
<PAGE>
<PAGE 7>
<TABLE>
SUMMARY COMPENSATION TABLE (CONT'D)
<CAPTION>
Long-Term Compensation
Annual Compensation Awards Payouts
Long-
Options Term
Other Restr- /Stock Incen- All
Annual icted Apprec- tive Other
Compen- Stock iation Plan Compen-
Name and Salary sation Awards Rights (LTIP) sation
Principal Position Year (1) Bonus (2) (3) (SARS) Payouts (4)
<S> <C> <C> <C> <C><C> <C> <C> <C>
Leonard R. Devanna 1996 $168,000 $ 56,799 - $ 55,200 - - $ 8,398
President and 1995 154,250 45,511 - - - - 7,714
Chief Operating 1994 142,166 41,745 - - - - 5,912
Officer of
COM/Energy Enterprises,
Inc. and COM/Energy
Resources, Inc.
- --------------------
<FN>
(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 and the Executive Salary Continuation and Excess
Benefit Plan of Commonwealth Energy System and Subsidiary Companies.
(2) The dollar value of perquisites and other personal benefits, securities
or property totalling 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
1996, 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, which was calculated by multiplying the average closing market
price of the System's Common Shares during the first week of February,
1997 (the time of 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 March 1, 1997, is 15,563 Common Shares, having an aggregate value
of $342,386.
(4) The amounts in this column represent the aggregate contributions by the
System and certain subsidiary companies during 1996 on behalf of the
above-named individuals to the Employees Savings Plan and the Executive
Salary Continuation and Excess Benefit Plan 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 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, $6,335, $4,860, $4,775, $2,376 and $2,968
<PAGE>
<PAGE 8>
represent the contributions made on behalf of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna, respectively, by the Employees Savings
Plan. Contributions made on behalf of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna by the Executive Salary Continuation and
Excess Benefit Plan in 1996 equalled $8,869, $5,160, $3,600, $4,750 and
$5,430, respectively.
(5) Mr. Margossian resigned as President and Chief Operating Officer of
Commonwealth Gas Company and Hopkinton LNG Corp. effective February 6,
1997.
</TABLE>
<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 of Commonwealth Energy
System and Subsidiary Companies, as of December 31, 1996.
<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 .... $15,722 $23,583 $ 31,444 $ 39,306 $ 47,167 $ 51,278
120,000 .... 21,222 31,833 42,444 53,056 63,667 69,278
150,000 .... 26,722 40,083 53,444 66,806 80,167 87,278
180,000 .... 32,222 48,333 64,445 80,555 96,667 105,278
210,000 .... 37,722 56,583 75,445 94,305 113,167 123,278
240,000 .... 43,222 64,833 86,445 108,055 129,667 141,278
270,000 .... 48,722 73,083 97,445 121,805 146,167 159,278
300,000 .... 54,222 81,333 108,445 135,555 162,667 177,278
330,000 .... 59,722 89,583 119,445 149,305 179,167 195,278
360,000 .... 65,222 97,833 130,445 163,055 195,667 213,278
390,000 .... 70,722 106,083 141,445 176,805 212,167 231,278
420,000 .... 76,222 114,333 152,445 190,555 228,667 249,278
450,000 .... 81,722 122,583 163,445 204,305 245,167 267,278
- -------------
<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 of
Commonwealth Energy System and Subsidiary Companies. For 1996, the
maximum annual compensation limit under the Pension Plan for Employees
of Commonwealth Energy System and Subsidiary Companies was $150,000, and
the maximum annual benefit under that Plan was $120,000.
</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 an 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, Margossian, Rappoli and Devanna have 32,
29, 27, 22 and 15 credited years of service respectively. For the purposes of
calculating the annual retirement benefits of Messrs. Poist, Wright,
Margossian, Rappoli and Devanna 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.
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
<PAGE>
<PAGE 10>
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 and Devanna. 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, Devanna and Rappoli 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>
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.
In setting the Chief Executive Officer's base salary for 1996, 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 1996, the Annual
Incentive Plan provided for awards to the Chief Executive Officer of up to a
maximum of 40% of annual base salary. Both individual and System performance
goals and objectives were set. The Chief Executive Officer's award for 1996
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
1996, the System criteria forming the goals and objectives applicable to the
<PAGE>
<PAGE 12>
Annual Incentive Plan were: 1) meeting pre-established targets comparing
System actual net income to budgeted net income for 1996; 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 1996 net income exceeded targeted net
income by 11.8%, resulting in a maximum award. The goal established for cost
control was for operation and maintenance expenses in 1996 to be below the
approved budgeted amounts. This goal was exceeded by the System having
reduced actual operation and maintenance expenses to 4.4% 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 1996 under the
Annual Incentive Plan included: originating and implementing several projects
and programs designed to maximize System synergies, the development of new
business opportunities and the oversight of COM/Electric's restructuring
compliance filings at the Massachusetts Department of Public Utilities. The
Chief Executive Officer's performance relative to achieving individual goals
was rated as 79% achieved, resulting in an aggregate performance rating of 90%
achievement.
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.
For the three-year Plan Period commencing in 1994, the Threshold, Plan
Target and Maximum Shareholder Return achievement standards were 95% of Index
Average, Index Average, and 120% of Index Average, respectively. During this
Plan Period, the System's average total return was equal to 142% of the peer
group index, resulting in a maximum award in March of 1997 to Mr. Poist equal
to 50% of his January 1, 1994 base salary ($160,000) in restricted Common
Shares. Under the terms of the Long-Term Incentive Plan, the restricted
Common Shares generally vest three years from the date they are issued.
The 1996-1997 Strategic Plan Compensation Program ("Program") provides
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 if a three-year Plan Period ending
in 1997 were in effect (no such Plan Period ending in 1997 was established
under the Long Term Incentive Plan). Unlike the Long Term Incentive Plan,
which uses Shareholder total return as the sole criterion, the Program also
<PAGE>
<PAGE 13>
rates both the Executive Officer's contributions to achieving results in
implementing the System's Strategic Plan and the Executive Officer's overall
performance. Awards, if any, under the Program would be made in 1998.
Other Executive Officers
With respect to 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 35% (for Vice Presidents) to 40% (for Operating Company Presidents)
of annual base salary under the Annual Incentive Plan and of up to 40% (for
Vice Presidents) to 50% (for Operating Company Presidents) of 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 1996,
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 such projects as restructuring the System's existing debt portfolio,
converting Canal Electric's Unit No. 2 so that it can be fueled by both oil
and natural gas, implementing an investor relations program and renegotiating
the lease for the System's Cambridge, Massachusetts headquarters.
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
compensated officers in excess of $1 million is limited by Federal Law. The
compensation of each of the System's Executive Officers, however, is
significantly 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 has taken action over the past three years 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
<PAGE>
<PAGE 14>
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 91 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 12/31/96)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1992-1996) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1991 1992 1993 1994 1995 1996
COM/Energy $100.00 $117.00 $135.25 $114.32 $151.51 $169.98
S&P 500 100.00 107.79 118.66 120.56 165.78 204.30
Peer Group 100.00 107.20 119.27 104.73 137.47 139.57
Assumes $100 invested at the close of trading on the last trading day of
1991 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. Minnesota Power & Light Co.
American Electric Power Co., Inc. Montana Power Co.
Atlantic Energy Inc. Nevada Power Co.
Baltimore Gas and Electric Company New England Electric System
Boston Edison Company New York State Electric & Gas Corp.
Carolina Power & Light Co. Niagara Mohawk Power Corporation
Centerior Energy Corporation NIPSCO Industries, Inc.
Central Hudson Gas & Electric Corp. Northeast Utilities
Central Louisiana Electric Company Inc. Northern States Power Co.
Central Maine Power Co. Northwestern Public Service Co.
Central & South West Corp. OGE Energy, Inc.
Central Vermont Public Service Corp. Ohio Edison Co.
CILCORP Inc. Orange and Rockland Utilities, Inc.
CINergy Corp. Otter Tail Power Co.
CIPSCO Incorporated PG&E Corporation
CMS Energy Corp. PacifiCorp.
<PAGE>
<PAGE 15>
Commonwealth Energy System PECO Energy Company
Consolidated Edison Co. of New York, Inc.Pinnacle West Capital Corp.
DPL Inc. Portland General Electric Co.
Delmarva Power & Light Co. Potomac Electric Power Co.
Dominion Resources, Inc. PP&L Resources, Inc.
DQE Public Service Co. of Colorado
DTE Energy Corporation Public Service Co. of New Mexico
Duke Power Co. Public Service Enterprise Group Inc.
Eastern Utilities Associates Puget Sound Power & Light Co.
Edison International Rochester Gas and Electric Corp.
Empire District Electric Company St. Joseph Light & Power Co.
Enova Corporation SCANA Corp.
Entergy Corporation Sierra Pacific Resources
Florida Progress Corp. SIGCORP
FPL Group, Inc. The Southern Company
GPU, Inc. Southwestern Public Service Co.
Green Mountain Power Corp. TECO Energy, Inc.
Hawaiian Electric Industries, Inc. Texas Utilities Company
Houston Industries, Incorporated TNP Enterprises, Inc.
Idaho Power Co. Tucson Electric Power Co.
IES Industries Unicom Corp.
Illinova Corp. Union Electric Co.
Interstate Power Co. United Illuminating Co.
IPALCO Enterprises, Inc. UtiliCorp. United Inc.
Kansas City Power & Light Co. Washington Water Power Co.
KU Energy Corporation Western Resources, Inc.
LG&E Energy Corp. Wisconsin Energy Corp.
Long Island Lighting Co. WPL Holdings, Inc.
MDU Resources Group, Inc. WPS Resources Corporation
MidAmerican Energy Holdings Company
MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES
The System's Board of Trustees held thirteen meetings throughout 1996.
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,
Peter H. Cressy and Henry Dormitzer. The Committee held four meetings in
1996. 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 1996,
the Committee held seven 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 one meeting in
1996. The functions of the Committee are to coordinate suggestions or
searches for potential nominees for the position of Trustee, to review and
<PAGE>
<PAGE 16>
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.
The Benefit Review Committee is composed of Franklin M. Hundley,
Chairperson, Henry Dormitzer and Betty L. Francis. During 1996, the Committee
held two meetings. 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
four meetings during 1996. 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 February 23, 1996, each Trustee who was not an employee of the
System was compensated for his or her services as Trustee at the rate of
$12,500 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 received an additional $1,000 during the
year. In addition, the Chairman of the Board received 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.
<PAGE>
<PAGE 17>
2-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 1998 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 4, 1997.
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 28, 1997
<PAGE>
<PAGE 18>
APPENDICES
COMMONWEALTH ENERGY SYSTEM
Proxy-Annual Meeting of Shareholders-May 1, 1997
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 1, 1997 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
"EXCEPTIONS" box and enter the name(s) of the exception(s) in the space
provided.
_____________________________________________________________________________
The Trustees recommend a vote "FOR"
1. Election of Trustees FOR WITHHELD
EXCEPTIONS*
Nominees: K. C. Bryant [ ] [ ] [ ]
F. M. Hundley
G. L. Wilson
*EXCEPTIONS: ____________________
_____________________________________________________________________________
2. 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 the election of Trustes.
Any proxy or proxies to vote such shares at said meeting
heretofore given by the sharheolder(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_______________________, 1997
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,
1996 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-31-1996
<PERIOD-END> DEC-31-1996
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,045,627
<OTHER-PROPERTY-AND-INVEST> 13,395
<TOTAL-CURRENT-ASSETS> 196,491
<TOTAL-DEFERRED-CHARGES> 173,442
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,428,955
<COMMON> 43,059
<CAPITAL-SURPLUS-PAID-IN> 111,685
<RETAINED-EARNINGS> 260,950
<TOTAL-COMMON-STOCKHOLDERS-EQ> 415,694
13,020
0
<LONG-TERM-DEBT-NET> 355,305
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 118,475
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 21,913
820
<CAPITAL-LEASE-OBLIGATIONS> 12,346
<LEASES-CURRENT> 1,531
<OTHER-ITEMS-CAPITAL-AND-LIAB> 489,851
<TOT-CAPITALIZATION-AND-LIAB> 1,428,955
<GROSS-OPERATING-REVENUE> 1,010,905
<INCOME-TAX-EXPENSE> 36,099
<OTHER-OPERATING-EXPENSES> 878,141
<TOTAL-OPERATING-EXPENSES> 914,240
<OPERATING-INCOME-LOSS> 96,665
<OTHER-INCOME-NET> 4,878
<INCOME-BEFORE-INTEREST-EXPEN> 101,543
<TOTAL-INTEREST-EXPENSE> 42,368
<NET-INCOME> 59,175
1,050
<EARNINGS-AVAILABLE-FOR-COMM> 58,125
<COMMON-STOCK-DIVIDENDS> 33,155
<TOTAL-INTEREST-ON-BONDS> 35,586
<CASH-FLOW-OPERATIONS> 63,325
<EPS-PRIMARY> 2.70
<EPS-DILUTED> 0
</TABLE>
<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,
1995 and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<RESTATED>
<CIK> 0000071304
<NAME> COMMONWEALTH ENERGY SYSTEM
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,043,204
<OTHER-PROPERTY-AND-INVEST> 13,214
<TOTAL-CURRENT-ASSETS> 184,960
<TOTAL-DEFERRED-CHARGES> 150,964
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,392,342
<COMMON> 43,056
<CAPITAL-SURPLUS-PAID-IN> 111,749
<RETAINED-EARNINGS> 235,980
<TOTAL-COMMON-STOCKHOLDERS-EQ> 390,785
13,840
0
<LONG-TERM-DEBT-NET> 377,181
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 55,600
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 41,513
820
<CAPITAL-LEASE-OBLIGATIONS> 13,291
<LEASES-CURRENT> 1,640
<OTHER-ITEMS-CAPITAL-AND-LIAB> 497,672
<TOT-CAPITALIZATION-AND-LIAB> 1,392,342
<GROSS-OPERATING-REVENUE> 929,288
<INCOME-TAX-EXPENSE> 24,574
<OTHER-OPERATING-EXPENSES> 810,171
<TOTAL-OPERATING-EXPENSES> 834,745
<OPERATING-INCOME-LOSS> 94,543
<OTHER-INCOME-NET> 1,461
<INCOME-BEFORE-INTEREST-EXPEN> 96,004
<TOTAL-INTEREST-EXPENSE> 44,608
<NET-INCOME> 51,396
1,110
<EARNINGS-AVAILABLE-FOR-COMM> 50,286
<COMMON-STOCK-DIVIDENDS> 32,032
<TOTAL-INTEREST-ON-BONDS> 38,581
<CASH-FLOW-OPERATIONS> 124,671
<EPS-PRIMARY> 2.36
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains restated 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, 1994 and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<RESTATED>
<CIK> 0000071304
<NAME> COMMONWEALTH ENERGY SYSTEM
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,014,857
<OTHER-PROPERTY-AND-INVEST> 13,648
<TOTAL-CURRENT-ASSETS> 181,606
<TOTAL-DEFERRED-CHARGES> 134,921
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,345,032
<COMMON> 42,103
<CAPITAL-SURPLUS-PAID-IN> 103,168
<RETAINED-EARNINGS> 217,726
<TOTAL-COMMON-STOCKHOLDERS-EQ> 362,997
14,660
0
<LONG-TERM-DEBT-NET> 418,307
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 44,850
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 30,973
820
<CAPITAL-LEASE-OBLIGATIONS> 14,098
<LEASES-CURRENT> 1,631
<OTHER-ITEMS-CAPITAL-AND-LIAB> 456,696
<TOT-CAPITALIZATION-AND-LIAB> 1,345,032
<GROSS-OPERATING-REVENUE> 977,585
<INCOME-TAX-EXPENSE> 29,154
<OTHER-OPERATING-EXPENSES> 856,616
<TOTAL-OPERATING-EXPENSES> 885,770
<OPERATING-INCOME-LOSS> 91,815
<OTHER-INCOME-NET> 627
<INCOME-BEFORE-INTEREST-EXPEN> 92,442
<TOTAL-INTEREST-EXPENSE> 43,474
<NET-INCOME> 48,968
1,170
<EARNINGS-AVAILABLE-FOR-COMM> 47,798
<COMMON-STOCK-DIVIDENDS> 31,305
<TOTAL-INTEREST-ON-BONDS> 39,442
<CASH-FLOW-OPERATIONS> 126,563
<EPS-PRIMARY> 2.29
<EPS-DILUTED> 0
</TABLE>
