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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
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 $4 par value Boston Stock Exchange, Inc.
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 15, 1995: $427,406,076
Common Shares outstanding at March 15, 1995: 10,585,909 shares
Document Incorporated by Reference Part in Form 10-K
Notice of 1995 Annual Meeting, Proxy State-
ment and 1994 Financial Information, dated
March 31, 1995 (pages as specified herein) Parts I, II and III
List of Exhibits begins on page 21 of this report.
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COMMONWEALTH ENERGY SYSTEM
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business............................................... 3
General............................................. 3
Electric Power Supply............................... 5
Power Supply Commitments and Support Agreements..... 7
Electric Fuel Supply................................ 8
Nuclear Fuel Supply and Disposal.................... 8
Gas Supply.......................................... 9
Rates, Regulation and Legislation................... 10
Competition......................................... 13
Segment Information................................. 14
Environmental Matters............................... 14
Construction and Financing.......................... 14
Employees........................................... 14
Item 2. Properties............................................. 14
Item 3. Legal Proceedings...................................... 15
Item 4. Submission of Matters to a Vote of Security Holders.... 15
PART II
Item 5. Market for the Registrant's Securities and Related
Stockholder Matters.................................... 16
Item 6. Selected Financial Data................................ 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 16
Item 8. Financial Statements and Supplementary Data............ 17
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 17
PART III
Item 10. Trustees and Executive Officers of the Registrant...... 18
Item 11. Executive Compensation................................. 19
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 19
Item 13. Certain Relationships and Related Transactions......... 19
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................ 20
Signatures........................................................ 47
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COMMONWEALTH ENERGY SYSTEM
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 and a liquefied natural gas (LNG) and vaporization facility
(Hopkinton LNG Corp.). 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 was
organized in 1986 to purchase and develop 596 acres of land in Freetown,
Massachusetts. As a result of unsuccessful efforts to develop an energy park
on this site, the System wrote down its investment in the Freetown project and
plans to sell the property.
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 two oil-fired steam electric generating units: Canal Unit 1, with a rated
capacity of 569 MW, wholly-owned by Canal; and Canal Unit 2, with a rated
capacity of 580 MW, jointly-owned by Canal and Montaup Electric Company
(Montaup) (an unaffiliated company). Canal Unit 2 is operated under an
agreement with Montaup which provides for the equal sharing of output, fixed
charges and operating expenses. In October 1993, Canal reached an agreement
with Montaup and Algonquin Gas Transmission Company to build a natural gas
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COMMONWEALTH ENERGY SYSTEM
pipeline that will serve Unit 2, subject to regulatory approvals. The project
will improve air quality on Cape Cod, enable the plant to exceed the stringent
1995 air quality standards established by the Massachusetts Department of
Environmental Protection and strengthen Canal's bargaining position as it
seeks to secure the lowest-cost fuel for its customers. Plant conversion and
pipeline construction are expected to be completed in 1996.
Electric service is furnished by Cambridge Electric Light Company (Cam-
bridge Electric) and Commonwealth Electric Company (Commonwealth Electric) at
retail to approximately 308,000 year-round and 49,000 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 232,000 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 20 customers in Cambridge and one
customer (Massachusetts General Hospital) in Boston. Steam is used for space
heating and other purposes. On August 17, 1993 COM/Energy Steam began
providing steam service to Genzyme Corporation (Genzyme), a biotechnology
company that is expected to become one of its largest customers. Genzyme's
steam need for 1995 is estimated to be 83.3 million pounds, which represents
approximately 5% of steam unit sales, for heating, air conditioning and
testing processes. In 1996, Genzyme's annual requirement is estimated to
reach approximately 175 million pounds based upon the expectation of
commercial manufacturing of a biotherapeutic product in 1995.
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 are several major educational institutions, including Harvard
University (Harvard) and the Massachusetts Institute of Technology (MIT).
MIT has completed construction of a 19 MW natural gas-fired cogeneration
facility which is expected to be in operation in 1995. MIT anticipates this
cogeneration facility will meet approximately 94% of its power, heating and
cooling requirements. Sales to MIT in 1994 accounted for approximately 1.8%
of total unit sales. MIT and Cambridge Electric were unsuccessful in attempts
to reach agreement on the cost to provide back up and supplemental service.
In March 1995, Cambridge Electric filed four rate schedules with the
Massachusetts Department of Public Utilities (DPU) which, in part, seek to
recover costs incurred to serve large customers such as MIT. These rates
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COMMONWEALTH ENERGY SYSTEM
include costs associated with providing standby, maintenance and supplemental
service on an ongoing basis as well as a customer transition charge to recover
other costs incurred to serve its largest customers should they discontinue
service with Cambridge Electric while remaining in Cambridge.
In March 1994, Cambridge Electric was successful in negotiating a seven-
year service agreement with another large customer, Harvard, whose sales in
1994 accounted for approximately 1.6% 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 DPU.
System companies own generating facilities with a capability totaling
1,046.5 MW at December 31, 1994. Including 560 MW provided by Canal Unit 1,
of which three-quarters (420 MW) is sold to neighboring utilities under long-
term contracts, and 292.0 MW provided by Canal Unit 2. Another 145.1 MW is
provided by various smaller system units. Of the 577.1 MW available to the
system, 77.6 MW are used principally for peaking purposes. A 3.52% ownership
interest in the Seabrook 1 nuclear power plant provides 40.5 MW of capability
to the system and Central Maine Power Company's Wyman Unit 4, an oil-fired
facility in which the system has a 1.4% joint-ownership interest, provides 8.9
MW. In 1991, Canal executed a transaction with Central Vermont Public Service
Corporation (CVPS) whereby 50 MW of Canal Unit 2 was exchanged for 25 MW each
of CVPS's entitlement in the Vermont Yankee nuclear power plant and the
Merrimack 2 coal-fired unit through October 1995. 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
hydro electric 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 67.9 MW. Purchase power arrangements were
also in place with the following natural gas-fired cogenerating units in
Massachusetts: 23 MW from Lowell Cogeneration Company Limited Partnership
(Lowell), 38 MW from Pepperell Power Associates Limited Partnership
(Pepperell), 53.0 MW from Northeast Energy Associates, 59.9 MW from Masspower
and 58.9 MW from Altresco Pittsfield. Additionally, the system receives 67.0
MW from the SEMASS waste-to-energy plant (which includes 20.8 MW from the
expansion unit which went on-line in May 1993); has entitlements totaling 24.4
MW through contracts with five (5) hydroelectric suppliers, including 20 MW
from Boott Hydropower, Inc., in Lowell, Massachusetts; and also receives 68.2
MW from a natural gas-fired independent power producer, Dartmouth Power
Associates.
The system anticipates providing for future peak load plus reserve
requirements through existing system generation, including purchasing
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COMMONWEALTH ENERGY SYSTEM
available capacity from neighboring utilities and/or non-utility generators.
Effective January 1, 1995, the system negotiated a restructured power sale
agreement with Lowell and terminated the Pepperell power sale agreement
through a buy-out arrangement, effective January 27, 1995.
In addition, the system has available 140.7 MW from four nuclear units
in which system distribution companies have life-of-the-unit contracts for
power. Information with respect to these units is as follows:
Connecticut Maine Vermont
Yankee Yankee Yankee Pilgrim
Year of Initial Operation 1968 1972 1972 1972
Contract Expiration Date 1998 2008 2012 2012
Equity Ownership (%) 4.50 4.00 2.50 -
Plant Entitlement (%) 4.50 3.59 2.25 11
Plant Capability (MW) 560.0 870.0 496.0 664.7
System Entitlement (MW) 25.2 31.2 11.2 73.1
On February 26, 1992, the Yankee Atomic Electric Company (Yankee) board
of directors agreed to permanently cease power operation of the Yankee nuclear
power plant in Rowe, Massachusetts. For additional information, refer to Note
2(e) of the Notes to Consolidated Financial Statements filed under Item 8 of
this report.
One of the operating nuclear units, located in Wiscasset, Maine and
operated by Maine Yankee Atomic Power Company, has been experiencing
degradation of its steam generator tubes, principally in the form of
circumferential cracking, which until early 1995 was believed to be limited to
a relatively small number of tubes. During a refueling and maintenance outage
that began in early February 1995, Maine Yankee, through the use of new
inspection methods, detected increased degradation of the tubes well above its
expectations. Maine Yankee is currently evaluating alternative courses of
action to remedy this situation, most of which could result in significant
capital expenditures and an extended outage period. At this time, Cambridge
Electric cannot predict what action will be needed to rectify the situation,
the costs to be incurred or the length of the outage. The Board of Directors
of Maine Yankee will be meeting in early April 1995 to consider various
options.
On October 1, 1992, Commonwealth Electric ceased power generation at
its 60 MW Cannon Street generating station located in New Bedford,
Massachusetts. During the past few years, the plant had been used primarily
to meet peak electric demand and as a backup unit for Commonwealth Electric
and the New England Power Pool (NEPOOL). A sharp decline in electric demand
brought about by the present economic slowdown was the key factor in
management's decision to close the plant. This decision was viewed as the
most cost-effective among several alternatives and leaves Commonwealth
Electric with the most flexibility for future capacity planning.
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.
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COMMONWEALTH ENERGY SYSTEM
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
requirement. 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 $13.8 million at December 31,
1994. In addition, Canal has an equity interest in Phase II which amounted to
$3.8 million in 1994 and $3.9 million in 1993.
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 NPCC. The system estimates that, during the next ten years,
reserve requirements so determined will be in the range of 23% to 29% 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 2(d) of Notes to Consolidated
Financial Statements filed under Item 8 of this report.
The system's 3.52% interest in the Seabrook nuclear power plant is
owned by Canal to provide for a portion of the capacity and energy needs of
Cambridge Electric and Commonwealth Electric. For additional information
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COMMONWEALTH ENERGY SYSTEM
concerning Seabrook 1, refer to Note 2(b) of Notes to Consolidated Financial
Statements filed under Item 8 of this report.
Electric Fuel Supply
(a) Oil
Imported residual oil is the fuel used in the generation of power in
system generating plants, producing approximately 24% of the system's total
energy requirement for 1994.
Effective July 1, 1993, Canal executed a twenty-two month contract with
Coastal Oil of New England, Inc. (Coastal) for the purchase of residual fuel
oil. The contract provides for delivery of a set percentage of Canal's fuel
requirement, the balance (a maximum of 20%) to be met by spot purchases or by
Coastal at the discretion of Canal. Through December 31, 1994, approximately
16% of Canal's total requirements have been met by lower-cost spot purchases.
Energy Supply and Credit Corporation (ESCO) operates Canal's oil
terminal and manages the purchase, receipt and payment of oil under assignment
of Canal's supply contracts to ESCO (Massachusetts), Inc. Oil in the
terminal's tanks is held in inventory by ESCO and delivered upon demand to
Canal's tanks.
Fuel oil storage facilities at the Canal site have a capacity of
1,199,000 barrels, representing 60 days of normal operation of the two units.
During 1994, ESCO maintained an average daily inventory of 575,000 barrels of
fuel oil which represents 30 days of normal operation of the two units. This
supply is maintained by tanker deliveries approximately every ten to fifteen
days.
Reference is made to Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations," for a discussion of the cost
of fuel oil.
(b) Nuclear Fuel Supply and Disposal
Approximately 25% of the system's total energy requirement for 1994 was
generated by nuclear plants. The nuclear fuel contract and inventory informa-
tion 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
generating 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 a monitored retrievable storage 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
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COMMONWEALTH ENERGY SYSTEM
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; however, 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.
Gas Supply
In April 1992, the Federal Energy Regulatory Commission (FERC) issued
Order No. 636 (Order 636) which became effective on November 1, 1993. The
order requires interstate pipelines to unbundle existing gas sales contracts
into separate components (gas sales, transportation and storage services) and
to provide transportation services that allow customers to receive the same
level and quality of service they had with the previous bundled contracts.
Prior to the implementation of Order 636 Commonwealth Gas purchased the
majority of its gas supplies from either Tennessee Gas Pipeline Company
(Tennessee) or Algonquin Gas Transmission Company (Algonquin), supplemented
with third-party firm gas purchases, storage services, and firm transportation
from various pipelines. Presently, Commonwealth Gas purchases only
transportation, storage, and balancing services from these pipelines (and
other upstream pipelines that bring gas from the supply wells to the final
transporting pipelines) and procures 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 small independent marketers to
major gas and oil companies. For additional information on Order 636, refer
to Note 2(g) of Notes to Financial Statements filed under Item 8 of this
report.
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. During 1994, over 98% of the gas utilized by Commonwealth Gas was
delivered by the interstate pipeline system, the remaining small quantity
(approximately 662,000 MMBTU) was delivered as liquid LNG from Distrigas of
Massachusetts.
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.
Commonwealth Gas is currently awaiting an order from the DPU.
Commonwealth Gas began transporting gas on its distribution system in
1990 for end-users. There are currently eleven customers using this transpor-
tation service, accounting for 2,208 BBTU (4.5%) of system throughput in 1994.
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Hopkinton LNG Facility
A portion of Commonwealth Gas' 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 a contract for LNG service with Hopkinton ex-
tending through 1996, thereafter renewable year to year with notice of
termination due five years in advance. Contract payments include a demand
charge sufficient to cover Hopkinton's fixed charges and an operating charge
which covers liquefaction and vaporization expenses. Commonwealth Gas
furnishes pipeline gas during the period April 15 to November 15 each year for
liquefaction and storage. As the need arises, LNG is vaporized and placed in
the distribution system of Commonwealth Gas.
Based upon information presently available regarding projected growth
in demand and estimates of availability of future supplies of pipeline gas,
Commonwealth Gas believes that its present sources of gas supply are adequate
to meet existing load and allow for future growth in sales.
Rates, Regulation and Legislation
Certain of the System's utility subsidiaries operate under the
jurisdiction of the 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.
(a) Most Recent Rate Case Proceedings
Electric
On May 28, 1993, the DPU issued an order increasing Cambridge
Electric's retail revenues by approximately $7.2 million, or 6.4%. The rates,
based on a June 30, 1992 test-year and effective June 1, 1993, provide an
overall return of 9.95%, including an equity return of 11% and represented
approximately 70% of the amount requested. The new rates reflect the costs
associated with postretirement benefits other than pensions which were
determined in accordance with Statement of Financial Accounting Standards No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions,"
adopted as of January 1, 1993. The DPU authorized full recovery of these
costs over a four-year phase-in period with carrying costs on the deferred
portion. The new base rates also reflect the roll-in of costs associated with
the Seabrook nuclear power plant which are billed to Cambridge Electric by
Canal. Previously these costs were recovered through Cambridge Electric's
Fuel Charge decimal.
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COMMONWEALTH ENERGY SYSTEM
On July 1, 1991, the DPU issued an order increasing Commonwealth Elec-
tric's retail electric revenues by $10.9 million, or 3.1%. The requested
increase was $17.3 million. The order, based on a June 30, 1990 test-year,
provided an overall return of 10.49%, including a return on equity of 12%.
Gas
On April 16, 1991, Commonwealth Gas requested a $27.7 million (11.3%)
revenue increase in a filing with the DPU using a test-year ended December 31,
1990. On September 16, 1991, the DPU approved a settlement of the revenue
requirements portion of the filing authorizing a $22.8 million increase in
annual revenues, approximately 82% of the original request. The agreement
included a return on equity, for accounting purposes, of 13%. The DPU later
ruled on the rate design portion of the request and new rates went into effect
on November 1, 1991.
In May 1994, Commonwealth Gas requested the DPU to change the backup
service charges under its firm transportation rate. Back up charges result
when Commonwealth Gas sells gas from its system supplies to a customer whose
off-system gas supply has failed or is temporarily unavailable for causes
beyond the customer's control. The change involved an upward indexing based
on changes in the gas supply demand costs occasioned by Order 636. On
December 22, 1994, the DPU approved Commonwealth Gas' requested change
effective January 1, 1995. This change, which has no effect on revenue,
results in a more equitable recovery of pipeline capacity costs between
Commonwealth Gas' total requirements and transportation customers.
(b) Wholesale Rate Proceedings
Cambridge Electric requires FERC approval to increase its wholesale
rates to the Town of Belmont, Massachusetts (Belmont), a "partial
requirements" customer since 1986. These rates include a fuel adjustment
clause which reflects changes in costs of fuels and purchased power used to
supply Belmont.
During March of 1993, Cambridge Electric and Belmont signed a net
requirements power supply agreement, the terms and conditions of which
required Belmont to pay for all costs except transmission fees which Cambridge
Electric and Belmont attempted to negotiate. The negotiations were not
successful and Cambridge Electric filed for approval of transmission rates
with the FERC on June 29, 1994. 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 and the proposed
transmission rates charged to Belmont. Cambridge Electric filed its case with
the FERC on October 25, 1994 and hearings are scheduled to begin during the
second quarter of 1995.
(c) 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.
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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 the
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
experience a revenue excess or shortfall which can have a significant impact
on net income. All other capacity and energy-related purchased power costs
are recovered through the Fuel Charge. Cambridge Electric and Commonwealth
Electric made a filing in late 1992 with the DPU seeking an alternative method
of recovery. This request was denied in a letter order issued on October 6,
1993. However, the companies were encouraged by the DPU's acknowledgement
that the issues presented warrant further consideration. The DPU encouraged
each company to continue to work with other interested parties, including the
Attorney General of Massachusetts, to reach a consensus solution on the issue
for future consideration. The companies have been involved in discussions
with interested parties in an effort to resolve this issue in a positive
fashion and hope to reach an agreement in the near future.
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 program costs. For
further information, refer to Management's Discussion and Analysis of
Financial Condition and Results of Operations filed under Item 7 of this
report.
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 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 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.
The DPU and the Massachusetts Energy Facilities Siting Council (the
Council) were merged in 1992. The Council is now a division of the DPU.
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 Council. To approve a long-range forecast, the Council must
find, among other things, that Commonwealth Gas plans for construction of new
gas manufacturing or storage facilities and certain high-pressure gas
pipelines are consistent with current health, environmental protection, and
resource use and development policies as adopted by the Commonwealth of
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<PAGE 13>
COMMONWEALTH ENERGY SYSTEM
Massachusetts. Commonwealth Gas filed a long-range forecast with the Council
on July 20, 1990 and updated aspects of the filing in March 1991. This
forecast was combined with the DPU review of the ANE contract. Both issues
are pending before the DPU.
(d) Gas Demand, Take-or-Pay Costs 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.
In June 1991, Tennessee filed a settlement with the FERC dealing with a
variety of contract restructuring issues, including the allocation of take-or-
pay costs to Tennessee's customers including Commonwealth Gas. This
comprehensive settlement was approved and implemented on July 1, 1992. As
part of the settlement, the allocation of take-or-pay costs was changed from a
deficiency basis to a contract demand basis which increased Commonwealth Gas'
allocation. There are still some small on-going amounts of take-or-pay costs
being collected by the pipeline, however, Tennessee has nearly reached the cap
of allowable collections under the settlement.
Algonquin made a series of filings with the FERC to recover from its
customers take-or-pay charges imposed on it by its upstream suppliers.
Algonquin billed Commonwealth Gas for gas supply inventory charges from Texas
Eastern and others through the Algonquin commodity rate. With the
implementation of Order 636, Algonquin allocated the remaining costs utilizing
a formula based on actual purchases for the twelve months prior to May 1,
1993. Commonwealth Gas' allocation was in excess of $5 million. Commonwealth
Gas successfully appealed Algonquin's allocation method to the FERC. The
change in allocation, combined with issues being settled in Algonquin's
current rate case will reduce Commonwealth Gas' allocated share to $2.5
million. In addition, a settlement was reached with Koch Gateway Pipeline
(formerly the United Gas Pipeline) whereby Commonwealth Gas received
approximately $2 million in refunds for take-or-pay costs allocated through
Texas Eastern and Algonquin since 1985. This amount is currently being
refunded to firm customers through the CGA.
Commonwealth Gas is collecting all contract restructuring costs from
its customers through the CGA as permitted by the DPU.
Competition
This past year, the system continued to develop and implement
strategies to deal with the increasingly competitive environment in our gas
and electric businesses. The inherently high cost of providing energy
services in the Northeast has placed the region at a competitive disadvan-
tageas more customers begin to explore alternative supply options. Many state
and federal government agencies are considering implementing 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 rate-making and in February
1995 opened an investigation into electric industry restructuring.
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COMMONWEALTH ENERGY SYSTEM
Actions by system companies in response to the new competitive
challenges have been well received by regulators, business groups and
customers. For a more detailed discussion of competition and the programs
currently in place within the system, refer to the "Competition" section of
Management's Discussion and Analysis of Financial Condition and Results of
Operation filed under Item 7 of this report.
Segment Information
System companies provide electric, gas and steam services to retail
customers in service territories located in central and eastern 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 and operation of rental properties and other investment
activities which do not presently contribute significantly to either revenues
or operating income.
Reference is made to additional industry segment information in Note 10
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 $41.8 million from 1995 through 1999 for the electric and gas
divisions.
For additional information concerning environmental issues including
those relating to former gas manufacturing sites, refer to the "Environmental
Matters" section of "Management's Discussion and Analysis of Financial Condi-
tion 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 2(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 2.2% to
2,169 in 1994 from 2,217 employees at year-end 1993. Of the current total,
1,282 (59%) are represented by various collective bargaining units. Existing
agreements are for varying periods and expire in 1995 and thereafter.
Employee relations have generally been satisfactory.
Item 2. Properties
The system's principal electric properties consist of Canal Unit 1, a
569 MW oil-fired steam electric generating unit, and its one-half ownership in
Canal Unit 2, a 580 MW oil-fired steam electric generating unit, both located
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<PAGE 15>
COMMONWEALTH ENERGY SYSTEM
at Canal Electric's facility in Sandwich, Massachusetts. Other electric
properties include an integrated system of distribution lines and substations
together with Commonwealth Electric's 60 MW steam electric generating station
located in New Bedford, Massachusetts which ceased operations in October 1992
and was abandoned in 1993.
Cambridge Electric has two steam electric generating stations with a
net capability of 76.5 MW located in Cambridge, Massachusetts. In addition,
the system has a 3.52% interest (40.5 MW of capacity) in Seabrook 1 and a 1.4%
or 8.9 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. 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, 1994, the electric transmission and distribution
system consisted of 5,790 pole miles of overhead lines, 4,192 cable miles of
underground line, 355 substations and 374,055 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 1994, the gas system included 2,761 miles of gas distribution
lines, 162,971 services and 239,302 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
The system is subject to legal claims and matters arising from its
course of business, including its participation in power contract arbitrations
as discussed in the "Power Contract Arbitrations" section of Management's
Discussion and Analysis of Financial Condition and Results of Operations filed
under Item 7 of this report.
Item 4. Submission of Matters to a Vote of Security Holders
None
<PAGE>
<PAGE 16>
COMMONWEALTH ENERGY SYSTEM
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, Boston 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.
1994 by Quarter
First Second Third Fourth
High $45 1/2 $43 3/4 $40 3/4 $38 3/4
Low 42 7/8 39 1/2 37 1/2 35 3/8
1993 by Quarter
First Second Third Fourth
High $48 7/8 $48 5/8 $50 1/8 $49 3/4
Low 40 1/2 43 3/8 46 3/4 43
(b) Number of Shareholders at December 31, 1994
15,081 shareholders
(c) Frequency and Amount of Dividends Declared in 1994 and 1993
1994 1993
Per Per
Share Share
Declaration Date Amount Declaration Date Amount
March 24, 1994 $ .75 March 25, 1993 $ .73
June 23, 1994 .75 June 24, 1993 .73
September 22, 1994 .75 September 23, 1993 .73
December 15, 1994 .75 December 16, 1993 .73
$3.00 $2.92
(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.
Item 6. Selected Financial Data
Information required by this item is incorporated herein by reference to
Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994
Financial Information dated March 31, 1995, page 58.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Information required by this item is incorporated herein by reference to
Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994
Financial Information dated March 31, 1995, pages 20 through 35.
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<PAGE 17>
COMMONWEALTH ENERGY SYSTEM
Item 8. Financial Statements and Supplementary Data
The following consolidated financial statements and supplementary data of
the System and its subsidiaries are incorporated herein by reference to
Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994
Financial Information dated March 31, 1995 on pages 35 through 58.
Proxy Page
Reference
Management's Report 35
Report of Independent Public Accountants 36
Consolidated Balance Sheets - At
December 31, 1994 and 1993 37/38
Consolidated Statements of Income - Years Ended
December 31, 1994, 1993 and 1992 39
Consolidated Statements of Cash Flows - Years Ended
December 31, 1994, 1993 and 1992 40
Consolidated Statements of Capitalization - At
December 31, 1994 and 1993 41
Consolidated Statements of Changes in Common
Shareholders' Investment and in Redeemable
Preferred Shares - Years Ended
December 31, 1994, 1993 and 1992 42
Notes to Consolidated Financial Statements 43/57
Quarterly Information pertaining to the results of
operations for the years ended December 31, 1994 and 1993 58
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure
None
<PAGE>
<PAGE 18>
COMMONWEALTH ENERGY SYSTEM
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 1995 Annual Meeting, Proxy Statement and 1994 Financial
Information dated March 31, 1995, pages 3-6.
b. Executive Officers of the Registrant:
Age at
December
Name of Officer Position and Business Experience 31, 1994
William G. Poist President, Chief Executive Officer and 61
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 43
the System and its subsidiary companies
effective March 1, 1993; Treasurer of System
subsidiary companies 1990; Assistant Treas-
urer of System subsidiary companies 1989.
Russell D. Wright President and Chief Operating Officer of 48
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.
Kenneth M. Margossian President and Chief Operating Officer of 46
Commonwealth Gas Company* and Hopkinton
LNG Corp.* effective September 1, 1991;
Vice President of Operations from 1988 to
1991; Vice President of Facilities Develop-
ment from 1987 to 1988; Vice President of
Human Resources and Administration of
Commonwealth Gas Company from 1985 to 1987.
*Subsidiary of the System.
<PAGE>
<PAGE 19>
COMMONWEALTH ENERGY SYSTEM
b. Executive officers of the Registrant (Continued):
Age at
December
Name of Officer Position and Business Experience 31, 1994
Michael P. Sullivan Vice President, Secretary, and 46
General Counsel of the System
and subsidiary companies (effective
June 1993); Vice President, Secretary,
and General Attorney of the System and
subsidiary companies since 1981.
John A. Whalen Comptroller of the System and subsidiary 47
companies since 1978.
The term of office for System officers expires May 4, 1995, 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 1995 Annual Meeting, Proxy Statement and 1994 Financial Informa-
tion dated March 31, 1995, pages 6-11.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this item is incorporated herein by reference to
the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Inform-
ation dated March 31, 1995, pages 3-6.
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by reference to
the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Inform-
ation dated March 31, 1995, pages 3-6.
<PAGE>
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM
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, as detailed on page 17 in Item 8 of this
Form 10-K, have been incorporated herein by reference to Exhibit A to the
Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial
Information dated March 31, 1995.
(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 42).
Schedule I - Investments in, Equity in Earnings of, and Dividends
Received from Related Parties - Years Ended December 31, 1994, 1993 and
1992 (pages 43-45).
Schedule II - Valuation and Qualifying Accounts - Years Ended December
31, 1994, 1993 and 1992 (page 46).
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 May 1, 1995.
(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.
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<PAGE 21>
COMMONWEALTH ENERGY SYSTEM
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 5, 1994 (Exhibit 1 to the
CES Form S-3 (September 1994), 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)
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)
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<PAGE 22>
COMMONWEALTH ENERGY SYSTEM
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).
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).
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<PAGE 23>
COMMONWEALTH ENERGY SYSTEM
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).
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).
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<PAGE 24>
COMMONWEALTH ENERGY SYSTEM
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).
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<PAGE 25>
COMMONWEALTH ENERGY SYSTEM
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 Interim Agreement to Preserve and Protect the Assets of and
Investment in the New Hampshire Nuclear Units dated April 27, 1984
(Exhibit 2 to the CEC Form 10-Q (June 1984), File No. 2-30057).
10.1.10 Resolutions proposed by Merrill Lynch Capital Markets and adopted
by the Joint-Owners of the Seabrook Nuclear Project regarding
Project financing, dated May 14, 1984 (Exhibit 1 to the CEC Form
10-Q (March 1984), File No. 2-30057).
10.1.11 Agreement for Seabrook Project Disbursing Agent establishing YAEC
as the disbursing agent under the Joint-Ownership Agreement, dated
May 23, 1984 (Exhibit 4 to the CEC Form 10-Q (June 1984), File No.
2-30057).
10.1.11.1 First Amendment to 10.1.11 as amended March 8, 1985 (Exhibit 2 to
the CEC Form 10-Q (March 1985), File No. 2-30057).
10.1.11.2 Second through Fifth Amendments to 10.1.11 as amended May 20, 1985,
June 18, 1985, January 2, 1986 and November 12, 1987, respectively
(Exhibit 4 to the CEC 1987 Form 10-K, File No. 2-30057).
<PAGE>
<PAGE 26>
COMMONWEALTH ENERGY SYSTEM
10.1.12 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).
10.1.13 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).
10.1.14 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).
10.1.15 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).
10.1.16 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).
10.1.17 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).
10.1.17.1 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).
10.1.18 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).
10.1.18.1 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).
10.1.18.2 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).
10.1.19 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).
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COMMONWEALTH ENERGY SYSTEM
10.1.20 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).
10.1.20.1 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).
10.1.20.2 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).
10.1.20.3 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).
10.1.20.4 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).
10.1.21 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).
10.1.21.1 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).
10.1.21.2 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).
10.1.22 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).
10.1.22.1 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).
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COMMONWEALTH ENERGY SYSTEM
10.1.23 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).
10.1.23.1 Power Purchase Agreement (Revised) between Weweantic Hydro Associ-
ates and Commonwealth Electric (CE) 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).
10.1.24 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE
for the purchase of available hydro-electric energy produced by a
facility located in Ware, Massachusetts, dated September 1, 1983
(Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.25 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).
10.1.25.1 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).
10.1.26 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).
10.1.26.1 Amendment No. 3 to 10.1.26 (Exhibit 2 to the CE Form 10-Q (June
1986), File No. 2-7749).
10.1.27 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).
10.1.28 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).
10.1.28.1 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).
10.1.29 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).
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<PAGE 29>
COMMONWEALTH ENERGY SYSTEM
10.1.30 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).
10.1.31 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).
10.1.32 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).
10.1.32.1 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).
10.1.32.2 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).
10.1.32.3 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).
10.1.32.4 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).
10.1.32.5 Eleventh Amendment to 10.1.32 as amended November 1, 1989 (Exhibit
4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.32.6 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).
10.1.33 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).
10.1.34 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).
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COMMONWEALTH ENERGY SYSTEM
10.1.35 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).
10.1.36 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).
10.1.36.1 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).
10.1.36.2 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).
10.1.37 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).
10.1.37.1 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).
10.1.37.2 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).
10.1.38 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).
10.1.38.1 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).
10.1.38.2 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).
10.1.39 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).
10.1.40 System Power Sales Agreement by and between CE, as seller, and
Central Vermont Public Service Corporation (CVPS), as buyer, dated
September 15, 1984 (Exhibit 2 to the CE Form 10-Q (September 1984),
File No. 2-7749).
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<PAGE 31>
COMMONWEALTH ENERGY SYSTEM
10.1.40.1 System Sales Agreement by CVPS, as seller, and CE, as buyer, dated
September 15, 1984 (Exhibit 9 to the CE 1984 Form 10-K, File No. 2-
7749).
10.1.40.2 System Sales and Exchange Agreement by and between CVPS and CE on
energy transactions, dated September 15, 1984 (Exhibit 10 to the CE
1984 Form 10-K, File No. 2-7749).
10.1.40.3 System Exchange Agreement by and between CE and CVPS for the
exchange of capacity and associated energy, dated September 3, 1985
(Exhibit 1 to the CE 1985 Form 10-K, File No. 2-7749).
10.1.40.4 Purchase Agreement by and between CEC and CVPS for the purchase of
capacity from CEC for the term March 1, 1991 to October 31, 1995,
dated March 1, 1991 (Exhibit 1 to CEC Form 10-Q (June 1991), File
No. 2-30057).
10.1.40.5 Power Sale Agreement by and between CEC and CVPS for the purchase
of 50 MW of capacity from CVPS's units (25 MW from Vermont Yankee
and 25 MW from Merrimack 2) for the term of March 1, 1991 to
October 31, 1995, dated March 1, 1991 (Exhibit 2 to CEC Form 10-Q
(June 1991), File No. 2-30057).
10.1.41 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).
10.1.41.1 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).
10.1.41.2 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).
10.1.42 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).
10.1.43 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).
10.1.44 Power Purchase Agreement with Respect to South Meadow Unit Nos. 11,
12, 13, and 14 of the NU system company of CL&P (seller) and CE
(buyer), dated November 1, 1985 (Exhibit 1 to the CE Form 10-Q
(June 1986), File No. 2-7749).
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COMMONWEALTH ENERGY SYSTEM
10.1.45 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).
10.1.45.1 Power Sales Agreement to 10.1.45 for all capacity and related
energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985
Form 10-K, File No. 2-7749).
10.1.45.2 Amendment to 10.1.45 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).
10.1.45.3 Amendment to 10.1.45 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).
10.1.46 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).
10.1.47 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).
10.1.48 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).
10.1.48.1 First Amendment to 10.1.48 as amended August 15, 1988 (Exhibit 1 to
the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.48.2 Second Amendment to 10.1.48 as amended January 1, 1989 (Exhibit 2
to the CE 1988 Form 10-K, File No. 2-7749).
10.1.48.3 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).
10.1.48.4 Amendment to 10.1.48.3 as amended January 1, 1989 (Exhibit 3 to the
CE 1988 Form 10-K, File No. 2-7749).
10.1.49 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).
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COMMONWEALTH ENERGY SYSTEM
10.1.49.1 First Amendment, dated November 24, 1992, to Exchange of Power
Agreement between Montaup Electric Company and Commonwealth
Electric Company (CE) dated January 17, 1991 (Exhibit 1 to CE Form
10-Q (March 1993) File No. 2-7749).
10.1.50 System Power Exchange Agreement by and between Commonwealth
Electric Company (CE) and New England Power Company dated January
16, 1992 (Exhibit 1 to CE Form 10-Q (March 1992), File No. 2-7749).
10.1.50.1 First Amendment, dated September 8, 1992, to System Power Exchange
Agreement by and between Commonwealth Electric Company (CE) and New
England Power Company dated January 16, 1992 (Exhibit 1 to CE Form
10-Q (September 1992), File No. 2-7749).
10.1.50.2 Second Amendment, dated March 2, 1993, to System Power Exchange
Agreement 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).
10.1.51 Power Purchase Agreement and First Amendment, dated September 5,
1989 and August 3, 1990, respectively, by and between Commonwealth
Electric (CE) (buyer) and Dartmouth Power Associates Limited
Partnership (seller), whereby buyer will purchase all of the energy
(67.6 MW) produced by a single gas turbine unit (Exhibit 1 to the
CE Form 10-Q (June 1992), File No. 2-7749).
10.1.52 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).
10.1.53 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).
10.1.54 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).
10.1.54.1 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).
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COMMONWEALTH ENERGY SYSTEM
10.1.54.2 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).
10.2 Natural gas purchase contracts.
10.2.2 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).
10.2.3 Service Agreement Applicable to Rate Schedule F-2 between AGT and
CG for the purchase of certain quantities of natural gas acquired
by AGT from CGS, dated April 11, 1985 (Exhibit 2 to the CG Form 10-
Q (March 1987), File No. 2-1647).
10.2.4 Service Agreement Applicable to Rate Schedule F-3 between AGT and
CG for the purchase of certain quantities of natural gas acquired
by AGT from National Fuel Gas Supply Corporation, dated April 11,
1985 (Exhibit 3 to the CG Form 10-Q (March 1987), File No. 1-1647).
10.2.5 Service Agreement Applicable to Rate Schedule F-4 between AGT and
CG for the purchase of certain quantities of natural gas acquired
by AGT from Texas Eastern Transmission Company, dated December 26,
1985 (Exhibit 4 to the CG Form 10-Q (March 1987), File No. 2-1647).
10.2.6 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).
10.2.6.1 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).
10.2.6.2 Amendments to 10.2.6 and 10.2.6.1 as amended December 1, 1976
(Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647).
10.2.6.3 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).
10.2.6.4 Supplement 1 to 10.2.6.1 dated September 14, 1977 (Exhibit 5(c)6 to
the CG Form S-16 (June 1979), File No. 2-64731).
10.2.6.5 Supplement 2 to 10.2.6.1 dated September 30, 1982 (Refiled as
Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647).
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COMMONWEALTH ENERGY SYSTEM
10.2.6.6 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).
10.2.7 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).
10.2.7.1 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).
10.2.8 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).
10.2.9 Agency Agreement for Certain Transportation Arrangements by and
between CG and Citizens Resources Corporation (CRC) whereby CRC
arranges for a third party transportation of natural gas acquired
by CG, dated April 14, 1986 (Exhibit 1 to the CG Form 10-Q (June
1986), File No. 2-1647).
10.2.9.1 Natural Gas Sales Agreement between CG and CRC, dated April 14,
1986 (Exhibit 2 to CG Form 10-Q (June 1986), File No. 2-1647).
10.2.10 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).
10.2.11 Agency Agreement for Certain Transportation Arrangements, dated
June 18, 1985 and Gas Purchase and Sales Agreement dated August 6,
1985 by and between CG and Tenngasco Corporation and other related
entities (Exhibit 4 to the CG Form 10-Q (June 1986), File No.
2-1647).
10.2.12 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).
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COMMONWEALTH ENERGY SYSTEM
10.2.13 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).
10.2.14 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).
10.2.15 Gas Sales Agreement by and between Texas Eastern Gas Trading
Company and CG providing for the sale of certain quantities of
natural gas to CG, dated May 15, 1986 (Exhibit 7 to the CG Form 10-
Q (June 1986), File No. 2-1647).
10.2.16 Service Agreement applicable to Rate Schedule TS-3 between TET and
CG for Firm natural gas service, dated April 16, 1987 (Exhibit 1 to
the CG Form 10-Q (June 1987), File No. 2-1647).
10.2.17 Natural Gas Sales Agreement between Summit Pipeline and Producing
Company and CG, dated April 16, 1987 (Exhibit 2 to the CG Form
10-Q (June 1987), File No. 2-1647).
10.2.18 Natural Gas Sales Agreement between Natural Gas Supply Company and
CG, dated May 12, 1987 (Exhibit 3 to the CG Form 10-Q (June 1987),
File No. 2-1647).
10.2.19 Natural Gas Sales Agreement between Stellar Gas Company and CG,
dated April 15, 1988 (Exhibit 1 to the CG Form 10-Q (March 1988),
File No. 2-1647).
10.2.20 Natural Gas Sales Agreement between Amalgamated Gas Pipeline
Company and CG dated April 5, 1988 (Exhibit 1 to the CG Form 10-Q
(June 1988), File No. 2-1647).
10.2.21 Natural Gas Sales Agreement between Gulf Ohio Pipeline Corporation
and CG dated May 18, 1988 (Exhibit 2 to the CG Form 10-Q (June
1988), File No. 2-1647).
10.2.22 Natural Gas Sales Agreement between Phillips Petroleum Company and
CG dated May 18, 1988 (Exhibit 3 to the CG Form 10-Q (June 1988),
File No. 2-1647).
10.2.23 Natural Gas Sales Agreement between TXO Gas Marketing Corp. and CG
dated April 25, 1988 (Exhibit 1 to the CG 1988 Form 10-K, File No.
2-1647).
10.2.24 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).
<PAGE>
<PAGE 37>
COMMONWEALTH ENERGY SYSTEM
10.2.25 Natural Gas Sales Agreement between Enermark Gas Gathering
Corporation and CG dated January 6, 1989 (Exhibit 3 to the CG 1988
Form 10-K, File No. 2-1647).
10.2.26 Gas Sales Agreement between BP Gas Inc. (seller) and CG (purchaser)
for the purchase of spot market gas, dated March 31, 1989 with a
contract term of at least one year (Exhibit 1 to the CG Form 10-Q
(March 1989), File No. 2-1647).
10.2.27 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).
10.2.28 Gas Sales Agreement between Catamount Natural Gas, Inc. (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).
10.2.29 Gas Sales Agreement between Transco Energy Marketing Company
(seller) and CG (purchaser) for the purchase of spot market gas,
dated March 1, 1989, with a contract term of at least one year
(Exhibit 2 to the CG Form 10-Q (June 1989), File No. 2-1647).
10.2.30 Gas Sales Agreement between V.H.C. Gas Systems, L.P. (seller) and
CG (purchaser) for the purchase of spot market gas, dated June 2,
1989, with a contract term of at least one year (Exhibit 3 to the
CG Form 10-Q (June 1989), File No. 2-1647).
10.2.31 Gas Sales Agreement between End-Users Supply System (seller) and CG
(purchaser) for the purchase of spot market gas, dated June 29,
1989, with a contract term of at least one year (Exhibit 1 to the
CG Form 10-Q (September 1989), File No. 2-1647).
10.2.32 Gas Sales Agreement between Entrade Corporation (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 2 to the
CG Form 10-Q (September 1989), File No. 2-1647).
10.2.33 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).
10.2.34 Gas Sales Agreement between Mobil Natural Gas Inc. (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).
10.2.35 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).
<PAGE>
<PAGE 38>
COMMONWEALTH ENERGY SYSTEM
10.2.35.1 Amendment, dated August 28, 1989, to 10.2.35 dated May 23, 1989
(Exhibit 5 to the CG Form 10-Q (September 1989), File No. 2-1647).
10.2.36 Gas Sales Agreement between PSI, Inc. (seller) and CG (purchaser)
for the purchase of spot market gas, dated September 25. 1989, with
a term of at least one year (Exhibit 1 to the CG 1989 Form 10-K,
File No. 2-1647).
10.2.37 Gas Sales Agreement between Hadson Gas Systems (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).
10.2.38 Gas Sales Agreement between Odeco Oil Company (seller) and CG
(purchaser) for the purchase of firm gas, dated August 15, 1990,
with a contract term of at least five years (Exhibit 2 to the CG
Form 10-Q (September 1990), File No. 2-1647).
10.2.39 Operating Agreement between AGT, CG and Distrigas of Massachusetts
Corporation in connection with the deliveries of regasified
liquified natural gas into the Algonquin J-system, dated August 1,
1990 (Exhibit 3 to the CG Form 10-Q (September 1990), File No.2-
1647).
10.2.40 Gas Sales Agreement between TEX/CON Marketing Gas Company (seller)
and CG (purchaser) for the purchase of firm gas, dated September
12, 1990, with a contract term of five years (Exhibit 3 to the CG
1990 Form 10-K, File No. 2-1647).
10.2.41 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).
10.2.42 Transportation Assignment Agreement between AGT and CG regarding
Rate Schedule ATAP Agreement No. 9020016 which provides for the
assignment, on an interruptible basis, of firm service rights on
TET's system under Rate Schedule FT-1, dated January 3, 1990, for a
term ending October 31, 1999 (Exhibit 4 to the CG 1991 Form 10-K,
File No. 2-1647).
10.2.43 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).
10.2.44 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).
10.2.45 Transportation Assignment Agreement between AFT and CG regarding
Rate Schedule ATAP Agreement No. 90202, which provides for the
assignment, on a firm basis, of firm service rights on TET's system
under Rate Schedule FT-1 dated November 1, 1990 (Exhibit 7 to the
CG 1991 Form 10-K, File No. 2-1647).
<PAGE>
<PAGE 39>
COMMONWEALTH ENERGY SYSTEM
10.2.46 Gas Sales Agreement between TGP and CG under TGP's CD-6 Rate
Schedules dated September 1, 1991 (Exhibit 8 to the CG 1991 Form
10-K, File No. 2-1647).
10.2.47 Transportation Agreement between TGP and CG dated September 1, 1991
(Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647).
10.2.48 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).
10.2.49 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>
<PAGE 40>
COMMONWEALTH ENERGY SYSTEM
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>
<PAGE 41>
COMMONWEALTH ENERGY SYSTEM
10.3.8 Stock Purchase Agreement by and among Texas Eastern Corporation
(purchaser) and Eastern Gas and Fuel Associates, Commonwealth
Energy System and Providence Energy Corporation (sellers) for the
purchase and sale of ownership interests in Algonquin Energy,
Inc., dated June 10, 1986 (Exhibit 1 to the CEC Form 10-Q (June
1986), File No. 1-7316).
Exhibit 21. Subsidiaries of the Registrant
Incorporated by reference to Exhibit 2 (page 101) to the System's
1988 Annual Report on Form 10-K, File No. 1-7316.
Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security
Holders.
Filed herewith as Exhibit 1 is the Notice of 1995 Annual Meeting,
Proxy Statement and 1994 Financial Information dated March 31,
1995.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 2 is the Financial Data Schedule 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, 1994.
<PAGE>
<PAGE 42>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Commonwealth Energy System:
We have audited, in accordance with generally accepted auditing standards,
the consolidated financial statements of Commonwealth Energy System appearing
in Exhibit A to the proxy statement for the 1995 annual meeting of
shareholders, incorporated by reference in this Form 10-K, and have issued our
report thereon dated February 21, 1995. 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
Arthur Andersen LLP
Boston, Massachusetts
February 21, 1995
<PAGE>
<PAGE 43>
<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>
<PAGE 44>
<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, 1993
(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 $ 42 774 $ 3 101 $ - $ 2 201 346 600 $ 43 674 $ -
COM/Energy Steam Company 25 500 3 113 1 703 - 1 495 25 500 3 321 830
Canal Electric Company 1 523 200 110 899 15 122 - 31 469 1 523 200 94 552 -
Commonwealth Gas Company 2 407 000 88 157 16 299 18 000 15 452 2 857 000 107 004 355
Darvel Realty Trust 26 1 127 (368) - - 26 759 -
COM/Energy Freetown Realty 1 (16 565) (2 267) - - 1 (18 832) 26 480
COM/Energy Research Park Realty 1 885 347 - 187 1 1 045 -
COM/Energy Cambridge Realty 1 157 (8) - 75 1 74 -
COM/Energy Acushnet Realty 1 560 69 - 71 1 558 -
COM/Energy Services Company 3 250 337 49 - 49 3 250 337 -
Commonwealth Electric Company 1 606 472 128 093 12 078 35 000 11 842 2 043 972 163 329 -
Hopkinton LNG Corp. 5 000 4 931 548 - 1 460 5 000 4 019 190
$364 468 $46 673 $53 000 $64 301 $399 840 $27 855
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52 454 $ 9 690 $ 1 069 $ - $ 1 099 52 454 $ 9 660
Hydro-Quebec Phase II 137 442 4 170 573 - 882 137 442 3 861
Other Investments - 28 - - - - 28
$ 13 888 $ 1 642 $ - $ 1 981 $ 13 549
<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>
<PAGE 45>
<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, 1992
(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 304 600 $ 37 945 $ 64 $5 250 $ 485 346 600 $ 42 774 $ -
COM/Energy Steam Company 25 500 3 106 1 272 - 1 265 25 500 3 113 -
Canal Electric Company 1 523 200 109 069 19 347 - 17 517 1 523 200 110 899 2 840
Commonwealth Gas Company 2 407 000 82 930 14 855 - 9 628 2 407 000 88 157 5 780
Darvel Realty Trust 26 1 557 45 - 475 26 1 127 -
COM/Energy Freetown Realty 1 (15 317) (1 248) - - 1 (16 565) 25 262
COM/Energy Research Park Realty 1 1 240 380 - 735 1 885 -
COM/Energy Cambridge Realty 1 82 75 - - 1 157 -
COM/Energy Acushnet Realty 1 558 72 - 70 1 560 -
COM/Energy Services Company 3 250 337 49 - 49 3 250 337 -
Commonwealth Electric Company 1 606 472 127 362 9 004 - 8 273 1 606 472 128 093 8 445
Hopkinton LNG Corp. 5 000 4 295 1 322 - 686 5 000 4 931 70
$353 164 $45 237 $5 250 $39 183 $364 468 $42 397
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52 454 $ 9 629 $ 1 397 $ - $ 1 336 52 454 $ 9 690
Hydro-Quebec Phase II 137 442 4 372 619 - 821 137 442 4 170
Other Investments - 28 - - - - 28
$ 14 029 $ 2 016 $ - $ 2 157 $ 13 888
<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>
<PAGE 46>
SCHEDULE II
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
(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, 1994
Allowance for
Doubtful Accounts $7 761 $ 9 396 $2 138 $11 339 $7 956
Year Ended December 31, 1993
Allowance for
Doubtful Accounts $6 861 $ 9 468 $2 142 $10 710 $7 761
Year Ended December 31, 1992
Allowance for
Doubtful Accounts $5 233 $12 082 $1 918 $12 372 $6 861
<PAGE>
<PAGE 47>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1994
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 23, 1995
William G. Poist,
President and Chief Executive Officer
Principal Financial Officer:
JAMES D. RAPPOLI March 23, 1995
James D. Rappoli,
Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 23, 1995
John A. Whalen,
Comptroller
A majority of the Board of Trustees:
SINCLAIR WEEKS, JR. March 23, 1995
Sinclair Weeks, Jr., Chairman of
the Board
SHELDON A. BUCKLER March 23, 1995
Sheldon A. Buckler, Trustee
PETER H. CRESSY March 23, 1995
Peter H. Cressy, Trustee
HENRY DORMITZER March 23, 1995
Henry Dormitzer, Trustee
<PAGE>
<PAGE 48>
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1994
SIGNATURES
(Continued)
B. L. FRANCIS March 23, 1995
Betty L. Francis, Trustee
FRANKLIN M. HUNDLEY March 23, 1995
Franklin M. Hundley, Trustee
WILLIAM J. O'BRIEN, March 23, 1995
William J. O'Brien, Trustee
WILLIAM G. POIST March 23, 1995
William G. Poist, Trustee
March , 1995
Gerald L. Wilson, Trustee
<PAGE>
<PAGE 49>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference in this Form 10-K of our report dated February 21, 1995 included
in Exhibit A to the proxy statement for the 1995 annual meeting of
shareholders and the incorporation of our reports included and incorporated by
reference 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, 1994 or performed any audit procedures
subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
Boston, Massachusetts
March 30, 1995
<PAGE 1>
EXHIBIT 1
Commonwealth
Energy System
Notice of 1995
Annual Meeting,
Proxy Statement
and 1994 Financial
Information
Please sign and return your
proxy promptly
<PAGE>
<PAGE 2>
COMMONWEALTH ENERGY SYSTEM
Cambridge, Massachusetts
Notice of Annual Meeting of Shareholders
May 4, 1995
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 4, 1995, at 10:30 o'clock A.M., Eastern Daylight Time, for the following
purposes:
1. To elect three Trustees to hold office for a three-year term and
until the election and qualification of their respective
successors.
2. To take action on a proposal by the Board of Trustees to amend
Section 6 of the System's Declaration of Trust, as amended, to
revise the geographic residency requirement for Trustees.
3. To consider and vote upon a shareholder proposal, if presented at
the meeting, as described herein.
4. 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, 1995
are entitled to notice of, and to vote at, the meeting.
By order of the Trustees,
MICHAEL P. SULLIVAN
Michael P. Sullivan
Vice President, Secretary
and General Counsel
March 31, 1995
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 4, 1995, 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 will 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 31, 1995.
FINANCIAL STATEMENTS
The audited financial statements of Commonwealth Energy System and
Subsidiary Companies, which include comparative Balance Sheets as of December
31, 1994 and 1993, Statements of Income and Statements of Cash Flows for the
three years ended December 31, 1994 and the Report of Independent Public
Accountants, are included in Exhibit A of this Proxy Statement.
VOTING SECURITIES
Each Common Share is entitled to one vote. Only Shareholders of record
at the close of business on March 17, 1995 are qualified to vote at the
meeting. There were outstanding as of the record date 10,585,909 Common
Shares.
The Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies owned beneficially 1,711,590 Common Shares representing 16.2% of the
outstanding Common Shares as of February 1, 1995. Members of the Plan are
entitled to give voting instructions with respect to their interests.
OWNERSHIP BY MANAGEMENT OF VOTING SECURITIES
The following table shows the beneficial ownership, reported to the
System as of February 1, 1995 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 5,309 0.1%
Russell D. Wright 4,153 0.1%
Kenneth M. Margossian 3,025 0.1%
James D. Rappoli 1,167 0.1%
Leonard R. Devanna 1,636 0.1%
All Trustees and Executive Officers
as a group (14 persons) 25,642 0.2%
<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:
Sheldon A. Buckler
Betty L. Francis
Michael C. Ruettgers
Of the three nominees, Dr. Buckler and Ms. Francis are presently
Trustees. Mr. Ruettgers was nominated by the Board on February 23, 1995 to
fill a vacancy which will be occasioned by the retirement of Mr. Sinclair
Weeks, who is retiring from the Board at the conclusion of his term effective
May 4, 1995.
Although it is not contemplated that any of the three (3) nominees will
be unable to serve, in the event a vacancy in the list of the System's
nominees is occasioned by death or other unexpected occurrence, your proxy
will be voted for the election of a nominee acceptable to the remaining
Trustees.
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a February 1,
Name, Principal Occupation and Term of Office Trustee Age 1995
(B) SHELDON A. BUCKLER, formerly Vice Chairman
(C) of the Board and Director, Polaroid
(E) Corporation, Cambridge, Massachusetts
(Manufacturer of photographic equipment
and supplies); Director, Lord Corp.;
Aseco Corp.; Nashua Corporation; Parlex
Corp.; Spectrum Information Technologies,
Inc.; and Speech Systems, Inc.
TERM EXPIRES IN 1995 (NOMINEE).......... (1991) 63 1,069
(A) PETER H. CRESSY, Chancellor, University of
Massachusetts Dartmouth, North Dartmouth,
Massachusetts
TERM EXPIRES IN 1996 ................... (1994) 53 100
<PAGE>
<PAGE 5>
INFORMATION CONCERNING NOMINEES AND TRUSTEES
Common Shares
Beneficially
Year First Owned as of
Became a February 1,
Name, Principal Occupation and Term of Office Trustee Age 1995
(B) HENRY DORMITZER, formerly Executive Vice
(D) President, Wyman-Gordon Company, Worcester,
Massachusetts (Producer of forgings for
aerospace and transportation industries)
TERM EXPIRES IN 1997 ................... (1985) 60 700
(A) BETTY L. FRANCIS, Executive Vice President
and Chief Financial Officer, BancBoston
Mortgage Corporation, Jacksonville, Florida
TERM EXPIRES IN 1995 (NOMINEE).......... (1991) 48 100
(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 ................... (1985) 60 2,293
(A) WILLIAM J. O'BRIEN, President, William J.
O'Brien, Inc., Southborough, Massachusetts
(management consulting)
TERM EXPIRES IN 1996................... (1994) 62 1,100
WILLIAM G. POIST, President and Chief
Executive Officer of Commonwealth Energy
System and Chairman, Chief Executive Officer
and a Director of its principal subsidiary
companies
TERM EXPIRES IN 1996 .................. (1992) 61 5,309
MICHAEL C. RUETTGERS, President, Chief
Executive Officer and Director, EMC
Corporation, Hopkinton, Massachusetts
(data storage technology); Director,
Keane, Inc. and Cross Comm Corporation
(NOMINEE).............................. - 52 -
(B) GERALD L. WILSON, Vannevar Bush Professor of
(D) Engineering, Massachusetts Institute of
(E) Technology, Cambridge, Massachusetts;
Director, Analogic Corp.
TERM EXPIRES IN 1997 ................... (1985) 55 464
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 Ms. Francis, who served in various executive capacities at
the Boston Five Cents Savings Bank from 1986 to 1990; 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; and Mr. O'Brien, who served as President and Chief
Executive Officer of The Hanover Insurance Company from 1979 to 1992.
During 1994, fees of $669,427 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.
<PAGE>
<PAGE 6>
Each Trustee, including nominees, owned beneficially less than one-third
of one percent of 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.
COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1994
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 1994 exceeded $100,000.
<TABLE>
SUMMARY COMPENSATION TABLE
<CAPTION>
Long-Term Compensation (3)
Annual Compensation Awards Payouts
Long-
Options Term
Other /Stock Incen- All
Annual Restr- Apprec- tive Other
Compen- icted iation Plan Compen-
Name and Salary sation Stock Rights (LTIP) sation
Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
William G. Poist 1994 $320,000 $98,721 - - - - $12,804
President and Chief 1993 291,888 78,031 - - - - 11,604
Executive Officer of 1992 270,000 65,121 - - - - 10,800
the System and Chair-
man and Chief Exec-
utive Officer of its
principal subsidiary
companies
Russell D. Wright 1994 $215,897 $60,964 - - - - $ 8,400
President and Chief 1993 195,000 53,814 - - - - 7,704
Operating Officer 1992 167,140 40,665 - - - - 6,884
of Cambridge
Electric Light
Company, Canal
Electric Company,
COM/Energy Steam
Company and
Commonwealth
Electric Company
Kenneth M. Margossian 1994 $179,917 $52,005 - - - - $ 7,140
President and 1993 165,000 47,256 - - - - 6,564
Chief Operating 1992 153,833 38,733 - - - - 6,120
Officer of Common-
wealth Gas Company
and Hopkinton LNG Corp.
</TABLE>
<PAGE>
<PAGE 7>
<TABLE>
SUMMARY COMPENSATION TABLE (CONT'D)
<CAPTION>
Long-Term Compensation (3)
Annual Compensation Awards Payouts
Long-
Options Term
Other /Stock Incen- All
Annual Restr- Apprec- tive Other
Compen- icted iation Plan Compen-
Name and Salary sation Stock Rights (LTIP) sation
Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
James D. Rappoli 1994 $151,686 $43,196 - - - - $ 5,880
Financial Vice 1993 130,333 36,184 - - - - 5,082
President and 1992 93,917 21,931 - - - - 3,732
Treasurer of the
System and its
subsidiary companies
Leonard R. Devanna 1994 $142,166 $41,745 - - - - $ 5,912
Vice President-New 1993 133,333 37,542 - - - - 6,603
Business Development 1992 124,167 29,939 - - - - 4,899
of COM/Energy
Services Company
</TABLE>
--------------------
(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
1994, there were no such perquisites, earnings, reimbursements or
discounts paid or made.
(3) In 1994, the System did not provide to its employees, including
Executive Officers, any payments or awards in the form of restricted
stock, stock options, stock appreciation rights, long-term incentive
plan payouts or other forms of long-term compensation.
(4) The amounts in this column represent the aggregate contributions by the
System and certain subsidiary companies during 1994 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 of
1986. The Plan was established to provide an additional benefit to any
participant in the Employees Savings Plan whose benefit under the 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, $6,162, $8,400, $4,622, $2,311 and $2,887
represent the contributions made on behalf of Messrs. Poist, Wright,
<PAGE>
<PAGE 8>
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 1994 equalled $6,642, $0, $2,518, $3,569 and
$4,139, respectively.
<PAGE>
<PAGE 9>
PENSION PLAN TABLE
The following table shows annual retirement benefits payable to
employees, including Executive Officers, upon retirement at age 65, in various
compensation and years of service classifications, assuming the election of a
retirement allowance payable as a life annuity from the Pension Plan for
Employees of Commonwealth Energy System and Subsidiary Companies and the
Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy
System and Subsidiary Companies, as of December 31, 1994.
<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 .... $15,818 $23,728 $ 31,637 $ 39,546 $ 47,455 $ 51,614
120,000 .... 21,318 31,978 42,637 53,296 64,955 69,614
150,000 .... 26,818 40,228 53,637 67,046 80,455 87,614
180,000 .... 32,318 48,478 64,637 80,796 96,955 105,614
210,000 .... 37,818 56,728 75,637 94,546 113,455 123,614
240,000 .... 43,318 64,978 86,637 108,296 129,955 141,614
270,000 .... 48,818 73,228 97,637 122,046 146,455 159,614
300,000 .... 54,318 81,478 108,637 135,796 162,955 177,614
330,000 .... 59,818 89,728 119,637 149,546 179,455 195,614
360,000 .... 65,318 97,978 130,637 163,296 195,955 213,614
-------------
<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 1994, 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 $118,800.
</TABLE>
The Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies 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 Plan formula to realize the maximum retirement
benefit applicable to his or her employment history. Both of the Plan
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 30,
27, 25, 20 and 13 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's three highest consecutive January 1 base salaries during the
ten year period preceding the executive'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 salary; or (ii)
fifty percent of monthly base salary for one hundred and eighty months. The
supplemental retirement benefit provides that an Executive Officer may retire
after the attainment of age fifty-five and completion of ten years of service.
Normal retirement at age sixty-five provides an annual payment equal to
<PAGE>
<PAGE 10>
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 the employment of the Executive Officer shall terminate for any
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.
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Executive Compensation Committee of the Board of Trustees has
furnished the following report on executive compensation for 1994:
The Chief Executive Officer's base salary compensation is determined by
review of comparable utility salary data and evaluation of certain reference
criteria. The Executive Compensation Committee (the "Committee") reviews
compensation comparisons prepared by an independent consultant for roles
comparable in scope to the Chief Executive Officer's and other executives. In
addition, the Committee reviews market compensation data provided by the
System's human resources department, selected utility proxy material, 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 are 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's utility sample.
The Chief Executive Officer's base salary target (i.e., control point)
is designed to match the market median for the utility reference group. The
Committee adjusts the Chief Executive Officer's salary in relation to the
salary range target on a subjective basis through evaluation of the same
objective criteria used to determine the Chief Executive Officer's annual
incentive award and individual goals as set forth below.
The Chief Executive Officer's award for 1994 pursuant to the System's
Annual Incentive Plan, as hereinafter described, 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 1994, the System
criteria forming the goals and objectives applicable to the Annual Incentive
Plan were: 1) meeting pre-established targets comparing System actual net
income to budgeted net income for 1994; 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 19 utility companies chosen by the
System's 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 1994 net income of $48.97 million exceeded targeted net income of
$41.20 million by 18.9%, resulting in a maximum award. The goal established
for cost control was for operating and maintenance expenses in 1994 to be
below the approved budgeted amounts. This goal was achieved by the System
having reduced actual operation and maintenance expenses to 5.3% below
established budgets, resulting in a maximum award for having exceeded the 5%
below budget maximum target. The goal of maintaining operating and
maintenance expenses per customer within the top 50% of the 19 company
industry peer group was exceeded, as the System was rated the seventh most
effective of the 19 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 95.8% achieved.
<PAGE>
<PAGE 11>
The individual goals of the Chief Executive Officer for 1994 under the
Annual Incentive Plan included: developing a System business development
plan, overseeing the formation of a key performance factor metering system,
and improving electric operations' overall customer favorability as measured
by customer surveys. The Chief Executive Officer's performance relative to
achieving individual goals was rated as 90% achieved, resulting in an
aggregate performance rating of 94% achievement.
The System's Long Term Incentive Plan, approved by shareholders in 1994,
measures performance and provides the potential for awards of Common Shares
over a three-year Plan Period. The first year of the initial Plan Period
established under that Plan was 1994, and as a result no award was made under
the Plan for 1994.
With respect to other Executive Officers, the Chief Executive Officer,
in conjunction with the System's human resources staff, 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
Executive Officer's performance of goals and 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 under the Annual Incentive Plan to receive annual variable incentive
compensation of up to a maximum of 30% of annual base salary. In 1994, 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 Plan participants included various
financial and operating performance standards, such as management of outside
legal services, the stabilization of electric customers' costs of purchased
power, and the maintenance of individual department total annual expenses at
amounts not exceeding approved budgets.
THE EXECUTIVE COMPENSATION COMMITTEE
Henry Dormitzer, Chairperson
Sheldon A. Buckler
Gerald L. Wilson
<PAGE>
<PAGE 12>
COMPARATIVE TOTAL SHAREHOLDER RETURN
Set forth below is a line graph comparing 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
93 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 12/31/94)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1990-1994) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1989 1990 1991 1992 1993 1994
COM/Energy $100.00 $ 94.55 $121.82 $142.53 $164.76 $139.27
S&P 500 100.00 96.83 126.41 136.26 150.00 151.73
Peer Group 100.00 101.47 131.43 140.92 156.53 137.46
Assumes $100 invested at the close of trading on the last trading day of
1989 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. Ohio Edison Co.
Central Vermont Public Service Corp. Oklahoma Gas & Electric Co.
CILCORP Inc. Orange and Rockland Utilities, Inc.
CINergy Corp. Otter Tail Power Co.
CIPSCO Incorporated Pacific Gas & Electric Co.
CMS Energy Corp. PacifiCorp.
<PAGE>
<PAGE 13>
Commonwealth Energy System PECO Energy Company
Consolidated Edison Co. of New York, Inc. Pennsylvania Power & Light Co.
DPL Inc. Pinnacle West Capital Corp.
Delmarva Power & Light Company Portland General Electric Co.
The Detroit Edison Company Potomac Electric Power Co.
Dominion Resources, Inc. Public Service Co. of Colorado
DQE Public Service Co. of New Mexico
Duke Power Co. Public Service Enterprise Group Inc.
Eastern Utilities Associates Puget Sound Power & Light Co.
El Paso Electric Rochester Gas and Electric Corp.
Empire District Electric Company St. Joseph Light & Power Co.
Entergy Corporation San Diego Gas & Electric Co.
Florida Progress SCANA Corp.
FPL Group, Inc. SCEcorp
General Public Utilities Corp. Sierra Pacific Power Co.
Green Mountain Power Corp. The Southern Company
Hawaiian Electric Co., Inc. Southern Indiana Gas & Electric Co.
Houston Industries Incorporated Southwestern Public Service Co.
Idaho Power Co. TECO Energy, Inc.
IES Industries Texas Utilities Company
Illinova Corp. TNP Enterprises, Inc.
Interstate Power Co. Tucson Electric Power Co.
Iowa-Illinois Gas and Electric Company Unicom Corp.
IPALCO Enterprises, Inc. Union Electric Co.
Kansas City Power & Light Co. United Illuminating Co.
KU Energy Corporation UtiliCorp. United Inc.
LG&E Energy Corp. Washington Water Power Co.
Long Island Lighting Co. Western Resources Inc.
MDU Resources Wisconsin Energy Corp.
Midwest Resources, Inc. Wisconsin Public Service Corp.
WPL Holdings, Inc.
MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES
The System's Board of Trustees held thirteen meetings throughout 1994.
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 William J. O'Brien. The Committee held four meetings in 1994.
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 Henry Dormitzer,
Chairperson, Sheldon A. Buckler and Gerald L. Wilson. During 1994 the
Committee held four meetings. The Committee was formed for the purpose of
reviewing and recommending compensation and promotional adjustments for
certain of the System's personnel.
The Nominating Committee is composed of Sinclair Weeks, Jr.,
Chairperson, Franklin M. Hundley and Sheldon A. Buckler. The Committee held
two meetings in 1994. The functions of the Committee are: to coordinate
suggestions or searches for potential nominees for the position of Trustee;
<PAGE>
<PAGE 14>
to review and evaluate qualifications of potential nominees; and to recommend
to the Board of Trustees nominees for vacancies occurring from time to time on
the Board of Trustees. The Committee will consider nominees recommended by
Shareholders upon the timely submission of the names of such nominees with
their qualifications and biographical information forwarded to the Nominating
Committee of the Board of Trustees.
The Benefit Review Committee is composed of Franklin M. Hundley,
Chairperson, Henry Dormitzer and Gerald L. Wilson. During 1994 the Committee
held one meeting. The Committee was organized to consider and recommend to
the Board of Trustees matters associated with the System's major funded
benefit plans. Functions of the Committee include: recommending the
composition of benefit plan boards and reviewing investment policy,
objectives, performance or proposed changes related to the plans.
The Strategic Planning Committee is composed of Gerald L. Wilson,
Chairperson and Sheldon A. Buckler. The Committee held seven meetings during
1994. The functions of this Committee are: attendance at strategic planning
sessions, support and insight to management and coordination and communication
of management planning activities with the Board of Trustees.
Each Trustee who was not an employee of the System is compensated for
his or her services as Trustee at the rate of $10,000 per annum, plus $850 for
each Trustee and Committee meeting attended. The Chairpersons of the Audit,
Executive Compensation, Benefit Review and Strategic Planning Committees each
receive an additional $1,000 during the year. In addition, the Chairman of
the Board receives a retainer of $10,000 per year for his services as Chairman
of the Board and of the Nominating Committee.
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.
2-AMENDMENT TO SECTION 6 OF THE
DECLARATION OF TRUST
There will be presented to shareholders by the Board of Trustees a
proposal to consent to an amendment to Section 6 of the System's Declaration
of Trust, which section contains the requirement that at least two-thirds of
the Trustees be at all times residents of Massachusetts and that each of the
remaining Trustees be a resident of one of the New England states. The
purpose of the amendment is to remove the restriction which requires that each
of the Trustees who are not Massachusetts residents be a resident of one of
the New England states. The text of the proposed amendment to section 6 is
set forth as follows:
Section 6 of the System's Declaration of Trust would be amended by
deleting from the second and third lines of the first paragraph of Section 6
the words "and each of the remaining Trustees shall at all times be a resident
of one of the New England states" so that the first sentence of section 6
reads as follows:
"At least two-thirds of the Trustees hereunder shall at all times be
residents of Massachusetts".
<PAGE>
<PAGE 15>
The Trustees believe that this amendment would be in the best interests
of Shareholders, as it will enable the System to attract and retain qualified
candidates for the position of Trustee throughout the System's geographic
shareholder base, which includes all of the United States. At the same time,
retention of the Massachusetts residency requirement for two-thirds of the
Board reflects the fact that the System is predominantly an intra-state
Massachusetts gas and electric utility company. The proposed amendment will
also allow for the continued service on the Board by Ms. Francis, who has
taken a position in the Jacksonville, Florida office of BancBoston Mortgage
Corporation.
The Board of Trustees believes that the restrictions relative to
residency which were inserted into the Declaration of Trust over forty years
ago no longer reflect the System's shareholder demographics, and that such
restrictions both limit the selection and retention of Trustees and fail to
provide for the mobility of today's workforce. At the same time, the
provisions set forth in section 6 requiring two-thirds of the Trustees to be
residents of Massachusetts will continue to ensure that the Board has a
majority of members who are aware of the business climate within which the
System operates so as to be able to provide valuable insight and advice in the
management of the System's affairs. Upon the consent of the holders of the
majority of the outstanding Common Shares present at the meeting and entitled
to vote on the proposed amendment, the Trustees of the System will on May 4,
1995 vote to amend the Declaration of Trust and will file the amended
Declaration of Trust, as required by the terms of the Declaration of Trust and
the laws of the Commonwealth of Massachusetts.
THE TRUSTEES RECOMMEND A VOTE "FOR" THE APPROVAL OF THE AMENDMENT.
3-SHAREHOLDER PROPOSAL
The System has been advised that Mr. John Jennings Crapo, Porter Square
Branch, P.O. Box 151, Cambridge, Massachusetts, 02140-0002, holder of 225
Common Shares, proposes to submit the following proposal at the 1995 Annual
Meeting:
RESOLVED: It is the judgment of the Shareholders of Commonwealth Energy
System ("CES") that it is advisable to amend the CES Declaration of Trust,
dated December 31, 1926, as amended, and that the Board of Trustees present to
Shareholders at the next Annual Meeting of Shareholders an appropriate
amendment to said Declaration of Trust to accomplish the following:
Trustees elected at the annual meeting of Shareholders commencing with the
1997 Annual Meeting of Shareholders shall be elected to hold office until the
next annual meeting and until their successors are elected and qualified.
SUPPORTING STATEMENT: This is a reasonable proposal. It has been
considered Annually at CES Shareholder Annual Meetings starting with 1991.
It provides for the appropriate modification to the Declaration of Trust in
1996, the election of ALL Trustees ANNUALLY commencing in 1997, in a carefully
thought out manner. This proposal at the May 05, 1994 Annual Meeting of
Shareholders received as follows:
1,483,947 Common Shares or 14% were voted "For" the Proposal
5,917,813 Common Shares or 57% were voted "Against" the Proposal, and
3% "Abstained" from the Proposal.
System Vice President, General Counsel, and Secretary, Mr. Michael P.
Sullivan, Esquire, has advised Proponent that based on this vote and the
applicable regulations Proponent may bring forth the Proposal again.
A proposal to abolish the Classified Board of Directors of Tri-Continental
Corporation, presented by this proponent May 19, 1994 at Chemical Bank, New
York City, received the following votes as reported to Proponent:
<PAGE>
<PAGE 16>
48,067,020 shareholders representing 59.8% of the shares outstanding &
eligible to vote balloted in person or by proxy ballot.
20.0% of the shares outstanding and 33.5% of the votes cast voted "For"
Proponent's proposal.
35.9% of the shares outstanding and entitled to vote and 60.9% of the
shareholder votes cast voted "Against" proponent's proposal.
And, 3.9% of the shares outstanding and entitled to vote and 6.5% of votes
cast votes "Abstained."
Objections of TY were that a classified board: provides continuity,
stability, and experience in leadership and in direction strategy...; ensures
Board Members will be fully accountable to Stockholders because each year a
portion of the Board must stand before Stockholders for election...; improves
the ability of Board Members to more effectively represent the interests of
all Stockholders.
The reactions of CES Shareholders and other Shareholders points out the
necessity for CES Shareholders to vote again on Board declassification.
BOARD OF TRUSTEES RECOMMENDATION:
The Board of Trustees recommends a vote AGAINST this proposal for the
following reasons:
This proposal has been submitted at each Annual Meeting since 1991. It
requests that the Board of Trustees submit a proposal to Shareholders at the
1996 Annual Meeting, calling for the repeal of the classified Board, so that
all Trustees would be elected on an annual basis. The classified board was
adopted at the 1987 Annual Meeting, when Shareholders voted to amend the
System's Declaration of Trust to create three classes of Trustees, with an
equal number of Trustees in each class, and to provide that the Trustees would
serve three-year staggered terms, such that three Trustees are eligible for
election each year. The classified board is intended to help to ensure
continued familiarity of Board members with the business, management and
policies of the System, since a majority of the Trustees at any given time
would have prior experience as Board members. These amendments are also
designed to encourage persons seeking to acquire control of the System to
initiate an acquisition through arms-length negotiations with the System's
management and Board of Trustees, by making it more difficult to change the
composition of the Board. Also, the amendments may allow the System's
management to obtain more time and information for evaluating a takeover
proposal, in order to fully protect the interests of the System and its
Shareholders.
The Board continues to believe that each Trustee is fully accountable to
Shareholders throughout each term of office, whether that term is three years
or one year. The Board further notes that the classified board system was
determined to be of sufficient merit such that the Massachusetts legislature
has codified that system, in its 1990 amendments to the laws pertaining to
Massachusetts business corporations (however, the System, as a Massachusetts
Trust, is not affected by this legislation).
Repeal of the classified Board (which, if the present proposal is
adopted, would actually be pursuant to the acceptance of a proposed Amendment
to the Declaration of Trust to be offered at the 1996 Annual Meeting of
Shareholders) requires the affirmative vote or written consent of three-
quarters of the shares entitled to vote, in accordance with the terms of the
System's Declaration of Trust.
<PAGE>
<PAGE 17>
ACCORDINGLY, A VOTE "AGAINST" THE PROPOSAL IS RECOMMENDED.
4-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. However, if any other matters of which the Board of
Trustees is not aware are appropriately presented for action, 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 1996 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 2, 1995.
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
Michael P. Sullivan
Vice President, Secretary
and General Counsel
Cambridge, Massachusetts 02142-9150
March 31, 1995
<PAGE>
<PAGE 18>
Commonwealth
Energy System
1994 Financial
Information
Exhibit A
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<PAGE 19>
CONTENTS PAGE REFERENCE
PUBLISHED EDGAR
Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... A-3 20
Management's Report............................................ A-15 35
Report of Independent Public Accountants....................... A-15 36
Consolidated Balance Sheets.................................... A-16 37
Consolidated Statements of Income.............................. A-18 39
Consolidated Statements of Cash Flows.......................... A-19 40
Consolidated Statements of Capitalization...................... A-20 41
Consolidated Statements of Changes in Common Shareholders'
Investment and Consolidated Statements of Changes in
Redeemable Preferred Shares.................................. A-21 42
Notes to Consolidated Financial Statements..................... A-22 43
Selected Financial Data........................................ A-36 58
<PAGE>
<PAGE 20>
COMMONWEALTH ENERGY SYSTEM
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Earnings
Earnings and earnings per common share by organizational element for the
three-year period are summarized in the table below:
1994 1993 1992
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in Thousands Except Per Share Amounts)
Electric.......... $32,952 $3.16 $28,742 $2.82 $23,295 $2.31
Gas............... 12,346 1.19 15,746 1.54 13,253 1.32
Other............. 2,500 .24 116 .01 2,058 .20
Total........... $47,798 $4.59 $44,604 $4.37 $38,606 $3.83
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.
1994 versus 1993
In 1994, earnings improved by 7.2% to the highest year-end level in the
history of the System. Return on average common equity for 1994 was 13.7%,
equaling the return for 1993, which was the highest since 1985. Significant
factors that contributed to the improved earnings were: 1) cost savings of
$2.7 million in direct payroll and the absence in 1994 of $3.7 million in
severance pay attributable to a work force reduction implemented at our
electric division and services company during the second quarter of 1993;
2) reduced undercollection of certain purchased power capacity costs that
resulted in a positive earnings change of $2.9 million; 3) a full year of new
base rates for Cambridge Electric Light Company that became effective in June
1993; 4) an increase of 1.4% in retail electric unit sales; and 5) lower
short-term interest costs of $2.3 million reflecting a 38% decrease in the
debt level to $44.9 million (the lowest year-end amount since 1986 and only
5.2% of total capitalization).
The higher earnings in 1994 were achieved despite the decline in
earnings from gas operations that reflected milder weather conditions in the
fourth quarter when degree days were 14% below both normal and the fourth
quarter of the prior year. For the year, firm gas sales decreased 1.7% but
several record daily send-outs were achieved, including a new peak on January
19, 1994 of 364,799 MMBTU.
1993 versus 1992
Earnings improved in 1993 by 15.5% due, in part, to a significant
reduction in other operation expense ($16.6 million or 7.4%) that reflected
the system's cost containment efforts which included the shutdown of the
Cannon Street generating station in late 1992 ($1.5 million) and the work
force reduction that provided a net payroll savings of $1.6 million. The
provision for bad debt expense declined by $2.7 million and resulted from
improved collection experience. Other factors which contributed to the
earnings increase were: 1) higher retail electric unit sales and firm gas
sales during the heating season; 2) new base rates for Cambridge Electric;
3) the recognition of electric conservation and load management (C&LM) related
lost base revenues ($2.4 million); and 4) the reversal of a reserve ($3.8
million) following the resolution of uncertainties related to the system's
Seabrook investment.
<PAGE>
<PAGE 21>
Electric Revenues and Unit Sales
Electric operating revenues for the years 1994, 1993 and 1992 consisted
of:
1994 1993 1992
Operating Revenues - In Thousands
Retail....................... $525,326 $513,160 $483,151
Wholesale.................... 108,171 105,445 108,197
Other........................ 5,630 5,415 5,921
Total.................... $639,127 $624,020 $597,269
Unit sales (in Megawatthours or MWH) for the years 1994, 1993 and 1992
consisted of:
% %
1994 Change 1993 Change 1992
Residential.......... 1,770,095 1.5 1,744,181 1.0 1,726,139
Commercial........... 2,049,949 2.1 2,008,213 2.9 1,951,228
Industrial and Other. 801,165 (0.3) 803,630 1.4 792,505
Total Retail......... 4,621,209 1.4 4,556,024 1.9 4,469,872
Wholesale............ 3,803,786 3.1 3,689,129 (5.4) 3,898,924
Total.............. 8,424,995 2.2 8,245,153 (1.5) 8,368,796
Customers served..... 357,000 1.4 352,000 1.1 348,000
In 1994, electric operating revenues increased $15.1 million (2.4%) due
primarily to higher fuel and purchased power costs of $11 million (3.2%), the
new base rates for Cambridge Electric that became effective June 1, 1993 and
higher total unit sales of 2.2%. Another factor contributing to the increased
level of revenues was a greater recovery of lost base revenues of approximate-
ly $920,000. Partially offsetting these increases was a $1.5 million reduc-
tion in C&LM program costs for electric operations which are being recovered
through revenues. To the extent that costs associated with these programs
increase or decrease from period to period, a corresponding change will occur
in revenues. The recovery of lost base revenues is allowed by the Massachu-
setts Department of Public Utilities (DPU) to encourage effective implementa-
tion of C&LM programs. The rise in wholesale revenues of $2.7 million (2.6%)
was due to a $9.3 million (12.8%) increase in sales to other utilities offset,
in part, by a $5.9 million (21.7%) decline in sales to the New England Power
Pool. Fluctuations in the level of wholesale electric sales have little, if
any, impact on earnings.
For 1994, retail electric unit sales gained 1.4% as a result of
increased heating demand caused by the extremely cold weather conditions
during the first quarter and greater usage, particularly air conditioning
load, during the summer months. Unit sales reflect continued moderate growth
of approximately 5,000 customers, mainly in the residential and commercial
sectors, resulting from more housing units and an improved economy that
produces added heating and air conditioning loads. Growth in unit sales is
reduced somewhat by the system's conservation programs. The system expects
that its retail unit sales growth will average 1% - 2% over the next five
years.
1993 electric operating revenues increased $26.8 million (4.5%) due
primarily to the net increase in fuel and purchased power costs of $35.8
million (11.4%), the base rate increase for Cambridge Electric, a 1.9%
increase in retail unit sales and the recovery of approximately $2.4 million
in C&LM lost base revenues. Partially offsetting these increases was a lower
level ($9 million) of C&LM program costs. The decline in wholesale revenues
of $2.8 million (2.5%) was due to a 5.9% drop in unit sales to non-associated
utilities.
Retail electric unit sales for 1993 increased by 1.9%, as each customer
segment improved, offset somewhat by the impact of conservation programs. In
particular, unit sales reflected a moderate increase in customers, primarily
<PAGE>
<PAGE 22>
residential and commercial, a greater demand for power from seasonal custom-
ers, reflecting an improved economy and to a lesser extent, more extreme
weather conditions.
Fuel and Purchased Power
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 entitlements pursuant to 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 DPU.
The cost of fuel used for electric generation and purchased power per
KWH sold was $.043, $.042 and $.037 for 1994, 1993 and 1992, respectively.
These costs constitute 56% in both 1994 and 1993 and 52% in 1992 of electric
operating revenues for the respective years and reflect the impact of the
system's contractual obligations to purchase higher-cost power. These
contracts, negotiated in the 1980s when the system's customer base grew
dramatically and forecasts predicted continued growth, persisted to drive
costs up as additional "must run" capacity came on line displacing lower cost
units as the economy slowed. In 1994, the system took aggressive action to
deal with the escalating energy costs by concluding the negotiation of a
restructured power sales agreement, effective January 1, 1995, with an
independent power producer (IPP) that defers purchases for a maximum of six
years and requires the facility to provide power on a dispatchable basis at
the discretion of Commonwealth Electric. Another purchased power contract was
terminated through a buy-out arrangement effective January 27, 1995, pending
final Federal Energy Regulatory Commission (FERC) approval. For further
details, refer to the "Power Contract Negotiations" discussion that follows.
In 1994, the average cost reflects the moderating impact of the deferral
of $16 million of costs associated with Commonwealth Electric's rate
stabilization mechanism that was implemented on April 1, 1994 and is further
discussed in the "Rate Stabilization Plan" section to follow. The cost per
KWH would have been $.045 in 1994 were this mechanism not in effect.
For 1994 and 1993, fuel and purchased power costs increased $11 million
(3.2%) and $35.8 million (11.4%), respectively, due to higher unit sales in
both years and the contractual obligations discussed above prior to the
restructuring of one contract and the termination of a second. In both years,
there were additional power purchases from certain natural gas-fired IPP
facilities and reduced generation from Canal Electric Company's units (for
sales to non-associate utilities).
Fuel and purchased power in 1994 and 1993 includes the increased cost of
using cleaner burning but more expensive fuel oil (1% sulphur) at Canal
Electric. In addition, 1993 expense includes $5.6 million for capacity-
related costs associated with certain purchased power contracts that were not
recovered in revenues due to the recovery mechanism established by the DPU.
In 1994, this underrecovery was reduced to $800,000. This underrecovery
reduced net income by $485,000 and $3.4 million in 1994 and 1993, respective-
ly. (Refer to the "Cost Recovery" section of this discussion for more
information.)
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Energy Mix
The system's energy mix, including purchased power, is shown below:
Actual
1994 1993 1992
Natural gas................. 38% 29% 21%
Nuclear..................... 25 26 27
Oil......................... 24 31 41
Waste-to-energy............. 9 8 7
Hydro....................... 2 3 2
Coal........................ 2 3 2
Total..................... 100% 100% 100%
The system's energy mix has shifted during the last several years from
oil to natural gas and other fuels due to the requirement to purchase capacity
from IPP facilities and, to a lesser extent, continued efforts to reduce its
reliance on oil. There were no new sources of system generation or purchased
power in 1994. In 1993, Commonwealth Electric began receiving power from:
1) an 11.1% entitlement in a 240 megawatt (MW) gas-fired cogeneration
facility; 2) a 17.2% entitlement in a 160 MW gas-fired cogeneration facility;
3) additional energy from the expansion of a waste-to-energy plant; and 4) an
extended commitment to April 1997 to exchange 50 MW of Canal Electric's oil-
fired generation with 50 MW of pumped storage energy capacity from non-
affiliate New England Power Company's Bear Swamp Units (an initial, smaller
exchange of 25 MW began in 1992). In 1991, Canal Electric arranged for a
long-term exchange of power with Central Vermont Public Service Company (CVPS)
whereby 50 MW from Canal Electric's oil-fired Unit 2 was exchanged for 25 MW
from CVPS's Vermont Yankee nuclear unit and 25 MW from its Merrimack Unit 2
coal-fired facility. This agreement expires in October 1995. In certain
circumstances, it is possible to exchange capacity with another utility so
that the mix of power improves the pricing for dispatch for both the seller
and the purchaser. The Canal Electric/Bear Swamp transaction alone will save
the system's customers $2.7 million over a four-year period that began in June
1993. In 1995, it is expected that these exchanges, combined with a reduction
in the capacity from purchased power contracts with natural gas-fired IPPs,
will necessitate increased purchases from the oil-fired Canal Electric units.
In October 1993, the system reached an agreement (subject to regulatory
approvals) with Montaup Electric Company (the 50% owner of Canal Unit 2) and
Algonquin Gas Transmission Company to build a natural gas pipeline that will
serve the Canal Unit 2 generating station. Unit 2 will be modified to burn
gas as well as oil. (Refer to "Environmental Matters" section for more
information.)
Oil-fired generation has been significantly reduced from pre-1993 levels
but still accounts for 24% of the system's total sources, with higher levels
anticipated for 1995 and beyond. Average oil prices in 1994 at Canal Elec-
tric's generating plant, a major supplier of electricity for the system, were
$14.33 per barrel as compared to $14.02 and $12.95 per barrel in 1993 and
1992, respectively. In conformance with tighter restrictions on stack
emissions, the Massachusetts Department of Environmental Protection (DEP)
mandated a reduction in sulphur dioxide emissions requiring the periodic use
of lower-sulphur (1%) content oil. In 1994, 1% oil averaged $14.92 per
barrel, a 1.6% and 12.1% decrease from the $15.16 and $17.25 per barrel cost
in 1993 and 1992, respectively. However, in 1994 and 1993 lower-sulphur oil
displaced 70.4% and 57.5% of the higher-sulphur (2.2%) content oil as compared
to 24% in 1992.
In addition to power purchases, the system is actively pursuing the
marketing of certain capacity at competitive terms and rates to utilities in
and outside the New England region at a higher price (thus saving the system's
customers the difference) than if it were to sell to the New England Power
Pool. This situation is a result of several utilities in New England (the
<PAGE>
<PAGE 24>
system included) having excess capacity and lowered prospects for sales
growth. This competitive business developed for the system in the early 1990s
when it began to formally request proposals to supply short-term energy and
associated capacity to other utilities on the open market to fulfill their
power requirements. Increased emphasis on the marketing of this capacity
yielded approximate savings of $1,039,000, $429,000 and $451,000 in 1994, 1993
and 1992, respectively.
Gas Revenues, Unit Sales and Cost of Gas Sold
Gas operating revenues for the years 1994, 1993 and 1992 consisted of:
1994 1993 1992
Operating Revenues - In Thousands
Firm............................ $296,027 $291,986 $283,792
Interruptible................... 5,864 5,367 6,389
Transportation.................. 2,563 1,566 1,087
Other........................... 19,114 3,725 3,606
Total........................ $323,568 $302,644 $294,874
Unit sales and transportation volume (in billions of British thermal
units or BBTU) for the years 1994, 1993 and 1992 consisted of:
% %
1994 Change 1993 Change 1992
Residential......... 21,515 (3.3) 22,252 (0.6) 22,392
Commercial.......... 10,728 (1.9) 10,931 0.2 10,913
Industrial and other 6,296 4.3 6,036 (7.2) 6,505
Total firm....... 38,539 (1.7) 39,219 (1.5) 39,810
Off-system.......... 6,401 - - - -
Quasi-firm.......... 487 - - - -
Interruptible....... 1,927 1.6 1,896 (23.1) 2,464
Total sales...... 47,354 15.2 41,115 (2.7) 42,274
Transportation...... 2,208 26.0 1,753 59.9 1,096
Total............. 49,562 15.6 42,868 (1.2) 43,370
Customers served.... 232,000 - 232,000 2.2 227,000
For 1994, gas operating revenues increased $20.9 million (6.9%) due
primarily to an increase in the cost of gas sold of $20.4 million (13%),
higher C&LM costs ($2.6 million) that are recovered through a Conservation
Charge (CC) recovery mechanism which is part of the existing Cost of Gas
Adjustment Clause (CGAC), an increase in transportation revenues ($997,000)
and higher interruptible sales. To the extent that costs associated with C&LM
programs increase or decrease from period to period, a corresponding change
will occur in revenues. Included in other revenues for the first time were
new off-system sales. The margin on these sales will be shared with one-half
used to reduce the cost of gas to firm customers and the remainder deferred
pending DPU approval of Commonwealth Gas Company's margin sharing proposal
that is expected to be filed in 1995. Although the per unit cost of gas sold
decreased slightly, the increase in the total cost of gas sold reflects a 15%
increase in the volume of gas purchased due primarily to the off-system sales
noted above (there were no sales of this type in 1993) and sales from a new
"quasi-firm" service available to certain customers. Quasi-firm sales service
is designed for larger customers and provides a combination of firm and
interruptible service. In exchange for prices lower than full firm service,
quasi-firm customers will receive interruptible service in peak demand months
and firm service in off-peak months.
Gas operating revenues for 1993 rose $7.8 million (2.6%) due primarily
to increases in C&LM costs ($4.8 million), the cost of gas sold ($2.4 million)
and an increase in transportation revenues ($479,000). Offsetting these
increases were slightly lower unit sales.
<PAGE>
<PAGE 25>
Firm sales gains from extreme cold weather experienced during the first
quarter of 1994 (5.6%) were substantially offset by the decline in fourth
quarter sales (15%) due to mild weather. During January 1994, on four
different occasions, the system established all-time highs for daily send-out,
setting a new peak on January 19 of 364,799 MMBTU. The previous all-time peak
was 336,998 MMBTU set in January 1988. In 1993, firm gas sales declined by
1.5%, including a 7.2% decline in sales to industrial and other customers;
however, firm sales during the heating season when seasonal rates are in
effect increased by nearly 3%. Although interruptible sales decreased 23%
during 1993, these sales have no impact on net income since all of the margin
from these sales are flowed back to firm customers through the CGAC. The
variations from year to year in weather conditions, particularly during the
heating season, cause gas usage to fluctuate. The system expects that its
firm unit sales growth will average 1% - 2% over the next five years.
The total number of customers remained stable in 1994 but increased at a
rate of 1.8% in 1993 due to new home construction and conversion activity.
The fluctuation in interruptible sales during the three-year period reflects
the competitive market conditions for energy resources and the conversion in
1994 of interruptible sales to quasi-firm.
The cost of gas sold per MMBTU averaged $3.74, $3.81 and $3.65 in the
years 1994, 1993 and 1992, respectively. The average per unit cost in 1994
and 1993 reflects the amortization of FERC Order No. 636 (Order 636)
transition costs of $3.6 million and $396,000, respectively. Pursuant to a
DPU order issued on October 29, 1993, transition charges related to Order 636
costs are reflected as a regulatory asset which Commonwealth Gas will recover,
with carrying charges, over a four-year period that began in November 1993, as
further discussed in the "Cost Recovery" section that follows.
Other Operation and Maintenance
In 1994, other operation was virtually unchanged due to the savings
resulting from the second quarter 1993 work force reduction ($2.7 million),
the absence of severance pay incurred in 1993 ($3.7 million) and a decline in
the provision for bad debt expense due to improved collection experience
($600,000). The impact of these factors was offset by higher levels of
insurance and employee benefit costs ($2.4 million), a $1 million increase in
C&LM costs and the impact of inflation on the cost of labor, materials and
other services.
Other operation in 1993 decreased $16.6 million (7.4%) due to lower C&LM
costs ($4.2 million), the absence in 1993 of costs associated with Common-
wealth Electric's Cannon Street generating station ($1.5 million), which
ceased operations in October 1992, and the net savings of $1.6 million ($5.3
million in payroll savings less $3.7 million in severance costs) associated
with the second quarter work force reduction. Also contributing to the
decrease in costs in 1993 was the provision for bad debt expense which
declined $2.7 million (22.8%) due to improved collection experience, lower
liability insurance costs of $1.7 million due to lower claims, lower Seabrook
operating costs of $1.1 million and a decline in employee medical and life
insurance costs of $800,000. Offsetting these decreases, in part, was an
increase in pension costs of $1.5 million.
Cambridge Electric, Commonwealth Electric and Commonwealth Gas have
received approval from the DPU to recover certain costs associated with C&LM
programs through the operation of a CC decimal. For the years ended December
31, 1994, 1993 and 1992, C&LM costs (including amortization of prior period
<PAGE>
<PAGE 26>
amounts), which are included in other operation expense in the accompanying
consolidated statements of income, were as follows:
1994 1993 1992
(Dollars in Thousands)
Cambridge Electric............ $ 1,227 $ 2,905 $ 4,246
Commonwealth Electric......... 4,302 4,165 11,826
Commonwealth Gas.............. 7,685 5,094 286
Total...................... $13,214 $12,164 $16,358
Maintenance in 1994 declined $4.1 million (10%) due primarily to the
timing of scheduled maintenance at the Canal Units. Maintenance in 1993
increased by $700,000 (1.9%) due primarily to a scheduled major inspection and
overhaul of the Canal Unit 2 boiler, turbine and generator.
The total number of full-time employees declined 13.6% to 2,169 in 1994
from 2,510 employees at year-end 1991. Management believes the work force
level is adequate to service its customers.
Depreciation, Amortization and Taxes
Depreciation expense in 1994 increased $1.7 million (4%) due to slightly
higher rates and higher levels of plant in service and the absence of an
adjustment made in 1993 which lowered that year's expense by approximately
$700,000 (1.6%) due to an adjustment to the accrual rate used by Canal
Electric to reflect an extension of the depreciable life of Unit 1 from 1996
to 2002. The abandonment of the Cannon Street generating station also
contributed to the decrease in 1993.
Amortization increased by less than 2% in 1994, while the decline in
this expense for 1993 of $1.7 million (21.9%) was due to the absence of
amortization costs related to Commonwealth Gas' automated mapping system.
Income tax expense increased $900,000 (3.2%) in 1994 due to a higher
level of pretax income. In 1993, income tax expense rose $7.7 million (37.5%)
due to the significantly higher level of pretax income and, to a lesser
extent, an increase in the federal income tax rate to 35%, retroactive to
January 1, 1993.
Local property taxes increased $1.1 million (6.8%) in 1994 reflecting
higher tax rates and assessments. The 2.7% increase in local property taxes
in 1993 primarily reflects higher tax rates and assessments offset, in part,
by an adjustment to the 1993 property tax accrual associated with revisions
made to the nuclear station property tax assessed by the state of New
Hampshire to the joint-owners of Seabrook 1. Payroll and other taxes in 1994
declined nearly $600,000 (6.8%) reflecting the lower number of employees in
the current period. The 3.8% increase in payroll and other taxes in 1993 was
due to an increase in unemployment tax rates.
Other Income
The substantial decrease in other income during 1994 was primarily due
to the absence of a 1993 second quarter reversal of a reserve ($3.8 million
pretax) related to Canal Electric's Seabrook 1 investment. The decision to
eliminate this reserve was prompted by the inclusion of Seabrook 1 costs in
base rates at the state level for Cambridge Electric. Another factor
contributing to the decrease was a $2 million (pretax) charge related to a
settlement negotiated with an outside party for certain costs associated with
Commonwealth Electric's energy conservation program. The decline for 1994 was
offset, somewhat, by accrued interest on Commonwealth Electric's fuel charge
stabilization deferral ($674,000) and the equity component of allowance for
funds used during construction (AFUDC) of $341,000. There was no equity AFUDC
in 1993.
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The substantial increase in other income during 1993 reflects the
reversal of the aforementioned reserve, offset, in part, by the absence in
1993 of equity AFUDC.
Interest Charges
For 1994, long-term interest charges increased $2 million (5.4%) due to
a higher level of long-term debt reflecting a full year of new debt issued at
various times in 1993 by Commonwealth Electric, Commonwealth Gas and Hopkinton
LNG Corp. ($134 million). Interest on short-term borrowings declined by $2.3
million (33.5%) despite higher average interest rates (4.4% versus 3.5%) due
to the significantly lower average level of borrowings ($23.9 million versus
$103.1 million) resulting from a higher level of internally generated funds
and the 1993 financing activity.
Interest charges increased in 1993 by $2.5 million (6.1%) due to a lower
level of AFUDC debt resulting from the Seabrook settlement noted previously
and an increase in interest on long-term debt of $700,000 primarily due to the
issuance of $65 million in new debt in the first quarter of 1993. Somewhat
offsetting these increases was a $300,000 decline in other interest charges
due to lower rates (3.5% versus 4%) and a lower average level of short-term
borrowings ($103.1 million versus $126.3 million).
Liquidity and Capital Resources
Overview
The System is the largest combination public utility holding company in
New England with annual revenues approaching $1 billion and assets of approxi-
mately $1.3 billion. Capital resources of the System and its subsidiaries are
derived principally from retained earnings and equity funds provided through
the System's Dividend Reinvestment and Common Share Purchase Plan (DRP).
During 1994, nearly 34% of the System's shareholders participated in DRP.
Supplemental interim funds are borrowed on a short-term basis and, when
necessary, replaced with new equity and/or debt issues through permanent
financing secured on an individual company basis. The System and its subsidi-
aries have over the years, maintained adequate financial resources and access
to the capital markets and further, do not anticipate a change in 1995 or
beyond. The System purchases 100% of all subsidiary common stock issues and
provides, to the extent possible, a portion of the subsidiaries' short-term
financing needs. These combined resources provide the funds required for the
subsidiary companies' construction programs, current operations, debt service
and other capital requirements. In March 1994, the System's Board of Trustees
voted to increase the quarterly dividend per common share from 73 cents to 75
cents (2.7%) based on the System's improving financial condition and to
provide shareholders a fair and reasonable return. Through February 1995, the
System has paid dividends without interruption or reduction since 1947 (191
consecutive quarters).
Financial Condition
For 1994, cash flows from operating activities amounted to approximately
$126.6 million including net income of nearly $49 million and non-cash items
such as depreciation ($44.2 million), amortization ($9.5 million) and deferred
income taxes of $14.8 million. The change in working capital since December
31, 1993, exclusive of the changes in cash ($1.7 million) and interim
financing ($27.1 million), amounted to $52.7 million and had a significant
positive effect on cash flows from operating activities. The working capital
change reflects lower levels of unbilled revenues ($10.1 million) and accounts
receivable ($1.5 million) coupled with higher levels of accounts payable
($27.9 million), accrued taxes ($8.9 million) and other miscellaneous current
assets and liabilities ($4.3 million). The change in other operating items of
$41.8 million includes $16 million related to Commonwealth Electric's rate
stabilization deferral, $8.5 million related to uncollected postretirement
benefit costs, $2.6 million in uncollected Order 636 transition costs and
$14.7 million in other deferred costs.
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Capital Requirements
Construction expenditures for 1994 were $58.6 million, including AFUDC
and nuclear fuel while sinking fund requirements and redemptions of long-term
debt amounted to $16.4 million for a total capital requirement of $75 million,
a decrease of $23.6 million from the 1993 level. These requirements for 1994
were funded entirely with internally generated funds. In addition, short-term
borrowings were reduced by $27.1 million to $44.9 million, which for the most
part, was funded with internal cash generated from higher retail electric unit
sales and continued cost containment efforts.
The system anticipates that future capital requirements, as shown below,
will be met primarily through internally generated funds, supplemented by a
combination of debt and equity financings. As conditions warrant, the system
will refinance certain of its outstanding securities based on acceptable
market conditions resulting in a lower cost of debt. The timing and amount of
future debt and equity financings will be dictated by economic and financial
market conditions and the needs of system subsidiaries.
Capital requirements estimated for 1995 through 1999 are as follows:
1995 1996 1997 1998 1999 Total
(Dollars in Millions)
Construction expenditures
including AFUDC.............. $ 88 $ 77 $ 62 $ 66 $ 64 $357
Long-term debt maturities....... 25 33 14 19 20 111
Mandatory sinking funds on long-
term debt and preferred shares. 6 9 9 8 8 40
Total........................ $119 $119 $ 85 $ 93 $ 92 $508
Sources of Capital
It is anticipated that approximately $371 million or 73% of the
projected capital requirements shown above will be provided from internal
sources, a portion of which is the collection of accounts receivable generated
from the sale of electricity, gas and steam to retail and wholesale customers.
Other cash sources include the sale of Common Shares through DRP, periodic
short-term borrowings from banks, rental income and dividends from
investments.
Capital financings during the five-year forecast period are projected
to be issued by subsidiary companies, including common stock issued
exclusively to the System, as follows:
1996 1998 1999 Total
(Dollars in Millions)
Long-term debt...................... $ 62 $ 48 $ 41 $151
Common stock........................ 20 28 17 65
Total............................ $ 82 $ 76 $ 58 $216
The System could also raise capital through the issuance of additional
series of preferred shares or additional Common Shares. However, there are no
projected financings of this type anticipated at this time.
Cash provided by subsidiary company operations continues to be the prim-
ary source of funds. The proceeds from these sources were used to provide for
the payment of dividends and meet capital requirements. The System believes
its capital resources and liquidity are sufficient to meet its current and
projected requirements. In 1994, the subsidiaries of the system provided
$49.7 million to the Parent, and proceeds from DRP provided $9.4 million. In
1993, these amounts were $64.3 million and $7.1 million, respectively.
System companies also maintain lines of credit with banks. At December
31, 1994, short-term notes payable to banks were $44.9 million, representing
the lowest year-end level since 1986 and a decrease of $27.1 million (38%)
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from last year. Bank borrowings are used to temporarily fund construction
projects and to repay the long-term debt of the System and its subsidiary
companies ($10 million in 1994). Arrangements for bank lines of credit
totaled $90 million in committed lines and $90 million in uncommitted lines at
December 31, 1994, at which time approximately $135 million was available to
the system. At December 31, 1999, the system's level of bank borrowings is
projected to be approximately $1.8 million.
Subsidiary companies also participate in the COM/Energy Money Pool (the
Pool). This is an arrangement whereby subsidiary companies' short-term cash
surpluses are used to help meet the short-term borrowing needs of the utility
subsidiaries. In general, lenders to the Pool receive a higher rate of return
than they otherwise would on such investments, while borrowers pay a lower
interest rate than those available from banks.
Capital Structure
The system's objective is to maintain a capital structure that preserves
an appropriate balance between debt and equity. All long-term debt, preferred
shares and common equity issued by the system is ultimately used to repay
short-term debt. The system's capitalization structure, including short-term
debt, is presented below:
Estimate
1993 1994 1999
(Dollars in Thousands)
Long-term debt.... $458,893 51.9% $443,307 51.2% $447,052 46.8%
Preferred shares.. 15,480 1.8 14,660 1.7 10,560 1.1
Common equity..... 337,070 38.2 362,997 41.9 495,796 51.9
Short-term debt... 71,975 8.1 44,850 5.2 1,806 0.2
Total capitalization $883,418 100.0% $865,814 100.0% $955,214 100.0%
Rates and Regulatory Matters
Certain System utility subsidiaries operate under the jurisdiction of
the DPU, which regulates retail rates, accounting, issuance of securities and
other matters. The DPU requires historic test-year information to support
changes in rates. In addition, Canal Electric, Cambridge Electric and
Commonwealth Electric file their respective wholesale rates with the FERC.
Retail Rate Proceedings
The most recent general rate proceedings approved by, or settled with,
the DPU for the System's retail electric and gas subsidiaries were as follows:
Return on
Effective Common Total
Date Requested Authorized Equity Return
(Dollars in Millions)
Cambridge
Electric June 1, 1993 $10.2 $ 7.2 11% 9.95%
Commonwealth
Electric November 1, 1991 27.7 22.8 13% 11.22%
Commonwealth
Gas July 1, 1991 17.3 10.9 12% 10.49%
Cost Recovery
Fuel and Purchased Power
Commonwealth Electric and Cambridge Electric file Fuel Charge (FC) rate
schedules, subject to DPU regulation, under which they are allowed current
recovery from retail customers of costs of fuel used in electric generation
and a substantial portion of purchased power, demand and transmission costs.
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Cambridge Electric and Commonwealth Electric collect a portion of their
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
experience a revenue excess or shortfall which can have a significant impact
on net income. All other capacity and energy-related purchased power costs
are recovered dollar-for-dollar through the FC. Cambridge Electric and
Commonwealth Electric made a filing in late 1992 with the DPU seeking an
alternative method of recovery. This request was denied in a letter order
issued on October 6, 1993. However, the companies were encouraged by the
DPU's acknowledgement that the issues presented warranted further considera-
tion. The DPU encouraged each company to continue to work with other
interested parties, including the Attorney General of Massachusetts, to reach
a consensus solution on the issue for future consideration. The companies
have been involved in discussions with interested parties in an effort to
resolve this issue in a positive fashion and hope to reach an agreement in the
near future.
Cost of Gas Sold
Commonwealth Gas has a standard seasonal Cost of Gas Adjustment Clause
which provides for the recovery, from firm customers, of purchased gas costs
not recovered through base rates. These adjustment charges, 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 following year.
C&LM Programs
The system has implemented a variety of cost-effective C&LM programs for
its gas and electric customers which are designed to reduce future energy use.
On June 30, 1993, the DPU issued an order in Phase I of a C&LM cost recovery
filing made by Cambridge Electric and Commonwealth Electric which allows the
recovery of "lost base revenues" from electric customers. The recovery of
lost base revenues is employed by the DPU to encourage effective implementa-
tion of C&LM programs. The KWH savings that are realized as a result of the
successful implementation of C&LM programs serve as the basis for determining
lost base revenues. Commonwealth Electric and Cambridge Electric recovered
approximately $3.6 million based on estimated KWH savings for the eighteen-
month period that began January 1, 1993. Customer collections began July 1,
1993 over a twelve-month period. On June 30, 1994, the DPU issued an order
that further allows the companies to recover approximately $3.8 million in
additional lost base revenues for a one-year period that commenced July 1,
1994. Through December 31, 1994, the combined recovery was approximately $5.7
million, $2.4 million of which was collected in 1993.
Commonwealth Gas offers conservation measures and energy savings to its
residential and multi-family customers through programs approved by the DPU in
June 1992 and is recovering costs via separately stated CC decimals approved
in that year. On November 23, 1994, the DPU approved a settlement agreement
extending Commonwealth Gas' existing demand-side management (DSM) programs
until October 31, 1995 and allowing the recovery of "lost margins" from its
customers that commenced in January 1995. Specifically, the settlement allows
Commonwealth Gas to recover through the CC decimal the portion of the lost
margins related solely to savings resulting from installations during the
twelve-month period which began in November 1994. In addition, the lost
margins related to savings occurring from prior period installations will be
held in an interest-bearing account pending the completion of a DSM impact
evaluation proceeding currently before the DPU.
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FERC Order No. 636
In April 1992, the FERC issued Order No. 636 (Order 636), which became
effective on November 1, 1993. The order requires interstate pipelines to
unbundle existing gas sales contracts into separate components (gas sales,
transportation and storage services). Order 636 requires pipelines to provide
transportation services that allow customers to receive the same level and
quality of service they had with the previous bundled contracts. Prior to the
implementation of Order 636, Commonwealth Gas purchased the majority of its
gas supplies from either Tennessee Gas Pipeline Company or Algonquin Gas
Transmission Company, supplemented with third-party firm gas purchases,
storage services, and firm transportation from various pipelines. Presently,
Commonwealth Gas purchases only transportation, storage and balancing services
from these pipelines (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
small independent marketers to major gas and oil companies. (Refer to Note
2(g) of the accompanying Notes to Consolidated Financial Statements for more
information.)
Potential Impact of Regulatory Restructuring
Based on the current regulatory framework in which it operates, 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." Under SFAS No.
71, a utility is allowed to defer costs that would otherwise be expensed in
recognition of the ability to recover them in future rates. As a result, the
system has accumulated $111.7 million of regulatory assets (approximately 8%
of total assets) as of December 31, 1994. Management believes that the
current regulatory framework provides for the continued recovery of these
assets.
In the event that recovery of specific costs through rates becomes
uncertain or unlikely in the future either as a result of the expanding
effects of competition or specific regulatory actions, the system could be
required to move away from cost-of-service ratemaking and, therefore, SFAS
No.71 would no longer apply. Discontinuation of SFAS No. 71 could lead to the
write-off of various regulatory assets, which would have an adverse impact on
the system's financial position and results of operations. At this time,
management believes that it is unlikely that regulatory action would lead to
the discontinuation of SFAS No. 71 in the near future.
Competition
This past year, the system continued to develop and implement strategies
to deal with the increasingly competitive environment in our gas and electric
businesses. 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 supply options. Many state and federal
government agencies are considering implementing 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 and in February 1995
opened an investigation into electric industry restructuring.
System company actions in response to the new competitive challenges
have been well received by regulators, business groups and customers.
Commonwealth Gas and Commonwealth Electric have developed and continue to
develop innovative pricing mechanisms designed to retain existing customers,
add new retail and wholesale customers and expand beyond current markets.
Commonwealth Electric recently revised its Economic Development Rate
which will benefit a number of high-use industrial customers and contribute to
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economic development in the area. Another new rate will provide incentive for
business to expand into previously vacant space and its Rate Stabilization
Plan, approved in 1994, continues to hold the line on costs passed on to
customers while aggressively pursuing other cost reduction measures. Recently
completed contract negotiations are expected to save customers approximately
$42 million through 1999 as we continue to explore opportunities to reduce
purchased power costs. Commonwealth Electric recently signed an agreement
with another New England utility to purchase peaking-unit capacity at rates
lower than that available from the New England Power Pool or other regional
utilities.
FERC Order 636 (November 1993) marked the beginning of the deregulation
and restructuring of the natural gas industry. In addition to opening up
customer markets to competition, the regulations shifted many supply-related
responsibilities to local distribution companies including direct gas
purchases from suppliers, pipelines and producers, transportation services and
storage services. Commonwealth Gas has developed a gas control and informa-
tion system that is one of the most sophisticated purchasing and tracking
systems in the industry. This ability, coupled with aggressive planning and
procurement strategies will help to secure Commonwealth Gas' existing market
and permit the expansion of core and non-core supply capabilities.
Commonwealth Gas' substantial LNG and storage capabilities provide it
with the reliability needed during the coldest winter days and the flexibility
to sell capacity when supply and pricing conditions are favorable. Twenty
percent of the gas purchased during 1994 was sold outside Commonwealth Gas'
franchise area. These off-system sales reduced average gas costs by four
cents per MMBTU or a total of $1.7 million. These developments are pushing
the gas business beyond traditional markets and Commonwealth Gas will begin
to profit from these actions, pending DPU approval, by sharing in the margins
produced in the new competitive arena.
System companies continue to be aggressive in their cost containment
efforts. For example, through work force reductions and attrition the system
has reduced its work force approximately 16.3% since 1989. Also, the intro-
duction of advanced technologies in the workplace continues to improve
customer service and our competitive position in our businesses. 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
strategy will have a positive impact in the near-term.
Some of the more specific details of the innovative measures taken in
response to competition include the following:
Rate Stabilization Plan
Commonwealth Electric implemented a FC rate settlement on April 1, 1994
that stabilizes its quarterly FC rate during the years 1994 through 1996 at
6.5 cents per KWH and no greater than 6.7 cents per KWH during 1997. The
settlement results in billings at a lower rate than would have otherwise been
in effect and could save customers between 1.75% and 5% on their annual elec-
tric bills through 1997. This rate stabilization is achieved through the use
of a cost deferral mechanism that was sponsored jointly by Commonwealth
Electric and the Massachusetts Attorney General and approved by the DPU. The
deferred costs are reflected as a regulatory asset to be recovered, with
carrying charges, over the subsequent six-year period beginning in 1998
pursuant to a recovery schedule yet to be determined and subject to DPU
approval. The deferred amount, excluding carrying charges, is restricted to a
maximum of $40 million during the settlement period (1994 through 1997) and is
further limited to an annual amount of $16 million. Commonwealth Electric
deferred $15,964,000 in 1994. In view of recent contract renegotiations, the
system does not expect deferred amounts to exceed $20 million through 1997.
The rate stabilization mechanism is part of a long-term plan to control
Commonwealth Electric's retail rates. This plan will help eliminate the
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disincentive for economic development resulting from a volatile and unpredict-
able FC rate. The stabilized FC rate will enable current and prospective
customers to better plan their business and personal finances in a more
efficient and effective manner. In addition to the Massachusetts Attorney
General, this proposal has been widely supported by various business and
customer groups and other political interests.
Power Contract Negotiations
Commonwealth Electric concluded the negotiation of a restructured Power
Sale Agreement (PSA), effective January 1, 1995, with Lowell Cogeneration
Company Limited Partnership (23 MW). The restructured PSA will allow the
system to defer the purchase of capacity and energy for a maximum of six years
and allows the purchase of power from the plant, when called back into
service, to be dispatched only when needed at the discretion of Commonwealth
Electric. In addition, Commonwealth Electric terminated a PSA with Pepperell
Power Associates Limited Partnership (38 MW), effective January 27, 1995,
through a buy-out arrangement that is subject to final FERC approval. In
1994, the power purchased from these units cost the system 6 cents per
kilowatthour as compared to costs at the system's Canal Electric units of 3.5
cents. It is expected that the resolution of these contracts will enhance
Commonwealth Electric's competitiveness by lowering costs and saving customers
approximately $42 million through 1999.
Economic Development
Realizing a healthy regional economy benefits not only businesses but
all area residents, Commonwealth Electric actively encourages economic growth
by working in partnership with communities and businesses, providing resources
and incentives to drive the region's economy. One initiative involves funding
the development of an action plan to guide the work of the Massachusetts
Textile and Apparel Council, a trade group organized to improve competitive-
ness and job creation throughout the industry. Commonwealth Electric also
funded the development of a business plan that focuses on improving
infrastructure, regulation, access to capital, marketing and promotion,
cooperation and leadership on Cape Cod.
In an effort to foster industrial development in its service area,
Commonwealth Electric began offering an Economic Development Rate (EDR) in
October 1991 to new or existing industrial customers who have an electric
demand of 500 kilowatts or more and meet specific financial and other
criteria. As of December 31, 1994, twenty-three commercial and industrial
customers were benefitting from this special rate. The rate is available for
a six-year term. In 1993, the DPU conducted a generic investigation into EDRs
and rendered a decision on September 1, 1993 that established rate design
guidelines and minimum customer eligibility requirements. Commonwealth
Electric refiled its EDRs to comply with the ruling. The new EDR is available
to both commercial and industrial customers with loads greater than 500
kilowatts. Revenues were lower by $1.7 million, $1.5 million and $1.3 million
in 1994, 1993 and 1992, respectively. These amounts represent the difference
between what certain commercial and industrial customers would have paid prior
to the availability of this rate. Commonwealth Electric also received
approval for a Vacant Space Rate that is available to qualifying small
commercial and industrial customers who establish loads in previously
unoccupied building space.
Quasi-firm and Off-system Gas Sales Services
In late August 1994, Commonwealth Gas received regulatory approval for a
new quasi-firm sales service that is designed for larger customers and
provides a combination of firm and interruptible service. In exchange for
prices lower than full firm service, quasi-firm customers will receive
interruptible service in peak demand months and firm service in off-peak
months. These arrangements will give Commonwealth Gas and its customers more
flexibility in a constantly changing environment.
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During 1994, Commonwealth Gas was able to maximize the use of its gas
supply resources through off-system sales. These efforts primarily help to
reduce the cost of gas to Commonwealth Gas' firm customers thereby serving to
make Commonwealth Gas more competitive in its traditional markets.
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 $2.3 million liability that
reflects its best estimate (based on current information) of the costs to be
incurred in connection with the 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 $760,000 to cover the expected costs associated
with assessment and remediation activities. These estimates are reviewed and
adjusted periodically as further investigation and assignment of responsibil-
ity 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.
In October 1993, the system reached an agreement with Montaup Electric
Company (the 50% owner of Canal Unit 2) and Algonquin Gas Transmission Company
to build a natural gas pipeline that will serve the Canal Unit 2 generating
station, subject to regulatory approvals. Unit 2 will be modified to burn gas
in addition to oil. The project will improve air quality on Cape Cod, enable
the plant to exceed the stringent 1995 air quality standards established by
the DEP and strengthen the system's bargaining position as it seeks to secure
the lowest-cost fuel for its customers. Plant conversion and pipeline
construction are expected to be completed in 1996.
Power Contract Arbitrations
On May 2, 1994, Commonwealth Electric and Cambridge Electric gave notice
of termination of power purchase agreements with Eastern Energy Corporation,
the developer of a proposed 300 MW coal-fired plant, based upon the
developer's failure to meet its contractual obligations. In June 1989,
Commonwealth Electric and Cambridge Electric agreed to buy 27% (50 MW and 33
MW, respectively) of the power to be produced by the proposed plant, original-
ly scheduled to begin operation in January 1992. The developer did not meet
the permitting, construction or operation milestones established by the
contracts, and has not yet obtained the required permits, commenced construc-
tion or sold any additional power from the proposed plant. Efforts to reshape
the power purchase agreements to provide a satisfactory arrangement were
unsuccessful. In a letter dated June 30, 1994, the developer objected to the
notices of termination and invoked arbitration, which is pending. A decision
by the arbitrators on the legality of Commonwealth Electric's and Cambridge
Electric's termination is expected in 1995.
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Commonwealth Electric has initiated an arbitration proceeding with
Dartmouth Power Associates, an IPP, seeking approximately $5 million for
recovery of excess fuel charges billed to Commonwealth Electric for power
purchases in 1992. A decision is expected from the arbitrators in 1995.
______________________________________________________
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
financial statements.
JAMES D. RAPPOLI
James D. Rappoli,
Financial Vice President
February 21, 1995.
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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, 1994 and
1993, 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, 1994. These
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 the System
and subsidiary companies as of December 31, 1994 and 1993, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1994, in conformity with generally accepted
accounting principles.
As discussed in Note 4 to the consolidated financial statements,
effective January 1, 1993, the System and subsidiary companies changed their
method of accounting for costs associated with postretirement benefits other
than pensions.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
Boston, Massachusetts
February 21, 1995.
<PAGE>
<PAGE 37>
Consolidated Balance Sheets
December 31, 1994 and 1993
1994 1993
(Dollars in Thousands)
Assets
Property, Plant and Equipment, at original cost
Electric $1,047,140 $1,018,121
Gas 338,111 322,314
Other 59,213 58,473
1,444,464 1,398,908
Less-Accumulated depreciation and amortization 461,310 425,483
983,154 973,425
Construction work in progress 15,835 9,448
Nuclear fuel in process 139 1,641
999,128 984,514
Leased Property, net 15,729 16,150
Equity in Corporate Joint Ventures
Nuclear electric power companies (2.5% to 4.5%) 9,818 9,660
Other investments 3,830 3,889
13,648 13,549
Current Assets
Cash 7,722 6,007
Accounts receivable, less reserves of $7,956,000
in 1994 and $7,761,000 in 1993 92,157 93,663
Unbilled revenues 33,161 43,279
Inventories, at average cost-
Electric production fuel oil 1,689 1,440
Natural gas 24,161 25,810
Materials and supplies 7,736 8,852
Prepaid taxes 8,806 8,582
Other 5,858 6,649
181,290 194,282
Deferred Charges 134,921 106,668
$1,344,716 $1,315,163
<PAGE>
<PAGE 38>
Consolidated Balance Sheets
December 31, 1994 and 1993
1994 1993
(Dollars in Thousands)
Capitalization and Liabilities
Capitalization (See separate statement)
Common share investment $ 362,997 $ 337,070
Redeemable preferred shares, less current
sinking fund requirements 14,660 15,480
Long-term debt, less current sinking fund
requirements and maturing debt 418,307 448,893
795,964 801,443
Capital Lease Obligations 14,098 14,456
Current Liabilities
Interim Financing-
Notes payable to banks 44,850 71,975
Maturing long-term debt 25,000 10,000
69,850 81,975
Other Current Liabilities-
Current sinking fund requirements 6,793 6,793
Accounts payable 117,953 90,006
Accrued taxes-
Local property and other 10,293 9,090
Income 7,654 -
Accrued interest 7,251 7,325
Dividends declared 7,894 7,544
Other 23,359 22,453
181,197 143,211
251,047 225,186
Deferred Credits
Accumulated deferred income taxes 160,944 156,851
Unamortized investment tax credits 29,304 30,774
Other 93,359 86,453
283,607 274,078
Commitments and Contingencies
$1,344,716 $1,315,163
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<PAGE 39>
Consolidated Statements of Income
For the Years Ended December 31, 1994, 1993 and 1992
1994 1993 1992
(Dollars in Thousands)
Operating Revenues
Electric $639,127 $624,020 $597,269
Gas 323,568 302,644 294,874
Steam and other 15,867 14,035 14,307
978,562 940,699 906,450
Operating Expenses
Fuel used in electric production,
principally oil 90,414 90,346 104,640
Electricity purchased for resale 269,418 258,490 208,427
Cost of gas sold 177,150 156,709 154,304
Other operation 207,502 207,053 223,620
Maintenance 36,522 40,574 39,836
Depreciation 44,188 42,480 43,164
Amortization 5,868 5,764 7,697
Taxes-
Local property 17,467 16,350 15,923
Income 29,154 28,256 20,557
Payroll and other 8,087 8,676 8,357
885,770 854,698 826,525
Operating Income 92,792 86,001 79,925
Other Income (Expense)
Allowance for equity funds used during
construction 341 - 1,827
Other, net (691) 3,784 (417)
(350) 3,784 1,410
Income Before Interest Charges 92,442 89,785 81,335
Interest Charges
Long-term debt 39,442 37,416 36,722
Other interest charges 4,475 6,730 7,034
Allowance for borrowed funds used during
construction (443) (195) (2,318)
43,474 43,951 41,438
Net Income 48,968 45,834 39,897
Dividends on preferred shares 1,170 1,230 1,291
Earnings Applicable to Common Shares $ 47,798 $ 44,604 $ 38,606
Average Number of Common Shares
Outstanding 10,413,781 10,215,614 10,081,868
Earnings Per Common Share $4.59 $4.37 $3.83
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<PAGE 40>
Consolidated Statements of Cash Flows
For the Years Ended December 31, 1994, 1993 and 1992
1994 1993 1992
(Dollars in Thousands)
Operating Activities
Net income $ 48,968 $ 45,834 $ 39,897
Effects of non cash items-
Depreciation and amortization 53,727 53,088 58,883
Deferred income taxes, net 14,846 17,059 (74)
Investment tax credits (1,470) (1,500) (1,543)
Allowance for equity funds used
during construction (341) - (1,827)
Earnings from corporate joint ventures (1,750) (1,642) (2,016)
Dividends from corporate joint ventures 1,651 1,981 2,157
Change in working capital, exclusive of cash-
Accounts receivable and unbilled revenues 11,624 (3,961) 4,814
Prepaid (accrued) income taxes 8,016 7,321 (4,539)
Prepaid (accrued) local property and
other taxes 616 301 (598)
Accounts payable and other 32,437 4,642 1,441
Fuel charge stabilization deferral (15,964) - -
Deferred postretirement benefit and
pension costs (8,536) (10,175) (1,418)
Deferred Order 636 transition costs, net (2,585) (8,805) -
All other operating items (14,676) (17,451) 5,233
Net cash provided by operating activities 126,563 86,692 100,410
Investing Activities
Additions to property, plant and
equipment (exclusive of AFUDC)-
Electric (37,997) (29,490) (26,080)
Gas (17,993) (23,099) (20,437)
Other (1,843) (1,796) (2,577)
Allowance for borrowed funds used during
construction (443) (195) (2,318)
Net cash used for investing activities (58,276) (54,580) (51,412)
Financing Activities
Sale of common shares 9,434 7,118 5,233
Payment of dividends (32,475) (31,101) (30,770)
Proceeds from (payment of) short-term
borrowings, net (27,125) (93,625) 19,800
Long-term debt issues - 134,000 15,000
Retirement of long-term debt and preferred
shares through sinking funds (6,406) (6,419) (5,678)
Long-term debt issues refunded (10,000) (37,600) (51,632)
Net cash used for financing activities (66,572) (27,627) (48,047)
Net increase in cash 1,715 4,485 951
Cash at beginning of period 6,007 1,522 571
Cash at end of period $ 7,722 $ 6,007 $ 1,522
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of capitalized amounts) $ 41,022 $ 39,685 $ 40,116
Income taxes $ 17,563 $ 13,528 $ 14,460
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<PAGE 41>
Consolidated Statements of Capitalization
December 31, 1994 and 1993
1994 1993
(Dollars in Thousands)
Common Share Investment
Common shares, $4 par value-
Authorized-18,000,000 shares
Outstanding-10,525,897 in 1994
and 10,295,077 in 1993 $ 42,103 $ 41,180
Amounts paid in excess of par value 103,168 94,657
Retained earnings 217,726 201,233
Total common share investment 362,997 337,070
Redeemable Preferred Shares,
Cumulative, $100 Par Value
Series A, 4.80% 2,880 3,000
Series B, 8.10% 4,320 4,480
Series C, 7.75% 8,280 8,820
Less-Current sinking fund requirements (820) (820)
Total redeemable preferred shares 14,660 15,480
Long-term Debt
Notes due-
1995, 4.70% 15,000 25,000
System Senior Notes due-
1995, 10.39% 10,000 10,000
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 (25,000) (10,000)
Total System long-term debt 30,000 55,000
Subsidiary companies' long-term debt
Mortgage Bonds, collateralized by property of
operating subsidiaries, due-
1996, 7% 4,560 5,320
1996, 8.99% 10,000 10,000
2001, 8.99% 25,400 29,050
2006, 8.85% 35,000 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 20,000
1997, 6 1/4% 4,380 4,440
1998, variable rate (6.75% in 1994 and
4.03% in 1993) 9,000 9,000
1999, 8.04% 10,000 10,000
2002, 7 3/4% 2,800 2,900
2002, 9.30% 30,000 30,000
2003, 7.43% 15,000 15,000
2004, 9.50% 15,000 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% 18,947 20,000
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-Current sinking fund requirements (5,973) (5,973)
Unamortized discount, net (807) (844)
Total subsidiary companies' long-term debt 388,307 393,893
Total long-term debt 418,307 448,893
Total capitalization $795,964 $801,443
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<PAGE 42>
Consolidated Statements of Changes in Common Shareholders' Investment
For the Years Ended December 31, 1994, 1993 and 1992
Amounts
Par Paid in
Value Excess
$4 Per of Par Retained
Shares Share Value Earnings Total
(Dollars in Thousands)
Balance December 31, 1991 10,007,237 $40,029 $ 83,457 $177,373 $300,859
Add (Deduct)-
Net income - - - 39,897 39,897
Sale of shares 134,438 538 4,695 - 5,233
Cash dividends declared-
Common shares-$2.92 per share - - - (29,479) (29,479)
Preferred shares - - - (1,291) (1,291)
Balance December 31, 1992 10,141,675 40,567 88,152 186,500 315,219
Add (Deduct)-
Net income - - - 45,834 45,834
Sale of shares 153,402 613 6,505 - 7,118
Cash dividends declared-
Common shares-$2.92 per share - - - (29,871) (29,871)
Preferred shares - - - (1,230) (1,230)
Balance December 31, 1993 10,295,077 41,180 94,657 201,233 337,070
Add (Deduct)-
Net income - - - 48,968 48,968
Sale of shares 230,820 923 8,511 - 9,434
Cash dividends declared-
Common shares-$3.00 per share - - - (31,305) (31,305)
Preferred shares - - - (1,170) (1,170)
Balance December 31, 1994 10,525,897 $42,103 $103,168 $217,726 $362,997
Consolidated Statements of Changes in Redeemable Preferred Shares
For the Years Ended December 31, 1994, 1993 and 1992
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, 1991 32,400 48,000 99,000 179,400
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
Balance December 31, 1992 31,200 46,400 93,600 171,200
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
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
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
<PAGE 43>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Significant Accounting Policies
(a) General and Regulatory
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 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).
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, certain regula-
tory liabilities established by the system are required to be refunded to
customers over time. The principal regulatory assets included in deferred
charges at December 31, 1994 and 1993 were as follows:
1994 1993
(Dollars in Thousands)
Postretirement benefit costs including
pensions $ 20,129 $ 11,593
FERC Order 636 transition costs 19,201 21,939
Yankee Atomic unrecovered plant and
decommissioning costs 18,368 15,525
Fuel charge stabilization 16,638 -
Seabrook related costs 12,648 15,774
Pilgrim nuclear plant litigation costs 7,001 7,358
Deferred income taxes 5,537 7,345
Cannon Street generating plant abandonment, net 4,400 4,391
Conservation and load management 3,773 4,136
Other 4,042 3,478
Total regulatory assets $111,737 $ 91,539
Regulatory assets as a percent of total assets 8.3% 7.0%
The principal regulatory liabilities, reflected in deferred credits-
other and relating to income taxes, were $17.3 million and $17.9 million at
December 31, 1994 and 1993, respectively.
(b) Principles of Consolidation
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.
(c) Reclassifications
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(d) 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>
<PAGE 44>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(e) 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
currently for fuel used in electric production, purchased power and
transmission costs, total gas costs and conservation and load management and
environmental costs through adjustment clauses. Amounts recoverable under
these clauses are subject to review and adjustment by the DPU. Cambridge
Electric Light Company (Cambridge) and Commonwealth Electric Company
(Commonwealth Electric) collect a portion of capacity-related purchased power
costs associated with certain long-term power arrangements through base rates.
The amount of such fuel and energy costs incurred but not yet reflected in
customers' bills, which totaled $306,000 in 1994 and $5,565,000 in 1993, is
recorded as unbilled revenues. Commonwealth Electric also has implemented a
Fuel Charge (FC) rate settlement that stabilizes its quarterly FC rate for the
years 1994 through 1997 by utilizing a cost deferral mechanism approved by the
DPU. The deferral, which will ultimately be recovered in revenues beginning
in 1998, is limited to $16 million annually (excluding carrying charges) and
is further restricted to a maximum of $40 million during the settlement
period.
(f) 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:
1994 1993 1992
Electric 3.30% 3.28% 3.49%
Gas 2.98 2.95 2.90
Steam 3.94 3.61 3.50
LNG 3.12 3.07 3.00
(g) 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 9.1% in 1994,
3.9% in 1993 and 4.5% in 1992.
(2) Commitments and Contingencies
(a) Construction
The system is engaged in a continuous construction program presently
estimated at $357.4 million for the five-year period 1995 through 1999. Of
that amount, $87.7 million is estimated for 1995. The program is subject to
periodic review and revision.
<PAGE>
<PAGE 45>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(b) Seabrook Nuclear Power Plant
The system's 3.52% interest in the Seabrook nuclear power plant is owned
by Canal Electric Company (Canal), a wholesale electric generating subsidiary,
to provide for a portion of the capacity and energy needs of affiliates
Cambridge and Commonwealth Electric. Canal is recovering 100% of its Seabrook
1 investment through a power contract with Cambridge and Commonwealth Electric
pursuant to FERC and DPU approval.
Pertinent information with respect to Canal's joint-ownership interest
in Seabrook 1 and information relating to operating expenses which are
included in the accompanying financial statements are as follows:
1994 1993
(Dollars in Thousands)
Utility-plant-in
service $232,374 $233,140 Plant capacity (MW) 1,150
Nuclear fuel 18,500 18,514 Canal's share:
Accumulated depreciation Percent interest 3.52%
and amortization (41,654) (34,771) Entitlement (MW) 40.5
Construction work in In-Service date 1990
progress 651 881 Operating license
$209,871 $217,764 expiration date 2026
1994 1993 1992
(Dollars in Thousands)
Operating expenses:
Fuel $ 1,939 $ 3,853 $ 3,952
Other operation 4,340 4,580 5,705
Maintenance 1,688 893 1,508
Depreciation 6,531 6,522 6,426
Amortization 1,320 1,319 1,320
$15,818 $17,167 $18,911
Canal and the other joint owners have established a Seabrook Nuclear
Decommissioning Financing Fund to cover post operation decommissioning costs.
For the years 1994, 1993 and 1992, Canal paid $271,000, $259,000 and $235,000,
respectively, as its share of the cost of this fund. The estimated cost to
decommission the plant is $382 million in 1994 dollars, through December 31,
1994. Canal's share of this liability (approximately $13.4 million) less its
share of the market value of the decommissioning trust ($1 million) is
approximately $12.4 million.
(c) Price-Anderson Act
Under the Price-Anderson Act (the Act), owners of nuclear power plants
have the benefit of approximately $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 $79.2 million per nuclear incident
with a maximum assessment of $10 million per incident within one calendar
year. Nuclear plant owners have initiated insurance programs designed to help
cover liability claims relating to property damage, decontamination,
replacement power and business interruption costs for participating utilities
arising from a nuclear incident.
The system has an equity ownership interest in four nuclear generating
facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The
operators of these units maintain nuclear insurance coverage (on behalf of the
owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II and
NEIL III) and the combined American Nuclear Insurers/Mutual Atomic Energy
Liability Underwriters (ANI). NEIL II provides $1.4 billion of property,
<PAGE>
<PAGE 46>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
boiler, machinery and decontamination insurance coverage, including $250
million of accidental premature decommissioning losses both in excess of the
$500 million required by the Act. NEIL III provides $850 million of
additional insurance coverage. All companies insured with NEIL 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 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 ($4 million)
in the event that total public liability claims from a nuclear incident exceed
the funds available to pay such claims.
(d) Power Contracts
Cambridge and Commonwealth Electric have long-term contracts for the
purchase of electricity from various sources. Generally, these contracts are
for fixed periods and require payment of a demand charge for the capacity
entitlement and an energy charge to cover the cost of fuel. Pertinent
information with respect to life-of-the-unit contracts for power from
operating nuclear units in which the system has an equity ownership (Yankee
Nuclear Units) is as follows:
Connecticut Maine Vermont
Yankee Yankee Yankee
(Dollars in Thousands)
Equity Ownership (%) 4.50 4.00 2.50
Plant Entitlement (%) 4.50 3.59 2.25
Plant Capability (MW) 560.0 870.0 496.0
System Entitlement (MW) 25.2 31.2 11.2
Contract Expiration Date 1998 2008 2012
1992 Actual Cost ($) 9,508 6,671 3,970
1993 Actual Cost ($) 10,016 7,050 4,076
1994 Actual Cost ($) 8,902 6,250 3,660
Decommissioning cost estimate (100%) ($) 361,994 342,706 329,586
System's decommissioning cost ($) 16,290 12,303 7,416
Market value of assets (100%) ($) 148,474 108,678 113,300
System's market value of assets ($) 6,681 3,902 2,549
Cambridge 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>
<PAGE 47>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 1994 1993 1992
Dates % MW Cost Cost Cost
(Dollars in Thousands)
Type of Unit
Cogenerating 2008-2017 * 255.9 $137,304 $104,599 $ 69,742
Nuclear 2012 11 73.1 41,475 40,578 37,516
Waste-to-energy 2015 100 70.2 38,107 34,189 27,206
Hydro 2008-2014 100 29.9 7,521 8,904 10,941
Total 429.1 $224,407 $188,270 $145,405
* Includes contracts to purchase power from various cogenerating units
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 through either the Fuel Charge or in base rates.
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 1994 is
as follows:
Long-Term
Equity Owned Purchased
Nuclear Units Power Total
(Dollars in Thousands)
1995 $21,740 $203,320 $225,060
1996 22,959 207,372 230,331
1997 20,609 212,419 233,028
1998 24,801 227,272 252,073
1999 24,487 240,243 264,730
Commonwealth Electric successfully negotiated a restructured Power Sale
Agreement (PSA), effective January 1, 1995, with an independent power producer
(IPP) that defers purchases for a maximum of six years and requires the
facility to provide power on a dispatchable basis at the discretion of
Commonwealth Electric. In addition, Commonwealth Electric terminated a PSA
with another IPP, effective January 27, 1995, through a buy-out arrangement,
the cost of which will be recorded as a regulatory asset in 1995 pending final
FERC approval.
(e) Yankee Atomic Nuclear Power Plant
In February 1992, the Board of Directors of Yankee Atomic Electric
Company (Yankee Atomic) agreed to permanently discontinue power operation and
decommission the Yankee Nuclear Power Station (the plant). At December 31,
1994, Cambridge and Commonwealth Electric's respective 2% and 2.5% investment
in Yankee Atomic was approximately $1.2 million. The companies' estimated
decommissioning costs include its unrecovered share of all costs associated
with the shutdown of the plant, recovery of its plant investment, and
decommissioning and closing the plant. The most recent cost estimate to
permanently shut down the plant is approximately $408.2 million. The
companies' share of this liability is $18.4 million and is currently reflected
in the accompanying consolidated balance sheets as a liability and
corresponding regulatory asset. The market value of the companies' share of
assets in the plant's decommissioning fund at December 31, 1994 is
approximately $4.9 million.
<PAGE>
<PAGE 48>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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.
(g) FERC Order No. 636
As a result of implementing FERC Order No. 636 (Order 636), each
interstate pipeline company is allowed to collect certain transition costs
from its customers that resulted from the pipelines' need to buy out gas
supply contracts entered into prior to the issuance of Order 636.
Commonwealth Gas has been billed a total of approximately $21.7 million from
Tennessee Gas Pipeline Company (Tennessee), Algonquin Gas Transmission Company
and Texas Eastern Transmission Company (Texas Eastern) through December 31,
1994.
As of October 29, 1993, Commonwealth Gas received preliminary DPU
authorization to recover these costs, with carrying charges, through the cost
of gas adjustment (CGA) over a four-year period that began in November 1993.
As a result, a regulatory asset totaling $19.2 million is reflected in
deferred charges as of December 31, 1994. In addition, a related liability of
$7.8 million is reflected in deferred credits. Final DPU approval for
recovery was received in March 1995.
After extensive negotiations between Texas Eastern, Tennessee and their
customers (including Commonwealth Gas), settlements were reached regarding a
number of transition obligation issues. The settlement with Texas Eastern,
which was approved by FERC, calls for the pipeline to absorb approximately 20%
of all transition costs incurred from June 1993 forward. This agreement also
provides for an extended billing period and annual caps on the collection of
future costs. Commonwealth Gas believes that the absorption requirement will
give the pipeline incentive to minimize future costs. This settlement
resulted in a refund of $2.7 million to Commonwealth Gas which will be
refunded to firm customers beginning in 1995.
The settlement with Tennessee, which received preliminary approval from
the FERC on November 15, 1994, pending rehearings, will lower one element of
Commonwealth Gas' transition obligation by approximately $1 million. Further
negotiations are underway with Tennessee to craft a total settlement similar
to that achieved with Texas Eastern.
Commonwealth Gas is continuing to negotiate with the pipelines on
several other issues. As a result, Commonwealth Gas is unable to predict its
final transition obligation at this time; however, based on these and
subsequent settlement activities, Commonwealth Gas will adjust its regulatory
asset and liability accounts accordingly.
(3) 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.
<PAGE>
<PAGE 49>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a summary of the consolidated provisions for income
taxes for the years ended December 31, 1994, 1993 and 1992:
1994 1993 1992
(Dollars in Thousands)
Federal
Current $12,789 $ 9,438 $10,581
Deferred 12,562 15,127 69
Investment tax credits (1,470) (1,500) (1,543)
23,881 23,065 9,107
State
Current 3,171 2,692 2,599
Deferred 2,403 2,282 2,046
5,574 4,974 4,645
29,455 28,039 13,752
Amortization of regulatory liability
relating to deferred income taxes (119) (350) (2,189)
$29,336 $27,689 $11,563
Federal and state income taxes
charged to:
Operating expense $29,154 $28,256 $20,557
Other income/(expense) 182 (567) (8,994)
$29,336 $27,689 $11,563
Effective January 1, 1992, the system adopted the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of deferred tax
liabilities and assets for the expected future tax consequences of events that
have been included in the financial statements or tax returns. Under this
method, deferred tax liabilities and assets are determined based on the
difference between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect in the year in which the
differences are expected to reverse.
Accumulated deferred income taxes consisted of the following in 1994 and
1993:
1994 1993
(Dollars in Thousands)
Liabilities
Property-related $183,019 $178,739
Fuel charge stabilization 6,526 -
Postretirement benefits plan 5,543 4,136
Order 636 transition costs, net 4,094 3,450
Seabrook nonconstruction 4,504 6,017
All other 19,999 17,054
223,685 209,396
Assets
Investment tax credit 18,941 19,891
Pension plan 6,744 5,720
Regulatory liability 9,536 9,452
All other 19,452 17,689
54,673 52,752
Accumulated deferred income taxes, net $169,012 $156,644
The net year-end deferred income tax liability above includes a current
deferred tax liability of $8,068,000 and a current deferred tax asset of
$207,000 in 1994 and 1993, respectively, which are included in accrued income
taxes and prepaid income taxes, respectively, in the accompanying consolidated
balance sheets.
<PAGE>
<PAGE 50>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The total income tax provision set forth on the previous page represents
37% in 1994, 38% in 1993 and 23% in 1992 of income before such taxes. The
following table reconciles the statutory federal income tax rate to these
percentages:
1994 1993 1992
(Dollars in Thousands)
Federal statutory rate 35% 35% 34%
Federal income tax expense at statutory
levels $27,406 $25,733 $17,496
Increase (Decrease) from statutory levels:
Amortization of regulatory liability
relating to deferred income taxes - - (5,700)
State tax net of federal tax benefit 3,623 3,233 3,353
Tax versus book depreciation 1,471 1,501 1,069
Amortization of investment tax credits (1,457) (1,454) (1,468)
Reversals of capitalized expenses (654) (655) -
Dividend received deduction (428) (405) (480)
Amortization of excess deferred reserves (174) (350) (820)
Other (451) 86 (1,887)
$29,336 $27,689 $11,563
Effective federal income tax rate 37% 38% 23%
On April 22, 1992, the DPU approved a settlement agreement between
Commonwealth Electric, the Attorney General of Massachusetts and a consumer
group, which resulted in the issuance of an accounting order authorizing its
retention of $5.7 million in excess deferred taxes subject to obtaining a
favorable ruling from the Internal Revenue Service which was received on
November 30, 1992.
In accordance with the above settlement agreement, Commonwealth Electric
wrote off in 1992 storm damage costs of $9.2 million ($5.7 million net of
tax). The balance of the excess reserves that would have been returned to
customers was removed from the deferred tax reserve account and, after
adjustment to its pretax amount as required by SFAS 109, was credited to a
liability account. The excess reserves/regulatory liability which Common-
wealth Electric would retain pursuant to the settlement agreement was also
removed from this liability account and credited to other income together with
the related income taxes. These amounts were classified as income tax expense
and were used in the reconciliation of the income tax rate.
As a result of the Revenue Reconciliation Act of 1993, the System's con-
solidated federal income tax rate increased to 35% effective January 1, 1993.
(4) 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>
<PAGE 51>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Components of pension expense and related assumptions to develop pension
expense were as follows:
1994 1993 1992
(Dollars in Thousands)
Service cost $ 7,316 $ 6,069 $ 5,973
Interest cost 21,452 20,410 18,653
Return on plan assets-(gain)/loss 4,544 (36,552) (24,524)
Net amortization and deferral (21,990) 20,669 9,644
Total pension expense 11,322 10,596 9,746
Less: Amounts capitalized
and deferred 2,823 2,130 2,761
Net pension expense $ 8,499 $ 8,466 $ 6,985
Discount rate 7.25% 8.50% 8.50%
Assumed rate of return 8.50 8.50 8.50
Rate of increase in future
compensation 4.50 5.50 5.50
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, in accordance with current
ratemaking, are deferring the difference between pension contribution, which
is allowed currently in base rates, and pension expense, recognized pursuant
to Statement of Financial Accounting Standards No. 87, "Employers' Accounting
for Pensions." The funded status of the system's pension plan (using a
measurement date of December 31) is as follows:
1994 1993
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(200,273) $(209,966)
Nonvested (23,299) (28,184)
$(223,572) $(238,150)
Projected benefit obligation $(274,120) $(288,309)
Plan assets at fair market value 255,263 268,672
Projected benefit obligation
greater than plan assets (18,857) (19,637)
Unamortized transition obligation 11,250 12,857
Unrecognized prior service cost 16,227 14,524
Unrecognized gain (24,998) (20,905)
Accrued pension liability $ (16,378) $ (13,161)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1994 1993
Discount rate 8.50% 7.25%
Rate of increase in future compensation 5.00 4.50
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.
<PAGE>
<PAGE 52>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(b) Other Postretirement Benefits
Through December 31, 1992, the system provided postretirement health
care and life insurance benefits to eligible retired employees. Employees
became eligible for these benefits if their age plus years of service at
retirement equaled 75 or more, provided, however, that such service was
performed for a subsidiary of the System. As of January 1, 1993, the system
eliminated postretirement health care benefits for those non-bargaining
employees who were less than 40 years of age or had less than 12 years of
service at that date. Under certain circumstances, eligible employees are now
required to make contributions for postretirement benefits. Certain
bargaining employees are also participating under these new eligibility
requirements.
Effective January 1, 1993, the system adopted the provisions of
Statement of Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions" (SFAS No. 106). This new
standard requires the accrual of the expected cost of such benefits during the
employees' years of service and the recognition of an actuarially determined
postretirement benefit obligation earned by existing retirees. The
assumptions and calculations involved in determining the accrual and the
accumulated postretirement benefit obligation (APBO) closely parallel pension
accounting requirements. The cumulative effect of implementation of SFAS No.
106 as of January 1, 1993 was approximately $106.7 million which is being
amortized over 20 years. Prior to 1993, the cost of postretirement benefits
was recognized as the benefits were paid. The cost of retiree medical care
and life insurance benefits under the traditional pay-as-you-go method totaled
$4,738,000 during 1992.
In 1993, the system began making contributions to various voluntary
employees' beneficiary association (VEBA) 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 satisfy a portion of its postretirement
benefit obligation. The system contributed approximately $14.5 million and
$12.6 million to these trusts during 1994 and 1993, respectively.
The net periodic postretirement benefit cost for the years ended
December 31, 1994 and 1993 include the following components and related
assumptions:
1994 1993
(Dollars in Thousands)
Service cost $ 2,198 $ 2,100
Interest cost 8,299 9,017
Return on plan assets (186) (661)
Amortization of transition obligation
over 20 years 5,336 5,336
Net amortization and deferral (1,118) 30
Total postretirement benefit cost 14,529 15,822
Less: Amounts capitalized and deferred 8,811 10,832
Net postretirement benefit cost $ 5,718 $ 4,990
Discount rate 7.25% 8.50%
Assumed rate of return 8.50 8.50
Rate of increase in future compensation 4.50 4.50
<PAGE>
<PAGE 53>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The funded status of the system's postretirement benefit plan using a
measurement date of December 31, 1994 and 1993 is as follows:
1994 1993
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (63,280) $ (63,211)
Fully eligible active plan participants (10,680) (10,922)
Other active plan participants (37,396) (37,726)
(111,356) (111,859)
Plan assets at fair market value 19,972 11,037
Accumulated postretirement benefit obligation
greater than plan assets (91,384) (100,822)
Unamortized transition obligation 96,039 101,375
Unrecognized gain (4,655) (553)
$ - $ -
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1994 1993
Discount rate 8.50% 7.25%
Rate of increase in future compensation 5.00 4.50
In determining its estimated APBO and the funded status of the plan for
1994 and 1993, the system assumed estimated health care trend rates as
follows:
1994 1993
Medicare part B premiums 12.30% 14.90%
Medical care 8.50 9.00
Dental care 5.00 5.00
The above rates, with the exception of the dental rate which remains
constant, decrease to five percent in the year 2007 and remain at that level
thereafter. A one percent change in the medical trend rate would have a $1.6
million impact on the system's annual expense (interest component - $1.1
million; service cost - $500,000) and would change the transition obligation
by approximately $13.9 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.
The DPU's policy on postretirement benefits is to allow in rates the
maximum tax deductible contributions made to trusts that have been established
specifically to pay postretirement benefits. Effective with its June 1, 1993
rate order from the DPU, Cambridge was allowed to recover its SFAS No. 106
expense in base rates over a four-year phase-in period with carrying costs on
the deferred balance. The other System companies intend to seek recovery in
their next rate proceeding. While the system is unable to predict the outcome
of these rate proceedings, it believes the DPU will authorize similar rate
treatment as provided to Cambridge and other Massachusetts electric and gas
companies for the recovery of the cost of these benefits. Further, based on
DPU action and discussions with regulators, the system believes that it is
appropriate to record the difference between the amount included in rates and
SFAS No. 106 expense as a regulatory asset. At December 31, 1994 and 1993,
this deferral amounted to approximately $15.7 million and $8.9 million,
respectively.
<PAGE>
<PAGE 54>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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. Effective January 1, 1993, the
rate was increased to five percent for those employees no longer eligible for
postretirement health benefits. The total system contribution was $4,302,000
in 1994, $4,245,000 in 1993 and $4,134,000 in 1992.
(5) 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
corporate purposes. As of December 31, 1994, system companies had $90 million
of committed lines of credit that will expire at varying intervals in 1995.
These lines are normally renewed upon expiration and require annual fees of up
to .1875% of the individual line. At December 31, 1994, the uncommitted lines
of credit totaled $90 million. Interest rates on the outstanding borrowings
generally are at an adjusted money market rate and averaged 4.4% and 3.5% in
1994 and 1993, respectively. Notes payable to banks totaled $44,850,000 and
$71,975,000 at December 31, 1994 and 1993, 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,
1994 are as follows:
Sinking Funds Maturing Debt Issues
Year Subsidiaries System Subsidiaries Total
(Dollars in Thousands)
1995 $5,973 $25,000 $ - $30,973
1996 8,283 - 33,230 41,513
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
(6) 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 1995-1999 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
<PAGE>
<PAGE 55>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
(7) 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, 1994 and 1993 are
as follows:
1994 1993
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-term Debt $449,280 $449,292 $464,866 $526,405
Preferred Stock 15,480 14,687 16,300 15,759
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.
(8) 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,
transportation and other 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, 1994 and 1993:
1994 1993
(Dollars in Thousands)
Transmission facilities $13,844 $14,150
Office furniture and computer equipment 2,136 10,719
Other 100 85
16,080 24,954
Less: Accumulated amortization 351 8,804
$15,729 $16,150
<PAGE>
<PAGE 56>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1994:
Capital Operating
Leases Leases
(Dollars in Thousands)
1995 $ 3,213 $11,264
1996 2,865 8,010
1997 1,963 1,947
1998 1,888 995
1999 1,825 413
Beyond 1999 22,640 1,036
Total future minimum lease payments 34,394 $23,665
Less: Estimated interest element
included therein 18,665
Estimated present value of future minimum
lease payments $15,729
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $13,052,000 in 1994, $12,701,000 in 1993 and
$13,149,000 in 1992. There were no contingent rentals and no sublease rentals
for the years 1994, 1993 and 1992.
(9) Dividend Restriction
At December 31, 1994, approximately $114,876,000 of consolidated
retained earnings was restricted against the payment of cash dividends by
terms of indentures and note agreements securing long-term debt.
(10) Segment Information
System companies provide electric, gas and steam services to retail
customers in communities located in central and eastern 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.
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.
<PAGE>
<PAGE 57>
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
1994 1993 1992
(Dollars in Thousands)
Revenues from
Unaffiliated Customers
Electric $ 639,127 $ 624,020 $ 597,269
Gas 323,568 302,644 294,874
Steam and other 15,867 14,035 14,307
Total Revenues $ 978,562 $ 940,699 $ 906,450
Capital Expenditures (including AFUDC)
Electric $ 38,754 $ 29,667 $ 30,207
Gas 18,020 23,117 20,455
Other 1,843 1,796 2,577
$ 58,617 $ 54,580 $ 53,239
Operating Income
Before Income Taxes
Electric $ 86,800 $ 76,117 $ 65,169
Gas 31,664 35,001 32,891
Steam and other 3,482 3,139 2,422
Total Operating Income Before
Income Taxes $ 121,946 $ 114,257 $ 100,482
Identifiable Assets
Electric $ 930,852 $ 914,571 $ 911,877
Gas 380,805 376,683 328,410
Steam and other 53,914 53,062 53,497
1,365,571 1,344,316 1,293,784
Intercompany eliminations (34,503) (42,702) (35,653)
Investment in corporate joint
ventures 13,648 13,549 13,888
Total Identifiable Assets $1,344,716 $1,315,163 $1,272,019
Depreciation Expense
Electric $ 33,188 $ 32,188 $ 33,632
Gas 9,559 8,939 8,270
Steam and other 1,441 1,353 1,262
Total Depreciation $ 44,188 $ 42,480 $ 43,164
<PAGE>
<PAGE 58>
COMMONWEALTH ENERGY SYSTEM
SELECTED FINANCIAL DATA
1994 1993 1992 1991 1990
(Dollars In Thousands Except Common Share Data)
Operating Revenues
Electric $ 639,127 $ 624,020 $ 597,269 $ 607,371 $ 576,416
Gas 323,568 302,644 294,874 252,239 244,074
Steam and other 15,867 14,035 14,307 13,824 15,308
Total $ 978,562 $ 940,699 $ 906,450 $ 873,434 $ 835,798
Net Income $ 48,968 $ 45,834 $ 39,897 $ 19,472 $ 22,636
Common Share Data-
Earnings per share $4.59 $4.37 $3.83 $1.82 $2.16
Dividends declared
per share $3.00 $2.92 $2.92 $2.92 $2.92
Average shares
outstanding 10,413,781 10,215,614 10,081,868 9,944,433 9,810,180
Total Assets $1,344,716 $1,315,163 $1,272,019 $1,247,386 $1,238,083
Long-term debt $ 418,307 $ 448,893 $ 361,092 $ 366,010 $ 412,211
Redeemable preferred
share investment 14,660 15,480 16,300 17,120 17,940
Common share
investment 362,997 337,070 315,219 300,859 307,282
Total Capitalization $ 795,964 $ 801,443 $ 692,611 $ 683,989 $ 737,433
1994 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $312,906 $213,632 $223,299 $228,725
Operating Income 38,135 14,201 17,639 22,817
Income Before Interest Charges 38,745 14,399 16,880 22,418
Net Income 27,951 3 760 6,216 11,041
Earnings per Common Share 2.68 .32 .57 1.02
Dividends Declared per
Common Share .75 .75 .75 .75
Closing Price of Common Shares-
High 45 1/2 43 3/4 40 3/4 38 3/4
Low 42 7/8 39 1/2 37 1/2 35 3/8
1993 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $276,902 $203,347 $217,884 $242,566
Operating Income 33,868 8,886 16,041 27,206
Income Before Interest Charges 34,319 13,015 16,571 25,880
Net Income 24,063 2,174 5,696 13,901
Earnings per Common Share 2.34 .18 .52 1.33
Dividends Declared per
Common Share .73 .73 .73 .73
Closing Price of Common Shares-
High 48 7/8 48 5/8 50 1/8 49 3/4
Low 40 1/2 43 3/8 46 3/4 43
<PAGE>
<PAGE 59>
Commonwealth Energy System
One Main Street
Post Office Box 9150
Cambridge, Massachusetts 02142-9150
Telephone (617) 225-4000
<PAGE>
<PAGE 60>
Appendices
COMMONWEALTH ENERGY SYSTEM
Proxy-Annual Meeting of Shareholders-May 4, 1995
This Proxy is Solicited on Behalf of the Board of Trustees
The undersigned hereby appoints Henry Dormitzer, William G. Poist and
Sinclair Weeks, Jr., 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 4, 1995 and at any adjournment thereof and to vote the number
of shares which the shareholder(s) would be entitled to vote if personally
present:
To vote your shares for all Trustee nominees, mark the "FOR" box on
item 1. To withhold voting for all nominees, mark the "WITHHELD" box. If you
do not wish your shares voted "FOR" a particular nominee, mark the
"EXCEPTION" box and enter name(s) of the exception(s) in the space provided.
_____________________________________________________________________________
The Trustees recommend a vote "FOR" #1 and #2
1. Election of Trustees
Nominees: S. A. Buckler, B. L. Francis, M. C. Ruettgers
[ ] FOR [ ] WITHHELD [ ] EXCEPTIONS
EXCEPTIONS: ____________________
2. Amendment to Declaration of Trust
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
The Trustees recommend a vote "AGAINST" #3
3. Shareholder Proposal
[ ] FOR [ ] AGAINST [ ] ABSTAIN
_____________________________________________________________________________
4. Upon any other business that may properly come before the meeting.
_____________________________________________________________________________
This Proxy will be voted as directed above. If no other indication
is made, this proxy will be voted FOR proposals #1 and 2,
and AGAINST proposal #3.
Any proxy or proxies to vote such shares at said meeting
heretofore given by the shareholder(s) are hereby revoked.
PLEASE SIGN AND DATE ON REVERSE SIDE
____________________________________________________
____________________________________________________
Signature(s) should agree with name(s) printed below
(When signing as attorney, executor or administrator, trustee or
guardian, etc., please indicate your full title as such.)
Acct. No. No. of Shares
Dated_______________________, 1995
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,
1994 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-31-1994
<PERIOD-END> DEC-31-1994
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 999,128
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<TOTAL-COMMON-STOCKHOLDERS-EQ> 362,997
14,660
0
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820
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<TOTAL-OPERATING-EXPENSES> 885,770
<OPERATING-INCOME-LOSS> 92,792
<OTHER-INCOME-NET> (350)
<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> 4.59
<EPS-DILUTED> 0
</TABLE>
