PAGE 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
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, 1994: $448,741,224
Common Shares outstanding at March 15, 1994: 10,345,619 shares
Document Incorporated by Reference Part in Form 10-K
Notice of 1994 Annual Meeting, Proxy State-
ment and 1993 Financial Information, dated
April 1, 1994 (pages as specified herein) Parts I, II and III
List of Exhibits begins on page 23 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.................... 9
Gas Supply.......................................... 9
Rates, Regulation and Legislation................... 11
Segment Information................................. 15
Environmental Matters............................... 16
Construction and Financing.......................... 16
Employees........................................... 16
Item 2. Properties............................................. 16
Item 3. Legal Proceedings...................................... 17
Item 4. Submission of Matters to a Vote of Security Holders.... 17
PART II
Item 5. Market for the Registrant's Securities and Related
Stockholder Matters.................................... 18
Item 6. Selected Financial Data................................ 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 18
Item 8. Financial Statements and Supplementary Data............ 19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 19
PART III
Item 10. Trustees and Executive Officers of the Registrant...... 20
Item 11. Executive Compensation................................. 21
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 21
Item 13. Certain Relationships and Related Transactions......... 21
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................ 22
Signatures........................................................ 56
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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.; 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 announced on January 23, 1992 its decision to write down its investment
in the Freetown project. This action resulted in the recognition of a charge
(net of tax) of $14.8 million in 1991.
Each of the operating utility subsidiaries previously listed serves
retail customers except for Canal Electric Company (Canal) which operates an
electric generating station located at the eastern end of the Cape Cod Canal
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 expen-
ses. In October 1993, Canal reached an agreement with Montaup and Algonquin
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COMMONWEALTH ENERGY SYSTEM
Gas Transmission Company to build a natural gas 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 304,000 year-round customers in 41 communities in
eastern Massachusetts covering 1,112 square miles and having an aggregate
population of 645,000. The system also serves approximately 48,000 seasonal
retail customers. 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.
The results of the 1990 federal census taken in the system's electric
and gas service areas indicated an increase in population of 15.2% and 12%,
respectively, since 1980.
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 1 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 the largest customers of COM/Energy Steam.
Genzyme's steam need for 1994 is estimated to be 160 million pounds, which
represents approximately 10% of steam unit sales, for heating, air
conditioning and testing processes. After 1994, Genzyme's annual requirement
is estimated to reach approximately 230 million pounds upon commercial
manufacturing of a biotherapeutic product in 1995. New England Confectionery
Company (Necco), began receiving steam service in October 1992 and is the
fourth largest customer of COM/Energy Steam.
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 and the Massachusetts Institute of Technology (MIT).
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COMMONWEALTH ENERGY SYSTEM
Presently, MIT is constructing a 19 MW natural gas-fired cogeneration
facility which is expected to be completed in January 1995. MIT expects that
this cogeneration facility will meet approximately 94% of its power, heating
and cooling requirements. Sales to MIT in 1993 accounted for approximately
1.9% of consolidated unit sales. MIT and Cambridge Electric are presently
negotiating a buy and sell arrangement which will require the approval of the
Massachusetts Department of Public Utilities (DPU).
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
967.1 MW. Included in this amount is 569 MW provided by Canal Unit 1, of
which three-quarters (427 MW) is sold to neighboring utilities under long-term
contracts, and 220.5 MW provided by Canal Unit 2. In 1991, Canal executed an
exchange transaction with Central Vermont Public Service Corporation (CVPS)
whereby 50 MW of Canal Unit 2 was exchanged for 25 MW each of CVPS's entitle-
ment in the Vermont Yankee nuclear power plant and the Merrimack 2 coal-fired
unit through October 1995. These contracts are designed to reduce the
system's reliance on oil. Additionally, in 1993, Canal executed an exchange
transaction with New England Power Company (NEP) whereby 20 MW of Canal Unit 2
was exchanged for 20 MW of Bear Swamp Unit Nos. 1 and 2 through October 1993.
As of November 1, 1993, the exchange was increased to 50 MW through April
1997. The Bear Swamp Units are pumped storage hydro electric generating
facilities. Another 128.3 MW is provided by various smaller system units. Of
the 540.3 MW available to the system, 65.3 MW are used principally for peaking
purposes. A 3.52% ownership interest in the Seabrook 1 nuclear power plant
provides 40.5 MW of capability to the system and Central Maine Power Company's
Wyman Unit 4, an oil-fired facility in which the system has a 1.4% joint-
ownership interest, provides 8.8 MW.
In addition, through Canal's equity ownership in Hydro-Quebec Phase II,
the system has an entitlement of 67.9 MW. Long-term purchase arrangements are
also in place with the following natural gas-fired cogenerating units in
Massachusetts: 23.8 MW from the Consolidated Power Company, 31.4 MW from Pep-
perell Power Associates and 43.9 MW from Northeast Energy Associates and
effective July 31 and September 1, 1993, 51 MW and 55 MW from Masspower and
Altresco Pittsfield, respectively. 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 May 17, 1993); has entitlements totaling
41.6 MW through contracts with five (5) hydroelectric suppliers, including
29.1 MW of pumped storage capacity from New England Power's Bear Swamp Units 1
and 2 and 10 MW from Boott Hydropower, Inc., in Lowell, Massachusetts; and
also receives 61.8 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 and planned system generation,
including purchasing available capacity from neighboring utilities and/or non-
utility generators.
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COMMONWEALTH ENERGY SYSTEM
In addition, the system has available 140.7 MW from four (4) 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
(Dollars in Thousands)
Location Haddam Neck, Wiscasset, Vernon, Plymouth,
Connecticut Maine Vermont Massachusetts
Year of Initial Operation 1968 1972 1972 1972
Contract Expiration Date 1998 2008 2012 2012
System Percent of Equity
Ownership 4.50% 4.00% 2.50% -
System Percent of Plant
Entitlement 4.50% 3.59% 2.25% 11.0%
Plant Capability (MW) 560.0 870.0 496.0 664.7
System Entitlement (MW) 25.2 31.2 11.2 73.1
1991 Actual Cost $ 9,692 $5,900 $3,383 $30,992
1992 Actual Cost 9,508 6,671 3,970 37,516
1993 Actual Cost 10,016 7,050 4,076 40,578
1994 Estimated Cost 10,005 6,755 3,755 41,963
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.
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) when other area units were taken off line. 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.
Additionally, forecasts for electric demand indicated an excess regional
supply in the near term and no need for increased generating capacity until
the late-1990s or beyond. Commonwealth Electric made the decision during the
second quarter of 1993 to abandon the plant and transfer its net book value to
a regulatory asset subsequent to FERC approval. 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.
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
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COMMONWEALTH ENERGY SYSTEM
is accomplished by use of computers to monitor and forecast load requirements
and provide for the economic dispatching of generation.
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 (Phase
I) 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. The
Phase I Interconnection began operation in October 1986. 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.
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 in enhancing reliability.
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.
The system's 3.52% interest in the Seabrook nuclear power plant is owned
by Canal to provide for a portion of the capacity and energy needs of Cam-
bridge Electric and Commonwealth Electric. Canal began recovering 100% of its
Seabrook investment through a power contract with Cambridge Electric and
Commonwealth Electric in June 1990, subject to refund pending a full review of
Canal's investment in the unit by the Federal Energy Regulatory Commission
(FERC). In November 1991, the FERC approved a settlement agreement which
resolved all Seabrook cost-of-service issues (except rate of return). In
December 1991, a FERC Administrative Law Judge (ALJ) affirmed the prudence of
Canal's investment in Seabrook and on January 29, 1992, the FERC approved a
settlement proposal that allows a return on equity of 11.72%. The ALJ's
decision was approved by the full commission in a final order issued on
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COMMONWEALTH ENERGY SYSTEM
August 4, 1992. For additional information concerning Seabrook 1, refer to
Note 2(b) of Notes to Consolidated Financial Statements filed under Item 8 of
this report.
In response to solicitations made to NEPOOL member companies by
Northeast Utilities (NU), Canal, on behalf of Commonwealth Electric and
Cambridge Electric, agreed to purchase entitlements through various contracts
ranging up to five years in length. The terms of the five-year agreement
stipulate the purchase of 50 MW, on average, from NU annually from November
1989 through October 1994. Commonwealth Electric and Cambridge Electric are
each appropriated a portion of the power received from NU based on need.
These and other bulk electric power purchases are necessary in order to
fulfill the system's NEPOOL obligation and to meet Commonwealth Electric and
Cambridge Electric capacity requirements.
Canal has entered into support agreements for Phase I and Phase II of
the Hydro-Quebec Project. 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 $14.2
million at December 31, 1993. In addition, Canal has an equity interest in
Phase II which amounted to $3.9 million in 1993 and $4.2 million in 1992.
Electric Fuel Supply
(a) Oil
Imported residual oil is the fuel used in the generation of power in
system generating plants, producing approximately 31% of the system's total
energy requirement for 1993.
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.
Energy Supply and Credit Corporation (ESCO) operates Canal's oil
terminal for 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 1993, ESCO maintained an average daily inventory of 583,000 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.
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COMMONWEALTH ENERGY SYSTEM
(b) Nuclear Fuel Supply and Disposal
Approximately 26% of the system's total energy requirement for 1993 was
generated by nuclear plants. The nuclear fuel contract and inventory
information for Seabrook 1 has been furnished to the system by North Atlantic
Energy Services Corporation (NAESCO), the plant manager responsible for
operation of the unit.
The supply of fuel for nuclear generating plants generally involves the
acquisition of uranium concentrate, its conversion to uranium hexafluoride,
enrichment, fabrication of the nuclear fuel assemblies and disposition through
reprocessing or storage of spent fuel. Seabrook's requirements for each of
these 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.
Owners or generators of spent nuclear fuel or its associated wastes are
required to bear all of the costs for such transportation and disposal through
payment of a fee of approximately 1 mill/KWH based on net electric generation
to the Nuclear Waste Fund. Under the Act, a temporary storage facility for
nuclear waste was anticipated to be in operation by 1998; however, a reassess-
ment 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 accumulat-
ed through the year 2010.
Gas Supply
In April 1992, the FERC issued Order 636 which became effective on
November 1, 1993 and requires interstate pipelines to unbundle existing gas
sales contracts into separate components (gas sales, transportation and
storage services). Order 636 provides mechanisms which will allow customers
such as Commonwealth Gas to reduce the level of firm services from the
pipelines and "broker" excess capacity on a temporary or permanent basis.
Order 636 also requires pipelines to provide transportation services that
allow customers to receive the same level of service they had with the bundled
contracts. In the past, Commonwealth Gas purchased the majority of its gas
supplies from either Tennessee Gas Pipeline Company (Tennessee) or Algonquin
Gas Transmission Company (Algonquin), a wholly-owned subsidiary of Texas
Eastern Transmission Company (Texas Eastern), supplemented with third-party
firm gas purchases and firm transportation from the various pipelines.
Presently, Commonwealth Gas has only transportation, storage, and balancing
contracts with these pipelines (and other upstream pipelines that bring gas
from the supply wells to the final transporting pipelines), and contracts with
a variety of independent vendors for firm gas supply. Twelve new firm gas
supply contracts have been negotiated with suppliers and filed with the DPU.
During the interim, Commonwealth Gas is operating under short-term firm
agreements with these same vendors to provide firm supplies under similar
terms and conditions as the long-term agreements, which are presently under
review. Approvals are expected during the first half of 1994.
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COMMONWEALTH ENERGY SYSTEM
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 agreements, that have been in existence for many
years, and new agreements which are the result of Order 636 requirements for
total 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 1993, over 99% of the gas utilized by Commonwealth Gas
was delivered by the interstate pipeline system, the remaining small quantity
(approximately 360,000 MMBTU) was delivered as liquid LNG from Distrigas of
Massachusetts.
Commonwealth Gas entered into a multi-party agreement 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 only eleven customers using this
transportation service, accounting for only 1,623 BBTU of throughput in 1993
which represented approximately 3.5% of system throughput.
Hopkinton LNG Facility
A portion of the system's 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 extending
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, the
System believes that its present sources of gas supply are adequate to meet
existing load and allow for future growth in sales.
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COMMONWEALTH ENERGY SYSTEM
Rates, Regulation and Legislation
Certain of the System's utility subsidiaries operate under the jurisdic-
tion of the DPU, which regulates retail rates, accounting, issuance of secur-
ities and other matters. In addition, Canal and Cambridge 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 will have a positive impact on net
income for the balance of 1993 and beyond. More than 80% of the increase
related to: 1) plant additions since Cambridge Electric's last retail rate
proceeding in 1989; 2) capacity costs associated with certain purchased power
contracts; and 3) costs of postretirement benefits other than pensions. The
costs associated with these postretirement benefits were determined in
accordance with Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions,"
issued in 1990 and adopted as of January 1, 1993. The DPU authorized recovery
of these costs over a four-year 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.
On May 17, 1989, Cambridge Electric filed for an increase in its base
rates using a 1988 test-year. On August 31, 1989, the DPU approved an Offer
of Settlement between the parties which resolved all revenue requirements
issues. Cambridge Electric was allowed to increase annual revenues by
$4,438,000 or 5.5% of total test-year revenue, approximately 73% of the
$6,111,000 originally requested. The new rates became effective on December
18, 1989 and represented the first increase in Cambridge Electric's rates
since 1982.
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%.
The DPU ordered the restructuring of the Company's rates to more closely
reflect the actual cost of providing service to each customer class. The DPU
also ordered Commonwealth Electric to undertake an independent management
audit to address, among other areas, its management, planning and control
practices. In February 1992, Ernst & Young was selected by the DPU from three
management consulting firms submitted by Commonwealth Electric to perform the
audit which began on March 6, 1992. On October 9, 1992, the DPU released the
results of the audit which evaluated existing activities and processes and
identified opportunities for improved operations in the areas of strategic
planning, budget development, control of capital and operations costs,
management of outside services, employment policies and customer services.
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COMMONWEALTH ENERGY SYSTEM
Throughout 1993, follow-up discussions were held between Commonwealth Electric
and the DPU regarding the status of each audit recommendation with both
parties expressing overall satisfaction with their progress. Changes in the
implementation plan were discussed, with the plan expected to be completed in
1994.
In January 1989, Commonwealth Electric received authorization from the
DPU to increase base revenues by $18 million or 6.6% of total test-year
revenues. This increase, representing approximately 77% of its original $23.3
million request, included an overall rate of return of 10.89% and a return on
common equity of 13%. It represented the first increase in Commonwealth Elec-
tric's base rates since 1982.
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 the new rates went into
effect on November 1, 1991. The increase was necessitated by the rising costs
of providing service to customers and substantial expenditures to upgrade,
improve and maintain the Commonwealth Gas distribution system.
(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.
On March 23, 1990, Cambridge Electric filed a request with the FERC to
increase its wholesale rates to Belmont by $2,252,000 annually. The request
was largely due to increased purchased power costs and major additions to
plant-in-service. The proposed rates were accepted by the FERC, subject to
refund, on August 1, 1990. On September 19, 1990, Cambridge Electric and
Belmont filed an uncontested Offer of Settlement which the FERC approved on
December 6, 1990 resolving all issues with the exception of Seabrook 1 costs
which were subject to change based upon the results of the FERC's final review
of Canal's investment in the unit. This settlement required Cambridge
Electric to adjust its Belmont rate to reflect the final allocation of power
purchased by Canal on behalf of Cambridge Electric and Commonwealth Electric.
Cambridge Electric made a refund to Belmont in August 1991 and filed the
requisite compliance report with the FERC on September 16, 1991.
A settlement agreement between Canal and Belmont addressing all Seabrook
cost-of-service issues (except rate of return on common equity) was filed with
the FERC on April 16, 1991 and subsequently approved by the FERC on November
13, 1991. In addition, this settlement changed the effective date of the
Belmont Service Agreement from August 1, 1990 to June 30, 1990. The charges
and refunds resulting from this settlement were applied to Belmont's bill in
January 1992.
PAGE 13
COMMONWEALTH ENERGY SYSTEM
On November 12, 1991 a settlement agreement between Canal and Belmont
addressing the rate of return on common equity in the Seabrook Power Contract
was filed with the FERC. The return on equity settlement, which was approved
by the FERC on January 29, 1992, allowed a return on equity of 11.72% and
required Canal to refund certain sums to Cambridge Electric and Commonwealth
Electric and to make a compliance report to the FERC. On March 12, 1992,
Canal made its compliance filing with the FERC indicating that all refunds
were made to Cambridge Electric and Commonwealth Electric on February 27,
1992.
As a result of the return on equity settlement, Cambridge Electric was
required to refund certain sums to Belmont. On April 2, 1992 Cambridge made
its requisite compliance filing with the FERC indicating that refunds were
made to Belmont in the March 1992 billings.
(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.
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, Cambridge Electric and Commonwealth Electric 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 consideration in each company's next
base rate proceeding.
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.
PAGE 14
COMMONWEALTH ENERGY SYSTEM
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
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 dockets
remain pending before the DPU.
(d) Gas Demand, Take-or-Pay Costs and Transition Costs
Commonwealth Gas is obligated, as part of its pipeline transportation
contracts and supplier gas purchase contracts, to pay monthly demand charges
which are recovered from customers 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. Future take-or-pay costs will be included in Tennessee's
Temporary Gas Inventory Charge and transition costs under Tennessee's
restructuring pursuant to Order 636.
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 by $1.5
million to $2.5 million.
As a direct result of implementation of Order 636, most pipeline
companies are incurring transition costs which include the cost of
PAGE 15
COMMONWEALTH ENERGY SYSTEM
restructuring gas supply contracts, the value of facilities that were
supporting the gas sales function and are no longer used and useful for
transportation only services, the cost of contracts with upstream pipeline
companies and various miscellaneous costs. For additional information on
these transition costs refer to Note 2(g) of Notes to Financial Statements
filed under Item 8 of this report.
Commonwealth Gas is collecting take-or-pay and other contract
restructuring costs from its customers through the CGA as permitted by the
DPU. The remaining take-or-pay costs to be billed to Commonwealth Gas from
both Algonquin and Tennessee are estimated at approximately $431,000 as of
December 31, 1993, subject to change upon FERC approval.
(e) Economic Development Rate
Commonwealth Electric implemented an Economic Development Rate (EDR) on
October 1, 1991. The rate is available to new or existing industrial customers
who have an electric demand of 500 kilowatts or more and meet specific
financial criteria. For additional information concerning the EDR, refer to
the "Economic Development Rate" section of "Management's Discussion and
Analysis of Financial Condition and Results of Operations" filed under Item 7
of this report.
(f) Other
Storm Damage Costs
In August 1991, Commonwealth Electric's service territory was partic-
ularly hard hit by Hurricane Bob. Its transmission and distribution system
suffered such extensive damage that its entire service territory (with minor
exceptions) was without power at one point. Commonwealth Electric's franchise
is located entirely within four of the ten Massachusetts counties which were
declared federal disaster zones.
In April 1992, the DPU approved an offer of settlement between
Commonwealth Electric, the Attorney General of Massachusetts and a Cape Cod
consumer group relating to certain costs associated with this storm. For
further information on this settlement, refer to Note 3 of Notes to
Consolidated Financial Statements filed under Item 8 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 11
of Notes to Consolidated Financial Statements filed under Item 8 of this re-
port.
PAGE 16
COMMONWEALTH ENERGY SYSTEM
Environmental Matters
The system is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment.
Compliance with these laws and regulations has required capital expenditures
by the system for the period 1968 through 1993 of approximately $51.8 million,
$29.7 million of which was for facilities and studies at Seabrook. Additional
capital expenditures through 1998 will require an estimated $25.1 million.
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 8.2% to
2,217 in 1993 from 2,414 employees at year-end 1992 due to a second quarter
work force reduction. Of the current total, 1,338 (60%) are represented by
various collective bargaining units. Existing agreements are for varying
periods and expire in 1994 and thereafter. Employee relations have generally
been satisfactory and management views the current work force level to be
appropriate to service the system's customers.
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
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. This unit, which ceased operations in
October 1992, was abandoned in 1993. As a result, the net book value of the
plant of approximately $4 million was reclassified from property, plant and
equipment to a regulatory asset in anticipation of future recovery.
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
8.8 MW joint-ownership interest in Central Maine Power Company's Wyman Unit 4.
The system also owns smaller generating units totaling 65.3 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.
PAGE 17
COMMONWEALTH ENERGY SYSTEM
At December 31, 1993, the electric transmission and distribution system
consisted of 5,784 pole miles of overhead lines, 4,095 cable miles of under-
ground line, 359 substations and 371,594 active customer meters.
The principal natural gas properties consist of distribution mains, ser-
vices and meters necessary to maintain reliable service to customers. At the
end of 1993, the gas system included 2,739 miles of gas distribution lines,
151,192 services and 237,318 customer meters together with the necessary
measuring and regulating equipment. In addition, the system owns a lique-
faction 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
Refer to the "Environmental Matters" section of "Management's Discussion
and Analysis of Financial Condition and Results of Operations" section of the
Notice of 1994 Annual Meeting, Proxy Statement and 1993 Financial Information
dated April 1, 1994, page 42.
Item 4. Submission of Matters to a Vote of Security Holders
None
PAGE 18
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.
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
1992 by Quarter
First Second Third Fourth
High $39 $40 $43 $43
Low 36 3/8 34 7/8 39 1/2 40 1/4
(b) Number of Shareholders at December 31, 1993
15,877 shareholders
(c) Frequency and Amount of Dividends Declared in 1993 and 1992
1993 1992
Per Per
Share Share
Declaration Date Amount Declaration Date Amount
March 25, 1993 $ .73 March 26, 1992 $ .73
June 24, 1993 .73 June 25, 1992 .73
September 23, 1993 .73 September 24, 1992 .73
December 16, 1993 .73 December 17, 1992 .73
$2.92 $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 1994 Annual Meeting, Proxy Statement and 1993
Financial Information dated April 1, 1994, page 67.
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 1994 Annual Meeting, Proxy Statement and 1993
Financial Information dated April 1, 1994, pages 33 through 45.
PAGE 19
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 1994 Annual Meeting, Proxy Statement and 1993
Financial Information dated April 1, 1994 on pages 46 through 66.
Proxy Page
Reference
Management's Report 46
Report of Independent Public Accountants 47
Consolidated Balance Sheets - At
December 31, 1993 and 1992 48-49
Consolidated Statements of Income - Years Ended
December 31, 1993, 1992 and 1991 50
Consolidated Statements of Cash Flows - Years Ended
December 31, 1993, 1992 and 1991 51
Consolidated Statements of Capitalization - At
December 31, 1993 and 1992 52
Consolidated Statements of Changes in Common
Shareholders' Investment and in Redeemable
Preferred Shares - Years Ended
December 31, 1993, 1992 and 1991 53
Notes to Consolidated Financial Statements 54-66
Quarterly Information pertaining to the results of
operations for the years ended December 31, 1993 and 1992 67
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure
None
PAGE 20
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 1994 Annual Meeting, Proxy Statement and 1993 Financial
Information dated April 1, 1994, pages 3-5.
b. Executive Officers of the Registrant:
Age at
December
Name of Officer Position and Business Experience 31, 1993
William G. Poist President, Chief Executive Officer and 60
Trustee of the System and Chairman and
Chief Executive Officer of its principal
subsidiary companies since January 1,
1992; President and Chief Operating
Officer of Commonwealth Gas Company* from
1983 to 1991 and Hopkinton LNG Corp.*
from 1985 to 1991; Vice President of the
System and COM/Energy Services Company*
effective September 1, 1991.
James D. Rappoli Financial Vice President and Treasurer of 42
the System and its subsidiary companies
effective March 1, 1993; Treasurer of System
subsidiary companies 1990; Assistant
Treasurer of System subsidiary companies
1989.
Russell D. Wright President and Chief Operating Officer of 47
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 45
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 21
COMMONWEALTH ENERGY SYSTEM
b. Executive officers of the Registrant (Continued):
Age at
December
Name of Officer Position and Business Experience 31, 1993
Michael P. Sullivan Vice President, Secretary, and 45
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 46
companies since 1978.
*Subsidiary of the System.
The term of office for System officers expires May 5, 1994, 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 1994 Annual Meeting, Proxy Statement and 1993 Financial Informa-
tion dated April 1, 1994, pages 6-10.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this item is incorporated herein by reference to
the Notice of 1994 Annual Meeting, Proxy Statement and 1993 Financial Inform-
ation dated April 1, 1994, pages 3-5.
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by reference to
the Notice of 1994 Annual Meeting, Proxy Statement and 1993 Financial Inform-
ation dated April 1, 1994, pages 3-5.
PAGE 22
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 19 in Item 8 of this
Form 10-K, have been incorporated herein by reference to Exhibit A to the
Notice of 1994 Annual Meeting, Proxy Statement and 1993 Financial
Information dated April 1, 1994.
(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 46).
Schedule III - Investments in, Equity in Earnings of, and Dividends
Received from Related Parties - Years Ended December 31, 1993, 1992 and
1991 (pages 47-49).
Schedule V - Property, Plant and Equipment - Years Ended December 31,
1993, 1992 and 1991 (pages 50-52).
Schedule VI - Accumulated Depreciation and Amortization of Property,
Plant and Equipment - Years Ended December 31, 1993, 1992 and 1991 (page
53).
Schedule VIII - Valuation and Qualifying Accounts - Years Ended December
31, 1993, 1992 and 1991 (page 54).
Schedule IX - Short-Term Borrowings - Years Ended December 31, 1993, 1992
and 1991 (page 55).
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 or Form SE no later than May 2, 1994.
PAGE 23
COMMONWEALTH ENERGY SYSTEM
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incorporated
by reference to the appropriate exhibit numbers and the Securities and
Exchange Commission file numbers indicated in parentheses.
b. If applicable, as designated by an asterisk, certain documents prev-
iously filed by the System or its subsidiary companies have been dis-
posed of by the Commission pursuant to its Records Control Schedule and
are hereby being refiled by the appropriate registrant and to the
appropriate file number.
c. 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.
d. 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 7, 1987 (Exhibit 1 to the
CES Form 10-Q (March 1987), 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).
PAGE 24
COMMONWEALTH ENERGY SYSTEM
Subsidiary Companies of the Registrant
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 First Supplemental on Form S-9 (Jan., 1958) (Exhibit 2(b)2, File No.
2-13783)
4.2.3 Second Supplemental on Form 8-K (Feb., 1962) (Exhibit A, File No.
2-7909)
4.2.4 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-7909)
4.2.5 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-7909)
4.2.6 Fifth Supplemental on Form 10-K (1983) (Exhibit 1, File No. 2-7909)
4.2.7 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2-
7909)
4.2.8 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 Second Supplemental dated September 1, 1976 with Citibank, N.A., New
York, N.Y., Trustee, dated December 1, 1983 (Exhibit 1 to 1983 Form
10-K, File No. 2-30057).
4.3.5 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).
4.3.6 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).
PAGE 25
COMMONWEALTH ENERGY SYSTEM
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 First Supplemental on Form S-1 (Mar., 1950) (Exhibit 7(a), File No.
2-8418)
4.4.3 Second and Third Supplemental on Form S-1 (Nov., 1952) (Exhibits
4(a)(2) and 4(a)(3), File No. 2-10445)
4.4.4 Fourth Supplemental on Form S-9 (Oct., 1954) (Exhibit 2(b)(5), File
No. 2-15089)
4.4.5 Fifth Supplemental on Form S-9 (Mar., 1956) (Exhibit 2(b)(6), File
No. 2-15089)
4.4.6 Sixth Supplemental on Form S-9 (April, 1957) (Exhibit 2(b)(7), File
No. 2-15089)
4.4.7 Seventh Supplemental on Form S-9 (June 1959) (Exhibit 2(b)(8), File
No. 2-20532)
4.4.8 Eighth Supplemental on Form S-9 (Sept., 1961) (Exhibit 2(b)(9),
File No. 2-20532)
4.4.9 Ninth Supplemental on Form 8-K (Aug., 1962) (Exhibit A, File No. 2-
1647)
4.4.10 Tenth Supplemental on Form 10-K (1970) (Exhibit 2, File No. 2-1647)
4.4.11 Eleventh Supplemental on Form S-1 (June, 1972) (Exhibit 4(b)(2),
File No. 2-48556)
4.4.12 Twelfth Supplemental on Form S-1 (Aug., 1973) (Exhibit 4(b)(3),
File No. 2-48556)
4.4.13 Thirteenth Supplemental on Form 10-K (1992) (Refiled as Exhibit 1,
File No. 2- 1647)
4.4.14 Fourteenth Supplemental on Form 10-K (1990) (Exhibit 1, File No. 2-
1647)
4.4.15 Fifteenth Supplemental on Form 10-K (1982) (Exhibit 1, File No. 2-
1647)
4.4.16 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2-
1647)
4.4.17 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No.
2-1647)
PAGE 26
COMMONWEALTH ENERGY SYSTEM
Commonwealth Electric Company
Indenture of Trust or Supplemental Indenture of Trust -
4.5.1 Original Indenture on Form S-1 (Nov., 1948) (Exhibit 7(a), File No.
2-7749)
4.5.2 First Supplemental on Form S-1 (Oct., 1950) (Exhibit 7(a-1), File
No. 2-8605)
4.5.3 Second Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-
7749)
4.5.4 Third Supplemental on Form 8-K (Feb., 1962) (Exhibit A, File No. 2-
7749)
4.5.5 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-
7749)
4.5.6 Fifth Supplemental on Form 10-K (1984) (Exhibit 3, File No. 2-7749)
4.5.7 Sixth Supplemental on Form 10-K (1984) (Exhibit 4, File No. 2-7749)
4.5.8 Seventh Supplemental on Form S-1 (Dec., 1975) (Exhibit 4(b)2, File
No. 2-54955)
Cape & Vineyard Electric Company**
4.5.9 Original Indenture on Form S-1 (Apr., 1957) (Exhibit 4(b)1, File
No. 2-26429)
4.5.10 First Supplemental on Form 10-K (1984) (Exhibit 5, File No. 2-7749)
4.5.11 Second Supplemental on Form 10-K (1984) (Exhibit 6, File No. 2-
7749)
** Merged with Commonwealth Electric Company January 1, 1971.
Exhibit 10. Material Contracts
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated
December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No.
2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and
CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as
Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October
1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to
the CEL Form 10-Q (June 1988), File No. 2-7909).
PAGE 27
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 28
COMMONWEALTH ENERGY SYSTEM
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).
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 (Refiled as
Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749).
PAGE 29
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 30
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 31
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 32
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 33
COMMONWEALTH ENERGY SYSTEM
10.1.31 Agreement to Preliminary Quebec Interconnection Support Agree-
ment - 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).
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).
PAGE 34
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 35
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 36
COMMONWEALTH ENERGY SYSTEM
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 Power Sale Agreement by and between CE (buyer) and CPC Lowell
Cogeneration Corp.(seller) of all capacity and related energy
produced, dated September 29, 1986 (Exhibit 2 to the CE Form 10-Q
(March 1987), File No. 2-7749).
10.1.49.1 Restatement of 10.1.49 as restated March 30, 1987 (Exhibit 2 to
the CE Form 10-Q (June 1987), File No. 2-7749).
10.1.50 Power Sale Agreement by and between CE (buyer) and Pepperell Power
Associates Limited Partnership (seller) of all electricity
produced from a 38 KW generating unit, dated April 13, 1987
(Exhibit 3 to the CE Form 10-Q (March 1987), File No. 2-7749).
PAGE 37
COMMONWEALTH ENERGY SYSTEM
10.1.51 Power Contract between CEC (seller) and CE and CEL (purchasers)
dated August 14, 1989 whereby purchasers agree to purchase the
capacity and energy from seller's "Slice-of-System" entitlement
from CL&P for the term of November 1, 1989 to October 31, 1994
(Exhibit 1 to the CEC Form 10-Q (September 1989), File No.
2-30057).
10.1.51.1 Power Sale Agreement dated November 1, 1988, by and between CEC
(buyer) and CL&P (seller), whereby buyer will purchase generating
capacity totaling 250 MW from various seller's units ("Slice of
System") for the term November 1, 1989 to October 31, 1994
(Exhibit 3 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.52 Exchange of Power Agreement between Montaup Electric Company and
CE dated January 17, 1991 (Exhibit 2 to CE Form 10-Q (September
1991) File No. 2-7749).
10.1.52.1 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).
10.1.53 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).
10.1.53.1 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).
10.1.53.2 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).
10.1.54 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).
10.1.55 Power Exchange Contract, dated March 24, 1993, between NEP and
Canal Electric Company (Canal) for an exchange of unit capacity in
which NEP will purchase 20 MW of Canal Unit 2 capacity in exchange
for Canal's purchase of 20 MW of NEP's Bear Swamp Units 1 and 2
(10 MW per unit) commencing May 31, 1993 through April 28, 1997
and NEP will purchase 50 MW of Canal's Unit 2 capacity in exchange
for Canal's purchase of 50 MW of NEP's Bear Swamp Units 1 and 2
(25 MW per unit) commencing November 1, 1993 through April 28,
1997 (Exhibit 1 to Canal's Form 10-Q (March 1993) File No. 2-
30057).
PAGE 38
COMMONWEALTH ENERGY SYSTEM
10.1.56 Power Purchase Agreement by and between Masspower (seller) and
Commonwealth Electric Company (buyer) for a 11.11% entitlement to
the electric capacity and related energy of a 240 MW gas-fired
cogeneration facility, dated February 14, 1992 (Exhibit 1 to
Commonwealth Electric's Form 10-Q (September 1993), File No. 2-
7749).
10.1.57 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).
10.1.58.1 System Exchange Agreement by and among Altresco Pittsfield, L.P.,
Cambridge Electric Light Company, Commonwealth Electric Company
and New England Power Company, dated July 2, 1993 (Exhibit 3 to
Commonwealth Electric's Form 10-Q (September 1993), File No 2-
7749).
10.1.58.2 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.
10.2.1 Natural gas purchase contracts between Algonquin Gas Transmission
Company (AGT) and the gas subsidiaries of the System: Firm Service
contracts dated October 28, 1969 and July 10, 1972; Winter Service
contracts dated August 14, 1968 and July 10, 1972 (Exhibits 1, 2,
3, and 4, respectively, to the CG 1984 Form 10-K, File No. 2-
1647).
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).
PAGE 39
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 40
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 41
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 42
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 43
COMMONWEALTH ENERGY SYSTEM
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).
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).
PAGE 44
COMMONWEALTH ENERGY SYSTEM
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).
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)
10.3.4 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).
PAGE 45
COMMONWEALTH ENERGY SYSTEM
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).
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 22. 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 99. Additional Exhibit
Filed herewith as Exhibit 1 is the Notice of 1994 Annual Meeting,
Proxy Statement and 1993 Financial Information dated April 1,
1994.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the three months ended
December 31, 1993.
PAGE 46
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 1994 annual meeting of
shareholders incorporated by reference in this Form 10-K, and have issued our
report thereon dated February 17, 1994. Our audits were made for the purpose
of forming an opinion on those 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 financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN & CO.
Arthur Andersen & Co.
Boston, Massachusetts,
February 17, 1994.
PAGE 47
<TABLE>
SCHEDULE III
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 eleven months and twenty-nine days. Interest is at the prime interest rate and is adjusted
for changes in the rate during the term of the notes.
(B) Additional investment.
</TABLE>
PAGE 48
<TABLE>
SCHEDULE III
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 eleven months and twenty-nine days. Interest is at the prime interest rate and is
adjusted for changes in the rate during the term of the notes.
(B) Additional investment.
</TABLE>
PAGE 49
<TABLE>
SCHEDULE III
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES
FOR THE YEAR ENDED DECEMBER 31, 1991
(Dollars in Thousands)
<CAPTION>
Balance at Balance at
Beginning of Year Additions Deductions End of Year
Number Equity Number Notes
of in Distribution of Receivable
Shares Investment Earnings of Earnings Other 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 $ 37 972 $ 4 039 $ 4 066 $ - 304 600 $ 37 945 $ 655
COM/Energy Steam Company 25 500 2 708 1 125 727 - 25 500 3 106 -
Canal Electric Company 1 523 200 106 846 18 978 16 755 - 1 523 200 109 069 2 570
Commonwealth Gas Company 2 407 000 85 226 3 120 5 416 - 2 407 000 82 930 3 725
Darvel Realty Trust 26 1 307 360 110 - 26 1 557 -
COM/Energy Freetown Realty 1 478 (15,795) - - 1 (15 317) -
COM/Energy Research Park Realty 1 790 450 - - 1 1 240 -
COM/Energy Cambridge Realty 1 90 (8) - - 1 82 -
COM/Energy Acushnet Realty 1 488 70 - - 1 558 -
COM/Energy Services Company 3 250 325 49 37 - 3 250 337 -
Commonwealth Electric Company 1 606 472 125 457 9 857 7 952 - 1 606 472 127 362 5 950
Hopkinton LNG Corp. 5 000 3 747 548 - - 5 000 4 295 -
$365 434 $22 793 $35 063 $ - $353 164 $12 900
OTHER INVESTMENTS:
(Accounted for by the equity method)
Nuclear Electric Power Companies 52 654 $ 9 475 $ 1 504 $ 1 330 $20(B) 52 454 $ 9 629
Hydro-Quebec Phase II 137 442 3 453 1 195 276 - 137 442 4 372
Other Investments - 713 (685) - - - 28
$ 13 641 $ 2 014 $ 1 606 $20 $ 14 029
<FN>
NOTES: (A) Notes are written for eleven months and twenty-nine days. Interest is at the prime interest rate and is
adjusted for changes in the rate during the term of the notes.
(B) In 1991, Vermont Yankee repurchased 2% of its common stock at $150 per share from Cambridge Electric. Cambridge
Electric's original cost was $100 per share. As of December 31, 1991, Cambridge Electric held 9,801 shares in
Vermont Yankee.
</TABLE>
PAGE 50
<TABLE>
SCHEDULE V
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1993
(Dollars in Thousands
<CAPTION>
Balance Retirements Adjustments Balance
Beginning Additions Charged to and End of
Classification of Year at Cost Reserve Other Transfers Year
<S> <C> <C> <C> <C> <C> <C>
ELECTRIC
Intangible plant $ 2 386 $ - $ - $ - $ - $ 2 386
Land and rights of way 10 092 7 - 2 - 10 097
Structures and leasehold improvements 130 473 789 82 - - 131 180
Production equipment 307 088 4 130 1 983 - 24 309 259
Transmission equipment 114 660 2 827 777 - 13 116 723
Distribution equipment 406 064 17 818 4 059 - (9) 419 814
Nuclear fuel in reactor 16 928 (55) - - - 16 873
General equipment, vehicles, and other 27 306 188 145 - (15 560)(C) 11 789
Total plant in service 1 014 997 25 704 7 046 2 (15 532) 1 018 121
Construction work in progress 6 515 2 477 - - - 8 992
Nuclear fuel in process 155 1 486 - - - 1 641
Total electric 1 021 667 29 667 7 046 2 (15 532) 1 028 754
GAS
Intangible plant 1 392 - - - - 1 392
Land and rights of way 979 43 - - - 1 022
Structures and leasehold improvements 13 173 211 40 - - 13 344
Distribution equipment 286 093 22 850 4 685 - 1 304 259
General equipment and vehicles 2 119 178 - - - 2 297
Total plant in service 303 756 23 282 4 725 - 1 322 314
Construction work in progress 566 (165) - - - 401
Total gas 304 322 23 117 4 725 - - 1 322 715
OTHER
Steam heating equipment 5 479 1 127 11 - (1) 6 594
Gas liquefaction facility 36 680 962 - - - 37 642
Miscellaneous physical property (B) 15 845 293 42 9 (1 850) 14 237
Total plant in service 58 004 2 382 53 9 (1 851) 58 473
Construction work in progress 641 (586) - - - 55
Total other 58 645 1 796 53 9 (1 851) 58 528
Total Property, Plant and Equipment $1 384 634 $ 54 580 $11 824 $ 11 $(17 382) $1 409 997
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
(B) Principally real estate.
(C) Principally the abandoned Cannon Street generating station reclassified to Deferred Charges.
</TABLE>
PAGE 51
<TABLE>
SCHEDULE V
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1992
(Dollars in Thousands)
<CAPTION>
Balance Retirements Adjustments Balance
Beginning Additions Charged to and End of
Classification of Year at Cost Reserve Other Transfers Year
<S> <C> <C> <C> <C> <C> <C>
ELECTRIC
Intangible plant $ 2 387 $ (1) $ - $ - $ - $ 2 386
Land and rights of way 10 121 161 - (35) (225) 10 092
Structures and leasehold improvements 134 077 379 109 - (3 874) (D) 130 473
Production equipment 313 196 4 560 1 765 - (8 903) (D) 307 088
Transmission equipment 106 288 9 468 1 077 - (19) 114 660
Distribution equipment 390 810 19 556 4 271 - (31) 406 064
Nuclear fuel in reactor 12 780 3 442 - - 706 16 928
General equipment, vehicles, and other 11 664 272 89 - 15 459 (D) 27 306
Total plant in service 981 323 37 837 7 311 (35) 3 113 1 014 997
Construction work in progress 11 739 (5 224) - - - 6 515
Nuclear fuel in process 2 561 (2 406) - - - 155
Total electric 995 623 30 207 7 311 (35) 3 113 1 021 667
GAS
Intangible plant 1 392 - - - - 1 392
Land and rights of way 979 - - - - 979
Structures and leasehold improvements 12 931 281 39 - - 13 173
Distribution equipment 267 855 19 871 1 633 - - 286 093
General equipment and vehicles 1 869 250 - - - 2 119
Total plant in service 285 026 20 402 1 672 - - 303 756
Construction work in progress 513 53 - - - 566
Total gas 285 539 20 455 1 672 - - 304 322
OTHER
Steam heating equipment 5 026 476 23 - - 5 479
Gas liquefaction facility 35 133 1 547 - - - 36 680
Miscellaneous physical property (B) 14 203 184 93 9 1 560 15 845
Total plant in service 54 362 2 207 116 9 1 560 58 004
Construction work in progress 271 370 - - - 641
Total other 54 633 2 577 116 9 1 560 58 645
Total Property, Plant and Equipment $1 335 795 $ 53 239 $ 9 099 $ (26) $ 4 673 (C) $1 384 634
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
(B) Principally real estate.
(C) Adjustments to AFUDC related to Seabrook 1 resulting from FERC settlement.
(D) Principally the Cannon Street generating station reclassified to property held for future use.
</TABLE>
PAGE 52
<TABLE>
SCHEDULE V
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1991
(Dollars in Thousands)
<CAPTION>
Balance Retirements Adjustments Balance
Beginning Additions Charged to and End of
Classification of Year at Cost Reserve Other Transfers Year
<S> <C> <C> <C> <C> <C> <C>
ELECTRIC
Intangible plant $ 2 208 $ 179 $ - $ - $ - $ 2 387
Land and rights of way 9 947 12 - 1 163 10 121
Structures and leasehold improvements 133 436 675 (16) - (50) 134 077
Production equipment 310 464 3 861 1 054 - (75) 313 196
Transmission equipment 103 466 3 157 336 - 1 106 288
Distribution equipment 363 728 31 233 4 123 - (28) 390 810
Nuclear fuel in reactor 8 598 4 182 - - - 12 780
General equipment, vehicles, and other 11 434 472 238 - (4) 11 664
Total plant in service 943 281 43 771 5 735 1 7 981 323
Construction work in progress 10 623 1 211 - - (95) 11 739
Nuclear fuel in process 5 655 (3 341) - - 247 2 561
Total electric 959 559 41 641 5 735 1 159 995 623
GAS
Intangible plant 1 392 - - - - 1 392
Land and rights of way 979 - - - - 979
Structures and leasehold improvements 12 463 598 131 - 1 12 931
Distribution equipment 253 021 16 606 1 772 - - 267 855
General equipment and vehicles 1 918 72 120 - (1) 1 869
Total plant in service 269 773 17 276 2 023 - - 285 026
Construction work in progress 678 (165) - - - 513
Total gas 270 451 17 111 2 023 - - 285 539
OTHER
Steam heating equipment 4 727 305 6 - - 5 026
Gas liquefaction facility 34 085 1 098 50 - - 35 133
Miscellaneous physical property (B) 35 320 891 18 9 (21 981) 14 203
Total plant in service 74 132 2 294 74 9 (21 981) 54 362
Construction work in progress 299 (28) - - - 271
Total other 74 431 2 266 74 9 (21 981) 54 633
Total Property, Plant and Equipment $1 304 441 $ 61 018 $7 832 $ 10 $(21 822)(C) $1 335 795
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
(B) Principally real estate.
(C) Freetown project write-down.
</TABLE>
PAGE 53
<TABLE>
SCHEDULE VI
COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Dollars in Thousands)
<CAPTION>
Provision
Clearing Transfers
Balance at Nuclear Accounts Amortization of and Balance
Beginning of Charged to Fuel and Other Leasehold Removal at End
Classification Year Operations Expense Income Improvements Retirements Cost Salvage of Year
YEAR ENDED DECEMBER 31, 1993
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Electric $305 277 $32 188 $3 549 $ - $ 471 $ 7 046 $17 355 (A) $ 720 $317 804
Gas 73 187 8 939 - - 1 089 4 725 865 (49) 77 576
Other 27 605 1 353 - (6) - 53 (1 147) 57 30 103
Total Accumulated
Depreciation and
Amortization $406 069 $42 480 $3 549 $ (6) $1 560 $11 824 $17 073 $ 728 $425 483
YEAR ENDED DECEMBER 31, 1992
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Electric $280 011 $33 632 $3 696 $ - $ 470 $ 7 311 $ 6 292 $1 071 $305 277
Gas 66 389 8 270 - - 1 045 1 672 830 (15) 73 187
Other 26 587 1 262 - 315 - 116 443 - 27 605
Total Accumulated
Depreciation and
Amortization $372 987 $43 164 $3 696 $ 315 $1 515 $ 9 099 $ 7 565 $1 056 $406 069
YEAR ENDED DECEMBER 31, 1991
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Electric $251 742 $32 869 $3 823 $ - $ 481 $ 5 735 $ 3 439 $ 270 $280 011
Gas 60 720 7 910 - - 835 2 023 1 084 31 66 389
Other 25 592 1 172 - 300 - 74 403 - 26 587
Total Accumulated
Depreciation and
Amortization $338 054 $41 951 $3 823 $ 300 $1 316 $ 7 832 $ 4 926 $ 301 $372 987
<FN>
(A) Includes $11,010,000 of accumulated depreciation related to the abandoned Cannon Street generating station which
was reclassified to Deferred Charges.
</TABLE>
PAGE 54
SCHEDULE VIII
COMMONWEALTH ENERGY SYSTEM
AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
Additions
Balance Provision Deductions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written-Off of Year
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
Year Ended December 31, 1991
Allowance for
Doubtful Accounts $4 506 $10 943 $2 042 $12 258 $5 233
PAGE 55
SCHEDULE IX
COMMONWEALTH ENERGY SYSTEM
AND SUBSIDIARY COMPANIES
SHORT-TERM BORROWINGS(A)
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 and 1991
(Dollars in Thousands)
Weighted
Average Maximum Average Weighted
Category of Interest Amount Amount Average
Aggregate Rate OutstandingOutstanding Interest
Short-Term Balance at at End During During the Rate During
Borrowings End of Period of Period the Period Period (B) the Period (C)
Year Ended December 31, 1993
Notes Payable
to Banks $ 71 975 3.4% $165 525 $103 100 3.5%
Year Ended December 31, 1992
Notes Payable
to Banks $165 600 4.0% $165 600 $126 321 4.0%
Year Ended December 31, 1991
Notes Payable
to Banks $145 800 5.5% $150 875 $120 567 6.3%
(A) Refer to Note 5 of Notes to Financial Statements filed under Item 8 of
this report for the general terms of notes payable to banks.
(B) The average amount outstanding during the period is determined by
averaging the level of month-end principal balances outstanding using a
rolling thirteen-month period through December 31.
(C) The weighted average interest rate during the period is determined by
averaging the interest rates in effect on all loans transacted for the
twelve-month period ended December 31.
PAGE 56
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1993
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 24, 1994
William G. Poist,
President and Chief Executive Officer
Principal Financial Officer:
JAMES D. RAPPOLI March 24, 1994
James D. Rappoli,
Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 24, 1994
John A. Whalen,
Comptroller
A majority of the Board of Trustees:
SINCLAIR WEEKS, JR. March 24, 1994
Sinclair Weeks, Jr., Chairman of
the Board
SHELDON A. BUCKLER March 24, 1994
Sheldon A. Buckler, Trustee
HENRY DORMITZER March 24, 1994
Henry Dormitzer, Trustee
B. L. FRANCIS March 24, 1994
Betty L. Francis, Trustee
FRANKLIN M. HUNDLEY March 24, 1994
Franklin M. Hundley, Trustee
PAGE 57
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1993
SIGNATURES
(Continued)
March , 1994
William J. O'Brien, Trustee
WILLIAM G. POIST March 24, 1994
William G. Poist, Trustee
G. L. WILSON March 24, 1994
Gerald L. Wilson, Trustee
PAGE 58
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 17, 1994 included
in Exhibit A to the proxy statement for the 1994 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. 33-28435 and on Form S-3 File No. 33-44161.
It should be noted that we have not audited any financial statements of the
System subsequent to December 31, 1993 or performed any audit procedures
subsequent to the date of our report.
ARTHUR ANDERSEN & CO.
Arthur Andersen & Co.
Boston, Massachusetts,
March 30, 1994
PAGE 1
EXHIBIT 1
Commonwealth
Energy System
Notice of 1994
Annual Meeting,
Proxy Statement
and 1993 Financial
Information
Please sign and return your
proxy promptly
PAGE 2
COMMONWEALTH ENERGY SYSTEM
Cambridge, Massachusetts
Notice of Annual Meeting of Shareholders
May 5, 1994
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 5, 1994, at 10:30 o'clock A.M., Eastern Daylight Time, for the following
purposes:
1. To elect three Trustees to hold office for a three-year term and
until the election and qualification of their respective
successors.
2. To take action on a proposal by the Board of Trustees to amend
Section 22 of the System's Declaration of Trust, as amended,
to revise the conditions under which presently authorized
but unissued Common Shares of the System might be issued.
3. To approve the Long-Term Incentive Compensation Plan of
Commonwealth Energy System and Subsidiary Companies.
4. To consider and vote upon a shareholder proposal, if presented at
the meeting, as described herein.
5. To transact such other business as may properly come before the
meeting or any adjournment or adjournments thereof.
Common Shareholders of record at the close of business on March 18, 1994
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
April 1, 1994
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 Common-
wealth Energy System, P.O. Box 9150, Cambridge, Massachusetts 02142-9150.
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 5, 1994, 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.
Abstensions 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 purposes of determination
of a quorum or for the purposes 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
April 1, 1994.
FINANCIAL STATEMENTS
The audited financial statements of Commonwealth Energy System and
Subsidiary Companies, which include comparative Balance Sheets as of December
31, 1993 and 1992, Statements of Income and Statements of Cash Flows for the
three years ended December 31, 1993 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 18, 1994 are qualified to vote at the
meeting. There were outstanding as of the record date 10,345,619 Common
Shares.
The Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies owned beneficially 1,667,066 Common Shares representing 16.2% of the
outstanding Common Shares as of February 1, 1994. 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, 1994 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 4,745 0.1%
Russell D. Wright 3,850 0.1%
Kenneth M. Margossian 3,403 0.1%
Leonard R. Devanna 218 0.1%
Michael P. Sullivan 1,996 0.1%
All Trustees and Executive Officers
as a group (13 persons) 20,538 0.2%
(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.
PAGE 4
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, all of whom are presently Trustees:
Henry Dormitzer
Franklin M. Hundley
Gerald L. Wilson
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 nomi-
nees 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 1994
(B) SHELDON A. BUCKLER, Vice Chairman of the
(C) Board and Director, Polaroid Corporation,
Cambridge, Massachusetts (Manufacturer of
photographic equipment and supplies);
Director, Lord Corp.
TERM EXPIRES IN 1995 ................... (1991) 62 698
(B) HENRY DORMITZER, formerly Executive Vice
(D) President, Wyman-Gordon Company, Worcester,
Massachusetts (Producer of forgings for
aerospace and transportation industries)
TERM EXPIRES IN 1994 (NOMINEE).......... (1985) 59 400
(A) BETTY L. FRANCIS, Senior Finance Officer,
Bank of Boston Corporation, Boston,
Massachusetts
TERM EXPIRES IN 1995 ................... (1991) 47 100
(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 1994 (NOMINEE).......... (1985) 59 2,129
*WILLIAM J. O'BRIEN, formerly President
and Chief Executive Officer, The Hanover
Insurance Companies, Worcester,
Massachusetts
TERM EXPIRES IN 1996................... (1994) 61 1,000
*Mr. O'Brien was elected a Trustee on March 24, 1994 to fill the
vacancy on the Board of Trustees occasioned by the retirement of
Mr. Calvin Siegal.
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 1994
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) 60 4,745
(A) SINCLAIR WEEKS, JR., Chairman of the Board
(C) of Trustees of Commonwealth Energy System
(elected February 1, 1994); Chairman of
the Board and Director, Reed & Barton
Corp., Taunton, Massachusetts (Silverware)
TERM EXPIRES IN 1995 ................... (1981) 70 1,488
(B) GERALD L. WILSON, Vannevar Bush Professor of
(D) Engineering, Massachusetts Institute of
Technology, Cambridge, Massachusetts;
Director, Analogic Corp.
TERM EXPIRES IN 1994 (NOMINEE).......... (1985) 54 313
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, and 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.
In addition to the principal occupation listed above, Mr. Weeks is a
trustee of numerous registered investment companies for which Colonial
Management Associates Incorporated is investment advisor.
During 1993, fees of $1,169,351 were incurred for legal services
rendered by the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr.
Hundley is a Member and a Managing Director. The firm has been employed in
the last fiscal year and the current fiscal year.
Each Trustee, including nominees, owned beneficially less than one-third
of one percent of 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.
PAGE 6
COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1993
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 1993 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 1993 $291,888 $78,031 - - - - $11,604
President and Chief 1992 270,000 65,121 - - - - 10,800
Executive Officer of 1991 190,000 - - - - - -
the System and Chair-
man and Chief Exec-
utive Officer of its
principal subsidiary
companies
Russell D. Wright 1993 $195,000 $53,814 - - - - $ 7,704
President and Chief 1992 167,140 40,665 - - - - 6,884
Operating Officer 1991 154,743 - - - - - -
of Cambridge
Electric Light
Company, Canal
Electric Company,
COM/Energy Steam
Company and
Commonwealth
Electric Company
Kenneth M. Margossian 1993 $165,000 $47,256 - - - - $ 6,564
President and 1992 153,833 38,733 - - - - 6,120
Chief Operating 1991 118,000 - - - - - -
Officer of Common-
wealth Gas Company
and Hopkinton LNG Corp.
Leonard R. Devanna 1993 $133,333 $37,542 - - - - $ 6,603
Vice President-New 1992 124,167 29,939 - - - - 4,899
Business Development 1991 102,275 - - - - - -
of COM/Energy
Services Company
Michael P. Sullivan 1993 $131,000 $36,993 - - - - $ 5,160
Vice President, 1992 119,833 30,165 - - - - 4,728
Secretary/Clerk and 1991 111,000 - - - - - -
General Counsel
of the System
and its subsidiary
companies
</TABLE>
- --------------------
PAGE 7
(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/or 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
1993, there were no such perquisites, earnings, reimbursements or
discounts paid or made.
(3) In 1993, the System did not provide to its employees, including
Executive Officers, any 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 1993 on behalf of the
above-named individuals to the Employees Savings Plan and/or 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.
PAGE 8
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, 1993.
<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 .... $15,861 $23,796 $ 31,722 $ 39,657 $ 47,952 $ 51,775
120,000 .... 21,360 32,046 42,720 53,406 64,092 69,775
150,000 .... 26,859 40,296 53,718 67,155 80,592 87,775
180,000 .... 32,358 48,546 64,716 80,904 97,092 105,775
210,000 .... 37,857 56,796 75,714 94,653 113,592 123,775
240,000 .... 43,356 65,046 86,712 108,402 130,092 141,775
270,000 .... 48,855 73,296 97,710 122,151 146,592 159,775
300,000 .... 54,354 81,546 108,708 135,900 163,092 177,775
330,000 .... 59,853 89,796 119,706 149,649 179,592 195,775
360,000 .... 65,352 98,046 130,704 163,398 196,092 213,775
- -------------
<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 1993, the maximum annual compensation limit under the
Pension Plan for Employees of Commonwealth Energy System and Subsidiary
Companies was $235,840, and the maximum annual benefit under that Plan was
$115,641.
</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, Devanna and Sullivan have
29, 26, 24, 12 and 18 credited years of service respectively.
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
thirty-five percent of final base salary per year for life, or for a period of
PAGE 9
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 1993:
Compensation for the Chief Executive Officer, as well as for the named
Executive Officers, consists of base salary plus annual variable incentive
compensation of up to 30% of base salary, which is awarded if certain
designated performance criteria are achieved. The Executive Compensation
Committee has developed this compensation package in order to motivate
executive performance, enhance the profitability of the System and maximize
shareholder value.
The Chief Executive Officer's base compensation is determined by review
of comparative salary data and by evaluation of certain performance criteria.
The Executive Compensation Committee performs periodic comparisons of
executive compensation at other similarly sized utility companies.
Comparative data has been provided by external consulting services, the
System's human resource department and by reference to information provided by
industry sources such as the Edison Electric Institute. Base salary has been
continually reviewed and is adjusted to reflect the competitive market and the
performance of the Chief Executive Officer, as judged by the Executive
Compensation Committee on a subjective basis through the evaluation of
objective criteria.
The Chief Executive Officer's award for 1993 pursuant to the System's
Annual Incentive Plan (the "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 1993, the
System criteria forming the goals and objectives applicable to the Plan were:
1) total shareholder return as measured by stock appreciation plus dividend
rate and as compared to a representative peer group of investor-owned public
utilities as provided by Duff & Phelps Investment Research Co.; 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 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 total shareholder return was to meet or exceed the average
return for the peer group. The System realized a return of 15.25% in 1993,
compared to an industry peer group average of 9.46%, which resulted in the
maximum award as a result of exceeding the maximum target of 10% over the
industry peer group average. The goal established for cost control was for
operating and maintenance expenses in 1993 to be below the approved budgeted
amounts. This goal was achieved by the System having reduced actual operation
and maintenance expenses to 7.1% 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. The System was
rated eighth out of nineteen companies in the peer group. In the aggregate,
the goals and objectives applicable to the System component of the Plan were
rated as 92% achieved.
PAGE 10
The individual goals of the Chief Executive Officer for 1993 included:
organizational change relating to subsidiary operations, System strategic
planning documentation, improved regulatory relations, and the development of
an incentive award plan to align shareholder and management interests. The
Chief Executive Officer's performance relative to achieving individual goals
was rated as 85% achieved, resulting in an aggregate performance rating of
89.7% achievement.
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, including goals relating
to earnings levels and return on equity. 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 Plan to receive annual variable incentive compensation of
up to a maximum of 30% of annual base salary. In 1993, 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 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 the successful completion of debt and equity financings of
certain of the System's subsidiaries, and the maintenance of individual
department total annual expenses at amounts not exceeding approved budgets.
THE EXECUTIVE COMPENSATION COMMITTEE
Henry Dormitzer, Chairman
Sheldon A. Buckler
Gerald L. Wilson
PAGE 11
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
95 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 12/31/93)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1989-1993) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1988 1989 1990 1991 1992 1993
COM/Energy $100.00 $132.73 $124.98 $160.87 $188.19 $217.54
S&P 500 $100.00 $131.49 $127.32 $166.21 $179.30 $197.23
Peer Group $100.00 $130.25 $131.97 $170.41 $183.14 $203.88
Assumes $100 invested at the close of trading on the last trading day of
1988 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.
Cincinnati Gas & Electric Co. Otter Tail Power Co.
CIPSCO Incorporated Pacific Gas & Electric Co.
CMS Energy Corp. PacifiCorp.
PAGE 12
Commonwealth Edison Company PECO Energy Company
Commonwealth Energy System Pennsylvania Power & Light Co.
Consolidated Edison Co. of New York, Inc. Pinnacle West Capital Corp.
DPL Inc. Portland General Electric Co.
Delmarva Power & Light Company Potomac Electric Power Co.
The Detroit Edison Company PSI Resources, Inc.
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
Gulf States Utilities Co. Southern Indiana Gas & Electric Co.
Hawaiian Electric Co., Inc. Southwestern Public Service Co.
Houston Industries Incorporated TECO Energy, Inc.
Idaho Power Co. Texas Utilities Company
IES Industries TNP Enterprises, Inc.
Illinois Power Co. Tucson Electric Power Co.
Interstate Power Co. Union Electric Co.
Iowa-Illinois Gas and Electric Company United Illuminating Co.
IPALCO Enterprises, Inc. UtiliCorp. United Inc.
Kansas City Power & Light Co. Washington Water Power Co.
KU Energy Corporation Western Resources Inc.
LG&E Energy Corp. Wisconsin Energy Corp.
Long Island Lighting Co. Wisconsin Public Service Corp.
MDU Resources WPL Holdings, Inc.
Midwest Resources Inc.
MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES
The System's Board of Trustees held thirteen meetings throughout 1993.
The Board has an Audit Committee, an Executive Compensation Committee, a
Nominating Committee and a Benefit Review Committee.
The Audit Committee is composed of Betty L. Francis, Chairperson, and
Sinclair Weeks, Jr. The Committee held four meetings in 1993. 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 1993 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
four meetings in 1993. The functions of the Committee are: to coordinate
PAGE 13
suggestions or searches for potential nominees for the position of Trustee; to
review and evaluate qualifications of potential nominees; and to recommend to
the Board of Trustees nominees for vacancies occurring from time to time on
the Board of Trustees. The Committee will consider nominees recommended by
Shareholders upon the timely submission of the names of such nominees with
their qualifications and biographical information forwarded to the Nominating
Committee of the Board of Trustees.
The Benefit Review Committee is composed of Franklin M. Hundley,
Chairperson, Henry Dormitzer and Gerald L. Wilson. During 1993 the Committee
held two meetings. The Committee was organized to consider and recommend to
the Board of Trustees matters associated with the System's major funded
benefit plans. Functions of the Committee include: recommending the
composition of benefit plan boards and reviewing investment policy,
objectives, performance or proposed changes related to the plans.
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 $750 for
each Trustee and Committee meeting attended. The Chairpersons of the Audit,
Executive Compensation and Benefit Review Committees each receive an
additional $1,000 during the year. In addition, the Chairman of the Board
receives a retainer of $10,000 per annum 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 will be payable to Trustees for a period of ten years.
2-AMENDMENT TO SECTION 22 OF THE DECLARATION OF TRUST
There will be presented to Shareholders by the Board of Trustees a
proposal to consent to an amendment to Section 22 of the System's Declaration
of Trust, which Section sets forth the conditions under which presently
authorized but unissued Common Shares of the System may be issued by the
Trustees without the vote or written consent of a majority of the Common
Shares outstanding at the time. The purposes of the amendment are to expand
the conditions under which such presently authorized but unissued Common
Shares may be issued without the vote or written consent of a majority of the
Common Shares outstanding at the time, and to also delete some of the existing
conditions under which such authorized but unissued shares may be issued, due
to the fact that certain events which have occurred in the last ten years make
such provisions no longer applicable. The text of the proposed amendment to
Section 22 is annexed as Appendix A to this Proxy Statement.
PAGE 14
The proposed amendment to Section 22 would allow for the issuance of
Common Shares to fund long-term compensation plans which might be adopted by
the Board of Trustees from time to time. The Trustees believe that such
amendment would be in the interests of Shareholders, as it will enable the
System to attract and retain qualified employees and will provide to such
employees further incentive to maximize shareholder value for the benefit of
Shareholders. Under the terms of the Commonwealth Energy System and
Subsidiary Companies Long-Term Incentive Compensation Plan, which Shareholders
are being requested to approve pursuant to Item 3 of this Proxy Statement, no
issuance of Common Shares will be made to employees until certain benchmarks,
set to require that Shareholders' interests have first been protected, have
been met. The Board of Trustees believes that the Long-Term Incentive
Compensation Plan will provide key employees with greater incentive and that
it will enable the System to attract and retain highly qualified executives
and other key employees in the future, and will advance the operational and
financial interest of the System by better aligning the interests of key
employees with the interests of Shareholders.
The required approval by Shareholders to the proposed amendment and the
subsequent enactment of the Long-Term Incentive Compensation Plan will allow
the System to continue to employ and to keep in employment valuable employees
who will continue to advance the interests of Shareholders.
With respect to the proposed amendment which eliminates the references
to Algonquin Energy, Inc. in subparagraphs 3 and 4 of the third paragraph of
Section 22 of the Declaration of Trust, such elimination simply reflects the
sale by the System of its interest in Algonquin Energy, Inc. in 1986.
Upon the consent of the holders of a majority of the outstanding Common
Shares present at the meeting and entitled to vote on the proposed amendment,
the Trustees of the System will on May 5, 1994 vote to amend the Declaration
of Trust and will file said Declaration of Trust, as amended, as required by
the terms of the Declaration of Trust and the laws of the Commonwealth of
Massachusetts.
THE TRUSTEES RECOMMEND A VOTE "FOR" THE APPROVAL OF THE AMENDMENT.
3-LONG-TERM INCENTIVE COMPENSATION PLAN
On February 16, 1994, the Board of Trustees approved and adopted the
Commonwealth Energy System and Subsidiary Companies Long-Term Incentive
Compensation Plan ("Incentive Plan") for key employees of the System and its
subsidiaries. Since the Incentive Plan awards are to be paid in the form of
System Common Shares, the Board of Trustees is seeking Shareholder approval of
the Incentive Plan and has conditioned adoption of the Incentive Plan on
Shareholder approval.
The following is a summary of the principal features of the Incentive
Plan. The summary is qualified in its entirety by reference to the complete
text of the Incentive Plan, which is attached to this Proxy Statement as
Appendix B.
The Incentive Plan is intended to compensate the System's key employees
based upon performance standards and objectives and to reward performance with
Share ownership in the System so that key employees have a greater proprietary
interest in the System. The Incentive Plan will provide for competitive,
market-based total compensation for key employees comprised of base salary
PAGE 15
plus incentive salary, including Common Shares issued to such key employees
under the Incentive Plan that is at risk. The Board of Trustees believes that
the Incentive Plan will provide key employees with greater incentive and that
it will enable the System to attract and retain highly qualified executives
and other key employees in the future, and will advance the operational and
financial interest of the System by better aligning the interests of key
employees with the interests of Shareholders.
An Incentive Plan Period shall have a three year term, with the first
Plan Period commencing on January 1, 1994. The Incentive Plan will be
administered by members of the Executive Compensation Committee of the Board
of Trustees, none of whom may participate in the Plan. The Executive
Compensation Committee will have full authority to interpret and administer
the Incentive Plan, including the authority to determine the key employees who
will participate in the Incentive Plan and the performance standards that will
be used to determine the amounts of Incentive Awards that can be earned under
the Incentive Plan. No Incentive Award shall be made by the Executive
Compensation Committee without the prior approval of a majority of the members
of the Board of Trustees of the System who at the time are ineligible to
participate in the Plan. Awards under the Plan may be made until February 16,
2003.
The Incentive Plan provides that key employees designated by the
Executive Compensation Committee can earn a portion of their compensation
("Incentive Awards") based upon total Shareholder return criteria as set from
time to time by the Executive Compensation Committee. No Incentive Awards are
earned under the Incentive Plan unless certain Shareholder success criteria
are met with respect to total Shareholder return. In addition, no Incentive
Awards will be earned if the System's average return on equity for any Plan
Period does not achieve at least 80 percent of the target return over the
performance period.
The System's Chief Executive Officer, the presidents of the System's
operating companies, all vice presidents of the System's subsidiary companies
and certain other senior management employees designated by the Executive
Compensation Committee are eligible to participate in the Incentive Plan.
Incentive Awards are established for each Plan Period for Incentive Plan
participants and are calculated as a percentage of the employee's annual base
salary as of January 1 at the beginning of the Plan Period. For the initial
Plan Period, the Incentive Awards range up to 50% of salary for Messrs. Poist,
Wright and Margossian and up to 40% of salary for the 11 vice president
participants, including Messrs. Devanna and Sullivan. The initial shareholder
category Incentive Award standards, which use the same Peer Group Index used
to compare total shareholder return of the System's Common Shares as described
on page 7 in this Proxy Statement, and the Incentive Award Potentials for the
initial Plan Period are as follows:
Shareholder Total Return Standards
Threshold Plan Target Maximum
95% of Index Average Index Average 120% above Index Average
Incentive Award Potentials
Plan
Participant Threshold Target Maximum
CEO and Operating
Company Presidents 16.5% 33.5% 50.0%
Vice Presidents 13.0 27.0 40.0
PAGE 16
Incentive Awards shall be awarded in the form of the System's Common
Shares ("Grant Shares"). The number of Common Shares awarded will be based on
the average market price of the System's Common Shares during the first five
trading days of the February following the close of the Plan Period. Provided
that the amendment to the System's Declaration of Trust hereinbefore described
is approved, the Common Shares which are awarded may be directly issued to the
Incentive Plan participants. The maximum number of Common Shares in respect
for which Grant Shares may be cumulatively granted under the Incentive Plan,
subject to adjustment as provided in Paragraph 11 of the Incentive Plan,
during the term in which the Incentive Plan is effective, shall be one percent
(1%) of the total issued and outstanding Common Shares of the System.
Shares awarded will be subject to forfeiture to the System and cannot be
transferred for a period of three years from the date of each Incentive Award.
Such forfeiture will generally occur on termination of employment within the
three-year period. The three-year forfeiture and non-transferability period
will terminate automatically in the event of death, disability, or a change in
control as defined in the Incentive Plan, or, at the Executive Compensation
Committee's discretion upon normal retirement. During such three-year period,
Incentive Plan participants will own the Shares awarded and will have the
right to vote such Shares and receive dividends and other distributions.
Participants will generally be subject to federal income taxation on receipt
of Shares awarded in the year in which the three-year forfeiture and non-
transferability periods lapse, based upon the market value at the date of
lapse.
Reference is made to "Executive Compensation," pages 4 through 7 above,
for information regarding various other employee benefit plans and agreements
of the System. None of the prospective Executive Officer participants in the
Incentive Plan received any payments or distributions during the last three
fiscal years, other than salary and cash compensation pursuant to the employee
benefit plans and agreements described on pages 4 and 5 in this Proxy
Statement, and annual incentive compensation earned and awarded to the persons
and in the amounts set forth on page 4 of this Proxy Statement.
The adoption of the Incentive Plan will require the affirmative votes of
the holders of a majority of the Shares present at the meeting and entitled to
vote. If approved by the Shareholders, the Incentive Plan will be effective
for the System's 1994 fiscal year.
THE TRUSTEES RECOMMEND A VOTE "FOR" THE ADOPTION OF THE LONG-TERM
INCENTIVE COMPENSATION PLAN.
4-SHAREHOLDER PROPOSAL
The System has been advised that Mr. John Jennings Crapo, Porter Square
Branch, P.O. Box 151, Cambridge, Massachusetts, 02140-0002, holder of 225
Common Shares, proposes to submit the following proposal at the 1994 Annual
Meeting:
RESOLVED: That the Shareholders of Commonwealth Energy System assembled
in Annual Meeting of Shareholders balloting in person and by Proxy hereby
request that the Board of Trustees present to shareholders at the next Annual
Meeting of Shareholders an appropriate amendment to the DECLARATION OF TRUST,
dated December 31, 1926, as amended, to provide that at any elections
following the adoption of the said amendment, Trustees whose terms have
expired be elected annually and not by classes as is now provided.
PAGE 17
SUPPORTING STATEMENT: The Proposal received enough votes at the May 06,
1993 Annual Meeting of Shareholders to be considered again, so ruled System
Chief Executive Officer, the Honorable President William G. Poist. The vote
was announced at the meeting and in compliance with my request at said
meeting, System Vice President, General Attorney, and Secretary, Mr. Michael
P. Sullivan, Esquire, sent me by mail a written report of the vote concerning
the Proposal.
The vote was this way:
1,689,952 Common Shares or 16.9% were voted "For" the Proposal
5,726,876 Common Shares or 56.2% were voted "Against" the Proposal
288,974 Common Shares or 2.8% "Abstained" from the Proposal.
Mr. Vice President added 'As a result and in accordance with the applicable
regulations you are entitled to bring forth your proposal at the 1994 Annual
Meeting of Shareholders.'
The Board of Trustees have continued to offer very persuasive arguments in
behalf of retaining the staggered system of electing Trustees, to such an
extent I had begun to think maybe I had the wrong idea on the matter. I
offered a Proposal to a New England utility to institute at it classified
elections of Trustees. Due to slow mail the Proposal didn't arrive in time to
be considered timely but an official of that utility assured me January 21,
1993, in his letter, that the directors at that company 'keep informed of
developments that could have an adverse impact on our shareholders' best
interest.' I was alarmed that mutual funds could take the utility over and he
said the company is regulated under the Public Utility Act of 1935 and under
that Act a person or company must obtain the approval of the SEC to acquire 5%
or more of the voting stock of a public utility holding company. In addition,
if a person or company owns more than 10% of the voting stock, it becomes
subject to regulation as a public utility holding company. Few companies,
other than utilities, would want to subject themselves to such rigorous
regulation.'
We're all stockholders, not just the Trustees, so I feel we all have a right
to decide this and our System Trustees should offer us additional arguments as
to why we shouldn't reinstitute annual elections to all Trustees.
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
1995 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 assure
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.
PAGE 18
The Board believes 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 1995 Annual Meeting of
Shareholders) requires the affirmative vote or written consent of three-
quarters of the shares entitled to vote (by the terms of the System's
Declaration of Trust).
ACCORDINGLY, A VOTE "AGAINST" THE PROPOSAL IS RECOMMENDED.
5-OTHER BUSINESS
The Board of Trustees of the System knows of no matters other than those
set forth in the Notice of the Annual Meeting which are likely to be brought
before the meeting. 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 & Co. It is expected that
representatives of Arthur Andersen & Co. 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 $5,000 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 1995 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, 1994.
PAGE 19
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
April 1, 1994
PAGE 20
APPENDIX A
PROPOSED AMENDMENT TO
SECTION 22 OF THE DECLARATION OF TRUST
Section 22 of the System's Declaration of Trust would be amended (1) by
deleting subparagraph (A)(3), which contains the words "to acquire additional
stock of Algonquin Energy, Inc.;" (2) by deleting in the second line of the
existing subparagraph (A)(4) the words "of Algonquin Energy, Inc., or" and (3)
by adding the following new subparagraph (C) "To provide Common Shares to fund
long-term incentive compensation plans that may be adopted from time to time",
so that the third paragraph of Section 22 reads in its entirety, as
follows:
(A) To provide the System with Funds
(1) To acquire additional stock of any subsidiary of the
System which is authorized for its proper corporate purposes;
(2) To acquire common stock of any Massachusetts gas or
electric company if as a result of such transaction the System
will own 51% or more of such stock;
(3) To acquire debt securities maturing more than one year
from the date of issue thereof of any subsidiary of the System;
(4) To retire temporary indebtedness of the System incurred
by it for the purchase of such stock or debt securities; or
(5) To make temporary advances to any subsidiary of the
System; or
(B) In Exchange
(1) For publicly held stock of any subsidiary of the System;
or
(2) For stock of any Massachusetts gas or electric company
if as a result of such exchange the System will own 51% or more
of such stock; or
(C) To provide Common Shares to fund long-term incentive compensation
plans that may be adopted from time to time.
PAGE 21
APPENDIX B
COMMONWEALTH ENERGY SYSTEM
AND SUBSIDIARY COMPANIES
Long-Term Incentive Compensation Plan
1. Purpose. The purpose of this Plan is to advance the interests
of Commonwealth Energy System (the "System") by providing
long-term financial incentives to selected key employees of
the System and its subsidiaries for achieving specified
objectives. The Plan is designed to recognize and reward
success relative to Plan objectives and permit participants
to acquire Common Shares of the System ("Shares"). By
encouraging such share ownership, the System seeks to
attract, retain and motivate employees of experience,
ability and quality and to strengthen the mutuality of
interests between such key employees and the System's
common shareholders.
2. Plan Term. The Plan became effective on February 16, 1994,
(the "Effective Date"), the date it was adopted by the Board
of Trustees of the System, provided the Plan is approved by
common shareholders at the next annual meeting of shareholders
of the System following the Effective Date. If such approval
is not granted, the Plan shall become null and void. Awards
under the Plan may be granted through February 16, 2003.
3. Administration.
(a) The Plan shall be administered by the Executive
Compensation Committee of the Board of Trustees of
the System (the "Committee"). The members of the
Committee shall not be eligible to participate in
the Plan and shall be disinterested persons as
defined in Rule 16(b)-3(c) under the Securities
Exchange Act of 1934 (the "Exchange Act").
Subject to the provisions of the Plan, the
Committee shall have full power to construe and
interpret the Plan and to establish, amend and
rescind rules and regulations for its administration.
The interpretation and construction by the
Committee of any provision of the Plan or an
award ("Incentive Award") granted pursuant to the
Plan and any determination by the Committee
pursuant to any provision of the Plan or any
such Incentive Award shall be final and conclusive,
and binding on both the Participant (as defined in
paragraph 4) and the System. All Incentive Awards
shall be made in the form of Shares ("Grant Shares").
Notwithstanding the foregoing or any other
provision of the Plan, no Incentive Award shall be
made by the Committee without the prior approval of
a majority of the members of the Board of
Trustees of the System who at the time are ineligible
to participate in the Plan and who are disinterested
persons as defined in Rule 16(b)-3(c) under the
Exchange Act.
PAGE 22
(b) The Committee shall hold meetings at such times and
places as it may determine. A majority of members
of the Committee shall constitute a quorum and
actions approved by a majority of the members of
the Committee at a meeting at which there is a
quorum, or actions approved in writing by a
majority of the members of the Committee, shall
be valid actions of the Committee.
4. Eligible Employees. Participants in the Plan shall comprise
such key employees of the System or of any of its subsidiaries
(including members of the Board of Trustees who are also
employees of the System or any of its subsidiaries) as
are selected by the Committee from time to time (any such
selected employee being referred to as a "Participant").
To be eligible for a Grant Share award, the designated
employee must be an officer or other senior employee who
holds a position of significant responsibility. Grant
Shares shall consist of restricted Shares of the System
and shall be subject to the provisions of this Plan.
5. Shares Subject to the Plan. The maximum number of Grant
Shares which may be cumulatively granted under the Plan,
subject to adjustment as provided in Paragraph 11 of the
Plan, during the term in which the Plan is effective,
shall be one percent (1%) of the total issued and
outstanding Shares. Any Grant Shares which are forfeited
pursuant to paragraph 9 (g)(i) shall again be eligible
for issuance.
6. Incentive Awards.
(a) Incentive Award Potential. A Plan Period shall
be three years, commencing on January 1 and
terminating on the December 31 occurring two
years after the year in which the period commenced.
The first Plan Period shall commence on January 1,
1994 and conclude on December 31, 1996. No Plan
Period shall commence in 1995. The second Plan
Period shall commence on January 1, 1996, and
conclude on December 31, 1998. The Committee, in its
sole discretion, may amend or modify the commencement
and duration of Plan Periods.
As soon as practicable during each Plan Period, the
Committee shall (i) designate those individuals who
are to be Participants hereunder in the Plan for such
Plan Period, (ii) assign each such Participant a
level of participation in the Plan for such Plan Period
and (iii) establish for each level of participation
the threshold, target and maximum Incentive Award
Potential, expressed in each case as a percentage of
the Participant's annual base salary as of January 1
at the beginning of the Plan Period. The Incentive
Award Potentials for the Participants in the Plan
for the Plan Period terminating December 31, 1996,
(Plan Period 1994), are set forth in Table 1 below.
PAGE 23
Incentive Award potentials applicable to levels of
participation in the Plan for Plan Periods subsequent
to 1994 shall be established by the Committee from
time to time as provided above.
TABLE 1
1994 Incentive Award Potentials
(Plan Period 1-1-94 through 12-31-96)
Plan
Participant Level Threshold Target Maximum
CEO and Operating
Company Presidents 1 16.5% 33.5% 50.0%
Vice Presidents 2 13.0 27.0 40.0
The amount of each Participant's actual Incentive
Award (if any) hereunder will depend upon the System's
achievement of specified performance criteria set
forth in subparagraph (b) below and subject to the
satisfaction of the provisions of paragraph 8.
(b) Performance Evaluation. The Committee shall evaluate
the System's performance relative to a specified
shareholder success criterion for the three years
comprising a Plan Period. For the 1994 Plan Period,
the shareholder success criterion shall be the System's
three-year average shareholder total return results
(share appreciation and dividends) compared to the
Peer Group Index of utility companies published by
Value Line, Inc.
The Committee shall establish performance standards
for each Plan Period in such a manner as to promote
achievement of meaningful total return results. Three
levels of performance standards shall apply and be set
by the Committee. Except in the 1994 Plan Period, the
three levels of performance standards shall be set
prior to the onset of a Plan Period. For the 1994 Plan
Period, the shareholder total return standards are set
forth in Table 2.
TABLE 2
1994 Plan Period
Shareholder Total Return Standards
Threshold Plan Target Maximum
95% of Index Average Index Average 120% of Index Average
PAGE 24
If the System's performance for any Plan Period
results in its achieving the Threshold, Plan Target
or Maximum performance standard, the earned Incentive
Award shall be determined by the levels set forth in
Table 1. If achieved results fall between the
Threshold, Plan or Maximum performance standards, the
Incentive Award shall be determined by interpolation.
If performance falls below the Threshold, there will
be no Incentive Award.
7. Discretionary Incentive Awards. In addition to Incentive Awards
pursuant to paragraph 6 hereof, the Committee may, in its sole
discretion, make an Incentive Award with respect to a Plan
Period to an employee of the System who, upon recommendation
by the System's Management Committee, is deemed to be an
exceptional performer. The maximum discretionary Grant Share
Award hereunder for a Plan Period to any Participant who is not
an officer may not exceed 10% of such Participant's annual base
salary as of January 1 at the beginning of the Plan Period.
All such Incentive Awards shall also be subject to the provisions
of paragraph 8.
8. Shareholder Protection. No grant of an Incentive Award
shall be made for any Plan Period in which the System's
average return on equity does not achieve at least 80
percent of the target return over the performance period
as established by the Committee.
9. Terms and Conditions of Grant Shares. Grant Shares may
be issued pursuant to the Plan and shall be subject to
the following terms and conditions:
(a) Price. Grant Shares shall be issued in consideration
of services rendered by the Participant.
(b) Number of Shares. The number of Grant Shares
issued to each Participant, if any, shall be
determined by dividing the amount of a Participant's
Incentive Award or the Committee's discretionary
award of Grant Shares by the average closing price
for the Shares on the principal national securities
exchange on which the Shares are listed or admitted
to trading on the first five (5) trading days of
the February following the close of the Plan Period.
Fractional Shares shall be rounded up or down to
whole Shares.
(c) Match Shares. The Committee shall award any
Participant who accumulates a Grant Share balance
equal in value to 100 percent of the Participant's
base salary an additional award of Grant Shares
in an amount equal to 10 percent of the Participant's
base salary in effect on January 1 during the year
during which the 100 percent value is realized. Grant
Share balance shall mean the cumulative total of
all Grant Shares issued and retained exclusive of
PAGE 25
the present award. The number of Grant Shares
awarded shall be found by dividing the award value
of 10 percent of the Participant's base salary by
the average closing price of the Shares on the
principal national securities exchange on which
the Shares are listed or admitted to trading on
the first five (5) days of the February following
the close of the Plan Period. Each succeeding
25 percent of base salary held as Grant Shares
in addition to the 100 percent value shall be
similarly matched by an additional award of Grant
Shares at the rate of five (5) percent
of base salary.
(d) Forfeiture of Grant Shares. Grant Shares issued
under this Plan shall be subject to forfeiture as
specified in paragraph 9 (g)(i).
(e) Non-Transferability. To the extent that any Grant
Shares remain subject to the forfeiture provisions
of paragraph 9 (g)(i), they shall be non-transferable
by the Participant and may not be pledged,
hypothecated or otherwise encumbered.
(f) Withholding Taxes. At the time that the interest of
a Participant in Grant Shares vests and as a condition
of the System's obligation to deliver a certificate
for such Grant Shares to the Participant, the
Participant shall pay to the System an amount equal
to all taxes required to be withheld by the System
for the account of the Participant as a result
of such issuance; or, in lieu of such payment, the
System may, at its sole option, accept the written
authorization of the Participant to withhold such
taxes from compensation thereafter becoming
payable to the Participant by the System. If the
Participant shall elect under Section 83 of the
Internal Revenue Code of 1986, as amended, to
accelerate the recognition of income attributable
to the receipt of Grant Shares, the Participant
shall furnish the System with a copy of such election
concurrently with its filing with the Internal
Revenue Service and shall pay the System the amount
of taxes required to be withheld for the account
of the Participant by reason of such election.
(g) Vesting.
(i) The interest of a Participant in Grant Shares
shall vest on the date three (3) years from
the date such Grant Shares were issued to
the Participant, except as provided in
subparagraph (ii), below, provided that the
Participant shall have remained employed by
the System one of its subsidiaries during the
three-year period immediately following the
date the Grant Shares were issued to the
Participant. If the Participant fails to
complete such three-year employment requirement
PAGE 26
and his or her interest in the Grant Shares is
not otherwise vested under subparagraph (ii),
below, the Participant shall forfeit to the
System all unvested Grant Shares theretofore
issued to such Participant and the Participant
shall thereafter have no further rights with
respect to such Grant Shares.
(ii) Notwithstanding the foregoing, a Participant's
interest in Grant Shares may become vested
at a date earlier than three years from the
date of issue for such reasons as may be
specified by the Committee, in its sole discretion
at the time of or subsequent to an award of
Grant Shares and shall become immediately
vested upon any one of the following occurrences:
(A) The Participant's employment by the System
or any of its subsidiaries terminates by
reason of such Participant's death or
disability (as defined in Section 72(m)(7)
of the Internal Revenue Code of 1986, as
amended); or
(B) There is a "change in control" of the
System. For the purposes of this Plan, a
"change in control" shall mean the occurrence
of any of the following:
(1) The System receives a report on
Schedule 13D filed with the Securities
and Exchange Commission disclosing that
any person (as such term is defined in
Section 13(d) of the Exchange Act), group,
partnership, association, corporation or
other entity is the beneficial owner,
directly or indirectly, of 20% or more
of the outstanding voting Common Shares of
the System (other than: 1) a registered
investment company which has expressly
stated that it has no intention to
acquire control of the System or which
the Committee has determined that such
registered investment company has no
intention to acquire control of the
System and 2) the Employees Savings
Plan of Commonwealth Energy System and
Subsidiaries); provided that if the
Committee subsequently determines that
such registered investment company does
intend to acquire control of the System
PAGE 27
or the registered investment company
expresses this intent, the beneficial
ownership of 20% or more of the outstanding
voting Common Shares of the System shall
be considered to be a "change in
control" event described in this
clause (1);
(2) Any person (as such term is defined in
in Section 13(d) of the Act), group,
partnership, association, corporation
or other entity other than the System
or a wholly-owned subsidiary of the
System, purchases Shares pursuant to
a tender offer or exchange offer to
acquire voting Shares (or securities
convertible into shares) for cash,
securities or any other consideration,
provided that after consummation of the
offer, the person, group, partnership,
association, corporation or other
entity in question is the beneficial
owner (as defined in Rule 13(d)-3 under
the Act) directly or indirectly, of
20% or more of the then outstanding
voting Common Shares of the System
(calculated as directed in paragraph (d)
of Rule 13(d)-3 under the Act in the
case of rights to acquire Common Shares);
(3) The Trustees of the System approve (a)
any consolidation or merger of the System
in which the System is not the continuing
or surviving entity or pursuant to
which Common Shares of the System would
be converted into cash, securities or
other property; or (b) any transaction
or series of related transactions the
result of which all or substantially all
the assets of the System are sold;
(4) The System ceases to be a reporting
company pursuant to Section 13(a) of the
Securities Exchange Act of 1934 or any
similar successor provision; or
(5) During any period of two consecutive
years (24-month period), individuals
who at the beginning of such period
constituted the Board of Trustees of the
System cease for any reason (other than
retirements or resignations in the
normal course of business) to constitute
a majority thereof; provided, however,
that any Trustee who is not in office
PAGE 28
at the beginning of such 24-month period,
but whose election by the Board of Trustees
or whose nomination for election by the
System's Common Shareholders was to fill
a vacancy caused by death or retirement
and was approved by a vote of at least
two-thirds of the Trustees then still in
office and who either were Trustees at the
beginning of such period or whose election
or nomination for election was previously
so approved, shall be deemed to have
been in office at the beginning of such
period for purposes of this definition.
(iii) If a Participant's employment by the System or one
of its subsidiaries terminates during the three-
year employment period described in paragraph 9(g)(i)
by reason of his or her retirement, as determined
by the Committee, the Committee may, in its
discretion, specify that the interest of the
Participant in any Grant Shares then subject to
forfeiture shall become vested at that time, at
a future date, or upon the completion of such
other conditions as the Committee may provide.
10. Rights as Shareholder. Except as otherwise provided in
paragraphs 9 and 13, a Participant shall have all of the rights
of a shareholder of the System with respect to the Grant Shares
registered in his or her name, including the right to vote such
Grant Shares and receive dividends and other distributions
paid or made with respect to such Grant Shares. A Participant
shall have the right to purchase Shares from such dividends
and/or to reinvest dividends through the System's Dividend
Reinvestment and Common Share Purchase Plan, and any such
Shares purchased shall be immediately vested and not subject
to forfeiture.
11. Share Dividends; Share Splits; Share Combinations; Recapitalization.
The Board of Trustees of the System may make appropriate
adjustments in the maximum number of Shares subject to the Plan
to give effect to any share dividends, Share splits, Share
combinations, recapitalizations and other similar changes in
the capital structure of the System. The provisions contained
in the Plan shall apply to any other capital shares of the
System, and any other securities which may be acquired by
the Participant as a result of a Share dividend, Share split,
Share combination, or exchange for other securities resulting
from any recapitalization, reorganization or any other
transaction affecting the Grant Shares.
12. No Employment Commitment; Tax Treatment. Nothing herein
contained shall be deemed to be or constitute an agreement
or commitment by the System to continue the Participant
in its employ. The System makes no representation about
the tax treatment to the Participant with respect to
receiving, holding or disposing of the Grant Shares,
including the possible application of Section 83 of the Code.
PAGE 29
13. Legends. Unless and until Grant Shares are fully vested,
certificates evidencing ownership of Grant Shares shall
be kept under the possession and control of the System
and shall contain appropriate statements setting forth
the conditions and restrictions applicable to such
Grant Shares as are set forth herein. At the time
restrictions have lapsed, the System will, upon satisfaction
by the Participant of all withholding and other tax
obligations, issue a new certificate without restrictions.
14. Termination or Amendment of Plan.
(a) Except as provided in paragraph 14(b), the Board of
Trustees may at any time suspend, reinstate, or
terminate the Plan or make such changes in or additions
to the Plan as it deems advisable without further
action on the part of the shareholders of the System,
provided:
(i) that no such termination or amendment shall
adversely affect or impair any then issued and
outstanding Grant Shares without the consent
of the Participant holding such Grant Shares; and
(ii) that no such amendment which (a) materially
increases the maximum number of Grant Shares
subject to this Plan; (b) materially increases
the benefits accruing to Participants under
the Plan; or (c) materially modifies the
requirement as to eligibility for participation
in the Plan may be made without first obtaining
shareholder approval if independent legal
counsel advises that such approval is necessary.
(b) In the event of a change in control (as defined in
Section 9 (g)(ii)), the System may neither terminate
the Plan nor reduce benefits under the Plan with
respect to those individuals who are Participants as
of the date of the change in control.
15. Indemnification of Committee. In addition to such other rights of
indemnification as they may have as Trustees or as members of the
Committee, each member of the Committee shall be indemnified by
the System against the reasonable expenses, including attorneys'
fees, actually and necessarily incurred in connection with the
defense of any action, suit or proceeding, or in connection with
any appeal therein, to which he/she may be a party by reason of
any action taken or any failure to act under or in connection with
the Plan, or any Incentive Award granted thereunder, and against
all amounts paid by him/her in settlement thereof, provided such
settlement is approved by independent legal counsel selected
by the System, or paid by him/her in satisfaction of a judgment
in any such action, suit or proceeding that such Committee
member is liable for misconduct in his or her duties;
PAGE 30
provided that within 60 days after the institution of such
action, suit or proceeding, the Committee member shall in
writing offer the System the opportunity, at its own expense,
to handle and defend the same.
16. Governing Law. This Plan shall be subject to and construed
in accordance with the laws of the Commonwealth of Massachusetts.
PAGE 31
Commonwealth
Energy System
1993 Financial
Information
Exhibit A
PAGE 32
CONTENTS
Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 33
Management's Report............................................ 46
Report of Independent Public Accountants....................... 47
Consolidated Balance Sheets.................................... 48-49
Consolidated Statements of Income.............................. 50
Consolidated Statements of Cash Flows.......................... 51
Consolidated Statements of Capitalization...................... 52
Consolidated Statements of Changes in Common Shareholders'
Investment and Consolidated Statements of Changes in
Redeemable Preferred Shares.................................. 53
Notes to Consolidated Financial Statements..................... 54-66
Selected Financial Data........................................ 67
PAGE 33
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:
1993 1992 1991
Per Per Per
Amount Share Amount Share Amount Share
(Dollars in Thousands Except Per Share Amounts)
Electric $28,742 $2.82 $23,295 $2.31 $29,249 $2.94
Gas 15,746 1.54 13,253 1.32 2,024 .20
Other 116 .01 2,058 .20 1,652 .17
44,604 4.37 38,606 3.83 32,925 3.31
Freetown write-down - - - - (14,805) (1.49)
Total $44,604 $4.37 $38,606 $3.83 $18,120 $1.82
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.
1993 versus 1992
In 1993, earnings improved by 15.5% due, in part, to a significant
reduction in other operation expense ($12.6 million or 6.1%) that reflects the
system's continued cost containment efforts. These efforts included the
shutdown of the Cannon Street generating station in late 1992 which had a $1.5
million impact on other operation expense and a second quarter work force
reduction that provided a net payroll savings of $1.6 million. A $2.7 million
decline in the provision for bad debt expense that resulted from improved
collection experience also contributed to the reduction in other operation.
Other factors contributing to the improved earnings were: 1) higher retail
electric unit sales as well as an increase in firm gas sales during the
heating season; 2) new base rates for Cambridge Electric Light Company,
effective June 1, 1993 ($7.2 million on an annual basis); 3) the recognition
of "lost base revenues" ($2.4 million) relating to electric conservation and
load management (C&LM) programs; and 4) the reversal of a reserve ($3.8
million) following the resolution of uncertainties related to the system's
Seabrook investment which was included in retail base rates by the
Massachusetts Department of Public Utilities (DPU) in Cambridge Electric's
June 1993 rate order.
1992 versus 1991
Contributing to the overall increase in 1992 operating results were:
1) significantly improved gas operations due to a 9.4% increase in firm unit
sales and a full year of higher base rates ($22.8 million) authorized in
November 1991; 2) the absence in 1992 of the Freetown Energy Park write-down
in late 1991; 3) lower short-term interest rates ($2.7 million); 4) a return
to more seasonable winter temperatures during the heating season; and 5) cost
control measures designed to eliminate or delay expenditures. Earnings from
electric operations declined due, in part, to: 1) the need for higher base
rates for Cambridge Electric; 2) the undercollection of $3 million, due to the
existing cost recovery mechanism, of certain long-term purchased power
capacity costs; and 3) a decreased return on equity due to declining net plant
investment bases.
PAGE 34
Electric Revenues and Unit Sales
Electric operating revenues for the years 1993, 1992 and 1991 consisted
of:
1993 1992 1991
Operating Revenues - In Thousands
Retail $513,160 $483,151 $488,539
Wholesale 105,445 108,197 112,261
Other 5,415 5,921 6,571
Total $624,020 $597,269 $607,371
Unit sales (in Megawatthours or MWH) for the years 1993, 1992 and 1991
consisted of:
1993 1992 1991
% %
Change Change
Residential 1,744,181 1.0 1,726,139 1.9 1,694,445
Commercial 2,008,213 2.9 1,951,228 1.1 1,929,852
Industrial
and Other 803,630 1.4 792,505 1.2 782,799
Total Retail 4,556,024 1.9 4,469,872 1.4 4,407,096
Wholesale 3,665,089 (6.0) 3,898,924 (3.2) 4,027,714
Total 8,221,113 (1.8) 8,368,796 (0.8) 8,434,810
Customers served 352,000 1.1 348,000 - 348,000
In 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 ($7.2 million
on an annualized basis), a 1.9% increase in retail unit sales and the recovery
of approximately $2.4 million in lost base revenues related to electric C&LM
programs. Partially offsetting these increases was a lower level ($9 million)
of C&LM program costs. The decline in wholesale revenues of $2.8 million or
2.5% was due to a 5.9% drop in unit sales to non-associate utilities.
Fluctuations in the level of wholesale electric sales have little, if any,
impact on earnings.
For 1993, retail electric unit sales increased 1.9%, as each customer
segment continued to show improvement, offset somewhat by the impact of
conservation programs. In particular, unit sales reflect a moderate increase
in customers, primarily residential, a greater demand for power from
commercial and seasonal customers, reflecting an improving economy and to a
lesser extent, more extreme weather conditions resulting in additional use to
meet heating or air conditioning requirements.
1992 operating revenues decreased $10.1 million, or 1.7%, despite a net
increase in fuel and purchased power costs of $30.3 million or 10.7%, a 1.4%
increase in retail unit sales and a full year of higher base rates for
Commonwealth Electric Company. This reduction was due primarily to a $26.3
million or 62% decrease in C&LM costs at Commonwealth Electric and Cambridge
Electric and a $6.9 million revenue decline associated with the operation of
Seabrook 1. Wholesale revenues in 1992 declined 3.6% due to a 3.2% drop in
unit sales to non-associate utilities and the New England Power Pool.
Revenues during a portion of 1991 and through 1993 also reflect the
impact of Commonwealth Electric's Economic Development Rate which became
effective on October 1, 1991. Revenues were lower by $1.5 million, $1.3
million and $552,000 in 1993, 1992 and 1991, respectively. These amounts
represent the difference between what certain commercial and industrial
customers would have paid prior to the availability of this rate. For
additional information on this special rate, refer to the "Rates and
Regulatory Matters" section of this discussion.
PAGE 35
Retail electric unit sales increased by 1.4% in 1992 primarily due to
increases in the residential sector caused by a return to more normal (colder)
temperatures in the first and fourth quarters of the year, offset somewhat by
a cooler than average summer, C&LM programs and the prolonged negative impact
of the state's depressed economic condition.
Fuel and Purchased Power
The cost of fuel used for electric generation and purchased power per
KWH sold was $.042, $.037 and $.034 for 1993, 1992 and 1991, respectively.
These costs constitute 56%, 52% and 47% of electric operating revenues for the
respective years. The upward trend since 1991 reflects the impact of the
system's contractual obligations to take higher-cost power contracted for in
the 1980s when the system's customer base grew dramatically and forecasts
predicted continued growth. These contracts, which are typically long-term,
will continue to drive costs up as additional capacity comes on line. The
system is currently involved in negotiations to restructure or buy out certain
of these long-term contracts.
For 1993 and 1992, fuel and purchased power costs increased $35.8
million or 11.4% and $30.3 million or 10.7%, respectively, due to higher unit
sales in both years and the contractual obligations discussed above including
additional power purchases from certain gas-fired independent power producing
(IPP) facilities. Both 1993 and 1992 reflect reduced generation from Canal
Electric Company's units (for sales to non-associate utilities) and other oil-
fired units. The increased costs for power from the IPPs and other sources
were offset somewhat by lower Seabrook 1 costs in both years.
Reflected in the 1993 and 1992 cost is the increased use of a cleaner
burning but more expensive (1% sulphur) fuel oil at Canal Electric. In
addition, fuel and purchased power expense for 1993, 1992 and 1991 includes
$5.6 million, $3.9 million and $872,000, respectively, of capacity-related
costs associated with certain purchased power contracts that were not
recovered in revenues due to the mechanism established by the DPU. The impact
of this underrecovery reduced net income by $3.4 million, $2.5 million and
$538,000 in 1993, 1992 and 1991, respectively. (Refer to the "Rates and
Regulatory Matters" section of this discussion for more information.)
The system's energy mix, including purchased power, was as follows:
1993 1992 1991
Oil 31% 41% 42%
Nuclear 26 27 31
Natural gas 29 21 15
Waste-to-energy 8 7 7
Hydro 3 2 3
Coal 3 2 2
Total 100% 100% 100%
The system's energy mix has shifted during the last several years from
oil to natural gas and other types of generation due to the availability of
capacity from IPP facilities and, to a lesser extent, an effort to reduce its
reliance on oil. 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 exchange 50 MW (25 MW in 1992) of Canal's oil-fired
generation with 50 MW of pumped storage capacity from non-affiliate New
England Power Company's Bear Swamp Units. In 1991, Canal arranged for a long-
term exchange of power with Central Vermont Public Service Company (CVPS)
whereby 50 MW from Canal'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
PAGE 36
and the purchaser. The Canal/Bear Swamp transaction alone will save the
system's customers $2.7 million over a four-year period that began in June
1993. These exchanges and other future capacity purchased power contracts
with natural gas-fired IPPs will continue to shift the system's energy mix
from oil to other energy sources. In addition to power purchases, the system
is actively pursuing sales of certain available capacity to utilities in and
outside the New England region.
Oil-fired generation, although reduced from prior years' levels, still
accounts for a major percentage of the system's total sources, including
purchased power. Average oil prices in 1993 at Canal's generating plant, a
major supplier of electricity for the system, were $14.02 per barrel as
compared to $12.95 and $12.53 per barrel in 1992 and 1991, respectively. In
conformance with tighter restrictions on stack emissions, the Commonwealth of
Massachusetts mandated a reduction in sulphur dioxide emissions requiring the
periodic use of lower-sulphur (1%) content oil. In 1993, 1% oil averaged
$15.16 per barrel, a 12.1% decrease from the $17.25 cost in 1992. However,
lower-sulphur oil displaced 57.5% of the higher-sulphur (2.2%) content oil as
compared to 24% in 1992. This higher cost oil is reflected in the total
average cost per barrel for 1993 and 1992 but was not used at Canal in 1991.
The price of oil is expected to average approximately $15.62 per barrel in
1994.
Gas Revenues, Unit Sales and Cost of Gas
Gas operating revenues for the years 1993, 1992 and 1991 consisted of:
1993 1992 1991
Operating Revenues - In Thousands
Firm $293,552 $284,879 $241,619
Interruptible 5,367 6,389 7,590
Other 3,725 3,606 3,030
Total $302,644 $294,874 $252,239
Unit sales (in billions of British thermal units or BBTU) for the years
1993, 1992 and 1991 consisted of:
1993 1992 1991
% %
Change Change
Residential 22,252 (0.6) 22,392 12.8 19,851
Commercial 10,931 0.2 10,913 14.0 9,575
Industrial
and Other 6,036 (7.2) 6,505 (6.7) 6,969
Total Firm 39,219 (1.5) 39,810 9.4 36,395
Interruptible 1,896 (23.1) 2,464 (16.1) 2,937
Total 41,115 (2.7) 42,274 7.5 39,332
Customers served 232,000 2.2 227,000 (0.4) 228,000
For 1993, gas operating revenues rose $7.8 million (2.6%) due primarily
to increases in C&LM costs ($4.8 million) which are being recovered through a
Conservation Charge (CC) decimal effective in late 1992 and the cost of gas
sold ($2.4 million). Also contributing to the increase in revenues were
transition costs ($1.4 million) associated with the implementation of the
Federal Energy Regulatory Commission's (FERC) Order No. 636 (refer to the
"Cost Recovery" section of this discussion) and an increase in firm
transportation revenues ($474,000). Offsetting these increases somewhat were
lower unit sales.
Operating revenues for 1992 increased $42.6 million or 16.9% due to a
$15.1 increase in the cost of gas sold, new base rates approved for
Commonwealth Gas effective November 1, 1991, a 9.4% increase in firm unit
sales and a nearly $600,000 increase in firm transportation revenues.
PAGE 37
Firm gas sales declined by 1.5% in 1993, including a 10.9% decline in
sales to industrial 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 little, if
any, impact on net income. In 1992, firm unit sales increased 9.4% due to
significantly higher residential and commercial customer use caused by colder
temperatures in the first and fourth quarters. The variations from year to
year in weather conditions, particularly during the heating seasons, cause gas
usage to fluctuate. 1992 weather patterns were more normal than 1991.
Customers increased at a rate of 2.2% in 1993 due to new home construc-
tion and conversion activity. The fluctuation in interruptible sales during
the three-year period reflects the competitive market conditions for energy
resources. However, interruptible sales have little impact on earnings.
The cost of gas sold per MMBTU averaged $3.81, $3.65 and $3.54 in the
years 1993, 1992 and 1991, respectively. In 1994, the cost of gas is expected
to cost approximately $4.40 per MMBTU due to the impact of FERC Order No. 636
and rising transportation costs.
Other Operation and Maintenance
In 1993, other operation decreased $12.6 million or 6.1% due to the
absence in the current year of costs associated with Commonwealth 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 debts expense which declined $2.7 million or
22.8% due to improved payment experience, lower liability insurance costs of
$1.7 million due to lower claims, lower Seabrook operating costs of $1.7
million and a decline in employee medical and life insurance costs of
$800,000. Offsetting these decreases somewhat was an increase in pension
costs of $1.2 million.
In 1992, other operation increased 6.1% due to higher costs for medical
and other types of insurance and consulting fees incurred primarily as a
result of an independent management audit which was conducted for Commonwealth
Electric during the year by order of the DPU. Also, the provision for bad
debts increased by $900,000 reflecting the difficult economic conditions in
the system's service territory and a decline in fuel assistance programs.
Offsetting these increases in 1992 was a $2.2 million reduction in net pension
expense as a result of asset valuation changes and Commonwealth Electric's
deferral of $1.4 million of accrued pension costs pursuant to rate-making
treatment. Additionally in 1992, there were positive results from the
system's cost containment efforts, including reduced overtime, work force
reductions through attrition, early retirements and the elimination of forty
positions and associated costs with the closing of Commonwealth Electric's
Cannon Street generating station in the fourth quarter.
The total number of full-time employees declined 11.7% to 2,217 in 1993
from 2,510 employees at year-end 1991. Management views the current work
force level to be adequate for service to its customers.
On October 1, 1992, Commonwealth Electric ceased power generation at its
59 MW Cannon Street station located in New Bedford, Massachusetts. Fuel costs
for this facility were $544,000 and $2.1 million in 1992 and 1991, respective-
ly, and operations and maintenance costs were $2.2 million and $2.4 million in
1992 and 1991, respectively. After reviewing several alternatives for the
facility including re-powering, management decided to abandon the plant in
1993. The sharp decline in electric demand brought about by an economic
slowdown was a key factor in the decision to close the plant. Additionally,
forecasts for electric demand indicated an excess regional supply in the near
term and no need for increased generating capacity until the late-1990s or
beyond. In 1993, a regulatory asset was established for the net book value of
the plant of approximately $4 million in anticipation of recovery.
PAGE 38
Maintenance in 1993 increased by $700,000 or 1.9% due primarily to a
scheduled major inspection and overhaul of the Canal 2 boiler, turbine and
generator. In 1992, maintenance decreased $4.5 million or 10.1% due to
reduced transmission and distribution related costs and the absence of major
repairs to Canal Unit 1 that were experienced in 1991.
Depreciation, Amortization and Taxes
Despite the higher level of depreciable plant, depreciation expense
declined by approximately $700,000 or 1.6% during 1993 due to an adjustment
made to the accrual rate used by Canal Electric to reflect an extension of the
depreciable life of Unit 1 from 1996 to 2002. This change reduced
depreciation expense for the year 1993 by approximately $3.5 million but had
no impact on net income because the new estimate is reflected in bills to
customers. The abandonment of the Cannon Street generating station also
contributed to the decrease in 1993. In 1992, depreciation increased by 2.9%
due to a higher level of depreciable plant-in-service.
The decline in amortization for 1993 of $1.7 million or 21.9% was due to
the absence in the current period of amortization costs related to
Commonwealth Gas' automated mapping system. In 1992, the $5 million rise in
amortization costs was due to a change made in 1991 in the recovery period of
Seabrook 1 non-construction costs from one year to ten years pursuant to a
settlement with the FERC. Amortization of these costs began with commercial
operation of the unit in 1990.
Income tax expense increased $7.7 million or 37.5% in 1993 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. In 1992, income tax expense increased $1.6 million or 8.7% as a result
of higher pretax income from the system's primary businesses.
The 2.7% change in local property taxes in 1993 primarily reflects
higher property tax rates. Local property taxes increased in 1992 by $3.9
million or 32% reflecting higher tax rates and/or assessments in the majority
of the communities the system serves and also reflected a $435,000 increase in
the nuclear station property tax assessed by the State of New Hampshire on the
joint owners of Seabrook. The 3.8% increase in payroll and other taxes for
1993 was due to an increase in unemployment tax rates.
Conservation and Load Management (C&LM)
Cambridge Electric, Commonwealth Electric and Commonwealth Gas have
received approval from the DPU to recover in revenues costs associated with
C&LM programs through the operation of a Conservation Charge (CC) decimal on a
dollar-for-dollar-basis. For the years ended December 31, 1993, 1992 and
1991, C&LM costs (including amortization of prior period amounts) were as
follows:
1993 1992 1991
(Dollars in Thousands)
Cambridge Electric $ 2,905 $ 4,246 $ 8,135
Commonwealth Electric 4,165 11,826 34,199
Commonwealth Gas 5,094 286 -
$12,164 $16,358 $42,334
Other Income
The substantial increase in other income during 1993 reflects the
reversal of a reserve ($3.8 million pretax) related to the system's Seabrook 1
investment. The decision to eliminate the reserve was prompted by the
allowance of Seabrook 1 costs in base rates at the state level for Cambridge
Electric. Offsetting this, in part, was the absence in the current year of an
equity component of allowance for funds used during construction (AFUDC). The
$1.8 million in equity AFUDC for 1992 resulted from an adjustment to reflect a
PAGE 39
final FERC settlement which provided for the full recovery of the system's
Seabrook investment.
Other income increased by 110% in 1992 due to the absence of the $14.8
million after-tax write-down which resulted from cancellation of the Freetown
Energy Park project and the $1.8 million equity component of AFUDC which
relates to the aforementioned FERC settlement. Also included in 1992 was
Commonwealth Electric's Hurricane Bob (August 1991) expenses of $9.2 million
($5.7 million after-tax) which had been deferred in 1991 pending regulatory
action. The impact of this write-off was neutralized by receipt of DPU and
Internal Revenue Service authorization to retain certain tax reserves which
would normally be returned to customers.
Interest Charges
For 1993, interest charges increased $2.5 million or 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 long-term notes in the first quarter
of 1993. Somewhat offsetting these increases was a $300,000 decline in other
interest charges that was due to lower interest rates and a lower average
level of short-term borrowings ($103 million versus $126 million). Interest
rates on short-term bank borrowings averaged 3.5% in 1993 as compared to 4%
for 1992. Total interest charges decreased 11% in 1992 due primarily to a
$1.5 million increase in the debt component of AFUDC relating to the Seabrook
investment and a $2.7 million or 27.5% reduction in short-term interest
charges. Despite a higher average level of bank borrowings created, in part,
by the retirement of several long-term debt issues during 1992, short-term
interest declined due to lower interest rates on bank borrowings (4% versus
6.3% for 1991).
New Accounting Standards
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." This statement establishes
new accounting and reporting standards for postretirement benefits other than
pensions. For further information, refer to Note 4(b) of the Notes to
Consolidated Financial Statements.
In 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits" (SFAS 112). The system is required to adopt this
statement effective January 1, 1994. SFAS 112 requires employers to recognize
the obligation to provide benefits to former or inactive employees after
employment but before retirement (postemployment). Those benefits include
salary continuation, supplemental employment benefits, severance benefits,
disability-related benefits and continuation of benefits such as health care
and life insurance coverage if each of the following conditions are met: 1)
the obligation is attributable to employee services already rendered, 2)
employees' rights to those benefits accumulate or vest, 3) payment of the
benefits is probable and 4) the cost of the benefits can be reasonably
estimated. The system believes that the adoption of the provisions of SFAS
112 will not have a material impact on its financial position or results of
operations.
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.
PAGE 40
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 are 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 Gas November 1, 1991 27.7 22.8 13% * 11.22%*
Commonwealth Electric July 1, 1991 17.3 10.9 12% 10.49%
* Returns are for accounting purposes only.
On May 28, 1993, the DPU issued an order, based on a June 30, 1992 test
year, increasing Cambridge Electric's retail revenues by approximately $7.2
million, or 6.4%. More than 80% of the increase related to: 1) plant
additions since Cambridge Electric's last retail rate proceeding in 1989; 2)
capacity costs associated with certain long-term purchased power contracts;
and 3) costs of postretirement benefits other than pensions. The costs
associated with postretirement benefits other than pensions were determined in
accordance with SFAS No. 106. The DPU authorized recovery of these costs over
a four-year period with carrying costs on the deferred portion. The new base
rates also reflect costs associated with power from the Seabrook nuclear power
plant which are billed to Cambridge Electric by Canal Electric. Previously
these costs were recovered through Cambridge Electric's Fuel Charge decimal.
The Commonwealth Gas settlement provided an 11.3% increase in revenues
(9% of 1990 revenues) and was the company's first rate increase request since
May 1987. The increase was necessitated by the rising costs of providing
service to customers and substantial expenditures to upgrade, improve and
maintain the Commonwealth Gas distribution system.
The Commonwealth Electric rate order provided a 3.1% increase in
revenues over the test year ended June 30, 1990. The DPU also ordered the
Company to undertake an independent management audit in 1992. In October
1992, the DPU released the results of the audit which evaluated existing
activities and processes and identified opportunities for improved operations
in the areas of strategic planning, budget development, control of capital and
operational costs, management of outside services, employment policies and
customer services. Throughout 1993, follow-up discussions were held between
Commonwealth Electric and the DPU regarding the status of each audit
recommendation with both parties expressing overall satisfaction with their
progress. Changes in the implementation plan were discussed, with the plan
expected to be complete in 1994.
Economic Development Rate
In an effort to foster industrial development in its service area,
Commonwealth Electric began offering an Economic Development Rate (EDR) on
October 1, 1991. The rate is offered 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, 1993, twenty-two industrial
customers are 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. Commonwealth Electric also received approval for a Vacant Space
Rate which it filed in conformance with the new EDR guidelines that is
available to qualifying small commercial and industrial customers who
establish loads in previously unoccupied building space.
PAGE 41
Cost Recovery
Fuel and Purchased Power and Purchased Gas
Commonwealth Electric and Cambridge Electric file Fuel Charge rate
schedules, subject to DPU regulation, under which they are allowed current
recovery, from retail customers, of fuel used in electric generation and a
substantial portion of purchased power, demand and transmission costs.
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 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, Cambridge Electric and Commonwealth Electric 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 consideration in each company's next
base rate proceeding.
Commonwealth Gas has a standard seasonal Cost of Gas Adjustment rate
schedule 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 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.
On April 8, 1992, the FERC issued Order No. 636 (Order 636), requiring
interstate pipelines to unbundle (separate) existing gas sales contracts into
separate components (gas sales, transportation and storage services). Order
636 provides mechanisms which will allow customers to reduce the level of firm
services from pipelines and permits the "brokering" of excess capacity on a
temporary or permanent basis. Order 636 also requires pipelines to provide
transportation services which allow customers to receive the quality of
service they had with bundled contracts. Refer to Note 2(g) of the Notes to
Consolidated Financial Statements for more information.
C&LM Programs
The system has implemented cost-effective C&LM programs for its gas and
electric ratepayers 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 allowed by the DPU to encourage effective implementation 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. The amount to be recovered is approximately $3.6 million for
Commonwealth Electric and Cambridge Electric combined and is based on
anticipated KWH savings for the eighteen-month period beginning January 1,
1993. The revenue will be recovered from customers over a twelve-month period
which began July 1, 1993. Through December 31, 1993, the combined recovery
was approximately $2.4 million.
On October 25, 1993, the DPU issued an order in Phase II of the C&LM
proceeding. In that order, the DPU disallowed approximately $195,000 in
expenditures that it determined exceeded benefits to customers. In addition,
PAGE 42
the DPU ruled that approximately $1.6 million in C&LM Task Force related
expenditures are not recoverable by Commonwealth Electric and Cambridge
Electric "at this time" because certain programs have yet to be implemented
and thus ratepayers are receiving no current benefits. The Companies have
removed these costs from the current CC decimal. Commonwealth Electric and
Cambridge Electric are continuing with the development of the programs and
plan to seek recovery of these costs in a subsequent filing with the DPU.
Based on the language in the order and subsequent discussions with the parties
involved in the proceeding, management believes that the ultimate recovery of
a substantial portion of these costs is likely.
Commonwealth Gas offers conservation measures to its residential,
commercial and industrial customers through formal programs approved by the
DPU in June 1992. On November 1, 1992, Commonwealth Gas implemented
separately stated CC decimals pursuant to its cost-recovery mechanism.
Environmental Matters
Commonwealth Gas is a potentially responsible party (PRP) in the
Sullivan's Ledge Superfund site in New Bedford, Massachusetts. In 1990,
Commonwealth Gas agreed to a settlement regarding this site and its share of
clean-up costs is presently estimated to be $1.8 million and is reflected on
the Consolidated Balance Sheets. Sampling work at the site indicates that a
more extensive clean-up than originally contemplated may be required, although
the financial impact of these findings is not presently known. The settling
parties for the site are now pursuing claims against a number of non-settling
PRPs, and any amounts recovered through those claims will be applied to offset
the settling parties' liabilities.
Commonwealth Gas is evaluating a former gas manufacturing plant site in
Worcester, Massachusetts, and a proposal for a comprehensive assessment of
this site has been prepared, and it is possible that this site may require
substantial remediation work due to the suspected presence of hazardous
substances. However, the cost of remediation cannot be estimated at this
time.
Commonwealth Gas anticipates recovery of costs associated with the
clean-up of such sites from its customers through a procedure established in a
generic order issued by the DPU, wherein such costs are recovered through an
element of the existing Cost of Gas Adjustment Clause (CGA).
COM/Energy Research Park Realty (RPR), another system subsidiary, owns a
parcel of land on Third Street in Cambridge, Massachusetts, which was also
formerly the site of a gas manufacturing facility. While the Massachusetts
Department of Environmental Protection has not designated this site as being
contaminated by hazardous substances, it is expected that RPR, in conjunction
with any future development of this site, will conduct a site assessment to
determine if clean-up activities are necessary. RPR, a non-regulated entity,
would be responsible for the costs associated with any such activities.
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 Massachusetts Department of Environmental Protection 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.
Liquidity and Capital Resources
Overview
Capital resources of the System and its subsidiaries are derived
principally from retained earnings and equity funds provided through the
PAGE 43
System's Dividend Reinvestment and Common Share Purchase Plan (DRP). Supple-
mental 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 subsidiaries have
over the years, maintained adequate financial resources and availability to
the capital markets and further, do not anticipate a change in 1994 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. In 1993, the System purchased $53 million in subsidiary stock which
provides funds for subsidiary companies' construction programs, current
operations, debt service and other capital requirements.
Capital Requirements
Construction expenditures for 1993 were $54.6 million, including AFUDC.
Sinking fund requirements and redemptions of long-term debt amounted to $44
million for a total capital requirement of $98.6 million, a decrease of $11.9
million from the 1992 level. Of this amount, $51.1 million, or 52%, was
provided from internally generated funds. 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.
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 1994 through 1998 are as follows:
1994 1995 1996 1997 1998 Total
(Dollars in Millions)
Construction expenditures
including AFUDC $ 72 $ 76 $ 80 $ 67 $ 63 $358
Retirement of long-term debt
and preferred shares 16 32 42 22 27 139
Total $ 88 $108 $122 $ 89 $ 90 $497
Sources of Capital
On March 31, 1993, Commonwealth Electric Company issued long-term notes
totaling $65 million and 437,500 shares of Common Stock ($25 par value) for
$35 million. The notes, which were sold through a private placement with
institutional investors, consisted of the following:
10 Year, 7.43% Notes, Due 2003 $15,000,000
15 Year, 7.70% Notes, Due 2008 10,000,000
20 Year, 7.98% Notes, Due 2013 25,000,000
30 Year, 8.47% Notes, Due 2023 15,000,000
$65,000,000
The proceeds from the notes, together with the proceeds from
Commonwealth Electric's sale of common stock to the System, were used to repay
outstanding short-term debt incurred to temporarily finance additions to
property, plant and equipment, and the early retirement on March 1, 1993 of
three series of long-term debt, as follows:
Series E, 8.125% Notes, Due 1995 $ 4,860,000
Series B, 6.125% Notes, Due 1997 4,440,000
Series F, 8.375% Notes, Due 1998 12,000,000
$21,300,000
Commonwealth Electric paid a premium totaling $337,000 on the early
retirement of the debt and is amortizing this amount to expense over the
remaining original life of the retired issues.
On December 1, 1993, Canal Electric redeemed its Series D, 11.125% Bonds
due December 1, 2007 totaling $9.3 million with short-term borrowings. Canal
paid a premium of $279,000 on this early redemption and will amortize this
amount to expense over the remaining original life of the retired issue.
PAGE 44
In late December 1993, Commonwealth Gas issued $35 million in First
Mortgage Bonds, Series K, 7.11%, due December 30, 2033. The proceeds from
this forty-year issue, together with an $18 million common stock issue
purchased by the Parent, were used to repay a portion of short-term debt that
had been incurred to temporarily finance construction expenditures and for
other working capital needs. Additionally, Hopkinton LNG Corp. issued a $9
million Note with a variable rate, due in 1998. The proceeds were used
primarily to refinance a $7 million Note, 7.11%, that matured during the
fourth quarter of 1993. The balance was used to satisfy other working capital
requirements.
It is anticipated that approximately $337 million or nearly 68% of the
projected capital requirements shown in the "Capital Requirements" section
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
rental income, dividends from investments, the sale of Common Shares through
DRP and periodic short-term borrowings from banks.
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 1997 1998 Total
(Dollars in Millions)
Long-term debt $ 72 $ 38 $ 9 $119
Common stock 32 29 - 61
Total $104 $ 67 $ 9 $180
In addition, the System could raise further 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
primary source of funds in addition to proceeds from DRP. 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.
System companies also maintain lines of credit with banks. At December
31, 1993, short-term notes payable to banks were $72 million, a decrease of
$93.6 million from last year's level of $165.6 million. Bank borrowings are
used to temporarily fund construction projects and to repay the long-term debt
of the System and its subsidiary companies ($37.6 million in 1993).
Arrangements for bank lines of credit totaled $115 million in committed lines
and $70 million in uncommitted lines at December 31, 1993, at which time $113
million was available to the system. At December 31, 1998, the system's level
of bank borrowings is projected to be approximately $82 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
PAGE 45
short-term debt. The system's capitalization structure, including maturing
long-term debt, is presented below:
1992 1993 1998
(Dollars in Thousands)
Long-term debt $368,092 42.6% $458,893 51.9% $441,288 45.6%
Preferred shares 16,300 1.9 15,480 1.8 11,380 1.2
Common equity 315,219 36.4 337,070 38.2 433,863 44.8
Short-term debt 165,600 19.1 71,975 8.1 81,705 8.4
Total Capitalization $865,211 100.0% $883,418 100.0% $968,236 100.0%
PAGE 46
MANAGEMEMT'S REPORT
The 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 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 17, 1994.
PAGE 47
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, 1993 and
1992, and the related consolidated statements of income, changes in common
shareholders' investment, changes in redeemable preferred shares and cash
flows for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the System and subsidiary
companies' management. Our responsibility is to express an opinion on these
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 financial statements referred to above present
fairly, in all material respects, the financial position of the System and
subsidiary companies as of December 31, 1993 and 1992, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1993, 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 & CO.
Arthur Andersen & Co.
Boston, Massachusetts
February 17, 1994.
PAGE 48
Consolidated Balance Sheets
December 31, 1993 and 1992
1993 1992
(Dollars in Thousands)
Assets
Property, Plant and Equipment, at original cost
Electric $1,018,121 $1,014,997
Gas 322,314 303,756
Other 58,473 58,004
1,398,908 1,376,757
Less-Accumulated depreciation and amortization 425,483 406,069
973,425 970,688
Construction work in progress 9,448 7,722
Nuclear fuel in process 1,641 155
984,514 978,565
Leased Property, net (Note 8) 16,150 18,388
Equity in Corporate Joint Ventures
Nuclear electric power companies (2.5% to 4.5%) 9,660 9,690
Other investments 3,889 4,198
13,549 13,888
Current Assets
Cash 6,007 1,522
Accounts receivable, less reserves of $7,761,000
in 1993 and $6,861,000 in 1992 93,663 85,325
Unbilled revenues 43,279 47,656
Inventories, at average cost-
Electric production fuel oil 1,440 3,792
Natural gas 25,810 17,906
Materials and supplies 8,852 10,387
Prepaid property taxes 8,220 7,509
Prepaid income taxes 362 7,683
Other 6,649 6,220
194,282 188,000
Deferred Charges (Notes 1, 2 and 4) 106,668 73,178
$1,315,163 $1,272,019
PAGE 49
Consolidated Balance Sheets
December 31, 1993 and 1992
1993 1992
(Dollars in Thousands)
Capitalization and Liabilities
Capitalization (See separate statement)
Common share investment $ 337,070 $ 315,219
Redeemable preferred shares, less current
sinking fund requirements 15,480 16,300
Long-term debt, less current sinking fund
requirements and maturing debt 448,893 361,092
801,443 692,611
Capital Lease Obligations (Note 8) 14,456 15,487
Current Liabilities
Interim Financing (Note 5)-
Notes payable to banks 71,975 165,600
Maturing long-term debt 10,000 7,000
81,975 172,600
Other Current Liabilities-
Current sinking fund requirements 6,793 6,213
Accounts payable 90,006 86,976
Accrued taxes 9,090 8,078
Accrued interest 7,325 6,576
Dividends declared 7,544 7,716
Capital lease obligations (Note 8) 1,694 2,901
Other 20,759 14,651
143,211 133,111
225,186 305,711
Deferred Credits
Accumulated deferred income taxes 156,851 146,328
Unamortized investment tax credits 30,774 32,274
Other (Notes 1 and 2) 86,453 79,608
274,078 258,210
Commitments and Contingencies (Note 2)
$1,315,163 $1,272,019
The accompanying notes are an integral part of these consolidated financial
statements.
PAGE 50
Consolidated Statements of Income
Years Ended December 31, 1993, 1992 and 1991
1993 1992 1991
(Dollars in Thousands)
Operating Revenues
Electric $624,020 $597,269 $607,371
Gas 302,644 294,874 252,239
Steam and other 14,035 14,307 13,824
940,699 906,450 873,434
Operating Expenses
Fuel used in electric production,
principally oil 90,346 104,640 110,480
Electricity purchased for resale 258,490 208,427 172,240
Cost of gas sold 156,709 154,304 139,169
Other operation 194,640 207,262 201,032
Maintenance 40,574 39,836 44,312
Depreciation 42,480 43,164 41,951
Amortization 6,013 7,697 2,709
Conservation and load management 12,164 16,358 42,334
Taxes-
Local property 16,350 15,923 12,065
Income (Note 3) 28,256 20,557 18,913
Payroll and other 8,676 8,357 8,773
854,698 826,525 793,978
Operating Income 86,001 79,925 79,456
Other Income (Expense)
Allowance for equity funds used during
construction - 1,827 -
Freetown project write-down (Note 10) - - (22,974)
Other, net (Note 3) 3,784 (417) 9,555
3,784 1,410 (13,419)
Income Before Interest Charges 89,785 81,335 66,037
Interest Charges
Long-term debt 37,416 36,722 37,657
Other interest charges 6,730 7,034 9,702
Allowance for borrowed funds used during
construction (195) (2,318) (794)
43,951 41,438 46,565
Net Income 45,834 39,897 19,472
Dividends on preferred shares 1,230 1,291 1,352
Earnings Applicable to Common Shares $ 44,604 $ 38,606 $ 18,120
Average Number of Common Shares
Outstanding 10,215,614 10,081,868 9,944,433
Earnings Per Common Share $4.37 $3.83 $1.82
The accompanying notes are an integral part of these consolidated financial
statements.
PAGE 51
Consolidated Statements of Cash Flows
Years Ended December 31, 1993, 1992 and 1991
1993 1992 1991
(Dollars in Thousands)
Operating Activities
Net income $ 45,834 $ 39,897 $ 19,472
Effects of non-cash items-
Depreciation and amortization 53,337 58,883 59,489
Freetown write-down (Note 10) - - 22,974
Deferred income taxes, net 17,059 (74) (3,872)
Investment tax credits (1,500) (1,543) (1,567)
Allowance for equity funds used
during construction - (1,827) -
Earnings from corporate joint ventures (1,642) (2,016) (2,699)
Dividends from corporate joint ventures 1,981 2,157 1,626
Change in working capital, exclusive of cash-
Accounts receivable and unbilled revenues (3,961) 4,814 (16,744)
Prepaid (accrued) income taxes 7,321 (4,539) (8,471)
Accrued local property and other taxes 301 (598) 883
Accounts payable and other 4,642 1,441 (5,013)
Uncollected Order 636 transition
costs (Note 2) (8,805) - -
Uncollected postretirement benefits
costs (Note 4) (8,910) - -
All other operating items (18,965) 3,815 (4,180)
Net cash provided by operating activities 86,692 100,410 61,898
Investing Activities
Additions to property, plant and
equipment (exclusive of AFUDC)
Electric (29,490) (26,080) (40,760)
Gas (23,099) (20,437) (17,103)
Other (1,796) (2,577) (2,266)
Allowance for borrowed funds used during
construction (195) (2,318) (794)
Net cash used for investing activities (54,580) (51,412) (60,923)
Financing Activities
Sale of common shares 7,118 5,233 4,533
Payment of dividends (31,101) (30,770) (30,428)
Proceeds from (payment of) short-term
borrowings (93,625) 19,800 2,375
Long-term debt issues 134,000 15,000 27,000
Retirement of long-term debt and preferred
shares through sinking funds (6,419) (5,678) (5,829)
Long-term debt issues refunded (37,600) (51,632) -
Net cash used for financing activities (27,627) (48,047) (2,349)
Net increase (decrease) in cash 4,485 951 (1,374)
Cash at beginning of period 1,522 571 1,945
Cash at end of period $ 6,007 $ 1,522 $ 571
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of capitalized amounts) $ 39,685 $ 40,116 $ 45,858
Income taxes $ 13,528 $ 14,460 $ 15,478
The accompanying notes are an integral part of these consolidated financial
statements.
PAGE 52
Consolidated Statements of Capitalization
December 31, 1993 and 1992
1993 1992
(Dollars in Thousands)
Common Share Investment
Common shares, $4 par value-
Authorized-18,000,000 shares
Outstanding-10,295,077 in 1993
and 10,141,675 in 1992 $ 41,180 $ 40,567
Amounts paid in excess of par value 94,657 88,152
Retained earnings (Note 9) 201,233 186,500
Total common share investment 337,070 315,219
Redeemable Preferred Shares,
Cumulative, $100 par value (Note 6)
Series A, 4.80% 3,000 3,120
Series B, 8.10% 4,480 4,640
Series C, 7.75% 8,820 9,360
Less current sinking fund requirements (820) (820)
Total redeemable preferred shares 15,480 16,300
Long-Term Debt (Note 5)
Notes due-
1995, 4.70% 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 (10,000) -
Total System long-term debt 55,000 40,000
Subsidiary companies' long-term debt
Mortgage Bonds, collateralized by property of
operating subsidiaries, due-
1996, 7% 5,320 6,078
1996, 8.99% 10,000 10,000
2001, 8.99% 29,050 32,700
2006, 8.85% 35,000 35,000
2007, 11 1/8% - 9,300
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 -
Notes due-
1993, 7.11% - 7,000
1995, 8 1/8% - 5,040
1996, 9.97% 20,000 20,000
1997, 6 1/8% - 4,500
1997, 6 1/4% 4,440 4,500
1998, variable rate (4.03% in 1993) 9,000 -
1998, 8 3/8% - 12,297
1999, 8.04% 10,000 10,000
2002, 7 3/4% 2,900 2,938
2002, 9.30% 30,000 30,000
2003, 7.43% 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 -
2012, 9.37% 20,000 20,000
2013, 7.98% 25,000 -
2014, 9.53% 10,000 10,000
2019, 9.60% 10,000 10,000
2023, 8.47% 15,000 -
Less-Current sinking fund requirements
and maturing debt (5,973) (12,393)
Unamortized discount, net (844) (868)
Total subsidiary companies' long-term debt 393,893 321,092
Total long-term debt 448,893 361,092
Total capitalization $801,443 $692,611
The accompanying notes are an integral part of these consolidated financial
statements.
PAGE 53
Consolidated Statements of Changes in Common Shareholders' Investment
Years Ended December 31, 1993, 1992 and 1991
Amounts
Paid in
Value Excess
$4 Per of Par Retained
Shares Share Value Earnings Total
(Dollars in Thousands)
Balance December 31, 1990 9,871,196 $39,485 $79,468 $188,329 $307,282
Add (Deduct)-
Net income - - - 19,472 19,472
Sale of shares 136,041 544 3,989 - 4,533
Cash dividends declared-
Common shares-$2.92 per share - - - (29,076) (29,076)
Preferred shares - - - (1,352) (1,352)
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
Consolidated Statements of Changes in Redeemable Preferred Shares
Years Ended December 31, 1993, 1992 and 1991
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, 1990 33,600 49,600 104,400 187,600
Less-Sinking fund redemptions 1,200 1,600 5,400 8,200
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
The accompanying notes are an integral part of these consolidated financial
statements.
PAGE 54
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. At December 31, 1993,
principal regulatory assets included in deferred charges were $21.9 million
for transition costs associated with FERC Order 636, $15.5 million for
unrecovered plant and decommissioning costs for the Yankee Atomic nuclear
plant, $15.5 million for abandonment and nonconstruction costs related to the
Seabrook project, $8.9 million for postretirement benefits costs, $7.4 million
in litigation costs associated with a settlement agreement with Boston Edison
Company relative to the Pilgrim nuclear plant and $7.3 million related to
deferred income taxes. The more significant regulatory liabilities, reflected
in deferred credits, include $17.9 million related to income taxes and $15.5
million related to the Yankee Atomic nuclear plant.
(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.
(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 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
$5,565,000 in 1993 and $8,315,000 in 1992, is recorded as unbilled revenues.
PAGE 55
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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:
1993 1992 1991
Electric 3.28% 3.49% 3.49%
Gas 2.95 2.90 2.94
Steam 3.61 3.50 3.50
LNG 3.07 3.00 2.89
(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 so
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 3.9% in 1993,
4.5% in 1992 and 6.7% in 1991.
(2) Commitments and Contingencies
(a) Construction
The system is engaged in a continuous construction program presently
estimated at $358.3 million for the five-year period 1994 through 1998. Of
that amount, $71.9 million is estimated for 1994. The program is subject to
periodic review and revision.
(b) Seabrook Nuclear Power Plant
The system's 3.52% interest in the Seabrook nuclear power plant is owned
by Canal Electric Company (Canal), 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:
1993 1992
(Dollars in Thousands)
Utility-plant-in
service $233,140 $233,651 Plant capacity (MW) 1,150
Nuclear fuel 18,514 17,083 Canal's share:
Accumulated depreciation Percent interest 3.52%
and amortization (34,771) (25,382) Entitlement (MW) 40.5
Construction work in In-Service date 1990
progress 881 623 Operating license
$217,764 $225,975 expiration date 2026
PAGE 56
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1993 1992 1991
(Dollars in Thousands)
Operating expenses:
Fuel $ 3,853 $ 3,952 $ 4,337
Other operation 4,580 5,705 9,239
Maintenance 893 1,508 1,601
Depreciation 6,522 6,426 7,214
Amortization 1,319 1,320 (3,333)
$17,167 $18,911 $19,058
Canal and the other joint owners have established a Seabrook Nuclear
Decommissioning Financing Fund to cover post operational decommissioning
costs. For the years 1993, 1992 and 1991, Canal paid $259,000, $235,000 and
$181,000, respectively, as its share of the cost of this fund. The estimated
cost to decommission the plant is $366 million. Canal's share, less its share
of the market value of the decommissioning trust, would amount to
approximately $11.6 million.
(c) Price-Anderson Act
The Price-Anderson Act (the Act) is a federal statute that includes
among its provisions a requirement that licensees of nuclear electric
generating units maintain financial protection to cover public liability
claims resulting from a nuclear incident or precautionary evacuation. In
1988, Congress enacted a 15 year extension of the Act and increased the
available insurance and the maximum liability. The higher liability is
provided by existing private insurance and retrospective assessments for costs
in excess of that covered by insurance, up to $66.15 million for each nuclear
reactor which is licensed to operate with a maximum assessment of $10 million
per incident within one calendar year. Based on the system's equity ownership
interest in four nuclear generating facilities and its 3.52% joint-ownership
interest in Seabrook 1, the system's retrospective premium could be as high as
$1.9 million yearly or a cumulative total of $12.6 million, exclusive of the
effect of inflation indexing (at five-year intervals) and a 5% surcharge ($3.3
million) in the event that total public liability claims from a nuclear
incident exceed the funds available to pay such claims.
(d) Power Contracts and Support Agreements
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 is as follows:
Connecticut Maine Vermont
Yankee Yankee Yankee Pilgrim
(Dollars in Thousands)
Equity Ownership 4.50% 4.00% 2.50% -
Plant Entitlement 4.50% 3.59% 2.25% 11.0%
Plant Capability (MW) 560.0 870.0 496.0 664.7
System Entitlement (MW) 25.2 31.2 11.2 73.1
Contract Expiration Date 1998 2008 2012 2012
1991 Actual Cost $ 9,692 $5,900 $3,383 $ 3,210
1992 Actual Cost 9,508 6,671 3,970 37,516
1993 Actual Cost 10,016 7,050 4,076 40,578
1994 Estimated Cost 10,005 6,755 3,755 41,963
Cambridge and Commonwealth Electric pay their share of decommissioning
expense to each of the operators of the nuclear facilities as a cost of
electricity purchased for resale.
PAGE 57
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The system has also contracted to purchase power and transmission
capacity from various other generating and transmission facilities as follows:
Estimated
1991 1992 1993 1994
MW Cost MW Cost MW Cost MW Cost
(Dollars in Thousands)
Purchased Power -
Nuclear 89.1 $43,686 15.5 $ 3,546 15.4 $ 4,976 23.1 $ 5,386
Hydro 35.4 14,214 20.3 13,161 23.2 12,370 29.6 14,477
Cogenerating 117.0 34,938 162.0 69,742 161.0 104,719 261.5 135,363
Waste-to-energy
and other 123.0 38,084 114.1 35,944 84.1 38,965 91.0 40,256
Transmission -
(Hydro-Quebec) - 5,470 - 4,213 - 4,247 - 4,457
Costs under these and other 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.
(e) Yankee Atomic Nuclear Power Plant
On February 26, 1992, the Board of Directors of Yankee Atomic Electric
Company agreed to permanently discontinue power operation of its plant and, in
time, decommission that facility. This plant provided less than 1% of system
capacity. Cambridge's and Commonwealth Electric's respective 2% and 2.5%
investment in Yankee Atomic is approximately $1 million. Presently, purchased
power costs, which include a provision for ultimate decommissioning of the
unit, are billed to Cambridge and Commonwealth Electric and collected from
customers.
Cambridge and Commonwealth Electric have estimated their unrecovered
share of all costs associated with the shutdown of the facility, recovery of
their respective plant investment and decommissioning and closing the plant to
be approximately $15.5 million. This amount is reflected in the accompanying
Consolidated Balance Sheets as a liability and a corresponding regulatory
asset at December 31, 1993.
(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 upon the System's operations in the past and
will continue to have an impact upon 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
On April 8, 1992, the FERC issued Order No. 636 (Order 636), requiring
interstate pipelines to unbundle (separate) existing gas sales contracts into
separate components (gas sales, transportation and storage services). Order
636 provides mechanisms that will allow customers such as Commonwealth Gas to
reduce the level of firm services from pipelines and permits the "brokering"
of excess capacity on a temporary or permanent basis. Order 636 also requires
pipelines to provide transportation services which allow customers to receive
the same level of service they had with bundled contracts. Pipelines were
required to be operating under Order 636 by November 1, 1993.
PAGE 58
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As a result of implementing Order 636, each pipeline company is allowed
to collect certain "transition costs" from their customers. Commonwealth Gas
has been billed a total of approximately $16.9 million from Tennessee Gas
Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern
Transmission Company through December 31, 1993. It is anticipated that as
much as $45 million in transition costs could be sought by these suppliers
through a series of FERC filings over the 12 to 24 month period that began on
June 1, 1993. The largest element of the aforementioned transition costs
results from the pipelines' need to buy out gas supply contracts entered into
prior to Order 636. The total amount of such costs ultimately billed to
Commonwealth Gas will vary depending on the success of the pipelines in
negotiating settlements with their former suppliers, and final review by the
FERC. Commonwealth Gas is actively reviewing the prudency of transition costs
billed in order to minimize costs to its customers. Commonwealth Gas has
recorded its estimated liability based on amounts incurred by the respective
pipelines as of December 31, 1993.
On October 29, 1993, Commonwealth Gas received preliminary DPU
authorization to recover these costs, with carrying charges, through the CGA
over a four-year period that began in November 1993. As a result, a
regulatory asset totaling $21.9 million, net of $400,000 recovered during the
fourth quarter, was recorded as of December 31, 1993 and reflected in deferred
charges. In addition, a related liability of $13.1 million was reflected in
deferred credits. Also, approximately $7.9 million of the amount paid to the
pipeline companies relates to gas inventory costs being allocated new storage
services under Order 636. Commonwealth Gas will recover these inventory costs
through the CGA.
(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.
The following is a summary of the consolidated provisions for income
taxes for the years ended December 31, 1993, 1992 and 1991.
1993 1992 1991
(Dollars in Thousands)
Federal
Current $ 9,438 $10,581 $13,102
Deferred 15,127 69 (4,598)
Investment tax credits (1,500) (1,543) (1,567)
23,065 9,107 6,937
State
Current 2,692 2,599 3,401
Deferred 2,282 2,046 726
4,974 4,645 4,127
28,039 13,752 11,064
Amortization of regulatory liability
relating to deferred income taxes (350) (2,189) -
$27,689 $11,563 $11,064
Federal and state income taxes
charged to:
Operating expense $28,256 $20,557 $18,913
Other income (567) (8,994) (7,849)
$27,689 $11,563 $11,064
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
PAGE 59
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 1993 and
1992:
1993 1992
(Dollars in Thousands)
Liabilities
Property-related $178,739 $167,669
Order 636 transition costs, net 3,450 -
Seabrook nonconstruction 6,017 8,175
Postretirement benefits plan 4,136 753
All other 17,054 15,366
209,396 191,963
Assets
Investment tax credit 19,891 19,642
Pension plan 5,720 6,355
Regulatory liability 9,452 10,325
All other 17,689 17,375
52,752 53,697
Accumulated deferred income taxes, net $156,644 $138,266
The net year-end deferred income tax liability above is net of a current
deferred tax asset of $207,000 in 1993 and $8,062,000 in 1992 which was
included in prepaid income taxes in the accompanying Consolidated Balance
Sheets.
The following table, detailing the significant timing differences for
1991, which resulted in deferred income taxes, is required to be disclosed
pursuant to accounting standards for income taxes in effect prior to adoption
of SFAS No. 109:
1991
(Dollars in Thousands)
Seabrook nonconstruction costs $ 1,179
Recovery of Seabrook 2 (826)
Seabrook power contract settlement (3,288)
Accelerated depreciation 11,977
Freetown write-down (7,520)
Capitalized interest during construction (894)
Capitalized leases (1,238)
Capitalized inventory costs (1,025)
Pension costs and deferred compensation (1,347)
Transmission costs (1,210)
Conservation and load management (4,421)
Replacement power costs 1,656
Storm damage 3,638
Other (553)
$(3,872)
PAGE 60
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The total income tax provision set forth on the previous page represents
38% in 1993, 23% in 1992 and 36% in 1991 of income before such taxes. The
following table reconciles the statutory federal income tax rate to these
percentages:
1993 1992 1991
Federal statutory rate 35% 34% 34%
Increase (Decrease) from statutory rate:
Amortization of regulatory liability
relating to deferred income taxes - (11) -
Dividend received deduction (1) (1) (2)
Tax versus book depreciation 2 2 2
State tax net of federal tax benefit 4 7 9
Amortization of investment tax credits (2) (3) (5)
Amortization of excess deferred reserves (1) (2) (2)
Other 1 (3) -
38% 23% 36%
On April 22, 1992, Commonwealth Electric reached a settlement agreement
with the Attorney General of Massachusetts and a consumer group, which was ap-
proved by the DPU. The settlement 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.
Components of pension expense and related economic assumptions were as
follows:
1993 1992 1991
(Dollars in Thousands)
Service cost $ 6,069 $ 5,973 $ 5,923
Interest cost 20,410 18,653 16,794
Return on plan assets (36,552) (24,524) (46,444)
Net amortization and deferral 20,669 9,644 34,359
Total pension expense 10,596 9,746 10,632
Less: Amounts capitalized
and deferred 2,130 2,761 1,435
Net pension expense $ 8,466 $ 6,985 $ 9,197
PAGE 61
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1993 1992 1991
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 8.50
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
rate-making, 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:
1993 1992
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(209,966) $(166,672)
Nonvested (28,184) (11,003)
$(238,150) $(177,675)
Projected benefit obligation $(288,309) $(228,194)
Plan assets at fair market value 268,672 239,849
Projected benefit obligation less
(greater) than plan assets (19,637) 11,655
Unamortized transition obligation 12,857 14,464
Unrecognized prior service cost 14,524 9,442
Unrecognized gain (20,905) (46,136)
Accrued pension liability $ (13,161) $ (10,575)
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. The increase in the accumulated benefit obligation
and the projected benefit obligation from December 31, 1992 to December 31,
1993 was primarily due to a reduction of the discount rate in light of current
interest rates.
(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
PAGE 62
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 and $4,258,000 in 1991.
In 1993, the system began making contributions to various voluntary
employee beneficiary association (VEBA) trusts that were established pursuant
to section 501(c)9 of the Internal Revenue Code (the Code). The system also
made 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 $12,600,000 to these trusts during 1993.
The net periodic postretirement benefit cost for the year ended
December 31, 1993 included the following components:
1993
(Dollars in Thousands)
Service cost $ 2,100
Interest cost 9,017
Return on plan assets (661)
Amortization of transition obligation over 20 years 5,336
Net amortization and deferral 30
Total postretirement benefit cost 15,822
Less: Amounts capitalized and deferred 10,832
Net postretirement benefit cost $ 4,990
The funded status of the system's postretirement benefit plan using a
measurement date of December 31, 1993 is as follows:
1993
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (63,211)
Active participants (48,648)
(111,859)
Plan assets at fair market value 11,037
Projected postretirement benefit obligation greater
than plan assets (100,822)
Unamortized transition obligation 101,375
Unrecognized gain (553)
$ -
In determining its estimated APBO and the funded status of the plan, the
system assumed a discount rate of 7.25%, an expected long-term rate of return
on plan assets of 8.5%, and a medical care cost trend rate of 9%, which
gradually decreases to 5% in the year 2007 and remains at that level
thereafter. The estimate also reflects a trend rate of 14.9% for
reimbursement of Medicare Part B premiums which decreases to 5% by 2007 and a
dental care trend rate of 5% in all years. A one percent change in the
medical trend rate would have a $1.7 million impact on the system's annual
expense (interest component - $1.2 million; service cost - $500,000) and would
change the transition obligation by approximately $14.5 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
PAGE 63
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
recent 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 costs as a regulatory asset. At December 31, 1993, this
deferral amounted to approximately $8.9 million.
(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 benefits other than pensions. The total system contribution
was $4,245,000 in 1993, $4,134,000 in 1992 and $3,903,000 in 1991.
(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, 1993, system companies had $115
million of committed lines of credit that will expire at varying intervals in
1994. These lines are normally renewed upon expiration and require annual
fees of up to .1875% of the individual line. At December 31, 1993, the
uncommitted lines of credit totaled $70 million. Interest rates on the
outstanding borrowings generally are at an adjusted money market rate. Notes
payable to banks totaled $71,975,000 and $165,600,000 at December 31, 1993 and
1992, 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,
1993 are as follows:
Sinking Funds Maturing Debt Issues
Year Subsidiaries System Subsidiaries Total
(Dollars in Thousands)
1994 $ 5,973 $10,000 $ - $15,973
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
(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
PAGE 64
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
payments if mandatory redemptions are in arrears. Details of redemptions for
each series are contained in the following table:
Sinking Funds Optional
Dividend 1994-1998 Redemption
Rate Mandatory Optional Call Prices
(Dollars in Thousands)
Series A 4.80% $120 $120 $102
Series B 8.10 160 160 101
Series C 7.75 540 540 101
Preferred shareholders have no voting rights except in the event that
six full quarterly dividends have not been paid. In this circumstance, the
preferred shareholders are entitled, voting as a class, to elect two of the
nine Trustees of the System.
The preference of these shares in involuntary liquidation is equal to
par value. The shares are of equal rank and are entitled to cumulative
dividends at the annual rate established for each series. No dividend can be
declared on any series unless proportionate dividends are concurrently
declared on the other outstanding series and in the event that dividend
payments are in arrears, the System may not redeem any shares unless all
shares of all preferred series are redeemed.
(7) Disclosure About Fair Value of Financial Instruments
As required by Statement of Financial Accounting Standards No. 107,
"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, 1993 and 1992 are as follows:
1993 1992
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-Term Debt $464,866 $526,405 $373,485 $411,241
Preferred Stock 16,300 15,759 17,120 16,026
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
upon 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.
PAGE 65
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a breakdown, by major class, of property under capital
lease at December 31, 1993 and 1992:
1993 1992
(Dollars in Thousands)
Transmission facilities $14,150 $14,868
Office furniture and computer equipment 10,719 10,733
Other 85 141
24,954 25,742
Less: Accumulated amortization 8,804 7,354
$16,150 $18,388
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, 1993:
Capital Operating
Leases Leases
(Dollars in Thousands)
1994 $ 3,287 $12,295
1995 2,927 10,887
1996 1,984 7,335
1997 1,912 1,248
1998 1,850 352
Beyond 1998 23,970 1,192
Total future minimum lease payments 35,930 $33,309
Less: Estimated interest element
included therein 19,780
Estimated present value of future minimum
lease payments $16,150
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $12,701,000 in 1993, $13,149,000 in 1992 and
$13,058,000 in 1991. There were no contingent rentals and no sublease rentals
for the years 1993, 1992 and 1991.
(9) Dividend Restriction
At December 31, 1993, approximately $116,046,000 of consolidated
retained earnings was restricted against the payment of cash dividends by
terms of indentures and note agreements securing long-term debt.
(10) Energy Park Development
As a result of unsuccessful efforts to develop an energy park, the
System announced on January 23, 1992 its decision to write down its investment
in the Freetown Energy Park project. This action resulted in the recognition
of a charge (net of tax) in 1991 of $14.8 million recorded by COM/Energy
Freetown Realty, a wholly-owned subsidiary of the System.
(11) 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 66
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.
1993 1992 1991
(Dollars in Thousands)
Revenues from
Unaffiliated Customers
Electric $ 624,020 $ 597,269 $ 607,371
Gas 302,644 294,874 252,239
Steam and other 14,035 14,307 13,824
Total Revenues $ 940,699 $ 906,450 $ 873,434
Capital Expenditures (including AFUDC)
Electric $ 29,667 $ 30,207 $ 41,546
Gas 23,117 20,455 17,111
Other 1,796 2,577 2,266
$ 54,580 $ 53,239 $ 60,923
Operating Income
Before Income Taxes
Electric $ 76,117 $ 65,169 $ 80,997
Gas 35,001 32,891 14,277
Steam and other 3,139 2,422 3,095
Total Operating Income Before
Income Taxes $ 114,257 $ 100,482 $ 98,369
Identifiable Assets
Electric $ 914,571 $ 911,877 $ 910,628
Gas 376,683 328,410 304,947
Steam and other 53,062 53,497 53,499
1,344,316 1,293,784 1,269,074
Intercompany eliminations (42,702) (35,653) (35,717)
Investment in corporate joint
ventures 13,549 13,888 14,029
Total Identifiable Assets $1,315,163 $1,272,019 $1,247,386
Depreciation Expense
Electric $ 32,188 $ 33,632 $ 32,869
Gas 8,939 8,270 7,910
Steam and other 1,353 1,262 1,172
Total Depreciation $ 42,480 $ 43,164 $ 41,951
PAGE 67
COMMONWEALTH ENERGY SYSTEM
SELECTED FINANCIAL DATA
1993 1992 1991 1990 1989
(Dollars In Thousands Except Common Share Data)
Operating Revenues
Electric $ 624,020 $ 597,269 $ 607,371 $ 576,416 $ 546,161
Gas 302,644 294,874 252,239 244,074 268,140
Steam and other 14,035 14,307 13,824 15,308 13,197
Total $ 940,699 $ 906,450 $ 873,434 $ 835,798 $ 827,498
Net Income $ 45,834 $ 39,897 $ 19,472 $ 22,636 $ 41,618
Common Share Data-
Earnings per share $4.37 $3.83 $1.82 $2.16 $4.14
Dividends declared
per share $2.92 $2.92 $2.92 $2.92 $2.80
Average shares
outstanding 10,215,614 10,081,868 9,944,433 9,810,180 9,690,277
Total Assets $1,315,163 $1,272,019 $1,247,386 $1,238,083 $1,164,572
Long-term debt $ 448,893 $ 361,092 $ 366,010 $ 412,211 $ 342,803
Redeemable preferred
share investment 15,480 16,300 17,120 17,940 18,760
Common share
investment 337,070 315,219 300,859 307,282 310,566
Total Capitalization $ 801,443 $ 692,611 $ 683,989 $ 737,433 $ 672,129
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
1992 by Quarter
1st 2nd 3rd 4th
(Dollars In Thousands Except Per Share Amounts)
Operating Revenues $257,926 $194,393 $199,703 $254,428
Operating Income 28,053 11,516 15,362 22,805
Income Before Interest Charges 30,148 11,883 15,674 23,630
Net Income 20,406 891 5,093 13,507
Earnings per Common Share 2.00 .05 .47 1.31
Dividends Declared per
Common Share .73 .73 .73 .73
Closing Price of Common Shares-
High 39 40 43 43
Low 36 3/8 34 7/8 39 1/2 40 1/4
PAGE 68
Commonwealth Energy System
One Main Street
Post Office Box 9150
Cambridge, Massachusetts 02142-9150
Telephone (617) 225-4000
