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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
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 2-1647
COMMONWEALTH GAS COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1989250
(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
None None
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
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 ( )
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Outstanding at
Class of Common Stock March 15, 1996
Common Stock, $25 par value 2,857,000 shares
The Company meets the conditions set forth in General Instruction J(1)(a) and
(b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this
Form with the reduced disclosure format.
Documents Incorporated by Reference Part in Form 10-K
None Not Applicable
List of Exhibits begins on page 34 of this report.
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COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1995
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business........................................ 3
General....................................... 3
Gas Supply
General..................................... 3
Hopkinton LNG Facility...................... 4
Rates and Regulation.......................... 5
Competition................................... 7
Environmental Matters......................... 8
Construction and Financing.................... 8
Employees..................................... 9
Item 2. Properties...................................... 9
Item 3. Legal Proceedings............................... 9
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 10
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 11
Item 8. Financial Statements and Supplementary Data..... 14
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............. 14
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 34
Signatures.................................................. 43
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COMMONWEALTH GAS COMPANY
PART I.
Item 1. Business
General
Commonwealth Gas Company (the Company) is engaged in the distribution
and sale of natural gas at retail to approximately 233,000 customers in a
1,067 square mile area which includes 49 communities in eastern, southeastern
and central Massachusetts. The approximate year-round population of this
service area is 1,128,000.
The Company, which was organized in 1851 under the laws of the
Commonwealth of Massachusetts, operates under the jurisdiction of the
Massachusetts Department of Public Utilities (DPU), which regulates retail
rates, accounting, issuance of securities and other matters. The Company is a
wholly-owned subsidiary of Commonwealth Energy System ("System"), which,
together with its subsidiaries, is collectively referred to as "the system."
Since the date of its organization the Company has, from time to time,
acquired the property and franchises of, or merged with, other gas companies.
The Company is the only gas distribution utility in its service area
and, by virtue of its existing franchises, no other gas distribution utility
may extend its operations into the Company's service area without the
authorization of the DPU. Alternative sources of energy are available to
customers within the service territory, but competition from these sources has
not been a significant factor affecting the Company's firm gas sales to
existing customers. Even with the higher cost of storage and liquefied
natural gas (LNG), which is required to supplement pipeline supply, the
overall long-term cost of gas has been competitive with the cost of
alternative fuel sources for most of the Company's customers.
Of the Company's 1995 firm gas unit sales, 55.5% was sold to residential
customers, 27.8% to commercial customers, 11.6% to industrial customers and
5.1% to other customers. Capital expenditures are required to bring gas into
areas of anticipated growth and both the distribution capability and gas
supply must be available when new development begins or potential customers
will seek alternative sources of fuel. Certain industrial customers with
dual-fuel capability can convert from gas to alternative fuels under terms of
contracts which permit interruption of their service upon short notice or at
contractually scheduled times.
Gas Supply
(a) General
In April 1992, the Federal Energy Regulatory Commission (FERC) issued
Order No. 636 (Order 636) which became effective on November 1, 1993. The
order required interstate pipelines to unbundle existing gas sales contracts
into separate components (gas sales, transportation and storage services) and
to provide transportation services that allow customers to receive the same
level and quality of service they had with the previous bundled contracts.
Prior to the implementation of Order 636 the Company purchased the majority of
its gas supplies from either Tennessee Gas Pipeline Company (Tennessee) or
Algonquin Gas Transmission Company (Algonquin), supplemented with third-party
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COMMONWEALTH GAS COMPANY
firm gas purchases, storage services and firm transportation from various
pipelines. Presently, the Company purchases only transportation, storage and
balancing services from these pipelines (and other upstream pipelines that
bring gas from the supply wells to the final transporting pipelines) and
purchases all of its gas supplies from third-party vendors, utilizing firm
contracts with terms ranging from less than one year to three or more years.
The vendors vary from small independent marketers to major gas and oil
companies. Further information concerning Order 636 is contained in Note 6(c)
of the Notes to Financial Statements filed under Item 8 of this report.
In addition to firm transportation and gas supplies mentioned above, the
Company utilizes contracts for underground storage and LNG facilities to meet
its winter peaking demands. The underground storage contracts are a
combination of existing and new agreements which are the result of Order 636
service unbundling. The LNG facilities, described below, are used to liquefy
and store pipeline gas during the warmer months for use during the heating
season. During 1995, over 99% of the gas utilized by the Company was
delivered by the interstate pipeline system. The remaining small quantity
(approximately 150,000 MMBTU) was delivered as LNG from Distrigas of
Massachusetts.
The Company entered into a multi-party agreement in 1992 to assume a
portion of Boston Gas Company's contracts to purchase Canadian gas supplies
from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois
Gas Transmission System and Tennessee pipelines. The ANE gas supply contract
was filed with the DPU and hearings were completed in April 1993. The DPU
approved the ANE gas supply contract in November 1995. The Company should
complete assumption of these contracts during the first half of 1996 upon
final execution of all pertinent agreements and contracts.
The Company began transporting gas on its distribution system in 1990
for end-users. There are currently thirty-four customers using this
transportation service, accounting for 6,791 BBTU of throughput in 1995 which
represented approximately 12.9% of system throughput.
(b) Hopkinton LNG Facility
A portion of the Company'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.
The Company 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. The Company furnishes pipeline gas
during the period April 15 to November 15 each year for liquefaction and
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COMMONWEALTH GAS COMPANY
storage. As the need arises, LNG is vaporized and placed in the distribution
system of the Company.
Based upon information presently available regarding projected growth in
demand and estimates of availability of future supplies of pipeline gas, the
Company believes that its present sources of gas supply are adequate to meet
existing load and allow for future growth in sales.
Rates and Regulation
(a) Automatic Adjustment Clauses
The Company has a Standard Seasonal Cost of Gas Adjustment rate schedule
(CGA) which provides for the recovery, from firm customers, of purchased gas
and conservation and load management costs not recovered through base rates.
These schedules, which require DPU approval, are estimated semi-annually and
include credits for gas pipeline refunds and profit margins applicable to
interruptible and other non-firm sales. Actual gas costs are reconciled
annually as of October 31, and any difference is included as an adjustment in
the calculation of the decimals for the two subsequent six-month periods.
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, the Company 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 the Company's plans for construction of new gas
manufacturing or storage facilities and certain high-pressure gas pipelines
are consistent with current health, environmental protection, resource use and
development policies as adopted by the Commonwealth of Massachusetts. The
Company filed a long-range forecast with the Council on July 20, 1990 and
updated aspects of the filing in March 1991. This forecast was combined with
the DPU review of the ANE contract. Both issues were approved by the DPU in
November 1995.
(b) Gas Demand and Transition Costs
The Company is obligated, as part of its pipeline transportation
contracts, storage contracts and gas purchase contracts, to pay monthly demand
charges which are recovered from customers through the CGA.
As a direct result of implementation of Order 636, most pipeline
companies are incurring transition costs which include the cost of
restructuring gas supply contracts, the value of facilities that were
supporting the gas sales function and are no longer used and useful for
transportation only services, the cost of contracts with upstream pipeline
companies and various miscellaneous costs. For additional information on
these transition costs refer to Note 6(c) of Notes to Financial Statements
filed under Item 8 of this report.
The Company is collecting all contract restructuring costs from its
customers through the CGA as permitted by the DPU.
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COMMONWEALTH GAS COMPANY
(c) Regulatory Matters
In May 1994, the Company requested the DPU to change the back-up service
charges under its firm transportation rate. Back-up charges result when the
Company sells gas from its system supplies to a customer whose off-system gas
supply has failed or is temporarily unavailable for reasons beyond the
customer's control. The change involved an upward indexing of backup charges
based on changes in the gas supply demand costs occasioned by Order 636. On
December 22, 1994, the DPU approved the Company's requested change effective
January 1, 1995. This change, which has no effect on revenue, results in a
more equitable recovery of pipeline capacity costs between Commonwealth Gas'
total requirements and transportation customers.
(d) Quasi-firm and Off-system Gas Sales Services
In late August 1994, the Company received regulatory approval for a new
quasi-firm sales service, designed for customers with dual-fuel capability,
that provides a level of service between full firm and interruptible. In
exchange for prices lower than full firm service, quasi-firm customers receive
interruptible service in peak demand months and firm service in off-peak
months. The Company sold 1,906 BBTU of gas to quasi-firm customers in 1995.
Also in 1995, the Company was able to maximize the use of its gas supply
portfolio through off-system sales and capacity release. In 1995, 4,043 BBTU
of gas was sold in the off-system market and 10,352 BBTU of pipeline capacity
was released. These efforts helped to reduce the cost of gas to the Company's
firm customers while allowing more flexibility in supply management and
pricing options.
A portion of the margins realized on quasi-firm and off-system sales
(approximately $2 million as of December 31, 1995) is currently being deferred
pending a ruling on a margin-sharing proposal filed with the DPU in December
1995 for quasi-firm sales. A similar filing is expected to be filed for off-
system sales in 1996. Both quasi-firm and off-system sales allow the Company
to more efficiently utilize its gas distribution system and enable fixed costs
to be spread over larger volumes of throughput. This results in a lower cost
of gas for firm customers helping the Company to remain as competitive as
possible in its traditional core market.
(e) Conservation and Load Management Program
The Company offers conservation measures to its residential and multi-
family customers through programs approved by the DPU in June 1992. The
Company recovers the costs of these programs via separately stated
Conservation Charge (CC) decimals. The programs have been extended through
subsequent DPU approvals, the most noteworthy being the settlement agreement
approved on November 23, 1994 which enabled the Company to recover "lost
margins" from customers effective January 1995. Specifically, the settlement
allows the Company to remain whole while it offers programs that reduce sales,
by recovering through the CC decimal the portion of the lost margins revenue
associated with all saved therms resulting from conservation program
installations. As a result, the Company collected $1.4 million in lost
margins during 1995, and has obtained approval to collect $2.1 million in lost
margins during 1996.
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COMMONWEALTH GAS COMPANY
(f) Potential Impact of Regulatory Restructuring
Based on the current regulatory framework, the Company accounts for the
economic effects of regulation in accordance with the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." The Company has established various regula-
tory assets in cases where the DPU has permitted or is expected to permit
recovery of specific costs over time. These regulatory assets amounted to $22
million (5.9% of total assets) as of December 31, 1995. Similarly, the
regulatory liability established by the Company is required to be refunded to
customers over time. In March 1995, the Financial Accounting Standards Board
issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes stricter
criteria for regulatory assets by requiring that such assets be probable of
future recovery at each balance sheet date. Management does not expect that
the effects of SFAS No. 121, which the Company adopted on January 1, 1996,
will have a material impact on its financial position or results of
operations.
Competition
The Company faces competition from suppliers of fuel oil, propane and
electricity and also, for large commercial and industrial customers, from
other suppliers of natural gas. The Company is continuously developing and
implementing strategies to deal with the increasingly competitive environment.
Innovative pricing mechanisms have been developed and will continue to be
developed to retain existing customers, add new retail and wholesale customers
and expand beyond current markets. Aggressive marketing efforts have
increased our residential heating customer base by more than 1,500 during
1995. In addition, there are vast opportunities in natural gas engine-driven
cooling systems and absorption chillers which are being actively and
successfully pursued by the Company and will add desirable off-peak summer
load. The Company has also expanded existing services such as the
merchandising of water-heaters and heating systems.
FERC Order 636 marked the beginning of the deregulation and
restructuring of the natural gas industry. In addition to opening up customer
markets to competition, the regulations shifted many supply-related
responsibilities to local distribution companies including direct gas
purchases from suppliers, pipelines and producers, transportation services and
storage services. The Company has developed a gas control and information
system that has very sophisticated purchasing and tracking systems. This
ability, coupled with aggressive planning and procurement strategies, will
help to secure the Company's existing market share and permit the expansion of
core and non-core supply capabilities.
The Company's substantial LNG and storage capabilities provide it with
the reliability needed during the coldest winter days and the flexibility to
sell capacity when supply and pricing conditions are favorable. Through
expanding non-firm and transportation sales, the Company has been able to
maximize the use of its gas supply and transportation system resulting in a
lower cost of gas for firm customers helping the Company to remain competitive
in its traditional markets.
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COMMONWEALTH GAS COMPANY
The Company continues to reduce costs and improve service through state-
of-the-art technology. Some of the examples of cost-effective technology
presently in use include: (1) Automated Meter Reading (AMR) which has
dramatically lowered meter reading costs, improved the rate at which meters
are read, and enhanced customer convenience. To date, 80% of the Company's
meters are equipped with AMR technology and the read rate has improved to
nearly 100%; (2) a new trenchless technology that enables the Company to
maintain or upgrade its distribution system with a minimum of cost and
disturbance with a device known as a "bullet" that allows the replacement of
old gas lines with polyethylene pipe, eliminating the need for costly and
time-consuming street excavations; and (3) the use of a miniature camera that
inspects the inside walls of low pressure mains without interrupting service
to customers and replaces the more traditional method which involved costly
digging and manual inspection to find problem areas.
Environmental Matters
The Company is participating in the assessment of a number of former
manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to
determine if and to what extent such sites have been contaminated and whether
the Company may be responsible for remedial actions.
The costs associated with the assessment and clean-up of these sites are
recoverable in rates through the cost of gas adjustment clause pursuant to a
1990 DPU order over a seven-year amortization period without carrying costs.
The Company has recorded a $2.6 million liability that reflects its best
estimate (based on current information) of the costs to be incurred in
connection with assessment and remediation activities identified to this
point. The Company has also recorded a regulatory asset in anticipation of
recovery of these costs. The Company is unable to predict the total cost to
ultimately resolve these matters due to significant uncertainty as to the
actual site conditions and the extent of any associated remediation activities
and the assignment of responsibility. However, it is expected that all such
costs will continue to be recovered in rates as described above.
The Company is also involved in certain other known or potentially
contaminated sites where the associated costs may not be recoverable in rates.
In 1994 the Company recorded an estimated liability (and a charge to
operations) of $500,000 to cover the expected costs associated with assessment
and remediation activities. These estimates are reviewed and adjusted
periodically as further investigation and assignment of responsibility occurs.
As noted above, the Company is unable to estimate its ultimate liability for
future environmental remediation costs. However, in view of the Company's
current assessment of its environmental responsibilities, existing legal
requirements and regulatory policies, management does not believe that these
matters will have a material adverse impact on the Company's results of
operations or financial position.
Construction and Financing
Information concerning the Company's financing and construction programs
is contained in Note 6(a) of the Notes to Financial Statements filed under
Item 8 of this report.
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COMMONWEALTH GAS COMPANY
Employees
The Company has 699 regular employees which is 3.3% lower than last
year's level. Approximately 64% of these employees are represented by three
collective bargaining units with agreements in effect through March 31, 1996,
June 30, 1996 and September 18, 1998. Employee relations have generally been
satisfactory.
Item 2. Properties
The Company's principal gas properties consist of distribution mains,
services and meters necessary to maintain reliable service to customers. At
the end of 1995, the gas system included 2,778 miles of gas distribution
lines, 164,697 services and 240,948 customer meters together with the
necessary measuring and regulating equipment.
In addition, the Company owns a central headquarters and service
building in Southborough, Massachusetts, five district office buildings and
various natural gas receiving and take stations.
The Company's property is subject to encumbrances under its Indenture of
Trust and First Mortgage Bonds.
Item 3. Legal Proceedings
The Company is not a party to any pending material legal proceeding.
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COMMONWEALTH GAS COMPANY
PART II.
Item 5. Market for the Registrant's Common Stock and Related Stockholder
Matters
(a) Principal Market
Not applicable. The Company is a wholly-owned subsidiary of
Commonwealth Energy System.
(b) Number of Shareholders at December 31, 1995
One
(c) Frequency and Amount of Dividends Declared in 1995 and 1994
1995 1994
Per Share Per Share
Declaration Date Amount Declaration Date Amount
January 25, 1995 $1.75 January 24, 1994 $2.10
April 21, 1995 2.65 April 21, 1994 2.50
$4.40 July 15, 1994 .50
$5.10
(d) Future dividends may vary depending upon the Company's earnings
and capital requirements as well as financial and other conditions
existing at that time.
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COMMONWEALTH GAS COMPANY
Item 7. Management's Discussion and Analysis of Results of Operations
The following is a discussion of certain significant factors which have
affected operating revenues, expenses and net income during the periods
included in the accompanying statements of income and is presented to
facilitate an understanding of the results of operations. This discussion
should be read in conjunction with the Notes to Financial Statements filed
under Item 8 of this report.
A summary of the period to period changes in the principal items
included in the accompanying statements of income for the years ended December
31, 1995 and 1994 and unit sales for these periods is shown below:
Years Ended Years Ended
December 31, December 31,
1995 and 1994 1994 and 1993
Increase (Decrease)
(Dollars in Thousands)
Gas Operating Revenues $(16 804) (5.2)% $21 597 7.1 %
Operating Expenses -
Cost of gas sold (19 657) (10.4) 21 162 12.6
Other operation
and maintenance (2 756) (3.1) 2 745 3.3
Depreciation 97 1.0 620 6.9
Taxes -
Federal and state income 1 686 21.1 (1 860) (18.9)
Local property 462 8.7 471 9.7
Payroll and other 103 3.8 (64) (2.3)
(20 065) (6.6) 23 074 8.3
Operating Income 3 261 13.8 (1 477) (5.9)
Other Income 812 192.9 (216) (33.9)
Income Before Interest Charges 4 073 16.9 (1 693) (6.6)
Interest Charges 1 412 13.4 1 038 10.9
Net Income $ 2 661 19.6 $(2 731) (16.8)
Unit Sales (BBTU)
Firm (81) (0.2) % (680) (1.7)%
Interruptible (1 437) (52.0) 302 12.3
Off-system (2 358) (36.8) 6 401 -
Quasi-firm 1 419 291.4 487 -
(2 457) (5.1) 6 510 15.6
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COMMONWEALTH GAS COMPANY
The following is a summary of unit sales, transportation volume and customers
for the periods indicated:
Years Ended December 31,
1995 1994 1993
Unit Sales (BBTU):
Residential 21 336 21 515 22 252
Commercial 10 710 10 728 10 931
Industrial 4 445 4 401 4 205
Other 1 967 1 895 1 831
Total firm 38 458 38 539 39 219
Off-System 4 043 6 401 -
Quasi-Firm 1 906 487 -
Interruptible 1 324 2 761 2 459
Total sales 45 731 48 188 41 678
Transportation 6 791 3 003 3 171
Total 52 522 51 191 44 849
Customers at End of Period:
Residential 212 329 211 075 211 877
Commercial 18 761 18 466 18 323
Industrial 933 928 920
Other 1 168 1 140 1 093
Total 233 191 231 609 232 213
Operating Revenues, Cost of Gas Sold and Unit Sales
In 1995, operating revenues decreased by $16.8 million or 5.2% mainly
due to a decrease in the cost of gas sold ($19.7 million), lower conservation
and load management (C&LM) costs ($910,000) and a decrease in unit sales.
Partially offsetting these decreases were higher transportation revenues ($2.3
million). In 1994, operating revenues increased by $21.6 million or 7.1%
mainly due to a $21 million increase in the cost of gas sold, revenues
associated with off-system and quasi-firm sales, which were non-existent in
1993, and higher transportation revenues ($478,000). Also contributing to the
increase were higher C&LM costs ($2.6 million). Partially offsetting these
increases was a decrease in firm unit sales of 1.7%.
The cost of gas sold in 1995 and 1994 reflects prices and sales levels
as well as the amortization of Order 636 transition costs ($1.3 million in
1995, $3.6 million in 1994 and $396,000 in 1993) and refunds received from gas
suppliers ($9.1 million in 1995, $6.1 million in 1994 and $7 million in 1993).
Despite extremely mild weather conditions experienced throughout the
region during the first quarter of 1995, a very cold fourth quarter left unit
sales virtually unchanged for the year. Firm unit sales decreased by 1.7% in
1994 due to the unseasonably warm weather conditions experienced throughout
the region in the fourth quarter. This more than offset a 5.4% increase in
the first quarter of 1994 resulting from the colder than normal weather.
Interruptible sales decreased by 52% in 1995 and increased by approximately
12% in 1994 reflecting the competitive market conditions for energy resources
that exists today as well as the conversion of interruptible sales to quasi-
firm. Interruptible sales have no impact on net income since all of the
margins from these sales are flowed back to firm customers through the CGA.
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COMMONWEALTH GAS COMPANY
Off-system sales and quasi-firm sales fluctuated but are expected to
continue as important elements of the Company's total gas service options.
The Company anticipates that the aforementioned margin-sharing proposal for
these sales will have a positive impact on earnings while continuing to reduce
the cost of gas to firm customers.
The customer level increased slightly in 1995 mainly due to new home
construction and conversion activity and was virtually unchanged in 1994.
Other Operating Expenses
In 1995, other operation and maintenance decreased by $2.8 million or
3.1% mainly due to lower C&LM costs ($910,000), lower distribution expenses
due to fewer leak repair activities ($699,000), a decreased provision for bad
debts ($640,000), lower insurance and employee benefit costs ($471,000) and
decreased engineering expenses ($392,000). Also contributing to the decrease
was net savings in several areas resulting primarily from the implementation
of automated meter reading (AMR) ($100,000). These decreases were partially
offset by increased labor costs ($1.2 million).
Other operation and maintenance increased by approximately 3.3%, or
$2.7 million, in 1994 due mainly to higher C&LM charges ($2.6 million) and
higher insurance and employee benefit costs ($821,000). These increases were
offset, in part, by a decline in the cost of services rendered by affiliate
COM/Energy Services Company attributable to a second quarter 1993 work force
reduction and a 2% ($683,000) decline in payroll costs reflecting a lower work
force level achieved through attrition and reduced overtime.
Depreciation and Taxes
The increase in depreciation expense in both 1995 and 1994 resulted
from higher levels of depreciable plant-in-service.
The increase in federal and state income taxes in 1995 and the decrease
in 1994 was due to the respective levels of pretax income. The change in
payroll and other taxes in both periods reflects the level of payroll costs in
each period. The increase in local property taxes during both 1995 and 1994
was due to higher tax rates and assessments in the Company's service
territory.
Other Income and Interest Charges
In 1995, other income increased by $812,000 due primarily to interest
income received by the Company in connection with its participation in the
COM/Energy Money Pool. Other income decreased by $216,000 in 1994 due
primarily to the absence of a litigation settlement received in 1993
($193,000) and lower sales of design heating systems offset, in part, by
interest related to a Massachusetts sales tax abatement ($58,000).
Total interest charges increased by $1.4 million in 1995 mainly due to
higher interest on deferred gas costs partially offset by a decrease in short-
term interest charges reflecting lower levels of debt.
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COMMONWEALTH GAS COMPANY
Total interest charges increased by more than $1 million in 1994 mainly
due to the issuance of $35 million in new long-term debt in December 1993 and,
to a lesser extent, higher interest rates and interest to be refunded to the
Company's customers in connection with the aforementioned sales tax abatement.
These increases were partially offset by a lower average level of short-term
borrowings.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed
herewith on pages 15 through 33 of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
None.
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COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1995
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Commonwealth Gas Company:
We have audited the accompanying balance sheets of COMMONWEALTH GAS
COMPANY (a Massachusetts corporation and wholly-owned subsidiary of
Commonwealth Energy System) as of December 31, 1995 and 1994, and the related
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1995. These financial statements and
the schedule referred to below are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule 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 Commonwealth Gas
Company as of December 31, 1995 and 1994, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting prin-
ciples.
Our audits were made for the purpose of forming an opinion on the
basic financial statements taken as a whole. The schedule listed in the index
to financial statements and schedule is presented for purposes of complying
with the Securities and Exchange Commission's rules and is not part of the
basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states, 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 LLP
Boston, Massachusetts
February 16, 1996.
<PAGE>
<PAGE 16>
COMMONWEALTH GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1995 and 1994
Statements of Income for the Years Ended December 31, 1995, 1994 and
1993
Statements of Retained Earnings for the Years Ended December 31, 1995,
1994 and 1993
Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993
Notes to Financial Statements
PART IV.
SCHEDULE
II Valuation and Qualifying Accounts for the Years Ended December 31,
1995, 1994 and 1993
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or
not required or because the required information is included in the
financial statements or notes thereto.
<PAGE>
<PAGE 17>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
ASSETS
1995 1994
(Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $348 284 $339 476
Less - Accumulated depreciation 92 881 85 162
255 403 254 314
Add - Construction work in progress 738 719
256 141 255 033
CURRENT ASSETS
Cash 2 113 4 862
Accounts receivable -
Affiliated companies 188 462
Customers, less reserves of $2,691,000 in 1995
and $2,827,000 in 1994 40 317 32 890
Unbilled revenues 22 850 20 892
Inventories, at average cost -
Natural gas 17 339 24 161
Materials and supplies 1 286 1 593
Prepaid taxes -
Property 3 094 2 861
Income 384 619
Other 1 138 1 076
88 709 89 416
DEFERRED CHARGES
Order 636 transition costs 11 711 19 201
Other 18 054 17 155
29 765 36 356
$374 615 $380 805
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 18>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
CAPITALIZATION AND LIABILITIES
1995 1994
(Dollars in Thousands)
CAPITALIZATION
Common Equity -
Common stock, $25 par value -
Authorized and outstanding -
2,857,000 shares, wholly-owned
by Commonwealth Energy
System (Parent) $ 71 425 $ 71 425
Amounts paid in excess of par value 27 739 27 739
Retained earnings 10 495 6 837
109 659 106 001
Long-term debt, less maturing issues and
current sinking fund requirements 78 100 91 750
187 759 197 751
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 12 200 24 950
Advances from affiliates 1 850 11 220
Maturing long-term debt 10 000 -
24 050 36 170
Other Current Liabilities -
Current sinking fund requirements 3 650 3 650
Accounts payable -
Affiliated companies 2 229 2 669
Other 37 471 33 214
Refundable gas costs 33 034 27 832
Customer deposits 1 354 1 433
Accrued local property and other taxes 3 435 3 317
Accrued interest 1 938 749
Other 3 535 4 746
86 646 77 610
110 696 113 780
DEFERRED CREDITS
Accumulated deferred income taxes 35 586 32 699
Unamortized investment tax credits 5 862 6 065
Order 636 transition costs 11 711 7 811
Other 23 001 22 699
76 160 69 274
COMMITMENTS AND CONTINGENCIES
$374 615 $380 805
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 19>
COMMONWEALTH GAS COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
(Dollars in Thousands)
GAS OPERATING REVENUES $308 922 $325 726 $304 129
OPERATING EXPENSES
Cost of gas sold 169 112 188 769 167 607
Other operation 72 138 74 636 71 776
Maintenance 11 577 11 809 11 929
Depreciation 9 656 9 559 8 939
Amortization 1 212 1 238 1 233
Taxes -
Income 9 669 7 983 9 843
Local property 5 798 5 336 4 865
Payroll and other 2 818 2 715 2 779
281 980 302 045 278 971
OPERATING INCOME 26 942 23 681 25 158
OTHER INCOME 1 233 421 637
INCOME BEFORE INTEREST CHARGES 28 175 24 102 25 795
INTEREST CHARGES
Long-term debt 8 174 8 488 6 345
Other interest charges 3 827 2 073 3 170
Allowance for borrowed funds used
during construction (55) (27) (19)
11 946 10 534 9 496
NET INCOME $ 16 229 $ 13 568 $ 16 299
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 20>
COMMONWEALTH GAS COMPANY
STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
(Dollars in Thousands)
Balance at beginning of year $ 6 837 $ 7 840 $ 6 994
Add (Deduct):
Net income 16 229 13 568 16 299
Cash dividends on common stock (12 571) (14 571) (15 453)
Balance at end of year $10 495 $ 6 837 $ 7 840
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 21>
COMMONWEALTH GAS COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993
(Dollars in Thousands)
OPERATING ACTIVITIES
Net income $16 229 $13 568 $16 299
Effects of noncash items -
Depreciation and amortization 12 983 15 159 11 363
Deferred income taxes (4 026) 3 883 8 018
Investment tax credits (203) (205) (210)
Change in working capital exclusive
of cash and interim financing -
Accounts receivable and unbilled
revenues (9 111) 8 063 (4 714)
Prepaid income taxes 235 1 193 4 878
Local property and other taxes, net (115) 145 57
Accounts payable and other 15 985 17 925 (6 873)
Deferred postretirement benefit costs (2 376) (2 306) (3 062)
Transition costs, net 11 390 (2 585) (8 805)
All other operating items 10 908 (7 393) (9 065)
Net cash provided by operating activities 51 899 47 447 7 886
INVESTING ACTIVITIES
Additions to property, plant and
equipment (exclusive of AFUDC) (16 252) (17 994) (23 272)
Allowance for borrowed funds used
during construction (55) (27) (19)
Net cash used for investing activities (16 307) (18 021) (23 291)
FINANCING ACTIVITIES
Sale of common stock to Parent - - 18 000
Payment of dividends (12 571) (14 571) (15 453)
Payment of short-term borrowings (12 750) (16 025) (11 500)
Proceeds from (payment of) affiliate
borrowings (9 370) 8 385 (5 705)
Retirement of long-term debt
through sinking funds (3 650) (3 650) (3 650)
Long-term debt issue - - 35 000
Net cash provided by (used for)
financing activities (38 341) (25 861) 16 692
Net increase (decrease) in cash (2 749) 3 565 1 287
Cash at beginning of period 4 862 1 297 10
Cash at end of period $ 2 113 $ 4 862 $ 1 297
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $11 035 $ 9 799 $ 8 797
Income taxes $ 8 118 $ 4 636 $ 3 133
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 22>
COMMONWEALTH GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) General Information
Commonwealth Gas Company (the Company) is a wholly-owned subsidiary of
Commonwealth Energy System. The parent company is referred to in this
report as the "System" and, together with its subsidiaries, is referred to
as "the system." The System is an exempt public utility holding company
under the provisions of the Public Utility Holding Company Act of 1935 and,
in addition to its investment in the Company, has interests in other
utility companies and several non-regulated companies.
The Company is engaged in the distribution and sale of natural gas at
retail to approximately 233,000 customers in a 1,067 square-mile area which
includes 49 communities in eastern, southeastern and central Massachusetts
including New Bedford, Cambridge, Plymouth and Worcester. The approximate
year-round population of this service area is 1,128,000.
The Company has 699 regular employees including 447 (64%) who are repre-
sented by three collective bargaining units. Agreements with two units
representing approximately 63% of regular employees are scheduled to expire
in 1996. Employee relations have generally been satisfactory.
(2) Significant Accounting Policies
(a) Principles of Accounting
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Public Utilities (DPU).
Based on the current regulatory framework, the Company accounts for the
economic effects of regulation in accordance with the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." The Company has established
various regulatory assets in cases where the DPU has permitted or is
expected to permit recovery of specific costs over time. Similarly, the
regulatory liability established by the Company is required to be refunded
to customers over time. In March 1995, the Financial Accounting Standards
Board issued SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes
stricter criteria for regulatory assets by requiring that such assets be
probable of future recovery at each balance sheet date. Management does
not expect that the effects of SFAS No. 121, which the Company adopted on
<PAGE>
<PAGE 23>
COMMONWEALTH GAS COMPANY
January 1, 1996, will have a material impact on its financial position or
results of operations.
The principal regulatory assets included in deferred charges at
December 31, 1995 and 1994 were as follows:
1995 1994
(Dollars in Thousands)
Transition costs $11 711 $19 201
Postretirement benefit costs including
pensions 7 744 5 367
Environmental costs 2 551 2 346
Total regulatory assets $22 006 $26 914
The principal regulatory liability, reflected in deferred credits-other
and relating to income taxes, was $8.6 million and $9.9 million at
December 31, 1995 and 1994, respectively.
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliate Cambridge Electric
Light Company as follows:
(Dollars in Thousands)
1995 1994 1993
Cost $ 289 $1 493 $1 311
Margin 64 220 76
Total $ 353 $1 713 $1 387
The margin realized on these sales is credited to firm customers through
the Cost of Gas Adjustment (CGA).
Other intercompany transactions include payments by the Company for
management, accounting, data processing and other services provided by
COM/Energy Services Company. In addition, the Company incurred costs paid to
affiliate Hopkinton LNG Corp. for liquefaction and vaporization services that
amounted to $9,988,000, $10,126,000 and $9,587,000 in 1995, 1994 and 1993,
respectively. Transactions with system companies are subject to review by
the DPU.
(d) Operating Revenues
Customers are billed for their use of 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.
The Company is permitted to bill customers currently for total gas
costs, certain conservation and load management costs and environmental costs
through adjustment clauses. Amounts recoverable under the adjustment clauses
are subject to review and adjustment by the DPU.
The amount of such costs incurred by the Company but not yet reflected
in customers' bills is recorded as unbilled revenues. However, as of
December 31, 1995 and 1994, the Company had overcollected $33,034,000 and
$27,832,000, respectively, which is reflected as a liability in the
<PAGE>
<PAGE 24>
COMMONWEALTH GAS COMPANY
accompanying balance sheets. These overcollected amounts, which include
interest, are returned to customers in subsequent months.
(e) Depreciation
Depreciation is provided using the straight-line method at rates
intended to amortize the original cost and the estimated cost of removal less
salvage of properties over their estimated economic lives. The Company's
composite depreciation rate, based on average depreciable property in
service, was 2.90% in 1995, 2.98% in 1994 and 2.95% in 1993.
(f) Maintenance
Expenditures for repairs of property and replacement and renewal of
items determined to be less than units of property are charged to maintenance
expense. Additions, replacements and renewals of property considered to be
units of property are charged to the appropriate plant accounts. Upon
retirement, accumulated depreciation is charged with the original cost of
property units and the cost of removal less salvage.
(g) Allowance for Funds Used During Construction
Under applicable rate-making practices, the Company is permitted to
include an allowance for funds used during construction (AFUDC) as an element
of its 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
the Company earns a return. An amount equal to the AFUDC capitalized in the
current period is reflected in the accompanying statements of income.
While AFUDC does not provide funds currently, these amounts are
recoverable in revenues over the service life of the constructed property.
The amount of AFUDC recorded was at a weighted average rate of 6.50% in 1995,
4.75% in 1994 and 3.50% in 1993.
(3) Income Taxes
For financial reporting purposes, the Company provides federal and state
income taxes on a separate return basis. However, for federal income tax
purposes, the Company's taxable income and deductions are included in the
consolidated income tax return of the System, and it makes tax payments or
receives refunds on the basis of its tax attributes in the tax return in
accordance with applicable regulations.
<PAGE>
<PAGE 25>
COMMONWEALTH GAS COMPANY
The following is a summary of the provisions for income taxes for the
years ended December 31, 1995, 1994 and 1993:
1995 1994 1993
(Dollars in Thousands)
Federal -
Current $11 602 $3 585 $1 619
Deferred (3 155) 3 405 6 956
Investment tax credits (203) (205) (210)
8 244 6 785 8 365
State -
Current 2 296 720 416
Deferred (618) 667 1 278
1 678 1 387 1 694
9 922 8 172 10 059
Amortization of regulatory liability
relating to deferred income taxes (253) (189) (216)
Total federal and state
income taxes $ 9 669 $ 7 983 $ 9 843
Deferred tax liabilities and assets are determined based on the
difference between the financial statement basis 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 1995 and
1994:
1995 1994
(Dollars in Thousands)
Liabilities
Property-related $42 361 $39 768
Transition costs, net - 4 094
Postretirement benefits plan 2 933 2 101
All other 1 734 3 075
47 028 49 038
Assets
Investment tax credit 3 783 3 914
Pension plan 3 099 2 739
Regulatory liability 2 992 3 155
Inventory repricing 4 047 4 285
All other 3 707 2 828
17 628 16 921
Accumulated deferred income taxes, net $29 400 $32 117
The net year-end deferred income tax liability above is net of current
deferred tax assets of $6,186,000 in 1995 and $582,000 in 1994 which are
included in other deferred charges in the accompanying balance sheets.
<PAGE>
<PAGE 26>
COMMONWEALTH GAS COMPANY
The total income tax provision set forth on the previous page
represents 37% in 1995, 37% in 1994 and 38% in 1993 of income before such
taxes. The following table reconciles the statutory federal income tax rate
to these percentages:
1995 1994 1993
Federal statutory rate 35% 35% 35%
Federal income tax expense at statutory levels $9 064 $7 543 $9 150
Increase (Decrease) from statutory rate:
State tax net of federal tax benefit 1 091 902 1 101
Amortization of investment tax credits (203) (205) (210)
Amortization of excess deferred reserves (253) (189) (216)
Other (30) (68) 18
$9 669 $7 983 $ 9 843
Effective federal tax rate 37% 37% 38%
(4) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current maturities and current
sinking fund requirements, collateralized by substantially all of the
Company's property, is as follows:
Original Balance December 31,
Issue 1995 1994
(Dollars in Thousands)
First Mortgage Bonds -
8.99%, Series H, due 1996 $10 000 $ - $10 000
8.99%, Series I, due 2001 40 000 18 100 21 750
9.95%, Series J, due 2020 25 000 25 000 25 000
7.11%, Series K, due 2033 35 000 35 000 35 000
$78 100 $91 750
Under terms of its indenture, the Company is required to make periodic
sinking fund payments for retirement of outstanding long-term debt. The
Company may purchase its outstanding bonds in advance of sinking fund
requirements under favorable conditions. The required sinking fund payments
and balances of maturing debt issues for the five years subsequent to
December 31, 1995 are as follows:
Sinking Fund Maturing Debt
Year Requirements Issues Total
(Dollars in Thousands)
1996 $3 650 $10 000 $13 650
1997 3 650 - 3 650
1998 3 650 - 3 650
1999 3 650 - 3 650
2000 3 650 - 3 650
<PAGE>
<PAGE 27>
COMMONWEALTH GAS COMPANY
(b) Notes Payable to Banks
The Company and other system companies maintain both committed and
uncommitted lines of credit for the short-term financing of their
construction programs, on a short-term basis, and for other corporate
purposes. As of December 31, 1995, system companies had $80 million of
committed lines that will expire at varying intervals in 1996. These lines
are normally renewed upon expiration and require annual fees up to .1875% of
the individual line. At December 31, 1995, the uncommitted lines of credit
totaled $70 million. Interest rates on the outstanding borrowings generally
are at an adjusted money market rate and averaged 6.1% and 4.4% in 1995 and
1994, respectively. The Company's notes payable to banks totaled $12,200,000
and $24,950,000 at December 31, 1995 and 1994, respectively.
(c) Advances from Affiliates
The Company had short-term notes payable to the System totaling
$1,425,000 and $2,935,000 at December 31, 1995 and 1994, respectively. These
notes are written for a term of up to 11 months and 29 days. Interest is at
the prime rate and is adjusted for changes in that rate during the term of
the notes. This rate averaged 8.8% and 7.3% in 1995 and 1994, respectively.
The Company is a member of the COM/Energy Money Pool (the Pool), an
arrangement among the subsidiaries of the System, whereby 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. Interest rates on the
outstanding borrowings are based on the monthly average rate the Company
would otherwise have to pay banks, less one-half the difference between that
rate and the monthly average U.S. Treasury Bill weekly auction rate. The
borrowings are for a period of less than one year and are payable upon
demand. Rates on these borrowings averaged 5.8% and 4.3% in 1995 and 1994,
respectively. The Company had borrowings from the Pool of $425,000 and
$8,285,000 at December 31, 1995 and 1994, respectively.
(d) Disclosures about Fair Value of Financial Instruments
The fair value of certain financial instruments included in the
accompanying balance sheets as of December 31, 1995 and 1994 are as follows:
1995 1994
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-Term Debt $91 750 $103 055 $95 400 $ 93 134
The carrying amount of cash, notes payable to banks and advances from
affiliates approximates the fair value because of the short maturity of these
financial instruments.
<PAGE>
<PAGE 28>
COMMONWEALTH GAS COMPANY
The estimated fair value of long-term debt is based on quoted market
prices of the same or similar issues or on the current rates offered for debt
with the same remaining maturity. The fair values shown above do not purport
to represent the amounts at which those obligations would be settled.
(5) Employee Benefit Plans
(a) Pension
The Company has a noncontributory pension plan covering substantially
all regular employees who have attained the age of 21 and have completed one
year of service. Pension benefits are based on an employee's years of
service and compensation. The Company makes monthly contributions to the
plan consistent with the funding requirements of the Employee Retirement
Income Security Act of 1974.
Components of pension expense and related assumptions to develop pension
expense were as follows:
1995 1994 1993
(Dollars in Thousands)
Service cost $ 1 912 $ 2 278 $ 1 904
Interest cost 7 094 6 378 6 037
Return on plan assets - (gain)/loss (18 598) 1 345 (10 821)
Net amortization and deferral 12 909 (6 297) 6 317
Total pension expense 3 317 3 704 3 437
Transfers from affiliated
companies, net 463 478 453
Less: Amounts capitalized
and deferred 342 336 328
Net pension expense $ 3 438 $ 3 846 $ 3 562
Discount rate 8.50% 7.25% 8.50%
Assumed rate of return 9.00 8.50 8.50
Rate of increase in future compensation 5.00 4.50 5.50
<PAGE>
<PAGE 29>
COMMONWEALTH GAS COMPANY
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. The funded status of the Company's pension plan (using a
measurement date of December 31) is as follows:
1995 1994
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(71 818) $(58 636)
Nonvested (7 805) (6 767)
$(79 623) $(65 403)
Projected benefit obligation $(96 032) $(81 747)
Plan assets at fair market value 91 168 75 568
Projected benefit obligation
greater than plan assets (4 864) (6 179)
Unamortized transition obligation 3 717 4 336
Unrecognized prior service cost 5 327 5 830
Unrecognized gain (10 685) (9 934)
Accrued pension liability $ (6 505) $ (5 947)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1995 1994
Discount rate 7.25% 8.50%
Rate of increase in future compensation 4.25 5.00
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years.
(b) Other Postretirement Benefits
Historically, the Company 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 the
Company or a subsidiary of the System. As of January 1, 1993, the Company
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.
The Company adopted the provisions of Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS No. 106) as of January 1, 1993 and the cumulative effect
of implementation of SFAS No. 106 was approximately $34 million, which is
being amortized over 20 years. Prior to 1993, the cost of postretirement
benefits was recognized as the benefits were paid.
<PAGE>
<PAGE 30>
COMMONWEALTH GAS COMPANY
The Company makes contributions to various voluntary employees'
beneficiary association (VEBA) trusts that were established pursuant to
section 501(c)(9) of the Internal Revenue Code (the Code). The Company also
makes contributions to a subaccount of its pension plan pursuant to section
401(h) of the Code to satisfy a portion of its postretirement benefit
obligation. The Company contributed approximately $4.4 million and $4.5
million to these trusts during 1995 and 1994, respectively.
The net periodic postretirement benefit cost for the years ended
December 31, 1995 and 1994 include the following components and related
assumptions:
1995 1994
(Dollars in Thousands)
Service cost $ 452 $ 581
Interest cost 2 848 2 572
Return on plan assets (1 408) (47)
Amortization of transition obligation
over 20 years 1 700 1 700
Net amortization and deferral 811 (320)
Total postretirement benefit cost 4 403 4 486
Transfers to affiliated companies, net 524 539
Less: Amounts capitalized and deferred 2 834 2 785
Net postretirement benefit cost $ 2 093 $ 2 240
Discount rate 8.50% 7.25%
Assumed rate of return 9.00 8.50
Rate of increase in future compensation 5.00 4.50
The funded status of the Company's postretirement benefit plan using a
measurement date of December 31, 1995 and 1994 is as follows:
1995 1994
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (24 263) $ (20 304)
Fully eligible active plan participants (3 848) (4 060)
Other active plan participants (11 318) (10 082)
(39 429) (34 446)
Plan assets at fair market value 9 086 5 681
Accumulated postretirement benefit obligation
greater than plan assets (30 343) (28 765)
Unamortized transition obligation 28 904 30 604
Unrecognized (gain) loss 1 439 (1 839)
$ - $ -
<PAGE>
<PAGE 31>
COMMONWEALTH GAS COMPANY
The following actuarial assumptions were used in determining the plan's
estimated accumulated postretirement benefit obligation (APBO) and funded
status for 1995 and 1994:
1995 1994
Discount rate 7.25% 8.50%
Rate of increase in future compensation 4.25 5.00
Medicare part B premiums 12.20% 12.30%
Medical care 8.00 8.50
Dental care 5.00 5.00
The above rates, with the exception of the dental rate, which remains
constant, decrease to five percent in the year 2007 and remain at that level
thereafter. A one percent change in the medical trend rate would have a
$393,000 impact on the Company's annual expense and would change the APBO by
approximately $4.3 million.
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect post-
retirement benefit expense in future years.
The Company defers its SFAS No. 106 costs and intends to seek recovery
in its next rate proceeding. While the Company is unable to predict the
outcome of this proceeding, it believes the DPU will authorize similar
treatment as was provided to affiliate Cambridge Electric and other
Massachusetts electric and gas companies for the recovery of the cost of
these benefits. Further, based on historical DPU action, the Company
believes that it is appropriate to continue deferring the SFAS No. 106
expense as a regulatory asset. At December 31, 1995 and 1994, the Company's
deferral amounted to approximately $7.7 million and $5.4 million.
(c) Savings Plan
The Company has an Employees Savings Plan that provides for Company
contributions equal to contributions by eligible employees of up to four
percent of each employee's compensation rate. Effective January 1, 1993, the
rate was increased to five percent for those employees no longer eligible for
postretirement health benefits. The Company's contribution was $1,439,000 in
1995, $1,447,000 in 1994 and $1,444,000 in 1993.
(6) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently
estimated at $92 million for the five-year period 1996 through 2000. Of that
amount, $17.7 million is estimated for 1996. The program is subject to
periodic review and revision because of factors such as changes in business
conditions, rates of customer growth, effects of inflation, equipment
delivery schedules, licensing delays, availability and cost of capital and
environmental factors. The Company expects to finance future expenditures on
an interim basis with internally generated funds and short-term borrowings
which are ultimately expected to be repaid with the proceeds from the
issuance of long-term debt and/or equity securities.
<PAGE>
<PAGE 32>
COMMONWEALTH GAS COMPANY
(b) LNG Service Contract
The Company has contracted with Hopkinton LNG Corp., a wholly-owned
subsidiary of the System, for liquefaction and vaporization services over a
period ending in 1996, thereafter, renewable year to year with notice of
termination due five years in advance. The Company is obligated to pay
demand charges throughout the contract periods in addition to charges for
operating costs.
(c) FERC Order No. 636
As a result of implementing FERC Order No. 636 (Order 636), each
interstate pipeline company is allowed to collect certain transition costs
from its customers that resulted from the pipelines' need to buy out gas
supply contracts entered into prior to the issuance of Order 636. The
Company has been billed a total of approximately $23.8 million from Tennessee
Gas Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern
Transmission Company through December 31, 1995.
The Company's pipeline suppliers have made certain filings with the FERC
for the collection of their respective transition costs. The Company's
current best estimate of the total remaining transition costs is
approximately $11.7 million. This balance has been recorded as a liability
with a corresponding regulatory asset. The ultimate level of costs is
dependent upon future events, including the market price of natural gas and
final settlements between the FERC and the pipeline suppliers.
In May 1995, the DPU allowed the Company to accelerate recovery of its
Order 636 transition costs that were incurred to date. These costs had been
deferred as a regulatory asset and were being recovered through the CGA over
a four-year period that began in November 1993. The costs are now being
recovered through the CGA over a one-year period that began May 1, 1995. The
accelerated recovery was permitted by the DPU due to the minimal impact on
customers' bills. Any further transition costs are expected to be recovered
by the Company through the CGA as incurred.
(7) Gas Refunds
During 1995, 1994 and 1993, the Company received refunds from its gas
suppliers in settlement of several rate cases that had been pending before
the FERC. Operating revenues and the cost of gas sold have been reduced by
the amounts refunded to firm customers totaling $9,061,000 in 1995,
$6,077,000 in 1994 and $6,965,000 in 1993.
(8) Lease Obligations
The Company leases equipment and office space under arrangements that
are classified as operating leases. These lease agreements are for terms of
one year or longer. Leases currently in effect contain no provisions that
prohibit the Company from entering into future lease agreements or
obligations.
<PAGE>
<PAGE 33>
COMMONWEALTH GAS COMPANY
Future minimum lease payments, by period and in the aggregate, of non-
cancelable operating leases consisted of the following at December 31, 1995:
Operating Leases
(Dollars in Thousands)
1996 $ 3 070
1997 1 699
1998 1 084
1999 531
2000 347
Beyond 2000 1 387
Total future minimum lease payments $ 8 118
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $3,626,000 in 1995, $3,699,000 in 1994 and
$3,435,000 in 1993. There were no contingent rentals and no sublease rentals
for the years 1995, 1994 and 1993.
(9) Environmental Matters
The Company is subject to laws and regulations administered by federal,
state and local authorities relating to the quality of the environment.
These regulations authorize federal and state regulatory agencies to identify
and remediate hazardous waste sites and to seek recovery from statutorily
liable parties (usually referred to as potentially responsible parties or
PRPs), or to order these PRPs to undertake the clean-up themselves. (Refer to
"Environmental Matters" filed under Item 1 of this report for additional
information.)
<PAGE>
<PAGE 34>
COMMONWEALTH GAS COMPANY
PART IV.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Index to Financial Statements
Financial statements and notes thereto of the Company together
with the Report of Independent Public Accountants, are filed under
Item 8 of this report and listed on the Index to Financial
Statements and Schedules (page 14).
(a) 2. Index to Financial Statement Schedules
Filed herewith at page indicated is financial statement schedule
of the Company:
Schedule II - Valuation and Qualifying Accounts - Years Ended
December 31, 1995, 1994 and 1993 (page 42).
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are
incorporated by reference to the appropriate exhibit numbers and
the Securities and Exchange Commission file numbers indicated in
parentheses.
b. During 1981, New Bedford Gas and Edison Light Company sold its gas
business and properties to the Company and changed its corporate
name to Commonwealth Electric Company.
c. The following is a glossary of acronyms used throughout the
Exhibit Index:
<PAGE>
<PAGE 35>
COMMONWEALTH GAS COMPANY
AGT Algonquin Gas Transmission Company
CE Commonwealth Electric Company
CEC Canal Electric Company
CEL Cambridge Electric Light Company
CES Commonwealth Energy System
CG Commonwealth Gas Company
CNG CNG Transmission Corporation
CRC Citizens Resources Corporation
HOPCO Hopkinton LNG Corp.
NBGEL New Bedford Gas and Edison Light Company
TET Texas Eastern Transmission Corporation
TGP Tennessee Gas Pipeline Company
TGT Tennessee Gas Transmission Corporation
Exhibit Index:
Exhibit 3. Articles of incorporation and by-laws.
3.1.1 Articles of incorporation of CG (Exhibit 1 to the CG 1991 Form 10-
K, File No. 2-1647).
3.1.2 By-laws of CG, as amended (Exhibit 2 to the CG 1992 Form 10-K,
File No. 2-1647).
Exhibit 4. Instruments defining the rights of security holders, including
indentures.
4.1. Indentures of Trust or Supplemental Indenture of Trust
(as filed by the Registrant, except First Supplemental which was
filed by the System)
1. Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File
No. 2-7820).
2. First Supplemental on Form S-1 (Mar., 1950) (Exhibit 7(a), File
No. 2-8418).
3. Second Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(2),
File No. 2-10445).
4. Third Supplemental on Form S-1 (Nov., 1952) (Exhibit 4(a)(3), File
No. 2-10445).
5. Fourth Supplemental on Form S-9 (Oct. 1954) (Exhibit 2(b)(5), File
No. 2-15089).
6. Fifth Supplemental on Form S-9 (Mar., 1956) (Exhibit 2(b)(6), File
No. 2-15089).
7. Sixth Supplemental on Form S-9 (Apr., 1957) (Exhibit 2(b)(7), File
No. 2-15089).
8. Seventh Supplemental on Form S-9 (June 1959) (Exhibit 2(b)(8),
File No. 2-20532).
9. Eighth Supplemental on Form S-9 (Sept. 1961) (Exhibit 2(b)(9),
File No. 2-20532).
10. Ninth Supplemental on Form 8-K (Aug. 1962) (Exhibit A, File No. 2-
1647).
11. Tenth Supplemental on Form 10-K (1970) (Exhibit 2, File No. 2-
1647).
<PAGE>
<PAGE 36>
COMMONWEALTH GAS COMPANY
12. Eleventh Supplemental on Form S-1 (June, 1972) (Exhibit 4(b)(2),
File No. 2-48556).
13. Twelfth Supplemental on Form S-1 (Aug., 1973) (Exhibit
4(b)(3), File No. 2-48556).
14. Thirteenth Supplemental on Form 10-K (1992) (Exhibit 1, File No.
2-1647).
15. Fourteenth Supplemental on Form 10-K (1990) (Exhibit 1, File No.
2-1647).
16. Fifteenth Supplemental on Form 10-K (1982) (Exhibit 1, File No. 2-
1647).
17. Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2-
1647).
18. Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No.
2-1647).
19. Eighteenth Supplemental on Form 10-Q (March, 1994) (Exhibit 1,
File No. 2-1647)
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.3 Gas Service Contract between HOPCO and NBGEL dated September 1,
1971 for the performance of liquefaction, storage and vaporization
services and the operation and maintenance of an LNG Facility
located at Acushnet, MA (Exhibit 8 to the CG 1984 Form 10-K, File
No. 2-1647).
10.1.3.1 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).
10.1.4 Gas Service Contract between HOPCO and CG dated September 1, 1971
for the performance of liquefaction, storage and vaporization
services and the operation of LNG facilities located in Hopkinton,
MA (Exhibit 9 to the CG 1984 Form 10-K, File No. 2-1647).
10.1.4.1 Amendments to 10.1.3 and 10.1.4 as amended December 1, 1976
(Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647).
10.1.4.2 Supplement 2 to 10.1.4 dated September 30, 1982 (Exhibit 2 to the
CG 1992 Form 10-K, File No. 2-1647).
10.1.5 Supplement 1 to Gas Service Contract between HOPCO and CG dated
September 14, 1977 (Exhibit 5(c)6 to the CES Form S-16 (June
1979), File No. 2-64731).
10.1.6 Firm Storage Service Transportation Contract by and between TGT
and CG providing for firm transportation of natural gas from
Consolidated Gas Transmission Corporation dated December 15, 1985
(Exhibit 1 to the CG 1985 Form 10-K, File No. 2-1647).
10.1.7 Agency Agreement for Certain Transportation Arrangements by and
between CG and 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).
<PAGE>
<PAGE 37>
COMMONWEALTH GAS COMPANY
10.1.8 Natural Gas Sales Agreement between CG and CRC dated April 14,
1986 (Exhibit 2 to the CG Form 10-Q (June 1986), File No. 2-1647).
10.1.9 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).
10.1.10 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).
10.1.11 Service Agreement dated December 14, 1985 and an amendment thereto
dated May 15, 1986 by and between TET and CG to receive, transport
and deliver to points of delivery natural gas for the account of
the CG dated December 14, 1985 (Exhibit 5 to the CG Form 10-Q
(June 1986), File No. 2-1647).
10.1.12 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).
10.1.13 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).
10.1.14 Service Agreement Applicable to Rate Schedule F-2 between AGT and
CG dated April 11, 1985 for the purchase of certain quantities of
natural gas acquired by AGT from Consolidated Gas Supply
Corporation (Exhibit 2 to the CG Form 10-Q (March 1987), File No.
2-1647).
10.1.15 Service Agreement Applicable to Rate Schedule F-3 between AGT and
CG dated April 11, 1985 for the purchase of certain quantities of
natural gas acquired by AGT from National Fuel Gas Supply
Corporation (Exhibit 3 to the CG Form 10-Q (March 1987), File No.
2-1647).
10.1.16 Service Agreement Applicable to Rate Schedule F-4 between AGT and
CG dated December 26, 1985 for the purchase of certain quantities
of natural gas acquired by AGT from TET (Exhibit 4 to the CG Form
10-Q (March 1987), File No. 2-1647).
10.1.17 Service Agreement Applicable to Rate Schedule TS-3 between TET and
CG dated April 16, 1987 for Firm natural gas service (Exhibit 1 to
the CG Form 10-Q (June 1987), File No. 2-1647).
10.1.18 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).
<PAGE>
<PAGE 38>
COMMONWEALTH GAS COMPANY
10.1.19 Natural Gas Sales Agreement between Natural Gas Supply Company and
CG dated May 12, 1987 (Exhibit 3 to the CG Form 10-Q (June 1987),
File No. 2-1647).
10.1.20 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).
10.1.21 1986 Consolidating Supplement to CG Service Contract and NBGEL by
and between CG and HOPCO dated December 31, 1986 amending and
consolidating the CG Service Contract and the New Bedford Gas
Service Contract both as amended December 1, 1976 and supplemented
September 14, 1977 (Exhibit 2 to the CG Form 10-Q (March 1988),
File No. 2 -1647).
10.1.22 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).
10.1.23 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).
10.1.24 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).
10.1.25 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).
10.1.26 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).
10.1.27 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).
10.1.28 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).
10.1.29 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).
10.1.30 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).
<PAGE>
<PAGE 39>
COMMONWEALTH GAS COMPANY
10.1.31 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).
10.1.32 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).
10.1.33 Gas Storage Agreement between Steuben Gas Storage Company 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).
10.1.34 Gas Sales Agreement between V.H.C. Gas Systems, L.P. (seller) and
CG (purchaser) for the purchase of spot market gas, dated June 2,
1989, with a contract term of at least one year (Exhibit 3 to the
CG Form 10-Q (June 1989), File No. 2-1647).
10.1.35 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).
10.1.36 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).
10.1.36.1 Amendment to 10.1.36 dated August 28, 1989 (Exhibit 5 to the CG
Form 10-Q (September 1989), File No. 2-1647).
10.1.37 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).
10.1.38 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).
10.1.39 Gas Sales Agreement between PSI, Inc. (seller) and CG (purchaser)
for the purchase of spot market gas, dated September 25, 1989,
with a contract term of at least one year (Exhibit 1 to the CG
1989 Form 10-K, File No. 2-1647).
<PAGE>
<PAGE 40>
COMMONWEALTH GAS COMPANY
10.1.40 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).
10.1.41 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).
10.1.42 AGT, CG, and Distrigas of Massachusetts Corporation have entered
into an agreement 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).
10.1.43 Gas Sales Agreement between TEX/CON Marketing Gas Company (seller)
and CG (purchaser) for the purchase of firm gas, dated September
12, 1990, with a contract term of five years (Exhibit 3 to the CG
1990 Form 10-K, File No. 2-1647).
10.1.44 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).
10.1.45 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).
10.1.46 Gas Sales Agreement between AGT 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).
10.1.47 Transportation Agreement between AGT and CG for Rate Schedule AFT-
1, Agreement No. 90103, dated November 1, 1990 (Exhibit 6 to the
CG 1991 Form 10-K, File No. 2-1647).
10.1.48 Transportation Assignment Agreement between AGT 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).
10.1.49 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).
10.1.50 Transportation Agreement between TGP and CG dated September 1,
1991 (Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647).
<PAGE>
<PAGE 41>
COMMONWEALTH GAS COMPANY
10.1.51 Transportation Agreement between CNG and CG to provide for
transportation of natural gas on a daily basis from Steuben Gas
Storage Company to TGP, dated September 24, 1991 (Exhibit 10 to
the CG 1991 Form 10-K, File No. 2-1647).
10.1.52 Service Line Agreement by and between 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).
10.2 Other Agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993
(Filed as Exhibit 1 to the System's Form 10-Q (September 1993),
File No. 1-7316).
10.2.2 Employees Savings Plan for Employees of Commonwealth Energy System
and Subsidiary Companies as amended and restated January 1, 1993
(Filed as Exhibit 2 to the System's Form 10-Q (September 1993),
File No. 1-7316).
Filed herewith:
Exhibit 27.
Financial Data Schedule for the year ended December 31, 1995
(Filed herewith as Exhibit 1)
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended
December 31, 1995.
<PAGE>
<PAGE 42>
SCHEDULE II
COMMONWEALTH GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993
(Dollars in Thousands)
Additions
Balance Provision Deductions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off of Year
Allowance for
Doubtful Accounts Year Ended December 31, 1995
$ 2 827 $ 4 855 $ 1 375 $ 6 366 $ 2 691
Year Ended December 31, 1994
$ 3 162 $ 5 496 $ 1 405 $ 7 236 $ 2 827
Year Ended December 31, 1993
$ 2 890 $ 5 585 $ 1 079 $ 6 392 $ 3 162
<PAGE>
<PAGE 43>
COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1995
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 GAS COMPANY
(Registrant)
By: WILLIAM G. POIST
William G. Poist,
Chairman of the Board 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 dates indicated.
Principal Executive Officers:
WILLIAM G. POIST March 28, 1996
William G. Poist,
Chairman of the Board and
Chief Executive Officer
KENNETH M. MARGOSSIAN March 29, 1996
Kenneth M. Margossian,
President and Chief Operating Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 28, 1996
James D. Rappoli,
Financial Vice President and Treasurer
A majority of the Board of Directors:
WILLIAM G. POIST March 28, 1996
William G. Poist, Director
JAMES D. RAPPOLI March 28, 1996
James D. Rappoli, Director
KENNETH M. MARGOSSIAN March 29, 1996
Kenneth M. Margossian, Director
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
balance sheet, statement of income, statement of retained earnings and
statement of cash flows contained in Form 10-K of Commonwealth Gas Company for
fiscal year ended December 31, 1995 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<CIK> 0000022620
<NAME> COMMONWEALTH GAS COMPANY
<MULTIPLIER> 1,000
<S> <C>
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 256,141
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 88,709
<TOTAL-DEFERRED-CHARGES> 29,765
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 374,615
<COMMON> 71,425
<CAPITAL-SURPLUS-PAID-IN> 27,739
<RETAINED-EARNINGS> 10,495
<TOTAL-COMMON-STOCKHOLDERS-EQ> 109,659
0
0
<LONG-TERM-DEBT-NET> 78,100
<SHORT-TERM-NOTES> 14,050
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 13,650
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 159,156
<TOT-CAPITALIZATION-AND-LIAB> 374,615
<GROSS-OPERATING-REVENUE> 308,922
<INCOME-TAX-EXPENSE> 9,669
<OTHER-OPERATING-EXPENSES> 272,311
<TOTAL-OPERATING-EXPENSES> 281,980
<OPERATING-INCOME-LOSS> 26,942
<OTHER-INCOME-NET> 1,233
<INCOME-BEFORE-INTEREST-EXPEN> 28,175
<TOTAL-INTEREST-EXPENSE> 11,946
<NET-INCOME> 16,229
0
<EARNINGS-AVAILABLE-FOR-COMM> 16,229
<COMMON-STOCK-DIVIDENDS> 12,571
<TOTAL-INTEREST-ON-BONDS> 8,174
<CASH-FLOW-OPERATIONS> 51,899
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
