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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _______________ to _______________
Commission file number 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, 1995
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 33 of this report.
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COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1994
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business........................................ 3
General....................................... 3
Gas Supply
General..................................... 3
Hopkinton LNG Facility...................... 4
Rates and Regulation.......................... 5
Environmental Matters......................... 7
Construction and Financing.................... 8
Employees..................................... 8
Item 2. Properties...................................... 8
Item 3. Legal Proceedings............................... 8
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 9
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 10
Item 8. Financial Statements and Supplementary Data..... 13
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............. 13
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 33
Signatures.................................................. 42
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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 232,000 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.
Operating revenues are derived primarily from residential, commercial
and industrial 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 large industrial customers who
have dual fuel capability can convert from gas to alternative fuels under
terms of contracts which permit interruption of their service upon short
notice. The Company reserves the right to reduce or interrupt the supply of
gas to this class of customer at any time.
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 requires interstate pipelines to unbundle existing gas sales contracts
into separate components (gas sales, transportation and storage services) and
to provide transportation services that allow customers to receive the same
level and quality of service they had with the previous bundled contracts.
Prior to the implementation of Order 636 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.
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 1994, over 98% of the gas utilized by the Company was
delivered by the interstate pipeline system. The remaining small quantity
(approximately 662,000 MMBTU) was delivered as liquid 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 Company
is currently awaiting an order from the DPU.
The Company began transporting gas on its distribution system in 1990
for end-users. There are currently eleven customers using this transportation
service, accounting for 3,003 BBTU of throughput in 1994 which represented
approximately 5.9% 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
storage. As the need arises, LNG is vaporized and placed in the distribution
system of the Company.
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COMMONWEALTH GAS 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
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 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 remain pending before the
DPU.
(b) Gas Demand, Take-or-Pay Costs 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.
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 the Company. 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 the Company's allocation.
There are still some small on-going amounts of take-or-pay costs being
collected by the pipeline, however, Tennessee has nearly reached the cap of
allowable collections under the settlement.
Algonquin made a series of filings with the FERC to recover from its
customers take-or-pay charges imposed on it by its upstream suppliers.
Algonquin billed the Company 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. The Company's allocation was in excess of $5 million. The Company
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COMMONWEALTH GAS COMPANY
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 the Company's allocated share to $2.5 million. In addition,
a settlement was reached with Koch Gateway Pipeline (formerly the United Gas
Pipeline) whereby the Company, in October 1994, received approximately $2
million in refunds for take-or-pay costs allocated through Texas Eastern and
Algonquin since 1985. This amount is currently being refunded to firm
customers through the CGA.
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 5(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.
(c) Regulatory Matters
On April 16, 1991, the Company requested a $27.7 million (11.3%) revenue
increase in a filing with the DPU using a test-year ended December 31, 1990.
On September 16, 1991, the DPU approved a settlement of the revenue
requirements portion of the filing authorizing a $22.8 million increase in
annual revenues, approximately 82% of the original request. The agreement
included a return on equity, for accounting purposes, of 13%. The DPU later
ruled on the rate design portion of the request and new rates went into effect
on November 1, 1991.
In May 1994, the Company requested the DPU to change the backup 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 causes 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 larger customers, which provides a
level of service between full firm and interruptible. In exchange for prices
lower than full firm service, quasi-firm customers will receive interruptible
service in peak demand months and firm service in off-peak months. These
arrangements will give the Company and its customers more flexibility in
supply management and pricing options.
Also, during 1994, the Company was able to maximize the use of its gas
supply resources through off-system sales. Twenty percent of the gas
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COMMONWEALTH GAS COMPANY
purchased was sold outside the Company's franchise area. These efforts helped
to reduce the cost of gas to the Company's firm customers helping to make the
Company more competitive in its traditional markets.
The margin realized on these sales is shared with one-half used to
reduce the cost of gas to firm customers and the other deferred pending DPU
approval of the Company's margin sharing proposal that is expected to be filed
in 1995.
(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. On November 23, 1994, the DPU approved a
settlement agreement extending the Company's demand-side management (DSM)
programs until October 31, 1995 and allowing the recovery of "lost margins"
from its customers commencing in January 1995. Specifically, the settlement
allows the Company to recover through the CC decimal the portion of the lost
margins related to savings resulting from installations during the twelve-
month period which began in November 1994. In addition, the lost margins
related to savings occurring from prior period installations will be held in
an interest-bearing account pending the completion of a DSM impact evaluation
proceeding currently before the DPU.
(f) Potential Impact of Regulatory Restructuring
Based on the current regulatory framework in which it operates, 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." Under SFAS No.
71, a utility is allowed to defer costs that would otherwise be expensed in
recognition of the ability to recover them in future rates. As a result, the
Company has accumulated $26.9 million of regulatory assets (approximately 7.1%
of total assets) as of December 31, 1994. Management believes that the
current regulatory framework provides for the continued recovery of these
assets.
In the event that recovery of specific costs through rates becomes
uncertain or unlikely in the future, either as a result of the expanding
effects of competition or specific regulatory actions, the Company could be
required to move away from cost-of-service ratemaking and, therefore, SFAS No.
71 would no longer apply. Discontinuation of SFAS No. 71 could lead to the
write-off of various regulatory assets, which would have an adverse impact on
the Company's financial position and results of operations. At this time,
management believes that it is unlikely that regulatory action would lead to
the discontinuation of SFAS No. 71 in the near future.
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.
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COMMONWEALTH GAS COMPANY
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 $2.3 million liability that reflects its best
estimate (based on current information) of the costs to be incurred in
connection with the assessment and remediation activities identified to this
point. 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.
The Company has 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 predict at this time the ultimate
cost to resolve these matters due to the uncertainties inherent in the site
investigation and remediation process.
Construction and Financing
Information concerning the Company's financing and construction programs
is contained in Note 5(a) of the Notes to Financial Statements filed under
Item 8 of this report.
Employees
The Company has 723 regular employees which represents a 5.5% decrease
from last year's level. Approximately 67% of these employees are represented
by three collective bargaining units with agreements in effect until September
15, 1995, March 31, 1996 and June 30, 1996. 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 1994, the gas system included 2,761 miles of gas distribution
lines, 162,971 services and 239,302 customer meters together with the
necessary measuring and regulating equipment.
In addition, the 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, 1994
One
(c) Frequency and Amount of Dividends Declared in 1994 and 1993
1994 1993
Per Share Per Share
Declaration Date Amount Declaration Date Amount
January 24, 1994 $2.10 January 28, 1993 $2.17
April 21, 1994 2.50 April 15, 1993 3.75
July 15, 1994 .50 July 15, 1993 .50
$5.10 $6.42
(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, 1994 and 1993 and unit sales for these periods is shown below:
Years Ended Years Ended
December 31, December 31,
1994 and 1993 1993 and 1992
Increase (Decrease)
(Dollars in Thousands)
Gas Operating Revenues $21 597 7.1 % $ 6 896 2.3 %
Operating Expenses -
Cost of gas sold 21 162 12.6 2 736 1.7
Other operation
and maintenance 2 745 3.3 977 1.2
Depreciation 620 6.9 669 8.1
Taxes -
Federal and state income (1 860) (18.9) 1 265 14.7
Local property and other 407 5.3 404 5.6
23 074 8.3 6 051 2.2
Operating Income (1 477) (5.9) 845 3.5
Other Income (216) (33.9) 340 114.5
Income Before Interest Charges (1 693) (6.6) 1 185 4.8
Interest Charges 1 038 10.9 (259) (2.7)
Net Income $(2 731) (16.8) $ 1 444 9.7
Unit Sales (BBTU)
Firm (680) (1.7) % (591) (1.5)%
Interruptible 302 12.3 (844) (25.6)
Off-system 6 401 - - -
Quasi-firm 487 - - -
6 510 15.6 (1 435) (3.3)
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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,
1994 1993 1992
Unit Sales (BBTU):
Residential 21 515 22 252 22 392
Commercial 10 728 10 931 10 913
Industrial 4 401 4 205 4 717
Other 1 895 1 831 1 788
Total firm 38 539 39 219 39 810
Off-System 6 401 - -
Quasi-Firm 487 - -
Interruptible 2 761 2 459 3 303
Total sales 48 188 41 678 43 113
Transportation 3 003 3 171 1 898
Total 51 191 44 849 45 011
Customers at End of Period:
Residential 211 075 211 877 207 163
Commercial 18 466 18 323 17 932
Industrial 928 920 921
Other 1 140 1 093 1 009
Total 231 609 232 213 227 025
Operating Revenues, Cost of Gas Sold and Unit Sales
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 ($997,000). Also contributing to the increase
were higher conservation and load management (C&LM) costs ($2.6 million). The
Company is recovering in revenues current costs associated with C&LM programs
on a dollar-for-dollar basis through the CC decimal. To the extent that these
expenses increase or decrease from period to period based on customer
participation, a corresponding change will occur in revenue. Partially
offsetting these increases was a decrease in firm unit sales of 1.7%. The
decrease was most significant during the fourth quarter when seasonal rates
were in place and firm sales were 15% lower than the same period in 1993.
Seasonal rates recognize the increased cost of providing gas service during
the winter months. Operating revenues increased nearly $7 million or 2.3% in
1993 due primarily to an increase in C&LM costs ($4.8 million) and a 1.7%
increase in the cost of gas sold ($2.7 million). Somewhat offsetting these
increases were lower unit sales of approximately 3.3%.
The cost of gas sold per MMBTU averaged $3.92 in 1994, $4.02 in 1993
and $3.82 in 1992. The cost of gas in 1994 reflects lower prices offset, in
part, by the amortization of Order 636 transition costs ($3.6 million and
$396,000 in 1994 and 1993, respectively) and higher LNG costs. The increase
in 1993 was due, in part, to the costs incurred as a result of the
implementation of Order 636. Refunds from pipeline suppliers, which are
passed along to the Company's firm customers through the CGA, amounted to
approximately $6.1 million ($.16 per MMBTU) in 1994 and $7 million ($.18 per
MMBTU) in 1993 and 1992.
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COMMONWEALTH GAS COMPANY
Due to the unseasonably warm temperatures experienced throughout the
region in the fourth quarter, firm unit sales decreased by 1.7% in 1994. This
more than offset a 5.4% increase in the first quarter resulting from the
colder than normal weather. The Company established all-time highs for daily
send-out on four different occasions in January 1994, setting a new peak day
send-out of 364,799 MMBTU on January 19. Prior to this period, the previous
all-time peak was 336,998 MMBTU set in January 1988. Firm unit sales declined
nearly 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%. It is anticipated that firm unit sales
will grow at an average of 1% - 2% over the next five years. Interruptible
sales increased by approximately 12% in 1994 and decreased by approximately
26% during 1993 reflecting the competitive market conditions for energy
resources that exist today. 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. Quasi-firm and off-system sales are expected to increase
significantly over the next few years as they become an increasingly important
part 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 was unchanged in 1994 and increased approximately
2.3% in 1993 mainly due to new home construction and conversion activity.
Other Operating Expenses
Other operation and maintenance expenses increased by approximately
3.3%, or $2.7 million, 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 Company-wide cost containment efforts and a decline in the
cost of services rendered by affiliate COM/Energy Services Company
attributable to a second quarter 1993 work force reduction. Also, payroll
costs decreased by more than 2% ($683,000) reflecting a lower work force level
through attrition and reduced overtime. Other operation and maintenance
expenses increased approximately $977,000 or 1.2% in 1993 due primarily to the
implementation of C&LM programs ($4.8 million) during 1993, increased pension
costs ($500,000) and higher payroll costs ($821,000). Offsetting these
increases in 1993 were declines in employee medical and life insurance costs
($954,000), lower liability insurance costs ($1.4 million) and the absence of
amortization costs (totaling $1.9 million) associated with the Company's
automated mapping system (CAMRIS).
Depreciation and Taxes
The increase in depreciation expense in both 1994 and 1993 resulted
from higher levels of depreciable plant-in-service. The decrease in federal
and state income taxes in 1994 was due to the lower level of pretax income.
The increase during 1993 reflects a greater level of pretax income and, to a
lesser extent, the change in the federal tax rate to 35%, effective January 1,
1993.
The increase in local property taxes during both 1994 and 1993 was due
to higher tax rates and assessments in the Company's service territory.
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COMMONWEALTH GAS COMPANY
Other Income and Interest Charges
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). Other income increased during 1993 due
primarily to higher income from non-utility rental properties, the Company's
share of the net proceeds from the aforementioned litigation recorded in the
second quarter and interest on the Company's C&LM program development costs.
The impact of these items was offset somewhat by a decline in sales of design
heating systems.
Total interest charges increased by more than $1 million due mainly 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. Total interest charges decreased 2.7% in 1993, despite a higher
average level of short-term borrowings, due to lower interest rates and the
early retirement of the Company's Series F (9%, $8,060,000) and Series G
(8 5/8%, $1,050,000) First Mortgage Bonds during the second quarter of 1992.
Interest rates on bank borrowings averaged 4.4% in 1994 compared to 3.3% in
1993.
Financing Activity
On December 30, 1993, the Company issued $35 million of 7.11% First
Mortgage Bonds, Series K, Due 2033. In addition, on December 29, 1993 the
Company issued 450,000 shares of Common Stock ($25 par value) for $18,000,000
(purchased entirely by the System). The proceeds from these issues were used
to repay outstanding short-term borrowings incurred to temporarily finance
additions to property, plant and equipment.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed
herewith on pages 14 through 32 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, 1994
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To 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, 1994 and 1993, and the related
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, effective January
1, 1993, the Company changed its method of accounting for costs associated
with postretirement benefits other than pensions.
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 schedules 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
Arthur Andersen LLP
Boston, Massachusetts
February 21, 1995
<PAGE>
<PAGE 15>
COMMONWEALTH GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1994 and 1993
Statements of Income for the Years Ended December 31, 1994, 1993 and
1992
Statements of Retained Earnings for the Years Ended December 31, 1994,
1993 and 1992
Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and
1992
Notes to Financial Statements
PART IV.
SCHEDULE
II Valuation and Qualifying Accounts for the Years Ended December 31,
1994, 1993 and 1992
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 16>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1994 AND 1993
ASSETS
1994 1993
(Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $339 476 $323 607
Less - Accumulated depreciation 85 162 77 155
254 314 246 452
Add - Construction work in progress 719 400
255 033 246 852
CURRENT ASSETS
Cash 4 862 1 297
Accounts receivable -
Affiliated companies 462 173
Customers, less reserves of $2,827,000 in 1994
and $3,162,000 in 1993 32 890 33 066
Unbilled revenues 20 892 29 068
Inventories, at average cost -
Natural gas 24 161 25 810
Materials and supplies 1 593 1 979
Prepaid taxes -
Property 2 861 2 629
Income 619 1 812
Other 1 076 992
89 416 96 826
DEFERRED CHARGES
Order 636 transition costs 19 201 21 938
Other 17 155 11 067
36 356 33 005
$380 805 $376 683
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 17>
COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1994 AND 1993
CAPITALIZATION AND LIABILITIES
1994 1993
(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 6 837 7 840
106 001 107 004
Long-term debt, less current sinking
fund requirements 91 750 95 400
197 751 202 404
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 24 950 40 975
Advances from affiliates 11 220 2 835
36 170 43 810
Other Current Liabilities -
Current sinking fund requirements 3 650 3 650
Accounts payable -
Affiliated companies 2 669 1 811
Other 33 214 32 944
Refundable gas costs 27 832 13 253
Customer deposits 1 433 1 440
Accrued local property and other taxes 3 317 2 940
Accrued interest 749 774
Other 4 746 4 447
77 610 61 259
113 780 105 069
DEFERRED CREDITS
Accumulated deferred income taxes 32 699 30 176
Unamortized investment tax credits 6 065 6 270
Order 636 transition costs 7 811 13 133
Other 22 699 19 631
69 274 69 210
COMMITMENTS AND CONTINGENCIES
$380 805 $376 683
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 18>
COMMONWEALTH GAS COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992
(Dollars in Thousands)
GAS OPERATING REVENUES $325 726 $304 129 $297 233
OPERATING EXPENSES
Cost of gas sold 188 769 167 607 164 871
Other operation 74 636 71 776 69 126
Maintenance 11 809 11 929 11 611
Depreciation 9 559 8 939 8 270
Amortization 1 238 1 233 3 224
Taxes -
Income 7 983 9 843 8 578
Local property 5 336 4 865 4 608
Payroll and other 2 715 2 779 2 632
302 045 278 971 272 920
OPERATING INCOME 23 681 25 158 24 313
OTHER INCOME 421 637 297
INCOME BEFORE INTEREST CHARGES 24 102 25 795 24 610
INTEREST CHARGES
Long-term debt 8 488 6 345 7 004
Other interest charges 2 073 3 170 2 769
Allowance for borrowed funds used
during construction (27) (19) (18)
10 534 9 496 9 755
NET INCOME $ 13 568 $ 16 299 $ 14 855
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 19>
COMMONWEALTH GAS COMPANY
STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992
(Dollars in Thousands)
Balance at beginning of year $ 7 840 $ 6 994 $ 1 767
Add (Deduct):
Net income 13 568 16 299 14 855
Cash dividends on common stock (14 571) (15 453) (9 628)
Balance at end of year $ 6 837 $ 7 840 $ 6 994
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 20>
COMMONWEALTH GAS COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
1994 1993 1992
(Dollars in Thousands)
OPERATING ACTIVITIES
Net income $13 568 $16 299 $14 855
Effects of noncash items -
Depreciation and amortization 15 159 11 363 12 100
Deferred income taxes 3 883 8 018 1 478
Investment tax credits (205) (210) (217)
Change in working capital exclusive
of cash and interim financing -
Accounts receivable and unbilled
revenues 8 063 (4 714) (4 544)
Prepaid income taxes 1 193 4 878 729
Local property and other taxes, net 145 57 136
Accounts payable and other 17 925 (6 873) 3 032
Deferred postretirement benefit costs (2 306) (3 062) -
Deferred Order 636 transition costs, net (2 585) (8 805) -
All other operating items (7 393) (9 065) (3 003)
Net cash provided by operating activities 47 447 7 886 24 566
INVESTING ACTIVITIES
Additions to property, plant and
equipment (exclusive of AFUDC) (17 994) (23 272) (20 437)
Allowance for borrowed funds used
during construction (27) (19) (18)
Net cash used for investing activities (18 021) (23 291) (20 455)
FINANCING ACTIVITIES
Sale of common stock to Parent - 18 000 -
Payment of dividends (14 571) (15 453) (9 628)
Proceeds from (payment of) short-term
borrowings (16 025) (11 500) 14 875
Proceeds from (payment of) affiliate
borrowings 8 385 (5 705) 3 275
Retirement of long-term debt
through sinking funds (3 650) (3 650) (3 657)
Long-term debt issues refunded - - (9 110)
Long-term debt issues - 35 000 -
Net cash provided by (used for)
financing activities (25 861) 16 692 (4 245)
Net increase (decrease) in cash 3 565 1 287 (134)
Cash at beginning of period 1 297 10 144
Cash at end of period $ 4 862 $ 1 297 $ 10
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 9 799 $ 8 797 $ 9 377
Income taxes $ 4 636 $ 3 133 $ 6 167
The accompanying notes are an integral part of these financial statements.
<PAGE>
<PAGE 21>
COMMONWEALTH GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Significant Accounting Policies
(a) General and Regulatory
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 Company is regulated as to rates, accounting and other matters
by the Massachusetts Department of Public Utilities (DPU). The System is an
exempt 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 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. The principal regulatory
assets included in deferred charges at December 31, 1994 and 1993 were as
follows:
1994 1993
(Dollars in Thousands)
FERC Order 636 transition costs $19,201 $21,938
Postretirement benefit costs including
pensions 5,367 3,062
Environmental costs 2,346 1,768
Total regulatory assets $26,914 $26,768
Regulatory assets as a percent of total assets 7.1% 7.1%
The principal regulatory liability, reflected in deferred credits-other
and relating to income taxes, was $9.9 million and $10 million at December
31, 1994 and 1993, respectively.
(b) Reclassifications
Certain prior year amounts are reclassified from time to time to conform
with the presentation used in the current year's financial statements.
<PAGE>
<PAGE 22>
COMMONWEALTH GAS COMPANY
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliated companies as
follows:
(Dollars in Thousands)
1994 Cost Margin Total
Cambridge Electric $1 493 $ 220 $1 713
1993
Cambridge Electric $1 311 $ 76 $1 387
1992
Cambridge Electric $1 784 $ 334 $2 118
Commonwealth Electric 100 5 105
$1 884 $ 339 $2 223
The margin realized on these sales is credited to firm customers through
the 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 $10,126,000, $9,587,000 and $8,683,000 in 1994, 1993 and 1992,
respectively. Transactions with other 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, 1994 and 1993, the Company had overcollected $27,832,000 and
$13,253,000, respectively, which is reflected as a liability in the
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 2.98% in 1994, 2.95% in 1993 and 2.90% in 1992.
<PAGE>
<PAGE 23>
COMMONWEALTH GAS COMPANY
(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 4.75% in 1994,
3.5% in 1993 and 4.25% in 1992.
(2) 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.
The following is a summary of the provisions for income taxes for the
years ended December 31, 1994, 1993 and 1992:
1994 1993 1992
(Dollars in Thousands)
Federal -
Current $3 585 $1 619 $6 093
Deferred 3 405 6 956 1 422
Investment tax credits (205) (210) (217)
6 785 8 365 7 298
State -
Current 720 416 1 224
Deferred 667 1 278 343
1 387 1 694 1 567
8 172 10 059 8 865
Amortization of regulatory liability
relating to deferred income taxes (189) (216) (287)
Total federal and state
income taxes $ 7 983 $ 9 843 $ 8 578
<PAGE>
<PAGE 24>
COMMONWEALTH GAS COMPANY
Effective January 1, 1992, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of deferred tax
liabilities and assets for the expected future tax consequences of events
that have been included in the financial statements or tax returns. Under
this method, deferred tax liabilities and assets are determined based on the
difference between the financial statement 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 1994 and
1993:
1994 1993
(Dollars in Thousands)
Liabilities
Property-related $39 768 $37 230
Order 636 transition costs, net 4 094 3 450
Postretirement benefits plan 2 101 1 422
All other 3 075 1 419
49 038 43 521
Assets
Investment tax credit 3 914 4 047
Pension plan 2 739 2 284
Regulatory liability 3 155 3 006
Inventory repricing 4 285 2 946
All other 2 828 2 785
16 921 15 068
Accumulated deferred income taxes, net $32 117 $28 453
The net year-end deferred income tax liability above is net of current
deferred tax assets of $582,000 in 1994 and $1,723,000 in 1993 which are
included in prepaid income taxes in the accompanying balance sheets.
The total income tax provision set forth on the previous page
represents 37% in 1994, 38% in 1993 and 37% in 1992 of income before such
taxes. The following table reconciles the statutory federal income tax rate
to these percentages:
1994 1993 1992
Federal statutory rate 35% 35% 34%
Federal income tax expense at statutory levels $7 543 $9 150 $7 967
Increase (Decrease) from statutory rate:
State tax net of federal tax benefit 902 1 101 1 064
Amortization of investment tax credits (205) (209) (217)
Amortization of excess deferred reserves (189) (216) (140)
Other (68) 17 (96)
$8 572 $9 843 $11 989
Effective federal tax rate 37% 38% 37%
As a result of the Revenue Reconciliation Act of 1993, the Company's
federal income tax rate was increased to 35% effective January 1, 1993.
<PAGE>
<PAGE 25>
COMMONWEALTH GAS COMPANY
(3) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current sinking fund
requirements, collateralized by substantially all of the Company's property,
is as follows:
Original Balance December 31,
Issue 1994 1993
(Dollars in Thousands)
First Mortgage Bonds -
8.99%, Series H, due 1996 $10 000 $10 000 $10 000
8.99%, Series I, due 2001 40 000 21 750 25 400
9.95%, Series J, due 2020 25 000 25 000 25 000
7.11%, Series K, due 2033 35 000 35 000 35 000
$91 750 $95 400
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, 1994 are as follows:
Sinking Fund Maturing Debt
Year Requirements Issues Total
(Dollars in Thousands)
1995 $3 650 $ - $ 3 650
1996 3 650 10 000 13 650
1997 3 650 - 3 650
1998 3 650 - 3 650
1999 3 650 - 3 650
(b) Notes Payable to Banks
The Company and other system companies maintain both committed and
uncommitted lines of credit for the financing of their construction programs,
on a short-term basis, and for other corporate purposes. As of December 31,
1994, system companies had $90 million of committed lines that will expire at
varying intervals in 1995. These lines are normally renewed upon expiration
and require annual fees ranging from zero to .1875% of the individual line.
At December 31, 1994, the uncommitted lines of credit totaled $90 million.
Interest rates on the outstanding borrowings generally are at an adjusted
money market rate and averaged 4.4% and 3.3% in 1994 and 1993, respectively.
The Company's notes payable to banks totaled $24,950,000 and $40,975,000 at
December 31, 1994 and 1993, respectively.
(c) Advances from Affiliates
The Company had short-term notes payable to the System totaling
$2,935,000 and $355,000 at December 31, 1994 and 1993, respectively. These
notes are written for a term of up to 11 months and 29 days. Interest is at
<PAGE>
<PAGE 26>
COMMONWEALTH GAS COMPANY
the prime rate and is adjusted for changes in that rate during the term of
the notes. This rate averaged 7.3% and 6% in 1994 and 1993, 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 4.3% and 3.2% in 1994 and 1993,
respectively. The Company had borrowings from the Pool of $8,285,000 and
$2,480,000 at December 31, 1994 and 1993, respectively.
(d) Disclosures 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 balance sheets as
of December 31, 1994 and 1993 are as follows:
1994 1993
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-Term Debt $95 400 $93 134 $99 050 $111 718
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.
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.
(4) 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.
<PAGE>
<PAGE 27>
COMMONWEALTH GAS COMPANY
Components of pension expense and related assumptions to develop pension
expense were as follows:
1994 1993 1992
(Dollars in Thousands)
Service cost $ 2 278 $ 1 904 $ 1 720
Interest cost 6 378 6 037 5 478
Return on plan assets - (gain)/loss 1 345 (10 821) (7 278)
Net amortization and deferral (6 297) 6 317 3 001
Total pension expense 3 704 3 437 2 921
Transfers from affiliated
companies, net 478 453 466
Less: Amounts capitalized
and deferred 336 328 370
Net pension expense $ 3 846 $ 3 562 $ 3 017
1994 1993 1992
Discount rate 7.25% 8.50% 8.50%
Assumed rate of return 8.50 8.50 8.50
Rate of increase in future compensation 4.50 5.50 5.50
Pension expense reflects the use of the projected unit credit method
which is also the actuarial cost method used in determining future funding of
the plan. The funded status of the Company's pension plan (using a
measurement date of December 31) is as follows:
1994 1993
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(58 636) $(61 668)
Nonvested (6 767) (8 297)
$(65 403) $(69 965)
Projected benefit obligation $(81 747) $(85 269)
Plan assets at fair market value 75 568 79 553
Projected benefit obligation less
(greater) than plan assets (6 179) (5 716)
Unamortized transition obligation 4 336 4 955
Unrecognized prior service cost 5 830 5 115
Unrecognized gain (9 934) (9 141)
Accrued pension liability $ (5 947) $ (4 787)
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1994 1993
Discount rate 8.50% 7.25%
Rate of increase in future compensation 5.00 4.50
Plan assets consist primarily of fixed-income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years.
<PAGE>
<PAGE 28>
COMMONWEALTH GAS COMPANY
(b) Other Postretirement Benefits
Through December 31, 1992, 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 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.
Effective January 1, 1993, the Company 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 $34 million, which is being
amortized over 20 years. Prior to 1993, the cost of postretirement benefits
was recognized as the benefits were paid. The cost of retiree medical care
and life insurance benefits totaled $1,910,000 during 1992.
In 1993, the Company began making contributions to various voluntary
employees' beneficiary association (VEBA) trusts that were established
pursuant to section 501(c)9 of the Internal Revenue Code (the Code). The
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 $4.5 million and
$3.8 million to these trusts during 1994 and 1993, respectively.
The net periodic postretirement benefit cost for the years ended
December 31, 1994 and 1993 include the following components and related
assumptions:
1994 1993
(Dollars in Thousands)
Service cost $ 581 $ 535
Interest cost 2 572 2 858
Return on plan assets (47) (203)
Amortization of transition obligation
over 20 years 1 700 1 700
Net amortization and deferral (320) 22
Total postretirement benefit cost 4 486 4 912
Transfers to affiliated companies, net 539 540
Less: Amounts capitalized and deferred 2 785 3 564
Net postretirement benefit cost $ 2 240 $ 1 888
<PAGE>
<PAGE 29>
COMMONWEALTH GAS COMPANY
1994 1993
Discount rate 7.25% 8.50%
Assumed rate of return 8.50 8.50
Rate of increase in future compensation 4.50 4.50
The funded status of the Company's postretirement benefit plan using a
measurement date of December 31, 1994 and 1993 is as follows:
1994 1993
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $ (20 304) $ (20 779)
Fully eligible active plan participants (4 060) (4 152)
Other active plan participants (10 082) (10 847)
(34 446) (35 778)
Plan assets at fair market value 5 681 3 296
Accumulated postretirement benefit obligation
greater than plan assets (28 765) (32 482)
Unamortized transition obligation 30 604 32 304
Unrecognized (gain) loss (1 839) 178
$ - $ -
The following actuarial assumptions were used in determining the plan's
year-end funded status:
1994 1993
Discount rate 8.50% 7.25%
Rate of increase in future compensation 5.00 4.50
In determining its estimated APBO and the funded status of the plan for
1994 and 1993, the Company assumed estimated health care trend rates as
follows:
1994 1993
Medicare part B premiums 12.30% 14.90%
Medical care 8.50 9.00
Dental care 5.00 5.00
The above rates, with the exception of the dental rate, which remains
constant, decrease to five percent in the year 2007 and remain at that level
thereafter. A one percent change in the medical trend rate would have a
$446,000 impact on the Company's annual expense (interest component -
$318,000; service cost - $128,000) and would change the transition obligation
by approximately $1.3 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.
<PAGE>
<PAGE 30>
COMMONWEALTH GAS COMPANY
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. The Company intends
to seek regulatory approval to recover these costs and, while the outcome
cannot be predicted, it is likely that the DPU will authorize similar rate
treatment as was provided to Cambridge Electric and other Massachusetts
electric and gas companies. A deferral representing the difference between
what is being collected in rates and the SFAS No. 106 accrual amounted to
approximately $5.4 million in 1994 and $3.1 million in 1993.
(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 other than pensions. The Company's
contribution was $1,447,000 in 1994, $1,444,000 in 1993 and $1,284,000 in
1992.
(5) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently
estimated at $106.4 million for the five-year period 1995 through 1999. Of
that amount, $21.2 million is estimated for 1995. 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.
(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 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 $21.7 million from Tennessee Gas
<PAGE>
<PAGE 31>
COMMONWEALTH GAS COMPANY
Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern
Transmission Company through December 31, 1994.
As of October 29, 1993, the Company received preliminary DPU autho-
rization to recover these costs, with carrying charges, through the cost of
gas adjustment (CGA) over a four-year period that began in November 1993. As
a result, a regulatory asset totaling $19.2 million is reflected in deferred
charges as of December 31, 1994. In addition, a related liability of $7.8
million is reflected in deferred credits. Final DPU approval for recovery
was received in March 1995.
After extensive negotiations between Texas Eastern, Tennessee and their
customers (including the Company), settlements were reached regarding a
number of transition obligation issues. The settlement with Texas Eastern,
which was recently approved by FERC, calls for the pipeline to absorb
approximately 20% of all transition costs incurred from June 1993 forward.
This agreement also provides for an extended billing period and annual caps
on the collection of future costs. The Company believes that the absorption
requirement will give the pipeline incentive to minimize future costs. The
settlement resulted in a refund of $2.7 million to the Company, which will be
refunded to firm customers beginning in 1995.
The proposed settlement with Tennessee will lower one element of the
Company's transition obligation by approximately $1 million and enhance
certain services the Company receives from Tennessee. Further negotiations
are underway with Tennessee to craft a total settlement similar to that
achieved with Texas Eastern.
The Company is continuing to negotiate with the pipelines on several
other issues. As a result, the Company is unable to predict its final
transition obligation at this time; however, based on these and subsequent
settlement activities, the Company will adjust its regulatory asset and
liability accounts accordingly.
(6) Gas Refunds
During 1994, 1993 and 1992, 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 $6,077,000 in 1994,
$6,965,000 in 1993 and $7,012,000 in 1992.
(7) 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 32>
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, 1994:
Operating Leases
(Dollars in Thousands)
1995 $ 3 321
1996 2 607
1997 1 249
1998 780
1999 324
Beyond 1999 517
Total future minimum lease payments $ 8 798
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $3,699,000 in 1994, $3,435,000 in 1993 and
$3,171,000 in 1992. There were no contingent rentals and no sublease rentals
for the years 1994, 1993 and 1992.
(8) 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 33>
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 15).
(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, 1994, 1993 and 1992 (page 41).
(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 34>
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 35>
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 36>
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 37>
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 38>
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 39>
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 40>
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, 1994
(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, 1994.
<PAGE>
<PAGE 41>
SCHEDULE II
COMMONWEALTH GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 and 1992
(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, 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
Year Ended December 31, 1992
$ 2 271 $ 5 678 $ 1 063 $ 6 122 $ 2 890
<PAGE>
<PAGE 42>
COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1994
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
COMMONWEALTH 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 29, 1995
William G. Poist,
Chairman of the Board and
Chief Executive Officer
KENNETH M. MARGOSSIAN March 30, 1995
Kenneth M. Margossian,
President and Chief Operating Officer
Principal Financial Officer:
JAMES D. RAPPOLI March 29, 1995
James D. Rappoli,
Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 29, 1995
John A. Whalen, Comptroller
A majority of the Board of Directors:
WILLIAM G. POIST March 29, 1995
William G. Poist, Director
JAMES D. RAPPOLI March 29, 1995
James D. Rappoli, Director
KENNETH M. MARGOSSIAN March 30, 1995
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, 1994 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-31-1994
<PERIOD-END> DEC-31-1994
<PERIOD-TYPE> YEAR
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 255,033
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 89,416
<TOTAL-DEFERRED-CHARGES> 36,356
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 380,805
<COMMON> 71,425
<CAPITAL-SURPLUS-PAID-IN> 27,739
<RETAINED-EARNINGS> 6,837
<TOTAL-COMMON-STOCKHOLDERS-EQ> 106,001
0
0
<LONG-TERM-DEBT-NET> 91,750
<SHORT-TERM-NOTES> 36,170
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 3,650
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 143,234
<TOT-CAPITALIZATION-AND-LIAB> 380,805
<GROSS-OPERATING-REVENUE> 325,726
<INCOME-TAX-EXPENSE> 7,983
<OTHER-OPERATING-EXPENSES> 294,062
<TOTAL-OPERATING-EXPENSES> 302,045
<OPERATING-INCOME-LOSS> 23,681
<OTHER-INCOME-NET> 421
<INCOME-BEFORE-INTEREST-EXPEN> 24,102
<TOTAL-INTEREST-EXPENSE> 10,534
<NET-INCOME> 13,568
0
<EARNINGS-AVAILABLE-FOR-COMM> 13,568
<COMMON-STOCK-DIVIDENDS> 14,571
<TOTAL-INTEREST-ON-BONDS> 8,488
<CASH-FLOW-OPERATIONS> 47,447
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
