PAGE 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _______________ to _______________
Commission file number 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, 1994
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 32 of this report.
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COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1993
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......................... 6
Construction and Financing.................... 7
Employees..................................... 7
Item 2. Properties...................................... 7
Item 3. Legal Proceedings............................... 7
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 8
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 9
Item 8. Financial Statements and Supplementary Data..... 12
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............. 12
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................. 32
Signatures.................................................. 46
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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 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 and
requires interstate pipelines to unbundle existing gas sales contracts into
separate components (gas sales, transportation and storage services). Order
636 provides mechanisms that will allow customers such as the Company to
reduce the level of firm services from the pipelines and "broker" excess
capacity on a temporary or permanent basis. Order 636 also requires pipelines
to provide transportation services that allow customers to receive the same
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COMMONWEALTH GAS COMPANY
level of service they had with the bundled contracts. In the past, 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 firm gas purchases and firm
transportation from various pipelines. Presently, the Company has only
transportation, storage, and balancing contracts with these pipelines (and
other upstream pipelines that bring gas from the supply wells to the final
transporting pipelines), and contracts with a variety of independent vendors
for firm gas supply. Twelve new firm gas supply contracts have been
negotiated with suppliers and filed with the DPU. During the interim, the
Company is operating under short-term firm agreements with these same vendors
to provide firm supplies under similar terms and conditions as the long-term
agreements, which are presently under review. Approvals are expected during
the first half of 1994.
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 agreements and new agreements which are the result of
Order 636 requirements for total service unbundling. The LNG facilities,
described below, are used to liquefy and store pipeline gas during the warmer
months for use during the heating season. During 1993, over 99% of the gas
utilized by the Company was delivered by the interstate pipeline system, the
remaining small quantity (approximately 360,000 MMBTU) was delivered as liquid
LNG from Distrigas of Massachusetts.
The Company entered into a multi-party agreement to assume a portion of
Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta
Northeast (ANE), and have the volumes delivered by the Iroquois Gas
Transmission System and Tennessee pipelines. The ANE gas supply contract was
filed with the DPU and hearings were completed in April 1993. 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 only eleven customers using this
transportation service, accounting for only 1,623 BBTU of throughput in 1993
which represented approximately 3.5% of system throughput.
(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
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COMMONWEALTH GAS COMPANY
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.
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 dockets 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 and supplier gas purchase contracts, to pay monthly demand charges
which are recovered from customers through the CGA.
In June 1991, Tennessee filed a settlement with the FERC dealing with a
variety of contract restructuring issues, including the allocation of take-or-
pay costs to Tennessee's customers, including 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.
Future take-or-pay costs will be included in Tennessee's Temporary Gas
Inventory Charge and transition costs under Tennessee's restructuring pursuant
to Order 636.
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COMMONWEALTH GAS COMPANY
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
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 by $1.5 million to $2.5
million.
As a direct result of implementation of Order 636, most pipeline
companies are incurring transition costs which include the cost of
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 take-or-pay and other contract restructuring
costs from its customers through the CGA as permitted by the DPU. The
remaining take-or-pay costs to be billed to the Company from both Algonquin
and Tennessee are estimated at approximately $431,000 as of December 31, 1993,
subject to change upon FERC approval.
(c) Most Recent Rate Case Proceeding
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. The increase was necessitated by the rising costs of
providing service to customers and substantial expenditures to upgrade,
improve and maintain the Company's distribution system.
Environmental Matters
The Company is a potentially responsible party (PRP) in the Sullivan's
Ledge Superfund site in New Bedford, Massachusetts. In 1990, the Company
agreed to a settlement regarding this site and its share of clean-up costs is
presently estimated to be $1.8 million and is reflected on the accompanying
Balance Sheets. Sampling work at the site indicates that a more extensive
clean-up than originally contemplated may be required, although the financial
impact of these findings is not presently known. The settling parties for the
site are now pursuing claims against a number of non-settling PRPs, and any
amounts recovered through those claims will be applied to offset the settling
parties' liabilities.
The Company is evaluating a former gas manufacturing plant site in
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COMMONWEALTH GAS COMPANY
Worcester, Massachusetts, and a proposal for a comprehensive assessment of
this site has been prepared. It is possible that this site may require
substantial remediation work due to the suspected presence of hazardous
substances. However, the cost of remediation cannot be estimated at this
time.
The Company anticipates recovery of costs associated with the clean-up
of such sites from its customers through a procedure established in a generic
order issued by the DPU, wherein such costs are recovered through an element
of the existing CGA. These costs are expected to be recovered over a seven-
year amortization period without a return on the unamortized balance.
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 765 regular employees, 526 (68.8%) 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 1993, the gas system included 2,739 miles of gas distribution
lines, 161,192 services and 237,318 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, 1993
One
(c) Frequency and Amount of Dividends Declared in 1993 and 1992
1993 1992
Per Share Per Share
Declaration Date Amount Declaration Date Amount
January 28, 1993 $2.17 April 16, 1992 $3.00
April 15, 1993 3.75 July 16, 1992 1.00
July 15, 1993 .50 $4.00
$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, 1993 and 1992 is shown below:
Years Ended Years Ended
December 31, December 31,
1993 and 1992 1992 and 1991
Increase (Decrease)
(Dollars in Thousands)
Gas Operating Revenues $ 6 896 2.3 % $ 38 998 15.1 %
Operating Expenses -
Cost of gas sold 2 736 1.7 11 981 7.8
Other operation
and maintenance 977 1.2 6 566 8.5
Depreciation 669 8.1 360 4.6
Taxes -
Federal and state income 1 265 14.7 7 223 533.1
Local property and other 404 5.6 1 477 25.6
6 051 2.2 27 607 11.3
Operating Income 845 3.5 11 391 88.2
Other Income 340 114.5 408 367.6
Income Before Interest Charges 1 185 4.8 11 799 92.1
Interest Charges (259) (2.7) 64 0.7
Net Income $ 1 444 9.7 $ 11 735 376.1
Unit Sales (BBTU) Increase (Decrease)
Firm (591) (1.5) % 3 415 9.4 %
Interruptible (844) (25.6) (2 201) (40.0)
(1 435) (3.3) 1 214 2.9
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COMMONWEALTH GAS COMPANY
The following is a summary of unit sales and customers for the periods
indicated:
Years Ended December 31,
1993 1992 1991
Unit Sales (BBTU):
Residential 22 252 22 392 19 851
Commercial 10 931 10 913 9 575
Industrial 4 205 4 717 5 388
Other 1 831 1 788 1 581
Total firm sales 39 219 39 810 36 395
Interruptible sales 2 459 3 303 5 504
Total 41 678 43 113 41 899
Customers at End of Period:
Residential 211 877 207 163 207 867
Commercial 18 323 17 932 18 515
Industrial 920 921 991
Other 1 093 1 009 1 022
Total 232 213 227 025 228 395
Operating Revenues and Cost of Gas Sold
Operating revenues increased nearly $7 million or 2.3% due primarily to
an increase in conservation and load management (C&LM) costs ($4.8 million)
which are being recovered through a Conservation Charge (CC) decimal effective
in late 1992 and a 1.7% increase in the cost of gas sold ($2.7 million). Also
contributing to the increase were transition costs ($1.4 million) associated
with the implementation of Order 636. Somewhat offsetting these increases
were lower unit sales of approximately 3.3%. The significant change in 1992
revenues from 1991 resulted from higher base rates which were approved for the
Company effective November 1, 1991, an increase in firm unit sales and higher
firm transportation revenues than in 1991. Seasonal rates recognize the
increased cost of providing gas service during the winter months.
The cost of gas sold per MMBTU averaged $3.81 in 1993, $3.65 in 1992
and $3.54 in 1991. The higher cost of gas in 1993, compared to 1992, was due,
in part, to the costs incurred as a result of the implementation of Order 636.
In 1992, the higher cost of gas, compared to 1991, was the result of lower
levels of refunds from pipeline suppliers and an increase in the cost of spot
market purchases. Refunds from pipeline suppliers, which are passed along to
the Company's firm customers, amounted to approximately $7 million ($.18 per
MMBTU) in both 1993 and 1992, as compared to $9.4 million ($.26 per MMBTU) for
1991. In 1994, the cost of gas is expected to average approximately $4.40 per
MMBTU due to the impact of Order 636 and rising transportation costs.
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%. Although
interruptible sales decreased approximately 26% during 1993, these sales have
little, if any, impact on net income. In 1992, firm unit sales increased 9.4%
due to significantly higher residential and commercial customer use caused by
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COMMONWEALTH GAS COMPANY
colder temperatures in the first and fourth quarters. The variations from
year to year in weather conditions, particularly during the heating season,
cause gas usage to fluctuate. 1992 weather patterns were more normal (colder)
than 1991.
The number of customers increased approximately 2.3% in 1993 due to new
home construction and conversion activity. The fluctuation in interruptible
sales during the three-year period reflects the competitive market conditions
for energy resources. However, interruptible sales have little impact on
earnings.
Operating Expenses
Other operation and maintenance increased approximately $977,000 or
1.2% in 1993 due primarily to the implementation of C&LM programs ($4.8
million) during 1993 and increased pension costs ($500,000). In addition,
payroll costs increased 2.6% or $821,000 for 1993 compared to an increase of
$1.2 million or 4.1% for 1992 reflecting the Company's continuing cost
containment efforts, including reduced overtime and work force reductions
through attrition. Offsetting these increases in 1993 were a decline in
employee medical and life insurance costs of $954,000, lower liability
insurance costs of $1.4 million due to fewer and less costly claims and the
absence of amortization costs (totaling $1.9 million) associated with the
Company's automated mapping system (CAMRIS). Engineering costs for CAMRIS
were incurred throughout the three-year period and amounted to $1,773,000,
$1,485,000 and $1,039,000 in 1993, 1992 and 1991, respectively. Overall costs
increased in 1992 due to an increase in insurance and benefits costs and an
increase in the provision for bad debts reflecting difficult economic
conditions. These increases were offset somewhat by the Company's continuing
cost containment efforts.
Depreciation and Taxes
The increase in depreciation expense in both 1993 and 1992 resulted
from higher levels of depreciable plant-in-service. Federal and state income
taxes increased during 1993 and 1992 due to a greater level of pretax income
and, to a lesser extent for 1993, the change in the federal tax rate to 35%,
effective January 1, 1993.
Other Income
Other income increased during 1993 due primarily to higher income from
non-utility rental properties, interest on the Company's C&LM program
development costs and from the Company's share of the net proceeds from a
litigation settlement recorded in the second quarter ($193,000). The impact
of these items was offset somewhat by a decline in sales of design heating
systems. For 1992, other income increased due primarily to lower costs
associated with the sale of appliances and an increase in the number of
appliances sold.
Interest Charges
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
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COMMONWEALTH GAS COMPANY
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 3.5% in 1993 compared to 4% for 1992.
During 1992, total interest charges increased only slightly due to a higher
average level of short-term borrowings offset by lower interest rates and the
aforementioned early retirement of long-term debt.
Financing Activity
On December 30, 1993, the Company issued $25 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.
New Accounting Standards
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." This statement establishes
new accounting and reporting standards for postretirement benefits other than
pensions. For further information, refer to Note 4(b) of the Notes to
Financial Statements.
In 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits" (SFAS 112). The Company is required to adopt this
statement effective January 1, 1994. SFAS 112 requires employers to recognize
the obligation to provide benefits to former or inactive employees after
employment but before retirement (postemployment). Those benefits include
salary continuation, supplemental employment benefits, severance benefits,
disability-related benefits and continuation of health care and life insurance
coverage if each of the following conditions are met: 1) the obligation is
attributable to employee services already rendered, 2) employees' rights to
those benefits accumulate or vest, 3) payment of the benefits is probable and
4) the cost of the benefits can be reasonably estimated. The Company believes
that the adoption of the provisions of SFAS 112 will not have a material
impact on its financial position or results of operations.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed
herewith on pages 13 through 31 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, 1993
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, 1993 and 1992, and the related
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements and
the schedules referred to below are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedules 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, 1993 and 1992, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1993, in conformity with generally accepted accounting principles.
As discussed in Note 4 to the 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 schedules listed in the
index to financial statements and schedules are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN & CO.
Arthur Andersen & Co.
Boston, Massachusetts,
February 17, 1994.
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COMMONWEALTH GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Balance Sheets at December 31, 1993 and 1992
Statements of Income for the Years Ended December 31, 1993, 1992 and
1991
Statements of Retained Earnings for the Years Ended December 31, 1993,
1992 and 1991
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and
1991
Notes to Financial Statements
PART IV.
SCHEDULES
V Property, Plant and Equipment for the Years Ended December 31,
1993, 1992 and 1991
VI Accumulated Depreciation of Property, Plant and Equipment for the
Years Ended December 31, 1993, 1992 and 1991
VIII Valuation and Qualifying Accounts for the Years Ended December 31,
1993, 1992 and 1991
IX Short-Term Borrowings for the Years Ended December 31, 1993, 1992
and 1991
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.
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COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1993 AND 1992
ASSETS
1993 1992
(Dollars in Thousands)
PROPERTY, PLANT AND EQUIPMENT, at original cost $323 607 $304 877
Less - Accumulated depreciation 77 155 72 766
246 452 232 111
Add - Construction work in progress 400 565
246 852 232 676
CURRENT ASSETS
Cash 1 297 10
Accounts receivable -
Affiliated companies 173 221
Customers, less reserves of $3,162,000 in 1993
and $2,890,000 in 1992 33 066 28 302
Unbilled revenues 29 068 29 070
Inventories, at average cost -
Natural gas 25 810 17 906
Materials and supplies 1 979 2 139
Prepaid taxes -
Property 2 629 2 329
Income 1 812 6 690
Other 992 1 179
96 826 87 846
DEFERRED CHARGES
Order 636 transition costs 21 938 -
Other 11 067 7 084
33 005 7 084
$376 683 $327 606
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COMMONWEALTH GAS COMPANY
BALANCE SHEETS
DECEMBER 31, 1993 AND 1992
CAPITALIZATION AND LIABILITIES
1993 1992
(Dollars in Thousands)
CAPITALIZATION
Common Equity -
Common stock, $25 par value -
Authorized and outstanding -
2,857,000 shares in 1993 and
2,407,000 in 1992, wholly-owned
by Commonwealth Energy System (Parent) $ 71 425 $ 60 175
Amounts paid in excess of par value 27 739 20 989
Retained earnings 7 840 6 994
107 004 88 158
Long-term debt, including premiums, less
current sinking fund requirements and
maturing debt (Note 3) 95 400 64 050
202 404 152 207
CURRENT LIABILITIES
Interim Financing (Note 3) -
Notes payable to banks 40 975 52 475
Advances from affiliates 2 835 8 540
43 810 61 015
Other Current Liabilities -
Current sinking fund requirements 3 650 3 650
Accounts payable -
Affiliated companies 1 811 1 610
Other 32 944 38 712
Refundable gas costs (Note 1) 13 253 7 824
Customer deposits 1 440 1 441
Accrued local property and other taxes 2 940 2 583
Accrued interest 774 781
Other 4 447 3 617
61 259 60 218
105 069 121 233
DEFERRED CREDITS
Accumulated deferred income taxes 30 176 27 120
Unamortized investment tax credits 6 270 6 480
Order 636 transition costs 13 133 -
Other 19 631 20 565
69 210 54 165
COMMITMENTS AND CONTINGENCIES (Notes 5 and 8)
$376 683 $327 606
The accompanying notes are an integral part of these financial statements.
PAGE 17
COMMONWEALTH GAS COMPANY
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991
(Dollars in Thousands)
GAS OPERATING REVENUES $304 129 $297 233 $258 235
OPERATING EXPENSES
Cost of gas sold 167 607 164 871 152 890
Other operation 71 380 69 126 62 926
Maintenance 11 929 11 611 11 608
Depreciation 8 939 8 270 7 910
Amortization 1 629 3 224 2 861
Taxes -
Income (Note 2) 9 843 8 578 1 355
Local property 4 865 4 608 3 008
Payroll and other 2 779 2 632 2 755
278 971 272 920 245 313
OPERATING INCOME 25 158 24 313 12 922
OTHER INCOME (EXPENSE) 637 297 (111)
INCOME BEFORE INTEREST CHARGES 25 795 24 610 12 811
INTEREST CHARGES
Long-term debt 6 345 7 004 7 523
Other interest charges 3 170 2 769 2 176
Allowance for borrowed funds used
during construction (19) (18) (8)
9 496 9 755 9 691
NET INCOME $ 16 299 $ 14 855 $ 3 120
The accompanying notes are an integral part of these financial statements.
PAGE 18
COMMONWEALTH GAS COMPANY
STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991
(Dollars in Thousands)
Balance at beginning of year $ 6 994 $ 1 767 $ 4 063
Add (Deduct)
Net income 16 299 14 855 3 120
Cash dividends on common stock (15 453) (9 628) (5 416)
Balance at end of year $ 7 840 $ 6 994 $ 1 767
The accompanying notes are an integral part of these financial statements.
PAGE 19
COMMONWEALTH GAS COMPANY
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
1993 1992 1991
(Dollars in Thousands)
OPERATING ACTIVITIES
Net income $16 299 $14 855 $ 3 120
Effects of non-cash items -
Depreciation and amortization 11 363 12 100 11 296
Deferred income taxes 8 018 1 478 453
Investment tax credits (210) (217) (224)
Change in working capital exclusive
of cash and interim financing -
Accounts receivable and unbilled
revenues (4 714) (4 544) (13 472)
Prepaid income taxes 4 878 729 147
Local property and other taxes, net 57 136 85
Accounts payable and other (6 873) 3 032 (9 620)
Uncollected postretirement benefits costs (3 062) - -
Uncollected Order 636 costs (8 805) - -
All other operating items (9 065) (3 003) (2 276)
Net cash provided by (used for)
operating activities 7 886 24 566 (10 491)
INVESTING ACTIVITIES
Additions to property, plant and
equipment (exclusive of AFUDC) (23 272) (20 437) (17 122)
Allowance for borrowed funds used
during construction (19) (18) (8)
Net cash used for investing activities (23 291) (20 455) (17 130)
FINANCING ACTIVITIES
Sale of common stock to Parent 18 000 - -
Payment of dividends (15 453) (9 628) (5 416)
Proceeds from (payment of) short-term
borrowings (11 500) 14 875 6 675
Proceeds from (payment of) affiliate
borrowings (5 705) 3 275 5 265
Retirement of long-term debt
through sinking funds (3 650) (3 657) (3 913)
Long-term debt issues refunded - (9 110) -
Long-term debt issues 35 000 - 25 000
Net cash provided by (used for)
financing activities 16 692 (4 245) 27 611
Net increase (decrease) in cash 1 287 (134) (10)
Cash at beginning of period 10 144 154
Cash at end of period $ 1 297 $ 10 $ 144
Supplemental Disclosures of Cash Flow Information
Cash paid (received) during the period for:
Interest (net of amounts capitalized) $ 8 797 $ 9 377 $ 8 733
Income taxes $ 3 133 $ 6 167 $ (668)
The accompanying notes are an integral part of these financial statements.
PAGE 20
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. At December 31, 1993, principal regulatory assets included in deferred
charges were $21.9 million for transition costs associated with FERC Order
No. 636 and $3.1 million for postretirement benefits costs. In addition, a
regulatory liability related to income taxes, amounting to $10 million, was
reflected in deferred credits.
(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.
(c) Transactions with Affiliates
Operating revenues include sales of gas to affiliated companies as
follows:
(Dollars in Thousands)
1993 Cost Margin Total
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
1991
Cambridge Electric $4 207 $ 501 $4 708
Commonwealth Electric 1 195 93 1 288
$5 402 $ 594 $5 996
The margin realized on these sales together with that realized from non-
affiliate interruptible sales is credited to firm customers through the Cost
of Gas Adjustment Clause (CGA).
PAGE 21
COMMONWEALTH GAS COMPANY
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 $9,587,000, $8,683,000 and $8,319,000 in 1993, 1992 and 1991,
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, 1993 and 1992, the Company
had overcollected $13,253,000 and $7,824,000, 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 2.95% in 1993, 2.90% in 1992 and 2.94% in 1991.
(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 3.5% in 1993,
4.25% in 1992 and 6.25% in 1991.
PAGE 22
COMMONWEALTH GAS COMPANY
(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, 1993, 1992 and 1991:
1993 1992 1991
(Dollars in Thousands)
Federal -
Current $1 619 $6 093 $ 964
Deferred 6 956 1 422 283
Investment tax credits (210) (217) (224)
8 365 7 298 1 023
State -
Current 416 1 224 162
Deferred 1 278 343 170
1 694 1 567 332
10 059 8 865 1 355
Amortization of regulatory liability
relating to deferred income taxes (216) (287) -
Total federal and state
income taxes $ 9 843 $ 8 578 $ 1 355
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 and tax basis of assets and
liabilities using enacted tax rates in effect in the year in which the
differences are expected to reverse.
Accumulated deferred income taxes consisted of the following in 1993 and
1992:
PAGE 23
COMMONWEALTH GAS COMPANY
1993 1992
(Dollars in Thousands)
Liabilities
Property-related $37 230 $34 483
Order 636 transition costs, net 3 450 -
Postretirement benefits plan 1 422 -
All other 1 419 1 763
43 521 36 246
Assets
Investment tax credit 4 047 4 021
Pension plan 2 284 1 843
Regulatory liability 3 006 3 342
Inventory repricing 2 946 3 980
All other 2 785 3 428
15 068 16 614
Accumulated deferred income taxes, net $28 453 $19 632
The net year-end deferred income tax liability above is net of a current
deferred tax asset of $1,723,000 in 1993 and $7,488,000 in 1992 which was
included in prepaid income taxes in the accompanying Balance Sheets.
The following table, detailing the significant timing differences for
1991 which resulted in deferred income taxes, is required to be disclosed
pursuant to accounting standards in effect prior to adoption of SFAS No. 109:
1991
(Dollars in Thousands)
Accelerated depreciation for tax purposes $ 2 775
Capitalized interest during construction (20)
Contributions in aid of construction (163)
Capitalized leases (310)
Repricing LNG inventory (1 025)
Provision for bad debts (120)
Pension costs and deferred compensation (302)
Conservation and load management 167
Other (549)
Deferred income tax provision $ 453
The total income tax provision set forth on the previous page
represents 38% in 1993, 37% in 1992 and 30% in 1991 of income before such
taxes. The following table reconciles the statutory federal income tax rate
to these percentages:
1993 1992 1991
Statutory federal income tax rate 35% 34% 34%
Increase (Decrease) from statutory rate:
State tax net of federal tax benefit 4 5 5
Amortization of investment tax credits (1) (1) (5)
Amortization of excess deferred reserves - (1) (3)
Other - - (1)
38% 37% 30%
PAGE 24
COMMONWEALTH GAS COMPANY
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.
(3) Long-Term Debt and Interim Financing
(a) Long-Term Debt
Long-term debt outstanding, exclusive of current maturities, current
sinking fund requirements and related premiums and discounts, collateralized
by substantially all of the Company's property, is as follows:
Original Balance December 31,
Issue 1993 1992
(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 25 400 29 050
9.95%, Series J, due 2020 25 000 25 000 25 000
7.11%, Series K, due 2033 35 000 35 000 -
$95 400 $64 050
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, 1993 are as follows:
Sinking Fund Maturing Debt
Year Requirements Issues Total
(Dollars in Thousands)
1994 $3 650 $ - $ 3 650
1995 3 650 - 3 650
1996 3 650 10 000 13 650
1997 3 650 - 3 650
1998 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,
1993, system companies had $115 million of committed lines of credit that
will expire at varying intervals in 1994. These lines are normally renewed
upon expiration and require annual fees ranging from zero to .1875% of the
individual line. At December 31, 1993, the uncommitted lines of credit
totaled $70 million. Interest rates on the outstanding borrowings generally
are at an adjusted money market rate. The Company's notes payable to banks
totaled $40,975,000 and $52,475,000 at December 31, 1993 and 1992,
respectively.
PAGE 25
COMMONWEALTH GAS COMPANY
(c) Advances from Affiliates
The Company had short-term notes payable to the System totaling $355,000
and $5,780,000 at December 31, 1993 and 1992, respectively. These notes are
written for a term of eleven months and twenty-nine days. Interest is at the
prime rate (6% at December 31, 1993 and 1992) and is adjusted for changes in
the rate during the term of the notes.
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 that available from banks. The Company had
borrowings from the Pool of $2,480,000 and $2,760,000 at December 31, 1993
and 1992, 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, 1993 and 1992 are as follows:
1993 1992
(Dollars in Thousands)
Carrying Fair Carrying Fair
Value Value Value Value
Long-Term Debt $99 050 $111 718 $67 700 $74 964
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 upon 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 and Postretirement Benefits
(a) Pension
The Company has a noncontributory pension plan covering substantially
all regular employees who have attained the age of 21 and have completed a
year of service. Pension benefits are based on an employee's years of
service and compensation. The Company makes monthly contributions to the
plan consistent with the funding requirements of the Employee Retirement
Income Security Act of 1974.
PAGE 26
COMMONWEALTH GAS COMPANY
Components of pension expense were as follows:
1993 1992 1991
(Dollars in Thousands)
Service cost $ 1 904 $ 1 720 $ 1 632
Interest cost 6 037 5 478 5 179
Return on plan assets (10 821) (7 278) (13 853)
Net amortization and deferral 6 317 3 001 10 387
Total pension expense 3 437 2 921 3 345
Transfers from affiliated
companies, net 37 77 72
Less: Amounts capitalized
and deferred 328 371 334
Net pension expense $ 3 146 $ 2 627 $ 3 083
The following economic assumptions were used to measure year-end
obligations and the estimated pension expense for the subsequent year:
1993 1992 1991
Discount rate 7.25% 8.50% 8.50%
Assumed rate of return 8.50 8.50 8.50
Rate of increase in future compensation 4.50 5.50 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:
1993 1992
(Dollars in Thousands)
Accumulated benefit obligation:
Vested $(61 668) $(50 331)
Nonvested (8 297) (2 649)
$(69 965) $(52 980)
Projected benefit obligation $(85 269) $(66 893)
Plan assets at fair market value 79 553 71 045
Projected benefit obligation less
(greater) than plan assets (5 716) 4 152
Unamortized transition obligation 4 955 5 574
Unrecognized prior service cost 5 115 2 773
Unrecognized gain (9 141) (16 317)
Accrued pension cost $ (4 787) $ (3 818)
Plan assets consist primarily of fixed income and equity securities.
Fluctuations in the fair market value of plan assets will affect pension
expense in future years. The increase in the accumulated benefit obligation
and the projected benefit obligation from December 31, 1992 to December 31,
1993 was primarily due to a reduction of the discount rate in light of
current interest rates.
PAGE 27
COMMONWEALTH GAS COMPANY
(b) Other Postretirement Benefits
Through December 31, 1992, the Company provided postretirement health
care and life insurance benefits to all 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 another 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 under the traditional pay-as-you-go method
totaled $1,910,000 in 1992 and $1,603,000 in 1991.
In 1993, the Company began making contributions to various voluntary
employee beneficiary association (VEBA) trusts that were established pursuant
to section 501(c)9 of the Internal Revenue Code (the Code). The Company also
made contributions to a sub-account 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 $3,780,000 to these trusts
during 1993.
The net periodic postretirement benefit cost for the year ended December
31, 1993 included the following components:
1993
(Dollars in Thousands)
Service cost $ 535
Interest cost 2 858
Return on plan assets (203)
Amortization of transition obligation
over 20 years 1 700
Net amortization and deferral 22
Total postretirement benefit cost 4 912
Less: Amounts capitalized and deferred 3 196
Net postretirement benefit cost $ 1 716
PAGE 28
COMMONWEALTH GAS COMPANY
The funded status of the Company's postretirement benefit plan using a
measurement date of December 31, 1993 is as follows:
1993
(Dollars in Thousands)
Accumulated postretirement benefit obligation:
Retirees $(20 779)
Active participants (14 999)
(35 778)
Plan assets at fair market value 3 296
Projected postretirement benefit obligation
greater than plan assets (32 482)
Unamortized transition obligation 32 304
Unrecognized gain 178
$ -
In determining its estimated APBO and the funded status of the plan, the
Company assumed a discount rate of 7.25%, an expected long-term rate of
return on plan assets of 8.5%, and a medical care cost trend rate of 9%,
which gradually decreases to 5% in the year 2007 and remains at that level
thereafter. The estimate also reflects a trend rate of 14.9% for
reimbursement of Medicare Part B premiums which decreases to 5% by 2007 and a
dental care trend rate of 5% in all years. A one percent change in the
medical trend rate would have a $479,000 impact on the Company's annual
expense (interest component-$357,000; service cost-$122,000) and would change
the accumulated benefit obligation by approximately $4.4 million.
Plan assets consist primarily of fixed income and equity securities.
Fluctuations in the fair market value of plan assets will affect
postretirement benefit expense in future years.
The DPU's policy on postretirement benefits is to allow in rates the
maximum tax deductible contributions made to trusts that have been
established specifically to pay postretirement benefits. The Company intends
to seek recovery in their next rate proceeding. While the Company is unable
to predict the outcome of these rate proceedings, it believes the DPU will
authorize similar rate treatment as provided to Cambridge Electric and other
Massachusetts electric and gas companies for the recovery of the cost of
these benefits. Further, based on recent DPU action and discussions with
regulators, the Company believes that it is appropriate to record the
difference between the amount included in rates and SFAS No. 106 costs as a
regulatory asset. At December 31, 1993, this deferral amounted to
approximately $3,062,000.
(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 benefits other than pensions. The Company's contribution was
$1,444,000 in 1993, $1,284,000 in 1992 and $1,207,000 in 1991.
PAGE 29
COMMONWEALTH GAS COMPANY
(5) Commitments and Contingencies
(a) Construction and Financing Program
The Company is engaged in a continuous construction program presently
estimated at $112.4 million for the five-year period 1994 through 1998. Of
that amount, $21.9 million is estimated for 1994. 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
On April 8, 1992, the Federal Energy Regulatory Commission (FERC) issued
Order No. 636 (Order 636), requiring interstate pipelines to unbundle
(separate) existing gas sales contracts into separate components (gas sales,
transportation and storage services). Order 636 provides mechanisms that
will allow customers such as the Company to reduce the level of firm services
from pipelines and permits the "brokering" of excess capacity on a temporary
or permanent basis. Order 636 also requires pipelines to provide
transportation services which allow customers to receive the same level of
service they had with bundled contracts. Pipelines were required to be
operating under Order 636 by November 1, 1993.
As a result of implementing Order 636, each pipeline company is allowed
to collect certain "transition costs" from their customers. The Company has
been billed a total of approximately $16.9 million from Tennessee Gas
Pipeline Company, Algonquin Gas Transmission Company and Texas Eastern
Transmission Company through December 31, 1993. It is anticipated that as
much as $45 million in transition costs could be sought by these suppliers
through a series of FERC filings over the 12 to 24 month period that began on
June 1, 1993. The largest element of the aforementioned transition costs
results from the pipelines' need to buy out gas supply contracts entered into
prior to Order 636. The total amount of such costs ultimately billed to the
Company will vary depending on the success of the pipelines in negotiating
settlements with their former suppliers, and final review by the FERC. The
Company is actively reviewing the prudency of transition costs billed in
order to minimize costs to its customers. The Company has recorded its
estimated liability based on amounts incurred by the respective pipelines as
of December 31, 1993.
PAGE 30
COMMONWEALTH GAS COMPANY
On October 29, 1993, the Company received preliminary DPU authorization
to recover these costs, with carrying charges, through the CGA over a four-
year period that began in November 1993. As a result, a regulatory asset
totaling $21.9 million, net of $400,000 recovered during the fourth quarter,
was recorded as of December 31, 1993 and reflected in deferred charges. In
addition, a related liability of $13.1 million was reflected in deferred
credits. Also, approximately $7.9 million of the amount paid to the pipeline
companies relates to gas inventory costs being allocated new storage services
under Order 636. The Company will recover these inventory costs through the
CGA.
(6) Gas Refunds
During 1993, 1992 and 1991, the Company received refunds from its gas
suppliers in settlement of several rate cases which 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 $6,965,000 in 1993,
$7,012,000 in 1992 and $9,409,000 in 1991.
(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 which
prohibit the Company from entering into future lease agreements or
obligations.
Future minimum lease payments, by period and in the aggregate, of non-
cancelable operating leases consisted of the following at December 31, 1993:
Operating Leases
(Dollars in Thousands)
1994 $ 3 183
1995 2 879
1996 1 994
1997 600
1998 159
Beyond 1998 477
Total future minimum lease payments $ 9 292
Total rent expense for all operating leases, except those with terms of
a month or less, amounted to $3,435,000 in 1993, $3,171,000 in 1992 and
$3,059,000 in 1991. There were no contingent rentals and no sublease rentals
for the years 1993, 1992 and 1991.
(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
PAGE 31
COMMONWEALTH GAS COMPANY
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 32
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(s) indicated are financial statement
schedules of the Company:
Schedule V - Property, Plant and Equipment - Years Ended December
31, 1993, 1992 and 1991 (pages 40-42).
Schedule VI - Accumulated Depreciation of Property, Plant and
Equipment - Years Ended December 31, 1993, 1992 and 1991 (page
43).
Schedule VIII - Valuation and Qualifying Accounts - Years Ended
December 31, 1993, 1992 and 1991 (page 44).
Schedule IX - Short-Term Borrowings - Years Ended December 31,
1993, 1992 and 1991 (page 45).
(a) 3. Exhibits:
Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are
incorporated by reference to the appropriate exhibit numbers and
the Securities and Exchange Commission file numbers indicated in
parentheses.
b. If applicable, as designated by an asterisk, certain documents
previously filed by the Company have been disposed of by the
Commission pursuant to its Records Control Schedule and are hereby
being refiled by the Company.
c. 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.
d. The following is a glossary of acronyms used throughout the
Exhibit Index:
PAGE 33
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 34
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).
Exhibit 10. Material Contracts.
10.1. Natural Gas Purchase Contracts.
10.1.1 Natural gas purchase contracts between AGT and NBGEL dated October
28, 1969 and August 14, 1968 for Firm and Winter Service,
respectively (Exhibits 1 and 2 to the CG 1984 Form 10-K, File No.
2-1647).
10.1.2 Natural gas purchase contracts between AGT and CG dated July 10,
1972 for Firm and Winter Service applicable to Rate Schedule WS-1
(Exhibits 3 and 4 to the CG 1984 Form 10-K, File No. 2-1647).
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).
PAGE 35
COMMONWEALTH GAS COMPANY
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).
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).
PAGE 36
COMMONWEALTH GAS COMPANY
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).
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).
PAGE 37
COMMONWEALTH GAS COMPANY
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).
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).
PAGE 38
COMMONWEALTH GAS COMPANY
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).
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).
PAGE 39
COMMONWEALTH GAS COMPANY
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).
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).
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the three months ended
December 31, 1993.
PAGE 40
SCHEDULE V
COMMONWEALTH GAS COMPANY
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1993
Balance Retirements Balance
Beginning Additions Charged To End of
Classification of Year at Cost Reserve Transfers Year
(Dollars in Thousands)
GAS
Intangible plant $ 1 392 $ - $ - $ - $ 1 392
Land and rights of way 979 43 - - 1 022
Structures and leasehold improvements 13 173 212 41 - 13 344
Distribution equipment 286 094 22 850 4 685 - 304 259
General equipment and vehicles 2 119 178 - - 2 297
Total plant in service 303 757 23 283 4 726 - 322 314
Construction work in progress 565 (165) - - 400
Total gas 304 322 23 118 4 726 - 322 714
OTHER
Miscellaneous physical property 1 120 173 - - 1 293
Total property, plant and equipment $305 442 $23 291 $4 726 $ - $324 007
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
PAGE 41
SCHEDULE V
COMMONWEALTH GAS COMPANY
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1992
Balance Retirements Balance
Beginning Additions Charged To End of
Classification of Year at Cost Reserve Transfers Year
(Dollars in Thousands)
GAS
Intangible plant $ 1 392 $ - $ - $ - $ 1 392
Land and rights of way 979 - - - 979
Structures and leasehold improvements 12 931 281 39 - 13 173
Distribution equipment 267 855 19 872 1 633 - 286 094
General equipment and vehicles 1 869 250 - - 2 119
Total plant in service 285 026 20 403 1 672 - 303 757
Construction work in progress 513 52 - - 565
Total gas 285 539 20 455 1 672 - 304 322
OTHER
Miscellaneous physical property 1 120 - - - 1 120
Total property, plant and equipment $286 659 $20 455 $1 672 $ - $305 442
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
PAGE 42
SCHEDULE V
COMMONWEALTH GAS COMPANY
PROPERTY, PLANT AND EQUIPMENT (A)
FOR THE YEAR ENDED DECEMBER 31, 1991
Balance Retirements Balance
Beginning Additions Charged To End of
Classification of Year at Cost Reserve Transfers Year
(Dollars in Thousands)
GAS
Intangible plant $ 1 392 $ - $ - $ - $ 1 392
Land and rights of way 979 - - - 979
Structures and leasehold improvements 12 463 598 131 1 12 931
Distribution equipment 253 021 16 606 1 772 - 267 855
General equipment and vehicles 1 918 72 120 (1) 1 869
Total plant in service 269 773 17 276 2 023 - 285 026
Construction work in progress 678 (165) - - 513
Total gas 270 451 17 111 2 023 - 285 539
OTHER
Miscellaneous physical property 1 101 19 - - 1 120
Total property, plant and equipment $271 552 $17 130 $2 023 $ - $286 659
<FN>
(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
PAGE 43
SCHEDULE VI
COMMONWEALTH GAS COMPANY
ACCUMULATED DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Dollars in Thousands)
Provision
Balance at Amortization Balance
Beginning Charged to of Leasehold Removal at End
Classification of Year Operations Improvements Retirements Cost Salvage of Year
YEAR ENDED DECEMBER 31, 1993
Gas $72 765 $ 8 939 $ 1 088 $ 4 725 $ 865 $ (48) $77 154
Other 1 - - - - - 1
Total Accumulated
Depreciation $72 766 $ 8 939 $ 1 088 $ 4 725 $ 865 $ (48) $77 155
YEAR ENDED DECEMBER 31, 1992
Gas $65 966 $ 8 270 $ 1 045 $ 1 672 $ 830 $ (14) $72 765
Other 1 - - - - - 1
Total Accumulated
Depreciation $65 967 $ 8 270 $ 1 045 $ 1 672 $ 830 $ (14) $72 766
YEAR ENDED DECEMBER 31, 1991
Gas $60 298 $ 7 910 $ 835 $ 2 023 $1 084 $ 30 $65 966
Other 1 - - - - - 1
Total Accumulated
Depreciation $60 299 $ 7 910 $ 835 $ 2 023 $1 084 $ 30 $65 967
PAGE 44
SCHEDULE VIII
COMMONWEALTH GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 and 1991
(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, 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
Year Ended December 31, 1991
$ 1 878 $ 5 208 $ 952 $ 5 767 $ 2 271
PAGE 45
SCHEDULE IX
COMMONWEALTH GAS COMPANY
SHORT-TERM BORROWINGS (A)
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Dollars in Thousands)
Maximum Weighted
Weighted Month-End Average Average
Category of Average Amount Amount Interest
Aggregate Balance Interest Outstanding Outstanding Rate
Short-Term at End Rate at End During During the During the
Borrowings of Period of Period the Period Period(B) Period(C)
December 31, 1993
Notes Payable
to Banks $40 975 3.3% $74 225 $49 133 3.3%
Notes Payable
to System $ 355 6.0% $ 9 630 $ 2 375 6.0%
COM/Energy
Money Pool $ 2 480 3.2% $18 640 $ 8 370 3.2%
December 31, 1992
Notes Payable
to Banks $52 475 3.8% $52 475 $29 460 4.0%
Notes Payable
to System $ 5 780 6.0% $ 6 260 $ 2 825 6.2%
COM/Energy
Money Pool $ 2 760 3.4% $ 2 760 $ 1 406 3.7%
December 31, 1991
Notes Payable
to Banks $37 600 5.6% $39 025 $17 365 6.3%
Notes Payable
to System $ 3 725 6.5% $ 3 725 $ 679 7.5%
COM/Energy
Money Pool $ 1 540 4.6% $ 1 540 $ 458 5.7%
(A) Refer to Note 3 of Notes to Financial Statements filed under Item 8 of
this report for the general terms of each category of short-term
borrowings.
(B) The average amount outstanding during the period is determined by
averaging the level of month-end principal balances outstanding for the
prior thirteen-month period ending December 31.
(C) The weighted average interest rate during the period is determined by
averaging the interest rates in effect on all loans transacted for the
twelve-month period ended December 31.
PAGE 46
COMMONWEALTH GAS COMPANY
FORM 10-K DECEMBER 31, 1993
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
COMMONWEALTH 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 30, 1994
William G. Poist,
Chairman of the Board and
Chief Executive Officer
KENNETH M. MARGOSSIAN March 28, 1994
Kenneth M. Margossian,
President and Chief Operating Officer
Principal Financial Officer:
JAMES D. RAPPOLI March 30, 1994
James D. Rappoli,
Financial Vice President and Treasurer
Principal Accounting Officer:
JOHN A. WHALEN March 28, 1994
John A. Whalen, Comptroller
A majority of the Board of Directors:
WILLIAM G. POIST March 30, 1994
William G. Poist, Director
JAMES D. RAPPOLI March 30, 1994
James D. Rappoli, Director
KENNETH M. MARGOSSIAN March 28, 1994
Kenneth M. Margossian, Director