SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
__x__ Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1995
OR
_____ Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from to
COMMISSION FILE NUMBER 0-10007
COLONIAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1558100
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
40 Market Street, Lowell, Massachusetts 01852
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (508) 458-3171
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $3.33 par value
(Title of Class)
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 by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
__x__
The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 1, 1996 was $182,187,962.
The number of shares of the registrant's common stock outstanding
as of March 1, 1996 was 8,376,458.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the annual report to stockholders for the year ended
December 31, 1995 are incorporated by reference into Part II and
Part IV. Portions of the proxy statement for the 1996 annual
meeting of stockholders are incorporated by reference into Part III.
COLONIAL GAS COMPANY
FORM 10-K ANNUAL REPORT - 1995
TABLE OF CONTENTS
PART I
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant's Common Stock and
Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain
Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement
Schedules, and Reports on Form 8-K
PART I
Item 1. Business
THE COMPANY
Colonial Gas Company ("Colonial" or the "Company"), a
Massachusetts corporation formed in 1849, is primarily a
regulated natural gas distribution utility. The Company serves
over 141,000 utility customers in 24 municipalities located
northwest of Boston and on Cape Cod. Through its wholly-owned
energy trucking subsidiary, Transgas Inc. ("Transgas"), the
Company also provides over-the-road transportation of liquefied
natural gas ("LNG"), propane and other commodities.
The Company's corporate office is located at 40 Market
Street, Lowell, Massachusetts 01852. The telephone number is
(508) 458-3171.
The Company's combined natural gas distribution service
areas in the Merrimack Valley region northwest of Boston and on
Cape Cod cover approximately 622 square miles with a year-round
population of approximately 500,000, which increases by
approximately 350,000 during the summer tourist season on Cape
Cod. The Company is serving approximately 49% of potential
customers in its service areas. Of its 141,399 customers,
approximately 90% are residential accounts. The Company added
4,723 firm sales customers in 1995. The Company's growth has been based
on new residential construction in its service areas and
conversions to gas from other energy sources for existing homes
and businesses. Of the total number of new customers in 1995, 44%
converted from other fuels and 56% were new construction.
The Company's 1995 consolidated operating revenues were
derived 62% from firm gas sales to residential customers, 32%
from firm gas sales to commercial and industrial customers, 2%
from non-firm customers, 1% from firm transportation
customers and 3% from other revenues. For the year 1995, the
Company sold 18,560 MMcf of gas, of which 11,333 MMcf was sold
in the Merrimack Valley area and 7,227 MMcf in the Cape Cod area.
At December 31, 1995, 90% of the Company's residential customers
used gas as their source of heating fuel. The demand for the products
and services furnished by the Company is to a great extent seasonal,
being heaviest in the colder months.
At December 31, 1995, the Company had 478 full-time-
equivalent employees. Of those employees, 95 are covered by a
collective bargaining agreement with the United Steelworkers of
America which expires in April 2001 and 77 are covered by a
separate collective bargaining agreement with the United
Steelworkers of America which expires in February 2000. In
addition, Transgas employs 80 full-time employees of which 62 are
covered by a collective bargaining agreement with the
International Brotherhood of Teamsters which expires in June 1996.
GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES
Pursuant to Federal Energy Regulatory Commission ("FERC")
Order 636 and other FERC directives of recent years, the Company
and other local distribution companies ("LDCs") have now been
responsible for managing their own supply, pipeline
transportation capacity and storage resources for two full years.
In order to meet its customers' evolving needs at the lowest
reasonable cost, the goal of the Company has been to compile a
reliable, flexible and diverse portfolio of resources. As
discussed below under "State Regulation", the Company is in the
process of exploring ways of further unbundling its services to
provide a greater number of its customers with real opportunities
to purchase gas, which would still be distributed by the Company,
from alternative suppliers. The further unbundling of services would likely
entail adjustments in the Company's gas portfolio, although those
adjustments cannot be precisely determined at this time.
Generally, the Company pays negotiated rates for pipeline-
transported supplies and tariffed rates (approved by FERC) for
pipeline transportation and storage services. The Company
continues to meet its customers' supply requirements through a
combination of firm and spot purchases of pipeline-transported
supply, supply from underground storage, liquefied natural gas
("LNG") and propane. The following table shows the Company's
sources of firm supply available to meet its gas requirements and
the actual components of gas sendout for each of the last three years:
1995 1994 1993
MMcf(a) % MMcf(a) % MMcf(a) %
Firm Pipeline Transpor-
tation Capacity 30,630 28,993 26,239
Firm Gas Supply Sources(b)
Contracts for Pipeline-
Transported Gas(c) 18,725 70 19,631 72 19,731 74
LNG contracts 4,150 15 4,050 15 3,450 13
Storage inventory at
January 1(d) 3,956 15 3,587 13 3,417 13
Total Available 26,831 100 27,268 100 26,598 100
Gas Sendout
Pipeline-Transported
Supplies (e) 14,659 72 14,392 72 14,982 74
Supplemental Supplies:
Underground storage 3,270 16 3,112 16 3,501 17
LNG-as liquid 844 4 1,129 6 907 4
LNG-as vapor 1,574 8 1,236 6 915 5
Propane-air 8 - 25 - 8 -
Total Sendout 20,355 100 19,894 100 20,313 100
Ratio of available firm supply
to sendout (f) 1.32 1.37 1.31
(a) The term "MMcf" means one million cubic feet of vapor
or vapor equivalent.
(b) 1994 and 1993 reflect the Company's portfolio of firm
supply sources subsequent to FERC Order 636, calculated on
an annualized basis.
(c) The Company's firm supply purchase contracts are
structured to enable the Company to purchase volumes
equivalent to the total amount of its firm pipeline
transportation capacity to its distribution system during
the winter or peak demand season, but less than total firm
pipeline capacity during the off-peak season. Accordingly,
the total supply purchase contract volumes shown are less
than total firm transportation capacity for 1995, 1994 and
1993.
(d) The Company's storage inventory is drawn down and
refilled throughout the year depending upon the availability
and price of gas sources and upon the requirements of the
Company's customers. The Company's current level of
underground storage capacity is 4,645 MMcf.
(e) Includes firm and spot sendout volumes.
(f) The Company's ratio of available firm supply to sendout
was determined by dividing total firm gas supply sources by
total sendout.
Based upon its firm contracts for transportation, storage,
supply and other supplemental sources, the Company expects to be
able to meet the gas requirements of its firm sales customers for
the foreseeable future. Additional information concerning the
Company's firm resources of gas transportation, storage and
supply for each of its two service territories is set forth
below.
Merrimack Valley Service Area Resources
The Company maintains three firm contracts with the
Tennessee Gas Pipeline Company ("Tennessee") for the
transportation of supply to the Merrimack Valley service area.
The first contract provides for the firm transportation of 25,196
Mcf per day and is in effect until November 1, 2000 and continues
year to year thereafter unless terminated upon twelve months
prior written notice. The second firm transportation contract is
for 17,300 Mcf per day and is in effect until April 1, 2013 and
continues year to year thereafter unless terminated upon twelve
months prior written notice. During the off-peak season (April 1
through October 31), the Company assigns this 17,300 Mcf per day
of transportation capacity and associated supply to an
independently owned, 84 MW cogeneration facility located in the
Company's service territory. The third firm transportation
service contract with Tennessee is utilized in conjunction with
the Iroquois Pipeline System ("Iroquois") to deliver 6,000 Mcf
per day of Canadian supplies to the Company. Of this amount,
4,000 Mcf per day can also be transported to the Cape Cod service
area on a firm basis via the Algonquin Gas Transmission Company
("Algonquin") system. This third Tennessee contract, as well as
the related Iroquois contract, is in effect until November 1,
2011 and continues year to year thereafter unless terminated by
twelve months prior written notice.
In addition, the Company contracts for underground storage
service which, in conjunction with two Tennessee firm
transportation contracts, provide an additional 23,587 Mcf per
day of firm deliverability. The Company has storage capacity of
2,000,000 Mcf and firm deliverability of 16,083 Mcf per day under
its contract with the National Fuel Gas Supply Corporation,
formerly known as Penn-York Energy Corporation, ("National
Fuel"). In order to deliver these volumes, the Company has a firm
transportation contract with Tennessee for 16,083 Mcf per day.
Both the National Fuel and Tennessee contracts expire on March
31, 1996 and continue from year to year thereafter unless
terminated upon twelve months prior written notice. The Company
also has a contract with Tennessee for an additional 1,095,830
Mcf of storage space and 14,150 Mcf per day of withdrawal
capacity. In order to deliver these volumes, the Company has a
separate firm transportation contract with Tennessee for 7,504
Mcf per day. Both of these contracts continue until November 1,
2000 and from year to year thereafter unless terminated upon
twelve months prior written notice.
The Company's portfolio of firm pipeline-transported supply
for the Merrimack Valley area consists principally of four
purchase contracts for domestically-produced gas and one purchase
contract for Canadian-produced gas. These individually negotiated
contracts provide an aggregate of up to 48,496 Mcf per day of
firm supply during the peak season (November 1 through March 31).
The Massachusetts Department of Public Utilities ("DPU") approved
all of these supply contracts in 1994. In 1995, the Company
renegotiated one of these supply contracts. This amended
contract, which is expected to be approved by the DPU in 1996,
features lower reservation fees and increased flexibility while
maintaining the same level of peak season daily volume capacity.
During the peak season, pipeline-transported supply and
storage volumes are supplemented by the Company's on-system LNG
facility in Tewksbury, Massachusetts which provides up to 60,000
Mcf per day of vaporization capability and can store up to
1,000,000 Mcf at any given time. The Company also owns facilities
for the storage of approximately 158,000 Mcf natural gas
equivalent of propane which can be vaporized, mixed with air and
injected into the Merrimack Valley service area distribution
system at a rate of up to approximately 26,000 Mcf per day.
Cape Cod Service Area Resources
The Cape Cod service area is directly served by the
Algonquin pipeline system. The Company maintains fourteen firm
transportation agreements with Algonquin which provide an
aggregate capacity of approximately 45,368 Mcf per day. Each of
these fourteen Algonquin transportation arrangements are in
effect until either October 31, 2012 or October 31, 2013 and
continues year to year thereafter unless terminated upon twelve
months prior written notice. Since the Company's firm supplies
and storage services are not directly connected to Algonquin,
these services are supported by multiple firm transportation and
storage services on seven different upstream pipelines.
The Company's portfolio of pipeline-transported supplies for
the Cape Cod area consists principally of three purchase
contracts for domestically-produced gas. These individually
negotiated contracts provide an aggregate of up to 20,918 Mcf per
day of firm supply during the peak season (November 1 through
March 31). The DPU approved all of these supply contracts in
1994. The Company also has the ability to deliver up to 4,000 Mcf
per day of Canadian supplies to the Cape Cod service area on a
firm basis utilizing the transportation contracted for the
Merrimack Valley service area.
In addition to the contracts for pipeline-transported
supply, the Company has five storage contracts to service the
Cape Cod area, two of which are on the Texas Eastern Transmission
Company ("Texas Eastern") system and three of which are on the
CNG Transmission Corporation ("CNG") system. The Company has
contracted for underground natural gas storage capacity of
approximately 493,486 Mcf with Texas Eastern through the 2012-
2013 heating season. The associated firm transportation capacity
from Texas Eastern storage provides deliverability of up to 6,969
Mcf per day. The Company has contracted with CNG for underground
natural gas storage capacity of approximately 823,529 Mcf through
March 31, 2006 and 232,600 Mcf through March 31, 2012. The
associated firm transportation capacity from CNG storage provides
deliverability of up to 6,342 Mcf per day and Colonial has other
arrangements in place by which it may increase that firm
deliverability by 6,999 Mcf per day.
The Company also leases, through 1998, and operates
facilities in the Cape Cod service area for the storage of
approximately 180,000 Mcf of LNG. Through April 1996, the Company
has contracted with a subsidiary of Algonquin for the additional
annual storage capacity of approximately 42,000 Mcf of LNG in a
Providence, Rhode Island facility.
REGULATORY MATTERS
Federal Regulation
As discussed above, pursuant to Order 636 and other FERC
directives, the Company is presently responsible for the procurement of
the gas supplies necessary to meet its load requirements, and
for contracting for interstate transportation and storage
services. As of this date, these FERC deregulation directives
have not materially affected the Company's results of operations
and the Company believes that they will continue not to affect
materially its results of operations.
State Regulation
The Company is a public utility subject to the jurisdiction
and regulatory authority of the DPU with respect to its rates as
well as to the issuance of securities, franchise territory and
other related matters. Under the present regulatory system, the
DPU permits Massachusetts gas companies to utilize a cost of gas
adjustment clause ("CGAC") which enables them to pass on to their
customers, via their monthly gas bill, changes in the cost of
procuring and delivering their gas. Included within the DPU-
approved costs passed on to customers through the CGAC are FERC-
ordered refunds and charges from interstate gas pipelines,
environmental response costs and demand side management ("DSM")
program costs. Changes in non-gas or base rates charged to
customers are subject to approval by the DPU after formal
proceedings.
The environmental response costs recovered through the CGAC
relate to the Company's former gas manufacturing operations, as
described under "Environmental Matters". Transition costs relate
to FERC approved pipeline charges resulting from Order 636. In addition
to full recovery of the installed conservation measures, the Company is
allowed to recover the margins lost as a result of the DSM programs
and financial incentives based on the attainment of performance
goals. In September 1995, the Company received approval from the
DPU to recover lost margins and financial incentives associated
with the residential DSM programs. Based on this approval, the
Company recorded as operating revenues $900,000 of lost margins
and $220,000 of financial incentives as revenue in 1995. The
Company anticipates recording as operating revenues approximately
$1 million of lost margins and incentives associated with the
residential and commercial DSM programs in 1996.
In 1993, the Company applied for what was only its second
base rate increase request since 1984. Effective November 1,
1993, the Company received DPU approval of a settlement
agreement that called for a base rate increase designed to
produce additional revenues of $6.7 million or 4.9% annually. In
addition to this rate increase, the DPU approved a proposal to
expand the eligibility criteria for Colonial's discount rate for
low-income residential heating customers and allowed the Company
to retain 10% of the revenues generated from releasing the
Company's interstate pipeline transportation capacity to third
parties above an initial threshold of $2,500,000. In 1995, the
Company received $2,818,000 of capacity release revenue,
$2,786,000 of which was credited back to firm customers and
$32,000 of which was retained by the Company.
In 1993, Colonial began unbundling its firm sales service
to commercial and industrial customers by offering a tariffed
firm transportation-only service. Pursuant to this service, a
customer procures its own gas supply and contracts with Colonial
for firm transportation service through Colonial's distribution
system. As of December 31, 1995, 11 customers had opted for
tariffed firm transportation service, representing less than 2%
of the Company's annual firm load.
Two 1994 DPU industry-wide proceedings may result in the
further unbundling and deregulation of the Company's business.
One of those proceedings addressed incentive or performance
based regulation. In a ruling issued in February 1995, the
DPU indicated that it has the authority to implement incentive
regulation and would be receptive to various types of
proposals. The other proceeding addressed interruptible transportation
(IT) and interruptible sales service on local distribution company
(LDC) systems, and the release of interstate pipeline capacity
by LDCs. In a ruling issued on February 14, 1996, the DPU directed
each LDC to prepare and file a new form IT contract. In this new
form contract, IT service must be unbundled from interruptible
sales service. The ruling also allows each LDC to retain 25% of
the respective profit margins earned from IT, interruptible sales
and capacity release transactions above an annual threshold level
adjusted on April 30th of each year. The Company is in the process of
preparing the new form IT contract while continuing to analyze other
unbundling and incentive regulation options which it could propose to
to the DPU as a means of benefiting its customers and shareholders.
COMPETITION
Massachusetts law protects gas companies from competition
with respect to pipeline distribution of gas within its franchise
areas by providing that, where a gas company exists in active
operation, no other person may lay pipe in the public ways
without the approval, after notice and hearing, of the municipal
authorities and the DPU. If a municipality desires to enter the
gas business, it must take certain procedural steps, including a
favorable vote by a majority of the voters in a city election or
two-thirds vote at each of two town meetings. In addition, the
municipality must purchase the property of any gas company
operating in the municipality (if the company elects to sell) to
the extent, and at such prices, as may be agreed upon; if no
agreement is reached, resolution will be determined by the DPU.
As discussed above under "State Regulation", the opportunity
already exists for commercial and industrial customers in the
Company's franchise areas to purchase gas supply and pipeline
transportation from entities other than the Company, and then
contract with Colonial for transportation-only service through
the Company's distribution system. The Company provides such
transportation-only service to commercial and industrial
customers on either a firm basis or an interruptible basis. As
also discussed above, the Company is evaluating ways to make
transportation-only service accessible to a greater number of
customers. While firm transportation service may displace firm
gas sales by the Company, this service assists qualifying
customers in obtaining the lowest possible gas costs while still
contributing to the profit margin of the Company. In general,
profit margins from interruptible sales and interruptible
transportation pass through to firm sales customers in the CGAC,
resulting in lower gas costs. Pursuant to the February 14, 1996
DPU ruling, the Company may now retain 25% of such profit margins
above an annual threshold level adjusted on Apil 30th of each year.
In addition although FERC has generally permitted larger
industrial users to obtain piped gas from other sources and by-
pass a utility's distribution system, the Company has not seen
nor does it believe that these FERC orders will have a material
adverse effect on its business, in part because large industrial
users are not a significant part of its customer base.
Fuel oil suppliers, electric utilities and propane suppliers
provide competition generally for residential, commercial and
industrial customers. Interruptible sales are generally in
competition with No. 6 fuel oil which most of the interruptible
customers are equipped to use. Lower prices of oil and other
fuels may adversely affect the Company's ability to retain or
attract customers. The Company's rates for bundled gas service
have remained generally competitive with the price of alternative
fuels, but the long-term impact of changes in fuel prices and
changes in state regulatory policies on the Company and its rates
cannot be predicted.
ENVIRONMENTAL MATTERS
The Company is subject to Federal and state laws and
regulations dealing with environmental protection. Compliance
with such environmental laws and regulations has resulted in
increased costs with respect to the Company's existing
operations.
Working with the Massachusetts Department of Environmental
Protection, the Company is engaged in site assessments and
evaluation of remedial options for contamination that has been
attributed to the Company's former gas manufacturing site and at
various related disposal sites. During 1990, the DPU ruled that
Colonial and eight other Massachusetts gas distribution
companies can recover environmental response costs related to
former gas manufacturing operations over a seven-year period,
without carrying costs, through the CGAC. Through December 31,
1995, the Company had incurred environmental response costs of
$10,418,000 of which $2,904,000 was for the former gas
manufacturing site and $7,514,000 for the related disposal
sites. The Company expects to continue incurring costs arising
from these environmental matters.
As of December 31, 1995, the Company has recorded on the
balance sheet a long-term liability of $2,300,000 representing
estimated future response costs for these sites based on the
Company's preferred methods of remediation, of which $1,700,000
relates to the gas manufacturing site. Based upon the DPU order
approving rate recovery of environmental response costs, a
regulatory asset of $2,300,000 has been recorded on the balance
sheet ("Unrecovered Environmental Costs Accrued"). Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
As of December 31, 1995, the Company had settled claims
relating to these matters with all liability insurers and other
known potentially responsible parties (PRP). In accordance with
the DPU order referred to above, half the costs incurred in
pursuing insurers and other PRP are recovered from the
ratepayers through the CGAC and half are initially borne by the
Company. Also, per this order, any insurance and other proceeds
are applied first to the Company's costs of pursuing recovery
from insurers and other PRP, with the remainder divided equally
between the ratepayers and shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Thousands) Response Costs Insurance and Other
Proceeds
Recovered Period Recorded as
from of Rate Returned Non-Operating
Year Incurred Customers Recovery to Income Net of
Customers Taxes
1988 $ 853 $ 732 1990-1997 - -
1989 4,031 3,455 1990-1997 - -
1990 639 457 1991-1998 - -
1991 374 213 1992-1999 $ 851 $ 525
1992 617 264 1993-2000 1,121 673
1993 1,226 350 1994-2001 469 290
1994 1,321 189 1995-2002 122 75
1995 1,357 - 1996-2003 - -
Total $10,418 $5,660 $2,563 $1,563
TRANSGAS INC.
Transgas primarily provides over-the-road transportation of
LNG, propane and other commodities. Transgas acts as a common and
contract carrier for approximately 55 commercial and gas utility
customers located in the eastern half of the United States.
Canadian over-the-road transportation services are also available
through CGI Transport Limited, which is a wholly-owned subsidiary
of Transgas. Transgas also provides a unique LNG portable
pipeline service, which permits gas utilities to provide
continuous supply of natural gas to communities while the
pipeline supply is temporarily interrupted during scheduled
maintenance, upgrading and recertification, or during emergency
interruption.
Transgas has both common and contract carrier authorization
issued by the Interstate Commerce Commission for its interstate
trucking activities. Transgas also maintains several intrastate
authorizations with various state public service commissions.
Transgas is subject to various regulations applicable to common
and contract carriers relating to safety and reporting matters,
but it may set its rates at negotiated levels.
Transgas had revenues of $7,576,000 in 1995. Approximately
54% of Transgas' revenue in 1995 was derived from transporting
Algerian LNG from the Distrigas import terminal, which is located
in Everett, Massachusetts. Transgas' revenues decreased
$4,490,000 or 37% compared to 1994 primarily due to the extremely
cold weather in the first quarter of 1994 which generated a
significant increase in demand for the truck transportation of
LNG and propane throughout the first three quarters of 1994.
Transgas provides over-the-road transportation services by
utilizing a fleet of 47 tractors. Transgas operates 62 trailers
which are specifically designed for the transportation of LNG and
other cryogenic liquids. Of those cryogenic transport trailers,
21 are leased to Transgas on a long-term basis. In addition,
Transgas has 24 trailers which are designed for the
transportation of propane. Of those propane transport trailers, 4
are leased to Transgas on a long-term basis. In addition to the
equipment described above, Transgas also has 15 trailers which
are designed for carrying portable LNG vaporizers, as well as 2
flat bed trailers and 2 van trailers.
Transgas competes with many other motor carriers engaged in
the transportation of various gases and other products. Transgas
believes, however, that it is the leading over-the-road
transporter of LNG due to the size of its fleet of specialized
cryogenic transport trailers.
Item 1A. Executive Officers of the Registrant.
The following table indicates the present executive officers
of the Company, their ages, the dates when their service with the
Company began and their respective positions with the Company.
Affiliated with
Name and Age Position with Company Company since
Frederic L. Putnam, Chairman and Senior 1953
Jr. (71) Executive Officer
Frederic L. Putnam, President and Chief 1975
III (50) Executive Officer
Charles W. Sawyer (50) Executive Vice President 1976
and Chief Operating Officer
Nickolas Stavropoulos Executive Vice President- 1979
(38) Finance, Marketing, and
Chief Financial Officer
John P. Harrington (53) Senior Vice President- 1966
Gas Supply and Assistant
to the President
Victor W. Baur (52) President-Transgas Inc. 1972
Dennis W. Carroll (49) Vice President and 1990
Treasurer
Charles A. Cook (43) Vice President and General 1978
Counsel
Mr. Putnam, Jr. has been Chairman of the Board of Directors
since 1981 and the Senior Executive Officer since February 1995
and before that the Chief Executive Officer since 1977. He has
also been a Director since 1973.
Mr. Putnam, III, the son of F.L. Putnam, Jr., has been
President and Chief Executive Officer since February 1995. He had
been President since May 1994. He had been Executive Vice
President and General Manager from April 1993 until May 1994 and
before that Vice President and General Manager from August 1989
until April 1993. He has also been a Director since November
1991.
Mr. Sawyer has been Executive Vice President and Chief
Operating Officer since February 1995. He had been Vice President
- - Operations since August 1989.
Mr. Stavropoulos has been Executive Vice President -
Finance, Marketing and Chief Financial Officer since February
1995. He had been Vice President - Finance and Chief Financial
Officer since August 1989. He has also been a Director since
February 1993.
Mr. Harrington has been Senior Vice President - Gas Supply
and Assistant to the President since February 1995. He had been
Vice President - Gas Supply since August 1989. He has also been a
Director since February 1993.
Mr. Baur has been President of Transgas Inc. since July
1990. He also became a Director in August 1993.
Mr. Carroll has been Vice President and Treasurer since
August 1990.
Mr. Cook has been Vice President and General Counsel since
July 1990.
These officers hold office until the next annual meeting of
the Board of Directors or until their successors are duly elected
and qualified, subject to earlier removal.
Item 2. Properties.
The Company has two principal operations centers and a
natural gas liquefaction and storage facility with approximately
1,000,000 Mcf of LNG storage capacity located in Tewksbury,
Massachusetts. The Company's gas production and storage
facilities, metering and regulation stations and operations
centers are generally located on land it owns.
A 175,000 Mcf LNG storage tank located on land owned by the
Company in South Yarmouth, Massachusetts is leased from an
unaffiliated company through 1998. The Company also has a lease
which expires in 2002 for office facilities in Lowell,
Massachusetts.
The Company's distribution mains of approximately 2,862
miles are located within public highways under franchises or
permits from state or municipal authorities, or on land owned by
others under easements or licenses from the owners. The Company's
first mortgage bonds are collateralized by utility property.
Management considers that the Company's properties are
adequate for the conduct of its business for the reasonably
foreseeable future.
Item 3. Legal Proceedings.
See Item 1, "Business--Environmental Matters" above, which
is incorporated herein.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of the Company's security
holders during the quarter ended December 31, 1995.
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's 1995 annual report to stockholders under the caption
"Shareholder Information" and under Note D of the "Notes to
Consolidated Financial Statements".
Item 6. Selected Financial Data.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's 1995 annual report to stockholders under the caption
"Selected Financial Data".
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's 1995 annual report to stockholders under the caption
"Management's Discussion and Analysis of Financial Condition and
Results of Operations".
Item 8. Financial Statements and Supplementary Data.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's 1995 annual report to stockholders under the following
captions: "Consolidated Statements of Income", "Consolidated
Balance Sheets", "Consolidated Statements of Cash Flows",
"Consolidated Statements of Common Equity", "Notes to
Consolidated Financial Statements", "Report of Independent
Certified Public Accountants" and "Shareholder Information".
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required to be reported hereunder for the
Company's Directors is incorporated by reference to the
information reported in the Company's Proxy Statement for its
1996 annual meeting of stockholders under the caption "Election
of Directors".
The information required to be reported hereunder for the
Executive Officers of the Registrant is incorporated by reference
to the information in Item 1A of this Form 10-K under the caption
"Executive Officers of the Registrant".
Item 11. Executive Compensation.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's Proxy Statement for its 1996 annual meeting of
stockholders under the captions "Executive Compensation" and
under the subheading "Directors' Compensation" of the caption
"Election of Directors".
Item 12. Security Ownership of Certain Beneficial Owners and
Management.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's Proxy Statement for its 1996 annual meeting of
stockholders under the caption "Security Ownership of Certain
Beneficial Owners and Management".
Item 13. Certain Relationships and Related Transactions.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's Proxy Statement for its 1996 annual meeting of
stockholders under the caption "Election of Directors".
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K.
(a) 1. Financial Statements The Consolidated Financial
Statements of the Company (including the Report of
Independent Certified Public Accountants) required to be
reported herein are incorporated by reference to the
information reported in the Company's 1995 annual report
to stockholders under the following captions:
"Consolidated Statements of Income", "Consolidated
Balance Sheets", "Consolidated Statements of Cash Flows",
"Consolidated Statements of Common Equity", "Notes to
Consolidated Financial Statements" and "Report of
Independent Certified Public Accountants".
2. Financial Statement Schedules The following
Financial Statement Schedules and report thereon are
filed as part of this Form 10-K on the pages indicated
below:
Schedule
Number Description
Report of Independent Certified Public
Accountants on Schedule
II Valuation and Qualifying Accounts for
the three years ended December 31, 1995
Schedules other than those listed above are either not required
or not applicable, or the required information is shown in the
financial statements or notes thereto. Columns omitted from
schedules filed have been omitted because the information is not
applicable.
3. List of Exhibits
Exhibit
Number Exhibit Reference
3a Restated Articles of Organization of Incorporated herein
Colonial Gas Company, dated April by reference.
19, 1989, as amended on July 16,
1992 and supplemented by a
certificate of vote of Directors
establishing a series of a class of
stock filed on November 30, 1993,
filed as Exhibit 3(a) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
3b By-Laws of Colonial Gas Company, as Incorporated herein
amended to date, filed as Exhibit by reference.
3(b) to the Registrant's Annual
Report on Form 10-K for the fiscal
year ended December 31, 1993.
4a Second Amended and Restated First Incorporated herein
Mortgage Indenture, dated as of June by reference.
1, 1992, filed as Exhibit 4(b) to
Form 10-Q of the Registrant for the
quarter ended June 30, 1992.
4b First Supplemental Indenture, dated Incorporated herein
as of June 15, 1992, filed as by reference.
Exhibit 4(c) to Form 10-Q of the
Registrant for the quarter ended
June 30, 1992.
4c Second Supplemental Indenture, Filed herewith as
executed on September 27, 1995, Exhibit 4c.
relating to the Secured Medium Term
Notes, Series A.
4d Amendment to Second Supplemental Filed herewith as
Indenture, dated as of October 12, Exhibit 4d.
1995, relating to the Secured Medium
Term Notes, Series A.
4e Credit Agreement for Colonial Gas Incorporated herein
Company, dated as of June 27, 1990, by reference.
filed as Exhibit 10(a) to Form 8-K
of the Registrant for the quarter
ended June 30, 1990, as amended on
December 24, 1991, filed as Exhibit
4(j) to Form 10-K of the Registrant
for the year ended December 31,
1991, as amended on July 27, 1993,
filed as Exhibit 4(a) to Form 10-Q
of the Registrant for the quarter
ended June 30, 1993, as amended on
June 16, 1994 filed as Exhibit 4(a)
to Form 10-Q of the Registrant for
the quarter ended June 30, 1994, as
amended on July 13, 1994 filed as
Exhibit (4b) to Form 10-Q of the
Registrant for the quarter ended
June 30, 1994.
4f Credit Agreement for Massachusetts Incorporated herein
Fuel Inventory Trust, dated as of by reference.
June 27, 1990, filed as Exhibit
10(b) to Form 8-K of the Registrant
for the quarter ended June 30, 1990,
as amended on July 27, 1993, filed
as Exhibit 4(b) to Form 10-Q of the
Registrant for the quarter ended
June 30, 1993, as amended on June
16, 1994 filed as Exhibit 4(c) to
Form 10-Q of the Registrant for the
quarter ended June 30, 1994, as
amended on July 13, 1994 filed as
Exhibit 4(d) to Form 10-Q of the
Registrant for the quarter ended
June 30, 1994.
4g Purchase Contract, dated as of June Incorporated herein
27, 1990 between Massachusetts Fuel by reference.
Inventory Trust acting by and
through its Trustee, Shawmut Bank,
N.A. and Colonial Gas Company, filed
as Exhibit 10(e) to Form 8-K of the
Registrant for quarter ended June
30, 1990.
4h Security Agreement and Assignment of Incorporated herein
Contracts, dated as of June 27, 1990 by reference.
made by Massachusetts Fuel Inventory
Trust in favor of The First National
Bank of Boston as Agent, for the
Ratable Benefit of the Secured
Parties Named Herein, filed as
Exhibit 10(c) to Form 8-K of the
Registrant for the quarter ended
June 30, 1990.
4i Trust Agreement, dated as of June Incorporated herein
22, 1990 between Colonial Gas by reference.
Company (as Trustor) and Shawmut
Bank, N.A. (as Trustee), filed as
Exhibit 10(d) to Form 8-K of the
Registrant for quarter ended June
30, 1990.
10a Service Agreement with Algonquin Gas Incorporated herein
Transmission Company, dated December by reference.
11, 1972, filed as Exhibit 13(n) to
Colonial Gas Energy System's
Registration Statement on Form S-1.
Commission File No. 2-54673.
10b Storage Service Agreement with Penn- Incorporated herein
York Energy Corporation, dated as of by reference.
December 21, 1984, filed as Exhibit
10(r) to the Registrant's Annual
Report on Form 10-K for the fiscal
year ended December 31, 1984.
10c Gas Transportation Contract for Firm Incorporated herein
Reserved Service with Iroquois, by reference.
dated February 7, 1991, filed as
Exhibit 10(v) to the Registrant's
Annual Report on Form 10-K for the
fiscal year ended December 31, 1990.
10d Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-E), dated June 1, 1993,
filed as Exhibit 10(p) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10e Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10(q) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10f Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10(r) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10g Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10(s) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10h Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-E), dated June 1, 1993,
filed as Exhibit 10(t) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10i Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10(u) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10j Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10(v) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10k Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule CDS), dated June 1, 1993,
filed as Exhibit 10(w) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10l Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated June 1, 1993,
filed as Exhibit 10(x) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10m Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FTS-8), dated June 1, 1993,
filed as Exhibit 10(y) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10n Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FTS-7), dated June 1, 1993,
filed as Exhibit 10(z) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10o Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated June 1, 1993,
filed as Exhibit 10(aa) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10p Service Agreement between Incorporated herein
Transcontinental Gas Pipe Line by reference.
Corporation and Colonial Gas Company
(under Rate Schedule FT), dated June
1, 1993, filed as Exhibit 10(ee) to
the Registrant's Annual Report on
Form 10-K for the fiscal year ended
December 31, 1993.
10q Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated June 1, 1993.
10r Firm Gas Transportation Agreement Incorporated herein
between Koch Gateway Pipeline by reference.
Company and Colonial Gas Company,
dated December 1, 1993, filed as
Exhibit 10(gg) to the Registrant's
Annual Report on Form 10-K for the
fiscal year ended December 31, 1993.
10s Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated August 1,
1993, filed as Exhibit 10(ll) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10t Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated September 1,
1993, filed as Exhibit 10(nn) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10u Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated September 1,
1993, filed as Exhibit 10(oo) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10v Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated September 1,
1993, filed as Exhibit 10(pp) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10w Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule FST-LG), dated October 1,
1993, filed as Exhibit 10(qq) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10x Service Agreement between CNG Incorporated herein
Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FTNN), dated October 1,
1993, filed as Exhibit 10(rr) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10y Service Agreement between CNG Incorporated herein
Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule GSS), dated October 1,
1993, filed as Exhibit 10(ss) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10z Service Agreements between CNG Incorporated herein
Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule GSS-II), dated September
30, 1993, filed as Exhibit 10(tt) to
the Registrant's Annual Report on
Form 10-K for the fiscal year ended
December 31, 1993.
10aa Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated October 1,
1993, filed as Exhibit 10(uu) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10bb Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated September 1,
1993, filed as Exhibit 10(vv) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10cc Service Agreement between National Incorporated herein
Fuel Gas Supply Corporation and by reference.
Colonial Gas Company (under Rate
Schedule EFT), dated October 28,
1993, filed as Exhibit 10(ww) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10dd Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated September 1,
1993, filed as Exhibit 10(xx) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10ee Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AIT-1), dated September 15,
1993, filed as Exhibit 10(yy) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10ff Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated October 1,
1993, filed as Exhibit 10(zz) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10gg Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated August 18,
1994, filed as Exhibit 10(kk) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10hh Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FSS-1), dated August 29,
1994, filed as Exhibit 10(ll) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10ii Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule CDS), dated August 29,
1994, filed as Exhibit 10(mm) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10jj Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule CDS), dated August 29,
1994, filed as Exhibit 10(nn) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10kk Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule SS-1), dated November 30,
1994, filed as Exhibit 10(oo) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10ll Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FSS-1), dated November 30,
1994, filed as Exhibit 10(pp) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10mm Letter Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company, regarding
transfer of transportation
entitlements, dated March 28, 1994,
filed as Exhibit 10(qq) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10nn Capacity Release Umbrella Agreement Incorporated herein
between Algonquin Gas Transmission by reference.
Company and Colonial Gas Company
(under Rate Schedules AFT-1 and AFT-
1S), dated September 14, 1994, filed
as Exhibit 10(rr) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10oo Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10(ss) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10pp Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10(tt) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
10qq Firm Natural Gas Transportation Filed herewith as
Agreement between Tennessee Gas Exhibit 10qq.
Pipeline Company and Colonial Gas
Company (under Rate Schedule NET-
Northeast), dated August 1, 1995.
10rr Gas Transportation Agreement between Filed herewith as
Tennessee Gas Pipeline Company and Exhibit 10rr.
Colonial Gas Company (under Rate
Schedule FT-A), dated June 1, 1995.
10ss Amendment No. 1 (dated July 1, 1995) Filed herewith as
to Gas Storage Contract between Exhibit 10ss.
Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate
Schedule FS), dated December 1, 1994
(which superseded contract dated
September 1, 1993).
10tt Amendment to Gas Transportation Filed herewith as
Contract for Firm Reserved Service Exhibit 10tt.
with Iroquois Gas Transmission
System, L.P., dated September 1,
1995.
10uu Service Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10uu.
Colonial Gas Company (under Rate
Schedule AFT-1), dated December 1,
1995.
10vv Lease Agreement, dated as of May 1, Incorporated herein
1982, with Olde Market House by reference.
Associates of Lowell, filed as
Exhibit 10(y) to the Registrant's
Annual Report on Form 10-K for the
fiscal year ended December 31, 1982.
10ww Lease of Equipment from The National Incorporated herein
Shawmut Bank of Boston (now Shawmut, by reference.
Bank N.A.) as Trustee, as Lessor
dated as of May 1, 1973, filed as
Exhibit 13(c) to Colonial Gas Energy
System's Registration Statement on
Form S-1. Commission File No. 2-
54673.
10xx Form Employment Agreement for Incorporated herein
corporate officers, filed as Exhibit by reference.
10(kk) to the Registrant's Annual
Report on Form 10-K for the fiscal
year ended December 31, 1992.
10yy Rate increase deferral incentive Incorporated herein
policy, dated January 1, 1995, filed by reference.
as Exhibit 10(xx) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1994.
13a Those portions of the 1995 Annual Filed herewith as
Report to Stockholders which have Exhibit 13a.
been incorporated by reference in
Part II Items 5 - 8 and Part IV Item
14 part a 1.
21a Subsidiaries of the Registrant. Filed herewith as
Exhibit 21a.
23a Consent of Independent Certified Filed herewith as
Public Accountants. Exhibit 23a.
____________________
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
Exhibits 10xx and 10yy above are management contracts or
compensatory plans or arrangements in which the executive
officers of the Company participate.
(b) Reports on Form 8-K.
None
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS ON SCHEDULE
To the Shareholders of
Colonial Gas Company
In connection with our audit of the consolidated financial
statements of Colonial Gas Company and subsidiaries referred
to in our report dated January 17, 1996, which is included
in the 1995 Annual Report to Stockholders and incorporated
by reference in Part II of this Form 10-K, we have also
audited the schedule listed at Part IV, Item 14(a)2. In our
opinion, this schedule presents fairly, in all material
respects, the information required to be set forth therein.
GRANT THORNTON LLP
Boston, Massachusetts
January 17, 1996
SCHEDULE II
COLONIAL GAS COMPANY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Three Years Ended December 31, 1995
(In Thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE CHARGED
AT BEGIN- TO COSTS BALANCE AT
NING OF AND END OF
DESCRIPTION PERIOD EXPENSES DEDUCTIONS PERIOD
For the Year Ended December 31, 1995
Reserve for $1,670 $1,821 $1,286 (1) $2,205
uncollectible accounts
Reserve for insurance $ 527 $ 431 $ 324 $ 634
claims
For the Year Ended December 31, 1994
Reserve for $1,682 $1,803 $1,815 (1) $1,670
uncollectible accounts
Reserve for insurance $ 598 $ 494 $ 565 $ 527
claims
For the Year Ended December 31, 1993
Reserve for $1,187 $2,101 $1,606 (1) $1,682
uncollectible accounts
Reserve for insurance $ 548 $ 616 $ 566 $ 598
claims
(1) Accounts charged off, net of collections.
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.
COLONIAL GAS COMPANY Date
By s/F.L. Putnam March 15, 1996
F.L. Putnam, Jr., Chairman
of the Board of Directors
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.
Signature Title Date
F.L. Putnam, Jr. Senior Executive Officer, March 15, 1996
Director
Nickolas Stavropoulos Executive Vice President - March 15, 1996
Finance, Marketing and
Chief Financial Officer,
Director (Principal
Financial Officer)
D.W. Carroll Vice President and March 15, 1996
Treasurer (Principal
Accounting Officer
V.W. Baur Director March 15, 1996
A.C. Dudley Director March 15, 1996
J.P. Harrington Director March 15, 1996
H.C. Homeyer Director March 15, 1996
R.L. Hull Director March 15, 1996
D.H. LeVan, Jr. Director March 15, 1996
K.R. Lydecker Director March 15, 1996
F.L. Putnam, III President and Chief March 15, 1996
Executive Officer,
Director
J.F. Reilly, Jr. Director March 15, 1996
A.B. Sides, Jr. Director March 15, 1996
M.M. Stapleton Director March 15, 1996
C.O. Swanson Director March 15, 1996
G.E. Wik Director March 15, 1996
[EXHIBIT 4c TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
COLONIAL GAS COMPANY
TO
THE FIRST NATIONAL BANK OF BOSTON,
Trustee
_______________
Second Supplemental Indenture
Dated as of August 1, 1995
to Second Amended and
Restated First Mortgage Indenture
Additional Issue (Secured Medium Term Notes, Series A) $75,000,000
COLONIAL GAS COMPANY
Second Supplemental Indenture
dated as of August 1, 1995 to Second
Amended and Restated First Mortgage Indenture
The above Supplemental Indenture was filed for recordation
in Massachusetts as follows:
Location Date Reference
Secretary of the Documents Nos.
Commonwealth Sept. 27, 1995 340818 and 340819
Barnstable Instrument No.
County Sept. 27, 1995 --, Book 9859,
Page 297
Barnstable County, Document No. 648544,
Land Registration Sept. 27, 1995 Certificates of
Division Title Nos. _____,
_____, and _____
Middlesex County, Instrument No.
North Division Sept. 27, 1995 42815, Book --,
Page --
Middlesex County, Instrument No.
South Division Sept. 27, 1995 685, Book --,
Page --
Instrument No.
Plymouth Sept. 27, 1995 82825, Book 13854,
Page 222
THIS SUPPLEMENTAL INDENTURE, dated as of August 1, 1995
(hereinafter referred to as this "Supplemental Indenture" or this
"Instrument"), made and entered into by and between Colonial Gas
Company (formerly named "Lowell Gas Company"), a corporation duly
organized and existing under the laws of The Commonwealth of
Massachusetts, having its principal place of business at 40
Market Street, Lowell, Massachusetts (hereinafter referred to as
the "Company"), and The First National Bank of Boston, a national
banking association, having its principal place of business at
100 Federal Street, Boston, Massachusetts, as successor Trustee
(hereinafter referred to, together with its successors hereunder,
as the "Trustee") under the Second Amended and Restated First
Mortgage Indenture dated as of June 15, 1992, as supplemented by
the First Supplemental Indenture dated as of June 15, 1992 (as so
supplemented, the "Indenture"), which amends, restates and
supplements the Amended and Restated First Mortgage Indenture
dated as of July 1, 1981 from the Company to State Street Bank
and Trust Company, as supplemented by the First to Eighth
Supplemental Indentures thereto, inclusive, which amended,
restated and supplemented the First Mortgage Indenture and Deed
of Trust dated as of June 1, 1951 from Lowell Gas Company to
State Street Bank and Trust Company, as supplemented by the First
to Twenty-second Supplemental Indentures thereto, inclusive, and
the Indenture of Trust and First Mortgage dated as of April 1,
1950 from Cape Cod Gas Company (which has been merged into and
with the Company) to State Street Bank and Trust Company, as
supplemented by the First to Twenty-fifth Supplemental
Indentures, thereto, inclusive.
WHEREAS, the Company has heretofore duly executed and
delivered to the Trustee the Indenture to which this instrument
is supplemental, whereby substantially all the properties of the
Company used by it in its gas business, whether then owned or
thereafter acquired, with certain exceptions and reservations
fully set forth in the Indenture, were given, granted, bargained,
sold, transferred, assigned, pledged, mortgaged and conveyed to
the Trustee, its successors and assigns, in trust upon the terms
and conditions set forth therein to secure bonds of the Company
issued and to be issued thereunder (the "Bonds"), and for other
purposes more particularly specified therein; and
WHEREAS, in order to comply with the provisions of sections
2.02, 3.01(g) and 4.07 of the Indenture, it is desirable and the
Company is required and has duly and lawfully determined, at the
request of the Trustee, to execute and deliver this instrument
for the purpose of complying with said provisions; and
WHEREAS, for the protection of the holders of the Bonds it
is desirable to add certain covenants to the covenants of the
Indenture; and;
WHEREAS, it is necessary, desirable and not inconsistent
with the security and protection intended to be conferred upon
the Trustee and the holders of the Bonds to make certain
provisions in this instrument in regard to matters arising under
the Indenture; and
WHEREAS, Bonds in the principal amounts specified below have
heretofore been issued under and in accordance with the terms of
the Indenture (or Prior Indentures, as defined in the Indenture)
as separate series described or designated as hereinafter
specified, of which the respective amounts specified below were
outstanding on July 31, 1995:
Principal Amount Principal
Authorized and Amount
Designation Issued Outstanding
First Mortgage Bonds, $12,000,000 $ 6,000,000
Series CD
First Mortgage Bonds, $15,000,000 $15,000,000
Series CE
First Mortgage Bonds, $20,000,000 $16,363,636
Series CF
First Mortgage Bonds, $20,000,000 $20,000,000
Series CG
First Mortgage Bonds, $25,000,000 $25,000,000
Series CH
and the Company now proposes to issue up to $75,000,000 in
aggregate principal amount of additional First Mortgage Bonds
designated Secured Medium Term Notes, Series A (herein referred
to as the "Series A Notes") under the Indenture, which Bonds are
to be further designated and described, as to dates, maturities,
interest rates, sinking funds, denominations and redemption and
call provisions, in such Series A Notes which the Company may
issue from time to time, each in the form hereinafter set forth
(and the Trustee hereby confirms its approval, previously given
prior to the certification of any of said additional Bonds, of
the form and designation thereof so specified); and
WHEREAS, this Supplemental Indenture has been duly
authorized by resolution of the Board of Directors of the
Company, as required by section 3.01(b) of the Indenture, and the
use of terms and expressions herein is in accordance with
definitions, uses and constructions contained in the Indenture;
and
WHEREAS, the Series A Notes to be issued under the Indenture
are to be substantially in the following form:
(Form of Series A Note)
No. ____-____ COLONIAL GAS COMPANY $____________
Secured Medium Term Note, Series A
Due ________ ___, _____
COLONIAL GAS COMPANY, a Massachusetts corporation
(hereinafter, with its successors and assigns, as defined in the
Indenture mentioned below, generally called the "Company"), for
value received, hereby promises to pay to _____________________
or registered assigns, on ________ ___, _____ (or earlier as
hereinafter referred to), the principal sum of
_____________________________________ dollars ($__________) in
lawful money of the United States of America, and to pay interest
thereon (computed on the basis of a 360-day year of twelve 30-day
months), in like lawful money, from the date hereof, at the rate
of ______________________ percent (______%) per annum,
semi-annually on February 15 and August 15 of each year and at
maturity, until the principal hereof shall become due and
payable. The Company agrees to pay on demand interest on any
overdue principal (including any overdue prepayment of principal)
and premium, if any, at the rate of ____________________ percent
(_____%) per annum and, to the extent permitted by law, interest
on any overdue installment of interest at the rate at which such
overdue installment was computed according to the terms hereof.
The principal of, premium, if any, and interest hereof and hereon
will be paid at the principal corporate trust office in Canton,
Massachusetts of The First National Bank of Boston (hereinafter,
with its successors and predecessors as defined in said
Indenture, generally called the "Trustee") or at the principal
office of its successor in the trust created by said Indenture
or, at the option of the registered owner hereof, at such other
office or agency of the Trustee or of the Company maintained by
it for the purpose in the Burough of Manhattan, The City of New
York, New York, or such other place as may be designated for the
purpose pursuant to the provisions of said Indenture.
This Note is one of a duly authorized issue of First
Mortgage Bonds of the Company (the "Bonds") issued or to be
issued in one or more series, the series of which this Note is
one being designated Secured Medium Term Notes, Series A (herein
generally referred to as the "Series A Notes"). The Series A
Notes may be issued from time to time in various principal
amounts and may mature at different times, may bear interest at
different rates, may have different sinking fund provisions, may
be in different denominations, may be subject to different
redemption or call provisions and may otherwise vary.
This Note is a Global Note within the
meaning of the Indenture and is registered in the name of The
Depository Trust Company, or its nominee, as depositary. This
Global Note is exchangeable for Series A Notes, registered in
the name of a person other than such depositary or its nominee
only in the limited circumstances described in the Indenture,
and no transfer of this Note (other than the transfer of this
Note as a whole by such depositary to its nominee or by such
nominee to such depositary or another nominee of such depositary)
may be registered except in such limited circumstances.
Unless this Note is presented by an authorized representative of
The Depository Trust Company to the issuer or its agent for
registration of transfer, exchange or payment, and any
certificate issued is registered in the name of Cede & Co. or
such other name as requested by an authorized representative of
The Depository Trust Company and any payment hereon is made to
Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR
OTHERWISE BY OR TO ANY PERSON IS WRONGFUL since the registered
owner hereof, Cede & Co., has an interest herein.
All Bonds of all series and forms are issued or to be issued
under and secured by a certain Second Amended and Restated First
Mortgage Indenture dated as of June 15, 1992, as supplemented by
the First and Second Supplemental Indentures, inclusive, executed
counterparts of which are on file with the Trustee and may be
examined at its principal corporate trust office in Canton,
Massachusetts. Said Second Amended and Restated First Mortgage
Indenture, as amended and so supplemented, is herein generally
called the Indenture. Reference is made to the Indenture for a
description of Bonds outstanding under the Indenture as of
particular dates, including Prior Series Bonds as defined in the
Indenture, for a description of the property mortgaged and
pledged to the Trustee as security for Bonds, for a statement of
the nature and extent of the security, the terms and conditions
upon which Bonds have been, are or are to be issued and secured,
the rights and remedies under the Indenture of the holders of all
of said Bonds, and the rights and obligations under the Indenture
of the Company and of the Trustee, and for the definitions of
certain terms used but not defined in this Note; but neither the
foregoing reference to the Indenture, nor any provision of this
Note or of the Indenture, shall affect or impair the obligation
of the Company, which is absolute, unconditional and unalterable,
to pay, at the stated or accelerated maturities herein provided,
the principal of and premium, if any, and interest on this Note
as herein provided. By the terms of the Indenture, the Bonds to
be secured thereby are issuable to an unlimited (except as
provided in said Indenture) aggregate principal amount, in series
which may vary as to date, amount, date of maturity, rate of
interest and in other respects as in the Indenture provided.
In certain events, on the conditions, in the manner, to the
extent and with the effect set forth in the Indenture,
(1) the principal of this Note may be declared and/or
may become due and payable before the stated maturity
hereof, together with the interest accrued hereon;
(2) the Company and the Trustee may make modifications
or alterations of the provisions of the Indenture and of
this Note with the consent of the holders of not less than
66 2/3% in principal amount of the Bonds outstanding under the
Indenture, including not less than 66 2/3% in principal amount
of the Bonds of any series or sub-series affected in any
manner or to any extent differing from that in or to which
the Bonds of any other series or sub-series are affected;
provided, however, that no such alteration or modification
shall, without the consent of the registered owner of this
Note, (a) impair the obligation of the Company in respect of
the principal of or premium, if any, or interest on this
Note, or extend the maturity hereof or change the rate or
extend the time of payment of interest hereon or modify the
terms of payment of such principal, premium, if any, or
interest, or (b) permit the creation of any lien prior to or
on a parity with the lien of the Indenture, except as
expressly authorized by the Indenture, or (c) alter the
percentages of the principal amount of Bonds required to
declare the principal of and interest accrued on all Bonds
outstanding immediately due and payable as a result of a
default under the Indenture or to annul such declaration, or
(d) reduce the percentage of the principal amount of Bonds
with the consent of the holders of which modifications or
alterations may be made as aforesaid;
(3) the holders of not less than 66 2/3% in principal
amount of the Bonds at the time outstanding under the
Indenture, including not less than 66 2/3% in principal amount
of the Bonds of any series or sub-series affected by the
waiver in a manner different from that of any other series
or sub-series, may waive any existing default under the
Indenture and the consequences of any such default, except a
default in the payment of the principal of, premium, if any,
or interest on any of the Bonds, and except a default
arising from the creation of any lien prior to or on a
parity with the lien of the Indenture;
(4) upon payment of charges and compliance with other
conditions as provided in the Indenture, the Series A Notes
are exchangeable, at the principal corporate trust office of
the Trustee and at such other offices or agencies of the
Trustee or of the Company as may be designated for the
purpose, for like aggregate principal amounts of Series A
Notes in authorized denominations; and this Note is
transferable on books kept by the Company at said office of
the Trustee and at such other offices or agencies, upon
surrender and cancellation hereof at any such office or
agency, duly endorsed or accompanied by a duly executed
instrument of transfer, and thereupon a new fully registered
Series A Note or Notes for a like aggregate principal amount
will be issued to the transferee or transferees in exchange
for this Note; and
(5) the Series A Notes (i) are subject to redemption
in whole or in part at any time prior to maturity if through
the application of eminent domain moneys or the proceeds of
insurance arising from loss or casualty, as specified in the
Indenture, at the principal amount thereof, and (ii) to the
extent specified in the attached table, if any, are subject
to redemption, in whole or in part, at any time prior to
maturity, at the option of the Company, on and after the
initial redemption date specified in the attached table, at
the applicable redemption prices (expressed as a percentage
of the principal amount) set forth in the attached table,
together in each case with accrued interest to the date
fixed for redemption. Any redemptions permitted or required
under the Indenture, other than those described in (i), will
be deemed optional redemptions.
At least thirty (30) but not more than sixty (60) days prior
to the date on which any Series A Note is to be redeemed as
aforesaid, written notice of such redemption shall be given by
registered mail to the registered owners of the Series A Notes
all or any portions of which are to be redeemed. If this Note is
called in whole or in part, after provision has been duly made
for notice of such call and after deposit shall have been made of
the principal, premium, if any, and interest to the date fixed
for redemption and such amounts are immediately available on the
date fixed for redemption to the holders of the Series A Notes to
be redeemed on surrender thereof, this Note, or such called part
of the principal amount hereof, shall cease to be secured by the
lien of the Indenture, no interest shall accrue on this Note or
such called part hereof on and after the date fixed for
redemption, and the Company after said date fixed for redemption
shall be under no further liability in respect of the principal
of or premium, if any, or interest on this Note or such called
part hereof (except as expressly provided in the Indenture); and
if less than the whole principal amount hereof shall be so
called, the registered owner hereof shall be entitled, in
addition to the sums payable on account of the part called, to
receive, without expense to such owner, on surrender of this Note
duly endorsed or accompanied by a duly executed instrument of
transfer, one or more Series A Notes for an aggregate principal
amount equal to that part of the principal amount hereof not then
called and paid, or to present this Note for the notation hereon
of the payment of the part of the principal amount then called
and paid.
This Note is not subject to redemption under any provision
of the Indenture, or otherwise, except as expressly referenced
above.
The Company, the Trustee, any paying agent, any bond
registrar and any other person may treat the registered owner
hereof as the absolute owner hereof for the purpose of receiving
payment of the principal of and premium, if any, and interest on
this Note and for all other purposes, and neither the Company nor
the Trustee, nor any paying agent or bond registrar, shall be
affected by any notice or knowledge to the contrary, whether
payments on this Note shall be overdue or not. The Company, and
every successive owner and assignee of this Note, by accepting
and holding the same, consents and agrees to the foregoing
provisions, and each invites the others and all persons to rely
thereon.
No recourse shall be had for the payment of the principal of
or premium, if any, or interest on this Note against any
incorporator, stockholder, director, officer or agent, past,
present or future, as such, of the Company or of any predecessor
or successor corporation, either directly or through the Company
or any such predecessor or successor corporation, under any rule
of law, statute or constitution or by the enforcement of any
assessment or otherwise, all such liability of incorporators,
stockholders, directors, officers and agents being released by
the holder hereof by the acceptance of this Note and being
likewise waived and released as provided in the Indenture,
provided that nothing herein or in the Indenture shall prevent
enforcement of obligations on stock not fully paid up.
This Note shall take effect as a sealed instrument.
This Note shall not be valid or become obligatory for any
purpose or be entitled to any security or benefit under the
Indenture until the certificate hereon shall have been signed by
the Trustee.
IN WITNESS WHEREOF, Colonial Gas Company has caused this
Note to be executed under its corporate seal and issued by its
duly authorized officers, all as of _________________ __, 19__.
COLONIAL GAS COMPANY
By
By
Attest:
(Form of Trustee's Certificate)
This is one of the Series A Notes referred to in the
within-mentioned Indenture.
THE FIRST NATIONAL BANK OF BOSTON,
as Trustee
By
Authorized Officer
(Form of Endorsement)
FOR VALUE RECEIVED, the undersigned hereby sells, assigns
and transfers unto ____________________ (whose Taxpayer
Identification Number is ____________________) the within Note,
and all rights thereunder, hereby irrevocably constituting and
appointing _________________ attorney to transfer said Note on
the books of the Company, with full power of substitution in the
premises.
Dated:
In the presence of:
Notice: The signature to this assignment must correspond
with the name as it appears upon the face of the within Note in
every particular, without alteration or enlargement or any change
whatever.
[Insert Redemption Table, if applicable]
NOW, THEREFORE, THIS INSTRUMENT (BEING THE SECOND
SUPPLEMENTAL INDENTURE TO THE INDENTURE) WITNESSETH that, in
consideration of the premises, and of the acceptance and purchase
of the Series A Notes by the holders thereof, and of the sum of
$1.00 duly paid by the Trustee to the Company, and of other good
and valuable consideration, the receipt of which is hereby
acknowledged, and in confirmation of and supplementing and
amending the Indenture and in performance of and compliance with
the provisions thereof, said Colonial Gas Company has given,
granted, bargained, sold, warranted, pledged, assigned,
transferred, mortgaged and conveyed, and by these presents does
give, grant, bargain, sell, transfer, warrant, assign, pledge,
mortgage, convey and confirm unto The First National Bank of
Boston, as Trustee, as provided in the Indenture, and its
successor or successors in the trust thereby and hereby created,
and its and their assigns, (a) all and singular the property, and
rights and interests in property, described (directly or by
cross-reference to the Prior Indentures) in the Indenture and
thereby conveyed, pledged, assigned, transferred and mortgaged,
or intended so to be (said descriptions being hereby made a part
hereof to the same extent as if set forth herein at length),
whether then or now owned or thereafter or hereafter acquired;
(b) all of the real estate and personal property owned by the
Company located respectively in the City of Lowell, and in the
Towns of Chelmsford, Tewksbury, Dracut, Billerica, Westford,
Tyngsboro, Dunstable, Pepperell, North Reading, Littleton,
Wilmington, Wareham, Bourne (which includes the village of
Buzzards Bay), Mashpee, Falmouth, Barnstable (which includes the
village of Hyannis), Yarmouth, Dennis, Harwich, Chatham,
Sandwich, Brewster, Orleans and Eastham, all in Massachusetts,
including (without in any way limiting the generality of the
foregoing) the parcel or parcels of real estate, if any,
described in Exhibit A hereto; and (c) also without limiting the
generality of the foregoing, all the right, title and interest of
the Company in and to the franchises, rights, titles, interests,
easements and all other real and personal property acquired or
constructed by the Company since the execution and delivery of
the Indenture as fully as if set forth herein at length; except
such of said properties or interests therein described above in
(a) to (c), inclusive, as may have been released by the Trustee
or sold or disposed of in whole or in part as permitted by the
Indenture.
SUBJECT, HOWEVER, as to all of the foregoing, to the
specific rights, privileges, liens, encumbrances, restrictions,
conditions, limitations, covenants, interests, reservations,
exceptions and otherwise as provided (directly or by cross-
reference to the Prior Indentures) in the Indenture and in the
descriptions (directly or by cross-reference to the Prior
Indentures) in the Indenture and in the deeds or grants referred
to therein (or in said Prior Indentures).
BUT SPECIFICALLY RESERVING AND EXCEPTING (as the same were
reserved and excepted from the lien of the Indenture) from this
instrument and the grant, conveyance, mortgage, transfer and
assignment herein contained all right, title and interest of the
Company, now owned or hereafter acquired, in and to the
properties and rights described (directly or by cross-reference
to the Prior Indentures) on page 11 of the Indenture as
specifically reserved and excepted.
PROVIDED, HOWEVER, that if an event of default occurs and
the Trustee or any receiver or trustee appointed for the purpose
shall enter upon and take possession of the trust estate, the
Trustee or such receiver or trustee may, to the extent permitted
by law, take possession of the said specifically excepted
property and use it as if such property were part of the trust
estate, unless and until such default shall be remedied and
possession of the trust estate restored to the Company.
TO HAVE AND TO HOLD all such property, rights, title and
interests unto The First National Bank of Boston, Trustee
hereunder, its successors in the trust created by the Indenture,
and its and their assigns, to its and their own use and behoof
forever;
BUT IN TRUST, NEVERTHELESS, under and subject to the
provisions and conditions, with all the powers and authority and
for the trusts and purposes set forth in the Indenture, and (1)
for the equal pro rata benefit and security (except as provided
in sections 2.09 and 2.10 of the Indenture, and except insofar as
a sinking, improvement or analogous fund or funds, established in
accordance with the provisions of the Indenture for any series of
Bonds, may afford particular security for Bonds of one or more
series or sub-series, and except independent security as provided
in section 2.02 of the Indenture) of the holders of such of said
series of Bonds as are now outstanding and $75,000,000 in
aggregate principal amount of Series A Notes for the issue of
which provision is made herein, and of the holders of all the
Bonds from time to time certified, issued and outstanding under
the Indenture, and the bearers of the coupons thereto
appertaining, without (except as aforesaid) any preference,
priority or distinction whatever of any Bond or coupon over any
other Bond or coupon by reason of priority in the series or in
the issue, sale or negotiation thereof, or otherwise, and (2)
subject to the covenants, agreements, rights, privileges,
immunities and duties set forth in the Indenture and this
instrument.
The Company hereby declares that it holds and will hold and
apply all property described (directly or by cross-reference to
the Prior Indentures) on page 11 of the Indenture as specifically
reserved and excepted, upon the trusts of the Indenture set forth
and as the Trustee (or any purchaser thereof upon any sale
thereof hereunder) shall for such purpose direct, from time to
time, to the fullest extent permitted by law or in equity, as
fully as if the same could be and had been granted, conveyed,
mortgaged, transferred and assigned to and vested in the Trustee
by the Indenture.
ARTICLE I
Series A Notes
Section 1.01. General Terms of Series A Notes. The second
series of Bonds to be issued under the Indenture shall be known
as "Secured Medium Term Notes, Series A." Such Series A Notes
shall be limited in aggregate principal amount to $75,000,000.
The Series A Notes shall be issued from time to time as fully
registered Bonds, without coupons, and no coupon bonds shall be
issued, whether upon original issue or upon transfers or
exchanges. The Series A Notes shall be substantially in the form
hereinbefore recited and, in each case, shall recite the
principal amount, interest rate, maturity, redemption or call
provisions and other provisions thereof, which may vary as among
the Series A Notes. The Series A Notes may be issued in the
denomination of one thousand dollars ($1,000) each or any
multiple thereof and, without regard to the denomination thereof,
shall be numbered consecutively. Each Series A Note shall be
dated as of the day of certification, except that Series A Notes
issued upon transfers and exchanges of Series A Notes and upon
exchanges of temporary Bonds for such Series A Notes shall be
dated so that no gain or loss of interest shall result from such
transfer or exchange. The Series A Notes shall be due and
payable on such dates, and shall bear interest at such rates (in
each case computed on the basis of a 360-day year of twelve
30-day months from the date thereof) as may be specified therein
from the date of issuance. Interest thereon shall be payable
semi-annually, on February 15 and August 15 in each year, and at
maturity, until the principal thereof shall become due and
payable. The Company also agrees to pay on demand interest on
any overdue principal (including any overdue prepayment of
principal) and premium, if any, at a rate equal to the interest
rate of the relevant Series A Note, plus one percent (1.00%) per
annum and, to the extent permitted by law, interest on any
overdue installment of interest at the rate at which such overdue
installment of interest was calculated according to the terms of
the Series A Notes. The Series A Notes shall be payable as to
principal, premium, if any, and interest at, unless the holder of
any such Bond and the Company shall have otherwise agreed in
writing, the principal corporate trust office of the Trustee in
Canton, Massachusetts, or at the principal office of its
successor in trust created by the Indenture or, at the option of
the registered owner thereof, at such other office or agency of
the Trustee or of the Company maintained by it for the purpose
in the Burough of Manhattan, The City of New York, New York, or
such other place as may be designated for the
purpose pursuant to the provisions hereof, in lawful money of
the United States of America.
The Series A Notes shall be exchangeable by the holders, and
may be transferred, in each case as provided in section 2.06 of
the Indenture, all upon payment of charges and otherwise as
provided in the Indenture.
The Series A Notes are not subject to redemption, at the
option of the Company or otherwise, by operation of the
provisions of the Indenture, whether under sections 7.02 and 7.03
of the Indenture, or otherwise, except as specifically set forth
in the form of such Notes.
Series A Notes at any time outstanding may be called for
redemption in the manner provided in Article 5 of the Indenture
and section 1.03 hereof (i) in whole or in part, at any time
prior to maturity, at the option of the Company, to the extent,
under the provisions of and at the redemption prices specified in
the resolution of the Company providing for the issue of such
Series A Notes (the "Resolution") and set forth in the related
Series A Notes or (ii) in whole or in part at
any time prior to maturity through the application of eminent
domain moneys (as hereinafter defined) or the proceeds of
insurance arising from loss or casualty under the provisions of
the Indenture at the principal amount thereof; together in each
case with unpaid interest accrued to the date fixed for
redemption. Any redemptions permitted or required under the
Indenture, other than those described in (ii) above, shall be
deemed optional redemptions. The term "eminent domain moneys"
shall mean the net proceeds of the taking of property included in
the trust estate by exercise of the power of eminent domain, or
by similar right or power, or the purchase or designation of the
purchaser of, or ordering of the sale of, all or any part of such
property by the exercise of any right of any governmental
authority, or the sale or conveyance in lieu and in reasonable
anticipation of any such event (provided that, in case of a sale
or conveyance in anticipation of any such event, "eminent domain
moneys" shall include, in addition to said net proceeds, the
excess of the fair value over the net proceeds, if the fair
value, as evidenced by an engineer's certificate, of the property
sold or conveyed, is greater than such net proceeds), together
with all net sums payable for any damage to any fixed assets
embraced in the trust estate by or in connection with any such
taking, sale or conveyance.
Section 1.02. Payment of Interest. Whenever Series A Notes
are called for redemption, the Company shall, in each case, prior
to the date fixed for redemption thereof, pay to the Trustee in
cash all unpaid interest accrued on such Series A Notes to said
date fixed for redemption.
Section 1.03. Procedure for Redemption. Except as otherwise
provided in this section 1.03 or the Resolution, the procedure
for redemption of Series A Notes shall be that specified in
sections 5.02, 5.03 and 5.04 of the Indenture.
Notice of redemption of any Series A Notes shall be given by
the Company as provided in sections 5.02 and 5.03 of the
Indenture, except that, unless otherwise provided in the
Resolution, notice need be given only by mail and not by
publication. Any such notice of redemption shall be mailed not
less than thirty (30) nor more than sixty (60) days prior to the
date on which the proposed redemption is to take place. The
mailing of such notice shall be a condition precedent to
redemption, provided that any notice which is so mailed shall be
conclusively presumed to have been duly given, whether or not the
holders receive such notice, and failure to give such notice by
mail, or any defect in such notice, to the holder of any such
Series A Note designated for redemption, in whole or in part,
shall not affect the validity of the redemption of any other such
Series A Note.
Section 1.04. Global Notes. Notwithstanding any other
provisions of this Supplemental Indenture, the Series A Notes
issued by the Company and authenticated and delivered by the
Trustee under this Supplemental Indenture shall be issued as
definitive, fully-registered global notes in the name of Cede
& Co., as nominee of The Depository Trust Company ("DTC"), in
the aggregate principal amount of all Series A Notes issued
hereunder.
The Company and the Trustee may treat DTC as, and shall deem
DTC to be, the absolute owner of the Series A Notes evidenced by
the global notes for the purpose of payment of principal of,
premium, if any, and interest on such Series A Notes, for the
purpose of all other matters with respect to such Series A Notes,
for the purpose of registering transfers with respect to Series A
Notes, and for all other purposes whatsoever. Neither the
Company nor the Trustee shall have any responsibility or
obligation to any of DTC's direct or indirect participants.
Without limiting the immediately preceding sentence, neither the
Company nor the Trustee shall have any responsibility or
obligation with respect to (i) the accuracy of the records of DTC
or its nominee or any of its direct or indirect participants with
respect to any ownership interest in the global notes, (ii) the
delivery to any of DTC's direct or indirect participants or any
other person, other than DTC, of any notice with respect to the
Series A Notes evidenced by the global notes, (iii) the payment
to any of DTC's direct or indirect participants or any other
person, other than DTC, of any amount with respect to the
principal of, premium, if any, or interest on the Series A Notes
evidenced by the global notes, and (iv) the failure of DTC to
provide any information or notification on behalf of any of DTC's
direct or indirect participants. The Trustee shall pay all
principal of and premium, if any, and interest on the Series A Notes
only to or upon the order of DTC, and all such payments shall be
valid and effective to fully satisfy the Company's obligations
with respect to the principal of and premium, if any, and
interest on such Series A Notes to the extent so paid.
Notwithstanding the provisions of the Indenture to the contrary
(including, without limitation, place of payment, surrender of
the Series A Notes, registration and transfer thereof and
authorized denominations), as long as any of the Series A Notes
are in the form of a global note, full effect shall be given to
the procedures and practices of DTC with respect thereto, and the
Trustee shall comply therewith.
In the event that (i) DTC (or any successor securities
depositary) is at any time unwilling or unable to continue as
depositary and a successor depositary is not appointed by the
Company within 90 days, (ii) the Company determines that the
continuation of the system of book-entry only transfers through
DTC (or a successor securities depositary) is not in the best
interests of the beneficial owners of the Series A Notes or is
burdensome to the Company, or (iii) a default under the Indenture
has occurred and is continuing, the Company will notify DTC and the
Trustee, whereupon DTC or the Trustee will notify DTC
participants of the availability through DTC of certificates for
the Series A Notes. In such event, the Company and the Trustee
shall execute and deliver a supplemental indenture to add such
provisions and to make such modifications, including in the
form of Series A Note, as may be necessary or appropriate to provide
for the issuance of the Series A Notes in certificated form and
the Company shall issue and the Trustee shall transfer and
exchange certificates for the Series A Notes as requested by DTC
in denominations as prescribed by Section 1.01 hereof, to the
identifiable beneficial owners in replacement of such beneficial
owners' respective beneficial interests in the Series A Notes.
ARTICLE II
Miscellaneous
Section 2.01. Certain Covenants. For purposes of Sections
3.01(h) and 4.22 of the Indenture, and not for any other purpose,
the Series A Notes are hereby designated as Prior Series Bonds.
Section 2.02. Miscellaneous Provisions. The Trustee shall
be entitled to, may exercise and shall be protected by, where and
to the full extent that the same are applicable, all the rights,
powers, privileges, immunities and exemptions provided in the
Indenture, as if the provisions concerning the same were
incorporated herein at length. The Trustee under the Indenture
shall ex officio be Trustee hereunder. The remedies and
provisions of the Indenture, applicable in case of any default by
the Company thereunder, are hereby adopted and made applicable in
case of any default with respect to the properties included
herein and, without limitation of the generality of the
foregoing, there are hereby conferred upon the Trustee the same
powers of sale and other powers over the properties described
herein as are expressed to be conferred by the Indenture.
If, pursuant to Article I of this Supplemental Indenture or
any similar provision of any other supplemental indenture, the
Trustee makes payment of the redemption price of all or a portion
of any registered Series A Note directly to the registered owner
thereof without presentation or surrender thereof, the Trustee
shall have no responsibility to ascertain whether such registered
owner carries out its agreement not to dispose of such Note
without prior presentation or surrender thereof to the Trustee as
provided in said Article I or similar provision, and the Trustee
shall not be liable for any claim if arising out of or because of
the failure of such registered owner to carry out its said
agreement.
The recitals in this Supplemental Indenture shall be taken
as recitals by the Company alone, and shall not be considered as
made by or as imposing any obligation or liability upon the
Trustee, nor shall the Trustee be held responsible for the
legality or validity of this Supplemental Indenture, and the
Trustee makes no covenants or representations, and shall not be
responsible, as to or for the effect, authorization, execution,
delivery or recording of this Supplemental Indenture, except as
expressly set forth in the Indenture. The Trustee shall not be
taken impliedly to waive by this Supplemental Indenture any right
it would otherwise have. As provided in the Indenture, this
Supplemental Indenture shall hereafter form a part of the
Indenture.
The date of this Supplemental Indenture is intended as and
for a date for reference and for identification, the actual time
of the execution hereof being the date set forth in the
testimonium clause hereof.
This Supplemental Indenture shall become void when the
Indenture shall be void.
If any provision of this Supplemental Indenture limits,
qualifies or conflicts with the duties imposed by operation of
Section 318(c) of the Trust Indenture Act of 1939, as amended,
such imposed duties shall control.
This Supplemental Indenture may be simultaneously executed
in any number of counterparts, each of which shall be deemed an
original; and all said counterparts executed and delivered, each
as an original, shall constitute but one and the same instrument,
which shall for all purposes be sufficiently evidenced by any
such original counterpart.
IN WITNESS WHEREOF, Colonial Gas Company has caused this
Supplemental Indenture to be executed, and its corporate seal to
be hereto affixed, by its officers thereunto duly authorized, and
The First National Bank of Boston has caused this Supplemental
Indenture to be executed, and its corporate seal to be hereto
affixed, by its officers thereunto duly authorized, all as of the
day and year first above written but actually on the 27th day of
September, 1995.
COLONIAL GAS COMPANY
[Seal]
By Dennis W. Carroll
Vice President
By Dennis W. Carroll
Treasurer
Attest:
June T. Abreu
Assistant Clerk
THE FIRST NATIONAL BANK OF BOSTON,
as Trustee
[Seal]
By James E. Mogavero
Authorized Officer
Attest:
Illegible
Clerk
The Commonwealth of Massachusetts )
) ss.:
County of Suffolk )
On this 27th day of September, 1995 before me personally
appeared Dennis W. Carroll and June T. Abreu, to me personally
known, who, being by me duly sworn, did say that they are the
Vice President & Treasurer and the Assistant Clerk, respectively,
of Colonial Gas Company, that the seal affixed to the foregoing
instrument is the corporate seal of said corporation, and that
said instrument was signed and sealed by them on behalf of said
corporation by authority of its Board of Directors; and the said
Dennis W. Carroll and June T. Abreu, acknowledged said instrument
to be the free act and deed of said corporation.
[Seal]
Timothy A. Clark
Notary Public
My Commission Expires:
10/06/2000
The Commonwealth of Massachusetts )
) ss.:
County of Suffolk )
On this 26th day of September, 1995 before me personally
appeared James E. Mogavero, to me
personally known, who, being by me duly sworn, did say that he is
an Authorized Officer of The First National Bank of Boston, that
the seal affixed to the foregoing instrument is the corporate seal
of said bank, and that said instrument was signed and sealed by them
on behalf of said bank, by authority of its Board of Directors; and
the said James E. Mogavero, acknowledged said instrument to be the
free act and deed of said trust company, as trustee.
[Seal]
Ralph E. Jones
Notary Public
My Commission Expires:
January 18, 2002
[END OF EXHIBIT 4c TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 4d TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
THIS AMENDMENT TO SECOND SUPPLEMENTAL INDENTURE, dated
as of August 1, 1995 (hereinafter referred to as this
"Amendment" or this "Instrument"), made and entered into by
and between Colonial Gas Company, a corporation duly
organized and existing under the laws of The Commonwealth of
Massachusetts, having its principal place of business at 40
Market Street, Lowell, Massachusetts (hereinafter referred to
as the "Company"), and The First National Bank of Boston, a
corporation duly organized and existing under the laws of The
Commonwealth of Massachusetts, having its principal place of
business at 100 Federal Street, Boston, Massachusetts, as
successor Trustee (hereinafter referred to, together with its
successors hereunder, as the "Trustee") under the Second
Amended and restated First Mortgage Indenture dated as of
June 15, 1992, as supplemented by the First Supplemental
Indenture dated as of June 15, 1992 and the Second
Supplemental Indenture (the "Second Supplement") dated as of
August 1, 1995 (as amended and so supplemented, the
"Indenture").
WHEREAS, the Company has heretofore duly executed and
delivered to the Trustee the Second Supplement, to issue up
to $75,000,000 in aggregate principal amount of First
Mortgage Bonds designated Secured Medium Term Notes, Series A
(herein referred to as the "Series A Notes") under the
Indenture, which Series A Notes are to be further designated
and described, as to dates, maturities, interest rates,
sinking funds, denominations and redemption and call
provisions, in such Series A Notes which the Company may
issue from time to time, each in the form hereinafter set
forth (and the Trustee hereby confirms its approval,
previously given prior to the certification of any of said
additional Series A Notes, of the form and designation
thereof so specified); and
WHEREAS, the Company desires to amend the Second
Supplemental to confirm its ability to fix interest payment
dates as it may determine;
NOW, THEREFORE, THIS INSTRUMENT (BEING THE AMENDMENT TO
SECOND SUPPLEMENT TO THE INDENTURE) WITNESSETH that, in
consideration of the premises, and of the acceptance and
purchase of the Series A Notes by the holders thereof, and of
the sum of $1.00 duly paid by the Trustee to the Company, and
of other good and valuable consideration, the receipt of
which is hereby acknowledged, and in confirmation of and
supplementing and amending the Indenture and in performance
of and compliance with the provisions thereof, the Company
and the Trustee agree as follows:
ARTICLE I
Series A Notes
Section 1.01. Amendment of the Second Supplement. The
Second Supplement is hereby amended as follows:
(a) The first paragraph of the Form of the Series A
Note in the last recital is amended by deleting the words
"February 15 and August 15" and replacing them with "April 14
& October 14."
(b) The first paragraph of Section 1.01 is hereby
amended by adding the phrase, "or such other dates as set
forth in the form of such Notes," after the phrase "February
15 and August 15 in each year."
IN WITNESS WHEREOF, Colonial Gas Company has caused this
Amendment to be executed, and its corporate seal to be hereto
affixed, by its officers thereunto duly authorized, and The
First National Bank of Boston has caused this Amendment to be
executed, and its corporate seal to be hereto affixed, by its
officers thereunto duly authorized, all as of the day and
year first above written but actually on the 12th day of
October, 1995.
COLONIAL GAS COMPANY
[SEAL] By Dennis W. Carroll
Vice President
BY Dennis W. Carroll
Treasurer
Attest:
Timothy A. Clark
Assistant Clerk
THE FIRST NATIONAL BANK OF
BOSTON, as Trustee
[SEAL] By Terence A. McGiunnis
Authorized Officer
Attest:
Michael R. Garfield
Assistant Secretary
Commonwealth of Massachusetts )
) ss.:
County of Middlesex )
On this 12th day of October, 1995 before me personally
appeared Dennis W. Carroll and Timothy A. Clark, to me
personally known, who, being by me duly sworn, did say that
they are the Vice President and Treasurer and the Assistant
Clerk, respectively, of Colonial Gas Company, that the seal
affixed to the foregoing instrument is the corporate seal of
said corporation, and that said instrument was signed and
sealed by them on behalf of said corporation by authority of
its Board of Directors; and the said Dennis W. Carroll and
Timothy A. Clark, acknowledged said instrument to be the free
act and deed of said corporation.
[Seal]
June T. Abreu
Notary Public
My Commission Expires:
2/19/99
Commonwealth of Massachusetts )
) ss.:
County of Middlesex )
On this 23rd day of October, 1995 before me personally
appeared Terence A. McGiunnis, to me personally known, who, being by
me duly sworn, did say that he is an Authorized Officer of
The First National Bank of Boston, that the seal affixed to
the foregoing instrument is the corporate seal of said bank,
and that said instrument was signed and sealed by him on
behalf of said bank, by authority of its Board of Directors;
and the said Terence A. McGiunnis acknowledged said
instrument to be the free act and deed of said company, as
trustee.
[Seal]
Michael R. Garfield
Notary Public
My Commission Expires:
January 31, 1997
COLONIAL GAS COMPANY
Amendment to Second Supplemental Indenture
Dated as of August 1, 1995 to Second
Amended and Restated First Mortgage Indenture
The above Amendment to Second Supplemental Indenture was
filed for recordation in Massachusetts as follows:
Location Date Reference
Secretary of the 10/26/95 Document Nos.
Commonwealth 374252 and 347251
Barnstable County 10/27/95 Instrument No.54662
Book 9903 Page 289
Barnstable County, Land 10/27/95 Document No. 650917
Registration Certificates of Title
Division Nos. 46050 (131302)
59716 (178392), and
84810 (278220)
Middlesex County, 10/30/95 Instrument No.49470
North Division Book ______, Page______
Middlesex County, 10/26/95 Instrument No. 699
South Division Book ______, Page ______
Plymouth 11/3/95 Instrument No.96562
Book 13940, Page 16
[EXHIBIT 4d TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 10qq TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
SERVICE PACKAGE NO. 11290
AMENDMENT NO. 0
FIRM NATURAL GAS TRANSPORTATION AGREEMENT
(For Use Under "NET-Niagara", "NET-Northeast" and "NET-Elgen"
Rate Schedules)
THIS FIRM NATURAL GAS TRANSPORTATION AGREEMENT ("Agreement") is
entered into this 1st day of August, 1995 between TENNESSEE GAS
PIPELINE COMPANY, a Delaware Corporation, herein called
"Transporter", and COLONIAL GAS COMPANY, a MASSACHUSETTS
corporation, herein called "Shipper", pursuant to the following
general terms and representations.
W I T N E S S E T H:
WHEREAS, Transporter owns and operates a natural gas transmission
pipeline system which extends in a northeasterly direction from
its principal sources of supply in Texas and Louisiana through
the States of Texas, Louisiana, Arkansas, Mississippi, Alabama,
Tennessee, Kentucky, West Virginia, Ohio, Pennsylvania, New York,
New Jersey, Massachusetts, New Hampshire, Rhode Island and
Connecticut; and
WHEREAS, Shipper has entered into certain gas purchase contracts
with various producers providing for the sale by such producers
to Shipper of a maximum quantity of 4,000 dekatherms ("Dth") of
natural gas per day and has made arrangements for the delivery of
such natural gas for the account of Shipper to the points listed
in Exhibit A hereto, and
WHEREAS, Shipper and Transporter have entered into a Precedent
Agreement dated December 16, 1988 (the "Precedent Agreement"),
pursuant to which Transporter agreed to file an application with
the Federal Energy Regulatory Commission ("FERC") for the
necessary authorizations to (i) provide firm natural gas
transportation service of a daily quantity not to exceed 4,000
Dth of natural gas, and (ii) construct and operate the facilities
necessary to provide such firm transportation service;
WHEREAS, Transporter has now been authorized by the FERC order
issued on November 14, 1990 in docket Nos. CP89-629-000, et al.,
to render the firm transportation service described herein and to
construct and operate the necessary facilities therefore; and
WHEREAS, Transporter and Shipper wish to set forth herein the
specified terms and conditions under which Transporter will
provide such transportation service to Shipper;
NOW, THEREFORE, in consideration of the promises and of the
mutual agreements herein contained, Transporter and Shipper agree
as follows:
ARTICLE I
DEFINITIONS
1.1 Equivalent Quantity - shall mean, during any given period of
time, a quantity of gas equal to the quantity of gas received
by Transporter for the account of Shipper for transportation
hereunder at the Point(s) of receipt, less quantities for
transport's system fuel and use requirements and gas lost and
unaccounted for associated with this transportation service,
which may be provided by Transporter or Shipper as specified
in Article VIII, Section 4. For purposes of determining an
Equivalent Quantity, quantities of gas shall be stated in
dekatherms and measured on a dry basis.
1.2 Point(s) of Receipt - shall mean those points as specified in
Exhibit A attached hereto at which Transporter shall receive
gas for transportation hereunder, and such other points as
may be agreed to from time to time by both parties.
1.3 Point(s) of Delivery - shall mean those points as specified
on Exhibit A attached hereto at which Transporter shall
deliver gas to Shipper, and such other points as may be agreed
to from time to time by both parties.
1.4 Transportation Quantity - shall mean the maximum daily
quantity of natural gas that Transporter hereby agrees to
receive, subject to Article II herein, for the account of
Shipper at the Point of Receipt during the term of hereof,
which shall be 4,000 Dth, provided that Transporter is under
no obligation to receive a volume in excess of 4,000 Mcf.
ARTICLE II
TRANSPORTATION
2.1 Transportation Service - After receipt and acceptance by
Transporter of all FERC and other authorizations necessary to
provide service hereunder and completion of the facilities
required to provide such service, beginning on the
Commencement Date (as defined in Article VIII, Section 8.1
hereof), Transporter agrees to accept and receive daily, on a
firm basis, at the Point of Receipt, from Shipper such
quantity of gas as Shipper makes available up to the
Transportation Quantity and to transport and deliver for
Shipper to the Point(s) of Delivery an Equivalent Quantity of
gas.
ARTICLE III
3.1 Shipper shall cause the delivery of natural gas to
Transporter at the Point(s) of Receipt to be at pressures
sufficient to enter Transporter's pipeline system.
3.2 Transporter shall cause the delivery of natural gas to
Shipper at the Point(s) of Delivery as nearly as practicable
at Transporter's line pressure, provided that pressure shall
not be less than 100 pounds per square inch gauge.
ARTICLE IV
CONTROL AND BALANCING OF DELIVERIES
The control and balancing of deliveries shall be as provided in
Article III, of the General Terms and Conditions of Transporter's
FERC Gas Tariff Volume No. 1.
ARTICLE V
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
For all gas received, transported and delivered hereunder, the
parties agree to the quality specifications and standards for
measurement provided for in Article II and III of the General
Terms and Conditions of Transporter's FERC Gas Tariff Volume No.
1.
ARTICLE VI
FACILITIES
Transporter shall construct, install own and operate the
facilities, including but not limited to measurement facilities
hot tap, necessary for Transporter to receive and deliver the gas
as contemplated herein for Shipper's account at the Point(s) of
Receipt and the Point(s) of Delivery.
ARTICLE VII
DISPATCHER'S NOTIFICATION
Shipper's dispatcher shall notify Transporter's dispatcher of the
daily volume which Shipper desires Transporter to transport on
any day in the manner set forth in Article III, Section 4 of the
General Terms and Conditions of Transporter's FERC Gas Tariff
Volume No. 1.
ARTICLE VIII
RATES FOR SERVICE
8.1 Transportation Rates - The compensation to be paid by Shipper
to Transporter for the transportation service provided for
herein shall be payable monthly in accordance with Article X
hereof and shall be equal to the sum of the following: (a) the
product of (1) the sum of the Monthly Demand Rates for
Segments 3 and 4 under Transporter's NET-NE Rate Schedule and
(2) the Transportation Quantity, (b) the product of (1) sum
of the Commodity Rates for Segments 3 and 4 under
Transporter's NET-NE Rate Schedule and (2) the quantity of
gas delivered by Transporter to Shipper during the applicable
billing period, and (c) the product of (1) any applicable
surcharges as included in Transporter's effective FERC Gas
Tariff and (2) the quantity of gas delivered by Transporter
to Shipper during the applicable billing period.
References herein to Transporter's NET-NE Rate Schedule shall
include any successor or substitute rate schedules.
8.2 Fuel and Use Quantity - Prior to the Commencement Date (as
defined in Section 8.1 hereof) and from time to time
thereafter Transporter and Shipper shall mutually agree
whether Transporter or Shipper shall supply the fuel required
for transportation hereunder. In the event Transporter and
Shipper agree that Transporter shall supply the fuel required
for fuel and losses ("Fuel and Use Quantity"), Transporter
shall charge Shipper an amount equal to the product of (a)
the amount specified for the cash out of delivery point
imbalances in the 0-5% range under Rate Schedule LMS-MA of
Transporter's FERC Gas Tariff, Volume No. I, and (b) the Fuel
and Use Quantity. Transporter's provision of the fuel
required for transportation hereunder is subject to
termination on 30 days' written notice, at the option of
either Transporter in its sole discretion or Shipper in its
sole discretion. In the event that Transporter does not
provide the Fuel and Use quantity as stated above, then
Shipper shall furnish the quantity of gas required for fuel
and losses. The quantity of gas retained by Transporter for
fuel and losses shall be equal to the quantity of gas
scheduled for delivery to Transporter multiplied by the
applicable percentage shown for Shipper's service in Article
7 of Transporter's NET Rate Schedule.
8.3 Rate Changes - Shipper agrees that Transporter shall have the
unilateral right pursuant to this Article VIII to file and
make effective changes in (a) the rates, charges, and
conditions applicable to service pursuant to the Rate
Schedule under which this service is rendered (b) the rate
schedule(s) pursuant to which service hereunder is rendered,
and/or (c) any provisions of the General Terms and Conditions
of Transporter's FERC Gas Tariff Volume No. 1 as such Tariff
may be revised or replaced from time to time. Transporter
agrees that Shipper may protest or contest the aforementioned
filings, or may seek authorization from duly constituted
regulatory authorities for such adjustment of Transporter's
existing FERC Gas Tariff as may be found necessary to assure
Transporter's just and reasonable rates.
NET-EU RATE SCHEDULE
ARTICLE IX
RESPONSIBILITY DURING TRANSPORTATION
As between the parties hereto, it is agreed that from the time
gas is delivered by Shipper to Transporter at the Point of
Receipt and prior to delivery of such gas to or for the account
Shipper at the Point(s) of Delivery, Transporter shall have the
unqualified right to commingle such gas with other gas in its
pipeline system and shall have the unqualified right to handle
such gas as its own.
ARTICLE X
BILLINGS AND PAYMENTS
Transporter and Shipper agree that the obligations of Transporter
and Shipper for billing and payment for the services provided
hereunder shall be in accordance with Articles V and VI of the
General Terms and Conditions of Transporter's FERC Gas Tariff
Volume No. 1.
ARTICLE XI
RATE SCHEDULES AND GENERAL TERMS AND CONDITIONS
This Agreement and all terms and provisions contained or
incorporated herein are subject to the provisions of
Transporter's applicable Rate Schedules and of Transporter's
General Terms and Conditions on file with the FERC, or other duly
constituted authorities having jurisdiction, as the same may be
legally amended or superseded, which Rate Schedules and General
Terms and Conditions are by this reference made a part hereof.
ARTICLE XII
TERM OF AGREEMENT
This Agreement shall become effective on the date hereof, and
shall remain in force and effect for a Primary Term extending
through October 31, 2012 and from year to year thereafter. After
the expiration of the Primary Term either party may elect to
terminate this Agreement by giving 12 months prior written notice
of such termination.
ARTICLE XIII
REGULATION
This Agreement shall be subject to all applicable governmental
statutes and all applicable and lawful orders, rules, and
regulations.
ARTICLE XIV
WARRANTY
Shipper warrants that it will at the time of delivery of gas to
Transporter hereunder have good title to and the good right to
deliver all gas so made available. Transporter warrants that it
will, at the time of delivery of gas for the account of Shipper
hereunder, have the right to deliver all such gas. Each party
warrants to the other and such other party's successors and
assigns that the gas covered by its warranty hereunder shall be
free and clear of all liens, encumbrances, or claims against the
warranting party or its affiliates for use of property of such
party or its affiliates. Each party will indemnify the other and
save it harmless from all suits, actions, debts, accounts,
damages, costs, losses, and expenses arising from or out of any
adverse claims regarding title and/or right to delivery of any or
all persons against the indemnifying party and/or to royalties,
taxes, license fees, or charges assessed against such party.
Title to the gas received, transported, and delivered hereunder
shall at all times remain with Shipper and shall not pass to
Transporter; provided that title to the gas delivered by Shipper
hereunder for fuel and use requirements of Transporter as set
forth in Article VIII herein, shall pass to Transporter upon
delivery of said gas to Transporter at the Point(s) of Receipt.
ARTICLE XV
ASSIGNMENTS
15.1 Either party may assign or pledge this Agreement and all
rights and obligations hereunder under the provisions of any
mortgage, deed of trust, indenture, or other instrument which
it has executed or may execute hereafter as security for
indebtedness. Either party may without relieving itself of
its obligations under this Agreement, assign any of its
rights hereunder to a wholly owned affiliate, but otherwise
no assignment of this Agreement or any of the rights or
obligations hereunder shall be made unless there first shall
have been obtained the written consent thereto of the other
party, which consent shall not be unreasonably withheld.
15.2 Any entity which shall succeed by purchase, merger, or
consolidation to the properties, substantially or as an
entirety of either party hereto shall be entitled to the
rights and shall be subject to the obligations of its
predecessor interest under this Agreement.
ARTICLE XVI
MISCELLANEOUS
16.1 Unless otherwise expressly provided for in this
Agreement or Transporter's FERC Gas Tariff, no modification
of or supplement to the terms and provisions hereof shall be
or become effective, except by the execution of supplementary
written consent by both parties.
16.2 No waiver by either party of any one or more defaults by
the other in the performance of any provisions of this
Agreement shall operate or be construed as a waiver of any
future default or defaults, whether of a like or of a
different character.
16.3 Except as herein otherwise provided, any notice,
request, demand, statement, or bill provided for in this
Agreement or any notice which either party may desire to give
to the other shall be in writing and mailed by registered or
certified mail to the post office address of the party
intended to receive the same, as the cause may be, as
follows:
TRANSPORTER: Tennessee Gas Pipeline Company
P.O. Box 2511
Houston, Texas 77252
Attn: Market Services
Invoices: Attn: Gas Accounting
Payments: Attn: Treasury Department
Gas Analysis
and Volume
Statements: Attn: Measurement Department
SHIPPER Colonial Gas Company
40 Market Street
Lowell, Massachusetts 01853
Attn: Scott B. Scholten
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, Massachusetts
01853-3064
Attn: Martin Debruin
or to such other address as either party shall designate by
formal written notice to the other. Routine communications,
including monthly statements and payments, may be mailed by
registered, certified or ordinary mail.
16.4 This Agreement shall be interpreted under the
laws of the State of Texas, without regard to the principles
governing choice of laws.
16.5 Exhibit A attached hereto is incorporated
herein by reference and made a part of this Agreement for all
purposes.
16.6 This Agreement, as of the date hereof, shall
supersede and cancel the Precedent Agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement
to be duly executed in multiple counterparts as of the date first
hereinabove written.
TENNESSEE GAS PIPELINE COMPANY
By: Byron S. Wright/wdw
Agent and Attorney-in-
Fact
Date: 7/21/95
COLONIAL GAS COMPANY
BY: John P. Harrington
TITLE: Senior Vice President-Gas Supply
DATE: 7/14/95
GAS TRANSPORTATION AGREEMENT
(For Use Under NET-NE Rate Schedule)
EXHIBIT "A"
Amendment #0 to Gas Transportation Agreement
Dated August 1, 1995
Between
TENNESSEE GAS PIPELINE COMPANY
AND
COLONIAL GAS COMPANY
SHIPPER: COLONIAL GAS COMPANY
EFFECTIVE DATE OF AMENDMENT: AUGUST 1, 1995
RATE SCHEDULE: NET-NE
SERVICE PACKAGE: 11290
MAXIMUM DAILY ELECTED QUANTITY: 4,000 Dth
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE
012181 IROQUOIS-WRIGHT IROQUOIS 05
SMS
020139 COLONIAL- COLONIAL GAS CO MIDDLESEX MA 06
TEWKSBURY MASS
020285 ALGONQUIN-MENDON ALGONQUIN MA 06
METER METER NAME R/D LEG METER-T MINIMUM PRESSURE
012181 IROQUOIS-WRIGHT R 200 4,000
SMS
Total Receipt TQ: 4,000
020139 COLONIAL- D 200 4,000 100 LBS
TEWKSBURY MASS
020285 ALGONQUIN-MENDON D 200 4,000 100 LBS
Total Delivery TQ: 4,000
NUMBER OF RECEIPT POINTS: 1
NUMBER OF DELIVERY POINTS: 2
NOTE: Exhibit "A" is a reflection of the contract and all amendments as of
the amendment effective date.
[END OF EXHIBIT 10qq TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 10rr TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1995]
SERVICE PACKAGE 10778
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
THIS AGREEMENT is made and entered into as of the 1st day of
June, 1995, by and between TENNESSEE GAS PIPELINE COMPANY, a
Delaware Corporation, hereinafter referred to as "Transporter"
and COLONIAL GAS COMPANY, a MASSACHUSETTS Corporation,
hereinafter referred to as "Shipper." Transporter and Shipper
shall collectively be referred to herein as the "Parties."
ARTICLE I
DEFINITIONS
1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily
quantity of gas which Transporter agrees to receive and
transport on a firm basis, subject to Article II herein,
for the account of Shipper hereunder on each day during
each year during the term hereof, which shall be 16,083
dekatherms. Any limitations of the quantities to be
received from each Point of Receipt and/or delivered to
each Point of Delivery shall be as specified on Exhibit "A"
attached hereto.
1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of
the General Terms and Conditions of Transporter's FERC Gas
Tariff.
ARTICLE II
TRANSPORTATION
Transportation Service - Transporter agrees to accept and
receive daily on a firm basis, at the Point(s) of Receipt from
Shipper or for Shipper's account such quantity of gas as Shipper
makes available up to the Transportation Quantity, and to deliver
to or for the account of Shipper to the Point(s) of Delivery an
Equivalent Quantity of gas.
ARTICLE III
POINT(S) OF RECEIPT AND DELIVERY
The Primary Point(s) of Receipt and Delivery shall be those
points specified on Exhibit "A" attached hereto.
ARTICLE IV
All facilities are in place to render the service provided for in
this Agreement.
ARTICLE V
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
For all gas received, transported and delivered hereunder the
Parties agree to the Quality Specifications and Standards for
Measurement as specified in the General Terms and Conditions of
Transporter's FERC Gas Tariff Volume No. 1. To the extent that
no new measurement facilities are installed to provide service
hereunder, measurement operations will continue in the manner in
which they have previously been handled. In the event that such
facilities are not operated by Transporter or a downstream
pipeline, then responsibility for operations shall be deemed to
be Shipper's.
ARTICLE VI
RATES AND CHARGES FOR GAS TRANSPORTATION
6.1 TRANSPORTATION RATES - Commencing upon the effective date
hereof, therates, charges, and surcharges to be paid by
Shipper to Transporter for the transportation service
provided herein shall be in accordance with Transporter's
Rate Schedule FT-A and the General Terms and Conditions of
Transporter's FERC Gas Tariff.
6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse
Transporter for any filing or similar fees, which have not
been previously paid for by Shipper, which Transporter
incurs in rendering service hereunder.
6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that
Transporter shall have the unilateral right to file with
the appropriate regulatory authority and make effective
changes in (a) the rates and charges applicable to service
pursuant to Transporter's Rate Schedule FT-A, (b) the rate
schedule(s) pursuant to which service hereunder is
rendered, or (c) any provision of the General Terms and
Conditions applicable to those rate schedules. Transporter
agrees that Shipper may protest or contest the
aforementioned filings, or may seek authorization from duly
constituted regulatory authorities for such adjustment of
Transporter's existing FERC Gas Tariff as may be found
necessary to assure Transporter just and reasonable rates.
ARTICLE VII
BILLINGS AND PAYMENTS
Transporter shall bill and Shipper shall pay all rates and
charges in accordance with Articles V and VI, respectively, of
the General Terms and Conditions of the FERC Gas Tariff.
ARTICLE VIII
GENERAL TERMS AND CONDITIONS
This Agreement shall be subject to the effective provisions of
Transporter's Rate Schedule FT-A and to the General Terms and
Conditions incorporated therein, as the same may be changed or
superseded from time to time in accordance with the rules and
regulations of the FERC.
ARTICLE IX
REGULATION
9.1 This Agreement shall be subject to all applicable and
lawful governmental statutes, orders, rules and regulations
and is contingent upon the receipt and continuation of all
necessary regulatory approvals or authorizations upon terms
acceptable to Transporter. This Agreement shall be void
and of no force and effect if any necessary regulatory
approval is not so obtained or continued. All Parties
hereto shall cooperate to obtain or continue all necessary
approvals or authorizations, but no Party shall be liable
to any other Party for failure to obtain or continue such
approvals or authorizations.
9.2 The transportation service described herein shall be
provided subject to Subpart G, Part 284, of the FERC
Regulations.
ARTICLE X
RESPONSIBILITY DURING TRANSPORTATION
Except as herein specified, the responsibility for gas during
transportation shall be as stated in the General Terms and
Conditions of Transporter's FERC Gas Tariff Volume No. 1.
ARTICLE XI
WARRANTIES
11.1 In addition to the warranties set forth in Article IX of
the General Terms and Conditions of Transporter's FERC Gas
Tariff, Shipper warrants the following:
(a) Shipper warrants that all upstream and downstream
transportation arrangements are in place, or will be
in place as of the requested effective date of
service, and that it has advised the upstream and
downstream transporters of the receipt and delivery
points under this Agreement and any quantity
limitations for each point as specified on Exhibit
"A" attached hereto. Shipper agrees to indemnify
and hold Transporter harmless for refusal to
transport gas hereunder in the event any upstream or
downstream transporter fails to receive or deliver
gas as contemplated by this Agreement.
(b) Shipper agrees to indemnify and hold Transporter
harmless from all suits, actions, debts, accounts,
damages, costs, losses and expenses (including
reasonable attorneys fees) arising from or out of
breach of any warranty by Shipper herein.
11.2 Transporter shall not be obligated to provide or continue
service hereunder in the event of any breach of warranty.
ARTICLE XII
TERM
12.1 This Agreement shall be effective as of June 1, 1995, and
shall remain in force and effect until May 31, 2000,
("Primary Term") and on a Automatic Rollover basis
thereafter unless terminated by either Party upon at least
thirty (30) days prior written notice to the other Party;
provided, however, that if the Primary Term is one year or
more, then unless Shipper elects upon one year's prior
written notice to Transporter to request a lesser extension
term, the Agreement shall automatically extend upon the
expiration of the Primary Term for a term of five years and
shall automatically extend upon the expiration of the
primary term for a term of five years and shall
automatically extend for successive five year terms
thereafter unless Shipper provides notice described above
in advance of the expiration of a succeeding term;
provided further, if the FERC or other governmental body
having jurisdiction over the service rendered pursuant to
this Agreement authorizes abandonment of such service, this
Agreement shall terminate on the abandonment date permitted
by the FERC or such other governmental body.
12.2 Any portions of this Agreement necessary to resolve or cash-
out imbalances under this Agreement as required by the
General Terms and Conditions of Transporter's Tariff, shall
survive the other parts of this Agreement until such time
as such balancing has been accomplished; provided, however,
that Transporter notifies Shipper of such imbalance not
later than twelve months after the termination of this
Agreement.
12.3 This Agreement will terminate automatically upon written
notice from Transporter in the event Shipper fails to pay
all of the amount of any bill for services rendered by
Transporter hereunder in accord with the terms and
conditions of Article VI of the General Terms and
Conditions of Transporter's FERC Gas Tariff.
ARTICLE XIII
NOTICE
Except as otherwise provided in the General Terms and Conditions
applicable to this Agreement, any notice under this Agreement
shall be in writing and mailed to the post office address of the
Party intended to receive the same, as follows:
TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY
P.O. BOX 2511
HOUSTON, TX 77252-2511
ATTENTION: DIRECTOR, TRANSPORTATION CONTROL
SHIPPER:
NOTICES: COLONIAL GAS CO
40 MARKET STREET
P.O. BOX 3064
LOWELL, MA 01853-3064
ATTENTION: MARTIN DEBRUIN
BILLING: COLONIAL GAS CO
40 MARKET STREET
P.O. BOX 3064
LOWELL, MA 01853-3064
ATTENTION: MARTIN DEBRUIN
or to such other address as either Party shall designate by
formal written notice to the other.
ARTICLE XIV
ASSIGNMENTS
14.1 Either Party may assign or pledge this Agreement and all
rights and obligations hereunder under the provisions of
any mortgage, deed of trust, indenture, or other instrument
which it has executed or may execute hereafter as security
for indebtedness. Either Party may, without relieving
itself of its obligation under this Agreement, assign any
of its rights hereunder to a company with which it is
affiliated. Otherwise, Shipper shall not assign this
Agreement or any of its rights hereunder, except in accord
with Article III, Section 11 of the General Terms and
Conditions of Transporter's FERC Gas Tariff.
14.2 Any person which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an
entirety, of either Party hereto shall be entitled to the
rights and shall be subject to the obligations of its
predecessor in interest under this Agreement.
ARTICLE XV
MISCELLANEOUS
15.1 The interpretation and performance of this Agreement shall
be in accordance with and controlled by the laws of the
State of Texas, without regard to the doctrines governing
choice of law.
15.2 If any provisions of this Agreement is declared null and
void, or voidable, by a court of competent jurisdiction,
then that provision will be considered severable at either
Party's option; and if the severability option is
exercised, the remaining provisions of the Agreement shall
remain in full force and effect.
15.3 Unless otherwise expressly provided in this Agreement or
Transporter's Gas Tariff, no modification of or supplement
to the terms and provisions stated in this agreement shall
be or become effective until Shipper has submitted a
request for change through the TENN-SPEED 2 System and
Shipper has been notified through TENN-SPEED 2 of
Transporter's agreement to such change.
15.4 Exhibit "A" attached hereto is incorporated herein by
reference and made a part hereof for all purposes.
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement
to be duly executed as of the date first hereinabove written.
"TRANSPORTER"
TENNESSEE GAS PIPELINE COMPANY
BY:___________________________
Agent and Attorney-in-Fact
DATE:_________________________
"SHIPPER"
COLONIAL GAS COMPANY
BY:____________________________
TITLE: ________________________
DATE: _________________________
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
EXHIBIT "A"
AMENDMENT #0 TO GAS TRANSPORTATION AGREEMENT
DATED June 1, 1995
BETWEEN
TENNESSEE GAS PIPELINE COMPANY
AND
COLONIAL GAS CO
COLONIAL GAS CO
EFFECTIVE DATE OF AMENDMENT: June 1, 1995
RATE SCHEDULE: FT-A
SERVICE PACKAGE: 10778
SERVICE PACKAGE TQ: 16,083 Dth
INTERCONNECT
METER METER NAME PARTY NAME COUNTY ST ZONE R/D LEG
020578 PENN-NFG- NATIONAL FUEL POTTER PA 04 R 300
ANDREWS GAS SUPPLY
SETTLEMENT CORP
SA
020139 COLONIAL- COLONIAL GAS MIDDLE- MA 06 D 200
TEWKSBURY CO SEX
MASS
INTERCONNECT
METER METER NAME PARTY NAME METER-TQ BILLABLE-TQ
020578 PENN-NFG- NATIONAL FUEL 16,083 16,083
ANDREWS GAS SUPPLY
SETTLEMENT CORP
SA
Total Receipt TQ: 16,083 16,083
020139 COLONIAL- COLONIAL GAS 16,083 16,083
TEWKSBURY CO
MASS
NUMBER OF RECEIPT POINTS AFFECTED: 1
NUMBER OF DELIVERY POINTS AFFECTED: 1
Note: Exhibit "A" is a reflection of the contract and all amendments
as of the amendment effective date.
[END OF EXHIBIT 10rr TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 10ss TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1995]
Tennessee Gas Pipeline 1010 Milam Street
A Tenneco Company P.O. Box 2511
Houston, Texas 77252-2511
(713) 757-2131
July 21, 1995
Mr. John P. Harrington
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
Re: Amendment No. 1 to
Gas Storage Contract
Dated December 1, 1994
Service Package No. 524
Dear John:
TENNESSEE GAS PIPELINE COMPANY (TENNESSEE) AND COLONIAL GAS
COMPANY (COLONIAL) agree to amend the above referenced gas
storage contract effective July 1, 1995, to increase the
Maximum Daily Withdrawal Quantity (MDWQ) when Shipper's
storage balance is equal to or less than 30% of the Maximum
Storage quantity (MSQ) and 20% of the MSQ, respectively,
as reflected in the attached Exhibit A-1 and as described
below.
The parties agree to amend Article I of the subject gas storage
contract as follows:
Following the commencement of services hereunder, in accordance
with the terms of Transporter's Rate Schedule FS, and of
this Agreement, Transporter shall receive for injection for
Shipper's account a daily quantity of gas up to Shipper's
Maximum Injection Quantity of 7,306 dekatherms (Dth) and
Maximum Storage Quantity (MSQ) of 1,095,830 (Dth) (on a
cumulative basis) and on demand shall withdraw from Shipper's
storage account and deliver to Shipper a daily quantity of
gas up to Shipper's Maximum Daily Withdrawal Quantity (MDWQ)
of 14,150 Dth; provided however, that when Shipper's storage
balance is equal to or less than 30% of the MSQ but greater
than 20% of the MSQ, the Maximum Daily Withdrawal Quantity shall
be 12,065 Dth; and provided further, that when Shipper's
storage balance is less than or equal to 20% of the MSQ, the
Maximum Daily Withdrawal Quantity shall be 7,670 Dth. For
demand charge purposes, the MDWQ for balances greater than 30%
of the MSQ shall be used.
Except as amended herein, all terms and provisions of the above
referenced gas storage contract shall remain in full force and
effect as written.
If the foregoing is in accordance with your understanding of our
agreement, please so indicate by signing and returning both
originals of this letter. Upon Tennessee's execution, an
original will be forwarded to you for your files.
Should you have any questions, please do not hesitate to contact
me at (713) 757-5125.
Sincerely,
/s/ John Templet
John Templet
Account Manager
ACCEPTED AND AGREED TO
This______ day of _________, 1995.
TENNESSEE GAS PIPELINE COMPANY
By:/s/ [Illegible]
ACCEPTED AND AGREED TO
This_____ day of _________, 1995.
COLONIAL GAS COMPANY
By /s/ John P. Harrington
Title: Senior Vice President - Gas Supply
Date: 7-27-95
GAS STORAGE SERVICE AGREEMENT
EXHIBIT "A-1"
SHOWING REQUESTED CHANGES
AMENDMENT #1 TO GAS STORAGE CONTRACT
DATED December 1, 1994
BETWEEN
TENNESSEE GAS PIPELINE COMPANY
AND
COLONIAL GAS COMPANY
SERVICE PACKAGE MSQ: 1,095,830 Dth
MAXIMUM DAILY INJECTION QUANTITY: 7,306
MAXIMUM DAILY WITHDRAWAL QUANTITY (MDWQ):
STORAGE BALANCE STORAGE BALANCE MAXIMUM DAILY WITH-
FROM DTH TO DTH DRAWAL QUANTITY DTH
328,750 1,095,830 14,150 Ratchet 0
219,167 328,749 12,065 Ratchet 1
0 219,166 7,670 Ratchet 2
SERVICE POINT: Compressor Station 313
INJECTION METER: 060018 TGP-NORTHERN STORAGE INJECTION
WITHDRAWAL METER: 070018 TGP-NORTHERN STORAGE WITHDRAWAL
METER METER NAME COUNTY ST ZONE I/W LEG
060018 TGP-NORTHERN POTTER PA 04 I 300
STORAGE INJECTION
070018 TGP-NORTHERN POTTER PA 04 W 300
STORAGE WITHDRAWAL
STORAGE STORAGE MDIQ
METER METER NAME BALANCE FROM BALANCE TO MDWQ
080018 TGP-NORTHERN 7,306
STORAGE
INJECTION
070018 TGP-NORTHERN 328,750 1,095,830 14,150 Ratchet 0
STORAGE 219,167 328,749 12,065 Ratchet 1
WITHDRAWAL 0 219,166 7,670 Ratchet 2
SERVICE PACKAGE 524
GAS STORAGE SERVICE CONTRACT
This Contract is made as of the 1st day of December 1994, by
and between TENNESSEE GAS PIPELINE COMPANY, a Delaware
corporation herein called "Transporter," and COLONIAL GAS CO a
MASSACHUSETTS Corporation, herein called "Shipper." Transporter
and Shipper collectively shall be referred to herein as the
"Parties."
ARTICLE I - SCOPE OF AGREEMENT
[SEE AMENDMENT NO. 1 EFFECTIVE JULY 1, 1995]
ARTICLE II - SERVICE POINT
The point or points at which the gas is to be tendered for
delivery by Transporter to Shipper under this Agreement shall be
at the storage service point at Transporter's Compressor Station
313.
ARTICLE III - PRICE
1.Shipper agrees to pay Transporter for all natural gas storage
service furnished to Shipper hereunder, including compensation
for system fuel and losses, at Transporter's legally effective
rate or at any effective superseding rate applicable to the
type of service specified herein. Transporter's present
legally effective rate for said service is contained in
Transporter's Tariff as filed with the Federal Energy
Regulatory Commission.
2.Shipper agrees to reimburse Transporter for any filing or
similar fees, which have not been previously paid by Shipper,
which Transporter incurs in rendering service hereunder.
3.Shipper agrees that Transporter shall have the unilateral
right to file with the appropriate regulatory authority and
make changes effective in (a) the rates and charges applicable
to service pursuant to Transporter's Rate Schedule FS, (b) the
rate schedule(s) pursuant to which service hereunder is
rendered, or (c) any provision of the General Terms and
Conditions applicable to those rate schedules. Transporter
agrees that Shipper may protest or contest the aforementioned
filings, or may seek authorization from duly constituted
regulatory authorities for such adjustment of Transporter's
existing FERC Gas Tariff as may be found necessary to assure
Transporter just and reasonable rates.
ARTICLE IV - INCORPORATION OF RATE SCHEDULE AND TARIFF PROVISIONS
This agreement shall be subject to the terms of Transporter's
Rate Schedule FS, as filed with the Federal Energy Regulatory
Commission, together with the General Terms and Conditions
applicable thereto (including any changes in said Rate Schedule
or General Terms and Conditions as may from time to time be filed
and made effective by Transporter).
ARTICLE V - TERM OF AGREEMENT
This Agreement shall be effective as of the December 1, 1994
and shall remain in force and effect until November 1,
2000, ("Primary Term") and on a month to month basis
thereafter unless terminated by either Party upon at least thirty
(30) days prior written notice to the other Party; provided,
however, that if the Primary Term is one year or more, then
unless Shipper elects upon one year's prior written notice to
Transporter to request a lesser extension term, the Agreement
shall automatically extend upon the expiration of the Primary
Term for a term of five years; and shall automatically extend for
successive five year terms thereafter unless Shipper provides
notice described above in advance of the expiration of a
succeeding term; provided further, if the FERC or other
governmental body having jurisdiction over the service rendered
pursuant to this Agreement authorizes abandonment of such
service, this Agreement shall terminate on the abandonment date
permitted by the FERC or such other governmental body.
This Agreement will terminate upon notice from Transporter in the
event Shipper fails to pay all of the amount of any bill for
service rendered by Transporter hereunder in accordance with the
terms and conditions of Article VI of the General Terms and
Conditions of Transporters Tariff.
ARTICLE VI - NOTICES
Except as otherwise provided in the General Terms and Conditions
applicable to this Agreement, any notice under this Agreement
shall be in writing and mailed to the post office address of the
Party intended to receive the same, as follows:
TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY
P. O. Box 2511
Houston, Texas 77252-2511
Attention: Transportation Services
SHIPPER:
NOTICES: COLONIAL GAS CO
40 MARKET STREET
LOWELL, MA 01852
Attention: JOHN P. HARRINGTON
BILLING: COLONIAL GAS CO
40 MARKET STREET
P.O. BOX 3064
LOWELL, MA 01853-3064
Attention: MARTIN DEBRUIN
or to such other address as either Party shall designate by
formal written notice to the other.
ARTICLE VII - ASSIGNMENT
Any company which shall succeed by purchase, merger or
consolidation to the properties, substantially as an entirety, of
Transporter or of Shipper, as the case may be, shall be entitled
to the rights and shall be subject to the obligations of its
predecessor in title under this Agreement. Otherwise no
assignment of the Agreement or any of the rights or obligations
thereunder shall be made by Shipper, except pursuant to the
General Terms and Conditions of Transporter's FERC Gas Tariff.
It is agreed, however, that the restrictions on assignment
contained in this Article shall not in any way prevent either
Party to the Agreement from pledging or mortgaging its rights
thereunder as security for its indebtedness.
ARTICLE VIII - MISCELLANEOUS
8.1 The interpretation and performance of this Agreement shall
be in accordance with and controlled by the laws of the
State of Texas, without regard to doctrines governing
choice of law.
8.2 If any provision of this Agreement is declared null and
void, or voidable, by a court of competent jurisdiction,
then that provision will be considered severable at either
Party's option; and if the severability option is
exercised, the remaining provisions of the Agreement shall
remain in full force and effect.
8.3 Unless otherwise expressly provided in this Agreement or
Transporter's Tariff, no modification of or supplement to
the terms and provisions stated in this Agreement shall be
or become effective, until Shipper has submitted a request
for change through the TENN-SPEED 2 System and Shipper has
been notified through TENN-SPEED 2 of Transporter's
agreement to such change.
8.4 Transporter and Shipper agree that this Agreement, as of the
date hereof, shall supersede and cancel the Gas Storage
Contract Number 524, dated September 1, 1993 between the
Parties hereto.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be
duly executed by their authorized agents.
TENNESSEE GAS PIPELINE COMPANY
BY:___________________________
RANDALL G. SCHORE
Agent and Attorney-in-fact
DATE:_________________________
COLONIAL GAS CO
BY: /s/ John P. Harrington
TITLE: Vice President - Gas Supply
DATE: 11-28-94
GAS STORAGE SERVICE AGREEMENT
EXHIBIT "A"
TO FIRM GAS STORAGE SERVICE AGREEMENT
DATED December 1, 1994
BETWEEN
TENNESSEE GAS PIPELINE COMPANY
AND
COLONIAL GAS COMPANY
[SUPERSEDED BY AMENDMENT NO. 1 EFFECTIVE JULY 1, 1995]
[END OF EXHIBIT 10ss TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 10tt TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
Contract No. R-480-01
AMENDMENT
TO GAS TRANSPORTATION CONTRACT
FOR FIRM SERVICE
THIS AMENDMENT, made and entered into this 1st day of
September 1995, by and between IROQUOIS GAS TRANSMISSION SYSTEM,
L.P., a Delaware limited partnership ("Transporter"), and
COLONIAL GAS COMPANY, a Massachusetts Corporation ("Shipper").
WHEREAS, Transporter and Shipper are parties to a Gas
Transportation Contract for Firm Service dated February 7, 1991,
designated as Transporter's Contract No. R-480-01, ("Contract
01") which provides for transportation service by Transporter of
up to 2,000 Mcf per day of natural gas on behalf of Shipper
between the interconnection points on Transporter's natural gas
system at Waddington, New York and Wright, New York for the
period November 1, 1991 to November 1, 2011;
WHEREAS, Transporter and Shipper are parties to a Gas
Transportation Contract for Firm Service dated November 25, 1991,
designated as Transporter's Contract No. R-480-03, ("Contract
03") which provides for transportation service by Transporter of
up to 4,000 Mcf per day of natural gas on behalf of Shipper
between the interconnection points on Transporter's natural gas
system at Waddington, New York and Wright, New York for the
period December 1, 1991 until a superceding agreement takes
effect;
WHEREAS, Transporter and Shipper mutually desire to amend
Contract 01 to provide for additional transportation service of
4,000 Mcf per day under the same terms and conditions as provided
in Contract 01 for a revised total contract quantity of 6,000 Mcf
per day.
WHEREAS, Transporter and Shipper mutually desire to
terminate Contract 03 under the same terms and conditions as
provided in Contract 03 under Article V, Section 3.
NOW THEREFORE, in consideration of the premises and the
mutual covenants herein contained, Transporter and Shipper hereby
agree to (1) amend the Contract 01 by modifying the Maximum Input
Quantity and Maximum Equivalent Quantity of Schedule 1 and
Schedule 2 to read "6,000 Mcf/d" and "The thermal equivalent of
6,000 Mcf/d", respectively; and (2) terminate Contract 03 as of
September 1, 1995. The amendment to Contract 01 shall be
effective as of September 1, 1995. All other terms and
conditions of Contract 01 shall remain the same.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be duly executed as of the date first above written.
IROQUOIS GAS TRANSMISSION SYSTEM, L.P.
By Its Agent
ATTEST: IROQUOIS PIPELINE OPERATING COMPANY
/s/ Joan Pastore /s/ Bernard M. Otis
Bernard M. Otis
Vice President, Transmission
ATTEST:
/s/ Joan Pastore /s/ Paul Bailey
Paul Bailey
Vice President, Finance &
Administration
ATTEST: COLONIAL GAS COMPANY
/s/ Susan Mousseau /s/ John P. Harrington
John P. Harrington
Senior Vice President - Gas Supply
and Assistant to the President
[END OF EXHIBIT 10tt TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 10uu TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
Contract No. 95135
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this
1st day of December, 1995, by and between Algonquin Gas
Transmission Company, a Delaware Corporation (herein called
"Algonquin"), and Colonial Gas Company, (herein called
"Customer" whether one or more persons).
In consideration of the premises and of the mutual covenants
herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations
hereof and of Algonquin's Rate Schedule AFT-1,
Algonquin agrees to receive from or for the account of
Customer for transportation on a firm basis quantities
of natural gas tendered by Customer on any day at the
Point(s) of Receipt; provided, however, Customer shall
not tender without the prior consent of Algonquin, at
any Point of Receipt on any day a quantity of natural
gas in excess of the applicable Maximum Daily Receipt
Obligation for such Point of Receipt plus the
applicable Fuel Reimbursement Quantity; and provided
further that Customer shall not tender at all Point(s)
of Receipt on any day or in any year a cumulative
quantity of natural gas, without the prior consent of
Algonquin, in excess of the following quantities of
natural gas plus the applicable Fuel Reimbursement
Quantities:
Maximum Daily Transportation Quantity 4,000 MMBtu
Maximum Annual Transportation Quantity 488,000 MMBtu
1.2 Algonquin agrees to transport and deliver to or
for the account of Customer at the Point(s) of Delivery
and Customer agrees to accept or cause acceptance of
delivery of the quantity received by Algonquin on any
day, less the Fuel Reimbursement Quantities; provided,
however, Algonquin shall not be obligated to deliver at
any Point of Delivery on any day a quantity of natural
gas in excess of the applicable Maximum Daily Delivery
Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective as of the
date set forth hereinabove and shall continue in effect
for a term ending on March 31, 1996. The term of this
agreement shall not be extended beyond March 31, 1996.
Upon expiration of this Agreement, Customer shall have
no rights providing for the avoidance of pregranted
abandonment.
2.2 This Agreement may be terminated at any time by
Algonquin in the event Customer fails to pay part or
all of the amount of any bill for service hereunder and
such failure continues for thirty days after payment is
due; provided Algonquin gives ten days prior written
notice to Customer of such termination and provided
further such termination shall not be effective if,
prior to the date of termination, Customer either pays
such outstanding bill or furnishes a good and
sufficient surety bond guaranteeing payment to
Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service
pending the resolution of a disputed bill if Customer
complies with the billing dispute procedure currently
on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services
rendered hereunder and for the availability of such
service under Algonquin's Rate Schedule AFT-1 as filed
with the Federal Energy Regulatory Commission and as
the same may be hereafter revised or changed. The rate
to be charged Customer for transportation hereunder
shall not be more than the maximum rate under Rate
Schedule AFT-1, nor less than the minimum rate under
Rate Schedule AFT-1.
3.2 This Agreement and all terms and provisions
contained or incorporated herein are subject to the
provisions of Algonquin's applicable rate schedules and
of Algonquin's General Terms and Conditions on file
with the Federal Energy Regulatory Commission, or other
duly constituted authorities having jurisdiction, and
as the same may be legally amended or superseded, which
rate schedules and General Terms and Conditions are by
this reference made a part hereof.
ARTICLE III
RATE SCHEDULE
3.3 Customer agrees that Algonquin shall have the
unilateral right to file with the appropriate
regulatory authority and make changes effective in (a)
the rates and charges applicable to service pursuant to
Algonquin's Rate Schedule AFT-1, (b) Algonquin's Rate
Schedule AFT-1, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and
Conditions applicable to Rate Schedule AFT-1.
Algonquin agrees that Customer may protest or contest
the aforementioned filings, or may seek authorization
from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as
may be found necessary to assure that the provisions in
(a), (b), or (c) above are just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of
Customer hereunder shall be received at the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt
pressure obligation indicated for each such Primary Point of
Receipt. Natural gas to be received by Algonquin for the
account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.2 of Rate
Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of
Customer hereunder shall be delivered on the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery
pressure obligation indicated for each such Primary Point of
Delivery. Natural gas to be delivered by Algonquin for the
account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.4 of Rate
Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Algonquin's FERC Gas Tariff,
any notice, request, demand, statement, bill or payment
provided for in this Agreement, or any notice which any
party may desire to give to the other, shall be in writing
and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post
office address of the parties hereto, as the case may be, as
follows:
(a) Algonquin: 1284 Soldiers Field Road
Boston, MA 02135
Attn: John J. Mullaney
Vice President, Marketing
(b) Customer: 40 Market Street
Lowell, MA 01852
Attn: John P. Harrington
Sr. Vice President, Gas Supply
or such other address as either party shall designate by
formal written notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be
in accordance with the laws of the Commonwealth of
Massachusetts, excluding conflicts of law principles that
would require the application of the laws of a different
jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede
the following agreements between the parties hereto, except
that in the case of conversions from former Rate Schedules
F-2 and F-3, the parties' obligations under Article II of
the service agreements pertaining to such rate schedules
shall continue in effect. Not Applicable.
IN WITNESS WHEREOF, the parties hereto have caused this
Agreement to be signed by their respective agents thereunto
duly authorized, the day and year first above written.
ALGONQUIN GAS TRANSMISSION COMPANY
By: /s/ John J. Mullaney/rsh
Title: Vice President, Marketing
COLONIAL GAS COMPANY
By: /s/ John P. Harrington
Title: Senior Vice President-Gas Supply
Exhibit A
Point(s) of Receipt
Dated: December 1, 1995
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin)
and Colonial Gas Company (Customer)
concerning Point(s) of Receipt.
Primary
Point of Maximum Daily Maximum
Receipt Receipt Obligation Receipt Pressure
Dey Street, RI 4,000 MMBtu Algonquin's
Line Pressure
as may exist
from time to time.
Signed for Identification
Algonquin: /s/ John J. Mullaney/rsh
Customer: /s/ John P. Harrington
[END OF EXHIBIT 10uu TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1995 1994 1993
Operating Revenues $164,649 $166,259 $166,261
Cost of gas sold 83,631 87,458 90,915
Operating Margin 81,018 78,801 75,346
Operating Expenses:
Operations 31,309 33,004 32,957
Maintenance 4,401 5,074 4,726
Depreciation and amortization 10,225 9,235 6,831
Local property taxes 3,020 2,740 2,496
Other taxes 2,130 2,182 2,055
Restructuring charge - 3,185 -
Total Operating Expenses 51,085 55,420 49,065
Income Taxes:
Federal income tax 6,912 4,806 6,111
State franchise tax 1,447 1,058 1,280
Total Income Taxes 8,359 5,864 7,391
Utility Operating Income 21,574 17,517 18,890
Other Operating Income (Expense):
Truck transportation revenues 7,576 12,066 7,558
Truck transportation expenses,
including income taxes and interest (6,972) (10,579) (7,163)
Truck Transportation Net Income 604 1,487 395
Other, net of income taxes (8) (151) (186)
Total Other Operating Income 596 1,336 209
Non-Operating Income, Net of Income 864 565 1,064
Taxes
Income Before Interest and Debt 23,034 19,418 20,163
Expense
Interest and Debt Expense 9,270 8,409 8,141
Net Income $13,764 $11,009 $12,022
Average Common Shares Outstanding 8,294 8,119 7,931
Income per Average Common Share $1.66 $1.36 $1.52
Dividends Paid per Common Share $1.275 $1.255 $1.235
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF INCOME]
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1995 1994
Utility Property:
At original cost $308,191 $287,158
Accumulated depreciation (72,636) (65,473)
Net Utility Property 235,555 221,685
Non-Utility Property - Net 5,036 3,479
Net Property 240,591 225,164
Capital Leases - Net 2,253 2,948
Current Assets:
Cash and cash equivalents 7,541 9,026
Accounts receivable 19,069 13,846
Allowance for doubtful accounts (2,205) (1,670)
Accrued utility revenues 8,924 6,148
Unbilled gas costs 9,688 12,178
Fuel inventory - at average cost 10,516 12,959
Materials and supplies - at average 3,132 3,537
cost
Prepayments and other current assets 4,337 9,544
Total Current Assets 61,002 65,568
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 10,562 11,471
Unrecovered demand side management costs 4,977 3,120
Unrecovered environmental costs incurred 4,761 4,577
Unrecovered environmental costs accrued 2,300 3,800
Unrecovered pension costs 3,917 2,607
Unrecovered transition costs accrued 3,600 4,700
Excess cost of investments over net assets 2,798 2,798
acquired
Other 5,660 4,595
Total Deferred Charges and Other 38,575 37,668
Assets
Total Assets $342,421 $331,348
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1995 1994
Capitalization:
Common Equity:
Common Stock $27,863 $27,397
Premium on Common Stock 51,447 49,211
Retained earnings 25,760 22,567
Total Common Equity 105,070 99,175
Long-Term Debt 75,418 77,923
Total Capitalization 180,488 177,098
Capital Lease Obligations 1,359 2,237
Current Liabilities:
Current maturities of long-term debt 6,141 8,449
Current capital lease obligations 894 712
Notes payable 61,835 49,500
Gas inventory purchase obligations 12,340 13,860
Accounts payable 12,150 9,635
Accrued interest 1,065 1,085
Pipeline refunds due customers 1,310 2,289
Current deferred income taxes 314 2,139
Other current liabilities 5,617 3,713
Total Current Liabilities 101,666 91,382
Deferred Credits and Reserves:
Deferred income taxes - Funded 32,299 29,373
Deferred income taxes - Unfunded 10,562 11,471
Deferred income taxes - Due customers 112 378
Accrued environmental costs 2,300 3,800
Accrued transition costs 3,600 4,700
Unamortized investment tax credits 3,940 4,215
Pension reserve 4,929 5,510
Other deferred credits and reserves 1,166 1,184
Total Deferred Credits and Reserves 58,908 60,631
Total Capitalization and Liabilities $342,421 $331,348
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED BALANCE SHEETS]
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1995 1994 1993
Cash Flows From Operating Activities:
Net Income $13,764 $11,009 $12,022
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 11,211 10,150 7,703
Deferred income taxes 1,159 3,555 2,139
Amortization of investment tax credits (275) (234) (255)
Provision for uncollectible accounts 1,829 1,803 2,102
Other, net 973 811 190
28,661 27,094 23,901
Changes in current assets and
liabilities:
Accounts receivable (6,517) 495 773
Accrued utility revenues (2,776) 1,022 (1,678)
Unbilled gas costs 2,490 4,581 2,122
Fuel inventory 2,443 758 (285)
Materials and supplies 405 275 56
Prepayments and other current assets 5,207 (3,290) 2,055
Accounts payable 2,515 (2,526) (382)
Accrued interest (20) 68 (7)
Pipeline refunds due customers (979) 213 620
Accrued pipeline charges - (305) (606)
Current deferred income taxes (1,825) (73) (2,111)
Other current liabilities 1,904 (13) 933
Net Cash Provided by Operating 31,508 28,299 25,391
Activities
Cash Flows From Investing Activities:
Utility capital expenditures (24,096) (28,195) (25,703)
Non-utility capital expenditures (1,974) (876) (453)
Sale of non-utility assets - - 586
Change in deferred accounts (2,077) (716) (354)
Net Cash Used in Investing Activities (28,147) (29,787) (25,924)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,571) (10,187) (9,793)
Issuance of Common Stock 2,702 4,070 4,283
Issuance of long-term debt, net of
issuance costs 19,685 741 -
Retirement of long-term debt, (27,477) (5,119) (1,500)
including premiums
Change in notes payable 12,335 16,900 8,100
Change in gas inventory purchase (1,520) (1,373) 492
obligations
Net Cash (Used in) Provided by (4,846) 5,032 1,582
Financing Activities
Net (Decrease) Increase in Cash and (1,485) 3,544 1,049
Cash Equivalents
Cash and Cash Equivalents at Beginning 9,026 5,482 4,433
of Year
Cash and Cash Equivalents at End $ 7,541 $ 9,026 $ 5,482
of Year
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 9,867 $ 9,283 $ 8,891
Income and state franchise taxes $ 3,444 $ 7,282 $ 4,939
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF CASH FLOWS]
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1995 1994 1993
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,367 in 1995, 8,227 in 1994,
and 8,030 in 1993
Beginning of year $27,397 $26,739 $26,122
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (140 shares
in 1995, 197 shares in 1994 and 186
shares in 1993) 466 658 617
End of year $27,863 $27,397 $26,739
Premium on Common Stock
Beginning of year $49,211 $45,799 $42,133
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 2,236 3,412 3,666
End of year $51,447 $49,211 $45,799
Retained Earnings
Beginning of year $22,567 $21,745 $19,516
Net income 13,764 11,009 12,022
Cash dividends on Common Stock ($1.275
a share in 1995, $1.255 a share in
1994 and $1.235 a share in 1993) (10,571)(10,187) (9,793)
End of year $25,760 $22,567 $21,745
Total Common Equity $105,070 $99,175 $94,283
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF COMMON EQUITY]
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A: Summary of Significant Accounting Policies
Nature of Operations - Colonial Gas Company, a Massachusetts
corporation formed in 1849, is primarily a regulated natural gas
distribution utility. The Company serves over 141,000 utility
customers in 24 municipalities located northwest of Boston and on
Cape Cod. Through its subsidiary, Transgas Inc., the Company also
provides over-the-road transportation of liquefied natural gas,
propane, and other commodities.
Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its
subsidiaries. All material intercompany items have been eliminated
in consolidation.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
Utility Regulation - The Company's utility operations are subject
to regulation by the Massachusetts Department of Public Utilities
(DPU) with respect to rates charged for natural gas sales and
transportation, among other things. The Company's policies conform
with generally accepted accounting principles, as applied to
regulated public utilities.
Utility Property and Non-Utility Property - Utility property and
non-utility property are stated at original cost, including labor,
materials, taxes and overheads. The amount of interest capitalized
as a component of construction overheads amounted to $568,000,
$294,000 and $227,000 in 1995, 1994 and 1993, respectively.
The original cost of depreciable utility property retired,
together with the cost of removal, net of salvage, is charged to
accumulated depreciation. Depreciation applicable to the Company's
utility property in service is calculated in accordance with
depreciation rates as approved by the DPU. The composite
depreciation rate which was approximately 2.91% through October
31, 1993, was increased to approximately 3.77% effective with a
rate increase as approved by the DPU on November 1, 1993. The
composite depreciation rate is applied to the utility property
balance at the beginning of each year. Depreciation on non-utility
property is computed by various methods.
Operating Revenues - Operating revenues are accrued based upon the
amount of gas delivered to utility customers through the end of
the accounting period. Accrued utility revenues of $8,924,000 and
$6,148,000, as reported in the Consolidated Balance Sheets at
December 31, 1995 and 1994, respectively, represent the accrual of
unbilled operating revenues net of related gas costs. The
Company's policy is to record lost margins and financial
incentives relating to the Company's demand side management (DSM)
programs as revenue when earned by the Company and approved by the
DPU. In September 1995, the Company received approval from the DPU
to recover financial incentives and lost margins associated with
the residential DSM programs. Based on this approval, the Company
recorded $900,000 of lost margins and $220,000 of financial
incentives as revenue in 1995. No lost margins or incentives for
the commercial DSM programs have been recorded to date.
Unbilled Gas Costs - The Company charges or credits its utility
customers for increases or decreases in gas costs from those
reflected in its base tariffs by applying a cost of gas adjustment
clause (CGAC). In accordance with the CGAC, any under or over
recoveries of gas costs are charged or credited to the unbilled
gas cost account and recorded as a current asset or liability.
Such under or over recoveries are collected or refunded, with
interest accrued at the prime rate, in subsequent periods.
Pipeline Refunds Due Customers - The Company periodically receives
refunds from interstate pipeline companies related to rate
adjustments ordered by the Federal Energy Regulatory Commission
(FERC). Refunds are returned to utility customers under methods
approved by the DPU.
Excess Cost of Investments over Net Assets Acquired - This asset
arose principally from the pre-1971 acquisitions of utility
operations. No amortization has been provided since, in the
opinion of management, there has been no diminution in value of
the applicable investments.
Income Taxes - The Company records deferred income taxes for the
income tax effect of the difference between book and tax
depreciation and all other temporary book and tax differences, in
accordance with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" (SFAS 109). Unamortized
investment tax credits, which were allowed under Federal income
tax laws prior to 1987, have been deferred and are being amortized
as a credit to income tax expense over the estimated service lives
of the corresponding assets.
Interest and Debt Expense - Interest and debt expense includes
interest on long-term debt, interest on short-term notes payable
and regulatory interest. As approved by the DPU, regulatory
interest is interest income credited on regulatory assets or
interest expense charged on regulatory liabilities.
Pension Plans - The Company and its subsidiaries have defined
benefit pension plans covering substantially all employees. These
include two qualified union plans, one qualified plan for non-
union employees, and various unqualified individual retirement
agreements covering certain key employees and retirees. The
Company's funding policy is to contribute annually an amount at
least equal to the normal cost plus a 30-year amortization of the
unfunded actuarially calculated accrued liability and additional
contributions to fund the unqualified individual retirement
agreements.
Cash and Cash Equivalents - For the purposes of the Consolidated
Balance Sheets and Statements of Cash Flows, the Company considers
cash investments with an original maturity of three months or less
to be cash equivalents.
Fair Value of Financial Instruments - In accordance with Statement
of Financial Accounting Standards No. 107 "Disclosures About Fair
Values of Financial Instruments", the fair value amounts are
disclosed below. These fair value amounts are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.
The carrying amount of cash and cash equivalents and short-
term debt approximates fair value. The fair value of long-term debt
is estimated based on the rates available to the Company at the end
of each respective year for debt of the same remaining maturities.
The carrying amount of long-term debt (including current
maturities) was $81,559,000 and $86,372,000 as of December 31, 1995
and 1994, respectively. The fair value of long-term debt was
$89,724,000 and $88,425,000 as of December 31, 1995 and 1994,
respectively.
Under current regulatory treatment, any premiums paid to
refinance long-term debt, would be recovered over the life of the
new debt, and would not have a significant impact on the Company's
results of operations.
Reclassifications - Reclassifications are made periodically to
previously issued financial statements to conform to the current
year presentation.
New Accounting Standard - In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards
No. 121 "Accounting for the Impairment of Long-Lived Assets and
Long-Lived Assets to be Disposed Of", which will be effective for
the Company's fiscal year ending December 31, 1996. This statement
requires the Company to review long-lived assets for impairment
whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. The Company
intends to adopt this statement prospectively. The impact of this
standard is not expected to have a material impact on the
Company's financial condition or results of operations.
Note B: Federal Income Tax
The Company records deferred income taxes for the income tax
effect of the difference between book and tax depreciation and all
other temporary book and tax differences, in accordance with SFAS
109. Prior to October 1981 as approved by the DPU, the Company did
not record deferred income taxes but rather "flowed through" tax
benefits to utility customers. At December 31, 1995, the Company
has a liability of $10,562,000 on the Consolidated Balance Sheet
as Deferred Income Taxes - Unfunded and a corresponding
unrecovered deferred asset. The liability represents the tax
effect of pre-1981 timing differences for which deferred income
taxes had not been provided, increased in accordance with SFAS 109
for the tax effect of future revenue requirements. The Company is
recovering these unfunded deferred taxes from utility customers
over the remaining book life of utility property.
The Company has a liability (Deferred Income Taxes- Due
Customers) of $112,000 at December 31, 1995, representing the
amount of pre-July 1, 1987 deferred income taxes that were
recorded in excess of the Federal statutory income tax rate of
34%. This liability is being returned to utility customers over
the remaining book life of utility property. This liability is
also charged for any Federal income taxes at rates above 34%.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1995 1994 1993
Charged (credited) to operations:
Current $6,455 $2,157 $5,191
Deferred:
Unbilled gas costs (1,523) (106) (1,753)
Accelerated depreciation 2,005 2,167 2,157
Demand side management costs (32) 1,115 -
Pension (38) (840) 141
Recovery of unfunded deferred taxes 398 398 556
Debt expense 848 (21) (20)
Transition costs (871) (55) -
Miscellaneous (57) 221 84
Amortization of investment tax (273) (230) (245)
credits
Total 6,912 4,806 6,111
Charged to other income 477 1,014 578
Total Federal income tax expense $7,389 $5,820 $6,689
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1995 1994 1993
Statutory Federal income tax rate 35% 35% 35%
Increases (reductions) in taxes
resulting from:
Amortization of investment tax (1) (1) (1)
credit
Recovery of unfunded deferred taxes 2 2 3
Miscellaneous items (1) (1) (1)
Effective Federal income tax rate 35% 35% 36%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1995 1994
Construction contributions $ 1,060 $ 1,117
Other 1,468 943
Total deferred tax assets 2,528 2,060
Accelerated depreciation (36,949) (34,698)
Cost of removal (2,554) (2,364)
Unbilled gas costs (315) (3,184)
Environmental response costs (1,865) (1,839)
Demand side management costs (1,764) (1,803)
Other (2,256) (1,155)
Total deferred tax liabilities (45,703) (45,043)
Total deferred taxes $(43,175) $(42,983)
Note C: Capital Stock
Pursuant to the Company's dividend reinvestment and common stock
purchase plan, shareholders can automatically reinvest their cash
dividends and can invest optional limited amounts of cash payments
in newly issued shares.
The Company has authorized and unissued 547,559 shares of Class
A Preferred Stock, $25 par value, of which 100,000 shares have
been designated a Junior Preferred Stock series and reserved for
issuance under the Rights Plan described below, and 370,000 shares
of Class B Preferred Stock, $1 par value.
A Shareholder Rights Plan provides one right ("Right") to
purchase one one-hundredth of a share of the Company's Series A-1
Junior Participating Preferred Stock, par value $25 per share, at
a price of $60 per share, subject to adjustment. The Rights expire
on December 1, 2003 and only become exercisable, or separately
transferable, 10 days after a person or group acquires, or
announces an intention to acquire, beneficial ownership of 20% or
more of the Company's Common Stock. The Rights are redeemable by
the Board at a price of $.01 per Right at any time prior to the
expiration of ten days after the acquisition by a person or group
of beneficial ownership of 20% or more of the Company's Common
Stock.
Note D: Retained Earnings
The Company's ability to pay dividends on its Common Stock from
retained earnings is restricted by the first mortgage bond
indenture and by the bank line of credit. Under the most
restrictive covenant, approximately $23,943,000 of retained
earnings was available to pay dividends on Common Stock as of
December 31, 1995.
Note E: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1995 1994
First mortgage bonds:
14.00% Series CC due 1999 $ - $ 500
8.86% Series CD due 2001 6,000 7,000
9.40% Series CE due 1997 10,000 15,000
10.25% Series CF due 2004 - 18,182
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
6.85% Series MTA-1 due 2025 10,000 -
6.45% Series MTA-2 due 2025 10,000 -
Total 81,000 85,682
Note payable 559 690
Less: Long-term debt due within (6,141) (8,449)
one year
Total long-term debt $75,418 $77,923
The aggregate amount of maturities and sinking fund requirements
for the years 1996, 1997, 1998, 1999, and 2000 are $6,141,000,
$6,152,000, $1,164,000, $21,102,000, and $1,000,000, respectively.
The first mortgage bonds are collateralized by utility property.
The Company's first mortgage bond indenture includes, among other
provisions, limitations on the issuance of long-term debt, leases
and the payment of dividends from retained earnings. The note
payable is collateralized by equipment.
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. It is anticipated that the remaining bonds under the MTN
program will be issued in several series over the next two years.
On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.
Note F: Short-Term Debt
In July 1994, the Company established a three-year bank line of
credit of $75 million with a consortium of four banks. The bank
line of credit allows the Company to borrow on a demand basis up
to $75 million, less whatever amount has been borrowed through the
Company's gas inventory trust (described below). The line of
credit allows the Company the option to borrow under four
alternative rates: prime rate, certificate of deposit rate,
eurodollar rate (LIBOR), and a competitive bid option. At December
31, 1995, the credit available under the bank line of credit was
$825,000. The weighted average interest rates for short-term debt
were 6.03% and 6.25% at December 31, 1995 and 1994, respectively.
The Company has an agreement with a single-purpose Massachusetts
trust, the Company's gas inventory trust, under which the Company
sells supplemental gas inventory to the trust at the Company's
cost. The Company's agreement with the trust requires it to
repurchase such inventory at cost when needed and reimburse the
trust for expenses incurred to finance the gas inventory. The
trust finances such purchases of inventory by borrowing under a
bank line of credit with a maximum borrowing commitment of $30
million that is complementary to and on similar terms as the
Company's bank line of credit described above. The DPU has
approved the inventory trust arrangement and has permitted the
cost of such gas inventory, including fees and financing costs, to
be recovered through the Company's CGAC. During 1995, 1994 and
1993 approximately $529,000, $504,000 and $390,000, respectively,
of financing costs were incurred by the trust.
Note G: Lease Obligations
The Company leases certain facilities and equipment used in its
operations. In accordance with accounting for regulated public
utilities, the Company has capitalized certain of these leases and
reflects lease payments as rental expense in the periods to which
they relate. This capitalization has no impact on the Company's
net income.
Assets held under capital leases amounted to approximately
$7,291,000 and $7,230,000 at December 31, 1995 and 1994,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $5,038,000 and $4,282,000
at December 31, 1995 and 1994, respectively.
The most significant agreements which meet the criteria for
capital lease classification are a lease which expires in 1998 for
a liquefied natural gas storage tank in South Yarmouth,
Massachusetts and a lease which expires in 2002 for office
facilities in Lowell, Massachusetts. Both leases have fair market
renewal options at the end of their initial terms.
Total rental expense for the years 1995, 1994 and 1993
approximated $1,429,000, $2,049,000 and $1,808,000, respectively.
At December 31, 1995, the future minimum payments (including
interest) under the Company's lease agreements are: $894,000 in
1996; $742,000 in 1997; $605,000 in 1998; $296,000 in 1999;
$254,000 in 2000; and $355,000 thereafter.
Note H: Employee Benefit Plans
Savings Plan - The Company sponsors an employee 401(k) Savings
Plan. The Company's matching contribution, exclusive of plan
administration costs, was $459,000, $387,000 and $418,000 for
1995, 1994 and 1993, respectively.
Pension Plans - The Company and its subsidiaries have various
defined benefit pension plans covering substantially all
employees.
Net periodic pension cost is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1995 1994 1993
Benefits earned during the period $ 836 $ 1,195 $ 1,031
Interest cost on projected 3,279 2,803 2,690
benefit obligation
Actual return on plan assets (5,515) 77 (2,656)
Net amortization and deferral 2,757 (2,657) 325
Net periodic pension cost $1,357 $1,418 $1,390
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1995 1994 1993
Weighted average discount rate 7.50% 8.50% 7.25%
Future compensation increases 4.00% 5.00% 5.00%
Expected long-term rate of return 9.00% 9.00% 9.00%
on assets
The funded status of the plans at December 31, 1995 and 1994 is as
follows:
1995 1994
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(28,993) $(10,388) $(21,897) $(8,544)
Nonvested (628) (869) (2,988) (563)
Accumulated (29,621) (11,257) (24,885) (9,107)
Due to recognition of
future salary increases (4,173) (88) (4,664) (42)
Total (33,794) (11,345) (29,549) (9,149)
Plan assets at fair 31,168 6,420 27,715 5,259
value
Projected benefit (2,626) (4,925) (1,834) (3,890)
obligation
in excess of
plan assets
Unrecognized net loss 1,758 1,232 (227) 513
(gain)
Unrecognized 1,572 1,247 2,059 1,430
transition amount
Unrecognized prior 347 1,493 448 706
service cost
Additional liability - (3,885) - (2,607)
accrued
Prepaid (accrued) $1,051 $(4,838) $ 446 $(3,848)
pension costs
Assets of the employee benefit plans are invested in domestic and
international equities, medium-term domestic fixed income
securities, international fixed income securities, real estate and
other short-term debt instruments.
Additional benefits upon retirement were given to 47 employees who
accepted the voluntary early retirement program in 1994. The
additional loss of $2,537,000 as a result of this program was
recorded as a restructuring charge in the fourth quarter of 1994.
Postretirement Life and Health Benefit Plan - The Company sponsors
a postretirement benefit plan that covers substantially all
employees. The plan provides medical, dental and life insurance
benefits. The plan is contributory for retirees, with respect to
postretirement medical and dental benefits; the plan is
noncontributory with respect to life insurance benefits.
During 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). Prior to
1993, expense was recognized when benefits were paid. In
accordance with SFAS 106, the Company began recording the cost for
this plan on an accrual basis in 1993. As permitted by SFAS 106,
the Company will record the transition obligation over a twenty-
year period. The Company's cost under this plan for 1995, 1994 and
1993 was $672,000, $694,000 and $817,000, respectively. A
regulatory asset of $431,000 was recorded in 1993, leaving a net
expense of $386,000. This regulatory asset represents the excess
of postretirement benefits on the accrual basis over the paid
amounts for the period of January 1, 1993 until November 1, 1993,
the effective date of the DPU's approval of the Company's new
rates. Currently, the DPU allows Massachusetts utilities to
recover the tax deductible portion of these postretirement
benefits.
Beginning in 1990, the Company has funded a portion of these
costs through the combination of a trust under Section 501(c)(9)
of the Internal Revenue Code and separate accounts of the trust
under Section 401(h) of the Internal Revenue Code. The Company is
currently funding an amount each year equal to the maximum tax
deductible amount.
The following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1995 and 1994:
(In Thousands) 1995 1994
Accumulated postretirement
benefit obligation:
Retirees $(3,816) $(2,416)
Fully eligible active plan (1,047) (1,457)
participants
Other active plan (1,275) (1,782)
participants
(6,138) (5,655)
Plan assets at fair value 4,102 3,135
Accumulated postretirement (2,036) (2,520)
benefit obligation
in excess of plan assets
Unrecognized net (gain) from (1,310) (1,016)
past experience
different from that assumed
and from changes in assumptions
Unrecognized transition obligation 4,584 4,854
Prepaid postretirement benefit $1,238 $1,318
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended December 31,
(In Thousands) 1995 1994 1993
Service cost - benefits $145 $202 $268
attributable to service
during the period
Interest cost on accumulated 505 455 478
postretirement
benefit obligation
Actual return on plan assets (639) 143 (202)
Net amortization and deferral 661 (106) 273
Net periodic postretirement $672 $694 $817
benefit cost
For measurement purposes, a 7% (4.5% for dental costs) annual
rate of increase in the per capita cost of covered health care
benefits was assumed for 1996; the rate of increase for medical
costs was assumed to decrease gradually from 7% to 4.5% in 2001
and remain at that level thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported.
To illustrate, increasing the assumed health care cost trend rates
by one percentage point in each year would increase the
accumulated postretirement benefit obligation as of December 31,
1995 by $706,000 and the aggregate of the service and the interest
cost components of net periodic postretirement benefit cost for
the year then ended by $84,000.
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5% and 8.5%
for 1995 and 1994, respectively. The expected long-term rate of
return on plan assets was 9% for assets in the Section 401(h)
accounts and, after estimated taxes, was 6% for assets in the
Section 501(c)(9) trust for all years presented.
Postemployment Benefits - During 1994, the Company adopted
Statement of Financial Accounting Standards No. 112 "Employer's
Accounting for Postemployment Benefits" (SFAS 112). This statement
requires accrual accounting for benefits to former or inactive
employees after employment but before retirement. The adoption of
SFAS 112 did not have a significant effect on the Company's
results of operations.
Note I: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2012, for the acquisition of gas
supplies and the storage and delivery of natural gas stored
underground. The contracts contain minimum payment provisions
which correspond to gas purchases that, in the opinion of
management, are not in excess of the Company's requirements.
FERC Order 636 Transition Costs - As a result of FERC Order 636,
the Company's interstate pipeline service providers have been
required to unbundle their supply and transportation services.
This unbundling has caused the interstate pipeline companies to
incur substantial costs in order to comply with Order 636. These
transition costs include four types: (1) unrecovered gas costs
(gas costs that had been incurred but not yet recovered by the
pipelines when they were providing bundled service to local
distribution companies); (2) gas supply realignment costs (the
cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that
can not be assigned to customers of unbundled services); and (4)
new facilities costs (costs of new facilities required to
physically implement Order 636).
Pipelines are expected to be allowed to recover prudently
incurred transition costs from customers such as the Company,
primarily through a demand charge, after approval by FERC. The
Company's transition cost liabilities are estimated to range from
$11,600,000 to $16,400,000, of which the Company has paid
$8,000,000 through December 31, 1995. The Company is recovering
these costs from its customers, as approved by the DPU in October
1994. As of December 31, 1995, the Company has recorded on the
balance sheet a long-term liability of $3,600,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $3,600,000 ("Unrecovered Transition Costs
Accrued"). Actual transition costs to be incurred depends on
various factors, and therefore future costs may differ from the
amounts discussed above.
Note J: Contingencies
Working with the Massachusetts Department of Environmental
Protection, the Company is engaged in site assessments and
evaluation of remedial options for contamination that has been
attributed to the Company's former gas manufacturing site and at
various related disposal sites. During 1990, the DPU ruled that
Colonial and eight other Massachusetts gas distribution companies
can recover environmental response costs related to former gas
manufacturing operations over a seven-year period, without
carrying costs, through the CGAC. Through December 31, 1995, the
Company had incurred environmental response costs of $10,418,000
of which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects to
continue incurring costs arising from these environmental matters.
As of December 31, 1995, the Company has recorded on the balance
sheet a long-term liability of $2,300,000 representing estimated
future response costs for these sites based on the Company's
preferred methods of remediation, of which $1,700,000 relates to
the gas manufacturing site. Based upon the DPU order approving
rate recovery of environmental response costs, a regulatory asset
of $2,300,000 has been recorded on the balance sheet ("Unrecovered
Environmental Costs Accrued"). Actual environmental response costs
to be incurred depends on various factors, and therefore future
costs may differ from the amount currently recorded as a
liability.
As of December 31, 1995, the Company had settled claims relating
to these matters with all liability insurers and other known
potentially responsible parties (PRP). In accordance with the DPU
order referred to above, half the costs incurred in pursuing
insurers and other PRP are recovered from the ratepayers through
the CGAC and half are initially borne by the Company. Also, per
this order, any insurance and other proceeds are applied first to
the Company's costs of pursuing recovery from insurers and other
PRP, with the remainder divided equally between the ratepayers and
shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Thousands) Response Costs Insurance and Other Proceeds
Recovered Period Recorded as
from of Rate Returned to Non-Operating
Year Incurred Customers Recovery Customers Income Net of
Taxes
1988 $ 853 $ 732 1990-1997 - -
1989 4,031 3,455 1990-1997 - -
1990 639 457 1991-1998 - -
1991 374 213 1992-1999 $ 851 $ 525
1992 617 264 1993-2000 1,121 673
1993 1,226 350 1994-2001 469 290
1994 1,321 189 1995-2002 122 75
1995 1,357 - 1996-2003 - -
Total $10,418 $5,660 $2,563 $1,563
Note K: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)
Income
Utility (Loss) Per Dividends
Operating Net Average Paid Per
Operating Income Income Common Common
Quarter Ended Revenues (Loss) (Loss) Share Share
1995
December 31 $56,625 $10,283 $8,530 $1.02 $.320
September 30 14,911 (2,251) (3,932) (.47) .320
June 30 22,760 (925) (3,283) (.40) .320
March 31 70,353 14,467 12,449 1.51 .315
1994
December 31 $48,077 $6,741 $4,782 $ .58 $.315
September 30 13,026 (3,132) (4,834) (.59) .315
June 30 19,073 (1,849) (3,338) (.41) .315
March 31 86,083 15,757 14,399 1.79 .310
In the opinion of management, the quarterly financial data
includes all adjustments, consisting only of normal recurring
accruals, necessary for a fair presentation of such information.
The Company typically reports profits during the first and fourth
quarters of each year while incurring losses during the second and
third quarters. This is due to significantly higher natural gas
sales during the colder months to satisfy customers' heating
needs.
Note L: Restructuring Charge
In the fourth quarter of 1994, the Company recorded a
restructuring charge of $3,185,000 ($1,965,000 after-tax or $.24
per share). This amount includes $2,537,000 for the cost of a
voluntary early retirement program which was accepted by 47
employees and $648,000 for costs accrued by the Company in
connection with the closure of two retail appliance stores.
[END OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS]
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Shareholders of Colonial Gas Company
We have audited the accompanying consolidated balance sheets of
Colonial Gas Company and subsidiaries as of December 31, 1995 and
1994, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and the
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe 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 consolidated
financial position of Colonial Gas Company and subsidiaries as of
December 31, 1995 and 1994, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
GRANT THORNTON LLP
Boston, Massachusetts
January 17, 1996
[END OF REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS]
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income and Dividends
Net income and income per average common share were $13,764,000
($1.66), $11,009,000 ($1.36) and $12,022,000 ($1.52) for the three
years ended December 31, 1995, 1994, and 1993, respectively.
Before a restructuring charge after-tax of $1,965,000 or $.24 per
share, 1994 net income and income per average common share were
$12,974,000 ($1.60).
Net income was favorably impacted by colder-than-normal
temperatures in 1995, 1994 and 1993, although at declining
percentages over the periods. This is summarized as follows:
1995 1994 1993
Percent colder than normal 2.7% 5.3% 6.7%
Percent (warmer) colder than prior year (2.5)% (1.3)% 3.3%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.275 in 1995, $1.255 in
1994 and $1.235 in 1993. The Company has paid dividends for 59
consecutive years, and has increased dividends each year for the
past 16 years.
Operating Revenues
Operating revenues were $164,649,000 in 1995, $166,259,000 in 1994
and $166,261,000 in 1993. Operating revenues are impacted by the
volumes of gas sold and transported, changes in base rates as
approved by the Massachusetts Department of Public Utilities
(DPU), and the pass-through of gas costs to customers via a cost
of gas adjustment clause (CGAC).
The volumes of gas sold are affected by fluctuations in weather
and the number of customers being served. Firm sales customers
increased by 13,395 over the last three years from 127,964 in 1992
to 141,359 in 1995, an increase of 10.5%, which has added to firm
sales volume. The chart below summarizes volumes of gas sold and
transported and number of firm sales customers:
1995 1994 1993
(In MMcf)
Gas sold
Firm 18,560 18,716 18,935
Non-Firm 1,148 729 1,030
Gas transported
Firm 2,537 6,090 4,163
Non-Firm 3,224 4,185 4,026
Total gas sold and
transported (In MMcf) 25,469 29,720 28,154
Firm Sales Customers 141,359 136,636 132,187
Operating revenues decreased $1,610,000, or 1.0%, from 1994 to
1995. This decrease resulted primarily from weather that was 2.5%
warmer than the prior year (although 2.7% colder than normal)
partially offset by a growing customer base and additional revenue
of $1,120,000 resulting from regulatory approval to recover lost
margins and financial incentives associated with the Company's
residential conservation programs.
Operating revenues were unchanged from 1993 to 1994. Utility
revenues were positively impacted during 1994 by a 3.4% customer
growth and a 4.9% rate increase which became effective in November
1993. Weather, although 5.3% colder than normal, was 1.3% warmer
than 1993.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.22 in 1995, $4.48 in 1994
and $4.53 in 1993. Cost of gas sold is based upon the sales
volumes, the price and mix of gas purchased and used to satisfy
demand, and profits on non-firm sales and transportation, which
flow back to firm sales customers as a credit through the CGAC.
The Company distributes natural gas purchased under long-term
contracts as well as gas purchased on the spot market. The
following table summarizes the sources of gas purchased by the
Company:
(In MMcf) 1995 1994 1993
Gas purchased
Pipeline 14,659 14,392 14,983
Underground storage 3,270 3,112 3,501
LNG/Other 2,426 2,390 1,832
Total gas purchased 20,355 19,894 20,316
Underground storage consists primarily of spot gas purchased and
injected into storage during the summer and fall for use during
the following winter.
Operating Expenses
Operations expense was $31,309,000 in 1995, a decrease of
$1,695,000 or 5.1%, from 1994, and $33,004,000 in 1994, an
increase of $47,000, or 0.1%, from 1993. In 1994, the Company
conducted a self-examination to reduce its cost structure. The
decrease in 1995 was primarily due to less payroll and related
benefits as a result of the early retirement program and other
cost saving initiatives. The Company has budgeted no increase in
operations and maintenance costs in 1996.
Maintenance expense decreased $673,000, or 13.3%, in 1995 from
1994 and increased $348,000, or 7.4%, in 1994 from 1993. The
decrease in 1995 was primarily due to cost controls resulting from
the Company's self-examination in 1994. The increase in 1994 was
primarily due to increased labor resulting from colder weather
during the first quarter.
Depreciation and amortization expense increased 10.7% or
$990,000 in 1995 and 35.2% or $2,404,000 in 1994. The increase in
1995 was due to an increase in utility property. The increase in
1994 was primarily due to the increased depreciation rates as a
result of the Company's 1993 rate order and an increase in utility
property.
Local property and other taxes increased 4.6% in 1995 from 1994
and 8.2% in 1994 from 1993. The increase in 1995 was due to higher
property taxes and additional property subject to property subject
to property taxes. The increase in 1994 was due to higher property
and payroll taxes, and additional property subject to property
taxes.
A restructuring charge of $3,185,000 ($1,965,000 after-tax or
$.24 per share) was recorded during the fourth quarter of 1994.
This amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.
Income Taxes
Total Federal income and state franchise taxes increased 42.5% or
$2,495,000 in 1995 as a result of a higher level of income. Total
Federal income and state franchise taxes decreased 20.7% or
$1,527,000 in 1994 as a result of less income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $596,000
in 1995, $1,336,000 in 1994 and $209,000 in 1993. Other operating
income primarily includes the results of the Company's wholly-
owned energy trucking subsidiary (Transgas). Also included are
heating and water heating equipment sales and installations. As
discussed previously, the Company's retail appliance sales
operation was discontinued as of December 31, 1994.
Transgas' 1994 financial results were driven by extremely cold
weather in the first quarter of 1994 which generated a significant
increase in demand for the truck transportation of liquefied
natural gas (LNG) and propane throughout the first three quarters
of 1994. This accounts for the sharp increase in 1994 other
operating income.
Factors affecting the future financial results of Transgas
include the amount of LNG used by local distribution companies
throughout the northeast United States to satisfy requirements of
their customers; the price of domestic and Canadian natural gas
compared to imported LNG; the continued availability of imported
LNG; and the level of construction and major maintenance projects
of interstate pipeline companies which drives the demand for
portable pipeline services.
Non-Operating Income
Non-operating income, net of income taxes, was $864,000 in 1995,
$565,000 in 1994 and $1,064,000 in 1993. Non-operating income
includes interest income and miscellaneous other income. Included
in non-operating income for 1994 and 1993 were recoveries of
$75,000 and $290,000, respectively, resulting from settlements
reached with insurers and other potentially responsible parties
relating to environmental response costs as described under
"Environmental Matters". Also included in non-operating income for
1993 is an insurance recovery of $509,000 relating to a line of
business that was discontinued in 1979.
Interest and Debt Expense
Interest and debt expense increased 10.2% and 3.3% in 1995 and
1994, respectively. The increase in 1995 was due to increased
levels of short-term debt and higher short-term interest rates
partially offset by a decrease in interest on long-term debt. The
increase in 1994 was due to increased levels of short-term debt
and higher short-term interest rates partially offset by a
decrease in interest on long-term debt due to paydowns in 1993.
Effects of Inflation
Inflation generally has a negative impact upon the Company's
profitability since the rates charged to the Company's utility
customers, excluding changes in the cost of gas sold, cannot be
increased without formal proceedings before the DPU. Changes in
the cost of gas sold are automatically reflected in customer rates
pursuant to semi-annual adjustments under the CGAC. In the absence
of authorized rate increases, the Company must look to increased
productivity and higher sales volumes to offset inflationary
increases in its other costs of operations. The present regulatory
process permits the Company to earn a rate of return based on the
historical cost of utility property without recognition of the
current replacement cost. The Company's policy is to file for an
increase in rates only when increases in productivity and
customers are not sufficient to counteract the impact of
inflation. The Company has set a goal to defer its next base rate
increase until at least the year 2000.
Regulatory Matters
Environmental response costs, transition costs and demand side
management (DSM) program costs are recovered through the CGAC, as
approved by the DPU. The environmental response costs recovered
through the CGAC relate to the Company's former gas manufacturing
operations, as described under "Environmental Matters". Transition
costs relate to FERC approved pipeline charges resulting from
Order 636. In addition to full recovery of the installed
conservation measures, the Company is allowed to recover the
margins lost as a result of the DSM programs and financial
incentives based on the attainment of performance goals. In
September 1995, the Company received approval from the DPU to
recover lost margins and financial incentives associated with the
residential DSM programs. Based on this approval, the Company
recorded as operating revenues $900,000 of lost margins and
$220,000 of financial incentives in 1995. The Company anticipates
recording as operating revenues approximately $1 million of lost
margins and incentives associated with the residential and
commercial DSM programs in 1996.
In 1993, the Company applied for what was only its second base
rate increase request since 1984. Effective November 1, 1993, the
Company received DPU approval of a settlement agreement that
called for a base rate increase designed to produce additional
revenues of $6.7 million or 4.9% annually. In addition to this
rate increase, the DPU approved a proposal to expand the
eligibility criteria for Colonial's discount rate for low-income
residential heating customers and allowed the Company to retain
10% of the revenues generated from releasing the Company's
interstate pipeline transportation capacity to third parties above
an initial threshold of $2,500,000. In 1995, the Company received
$2,818,000 of capacity release revenue, $2,786,000 of which was
credited back to firm customers and $32,000 of which was retained
by the Company.
The table below summarizes the Company's last three requests to
increase base revenue:
Increase Requested Increase Approved
Date Effective Amount Percentage Amount Percentage
November 1, 1984 $ 4.30 million 3.73% $2.8 million 2.4%
November 1, 1990 $12.80 million 9.86% $7.9 million 5.6%
November 1, 1993 $10.75 million 7.87% $6.7 million 4.9%
In 1993, Colonial began unbundling its firm sales service to
commercial and industrial customers by offering a tariffed firm
transportation-only service. Pursuant to this service, a customer
procures its own gas supply and contracts with Colonial for firm
transportation service through Colonial's distribution system. As
of December 31, 1995, 11 customers had opted for tariffed firm
transportation service, representing less than 2% of the Company's
annual firm load.
Two 1994 DPU industry-wide proceedings may result in the further
unbundling and deregulation of the Company's business. One of
those proceedings addresses whether and how the traditional cost-
of-service/rate-of-return method of regulating gas and electric
utilities might be replaced with some type of alternative
"incentive" method. In a ruling issued in February 1995, the DPU
indicated that it has the authority to implement incentive
regulation and would be receptive to various types of proposals.
The Company continues to analyze specific incentive regulation and
unbundling options which it could propose to the DPU as a means of
benefiting its customers and shareholders. The other proceeding
addresses whether interruptible transportation and interruptible
sales service on local distribution company (LDC) systems, and the
release of interstate pipeline capacity by LDCs, should be
structured or priced differently. The Company expects DPU rulings
containing general guidelines on these matters in 1996.
Environmental Matters
Working with the Massachusetts Department of Environmental
Protection, the Company is engaged in site assessments and
evaluation of remedial options for contamination that has been
attributed to the Company's former gas manufacturing site and at
various related disposal sites. During 1990, the DPU ruled that
Colonial and eight other Massachusetts gas distribution companies
can recover environmental response costs related to former gas
manufacturing operations over a seven-year period, without
carrying costs, through the CGAC. Through December 31, 1995, the
Company had incurred environmental response costs of $10,418,000,
of which $2,904,000 was for the former gas manufacturing site and
$7,514,000 for the related disposal sites. The Company expects to
continue incurring costs arising from these environmental matters.
As of December 31, 1995, the Company had recovered $5,660,000 from
customers and $1,563,000 from liability insurers and other known
potentially responsible parties.
As of December 31, 1995, the Company has recorded on the balance
sheet a long-term liability of $2,300,000 and, based upon rate
recovery, has recorded a corresponding regulatory asset. The
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation, of which
$1,700,000 relates to the gas manufacturing site. Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
Accounting Standards
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of", which will be effective for the Company's fiscal
year ending December 31, 1996. This statement requires the Company
to review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company intends to adopt this
statement prospectively. The impact of this standard is not
expected to have a material impact on the Company's financial
condition or results operations.
During 1993, the Company adopted Statement of Financial Accounting
Standards No. 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions" (SFAS 106). Prior to 1993, expense
was recognized when benefits were paid. In accordance with SFAS
106, the Company began recording the cost for this plan on an
accrual basis in 1993. As permitted by SFAS 106, the Company will
record the transition obligation over a twenty-year period. The
Company's cost under this plan for 1995, 1994 and 1993 was
$672,000, $694,000 and $817,000, respectively. A regulatory asset
of $431,000 was recorded in 1993, leaving a net expense of
$386,000. This regulatory asset represents the excess of
postretirement benefits on the accrual basis over the paid amounts
for the period of January 1, 1993 until November 1, 1993, the
effective date of the DPU's approval of the Company's new rates.
Currently the DPU allows Massachusetts utilities to recover the
tax deductible portion of these postretirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
The Company's liquidity is affected by its ability to generate
funds from operations and to access capital markets. The Company's
operations are seasonal with its cash flow reflecting this
seasonality. The Company typically generates approximately 70
percent of its annual operating revenues during the November
through April heating season, which results in a high level of
cash flow from operations from late winter through early summer.
As a result of this seasonality, the Company's liquidity can be
affected by significant variations in weather. Short-term
borrowings are highest during the fall and early winter months due
to the completion of the annual construction program and seasonal
working capital requirements.
Investing Activities
The Company invests in property, plant and equipment to improve
and protect its distribution system, and to expand its system to
meet customer demand. Utility capital expenditures were
$24,096,000 in 1995, $28,195,000 in 1994 and $25,703,000 in 1993.
The Company's long-range plan calls for annual utility
expenditures, of which over 40% is budgeted for new business,
averaging $27,000,000 over the next five years as follows:
(In Thousands) 1996 1997 1998 1999 2000
Distribution $20,700 $22,700 $22,300 $26,500 $24,800
Production 1,400 1,000 1,000 700 750
Information Systems 4,300 1,000 700 500 140
Automated Meter 1,100 1,100 $1,100 1,100 30
Reading
General 300 700 300 400 380
Total Capital $27,800 $26,500 $25,400 $29,200 $26,100
Expenditures
Financing Activities
In September 1995, with the approval of the DPU, the Company
established a medium term note (MTN) program which permits the
issuance of up to $75 million of MTN's as bonds under its
indenture. In October 1995, the Company issued $10 million of 30-
year bonds with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years). In
December 1995, the Company issued $10 million of 30-year bonds with
an average effective interest rate of 6.45% (6.08% during the first
ten years and 6.90% in the next twenty years). Both issues of bonds
can be redeemed by the holder within a 30 day period at the end of
ten years. In February 1996, the Company issued $10 million of 30-
year bonds with an interest rate of 6.94%. It is anticipated that
the remaining bonds under the MTN program will be issued in several
series over the next two years.
On December 29, 1995, the Company redeemed prior to maturity the
$16,364,000 of Series CF, 10.25%, first mortgage bonds.
The Company has a $75 million credit facility which allows it to
meet its seasonal working capital needs. The present facility
expires in June 1997. Up to $30 million of the credit facility can
be used by the Company's gas inventory trust. The credit facility
allows the Company the option to borrow under any one of four
alternative rates.
The Company has raised permanent capital during the last three
years as follows:
(In Thousands) 1995 1994 1993
Common Stock Under Dividend Reinvestment
and Common Stock Purchase Plan and
Employee Savings Plan $2,702 $4,070 $4,283
Long-Term Debt
Note Payable - $ 741 -
MTA-1, 6.85%, due 2025 * $10,000 - -
MTA-2, 6.45%, due 2025 * $10,000 - -
* Subject to redemption in 2005 at the option of the holder
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1995 1994 1993
Equity 58% 56% 52%
Long-Term Debt 42% 44% 48%
As of April 1995, the quarterly dividend paid on the Company's
Common Stock was increased to $.32 per share or an annualized
dividend rate of $1.28 per share.
[END OF MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS]
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)
1995 1994 1993 1992 1991
Balance Sheet Data:
Assets:
Utility property-net $235,555 $221,685 $202,713 $183,815 $162,736
Non-Utility property-net 5,036 3,479 3,235 4,039 4,767
Capital leases-net 2,253 2,948 3,914 4,366 4,557
Current assets 61,002 65,568 67,668 71,763 53,472
Deferred charges and 38,575 37,668 34,588 38,939 38,789
other assets
Total $342,421 $331,348 $312,118 $302,922 $264,321
Capitalization and
Liabilities:
Capitalization:
Common equity $105,070 $ 99,175 $ 94,283 $ 87,771 $ 82,221
Long-term debt 75,418 77,923 87,432 90,750 50,410
Total Capital-
ization 180,488 177,098 181,715 178,521 132,631
Capital lease 1,359 2,237 3,149 3,591 3,838
obligations
Current liabilities 101,666 91,382 73,413 64,567 73,993
Deferred credits and 58,908 60,631 53,841 56,243 53,859
reserves
Total $342,421 $331,348 $312,118 $302,922 $264,321
Income Statement Data:
Operating revenues $164,649 $166,259 $166,261 $145,054 $137,719
Cost of gas sold (83,631) (87,458) (90,915) (75,143) (73,288)
Operating margin 81,018 78,801 75,346 69,911 64,431
Operating expenses (59,444) (61,284) (56,456) (52,760) (48,009)
(including income
taxes)
Utility operating 21,574 17,517 18,890 17,151 16,422
income
Other income- 1,460 1,901 1,273 958 36
net of income taxes
Interest and (9,270) (8,409) (8,141) (7,466) (8,141)
debt expense
Accounting change - - - - -
Preferred stock - - - - -
dividends
Net income applicable $13,764 $11,009 $12,022 $10,643 $8,317
to common stock
Capitalization Ratios:
Common equity 58% 56% 52% 49% 62%
Long-term debt 42% 44% 48% 51% 38%
Common Stock Data:
Average shares 8,294 8,119 7,931 7,728 7,529
outstanding
Income per share $1.66 $1.36(a) $1.52 $1.38 $1.10
Dividends paid per share:
Common Stock $1.275 $1.255 $1.235 $1.213 $1.193
Class A Common Stock - - - - -
Per weighted average $1.275 $1.255 $1.235 $1.213 $1.193
common share
Dividend payout rate 77% 92% 81% 88% 108%
Book value per share $12.56 $12.05 $11.74 $11.19 $10.78
Dividends as a percent 10% 10% 11% 11% 11%
of book value
Market price per share $20.25 $19.25 $22.50 $21.25 $17.50
Market price as a 161% 160% 192% 190% 162%
percent of book value
Return on average 13.5% 11.4% 13.2% 12.5% 10.2%
common equity
(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting change
of $.33 per share.
SELECTED FINANCIAL DATA - Continued
(For the Years Ending December 31)
(In Thousands Except Per Share Amount)
1990 1989 1988 1987 1986
Balance Sheet Data:
Assets:
Utility property-net $151,480 $139,764 $131,450 $121,034 $111,214
Non-Utility property-net 5,076 3,893 2,793 3,167 3,665
Capital leases-net 4,962 5,853 6,679 6,563 9,201
Current assets 46,393 56,753 50,414 36,757 37,234
Deferred charges and 29,925 27,464 21,050 20,376 4,235
other assets
Total $237,836 $233,727 $212,386 $187,897 $165,549
Capitalization and
Liabilities:
Capitalization:
Common equity $ 80,109 $ 66,568 $ 63,027 $ 58,238 $ 54,569
Long-term debt 64,604 69,512 55,102 58,572 47,528
Total Capital- 144,713 136,080 118,129 116,810 102,097
ization
Capital lease 4,233 4,714 5,457 5,556 8,258
obligations
Current liabilities 47,729 54,590 53,375 34,781 41,151
Deferred credits and 41,161 38,343 35,425 30,750 14,043
reserves
Total $237,836 $233,727 $212,386 $187,897 $165,549
Income Statement Data:
Operating revenues $134,298 $139,892 $115,851 $117,947 $126,099
Cost of gas sold (78,930) (82,189) (63,401) (65,093) (75,157)
Operating margin 55,368 57,703 52,450 52,854 50,942
Operating expenses (42,853) (41,525) (38,844) (38,343) (37,938)
(including income
taxes)
Utility operating 12,515 16,178 13,606 14,511 13,004
income
Other income- 1,625 956 1,046 233 383
net of income taxes
Interest and (8,445) (8,217) (7,369) (6,740) (5,861)
debt expense
Accounting change - - 2,014 - -
Preferred stock - - - - (312)
dividends
Net income applicable $ 5,695 $ 8,917 $ 9,297 $ 8,004 $ 7,214
to common stock
Capitalization Ratios:
Common equity 55% 49% 53% 50% 53%
Long-term debt 45% 51% 47% 50% 47%
Common Stock Data:
Average shares 6,963 6,200 6,065 5,948 5,588
outstanding
Income per share $0.82 $1.44 $1.53(b) $1.35 $1.29
Dividends paid per share:
Common Stock $1.167 $1.140 $1.113 $1.087 $1.060
Class A Common Stock - - $ .800 $ .760 $ .720
Per weighted average $1.167 $1.140 $1.013 $ .987 $ .960
common share
Dividend payout rate 142% 79% 66% 73% 74%
Book value per share $10.75 $10.62 $10.27 $ 9.69 $ 9.25
Dividends as a percent 11% 11% 11% 11% 11%
of book value
Market price per share $15.00 $14.67 $13.00 $11.83 $14.33
Market price as a 139% 138% 127% 122% 155%
percent of book value
Return on average 7.8% 13.8% 15.3% 14.2% 14.3%
common equity
(a) 1994 is after a restructuring charge of $.24 per share.
(b) 1988 includes the cumulative effect of an accounting change
of $.33 per share.
[END OF SELECTED FINANCIAL DATA]
SHAREHOLDER INFORMATION
Corporate Headquarters
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
(508) 458-3171
FAX: (508) 459-2314
Stock Listing
The Company's Common Stock trades on the Nasdaq Stock Market
under the symbol: CGES. Stock trading activity is reported in
financial publications under the abbreviation of ColGas or
ClnGas.
Annual Meeting
The Annual Meeting of Stockholders will be held on April 17, 1996
at 10:00 A.M. at The First National Bank of Boston, 100 Federal
Street, Boston, Massachusetts.
Annual Report - Form 10-K
A copy of the Company's 1995 Annual Report on Form 10-K as filed
with the Securities and Exchange Commission will be sent free of
charge to any shareholder who contacts the Investor Relations
Department at the corporate headquarters address above.
Transfer Agent
The First National Bank of Boston
c/o Boston EquiServe, L.P.
P.O. Box 644
Mail Stop: 45-02-64
Boston, MA 02102-0644
(800) 736-3001
(617) 575-3100
Independent Certified Public Accountants
Grant Thornton LLP
98 North Washington Street
Boston, MA 02114
(617) 723-7900
Corporate Counsel
Palmer & Dodge
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 59 consecutive
years and has increased dividends each year for the past 16
years. Common Stock dividends are payable when declared by the
Board of Directors.
Anticipated Record Date Anticipated Payment Date
March 1, 1996 March 15, 1996
May 31, 1996 June 14, 1996
August 30, 1996 September 13, 1996
November 29, 1996 December 13, 1996
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock Purchase
Plan (DRIP) provides shareholders of record with an economical
and convenient method for purchasing additional shares of the
Company's Common Stock without paying any brokerage fees.
Participants in the plan may elect to purchase additional
Colonial shares at a 5% discount from the market price by
reinvesting all or a portion of their dividends with no brokerage
fees. Participants in the plan may also make optional cash
purchases of Common Stock at the market price in amounts ranging
from a minimum of $10 to a maximum of $5,000 per calendar
quarter, with no brokerage fees.
Features of the plan at no charge to shareholders include:
- Direct deposit of dividends by electronic deposit
- Automatic monthly investments by electronic funds transfer
- Safekeeping of stock certificates
Additional information describing the plan, including a
prospectus and enrollment information, can be obtained by
contacting the Company's Transfer Agent or Investor Relations
Department.
Investment Dates
The investment date for optional cash investments under the DRIP
will be the fifteenth day of each month or, if that day is not a
business day, the preceding business day. Optional cash
investments must be received by the Company's Transfer Agent five
business days before the investment date. The dates below will
help you plan for any optional cash investments during 1996.
Date Investment Must Be Investment
Received By Transfer Agent Dates
April 8 April 15
May 8 May 15
June 7 June 14
July 8 July 15
August 8 August 15
September 6 September 13
October 7 October 15
November 8 November 15
December 6 December 13
SHAREHOLDER INFORMATION
Market Prices and Dividends
The following table reflects the high and low sales prices as reported
by the Nasdaq Stock Market, for shares of the Company's Common Stock
for 1995 and 1994, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
1995
The Year $21.50 $18.00 $1.275
4th Quarter 21.50 19.50 .320
3rd Quarter 20.75 18.75 .320
2nd Quarter 21.25 18.00 .320
1st Quarter 21.25 18.25 .315
1994
The Year $23.75 $18.25 $1.255
4th Quarter 21.75 18.25 .315
3rd Quarter 22.00 20.50 .315
2nd Quarter 21.75 18.50 .315
1st Quarter 23.75 18.75 .310
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1995, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,592
shareholders of record.
Market Makers
Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; First Albany Corporation;
Herzog, Heine, Geduld, Inc.; S. J. Wolfe & Co.; and Tucker
Anthony Incorporated.
Investment Information
Colonial Gas Company is a corporate member of the National
Association of Investors Corporation (NAIC). The Company is also
a participant in NAIC's Low Cost Investment Plan.
[END OF SHAREHOLDER INFORMATION]
[END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
FOR 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
COLONIAL GAS COMPANY
SUBSIDIARIES OF REGISTRANT
Subsidiaries: Organized in Ownership
(a) Transgas Inc. Massachusetts 100%
(a) CGI Transport Limited (1) Canada 100%
(a) Included in consolidated financial statements.
(1) Owned by Transgas Inc.
[END OF EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
[EXHIBIT 23a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our reports dated January 17, 1996
accompanying the consolidated financial statements and schedules
incorporated by reference or included in the Annual Report on
Form 10-K of Colonial Gas Company and subsidiaries for the year
ended December 31, 1995. We hereby consent to the incorporation
by reference of said reports in the Colonial Gas Company
Registration Statements on Forms S-8, as amended (File No. 33-
34068, File No. 33-34066, File No. 33-34067 and File No. 33-
44427) and Form S-16, as amended on Form S-3 (File No. 2-93005).
GRANT THORNTON LLP
Boston, Massachusetts
March 15, 1996
[END OF EXHIBIT 23a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1995]
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