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, 1996
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) 322-3000
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
____
The aggregate market value of the voting stock held by non-
affiliates of the registrant as of February 28, 1997 was
$179,271,162.
The number of shares of the registrant's common stock outstanding
as of February 28, 1997 was 8,536,722.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the annual report to stockholders for the year ended
December 31, 1996 are incorporated by reference into Part II and
Part IV. Portions of the proxy statement for the 1997 annual
meeting of stockholders are incorporated by reference into Part
III.
COLONIAL GAS COMPANY
FORM 10-K ANNUAL REPORT - 1996
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 145,000 utility customers in 24 municipalities located
northwest of Boston and on Cape Cod. Through its 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) 322-3000.
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 145,471 customers,
approximately 90% are residential accounts. The Company added
4,072 firm sales customers in 1996. 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 1996, 53%
converted from other fuels and 47% were new construction.
The Company's 1996 consolidated operating revenues were
derived 64% 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 1% from other revenues. For the year 1996, the Company sold
19,564 MMcf of gas, of which 11,808 MMcf was sold in the
Merrimack Valley area and 7,756 MMcf in the Cape Cod area. At
December 31, 1996, 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, 1996, the Company had 475 full-time-
equivalent employees. Of those employees, 90 are covered by a
collective bargaining agreement with the United Steelworkers of
America which expires in April 2001 and 75 are covered by a
separate collective bargaining agreement with the United
Steelworkers of America which expires in February 2000. In
addition, Transgas employs 78 full-time employees of which 61 are
covered by collective bargaining agreements with the
International Brotherhood of Teamsters . The drivers agreement
expires in June 1999 while the mechanics agreement expires in
July 1999.
GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES
Since 1993, the effective date of Order 636 of the Federal
Energy Regulatory Commission ("FERC"), the Company has been
responsible for managing its own supply, pipeline transportation
capacity and storage resources on behalf of its firm sales
customers. Generally, the Company pays negotiated prices for
pipeline-transported supplies and tariffed rates (approved by
FERC) for pipeline transportation and storage services it
purchases to meet the requirements of its firm sales customers.
As discussed below under "State Regulation", the Company
continues to explore ways of further unbundling its services to
provide a greater number of its customers the opportunity 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.
The Company continues to meet its customers' firm supply
requirements through a combination of firm and spot purchases of
pipeline-transported supply, supply from underground storage,
liquefied natural gas 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:
1996 1995 1994
MMcf(a) % MMcf(a) % MMcf(a) %
Firm Pipeline
Transportation
Capacity 30,313 30,630 28,993
Firm Gas Supply Sources
Contracts for Pipeline-
Transported Gas(b) 18,698 71 18,725 70 19,631 72
LNG contracts 4,150 15 4,150 15 4,050 15
Storage inventory at
January 1 (c) 3,614 14 3,956 15 3,587 13
Total Available 26,462 100 26,831 100 27,268 100
Gas Sendout
Pipeline-Transported
Supplies (d) 15,115 72 14,659 72 14,392 72
Supplemental Supplies:
Underground
storage 3,346 16 3,270 16 3,112 16
LNG-as liquid 1,067 5 844 4 1,129 6
LNG-as vapor 1,528 7 1,574 8 1,236 6
Propane-air 1 0 8 _ 25 -
Total Sendout 21,057 100 20,355 100 19,894 100
Ratio of available
firm supply to
sendout (e) 1.26 1.32 1.37
_________________________
(a) The term "MMcf" means one million cubic feet of vapor
or vapor equivalent.
(b) 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 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 1996, 1995 and 1994.
(c) 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 4,674 MMcf.
(d) Includes firm and spot volumes.
(e) 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. The second
firm transportation contract is for 17,300 Mcf per day and is in
effect until April 1, 2013. 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.
In addition, the Company contracts for underground storage
service which, in conjunction with two Tennessee firm
transportation contracts, provide up to an additional 23,587 Mcf
per day of firm deliverability. The Company has storage capacity
of 2,028,800 Mcf and firm deliverability of 16,083 Mcf per day
under two contracts with the National Fuel Gas Supply
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, 2000 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.
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 Company has received the requisite approval of the
Massachusetts Department of Public Utilities ("DPU") for these
supply contracts.
During the peak season, pipeline-transported supply and
storage volumes are supplemented by on-system LNG and propane
facilities. On January 13, 1997, the Company entered into
definitive joint venture agreements with Cabot LNG Corporation
("Cabot LNG"). The joint venture agreements provide that,
subject to certain regulatory approvals, (1) the Company will
sell a 50% interest in Transgas to Cabot LNG (See the "Transgas
Inc." Section hereafter), and (2) the Company will lease its LNG
facility in Tewksbury, Massachusetts to a joint venture entity
owned 50/50 by the Company and Cabot LNG. Pursuant to this joint
venture, Cabot LNG's marketing subsidiary, Distrigas of
Massachusetts Corporation ("DOMAC") will market and sell
vaporized LNG from the Tewksbury LNG facility above the Company's
requirements, with the joint venture entity sharing in the net
revenues from such sales. For the 1997-98 heating season, the
Company would be entitled to receive up to 46,100 Mcf per day of
vaporized LNG through the Tewksbury LNG facility. The sendout
capability of the Company's remaining on-system LNG and propane
facilities is approximately 30,000 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 October 31, of either 2012 or 2013. 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 other upstream
pipelines.
The Company also 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 storage
contracts with Texas Eastern total approximately 493,486 Mcf of
capacity and run 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
storage contracts with CNG are for approximately 823,529 Mcf of
capacity through March 31, 2006 and 232,600 Mcf of capacity
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's portfolio of pipeline-transported supplies for
the Cape Cod area consists principally of four purchase contracts
for domestically-produced gas. These individually negotiated
contracts, all of which have been approved by the DPU, provide an
aggregate of up to 20,918 Mcf per day of firm supply during the
peak season (November 1 through March 31). 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.
The Company also operates facilities and maintains contracts
which provide up to approximately 32,500 Mcf per day of LNG vapor
to the Cape Cod Division during the peak season.
REGULATORY MATTERS
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") through which firm sales customers
pay, via their monthly gas bill, the exact costs incurred by the
companies in procuring and transporting gas to the companies'
distribution systems, as such costs change from time to time.
Changes in non-gas or base rates charged to customers are subject
to approval by the DPU after formal proceedings.
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 installed conservation measures, the Company is allowed to
recover, under methodologies approved in 1995 for its
residential DSM programs and in 1996 for its commercial and
industrial programs, resulting lost margins and financial
incentives based on the attainment of performance goals. In
1996, the Company recorded as operating revenues $1,034,000 of
lost margins and $142,000 of financial incentives associated
with the residential and commercial DSM programs and in 1995,
recorded as operating revenues $900,000 of lost margins and
$220,000 of financial incentives.
The Company has made only two requests for base rate
increases since 1984. Its most recent request was made in 1993.
In response to that request, the DPU approved a base rate
increase designed to produce additional revenues of $6.7 million
or 4.9% annually, effective November 1, 1993.
The Company's goal is to postpone the filing of a request for its
next base rate increase until at least the year 2000 through
cost-cutting and other measures, such as its joint venture with
Cabot LNG, while maintaining an adequate return to shareholders.
Under a 1995 industry-wide ruling of the DPU, the Company will be
required in its next base rate filing either to present an
alternative incentive-based method of pricing or to justify
continuation of the traditional cost-of-service/rate-of-return
method. The Company has reviewed alternative incentive-based
pricing methods but has not yet determined what method of regulation
will be of greater benefit to its customers and shareholders.
During 1996, the DPU ordered all Massachusetts gas companies
to offer only "unbundled" gas service to interruptible and
special contract customers, as a means of promoting greater
competition at the city-gate. Unbundled service separates (i)
the part of the service involving procuring the gas and
transporting it to the city-gate (i.e. the point where the
Company takes gas from the interstate pipeline into its
distribution system); and (ii) the delivery of the gas to the
customer's facility through the local distribution system. The
Company had previously offered both bundled and unbundled service
to interruptible and special contract customers.
Since 1993, the Company also has been offering unbundled
service as an alternative to its firm commercial and industrial
customers. As of December 31, 1996, 19 customers had opted for
this firm transportation service, representing less than 2% of
the Company's annual firm load. The Company is analyzing
methods for making unbundled service viable for a greater number
of firm customers, and anticipates DPU rulings containing
additional unbundling guidelines in 1997.
In its 1996 order, the DPU continued to allow Massachusetts
gas companies to price interruptible services at negotiated rates
based on the value of that service to the customer.
Additionally, Massachusetts gas companies will now be permitted
to retain 25% of the net margins earned on interruptible sales,
interruptible transportation and capacity release transactions,
to the extent those margins exceed thresholds based on previous
activity. The Company had previously been allowed to retain 10%
of capacity release revenues above an initial threshold of
$2,5000,000 under its 1993 base rate proceeding. The amounts
retained by the Company from interruptible sales, interruptible
transportation and capacity release transactions in 1996, 1995
and 1994 totaled $0, $81,000 and $32,000, respectively. All
other revenues from these transactions flow back to firm sales
customers through the CGAC.
The Company follows the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation," requiring the Company to record
the financial statement effects of the rate regulation to which
the Company is currently subject. Future regulatory changes
could result in the Company no longer meeting the provisions of
SFAS No.71 for all or part of its business; thereby requiring the
elimination of the financial statement effects of regulation for
that portion of its business.
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 "Regulatory Matters", 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. As also discussed above in
"Regulatory Matters", the Company may now retain 25% of such
profit margins above an annual threshold level adjusted on April
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,
1996, the Company had incurred environmental response costs of
$11,156,000 of which $7,148,000 has been recovered from
customers to date. The Company expects to continue incurring
costs arising from these environmental matters.
As of December 31, 1996, the Company has recorded on the
balance sheet a long-term liability of $1,183,000 and, based
upon rate recovery, has recorded a corresponding regulatory
asset. This amount represents estimated future response costs
for these sites based on the Company's preferred methods of
remediation. 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.
TRANSGAS INC.
Transgas primarily provides over-the-road transportation of
liquefied natural gas, propane and other commodities. In 1996,
Transgas provided such service to approximately 60 commercial and
gas utility customers located in the eastern half of the United
States. Transgas also provides a highly specialized LNG portable
pipeline service, which permits gas utilities to provide a
continuous supply of natural gas to communities when pipeline gas
is interrupted for scheduled or emergency shutdowns or when
supplemental supplies are required during periods of peak winter
demand. Transgas is subject to various federal and state
regulations applicable to motor carriers of hazardous materials.
During 1996, Transgas discontinued its propane trucking
operations for non-utility customers.
Transgas had revenues of $11,031,000 in 1996. Approximately
73% of Transgas' revenue in 1996 was derived from transporting
LNG from DOMAC's import terminal, located in Everett,
Massachusetts. Transgas' revenues increased $3,455,000 or 45%
compared to 1995 due primarily to the colder than normal weather
in the fourth quarter of 1995 and the first quarter of 1996 which
generated a significant increase in demand for the truck
transportation of LNG throughout the year.
Transgas provides over-the-road transportation services by
utilizing a fleet of 54 tractors. Transgas operates over 60
trailers which are specifically designed for the transportation
of LNG and other cryogenic liquids. Of those cryogenic transport
trailers, 20 are leased to Transgas . In addition, Transgas has
11 trailers which are designed for the transportation of propane.
Of those propane transport trailers, 6 are leased to Transgas. In
addition to the equipment described above, Transgas also has 15
trailers which are equipped as portable LNG vaporizers, as well
as 2 flat bed trailers and 2 van trailers.
Transgas competes with 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 specialized LNG trailer
fleet and the number of LNG loads it delivers annually.
Transgas is presently wholly-owned by the Company. As
referenced above in "Gas Supply, Transportation and Storage
Resources", the Company has agreed to sell a 50% interest in
Transgas to Cabot LNG as part of a joint venture. The purchase
price for the 50% interest is $7,000,000. The Company's sale of
a 50% interest in Transgas and its lease of the Tewksbury LNG
facility to a joint venture entity are designed to combine the
Company's LNG trucking and storage capabilities with the
marketing and storage capabilities of Cabot LNG. Completion of
the sale of the Transgas interest and implementation of the joint
venture are subject to certain regulatory approvals. The Company
will recognize a one-time gain of approximately $.35 per share at
the time of the sale, expected to occur in the first half of
1997. Effective upon such sale, the Company will be recognizing
50% of the net income of Transgas on an equity basis.
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, Jr. (72) Chairman and Senior 1953
Executive Officer
Frederic L. Putnam, III (51) President and Chief 1975
Executive Officer
Charles W. Sawyer (51) Executive Vice
President and Chief
Operating Officer 1976
Nickolas Stavropoulos (39) Executive Vice President 1979
- Finance, Marketing, and
Chief Financial Officer
John P. Harrington (54) Senior Vice President 1966
- Gas Supply and Assistant
to the President
Victor W. Baur (53) President - Transgas Inc. 1972
Dennis W. Carroll (50) Vice President and Treasurer 1990
Charles A. Cook (44) Vice President and 1978
General 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. Mr. Cook has announced his intention to leave the
Company for private practice, effective May 1, 1997.
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 storage facility with approximately 1,000,000 Mcf of
LNG storage capacity located in Tewksbury, Massachusetts. As
part of the joint venture with Cabot LNG described above in "Gas
Supply, Transportation and Storage Resources", the Company has
agreed to lease the Tewksbury LNG facility to an entity owned
50/50 by the Company and Cabot LNG. The Company will continue to
own the Tewksbury LNG facility and, under one of the joint
venture agreements, will initially be its operator. In general,
the Company's gas production and storage facilities, metering and
regulation stations and operations centers, including the
Tewksbury LNG facility, are 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 2,960
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, 1996.
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 1996 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 1996 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 1996 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 1996 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 pursuant
to Item 401 of Regulation S-K for the Company's Directors is
incorporated by reference to the information reported in the
Company's Proxy Statement for its 1997 annual meeting of
stockholders under the caption "Election of Directors".
The information required to be reported hereunder pursuant
to Item 401 of Regulation S-K 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".
The information required to be reported hereunder pursuant
to Item 405 of Regulation S-K is incorporated by reference to the
information reported in the Company's Proxy Statement for its
1997 annual meeting of stockholders under the caption "Section
16(a) Beneficial Ownership Reporting Compliance".
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 1997 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 1997 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 1997 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 1996 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 Page
Number Description Number
Report of Independent Certified
Public Accountants on Schedule
II Valuation and Qualifying Accounts
for the three years ended
December 31, 1996
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
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, Incorporated herein
executed on September 27, 1995, by reference.
relating to the Secured Medium Term
Notes, Series A, filed as Exhibit
4(c) to the Registrant's Form 10-K
for the fiscal year ended December
31, 1995.
4d Amendment to Second Supplemental Incorporated herein
Indenture, dated as of October 12, by reference.
1995, relating to the Secured Medium
Term Notes, Series A, filed as
Exhibit 4(d) to the Registrant's
Form 10-K for the fiscal year ended
December 31, 1995.
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 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.
10s 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.
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(oo) 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(pp) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10v 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.
10w 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.
10x 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.
10y 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.
10z 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.
10aa 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.
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(xx) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10cc 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.
10dd 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.
10ee 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.
10ff 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.
10gg 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.
10hh 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.
10ii 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.
10jj 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.
10kk 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.
10ll 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.
10mm Firm Natural Gas Transportation Incorporated herein
Agreement between Tennessee Gas by reference.
Pipeline Company and Colonial Gas
Company (under Rate Schedule NET-
Northeast), dated August 1, 1995,
filed as Exhibit 10(qq) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1995.
10nn Gas Transportation Agreement between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FT-A), dated June 1, 1995,
filed as Exhibit 10(rr) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1995.
10oo Amendment No. 1 (dated July 1, 1995) Incorporated herein
to Gas Storage Contract between by reference.
Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate
Schedule FS), dated December 1, 1994
(which superseded contract dated
September 1, 1993), filed as Exhibit
10(ss) to the Registrant's Annual
Report on Form 10-K for the fiscal
year ended December 31, 1995.
10pp Amendment to Gas Transportation Incorporated herein
Contract for Firm Reserved Service by reference.
with Iroquois Gas Transmission
System, L.P., dated September 1,
1995, filed as Exhibit 10(tt) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1995.
10qq Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule AFT-1), dated December 1,
1995, filed as Exhibit 10(uu) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1995.
10rr Amendment to Storage Service Filed herewith as
agreement with Penn-York Energy Exhibit 10rr.
Corporation (referenced as Exhibit
10b above) dated May 1, 1996 between
Colonial Gas Company and National
Fuel Gas Supply Corporation
(successor -in-interest to Penn-York
Energy Corporation)
10ss Service Agreement between National Filed herewith as
Fuel Gas Supply Corporation and Exhibit 10ss.
Colonial Gas Company (FST Service)
dated April 12, 1996 and amended May
1, 1996 and December 1, 1996.
10tt Service Agreement between National Filed herewith as
Fuel Gas Supply Corporation and Exhibit 10tt.
Colonial Gas Company (FSS Service)
dated April 12, 1996 and amended May
1, 1996 and December 1, 1996.
10uu Firm Gas Transportation Agreement Filed herewith as
between Koch Gateway Pipeline Co. Exhibit 10uu.
and Colonial Gas Company (FTS
Service) dated November 1, 1996.
10vv Service Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10vv.
Colonial Gas Company (under Rate
Schedule AFT-E) dated November 2,
1996.
10ww Service Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10ww.
Colonial Gas Company (under Rate
Schedule AFT-E) dated November 17,
1996.
10xx 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.
10yy 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.
10zz 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.
10aaa 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 1996 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 10zz and 10aaa 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 13, 1997, which is included
in the 1996 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 13, 1997
SCHEDULE II
COLONIAL GAS COMPANY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Three Years Ended December 31, 1996
(In Thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE CHARGED BALANCE
AT TO COSTS AT
DESCRIPTION BEGINNING AND DEDUCT- END OF
OF PERIOD EXPENSES IONS PERIOD
For the Year Ended December 31, 1996
Reserve for $2,205 $2,127 $1,617 (1) $2,715
uncollectible accounts
Reserve for insurance $634 $510 $402 $742
claims
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
_____________________________
(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 25, 1997
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
s/F.L. Putnam, Jr. Senior Executive Officer, March 25, 1997
F.L. Putnam, Jr. Director
s/Nickolas Stavropoulos Executive Vice President - March 25, 1997
Nickolas Stavropoulos Finance, Marketing and Chief
Financial Officer,Director
(Principal Financial Officer)
s/D.W. Carroll Vice President and Treasurer March 25, 1997
D.W. Carroll (Principal Accounting Officer)
s/V.W. Baur Director March 25, 1997
V.W. Baur
s/J.P. Harrington Director March 25, 1997
J.P. Harrington
s/H.C. Homeyer Director March 25, 1997
H.C. Homeyer
s/R.L. Hull Director March 25, 1997
R.L. Hull
s/D.H. LeVan, Jr. Director March 25, 1997
D.H. LeVan, Jr.
s/F.L. Putnam, III President and Chief March 25, 1997
F.L. Putnam, III Executive Officer, Director
s/J.F. Reilly, Jr. Director March 25, 1997
J.F. Reilly, Jr.
s/A.B. Sides, Jr. Director March 25, 1997
A.B. Sides, Jr.
s/M.M. Stapleton Director March 25, 1997
M.M. Stapleton
s/C.O. Swanson Director March 25, 1997
C.O. Swanson
[EXHIBIT 10rr TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
AMENDMENT TO
UNDERGROUND STORAGE SERVICE AGREEMENT
Rate Schedule SS-1
The parties to a certain Underground Storage Service
Agreement ("the Agreement"), dated as of December 21, 1984,
between National Fuel Gas Supply Corporation (successor -in-
interest to Penn-York Energy Corporation), and Colonial Gas
Company, hereby amend the Agreement, effective May 1, 1996,
as follows:
1. Article I of the Agreement shall be replaced in its
entirety with the following:
ARTICLE I
Character of Service and Volumes
Beginning on the date of the first injection of
Buyer's gas for storage hereunder and thereafter for the
remaining term of this agreement, Seller agrees to (a)
transport or cause gas to be transported for Buyer from the
delivery point set forth in Article IV hereof, (b) store
gas, and (c) transport or cause gas to be transported to the
delivery point set forth in Article IV hereof, as provided
herein, and Buyer agrees to engage Seller to transport and
store, and to pay therefor, volumes of natural gas as
follows:
(i) Annual Storage Volume
The Annual Storage Volume for the entire term of
this agreement is 1,098,350 Mcf.
(ii) Maximum Daily Injection Volume
The Maximum Daily Injection Volume for the period
commencing with the first injection of Buyer's gas for
storage hereunder and continuing for the remaining term of
this agreement will vary according to the percentage of
Buyer's Annual Storage Volume occupied at the commencement
of any given day as follows:
Percentage Maximum Daily
Annual Injection Volume
Storage Based on 1,098,350
Volume Occupied (Mcf)
Less than 10% 7,322
From greater than 10% to 30% 6,865
From greater than 30% to 50% 6,276
From greater than 50% to 70% 5,937
From greater than 70% to 100% 5,492
(iii) Maximum Daily Withdrawal Volume
The Maximum Daily Withdrawal Volume for the period
commencing with the first injection of Buyer's gas for
storage hereunder and continuing for the remaining term of
this agreement will vary according to the percentage of
Buyer's Annual Storage Volume occupied at the commencement
of any given day as follows:
Percentage Maximum Daily
Annual Withdrawal Volume
Storage Based on 1,098,350
Volume Occupied (Mcf)
From greater than 30% to 100% 9,985
From greater than 15% to 30% 9,153
From greater than 10% to 15% 8,136
Less than 10% 7,322
2, Article II of the Agreement shall be replaced in its
entirety with the following:
ARTICLE II
Term of Agreement
The term of this agreement shall commence as of May 1,
1996 and continue in effect until March 31, 1998, and from
year to year thereafter until terminated by either Seller or
Buyer upon not less than 12 months' prior written notice to
the other specifying a termination date at the end of such
period or any subsequent anniversary thereof.
3. Article IV of the Agreement shall be replaced in its
entirety with the following:
ARTICLE IV
Delivery Point and Pressures
The point of delivery for gas received for Buyer's
account by Seller and re-delivered by Seller to or for
Buyer's account shall be at the pipeline interconnection of
Seller's Line EC-1 with the interstate transmission
facilities of Tennessee Gas Pipeline Company ("Tennessee")
(Andrews Settlement) and/or other facilities of Seller near
Seller's Ellisburg Station in Potter County, Pennsylvania.
The gas received by Seller at the Ellisburg interconnection
shall be at the pressure at which Tennessee or Seller is
operating its facilities, but not less than 400psig, and
upon redelivery to or for the account of Buyer shall be at
pipeline pressures suitable for delivery into Tennessee's or
Seller's system, as the case may be; provided that Seller
shall not be obligated to deliver gas at a pressure in
excess of 1,000psig.
The partied hereto have caused this Amendment to be
duly executed by their proper officers thereunto duly
authorized as of the date first above written.
ATTEST: NATIONAL FUEL GAS SUPPLY
CORPORATION
By:
__/s/ illegible__________ __/s/__William A. Ross______
Secretary Vice President
ATTEST: COLONIAL GAS COMPANY
__/s/_Phyllis Semenchuk__ By:__/s/__John P. Harrington___
Secretary Senior Vice President-
Gas Supply
[END OF EXHIBIT 10rr]
[EXHIBIT 10ss TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
SERVICE AGREEMENT #NO1733
(FST Service)
AGREEMENT made this 12th day of April, 1996, by and
between NATIONAL FUEL GAS SUPPLY CORPORATION, hereinafter called
"Transporter" and COLONIAL GAS COMPANY, hereinafter called "Shipper."
WHEREAS, Shipper has requested that Transporter has
transport natural gas; and
WHEREAS, Transporter has agreed to provide such
transportation for Shipper subject to the terms and conditions hereof.
WITNESSETH, That, in consideration of the mutual
covenants herein contained, the parties hereto agree that
Transporter will transport for Shipper, on a firm basis, and
Shipper will furnish, or cause to be furnished, to Transporter
natural gas for such transportation during the term hereof, at
the prices and on the terms and conditions hereinafter provided.
ARTICLE I
Quantities
Beginning on the date on which deliveries of gas are
commenced hereunder and thereafter for the remaining term of this
Agreement, and subject to the provisions of Transporter's FST
Rate Schedule, Transporter agrees to transport for Shipper up to
the following quantities of natural gas:
Contract Maximum Daily Injection Transportation Quantity (MDITQ)
of 4,652 Dekatherms (Dth)
Contract Maximum Daily Withdrawal Transportation Quantity (MDWTQ)
of 6,203 Dekatherms (Dth)
ARTICLE II
Rate
Unless otherwise mutually agreed in a written amendment
to this Agreement for the service provided by Transporter
hereunder, Shipper shall pay Transporter the maximum rate
provided under Rate Schedule FST set forth in Transporter's
effective FERC Gas Tariff. In the event that Transporter places
on file with the Federal Energy Regulatory Commission
("Commission") another rate schedule which may be applicable to
transportation service rendered hereunder, then Transporter, at
its option, may from and after the effective date of such rate
schedule, utilize such rate schedule in performance of this
Agreement. Such a rate schedule (s) or superseding rate
schedule (s) and any revisions thereof which shall be filed and
become effective shall apply to and be a part of this Agreement.
Transporter shall have the right to propose, file and make
effective with the Commission, or other body having jurisdiction,
changes and revisions of any effective rate schedule (s), or to
propose, file, and make effective superseding rate schedule, for
the purpose of changing the rate, charges, and other provisions
thereof effective as to Shipper.
Shipper does not hereby waive its right to protest or
contest the aforementioned filings.
ARTICLE III
Term of Agreement
This Agreement shall be effective as of the effective
date of an amendment to the Underground Storage Service Agreement
between Transporter and Shipper, pursuant to Transporter's Rate
Schedule SS-1, that reduces the Annual Storage Volume thereunder
from 2,000,000 Mcf to 1,098,350 Mcf. This Agreement shall
continue in effect until March 31, 2000 [BY 12/1/96 AMENDMENT;
PREVIOUSLY, "MARCH 31, 1998"], and shall continue in
effect from year to year thereafter until terminated by either
Transporter or Shipper upon not less than 12 months' prior
written notice to the other specifying as a termination date the
end of such period or any subsequent anniversary thereof.
ARTICLE IV
Points of Receipt and Delivery
The primary injection receipt point (s) and the primary
withdrawal delivery point (s) shall be the pipeline
interconnection of Transporter's Line EC-1 with the interstate
transmission facilities of Tennessee Gas Pipeline Company
("Tennessee") (known as Andrews Settlement) and/or other
facilities of Transporter near Transporter's Ellisburg Station in
Potter County, Pennsylvania.
The primary injection delivery point (s) and the primary
withdrawal receipt point (s) shall be Transporter's System
Storage.
ARTICLE V
Gas Pressures at Points of Receipt and Delivery
The gas received by Transproter at the primary injection
receipt point (s) shall be at the pressure at which
Transporter or Tennessee is operating its Facilities, but not
less than 400 psig, and upon redelivery to or for the account
of Shipper at the primary withdrawal delivery point (s) shall
be at pipeline pressures suitable for delivery into
Tennessee's or Transporter's system, as the case may be;
provided that Transporter shall no be obligated to deliver
gas at a pressure in excess of 1,000 psig.
ARTICLE VI
Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and
conditions of this agreement, the provisions of Rate Schedule
FST, or any effective superseding rate schedule or otherwise
applicable rate schedule, including any provisions of the General
Terms and Conditions incorporated therein, and any revisions
thereof that may be made effective hereafter are hereby made
applicable to and a part hereof by reference.
ARTICLE VII
Miscellaneous
1. No charge, modification or alteration of this
Agreement shall be or become effective until executed in writing
by the parties hereto, and no course of dealing between the
parties shall be construed to alter the terms hereof, except as
expressly stated herein.
2. No waiver by any 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 other
default or defaults, whether of a like or of a different
character.
3. Any company which shall succeed by purchase, merger
or consolidation of the gas related 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.
Either party may, without relieving itself of its obligations
under this Agreement, assign any of its rights hereunder to a
company with which it is affiliated, but otherwise, no assignment
of this Agreement or of any of the rights or obligations
hereunder shall be made unless there first shall have been
obtained the consent thereto in writing of the other party.
Consent shall not be unreasonably withheld.
4. 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
the other, shall be in writing and shall be considered as duly
delivered when mailed by registered or certified mail to the Post
Office address of the parties hereto, as the case may be, as
follows:
Transporter: National Fuel Gas Supply Corporation
Gas Supply - Transportation
10 Lafayette Square
Buffalo, New York 14203
Shipper: Colonial Gas Company
40 Market Street
Lowell , Massachusetts 01853
Attn.: John P. Harrigton
Senior Vice President, Gas Supply
or at such other address as either party shall designate by
formal written notice. Routine communications, including monthly
statements, shall be considered as duly delivered when mailed by
either registered, certified, or ordinary mail, electronic
communication, or telecommunication.
5. This Agreement and the respective obligations of
the parties hereunder are subject to all present and future valid
laws, orders, rules and regulations of constituted authorities
having jurisdiction over the parties, their functions or gas
supply, this Agreement or any provision hereof. Neither party
shall be held in default for failure to perform hereunder if such
failure is due to compliance with laws, orders, rules or
regulations of any such duly constituted authorities.
6. The subject headings of the articles of this
Agreement are inserted for the purpose of convenient reference
and are not intended to be a part of he Agreement nor considered
in any interpretation of the same.
7. No presumption shall operate in favor of or against
either party hereto as a result of any responsibility either
party may have had for drafting this Agreement.
8. The interpretation and performance of this
Agreement shall be in accordance with the laws of the State of
Pennsylvania, without recourse to the law regarding the conflict
of laws.
The parties hereto have caused this Agreement to be
signed by their duly authorized personnel the day and year first
above written.
NATIONAL FUEL GAS SUPPLY CORPORATION
(Transporter)
____William A. Ross__________________________
Vice President
COLONIAL GAS COMPANY
(Shipper)
____John P. Harrington_____________________
Senior Vice President - Gas Supply
AMENDMENT I
Amendment to FSS Service Agreement # 001734
and FST Service Agreement #N01733
between
NATIONAL FUEL GAS SUPPLY CORPORATION ("TRANSPORTER") AND
COLONIAL GAS COMPANY ("SHIPPER")
EFFECTIVE MAY 1, 1996
1. The rates to be charged to Shipper under the above-referenced
agreements shall be calculated to recover the revenues that
would have been collected from the Shipper had the Shipper
entered into a new SS-2 Service Agreement for an Annual Storage
Volume of 901,650 Mcf. To arrive at rates that recover such
revenues, Transporter shall discount the following components,
only as necessary, in the following sequence:
FSS GRI Reservation
FST GRI Reservation
FSS GRI Commodity
FST GRI Commodity
FSS Injection/Withdrawal
FSS Storage Capacity
FSS Storage Demand
As of the effective date of this Amendment, the rates to be
charged under the above-captioned Agreements are as follows:
FSS
(Dth basis)
Storage Demand $2.1556
Storage Capacity $0.0413
Injection $0.0000
Withdrawal $0.0000
ACA Commodity $0.0022
GRI Reservation $0.0000
GRI Commodity $0.0000
FST
(Dth basis)
Reservation $3.5637
Gathering Surcharge
-Reservation $0.1486
Commodity $0.0064
ACA Commodity $0.0022
GRI Reservation $0.0000
GRI Commodity $0.0000
The attached table shows the methodology used to arrive at the
rates set forth above. If the rates under Rate Schedule SS-2,
FSS or FST change during the term of these agreements, the rates
shown above shall be adjusted, using the same methodology as
that shown on the attached table. This methodology shall
continue to be used to determine the rates applicable to Shipper
even if Transporter places on file with the Federal Energy
Regulatory Commission a superseding rate schedule, as described
in Article II of the FSS and FST Service Agreement, and elects
to utilize such superseding rate schedule in performance of the
services governed by such agreement.
2. Tranporter shall retain the full Surface Operating Allowance
under the FSS Rate Schedule. With respect to the service
provided under the FST Rate Schedule, no fuel, loss and
company-use retention shall be applied to quantities transported
between the primary points set forth in the service agreement,
or between the primary injection delivery point or primary
withdrawal receipt point and the following secondary points:
Tennessee at Ellisburg Meter 020527
Transco at Wharton Meter 6325
CNG at Ellisburg Meter 41202
TransCanada at Niagara Meter 010902
Texas Eastern at Bristoria Meter 70015
Otherwise, the full fuel, loss and company-use retention shall
be applied.
NATIONAL FUEL GAS SUPPLY CORPORATION
____William A. Ross_____________
By:_____________________________
Title:___Vice President_________
COLONIAL GAS COMPANY
____John P. Harrington__________
By:_____________________________
Title:__Senior_Vice President__
-Gas Supply
Colonial Gas Rates
Capacity 930,450 Dth
Deliverability 6,203 Dth/day
SS-2
SS-2 or FSS: Rate Annual Cost
Storage Demand $8.1470 $606,430
Storage Capacity $0.0260 $290,300
Injection $0.0106 $9,863
Withdrawal $0.0106 $9,863
Surface operating
allowance charge $0.0106 $276
ACA commodity $0.0000
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation
Gathering surcharge reservation
Commodity
ACA commodity
GRI Resrcation
GRI commodity
TOTAL ANNUAL COSTS $916,732
UNIT RATE (per Dth) $0.9853
Maximum FSS/FST
SS-2 or FSS: Maximum Rate Annual Cost
Storage Demand $2.1556 $160,454
Storage Capacity $0.0432 $482,345
Injection $0.0139 $12,933
Withdrawal $0.0139 $12,933
Surface operating
allowance charge
ACA commodity $0.0022 $2,047
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation $3.5637 $265,268
Gathering surcharge
reservation $0.1486 $11,061
Commodity $0.0064 $11,910
ACA commodity $0.0022 $4,094
GRI Reservation $0.0000
GRI commodity $0.0000
TOTAL ANNUAL COST $963,046
UNIT RATE (per Dth) $1.0350
Discounted FSS/FST
SS-2 or FSS: Rate Annual Cost
Storage Demand $2.1556 $160,454
Storage Capacity $0.0432 $461,131
Injection $0.0000 $0
Withdrawal $0.0000 $0
Surface operating
allowance charge
ACA commodity $0.0022 $2,047
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation $3.5637 $265,268
Gathering surcharge
reservation $0.1486 $11,061
Commodity $0.0064 $11.910
ACA commodity $0.0022 $4,094
GRI Reservation
GRI commodity
TOTAL ANNUAL COSTS $915,965
UNIT RATE (per Dth) $0.9844
[END OF EXHIBIT 10ss]
[EXHIBIT 10tt TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
SERVICE AGREEMENT #001734
(FSS Service)
AGREEMENT made this 12th day of April, 1996, by and
between NATIONAL FUEL GAS SUPPLY CORPORATION, hereinafter
called "Transporter" and COLONIAL GAS COMPANY, hereinafter
called "Shipper."
WITNESSETH: That in consideration of the mutual
covenants herein contained, the parties hereto agree that
Transporter will store natural gas for Shipper during the
term, at the rates and on the terms and conditions
hereinafter provided.
ARTICLE I
Quantities
Beginning on the date on which storage service is
commenced hereunder and thereafter for the remaining term of
this Agreement, and subject to the provisions of
Transporter's FSS Rate Schedule, Transporter agrees to
receive, cause to be injected into storage for Shipper's
account, store, withdraw from storage, and deliver to
Shipper quantities of natural gas as follows:
Maximum Storage Quantity (MSQ) of 930,450 Dekatherms (Dth)
Maximum Daily Injection Quantity (MDIQ) of 4,652 Dth
Maximum Daily Withdrawal Quantity (MDWQ) of 6,203 Dth
ARTICLE II
Rates
Unless otherwise mutually agreed in a written amendment
to this Agreement, for the service provided by Transporter
hereunder, Shipper shall pay Transporter the maximum rate
provided under Rate Schedule FSS set forth in Transporter's
effective FERC Gas Tariff. In the event that the
Transporter places on file with the Federal Energy
Regulatory Commission ("Commission") another rate schedule
which may be applicable to transportation service rendered
hereunder, then Transporter, at its option, may from and
after the effective date of such rate schedule, utilize such
rate schedule in performance of this Agreement. Such a rate
schedule(s) or superseding rate schedule(s) and any
revisions thereof which shall be filed and become effective
shall apply to and be part of this Agreement.
Transporter shall have the right to propose, file and
make effective with the Commission, or other body having
jurisdiction, changes and revisions of any effective rate
schedule(s), or to propose, file, and make effective
superseding rate schedules, for the purpose of changing the
rate, charges, and other provisions thereof effective as to
Shipper.
Shipper does not hereby waive its right to protest or
contest the aforementioned filings.
ARTICLE III
Term of Agreement
This Agreement shall be effective as of the effective
date of an amendment to the Underground Storage Service
Agreement between Transporter and Shipper, pursuant to
Transporter's Rate Schedule SS-1, that reduces the Annual
Storage Volume thereunder from 2,000,000 Mcf to 1,098,350
Mcf. This Agreement shall continue in effect until March
31, 2000 [BY 12/1/96 AMENDMENT; PREVIOUSLY MARCH 31,1998],
and shall continue in effect from year to year
thereafter until terminated by either Transporter or Shipper
upon not less than 12 months' prior written notice to the
other specifying as a termination date the end of such
period or any subsequent anniversary thereof.
The Injection Period shall commence April 1st of
each year and end the following October 31st. The
Withdrawal Period shall commence November 1st of each year
and end the following March 31st.
ARTICLE IV
Receipt and Delivery Points
The Point of Receipt for all gas that may be received
for Shipper's account for storage by Transporter shall be
Transporter's System Storage.
The Point of Delivery for all gas to be delivered by
Transporter for Shipper's account shall be Transporter's
System Storage.
ARTICLE V
Incorporation by Reference of Tariff Provisions
To the extent not inconsistent with the terms and
conditions of this agreement, the provisions of Rate
Schedule FSS, or any effective superseding rate schedule or
otherwise applicable rate schedule, including any provisions
of the General Terms and Conditions incorporated therein,
and any revisions thereof that may be made applicable to and
part hereof by reference.
ARTICLE VI
Miscellaneous
1. No change, modification or alteration of this
Agreement shall be or become effective until executed in
writing by the parties hereto, and no course of dealing
between the parties shall be construed to alter the terms
hereof, except as expressly stated herein.
2. No waiver by any 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
other default or defaults, whether of a like or of a
different character.
3. Any company which shall succeed by purchase,
merger or consolidation of the gas related properties,
substantially as an entirety, of Transporter or of Shipper,
as the case may be entitled to the rights and shall be
subject to the obligations of its predecessor in title under
this Agreement. Transporter may, without relieving itself
of its obligations under this Agreement, assign any of its
rights hereunder to a company with which it is affiliated,
but otherwise, no assignment of this Agreement or of any of
the rights or obligations hereunder shall be made unless
there first shall have been obtained the consent thereto in
writing of the other party. Consent shall not be
unreasonably withheld.
4. 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 the other, shall be in writing and shall be considered
as duly delivered when mailed by registered or certified
mail to the Post Office address of the parties hereto, as
the case may be, as follows:
Transporter: National Fuel Gas Supply Corporation
Gas Supply - Transportation
Room 1200
10 Lafayette Square
Buffalo, New York 14203
Shipper: Colonial Gas Company
40 Market Street
Lowell, Massachusetts 01853
Attn.: John P. Harrington
Senior Vice President, Gas Supply
or at such other address as either party shall designate by
formal written notice. Routine communications, including
monthly statements, shall be considered as duly delivered
when mailed by either registered, certified, or ordinary
mail, electronic communication, or telecommunication.
5. This Agreement and the respective obligations of
the parties hereunder are subject to all present and
future valid laws, orders, rules and regulations of
constituted authorities having jurisdiction over the
parties, their functions or gas supply, this Agreement or
any provision hereof. Neither party shall be held in
default for failure to perform hereunder if such failure is
due to compliance with laws, orders, rules or regulations of
any such duly constituted authorities.
6. The subject headings of the articles of this
Agreement are inserted for the purpose of convenient
reference and are not intended to be part of the Agreement
nor considered in any interpretation of the same.
7. No presumption shall operate in favor of or
against either party hereto as a result of any
responsibility either party may have had for drafting this
Agreement.
8. The interpretation and performance of this
Agreement shall be in accordance with the laws of the State
of Pennsylvania, without recourse to the law regarding the
conflict of laws.
The parties hereto have caused this Agreement to be
signed by their respective Presidents or Vice Presidents
thereunto duly authorized the day and year first above
written.
National Fuel Gas Supply Corporation
(Transporter)
_______William A. Ross________________
Vice President
Colonial Gas Company
(Shipper)
_________John P. Harrington____________
_____Senior Vice President-Gas Supply__
Title
AMENDMENT I
Amendment to FSS Service Agreement # 001734
and FST Service Agreement #N01733
between
NATIONAL FUEL GAS SUPPLY CORPORATION ("TRANSPORTER") AND
COLONIAL GAS COMPANY ("SHIPPER")
EFFECTIVE MAY 1, 1996
1. The rates to be charged to Shipper under the above-referenced
agreements shall be calculated to recover the revenues that
would have been collected from the Shipper had the Shipper
entered into a new SS-2 Service Agreement for an Annual Storage
Volume of 901,650 Mcf. To arrive at rates that recover such
revenues, Transporter shall discount the following components,
only as necessary, in the following sequence:
FSS GRI Reservation
FST GRI Reservation
FSS GRI Commodity
FST GRI Commodity
FSS Injection/Withdrawal
FSS Storage Capacity
FSS Storage Demand
As of the effective date of this Amendment, the rates to be
charged under the above-captioned Agreements are as follows:
FSS
(Dth basis)
Storage Demand $2.1556
Storage Capacity $0.0413
Injection $0.0000
Withdrawal $0.0000
ACA Commodity $0.0022
GRI Reservation $0.0000
GRI Commodity $0.0000
FST
(Dth basis)
Reservation $3.5637
Gathering Surcharge
-Reservation $0.1486
Commodity $0.0064
ACA Commodity $0.0022
GRI Reservation $0.0000
GRI Commodity $0.0000
The attached table shows the methodology used to arrive at the
rates set forth above. If the rates under Rate Schedule SS-2,
FSS or FST change during the term of these agreements, the rates
shown above shall be adjusted, using the same methodology as
that shown on the attached table. This methodology shall
continue to be used to determine the rates applicable to Shipper
even if Transporter places on file with the Federal Energy
Regulatory Commission a superseding rate schedule, as described
in Article II of the FSS and FST Service Agreement, and elects
to utilize such superseding rate schedule in performance of the
services governed by such agreement.
2. Tranporter shall retain the full Surface Operating Allowance
under the FSS Rate Schedule. With respect to the service
provided under the FST Rate Schedule, no fuel, loss and
company-use retention shall be applied to quantities transported
between the primary points set forth in the service agreement,
or between the primary injection delivery point or primary
withdrawal receipt point and the following secondary points:
Tennessee at Ellisburg Meter 020527
Transco at Wharton Meter 6325
CNG at Ellisburg Meter 41202
TransCanada at Niagara Meter 010902
Texas Eastern at Bristoria Meter 70015
Otherwise, the full fuel, loss and company-use retention shall
be applied.
NATIONAL FUEL GAS SUPPLY CORPORATION
___William A. Ross______________
By:_____________________________
Title:__Vice President__________
COLONIAL GAS COMPANY
____John P. Harrington__________
By:_____________________________
Title:__Senior Vice President___
Gas Supply
Colonial Gas Rates
Capacity 930,450 Dth
Deliverability 6,203 Dth/day
SS-2
SS-2 or FSS: Rate Annual Cost
Storage Demand $8.1470 $606,430
Storage Capacity $0.0260 $290,300
Injection $0.0106 $9,863
Withdrawal $0.0106 $9,863
Surface operating
allowance charge $0.0106 $276
ACA commodity $0.0000
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation
Gathering surcharge reservation
Commodity
ACA commodity
GRI Resrcation
GRI commodity
TOTAL ANNUAL COSTS $916,732
UNIT RATE (per Dth) $0.9853
Maximum FSS/FST
SS-2 or FSS: Maximum Rate Annual Cost
Storage Demand $2.1556 $160,454
Storage Capacity $0.0432 $482,345
Injection $0.0139 $12,933
Withdrawal $0.0139 $12,933
Surface operating
allowance charge
ACA commodity $0.0022 $2,047
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation $3.5637 $265,268
Gathering surcharge
reservation $0.1486 $11,061
Commodity $0.0064 $11,910
ACA commodity $0.0022 $4,094
GRI Reservation $0.0000
GRI commodity $0.0000
TOTAL ANNUAL COST $963,046
UNIT RATE (per Dth) $1.0350
Discounted FSS/FST
SS-2 or FSS: Rate Annual Cost
Storage Demand $2.1556 $160,454
Storage Capacity $0.0432 $461,131
Injection $0.0000 $0
Withdrawal $0.0000 $0
Surface operating
allowance charge
ACA commodity $0.0022 $2,047
GRI reservation $0.0000
GRI commodity $0.0000
FST:
Reservation $3.5637 $265,268
Gathering surcharge
reservation $0.1486 $11,061
Commodity $0.0064 $11.910
ACA commodity $0.0022 $4,094
GRI Reservation
GRI commodity
TOTAL ANNUAL COSTS $915,965
UNIT RATE (per Dth) $0.9844
[END OF EXHIBIT 10tt]
[EXHIBIT 10uu TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
FIRM GAS TRANSPORTATION SERVICE AGREEMENT
PURSUANT TO SECTION 284, SUBPART "G" or "B"
between KOCH GATEWAY PIPELINE COMPANY, as KGPC, and
COLONIAL GAS COMPANY, as CUSTOMER
Rate Schedule FTS
Option SCO Yes[ ]
No[X]
Reference No.:10344
CUSTOMER Correspondence:
COLONIAL GAS COMPANY
40 Market Street
Lowell, MA 01852
Attn: John P. Harrington
Telephone No. (508)458-3171
Fax No. (508)453-3999
Contract No.: 20958
CUSTOMER Billing:
COLONIAL GAS COMPANY
40 Market Street
Lowell, MA 01852
Attn: John P. Harrington
Telephone No. (508)458-3171
Fax No. (508)453-3999
Contract Date: November 1, 1996
Primary Term: 2 Years Beginning 7:00 A.M. on November 1, 1996
Thru 7:00 A.M. on November 1, 1998
Contract Maximum Daily Quantity (MDQ) 3310 MMBtu Contract Rate Type: IV
KGPC's Transportation Services Dept:
Telephone No. (800) 890-0205 Fax No. (713) 229-4624
CUSTOMER's Dispatcher: Joseph Murphy
Telephone No. (508)458-3177 ext. 3439 Fax No. (508)459-2314
Primary Receipt Point(s):
Station Location Primary Point MDQ
Number Description (MMBtu)
-------- SEE EXHIBIT A --------
Primary Delivery Point(s):
Station Location Primary Point MDQ
Number Description (MMBtu)
-------- SEE EXHIBIT B --------
(ALL POINTS ARE AVAILABLE AS SUPPLEMENTAL RECEIPT AND DELIVERY POINTS UP TO
THE CONTRACT MDQ)Special Provisions: Service hereunder is provided
pursuant to Section 284 either Subpart G or B.
please indicate below as appropriate:
Subpart G [X] Service hereunder is subject to Section 284.223, Title 18,
of the Code of Federal Regulations, or
Subpart B [ ] Service hereunder is subject to Section 284.101, Title 18,
of the Code of Federal Regulations, and CUSTOMER must execute Exhibit C
and the affidavits attached thereto, all of which are hereby incorporated by
reference and made a part of this Agreement. THE STANDARD TERMS AND
CONDITIONS SET FORTH ON THE REVERSE SIDE ARE INCORPORATED HEREIN BY
REFERENCE. IF YOU ARE IN AGREEMENT WITH THE FOREGOING, PLEASE INDICATE
IN THE SPACE PROVIDED BELOW.
KGPC Signature:
Date:
Name: Dan Stecklein
Title: President
CUSTOMER
Signature:
Date:
Name:John P. Harrington
Title: Senior Vice President- Gas Supply
STANDARD TERMS & CONDITIONS
1. CONDITIONS OF SERVICE:
Services provided hereunder are subject to and governed by the applicable
rate schedule and the General Terms and Conditions of KGPC's current
tariff, as may be revised from time to time, or any effective superseding
tariff (Tariff) on file with the Federal Energy Regulatory Commission
(FERC). The Tariff is incorporated by reference. In the event
of any conflict between this Agreement and the Tariff, the Tariff
shall govern as to the conflict. KGPC shall have the right to
interrupt service under this Agreement to the extent permitted by the Tariff.
2. TRANSPORTATION QUANTITY: CUSTOMER may deliver or cause to be
delivered to KGPC at the firm Primary Receipt Point(s) and Supplemental
receipt point(s) and KGPC agrees to accept, at such point(s) for
transportation, daily quantities of natural gas up to the
Contract MDQ. KGPC shall redeliver Equivalent Quantities, as
defined in the Tariff, to CUSTOMER at firm Primary Delivery
Points provided herein, and at Supplemental delivery points as
may be determined from time to time. Should CUSTOMER desire a
change in the Contract MDQ, CUSTOMER shall notify KGPC in
writing of the amount of the increase or decrease and of the
date CUSTOMER desires the change to become effective. If KGPC
advises it is not agreeable to the changed quantities of gas
requested in CUSTOMER's notice, the Contract MDQ shall remain
unchanged. KGPC shall review CUSTOMER's request within thirty
(30) days subject to the Tariff. Nothing herein shall require
KGPC to install equipment or facilities.
3. QUALITY AND PRESSURE: The gas received and delivered
hereunder shall be merchantable and of a quality sufficient to
meet the Tariff standards. Gas delivered to KGPC shall be at a
delivery pressure adequate to enter KGPC's facilities and such
pressure shall not exceed the Maximum Allowable Operating Pressure.
4. TERM: This Agreement shall become effective as of 7:00 A.M.
on the beginning Primary Term Date and continue as stated on the
face hereof and month to month thereafter.
5. TERMINATION: Subject to Section 30 of the General Terms and
Conditions of the Tariff, either party may cancel this Agreement
effective as of the end of the Primary Term by giving written
notice to the other at least thirty (30) days prior to the date
on which cancellation is requested. Termination of this
Agreement shall not relieve KGPC and CUSTOMER of the obligation
to correct any volume imbalances, or CUSTOMER to pay money due
to KGPC or KGPC to pay amount due to CUSTOMER.
6. TRANSPORTATION CHARGES: CUSTOMER shall be obligated to pay
KGPC monthly for the service provided under this Agreement.
CUSTOMER shall pay KGPC for any transportation of liquid
hydrocarbons and liquefiables. Pursuant to the Tariff, KGPC
shall retain Fuel and Company-Used Gas in-kind or, if mutually
agreed upon, CUSTOMER shall reimburse KGPC in cash for fuel and
Company-Used Gas. Such charges are specified in the FTS Rate
Schedule and/or the FTS Rate Sheet of the Tariff. KGPC may from
time elect in writing to collect a rate lower than that
specified in the FTS Rate Schedule of the Tariff. KGPC shall
have no obligation to make refunds to CUSTOMER unless the
maximum rate ultimately established by the FERC for the service
covered hereby is less than the rate paid by CUSTOMER.
7. PAYMENTS: Payment shall be made in compliance with the
Tariff. Payments by check shall be made to the remittance
address indicated on KGPC's invoice. Payment by wire transfer
shall be to a bank account designated by KGPC.
8. WAIVER: 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(s), whether of a like or different character.
9. APPLICABLE LAW: THE VALIDITY, CONSTRUCTION, INTERPRETATION
AND EFFECT OF THIS AGREEMENT SHALL BE GOVERNED BY THE
SUBSTANTIVE LAWS OF THE STATE OF TEXAS, THE PARTIES AGREE THAT
TEXAS' CHOICE OF LAW RULES MAY NOT BE USED TO DIRECT OR
DETERMINE THAT SOME OTHER STATES' LAW SHALL GOVERN A DISPUTE
ARISING UNDER THIS AGREEMENT.
10. SUCCESSORS AND ASSIGNS: This Agreement shall be binding upon
and inure to the benefit of the respective heirs,
representatives, successors and assigns of the parties hereto.
Except as provided in the General Terms and Conditions of the
Tariff, neither party may assign, pledge or otherwise transfer
or convey its rights, obligations or interests hereunder for any
purpose without the prior written consent of the other party,
which consent shall not unreasonably be withheld. Any
assignment, pledge, transfer or conveyance in breach of this
provision is voidable by the non-breaching party.
11. FILINGS: Each party shall make and diligently prosecute, all
necessary filings with governmental bodies as may be required
for the initiation and continuation of the transportation
service subject to this Agreement, as well as inform and, upon
request, provide copies to the other party of all filing
activities. CUSTOMER shall reimburse KGPC for all incurred
filing fees. KGPC shall have the unilateral right to file with
the appropriate regulatory authority and make changes effective
in (i) the filed rates and charges applicable under this Rate
Schedule, including both the level and design of such rates and
charges; and/or (ii) this Rate Schedule and the General Terms
and Conditions. Customer shall have the right to protest or
contest the aforementioned filings.
12. NOTICES: Routine communications shall be considered
delivered when received by ordinary mail. Communications
concerning scheduling, curtailments, and changes in nominations
shall be made via U-NITE or by fax in the event of failure of
KGPC's or the Customer's electronic communication system.
CUSTOMER's Dispatcher on the face hereof shall be the recipient
on a twenty-four (24) hour basis of all notices regarding
scheduling, curtailments, and changes in nominations. Either
party shall immediately notify the other of any changes of the
designated individuals or addresses herein.
All Administration Notices and Accounting Matters:
Koch Gateway Pipeline Company
P. O. Box 1478
Houston, Texas 77251-1478
Attention: Transportation Services
Master Contract No.: 20958
Amendment No.: 1
EXHIBIT A
TO
FIRM GAS TRANSPORTATION SERVICE AGREEMENT
BETWEEN
KOCH GATEWAY PIPELINE COMPANY
AND
COLONIAL GAS COMPANY
DATED
NOVEMBER 01, 1996
AS AMENDED
NOVEMBER 01, 1996
Point(s) of Receipt:
Gas shall be tendered by Customer for transportation hereunder at
the following receipt point(s):
SLN Location Description Gathering Charges and
Maximum Daily Quantity
(A) (B)
6366 The existing interconnection between $.0000 3,310
Transporter and United Texas Transmission
Company near Goodrich, Polk County, Texas.
SLN 6366
10144 The existing interconnection between $.0000 0
Transporter and Natural Gas Pipeline Co.
of America near Goodrich, Augustin
Viesca, A-77, Polk County, Texas. SLN
10144/671Service Agreement MDQ _______
Aggregate Firm Receipt Point MDQ 3,310
_______
Maximum Operating Pressure
Maximum Allowable Operating Pressure (MAOP) is the maximum pressure
(psig) at which a pipeline or segment of a pipeline may be operated
according to minimum federal safety standards defined in Part 192,
Title 49, Code of Federal Regulations or such state safety
standards, as may be applicable.
Delivery Pressure
Natural gas to be delivered by Customer to Pipeline at any receipt
point(s) shall be at a delivery pressure sufficient to enter
Pipeline's facilities, at a pressure available in Pipeline's
facilities in from time to time; but Customer shall not deliver gas
at a pressure in excess of the Maximum Allowable Operating Pressure
(MAOP).
Column Headings
(A) Gathering Charge per MMBtu
(B) Maximum Daily Quantity in MMBtu
Master Contract No.: 20958
EXIBIT B
TO
FIRM GAS TRANSPORTATION SERVICE AGREEMENT
BETWEEN
KOCH GATEWAY PIPELINE COMPANY
AND
COLONIAL GAS COMPANY
DATED
NOVEMBER 01, 1996
DELIVRY POINT(S)
Point(s) of Delivery:
Gas shall be tendered by Shipper for transportation hereunder at the
following point(s):
Pipeline Charges and
SLN Location Description Maximum Daily Quantity
(A) (B) (C) (D) (E)
471 The existing interconnection 4.8800 .0006 N $.0020 3,310
between Transporter and Texas
Eastern Transmission Corpora-
tion near Kosciusko, (UGPL to
TET), Section 14, T-13-N, R-7-E,
Attala County, Missisippi.
SLN 2471
Service Agreement MDQQ
Aggregate Firm Delivery Point MDQ 3,310
Shipper shall initially pay the amounts listed above, however, such amounts
are subject to change pursuant to Article VI of this Service Agreement,
without the need for this Exhibit B to be amended. An Account 858 surcharge
will be added effective December 1, 1994. An Account 191 surcharge will be
added effective November 1, 1995.
Delivery Pressure
Natural gas to be taken by Shipper from Transporter Delivery Point(s) shall be
at a sufficient to enter Texas Eastern Transmission Company at the Delivery
Point(s), but not to exceed Koch Gateway Pipeline Company's Maximum
Allowable Operating Pressure (MAOP).
Column Headings
(A) Reservation Charge per MMBtu
(B) Commodity Rate per MMBtu
(C) Gas Research Institute (GRI) surcharge
(d) Annual Charge Adjustment (ACA)
(E) Maximum Daily Quantity in MMBtu
[END OF EXHIBIT 10UU]
[EXHIBIT 10vv TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
960026E
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
This Agreement ("Agreement") is made and entered into this
2nd day of November, 1996, 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).
WHEREAS, Customer has been a Replacement Shipper under a
permanent release of a service agreement dated May 17, 1994
for service under Rate Schedule AFT-E ("the Prior
Agreement"); and
WHEREAS, the primary term of the Prior Agreement expires on
November 1, 1996; and
WHEREAS, Algonquin and Customer desire to execute a
superseding service agreement under Rate Schedule AFT-E in
order to provide for a primary term of three years.
NOW, THEREFORE, 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-E,
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 (MMBtu)
Nov 16 - Apr 15 6,106*
Apr 16 - May 31 5,867
Jun 1 - Sep 30 5,388
Oct 1 - Nov 15 5,867
*MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 2,119,106 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 and including November 1, 1999
("Primary Term") and shall remain in force from year to
year thereafter unless terminated by either party by
written notice one year or more prior to the end of the
Primary Term or any successive term thereafter.
Algonquin's right to cancel this Agreement upon the
expiration of the Primary Term hereof or any succeeding
term shall be subject to Customer's rights pursuant to
Sections 8 and 9 of the General Terms and Conditions.
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-E 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-E, nor less than the minimum rate under
Rate Schedule AFT-E.
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.
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-E, (b) Algonquin's Rate
Schedule AFT-E, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and
Conditions applicable to Rate Schedule AFT-E.
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-E.
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-E.
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: Algonquin Gas Transmission Company
1284 Soldiers Field Road
Boston, MA 02135
Attn: John J. Mullaney
Vice President, Marketing
(b) Customer: Colonial Gas Company
40 Market Street
Lowell, MA 08153
Attn: John Harrington
Senior 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.
Capacity Release Umbrella Agreement No. 93009ER5 executed by
Customer and Algonquin under Rate Schedule AFT-E dated
November 1, 1994.
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______
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: November 2, 1996
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Hanover, NJ (TETCO) At any pressure requested
Nov 16 - Apr 15 2,328 by Algonquin but not in
Apr 16 - May 31 2,237 excess of 750 Psig.
Jun 1 - Sep 30 2,054
Oct 1 - Nov 15 2,237
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 3,778 by Algonquin but not in
Apr 16 - May 31 3,630 excess of 750 Psig.
Jun 1 - Sep 30 3,334
Oct 1 - Nov 15 3,630
Signed for Identification
Algonquin: ___/s/ John J. Mullaney_____
Customer: ___/s/ John P. Harrington___
Exhibit B
Point(s) of Delivery
Dated: November 2, 1996
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
At the property line
on the outlet side
of a meter station
located at:
Parsippany-Troy Hills,
New Jersey 300
Nov 16 - Apr 15 6,106
Apr 16 - May 31 5,867
Jun 1 - Sep 30 5,388
Oct 1 - Nov 15 5,867
Signed for Identification
Algonquin: ___John J. Mullaney___
Customer: ___John P. Harrington_
[END OF EXHIBIT 10vv]
[EXHIBIT 10ww TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1996]
9W60027E
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
This Agreement ("Agreement") is made and entered into this
17th day of November, 1996, 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).
WHEREAS, Customer has been a Replacement Shipper under a
permanent release of a service agreement dated May 17, 1994
for service under Rate Schedule AFT-E ("the Prior
Agreement"); and
WHEREAS, the primary term of the Prior Agreement expires on
November 16, 1996; and
WHEREAS, Algonquin and Customer desire to execute a
superseding service agreement under Rate Schedule AFT-E in
order to provide for a primary term of three years.
NOW, THEREFORE, 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-E,
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 (MMBtu)
Nov 16 - Apr 15 1,221*
Apr 16 - May 31 814
Jun 1 - Sep 30 0
Oct 1 - Nov 15 814
*MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 259,259 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 and including November 16, 1999
("Primary Term") and shall remain in force from year to
year thereafter unless terminated by either party by
written notice one year or more prior to the end of the
Primary Term or any successive term thereafter.
Algonquin's right to cancel this Agreement upon the
expiration of the Primary Term hereof or any succeeding
term shall be subject to Customer's rights pursuant to
Sections 8 and 9 of the General Terms and Conditions.
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-E 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-E, nor less than the minimum rate under
Rate Schedule AFT-E.
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.
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-E, (b) Algonquin's Rate
Schedule AFT-E, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and
Conditions applicable to Rate Schedule AFT-E.
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-E.
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-E.
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: Algonquin Gas Transmission Company
1284 Soldiers Field Road
Boston, MA 02135
Attn: John J. Mullaney
Vice President, Marketing
(b) Customer: Colonial Gas Company
40 Market Street
Lowell, MA 08153
Attn: John Harrington
Senior 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.
Capacity Release Umbrella Agreement No. 9W007ER1 executed by
Customer and Algonquin under Rate Schedule AFT-E dated
November 1, 1994.
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____
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: November 17, 1996
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Hanover, NJ (TETCO) At any pressure requested
Nov 16 - Apr 15 757 by Algonquin but not in
Apr 16 - May 31 505 excess of 750 Psig.
Jun 1 - Sep 30 0
Oct 1 - Nov 15 505
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 464 by Algonquin but not in
Apr 16 - May 31 309 excess of 750 Psig.
Jun 1 - Sep 30 0
Oct 1 - Nov 15 309
Signed for Identification
Algonquin: __/s/ John J. Mullaney_____
Customer: __/s/ John P. Harrington___
Exhibit B
Point(s) of Delivery
Dated: November 17, 1996
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
At the property line
on the outlet side
of a meter station
located at:
Parsippany-Troy Hills,
New Jersey 300
Nov 16 - Apr 15 1,221
Apr 16 - May 31 814
Jun 1 - Sep 30 0
Oct 1 - Nov 15 814
Signed for Identification
Algonquin: __/s/ John J. Mullaney___
Customer: __/s/ John P. Harrington__
[END OF EXHIBIT 10ww]
[EXHIBIT 13a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1996]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1996 1995 1994
Operating Revenues $170,929 $164,649 $166,259
Cost of gas sold 87,188 83,631 87,458
Operating Margin 83,741 81,018 78,801
Operating Expenses:
Operations 31,383 31,309 33,004
Maintenance 4,476 4,401 5,074
Depreciation and amortization 11,228 10,225 9,235
Local property taxes 3,189 3,020 2,740
Other taxes 2,183 2,130 2,182
Restructuring charge - - 3,185
Total Operating Expenses 52,459 51,085 55,420
Income Taxes:
Federal income tax 7,001 6,912 4,806
State franchise tax 2,087 1,447 1,058
Total Income Taxes 9,088 8,359 5,864
Utility Operating Income 22,194 21,574 17,517
Other Operating Income (Expense):
Truck transportation revenues 11,031 7,576 12,066
Truck transportation expenses,including
income taxes and interest (9,005) (6,972) (10,579)
Truck Transportation Net Income 2,026 604 1,487
Other, net of income taxes 210 (8) (151)
Total Other Operating Income 2,236 596 1,336
Non-Operating Income,
Net of Income Taxes 757 864 565
Income Before Interest
and Debt Expense 25,187 23,034 19,418
Interest and Debt Expense 8,709 9,270 8,409
Net Income $16,478 $13,764 $11,009
Average Common Shares Outstanding 8,432 8,294 8,119
Income per Average Common Share $1.95 $1.66 $1.36
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1996 1995
Utility Property:
At original cost $333,319 $308,191
Accumulated depreciation (82,336) (72,636)
Net Utility Property 250,983 235,555
Non-Utility Property - Net 5,925 5,036
Net Property 256,908 240,591
Capital Leases - Net 1,811 2,253
Current Assets:
Cash and cash equivalents 3,541 7,541
Accounts receivable 17,719 19,069
Allowance for doubtful accounts (2,715) (2,205)
Accrued utility revenues 6,333 8,924
Unbilled gas costs 19,238 9,688
Fuel inventory - at average cost 11,958 10,516
Materials and supplies
-at average cost 2,891 3,132
Prepayments and other current assets 8,593 4,337
Total Current Assets 67,558 61,002
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 9,774 10,562
Unrecovered demand
side management costs 7,075 4,977
Unrecovered environmental
costs incurred 4,011 4,761
Unrecovered environmental
costs accrued 1,183 2,300
Unrecovered pension costs 3,135 3,917
Unrecovered transition costs accrued 4,500 3,600
Excess cost of investments over
net assets acquired 2,798 2,798
Other 5,659 5,660
Total Deferred
Charges and Other Assets 38,135 38,575
Total Assets $364,412 $342,421
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1996 1995
Capitalization:
Common Equity:
Common Stock $28,366 $27,863
Premium on Common Stock 54,221 51,447
Retained earnings 31,319 25,760
Total Common Equity 113,906 105,070
Long-Term Debt 95,266 75,418
Total Capitalization 209,172 180,488
Capital Lease Obligations 930 1,359
Current Liabilities:
Current maturities of long-term debt 5,152 6,141
Current capital lease obligations 881 894
Notes payable 50,400 61,835
Gas inventory purchase obligations 13,039 12,340
Accounts payable 14,544 12,150
Accrued interest 1,815 1,065
Current deferred income taxes 5,090 314
Other current liabilities 3,248 6,927
Total Current Liabilities 94,169 101,666
Deferred Credits and Reserves:
Deferred income taxes - Funded 35,886 32,299
Deferred income taxes - Unfunded 9,774 10,562
Accrued environmental costs 1,183 2,300
Accrued transition costs 4,500 3,600
Unamortized investment tax credits 3,672 3,940
Pension reserve 4,174 4,929
Other deferred credits and reserves 952 1,278
Total Deferred Credits and Reserves 60,141 58,908
Total Capitalization and
Liabilities $364,412 $342,421
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1996 1995 1994
Cash Flows From Operating Activities:
Net Income $16,478 $13,764 $11,009
Adjustments to reconcile net income to net cash:
Depreciation and amortization 12,361 11,211 10,150
Deferred income taxes 7,968 1,159 3,555
Amortization of investment
tax credits (268) (275) (234)
Provision for uncollectible
accounts 2,146 1,829 1,803
Other, net 171 973 811
Total adjustments 38,856 28,661 27,094
Changes in current assets and liabilities:
Accounts receivable (286) (6,517) 495
Accrued utility revenues 2,591 (2,776) 1,022
Unbilled gas costs (9,550) 2,490 4,581
Fuel inventory (1,442) 2,443 758
Materials and supplies 241 405 275
Prepayments and other
current assets (4,256) 5,207 (3,290)
Accounts payable 2,394 2,515 (2,526)
Accrued interest 750 (20) 68
Pipeline refunds due customes (2,077) (979) 213
Accrued pipeline charges - - (305)
Other current liabilities (1,602) 79 (86)
Net Cash Provided by
operating activity 25,619 31,508 28,299
Cash Flows From Investing Activities:
Utility capital expenditures (26,875) (24,096) (28,195)
Non-utility capital expenditures (1,367) (1,974) (876)
Change in deferred accounts (1,502) (2,077) (716)
Net Cash Used in
Investing Activities (29,744) (28,147) (29,787)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,919) (10,571) (10,187)
Issuance of Common Stock 3,277 2,702 4,070
Issuance of long-term debt,
net of issuance costs 29,787 19,685 741
Retirement of long-term debt,
including premiums (11,284) (27,477) (5,119)
Change in notes payable (11,435) 12,335 16,900
Change in gas inventory
purchase obligations 699 (1,520) (1,373)
Net Cash Provided by (Used in)
Financing Activities 125 (4,846) 5,032
Net (Decrease) Increase in Cash
and Cash Equivalents (4,000) (1,485) 3,544
Cash and Cash Equivalents
at Beginning of Year 7,541 9,026 5,482
Cash and Cash Equivalents
at End of Year $3,541 $7,541 $9,026
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $9,149 $9,867 $9,283
Income and state franchise taxes $8,489 $3,444 $7,282
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts)
1996 1995 1994
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,518 in 1996, 8,367 in 1995,
and 8,227 in 1994
Beginning of year $27,863 $27,397 $26,739
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (151 shares
in 1996, 140 shares in 1995
and 197 shares in 1994) 503 466 658
End of year $28,366 $27,863 $27,397
Premium on Common Stock
Beginning of year $51,447 $49,211 $45,799
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 2,774 2,236 3,412
End of year $54,221 $51,447 $49,211
Retained Earnings
Beginning of year $25,760 $22,567 $21,745
Net income 16,478 13,764 11,009
Cash dividends on Common
Stock ($1.295 a share in 1996,
$1.275 a share in 1995 and
$1.255 a share in 1994) (10,919) (10,571) (10,187)
End of year $31,319 $25,760 $22,567
Total Common Equity $113,906 $105,070 $99,175
The accompanying notes are an integral part of these statements.
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 145,000 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 $437,000,
$568,000, and $294,000 in 1996, 1995 and 1994, 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 is approximately 3.79%. 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 $6,333,000 and
$8,924,000, as reported in the Consolidated Balance Sheets at
December 31, 1996 and 1995, 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. Under methodologies approved in 1995 for its residential DSM
programs and in 1996 for its commercial and industrial programs,
the Company recorded as revenue $1,034,000 of lost margins and
$142,000 of financial incentives in 1996 and $900,000 of lost
margins and $220,000 of financial incentives in 1995.
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 for the qualified plan 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.
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 $100,418,000 and $81,559,000 as of December 31,
1996 and 1995, respectively. The fair value of long-term debt was
$102,016,000 and $89,724,000 as of December 31, 1996 and 1995,
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.
Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of". 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 adoption of this standard did not have a
material impact on the Company's financial condition or results of
operations.
Reclassifications - Reclassifications are made periodically to
previously issued financial statements to conform to the current
year presentation.
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, 1996, the Company has
a liability of $9,774,000 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 and was 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.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1996 1995 1994
Charged (credited) to operations:
Current $1,104 $6,455 $2,157
Deferred:
Unbilled gas costs 2,929 (1,523) (106)
Accelerated depreciation 2,202 2,005 2,167
Demand side management costs 747 (32) 1,115
Pension 449 (38) (840)
Recovery of unfunded deferred taxes 398 398 398
Debt expense (53) 848 (21)
Transition costs (1) (871) (55)
Environmental (246) 22 137
Miscellaneous (260) (79) 84
Amortization of investment
tax credits (268) (273) (230)
Total 7,001 6,912 4,806
Charged to other income 1,599 477 1,014
Total Federal income tax expense $8,600 $7,389 $5,820
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1996 1995 1994
Statutory Federal income tax rate 35% 35% 35%
Increases (reductions) in taxes resulting from:
Amortization of investment
tax credits (1) (1) (1)
Recovery of unfunded
deferred taxes 2 2 2
Miscellaneous items (2) (1) (1)
Effective Federal
income tax rate 34% 35% 35%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1996 1995
Construction contributions $974 $1,060
Other 335 1,468
Total deferred tax assets 1,309 2,528
Accelerated depreciation (39,580) (36,949)
Cost of removal (2,792) (2,554)
Unbilled gas costs (3,990) (315)
Environmental response costs (1,571) (1,865)
Demand side management costs (2,659) (1,764)
Other (1,467) (2,256)
Total deferred tax liabilities (52,059) (45,703)
Total deferred taxes $(50,750) $(43,175)
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: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1996 1995
First mortgage bonds:
8.86% Series CD due 2001 $ - $6,000
9.40% Series CE due 1997 5,000 10,000
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 10,000
6.45% Series MTA-2 due 2025 10,000 10,000
6.94% Series MTA-3 due 2026 10,000 -
6.20% Series MTA-4 due 1998 10,000 -
6.88% Series MTA-5 due 2008 10,000 -
Total 100,000 81,000
Note payable 418 559
Less: Long-term debt due
within one year (5,152) (6,141)
Total long-term debt $95,266 $75,418
The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
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 1995, the Company issued $10 million of 30-year bonds
(MTA-1) with an average effective interest rate of 6.85% (6.44%
during the first ten years and 7.38% in the next twenty years) and
$10 million of 30-year bonds (MTA-2) 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. During
1996, the Company issued three separate medium term notes totalling
$30 million at various rates and terms. It is anticipated that the
remaining bonds under the MTN program will be issued in 1997.
In June 1996, the Company redeemed prior to maturity $5 million
of Series CD, 8.86%, first mortgage bonds.
Note E: 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, 1996, the credit available under the bank line of credit was
$11,561,000. The weighted average interest rates for short-term
debt were 5.87% and 6.03% at December 31, 1996 and 1995,
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 1996, 1995 and
1994 approximately $500,000, $662,000 and $504,000, respectively,
of interest costs were incurred by the trust.
Note F: 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
$7,685,000 and $7,291,000 at December 31, 1996 and 1995,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $5,874,000 and $5,038,000
at December 31, 1996 and 1995, 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 1996, 1995 and 1994
approximated $1,493,000, $1,429,000 and $2,049,000, respectively.
At December 31, 1996, the future minimum payments (including
interest) under the Company's lease agreements are: $881,000 in
1997; $737,000 in 1998; $420,000 in 1999; $300,000 in 2000;
$255,000 in 2001; and $100,000 thereafter.
Note G: 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 $570,000, $459,000 and $387,000 for
1996, 1995 and 1994 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) 1996 1995 1994
Benefits earned during the period $1,036 $836 $1,195
Interest cost on projected
benefit obligation 3,267 3,279 2,803
Actual return on plan assets (4,710) (5,515) 77
Net amortization and deferral 1,882 2,757 (2,657)
Net periodic pension cost $1,475 $1,357 $1,418
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1996 1995 1994
Weighted average discount rate 7.75% 7.50% 8.50%
Future compensation increases 4.00% 4.00% 5.00%
Expected long-term rate of
return on assets 9.00% 9.00% 9.00%
The funded status of the plans at December 31, 1996 and 1995 is as
follows:
1996 1995
Assets Accumulated Assets Accumulated
Exceed Benefits Exceed Benefits
Accumulated Exceed Accumulated Exceed
(In Thousands) Benefits Assets Benefits Assets
Projected benefit
obligations:
Vested $(28,612) $(10,381) $(28,993) $(10,388)
Nonvested (703) (956) (628) (869)
Accumulated (29,315) (11,337) (29,621) (11,257)
Due to recognition
of future salary
increases (4,248) (116) (4,173) (88)
Total (33,563) (11,453) (33,794) (11,345)
Plan assets at
fair value 33,743 7,715 31,168 6,420
Projected benefit
obligation:
Less than (in 180 (3,738) (2,626) (4,925)
excess of)
plan assets
Unrecognized net (457) 188 1,758 1,232
(gain) loss
Unrecognized 1,398 2,020 1,572 1,247
transition amount
Unrecognized prior 487 1,064 347 1,493
service cost
Additional liability - (3,157) - (3,885)
accrued
Prepaid (accrued) $1,608 $(3,623) $1,051 $(4,838)
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 cost 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. The Company amortizes the
transition obligation over a twenty-year period. The Company's
cost under this plan for 1996, 1995 and 1994 was $502,000,
$672,000 and $694,000 respectively. A regulatory asset of $431,000
was recorded in 1993 representing 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 following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1996 and 1995:
(In Thousands) 1996 1995
Accumulated postretirement
benefit obligation:
Retirees $(3,957) $(3,816)
Fully eligible active plan
participants (1,033) (1,047)
Other active plan
participants (1,239) (1,275)
Total (6,229) (6,138)
Plan assets at fair value 4,563 4,102
Accumulated postretirement
benefit obligation
in excess of plan assets: (1,666) (2,036)
Unrecognized net (gain) from (1,339) (1,310)
past experience different from
that assumed and from changes
in assumptions
Unrecognized transition 4,315 4,584
obligation
Prepaid postretirement benefit $1,310 $1,238
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended December 31,
(In Thousands) 1996 1995 1994
Service cost - benefits
attributable to service $137 $145 $202
during the period
Interest cost on accumulated 461 505 455
postretirement
benefit obligation
Actual return on plan assets (507) (639) 143
Net amortization and deferral 410 661 (106)
Net periodic postretirement $501 $672 $694
benefit cost
For measurement purposes, a 6.5% (4.5% for dental costs)
annual rate of increase in the per capita cost of covered health
care benefits was assumed for 1997; the rate of increase for
medical costs was assumed to decrease gradually from 6.5% 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, 1996 by $755,000 and the aggregate of the service and the
interest cost components of net periodic postretirement benefit
cost for the year then ended by $71,000.
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.75%, 7.5% and
8.5% for 1996, 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.
Note H: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2013, 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 additional transition cost liabilities are estimated to
range from $4,500,000 to $6,500,000. The Company is recovering
these costs from its customers, as approved by the DPU in October
1994. As of December 31, 1996, the Company has recorded on the
balance sheet a long-term liability of $4,500,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $4,500,000 ("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 I: 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, 1996, the
Company had incurred environmental response costs of $11,156,000
of which $7,148,000 has been recovered from customers to date. The
Company expects to continue incurring costs arising from these
environmental matters.
As of December 31, 1996, the Company has recorded on the balance
sheet a long-term liability of $1,183,000 and, based upon rate
recovery, has recorded a corresponding regulatory asset. This
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation. 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.
Note J: 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
1996
December 31 $53,869 $9,236 $7,035 $.83 $.325
September 30 15,245 (2,566) (3,580) (.42) .325
June 30 24,237 (689) (2,205) (.26) .325
March 31 77,578 16,213 15,228 1.82 .320
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
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 K: 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.
Note L: Subsequent Event
In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the LNG storage joint venture is
subject to certain regulatory approvals. Colonial will recognize a
one-time gain, net of taxes, of approximately $.35 per share at the
time of the sale, expected to occur in the first half of 1997.
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, 1996 and
1995, and the related consolidated statements of income, cash flows,
and common equity for each of the three years in the period ended
December 31, 1996. 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 financialstatements referred to above present
fairly, in all material respects, the consolidated financial
position of Colonial Gas Company and subsidiaries as of December 31,
1996 and 1995, and the consolidated results of their operations and
their consolidated cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally
accepted accounting principles.
GRANT THORNTON LLP
Boston, Massachusetts
January 13, 1997
REPORT OF MANAGEMENT
To the Shareholders of Colonial Gas Company
Management is responsible for the preparation and integrity of the
Company's financial statements. The financial statements have been
prepared in accordance with generally accepted accounting principles
as applied to regulated public utilities and necessarily include
some amounts that are based on management's best estimates and
judgment.
The Company maintains a system of internal accounting and
administrative controls and an ongoing program of internal audits
that management believes provide reasonable assurance that assets
are safeguarded and that transactions are properly recorded and
executed in accordance with management's authorization. The
Company's financial statements have been audited by the independent
public accounting firm, Grant Thornton LLP, who also conducts a
review of internal controls to the extent required by generally
accepted auditing standards.
The Audit Committee of the Board of Directors, composed solely of
outside directors, meets with management, internal auditors and
Grant Thornton LLP to review planned audit scope and results and to
discuss other matters affecting internal accounting controls and
financial reporting. The independent accountants and internal
auditors have direct access to the Audit Committee and periodically
meet with its members without management representatives present.
F. L. Putnam, III Nickolas Stavropoulos
President and Chief Executive Officer Executive Vice President-
Finance, Marketing and
Chief Financial Officer
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 $16,478,000
($1.95), $13,764,000 ($1.66) and $11,009,000 ($1.36) for the three
years ended December 31, 1996, 1995, and 1994, respectively. Before
a restructuring charge of $1,965,000 after-tax 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 20-year average
temperatures in 1996, 1995 and 1994. This is summarized as follows:
1996 1995 1994
Percent colder than
20-year average 3.0% 2.3% 5.0%
Percent colder (warmer)
than prior year 0.7% (2.5)% (1.3)%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.295 in 1996, $1.275 in 1995
and $1.255 in 1994. The Company has paid dividends for 60
consecutive years, and has increased dividends each year for the
past 17 years.
Operating Revenues
Operating revenues were $170,929,000 in 1996, $164,649,000 in 1995
and $166,259,000 in 1994. 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 13,235 over the last three years from 132,187 in December 1993 to
145,422 in December 1996, an increase of 10%, which has added to
firm sales volume. The chart below summarizes volumes of gas sold
and transported and number of firm sales customers:
1996 1995 1994
(In MMcf)
Gas sold
Firm 19,563 18,560 18,716
Non-Firm 648 1,148 729
Gas transported
Firm 3,918 2,537 6,090
Non-Firm 2,671 3,224 4,185
Total gas sold and transported 26,800 25,469 29,720
(In MMcf)
Firm Sales Customers 145,422 141,359 136,636
Operating revenues increased $6,280,000, or 3.8% from 1995 to 1996.
This increase resulted from weather that was 0.7% colder than last
year and customer growth of 2.9%.
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 2.3% colder than the 20-year average)
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.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.29 in 1996, $4.22 in 1995
and $4.48 in 1994. 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) 1996 1995 1994
Gas purchased
Pipeline 15,115 14,659 14,392
Underground storage 3,346 3,270 3,112
LNG/Other 2,596 2,426 2,390
Total gas purchased 21,057 20,355 19,894
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 $31,383,000 in 1996, an increase of $74,000
or 0.2%, from 1995, and $31,309,000 in 1995, a decrease of
$1,695,000, or 5.1%, from 1994. In 1996, the Company was able to
maintain operations expense at prior years level. The decrease in
1995 was primarily due to less payroll and related benefits as a
result of the early retirement program and cost saving initiatives
resulting from the Company's self-examination in 1994. Maintenance
expense increased $75,000, or 1.7%, in 1996 from 1995 and decreased
$673,000, or 13.3%, in 1995 from 1994. The decrease in 1995 was
primarily due to cost saving initiatives.
Depreciation and amortization expense increased 9.8% or $1,003,000
in 1996 and 10.7% or $990,000 in 1995. The increases in 1996 and
1995 were due to an increase in utility property.
Local property and other taxes increased 4.3% in 1996 from 1995 and
4.6% in 1995 from 1994. The increases in 1996 and 1995 were due to
higher property 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 8.7% or
$729,000 in 1996 as a result of a higher level of income. Total
Federal income and state franchise taxes increased 42.5% or
$2,495,000 in 1995 as a result of more income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was $2,236,000
in 1996, $596,000 in 1995 and $1,336,000 in 1994. 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' 1996 financial results were driven by a 68% increase in
liquefied natural gas (LNG) hauls leading to a $3,455,000 increase
in trucking revenue and a $1,422,000 increase in truck
transportation net income. This increase in demand of truck
transportation of LNG occurred for most of the year and was
primarily due to the colder than normal weather in the fourth
quarter of 1995 and the first quarter of 1996.
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.
Factors affecting the future financial results of Transgas, in
addition to the impact of weather variations, 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.
As discussed in "LNG Joint Ventures", the Company has agreed to sell
a 50% interest in Transgas. Effective upon such sale, the Company
will be recognizing 50% of the net income of Transgas on an equity
basis.
Non-Operating Income
Non-operating income, net of income taxes, was $757,000 in 1996,
$864,000 in 1995 and $565,000 in 1994. Non-operating income
includes interest income and miscellaneous other income.
Interest and Debt Expense
Interest and debt expense decreased $561,000 or 6.1% in 1996. The
decrease in 1996 was due to a decrease in interest on long-term debt
resulting from the early retirement of higher interest debt in
December 1995 offset by increased levels of short-term debt, although
at lower short-term interest rates. Interest and debt expense
increased 10.2% in 1995 from 1994. 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.
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, under methodologies
approved in 1995 for its residential DSM programs and in 1996 for
its commercial and industrial programs resulting lost margins and
financial incentives based on the attainment of performance goals.
In 1996, the Company recorded as operating revenues $1,034,000 of
lost margins and $142,000 of financial incentives associated with
the residential and commercial DSM programs and in 1995, recorded as
operating revenues $900,000 of lost margins and $220,000 of
financial incentives.
The Company has made only two requests for base rate increases since
1984. Its most recent request was made in 1993. In response to that
request, the DPU approved a base rate increase designed to produce
additional revenues of $6.7 million or 4.9% annually, effective
November 1, 1993.
The Company's goal is to postpone the filing of a request for its
next base rate increase until at least the year 2000 through
cost-cutting and other measures, such as the LNG joint venture with
Cabot LNG Corporation described below, while maintaining an adequate
return to shareholders. Under a 1995 industry-wide ruling of the
DPU, the Company will be required in its next base rate filing
either to present an alternative incentive-based method of pricing
or to justify continuation of the traditional cost-of-service/
rate-of-return method. The Company has reviewed alternative
incentive-based pricing methods but has not yet determined
what method of regulation will be of greatest benefit to its
customers and shareholders.
During 1996, the DPU ordered all Massachusetts gas companies to
offer only "unbundled" gas service to interruptible and special
contract customers, as a means of promoting greater competition at
the city-gate. Unbundled service separates (i) the part of the
service involving procuring the gas and transporting it to the
city-gate (i.e. the point where the Company takes gas from the
interstate pipeline into its distribution systems); and (ii) the
delivery of the gas to the customer's facility through the local
distribution system. The Company had previously offered both
bundled and unbundled service to interruptible and special contract
customers.
Since 1993, the Company also has been offering unbundled service
as an alternative to its firm commercial and industrial customers.
As of December 31, 1996, 19 customers had opted for the firm
transportation service, representing less than 2% of the Company's
annual firm load. The Company is analyzing methods for making
unbundled service viable for the greater number of firm customers,
and anticipates DPU rulings containing additional unbundling
guidelines in 1997.
In its 1996 order, the DPU continued to allow Massachusetts gas
companies to price interruptible services at negotiated rates based
on the value of that service to the customer. Additionally,
Massachusetts gas companies will now be permitted to retain 25% of
the net margins earned on interruptible sales, interruptible
transportation and capacity release transactions, to the extent
those margins exceed thresholds based on previous activity. The
Company had previously been allowed to retain 10% of capacity
release revenues above an initial threshold of $2,500,000 under its
1993 base rate proceeding. The amounts retained by the Company from
interruptible sales, interruptible transportation and capacity
release transactions in 1996, 1995 and 1994 totaled $0, $81,000 and
$32,000 respectively. All other revenues from these transactions
flow back to firm sales customers through the CGAC.
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, 1996, the Company had
incurred environmental response costs of $11,156,000 of which
$7,148,000 has been recovered from customers to date. The Company
expects to continue incurring costs arising from these environmental
matters.
As of December 31, 1996, the Company has recorded on the balance
sheet a long-term liability of $1,183,000 and, based upon rate
recovery, has recorded a corresponding regulatory asset. This
amount represents estimated future response costs for these sites
based on the Company's preferred methods of remediation. 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
Impairment of Long-Lived Assets - During 1996, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting for
the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed Of". 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 adoption of this standard did not have a
material impact on the Company's financial condition or results of
operations.
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 $26,875,000 in
1996, $24,096,000 in 1995 and $28,195,000 in 1994. The Company's
long-range plan calls for annual utility expenditures, of which over
50% is budgeted for new business, averaging $28,000,000 over the
next five years as follows:
(In Thousands) 1997 1998 1999 2000 2001
Distribution $22,900 $22,500 $23,100 $23,800 $24,700
Production 3,200 200 100 400 300
Information Systems 7,400 4,100 400 400 400
Automated Meter 1,100 1,100 1,200 300 300
Reading
General
200 300 300 300 300
Total Capital $34,800 $28,200 $25,100 $25,200 $26,000
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 1995, the Company issued $10 million of 30-year bonds (MTA-1)
with an average effective interest rate of 6.85% (6.44% during the
first ten years and 7.38% in the next twenty years) and $10 million
of 30-year bonds (MTA-2) 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. During 1996, the Company
issued three separate medium term notes totaling $30 million at
various rates and terms. It is anticipated that the remaining bonds
under the MTN program will be issued in 1997.
In June 1996, the Company redeemed prior to maturity the $5 million
of Series CD, 8.86%, first mortgage bonds.
The aggregate amount of maturities for the years 1997, 1998, 1999,
2000 and 2001 are $5,152,000, $10,164,000, $20,102,000, $0 and $0,
respectively.
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 expects to make new short-term
credit arrangements prior to the expiration of the credit facility.
The Company has raised permanent capital during the last three years
as follows:
(In Thousands) 1996 1995 1994
Common Stock Under
Dividend Reinvestment
and Common Stock Purchase
Plan and
Employee Savings Plan $3,277 $2,702 $4,070
Note Payable - - $741
Medium term notes under the
first mortgage indenture $30,000 $20,000 -
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1996 1995 1994
Equity 54% 58% 56%
Long-Term Debt 46% 42% 44%
As of April 1996, the quarterly dividend paid on the Company's
Common Stock was increased to $.325 per share or an annualized
dividend rate of $1.30 per share.
LNG Joint Ventures
In January 1997, the Company executed definitive agreements with
Cabot LNG Corporation (Cabot) to (1) sell a 50% interest in Transgas
for $7,000,000 as part of a joint venture and (2) form a separate
joint venture owned 50/50 which will lease Colonial's LNG storage
tank and related equipment. These joint ventures combine the LNG
trucking and storage capabilities of Colonial with the marketing and
storage capabilities of Cabot, and are expected to expand the
overall utilization of LNG. Completion of the sale of the Transgas
interest and implementation of the joint venture is subject to
certain regulatory approvals. Colonial will recognize a one-time
gain, net of taxes, of approximately $.35 per share at the time of
the sale, expected to occur in the first half of 1997. The Company
has agreed to sell a 50% interest in Transgas. Effective upon such
sale, the Company will be recognizing 50% of the net income of
Transgas on an equity basis.
FINANCIAL AND OPERATING STATISTICS
(For the Years Ending December 31)
Operating Revenues (In Thousands)
1996 1995 1994 1993 1992
Residential $108,879 $103,991 $104,812 $106,362 $91,412
Commercial and
industrial 54,324 52,926 56,358 53,933 46,951
Firm transportation 1,843 1,294 1,210 816 585
Non-firm sales 2,985 3,745 2,429 3,613 4,860
Non-firm trans
- -portation 453 424 401 409 254
Other 2,445 2,269 1,049 1,128 992
Total operating
revenues $170,929 $164,649 $166,259 $166,261 $145,054
Gas Sold (MMcf)
Residential 12,094 12,734 11,190 11,492 11,097
Commercial and
industrial 7,469 5,826 7,526 7,443 7,445
Non-firm 648 1,148 729 1,030 1,508
Total gas sales 20,211 19,708 19,445 19,965 20,050
Gas Transported (MMcf)
Firm 3,918 2,537 6,090 4,163 1,997
Non-firm 2,671 3,224 4,185 4,026 2,820
Total gas transported 6,589 5,761 10,275 8,189 4,817
Total gas sold and
transported 26,800 25,469 29,720 28,154 24,867
Gas Purchased (MMcf)
Pipeline 15,115 14,659 14,392 14,983 16,633
Underground storage 3,346 3,270 3,112 3,501 2,666
LNG - as liquid 1,067 844 1,129 907 564
LNG - as vapor 1,528 1,574 1,236 917 1,095
Propane/SNG 1 8 25 8 9
Total gas purchased 21,057 20,355 19,894 20,316 20,967
Company use and other (846) (647) (449) (351) (917)
Available for sale 20,211 19,708 19,445 19,965 20,050
Customers - End of period
Residential 131,286 127,419 123,077 118,918 115,115
Commercial and
industrial 14,136 13,940 13,559 13,269 12,849
Firm transportation 19 11 8 1 1
Non-firm sales 25 27 21 21 21
Non-firm transportation 5 2 2 2 2
Total customers
- end of period 145,471 141,399 136,667 132,211 127,988
Average Annual Mcf Sold/Customer
Residential 96 94 96 101 103
Commercial and
industrial 533 531 569 575 595
Average Annual Bill/Customer
Residential $868 $858 $897 $939 $839
Commercial and
industrial $3,880 $3,901 $4,260 $4,167 $3,732
Average Revenue/Mcf
Residential $9.00 $9.15 $9.37 $9.26 $8.16
Commercial and
industrial $7.27 $7.35 $7.49 $7.25 $6.27
Residential Heating
Customers as a
% of all Residential
Customers 90% 90% 90% 90% 90%
Highest Daily
Sendout
(Mcf) 170,984 199,275 204,896 184,303 157,567
Percent Colder
(Warmer) than
20-year average 3.0% 2.3% 5.0% 6.3% 3.0%
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per Share Amounts)
1996 1995 1994 1993 1992
Balance Sheet Data:
Assets:
Utility property-net $250,983 $235,555 $221,685 $202,713 $183,815
Non-utility property
-net 5,925 5,036 3,479 3,235 4,039
Capital leases-net 1,811 2,253 2,948 3,914 4,366
Current assets 67,558 61,002 65,568 67,668 71,763
Deferred charges
and other assets 38,135 38,575 37,668 34,588 38,939
Total $364,412 $342,421 $331,348 $312,118 $302,922
Capitalization and Liabilities:
Capitalization:
Common equity $113,906 $105,070 $99,175 $94,283 $87,771
Long-term debt 95,266 75,418 77,923 87,432 90,750
Total Capitalization 209,172 180,488 177,098 181,715 178,521
Capital lease obligations 930 1,359 2,237 3,149 3,591
Current liabilities 94,169 101,666 91,382 73,413 64,567
Deferred credits
and reserves 60,141 58,908 60,631 53,841 56,243
Total $364,412 $342,421 $331,348 $312,118 $302,922
Income Statement Data:
Operating revenues $170,929 $164,649 $166,259 $166,261 $145,054
Cost of gas sold (87,188) (83,631) (87,458) (90,915) (75,143)
Operating margin 83,741 81,018 78,801 75,346 69,911
Operating expenses
(including income
taxes) (61,547) (59,444) (61,284) (56,456) (52,760)
Utility operating
income 22,194 21,574 17,517 18,890 17,151
Other income-net
of income taxes 2,993 1,460 1,901 1,273 958
Interest and debt
expense (8,709) (9,270) (8,409) (8,141) (7,466)
Accounting change - - - - -
Net income $16,478 $13,764 $11,009 $12,022 $10,643
Capitalization Ratios:
Common equity 54% 58% 56% 52% 49%
Long-term debt 46% 42% 44% 48% 51%
Common Stock Data:
Average shares
outstanding 8,432 8,294 8,119 7,931 7,728
Income per share $1.95 $1.66 $1.36(a) $1.52 $1.38
Dividends paid per share:
Common Stock $1.295 $1.275 $1.255 $1.235 $1.213
Class A Common Stock - - - - -
Per weighted average
common share $1.295 $1.275 $1.255 $1.235 $1.213
Dividend payout rate 66% 77% 92% 81% 88%
Book value per share $13.37 $12.56 $12.05 $11.74 $11.19
Dividends as a percent
of book value 10% 10% 10% 11% 11%
Market price per share $21.25 $20.25 $19.25 $22.50 $21.25
Market price as a percent
of book value 159% 161% 160% 192% 190%
Return on average
common equity 15.1% 13.5% 11.4% 13.2% 12.5%
(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.
SHAREHOLDER INFORMATION
Corporate Headquaters
Colonial Gas Company
40 Market Street
P. O. Box 3064
Lowell, MA 01853-3064
(508) 322-3000
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 16, 1997 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 1996 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 LLP
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 60 consecutive
years and has increased dividends each year for the past 17 years.
Common Stock dividends are payable when declared by the Board of
Directors.
Anticipated Record Date Anticipated Payment Date
February 28, 1997 March 14, 1997
May 30, 1997 June 13, 1997
August 29, 1997 September 15, 1997
December 1, 1997 December 15, 1997
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock Purchase Plan
(DRIP) provides shareholders of record with an economical and
convenient method of 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 calender quater, 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 contracting 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 preceeding business day. Optional cash
investments must be receiced 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 1997.
Date Investment Must Be Investment
Received By Transfer Agent Dates
April 8 April 15
May 8 May 15
June 6 June 13
July 8 July 15
August 8 August 15
September 8 September 15
October 7 October 15
November 7 November 14
December 8 December 15
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 1996 and 1995, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
_________________________________________________________________
1996 __________________________________
The Year $24.25 $20.00 $1.295
4th Quarter 24.00 21.25 .325
3rd Quarter 24.25 20.25 .325
2nd Quarter 24.25 20.00 .325
1st Quarter 24.00 20.25 .320
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
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1996, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,361
shareholders of record.
Market Makers
Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; 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 EXHIBIT 13a]
[EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1996]
Colonial Gas Company
Subsidiaries of Registrant
Subsidiaries: Organized in: Ownership:
(a) Transgas, Inc. Massachusetts 100% (b)
(a) CGI Transport Limited(c) Canada 100%
(a) Included in consolidated financial statements.
(b) The Company has agreed to sell a 50% interest in Transgas Inc. to
Cabot LNG Corporation as part of a joint venture. Completion of the
sale is subject to certain regulatory approvals.
(c) Owned by Transgas.
[END OF EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1996]
[EXHIBIT 23a TO COLONIAL GAS COMPANY
10-K FOR TERM ENDED DECEMBER 31, 1996]
EXHIBIT 23a
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our reports dated January 13, 1997 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, 1996.
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 Nos. 33-34067, 33-47099, and 33-54091), and
Forms S-3, as ammended (File Nos. 33-54135 and 33-616863).
GRANT THORTON LLP
Boston, Massachusetts
March 25, 1997
[END OF EXHIBIT 23a]
[EXHIBIT 27
FINANCIAL DATA SCHEDULE UT]
[ARTICLE] UT
<TABLE>
<S> <C>
[PERIOD-TYPE] 12-MOS
[FISCAL-YEAR-END] DEC-31-1996
[PERIOD-END] DEC-31-1996
[BOOK-VALUE] PER-BOOK
[TOTAL-NET-UTILITY-PLANT] 250,983
[OTHER-PROPERTY-AND-INVEST] 7,736
[TOTAL-CURRENT-ASSETS] 67,558
[TOTAL-DEFERRED-CHARGES] 32,476
[OTHER-ASSETS] 5,659
[TOTAL-ASSETS] 364,412
[COMMON] 28,366
[CAPITAL-SURPLUS-PAID-IN] 54,221
[RETAINED-EARNINGS] 31,319
[TOTAL-COMMON-STOCKHOLDERS-EQ] 113,906
[PREFERRED-MANDATORY] 0
[PREFERRED] 0
[LONG-TERM-DEBT-NET] 95,266
[SHORT-TERM-NOTES] 63,439
[LONG-TERM-NOTES-PAYABLE] 0
[COMMERCIAL-PAPER-OBLIGATIONS] 0
[LONG-TERM-DEBT-CURRENT-PORT] 5,152
[PREFERRED-STOCK-CURRENT] 0
[CAPITAL-LEASE-OBLIGATIONS] 930
[LEASES-CURRENT] 881
[OTHER-ITEMS-CAPITAL-AND-LIAB] 84,838
[TOT-CAPITALIZATION-AND-LIAB] 364,412
[GROSS-OPERATING-REVENUE] 170,929
[INCOME-TAX-EXPENSE] 9,088
[OTHER-OPERATING-EXPENSES] 139,647
[TOTAL-OPERATING-EXPENSES] 148,735
[OPERATING-INCOME-LOSS] 22,194
[OTHER-INCOME-NET] 2,993
[INCOME-BEFORE-INTEREST-EXPEN] 25,187
[TOTAL-INTEREST-EXPENSE] 8,709
[NET-INCOME] 16,478
[PREFERRED-STOCK-DIVIDENDS] 0
[EARNINGS-AVAILABLE-FOR-COMM] 16,478
[COMMON-STOCK-DIVIDENDS] 10,919
[TOTAL-INTEREST-ON-BONDS] 7,107
[CASH-FLOW-OPERATIONS] 38,856
[EPS-PRIMARY] 1.95
[EPS-DILUTED] 1.95
</TABLE>
[END OF EXHIBIT 27]
