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, 1994
OR
Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from to
COMMISSION FILE NUMBER 0-10007
COLONIAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1558100
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
40 Market Street, Lowell, Massachusetts 01852
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (508) 458-3171
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $3.33 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 1, 1995 was
$175,049,871.
The number of shares of the registrant's common stock
outstanding as of March 1, 1995 was 8,237,641.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the annual report to stockholders for the year
ended December 31, 1994 are incorporated by reference into Part
II and Part IV. Portions of the proxy statement for the 1995
annual meeting of stockholders are incorporated by reference into
Part III.
COLONIAL GAS COMPANY
FORM 10-K ANNUAL REPORT - 1994
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
136,000 utility customers in 24 municipalities located northwest
of Boston and on Cape Cod. Through its wholly-owned energy
trucking subsidiary, Transgas Inc. ("Transgas"), the Company also
provides over-the-road transportation of liquefied natural gas
("LNG"), propane and other commodities.
The Company's corporate office is located at 40 Market
Street, Lowell, Massachusetts 01852. The telephone number is
(508) 458-3171.
The Company's combined natural gas distribution service
areas in the Merrimack Valley region northwest of Boston and on
Cape Cod cover approximately 622 square miles with a year-round
population of approximately 500,000, which increases by
approximately 350,000 during the summer tourist season on Cape
Cod. The Company is serving approximately 48% of potential
customers in its service areas. Of its 136,000 customers,
approximately 90% are residential accounts. The Company added
4,456 firm customers in 1994. 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 1994, 45%
converted from other fuels and 55% were new construction.
The Company's 1994 consolidated operating revenues were
derived 63% from firm gas sales to residential customers, 34%
from firm gas sales to commercial and industrial customers, 2%
from non-firm customers and 1% from firm transportation
customers. For the year 1994, the Company sold 19,445 MMcf of
gas, of which 12,311 MMcf was sold in the Merrimack Valley area
and 7,134 MMcf in the Cape Cod area. At December 31, 1994, 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, 1994, the Company had 470 full-time and 52
part-time gas employees. Of those employees, 98 are covered by a
collective bargaining agreement with the United Steelworkers of
America which expires in April 1996 and 77 are covered by a
separate collective bargaining agreement with the United
Steelworkers of America which expires in February 2000. In
addition, Transgas employs 93 full-time employees of which 67 are
covered by a collective bargaining agreement with the
International Brotherhood of Teamsters which expires in June
1996.
GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES
In 1992, the Federal Energy Regulatory Commission ("FERC")
issued Order 636, which required interstate natural gas pipeline
companies to separate the supply, transportation and storage
components of their services. Intended to increase competition in
the natural gas industry, Order 636 enables local distribution
companies ("LDCs") who formerly received bundled service from
the pipelines to negotiate directly with suppliers of gas. It
also gives LDCs greater responsibility for managing the pipeline
transportation and storage resources which are required to get
that supply to their systems from source areas. By the end of
1993, all interstate natural gas pipelines had implemented
restructuring programs pursuant to Order 636. Consequently, 1994
marked the first full year in which LDCs such as the Company were
responsible for managing their own supply, transportation
capacity and storage resources.
In general the Company pays negotiated rates for pipeline-
transported supplies and tariffed rates (approved by FERC) for
pipeline transportation and storage services. The Company
currently meets its supply requirements through a combination of
firm and spot purchases of pipeline-transported supply, supply from
underground storage, liquefied natural gas ("LNG") and propane.
The following table shows the Company's sources of firm supply
available to meet its gas requirements and the actual components
of gas sendout for each of the last three years:
1994 1993 1992
MMcf(a) % MMcf(a) % MMcf(a) %
Firm Pipeline
Transportation Capacity 28,993 26,239 24,933
Firm Gas Supply Sources(b)
Contracts for Pipeline-
Transported Gas(c) 19,631 72 19,731 74 - -
Contracts with Pipelines - - - - 24,933 81
LNG contracts 4,050 15 3,450 13 3,125 10
Storage inventory at
January 1(d) 3,587 13 3,417 13 2,786 9
Total Available 27,268 100 26,598 100 30,844 100
Gas Sendout
Pipeline-Transported
Supplies(e) 14,392 72 14,982 74 16,633 80
Supplemental Supplies:
Underground storage 3,112 16 3,501 17 2,666 13
LNG-as liquid 1,129 6 907 4 564 2
LNG-as vapor 1,236 6 915 5 1,095 5
Propane-air 25 - 8 - 9 -
Total Sendout 19,894 100 20,313 100 20,967 100
Ratio of available firm supply
to sendout (f) 1.37 1.31 1.47
_________________________
(a) The term "MMcf" means one million cubic feet of vapor
or vapor equivalent.
(b) 1994 and 1993 reflect the Company's portfolio of firm
supply sources subsequent to FERC Order 636, calculated on
an annualized basis.
(c) The Company's firm supply purchase contracts are
structured to enable the Company to purchase volumes
equivalent to the total amount of its firm pipeline capacity
to its distribution system during the winter or peak demand
season, but less than total firm pipeline capacity during
the off-peak season. Accordingly, the total supply purchase
contract volumes shown are less than total firm
transportation capacity for 1994 and 1993.
(d) The Company's storage inventory is drawn down and
refilled throughout the year depending upon the availability
and price of gas sources and upon the requirements of the
Company's customers. The Company's current level of
underground storage inventory capacity is 4,645 MMcf.
(e) The Company previously differentiated its pipeline-
transported supply sendout between firm and spot sources.
The Company now reports these volumes on an aggregate basis.
(f) The Company's ratio of available firm supply to sendout
was determined by dividing total firm gas supply sources by
total sendout.
Based upon its firm contracts for transportation, storage,
supply and other supplemental sources, the Company expects to be
able to meet the gas requirements of its firm sales customers for
the foreseeable future. Additional information concerning the
Company's firm resources of gas transportation, storage and
supply for each of its two service territories is set forth
below.
Merrimack Valley Service Area Resources
The Company maintains three firm contracts with the
Tennessee Gas Pipeline Company ("Tennessee") for the
transportation of supply to the Merrimack Valley service area.
The first contract provides for the firm transportation of 25,196
Mcf per day and will be in effect until November 1, 2000 and year
to year thereafter unless terminated upon twelve months prior
written notice. The second firm transportation contract is for
17,300 Mcf per day and will be in effect until April 1, 2013 and
year to year thereafter unless terminated upon twelve months
prior written notice. During the off-peak season (April 1 through
October 31), the Company assigns this 17,300 Mcf per day of
transportation capacity and associated supply to an independently
owned, 84 MW cogeneration facility located in the Company's
service territory. The third firm transportation service contract
with Tennessee is utilized in conjunction with the Iroquois
Pipeline System ("Iroquois") to deliver 6,000 Mcf per day of
Canadian supplies to the Company. Of this amount, 4,000 Mcf per
day can also be transported to the Cape Cod service area on a
firm basis via the Algonquin Gas Transmission Company
("Algonquin") system. This third Tennessee contract, as well as
the related Iroquois contract, is in effect until November 1,
2011 and continues year to year thereafter unless terminated by
twelve months prior written notice.
In addition, the Company contracts for underground storage
service which, in conjunction with two Tennessee firm
transportation contracts, provide an additional 23,587 Mcf per
day of firm deliverability. The Company has storage capacity of
2,000,000 Mcf and firm deliverability of 16,083 Mcf per day under
its contract with the National Fuel Gas Supply Corporation,
formerly known as Penn-York Energy Corporation, ("National
Fuel"). In order to deliver these volumes, the Company has a firm
transportation contract with Tennessee for 16,083 Mcf per day.
Both the National Fuel and Tennessee contracts expire on March
31, 1996 and will 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 1,053,898
Mcf of storage space and 14,150 Mcf per day of withdrawal
capacity. In order to deliver these volumes, the Company has a
separate firm transportation contract with Tennessee for 7,504
Mcf per day. Both of these contracts continue until November 1,
2000 and from year to year thereafter unless terminated upon
twelve months prior written notice.
The Company's portfolio of firm pipeline-transported supply
for the Merrimack Valley area consists principally of four
purchase contracts for domestically-produced gas and one purchase
contract for Canadian-produced gas. These individually negotiated
contracts provide an aggregate of up to 48,496 Mcf per day of
firm supply during the peak season (November 1 through March 31).
The Massachusetts Department of Public Utilities ("DPU") approved
all of these supply contracts in 1994.
During the peak season, pipeline-transported supply and
storage volumes are supplemented by the Company's on-system LNG
facility in Tewksbury, Massachusetts which provides up to 60,000
Mcf per day of vaporization capability. This facility also has a
liquefaction capacity of 5,000 Mcf per day and can store up to
1,000,000 Mcf at any given time. The Company also owns facilities
for the storage of approximately 158,000 Mcf natural gas equivalent of
propane which can be vaporized, mixed with air and injected into
the Merrimack Valley service area distribution system at a rate
of up to approximately 26,000 Mcf per day.
Cape Cod Service Area Resources
The Cape Cod service area is directly served by the
Algonquin pipeline system. The Company maintains fourteen firm
transportation agreements with Algonquin which provide an
aggregate capacity of approximately 45,368 Mcf per day. Each of
these fourteen Algonquin transportation arrangements will be in
effect until either October 31, 2012 or October 31, 2013 and will
continue year to year thereafter unless terminated upon twelve
months prior written notice. Since the Company's firm supplies
and storage services are not directly connected to Algonquin,
these services are supported by multiple firm transportation and
storage services on seven different upstream pipelines.
The Company's portfolio of pipeline-transported supplies for
the Cape Cod area consists principally of three purchase
contracts for domestically-produced gas. These individually
negotiated contracts provide an aggregate of up to 20,918 Mcf per
day of firm supply during the peak season (November 1 through
March 31). The DPU approved all of these supply contracts in
1994. The Company also has the ability to deliver up to 4,000 Mcf
per day of Canadian supplies to the Cape Cod service area on a
firm basis.
In addition to the contracts for pipeline-transported supply,
the Company has five storage contracts to service the Cape Cod area,
two of which are on the Texas Eastern Transmission Company ("Texas
Eastern") system and three of which are on the CNG Transmission
Corporation ("CNG") system. The Company has contracted for underground
natural gas storage capacity of approximately 493,486 Mcf with
Texas Eastern through the 2012-2013 heating season. The
associated firm transportation capacity from Texas Eastern
storage provides deliverability of up to 6,969 Mcf per day. The
Company has contracted with CNG for underground natural gas
storage capacity of approximately 823,529 Mcf through March 31,
2006 and 232,600 Mcf through March 31, 2012. The associated firm
transportation capacity from CNG storage provides deliverability
of up to 6,442 Mcf per day and Colonial has other arrangements in
place by which it may increase that firm deliverability by 6,999
Mcf per day.
The Company also leases, through 1998, and operates
facilities in the Cape Cod service area for the storage (but not
the liquefaction) of approximately 180,000 Mcf of LNG. Through
May 1995, the Company has contracted with a subsidiary of
Algonquin for the additional annual storage capacity of
approximately 42,000 Mcf of LNG in a Providence, Rhode Island
facility. In addition, the Company has storage for 27,000 Mcf
natural gas equivalent of propane.
REGULATORY MATTERS
Federal Regulation
As discussed above, by the end of 1993, all interstate
pipelines serving the Company had implemented the unbundling
directives of FERC Order 636. Pursuant to these directives, the
Company itself now procures all of the gas supplies necessary to
meet its load requirements, and manages the transportation and
storage services now provided by the pipelines. It is still too
early to evaluate the full impact that Order 636 and related
FERC directives deregulating the gas industry will have on the
Company. While these directives have increased the contracting,
resource management and regulatory responsibilities of the
Company, they have also created a more competitive market for
gas supply and pipeline transportation which facilitates the
Company's efforts to achieve savings in its cost of gas. The
FERC deregulation directives did not materially affect the
Company's results of operations in 1994 and the Company
believes that they will continue not to affect materially its
results of operations.
State Regulation
The Company is a public utility subject to the jurisdiction
and regulatory authority of the DPU with respect to its rates as
well as to the issuance of securities, franchise territory and
other related matters. The DPU permits Massachusetts gas
companies to utilize a cost of gas adjustment clause ("CGAC")
which enables them to pass on to their customers, via their
monthly gas bill, changes in the cost of procuring and delivering
their gas. Other changes in rates charged to customers are
subject to approval by the DPU after formal proceedings.
The Company periodically receives refunds and charges from
its interstate gas transporters related to rate adjustments
ordered by the FERC. All of the refunds and charges are returned
to or collected from utility customers through the CGAC as
approved by the DPU.
Environmental response 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". The Company's DSM programs are in their third year and
are expected, based on methodology approved by the DPU, to save
approximately $25.5 million in gas costs that would have been
incurred over the lives of the installed conservation measures.
In order to achieve these savings, Colonial and its
participating customers will have invested approximately $14
million over the three-year period in customer conservation
measures such as insulation, heating system controls and water
heating conservation devices. As a result, Colonial expects to
reduce customer bills by approximately $11.5 million from the
levels they would have been at if no conservation occurred. In
addition, the Company is allowed to recover the margins lost as
a result of this program and financial incentives based on the
attainment of performance goals. The Company anticipates filing
in 1995 for approximately $400,000 of financial incentives.
In 1993, the Company applied for what was only its second
base rate increase request since 1984. Effective November 1,
1993, the Company received DPU approval of a settlement
agreement that called for a base rate increase designed to
produce additional revenues of $6.7 million or 4.9% annually. In
addition to this rate increase, the DPU approved a proposal to
expand the eligibility criteria for Colonial's discount rate for
low-income residential heating customers and allowed the Company
to retain 10% of the revenues generated from releasing the
Company's interstate pipeline transportation capacity to third
parties above an initial threshold of $2,500,000. In 1994, the
Company received $3,313,000 of capacity release revenue,
$3,232,000 of which was credited back to firm customers and
$81,000 of which was retained by the Company.
In 1993, Colonial began unbundling its firm sales service
to commercial and industrial customers by offering a tariffed
firm transportation-only service. Pursuant to this service, a
customer procures its own gas supply and contracts with Colonial
for firm transportation service through Colonial's distribution
system. As of December 31, 1994, six customers had opted for
tariffed firm transportation service, representing less than
1.5% of the Company's annual firm load.
In 1994, the DPU opened two industry-wide proceedings which
may result in the further unbundling and deregulation of the
Company's business. One of those proceedings addresses whether
interruptible transportation and interruptible sales service on
LDC systems, and the release of interstate pipeline capacity by
LDCs, should be structured or priced differently. The DPU has
stated that it intends to issue a ruling containing general
guidelines on these matters in 1995. The other proceeding
addresses whether and how the traditional cost-of-service/rate-
of-return method of regulating gas and electric utilities might
be replaced with some type of alternative "incentive" method. In
a ruling issued on February 24, 1995, the DPU indicated that it
has the authority to implement incentive regulation and would be
receptive to various types of proposals. The Company is in the
process of analyzing specific incentive regulation options which
it could propose to the DPU as a means of benefiting its
customers and shareholders.
COMPETITION
Massachusetts law protects gas companies from competition
with respect to pipeline distribution of gas within its franchise
areas by providing that, where a gas company exists in active
operation, no other person may lay pipe in the public ways
without the approval, after notice and hearing, of the municipal
authorities and the DPU. If a municipality desires to enter the
gas business, it must take certain procedural steps, including a
favorable vote by a majority of the voters in a city election or
two-thirds vote at each of two town meetings. In addition, the
municipality must purchase the property of any gas company
operating in the municipality (if the company elects to sell) to
the extent, and at such prices, as may be agreed upon; if no
agreement is reached, resolution will be determined by the DPU.
Although, under a series of FERC orders issued in the late
1980's, certain larger industrial users may attempt 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.
In addition, as a result of FERC Order 636 and related
directives, more opportunities exist 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. 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.
Profit margins from interruptible sales and interruptible
transportation currently result in lower gas costs which are
passed through to firm sales customers in the CGAC and,
therefore, do not directly affect operating margin or net income.
As discussed above in "State Regulation", however, the DPU is
investigating whether current interruptible sales and
interruptible transportation practices should be changed.
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,
1994, the Company had incurred environmental response costs of
$2,608,000 related to the former gas manufacturing site and
$6,463,000 on the related disposal sites. The Company expects to
continue incurring costs arising from these environmental
matters.
As of December 31, 1994, the Company has recorded on the
balance sheet a long-term liability of $3,800,000 representing
estimated future response costs relating to these sites based on
the Company's preferred methods of remediation, of which
$2,038,000 relates to the gas manufacturing site. Based upon the
DPU order approving rate recovery of environmental response
costs, a regulatory asset of $3,800,000 has been recorded on the
balance sheet ("Unrecovered Environmental Costs Accrued").
Actual environmental response costs to be incurred depends on
various factors, and therefore future costs may differ from the
amount currently recorded as a liability.
As of December 31, 1994, the Company had settled claims
relating to these matters with all liability insurers and other
known potentially responsible parties ("PRP"). In accordance
with the DPU order referred to above, half the costs incurred in
pursuing insurers and other PRP are recovered from the
ratepayers through the CGAC and half are initially borne by the
Company. Also, per this order, any insurance and other proceeds
are applied first to the Company's costs of pursuing recovery
from insurers and other PRP, with the remainder divided equally
between the ratepayers and shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Thousands) Response Costs Insurance and Other Proceeds
Recovered Period Recorded as Non-
from of Rate Returned to Operating Income
Year Incurred Customers Recovery Customers Net of Taxes
1988 $ 853 $ 610 1990-1997 - -
1989 4,031 2,879 1990-1997 - -
1990 639 365 1991-1998 - -
1991 374 160 1992-1999 $ 851 $ 525
1992 617 176 1993-2000 1,121 673
1993 1,236 175 1994-2001 469 290
1994 1,321 - 1995-2002 122 75
Total $9,071 $4,365 $2,563 $1,563
TRANSGAS INC.
Transgas primarily provides over-the-road transportation of
LNG, propane and other commodities. Transgas acts as a common and
contract carrier for approximately 55 commercial and gas utility
customers located in the eastern half of the United States.
Canadian over-the-road transportation services are also available
through CGI Transport Limited, which is a wholly-owned subsidiary
of Transgas. Transgas also provides a unique LNG portable
pipeline service, which permits gas utilities to provide
continuous supply of natural gas to communities while the
pipeline supply is temporarily interrupted during scheduled
maintenance, upgrading and recertification, or during emergency
interruption.
Transgas has both common and contract carrier authorization
issued by the Interstate Commerce Commission for its interstate
trucking activities. Transgas also maintains several intrastate
authorizations with various state public service commissions.
Transgas is subject to various regulations applicable to
common and contract carriers, including accounting matters,
safety matters, rates charged and various fiscal matters.
Transgas had revenues of $12.1 million in 1994.
Approximately 66% of Transgas' revenue in 1994 was derived from
transporting Algerian LNG from the Distrigas import terminal,
which is located in Everett, Massachusetts. Transgas' revenues
increased $4.7 million or 58% over 1993 primarily due to the
extremely cold weather in the first quarter of 1994 which
generated a significant increase in demand for the truck
transportation of LNG and propane throughout the first three
quarters of 1994.
Transgas provides over-the-road transportation services by
utilizing a fleet of 47 tractors. Transgas operates 56 trailers
which are specifically designed for the transportation of LNG and
other cryogenic liquids. Of those cryogenic transport trailers,
21 are leased to Transgas on a long-term basis. In addition,
Transgas has 24 trailers which are designed for the
transportation of propane. Of those propane transport trailers, 4
are leased to Transgas on a long-term basis. In addition to the
equipment described above, Transgas also has 13 trailers which
are designed for carrying portable LNG vaporizers, as well as 2
flat bed trailers and 2 van trailers.
Transgas competes with many other motor carriers engaged in
the transportation of various gases and other products. Transgas
believes, however, that it is the leading over-the-road
transporter of LNG due to the size of its fleet of specialized
cryogenic transport trailers.
Item 1A. Executive Officers of the Registrant.
The following table indicates the present executive officers
of the Company, their ages, the dates when their service with the
Company began and their respective positions with the Company.
Affiliated with
Name and Age Position with Company Company Since
Frederic L. Putnam, Jr. (70) Chairman and 1953
Senior Executive Officer
Frederic L. Putnam, III (49) President and 1975
Chief Executive Officer
Charles W. Sawyer (49) Executive Vice President and 1976
Chief Operating Officer
Nickolas Stavropoulos (37) Executive Vice President - 1979
Finance, Marketing, and
Chief Financial Officer
John P. Harrington (52) Senior Vice President - 1966
Gas Supply and
Assistant to the President
Victor W. Baur (51) President - Transgas Inc. 1972
Dennis W. Carroll (48) Vice President and Treasurer 1990
Charles A. Cook (42) Vice President and General Counsel 1978
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 had been Executive Vice President - General Manager
since 1984. He also became a Director in August 1993.
Mr. Carroll has been Vice President and Treasurer since
August 1990. Prior to then he was a partner with Grant Thornton,
the Company's independent certified public accountants.
Mr. Cook has been Vice President and General Counsel since
July 1990. He had been Vice President and Counsel since August
1989.
These officers hold office until the next annual meeting of
the Board of Directors or until their successors are duly elected
and qualified, subject to earlier removal.
Item 2. Properties.
The Company has two principal operations centers and a
natural gas liquefaction and storage facility with approximately
1,000,000 Mcf of LNG storage capacity located in Tewksbury,
Massachusetts. The Company's gas production and storage
facilities, metering and regulation stations and operations
centers are generally located on land it owns.
A 175,000 Mcf LNG storage tank located on land owned by the
Company in South Yarmouth, Massachusetts is leased from an
unaffiliated company through 1998. The Company also has a lease
which expires in 2002 for office facilities in Lowell,
Massachusetts.
The Company's distribution mains of approximately 2,764
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, 1994.
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 1994 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 1994 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 1994 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 1994 annual report to stockholders under the following
captions: "Consolidated Statements of Income", "Consolidated
Balance Sheets", "Consolidated Statements of Cash Flows",
"Consolidated Statements of Common Equity", "Notes to
Consolidated Financial Statements", "Report of Independent
Certified Public Accountants" and "Shareholder Information".
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required to be reported hereunder for the
Company's Directors is incorporated by reference to the
information reported in the Company's Proxy Statement for its
1995 annual meeting of stockholders under the caption "Election
of Directors".
The information required to be reported hereunder for the
Executive Officers of the Registrant is incorporated by reference
to the information in Item 1A of this Form 10-K under the caption
"Executive Officers of the Registrant".
Item 11. Executive Compensation.
The information required to be reported hereunder is
incorporated by reference to the information reported in the
Company's Proxy Statement for its 1995 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 1995 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 1995 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 1994 annual report
to stockholders under the following captions:
"Consolidated Statements of Income", "Consolidated
Balance Sheets", "Consolidated Statements of Cash Flows",
"Consolidated Statements of Common Equity", "Notes to
Consolidated Financial Statements" and "Report of
Independent Certified Public Accountants".
2. Financial Statement Schedules. The following
Financial Statement Schedules and report thereon are
filed as part of this Form 10-K on the pages indicated
below:
Schedule
Number Description
Report of Independent Certified Public Accountants on Schedule
II Valuation and Qualifying Accounts for the three years ended
December 31, 1994
Schedules other than those listed above are either not required
or not applicable, or the required information is shown in the
financial statements or notes thereto. Columns omitted from
schedules filed have been omitted because the information is not
applicable.
3. List of Exhibits
Exhibit
Number Exhibit Reference
3a Restated Articles of Organization of Incorporated herein
Colonial Gas Company, dated April by reference.
19, 1989, as amended on July 16,
1992 and supplemented by a
certificate of vote of Directors
establishing a series of a class of
stock filed on November 30, 1993,
filed as Exhibit 3(a) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
3b By-Laws of Colonial Gas Company, as Incorporated herein
amended to date, filed as Exhibit by reference.
3(b) to the Registrant's Annual
Report on Form 10-K for the fiscal
year ended December 31, 1993.
4a Second Amended and Restated First Incorporated herein
Mortgage Indenture, dated as of June by reference.
1, 1992, filed as Exhibit 4(b) to
Form 10-Q of the Registrant for the
quarter ended June 30, 1992.
4b First Supplemental Indenture, dated Incorporated herein
as of June 15, 1992, filed as by reference.
Exhibit 4(c) to Form 10-Q of the
Registrant for the quarter ended
June 30, 1992.
4c 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.
4d 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.
4e 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.
4f 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.
4g 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 Storage Service Transportation Incorporated herein
Contract with Tennessee Gas Pipeline by reference.
Company, a Division of Tenneco Inc.,
dated January 1, 1983, filed as
Exhibit 10(b) to the Registrant's
Registration Statement on Form S-2.
Commission File No. 2-93118.
10b 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.
10c 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.
10d 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.
10e Firm Natural Gas Transportation Incorporated herein
Agreement between Tennessee Gas by reference.
Pipeline Company and Colonial Gas
Company (under Rate Schedule NET-
NE), dated February 7, 1991, filed
as Exhibit 10(ff) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1991.
10f Gas Transportation Contract for Firm Incorporated herein
Reserved Service between Iroquois by reference.
Gas Transmission System, L.P. and
Colonial Gas Company, dated November
25, 1991, filed as Exhibit 10(gg) to
the Registrant's Annual Report on
Form 10-K for the fiscal year ended
December 31, 1992.
10g 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.
10h 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.
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(r) 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(s) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10k 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.
10l 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.
10m 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.
10n 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.
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(x) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10p 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.
10q 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.
10r 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.
10s 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.
10t Service Agreement between Texas Incorporated herein
Eastern Transmission Corporation and by reference.
Colonial Gas Company (under Rate
Schedule FT-1), dated June 1, 1993.
10u Firm Gas Transportation Agreement Incorporated herein
between Koch Gateway Pipeline by reference.
Company and Colonial Gas Company,
dated December 1, 1993, filed as
Exhibit 10(gg) to the Registrant's
Annual Report on Form 10-K for the
fiscal year ended December 31, 1993.
10v 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.
10w Gas Storage Contract between Incorporated herein
Tennessee Gas Pipeline Company and by reference.
Colonial Gas Company (under Rate
Schedule FS), dated September 1,
1993, filed as Exhibit 10(mm) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10x 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.
10y 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.
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(pp) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10aa Service Agreement between Algonquin Incorporated herein
Gas Transmission Company and by reference.
Colonial Gas Company (under Rate
Schedule FST-LG), dated October 1,
1993, filed as Exhibit 10(qq) to the
Registrant's Annual Report on Form
10-K for the fiscal year ended
December 31, 1993.
10bb 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.
10cc 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.
10dd 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.
10ee 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.
10ff 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.
10gg 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.
10hh 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.
10ii 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.
10jj 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.
10kk Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10kk.
Colonial Gas Company (under Rate
Schedule FT-1), dated August 18,
1994.
10ll Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10ll.
Colonial Gas Company (under Rate
Schedule FSS-1), dated August 29,
1994.
10mm Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10mm.
Colonial Gas Company (under Rate
Schedule CDS), dated August 29,
1994.
10nn Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10nn.
Colonial Gas Company (under Rate
Schedule CDS), dated August 29,
1994.
10oo Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10oo.
Colonial Gas Company (under Rate
Schedule SS-1), dated November 30,
1994.
10pp Service Agreement between Texas Filed herewith as
Eastern Transmission Corporation and Exhibit 10pp.
Colonial Gas Company (under Rate
Schedule FSS-1), dated November 30,
1994.
10qq Letter Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10qq.
Colonial Gas Company, regarding
transfer of transportation
entitlements, dated March 28, 1994.
10rr Capacity Release Umbrella Agreement Filed herewith as
between Algonquin Gas Transmission Exhibit 10rr.
Company and Colonial Gas Company
(under Rate Schedules AFT-1 and AFT-
1S), dated September 14, 1994.
10ss Service Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10ss.
Colonial Gas Company (under Rate
Schedule AFT-1), dated November 1,
1994.
10tt Service Agreement between Algonquin Filed herewith as
Gas Transmission Company and Exhibit 10tt.
Colonial Gas Company (under Rate
Schedule AFT-1), dated November 1,
1994.
10uu 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.
10vv 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.
10ww 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.
10xx Rate increase deferral incentive Filed herewith as
policy, dated January 1, 1995. Exhibit 10xx.
13a Those portions of the 1994 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 10ww and 10xx above are management contracts or
compensatory plans or arrangements in which the executive
officers of the Company participate.
(b) Reports on Form 8-K.
A report on Form 8-K was filed on November 16, 1994
reporting the Company's announcement of an early retirement
program and closing of its two retail appliance stores.
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 18, 1995, which is included
in the 1994 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 18, 1995
SCHEDULE II
COLONIAL GAS COMPANY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
For the Three Years Ended December 31, 1994
(In Thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE CHARGED
AT TO COSTS BALANCE AT
BEGINNING AND END OF
DESCRIPTION OF PERIOD EXPENSES DECUCTIONS PERIOD
For the Year Ended December 31, 1994
Reserve for $1,682 $1,803 $1,815 (1) $1,670
uncollectible accounts
Reserve for insurance $ 598 $ 494 $ 565 $ 527
claims
For the Year Ended December 31, 1993
Reserve for $1,187 $2,101 $1,606 (1) $1,682
uncollectible accounts
Reserve for insurance $ 548 $ 616 $ 566 $ 598
claims
For the Year Ended December 31, 1992
Reserve for $ 778 $1,696 $1,287 (1) $1,187
uncollectible accounts
Reserve for insurance $ - $ 622 $ 74 $ 548
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
F.L. Putnam, Jr., Chairman March 24, 1995
of the Board of Directors
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
Signature Title Date
F.L. Putnam, Jr. Senior Executive Officer, March 24, 1995
Director
Nickolas Stavropoulos Executive Vice President - Finance, March 24, 1995
Marketing and Chief Financial Officer,
Director (Principal Financial Officer)
D.W. Carroll Vice President and Treasurer March 24, 1995
(Principal Accounting Officer)
V.W. Baur Director March 24, 1995
A.C. Dudley Director March 24, 1995
J.P. Harrington Director March 24, 1995
H.C. Homeyer Director March 24, 1995
R.L. Hull Director March 24, 1995
D.H. LeVan, Jr. Director March 24, 1995
K.R. Lydecker Director March 24, 1995
F.L. Putnam, III President and Chief March 24, 1995
Executive Officer, Director
J.F. Reilly, Jr. Director March 24, 1995
A.B. Sides, Jr. Director March 24, 1995
M.M. Stapleton Director March 24, 1995
C.O. Swanson Director March 24, 1995
G.E. Wik Director March 24, 1995
[EXHIBIT 10kk TO COLONIAL GAS COMPANY
FORM 10-K FOR THE YEAR ENDED 12/31/94]
Contract #: 800400
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 18th day of
August, 1994, by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer", whether one
or more),
W I T N E S S E T H:
WHEREAS, there currently exists between Pipeline and Customer
two service agreements under Rate Schedule FT-1 (Pipeline's
Contract Nos. 330211 and 330916) which specify an MDQ of 52 dth
and 52 dth, respectively; and
WHEREAS, Pipeline and Customer desire to enter into one service
agreement under Rate Schedule FT-1 which shall supersede the two
existing Rate Schedule FT-1 service agreements; and
WHEREAS, transportation rights under the new Rate Schedule FT-1
service agreement are consistent with the existing rights under
the two existing Rate Schedule FT-1 service agreements it
supersedes;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of
Pipeline's Rate Schedule FT-1, and of the General Terms and
Conditions, transportation service hereunder will be firm.
Subject to the terms, conditions and limitations hereof and of
Pipeline's Rate Schedule FT-1, Pipeline agrees to deliver for
Customer's account quantities of natural gas up to the following
quantity:
Maximum Daily Quantity (MDQ) 104 dth
Pipeline shall receive for Customer's account, at those points
on Pipeline's system as specified in Article IV herein or
available to Customer pursuant to Section 14 of the General Terms
and Conditions (hereinafter referred to as Point(s) of Receipt)
for transportation hereunder daily quantities of gas up to
Customer's MDQ, plus Applicable Shrinkage. Pipeline shall
transport and deliver for Customer's account, at those points on
Pipeline's system as specified in Article IV herein or available
to Customer pursuant to Section 14 of the General Terms and
Conditions (hereinafter referred to as Point(s) of Delivery),
such daily quantities tendered up to such Customer's MDQ.
Pipeline shall not be obligated to, but may at its discretion,
receive at any Point of Receipt on any day a quantity of gas in
excess of the applicable Maximum Daily Receipt Obligation (MDRO),
plus Applicable Shrinkage, but shall not receive in the aggregate
at all Points of Receipt on any day a quantity of gas in excess
of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any
Point of Delivery on any day a quantity of gas in excess of the
applicable Maximum Daily Delivery Obligation (MDDO), but shall
not deliver in the aggregate at all Points of Delivery on any day
a quantity of gas in excess of the applicable MDQ.
In addition to the MDQ and subject to the terms, conditions and
limitations hereof, Rate Schedule FT-1 and the General Terms and
Conditions, Pipeline shall deliver within the Access Area under
this and all other service agreements under Rate Schedules CDS,
FT-1, and/or SCT, quantities up to Customer's Operational Segment
Capacity Entitlements, excluding those Operational Segment
Capacity Entitlements scheduled to meet Customer's MDQ, for
Customer's account, as requested on any day.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on October 1,
1994 and shall continue in force and effect until 10/31/2012 and
year to year thereafter unless this Service Agreement is
terminated as hereinafter provided. This Service Agreement may
be terminated by either Pipeline or Customer upon five (5) years
prior written notice to the other specifying a termination date
of any year occurring on or after the expiration of the primary
term. Subject to Section 22 of Pipeline's General Terms and
Conditions and without prejudice to such rights, this Service
Agreement may be terminated at any time by Pipeline 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 (30) days
after payment is due; provided, Pipeline gives thirty (30) 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 Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT
TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER
TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL
GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION
OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S
RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS
AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
Any portions of this Service Agreement necessary to correct or
cash-out imbalances under this Service Agreement as required by
the General Terms and Conditions of Pipeline's FERC Gas Tariff,
Volume No. 1, shall survive the other parts of this Service
Agreement until such time as such balancing has been
accomplished.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule FT-1 and of
the General Terms and Conditions of Pipeline's FERC Gas Tariff on
file with the Federal Energy Regulatory Commission, all of which
are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered hereunder
and for the availability of such service in the period stated,
the applicable prices established under Pipeline's Rate Schedule
FT-1 as filed with the Federal Energy Regulatory Commission, and
as same may hereafter be legally amended or superseded.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule FT-1, (b) Pipeline's Rate
Schedule FT-1 pursuant to which service hereunder is rendered or
(c) any provision of the General Terms and Conditions applicable
to Rate Schedule FT-1. Notwithstanding the foregoing, Customer
does not agree that Pipeline shall have the unilateral right
without the consent of Customer subsequent to the execution of
this Service Agreement and Pipeline shall not have the right
during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change
the MDQ specified in Article I, to change the term of the
agreement as specified in Article II, to change Point(s) of
Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character
of the service hereunder. Pipeline agrees that Customer may
protest or contest the aforementioned filings, and Customer does
not waive any rights it may have with respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The Point(s) of Receipt and Point(s) of Delivery at which
Pipeline shall receive and deliver gas, respectively, shall be
specified in Exhibit(s) A and B of the executed service
agreement. Customer's Zone Boundary Entry Quantity and Zone
Boundary Exit Quantity for each of Pipeline's zones shall be
specified in Exhibit C of the executed service agreement.
Exhibit(s) A, B and C are hereby incorporated as part of this
Service Agreement for all intents and purposes as if fully copied
and set forth herein at length.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform to the quality specifications set forth in
Section 5 of Pipeline's General Terms and Conditions. Customer
agrees that in the event Customer tenders for service hereunder
and Pipeline agrees to accept natural gas which does not comply
with Pipeline's quality specifications, as expressly provided for
in Section 5 of Pipeline's General Terms and Conditions, Customer
shall pay all costs associated with processing of such gas as
necessary to comply with such quality specifications. Customer
shall execute or cause its supplier to execute, if such supplier
has retained processing rights to the gas delivered to Customer,
the appropriate agreements prior to the commencement of service
for the transportation and processing of any liquefiable
hydrocarbons and any PVR quantities associated with the
processing of gas received by Pipeline at the Point(s) of Receipt
under such Customer's service agreement. In addition, subject to
the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered
for transportation hereunder.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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, cert-
ified, or regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: COLONIAL GAS COMPANY
40 MARKET STREET
LOWELL, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it
releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and
the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties are
subject to all present and future valid laws with respect to the
subject matter, State and Federal, and to all valid present and
future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
Service Agreement(s) dated, 06/01/93 between Pipeline
and Customer under Pipeline's Rate Schedule FT-1
(Pipeline's Contract Nos. 330211 and 330916).
IN WITNESS WHEREOF, the parties hereto have caused this Service
Agreement to be signed by their respective Presidents, Vice
Presidents or other duly authorized agents and their respective
corporate seals to be hereto affixed and attested by their
respective Secretaries or Assistant Secretaries, the day and year
first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By: John P. Harrington
Vice President - Gas Supply
ATTEST:
Phyllis G. Semenchuk
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED OCTOBER 1, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND COLONIAL GAS COMPANY ("Customer"),
DATED OCTOBER 1, 1994:
(1) Customer's firm Point(s) of Receipt:
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) Responsibilities Owner Operator
1. 72822 CNG, N. Summit 104 dth TETCO TETCO CNG
Storage Fayette
Co., PA
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published
by Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as
set forth in Section 6 of Pipeline's General Terms and Conditions at such
Point(s) of Receipt.
Transportation
Transportation Path Path Quantity (Dth/D)
M2 to M3 104
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT A DATED: June 1, 1993
EXHIBIT B, POINT(S) OF DELIVERY, DATED OCTOBER 1, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED OCTOBER 1, 1994:
Maximum
Daily
Point Delivery Delivery Measurement
of Obligation Pressure Responsi-
Delivery Description (dth) Obligation bilities Owner Operator
1. 70087 ALGONQUIN- 104 AT ANY TX EAST TX EAST ALGONQUIN
LAMBERTVILLE PRESSURE TRAN TRAN
NJ, REQUESTED BY
HUNTERDON CO., NJ CUSTOMER,
PROVIDED, HOWEVER,
THE MAXIMUM
DELIVERY PRESSURE
SHALL NOT EXCEED
750 POUNDS PER
SQUARE INCH GAUGE
2. 79821 AGT-COLONIAL 0 N/A N/A N/A N/A
GAS-FOR
NOMINATION
PURPOSES
provided, however, that, until changed by a subsequent agreement
between Pipeline and Customer, Pipeline's aggregate maximum daily
delivery obligation at the points of delivery described above,
including Pipeline's maximum daily delivery obligation under this
and all other service agreements existing between Pipeline and
Customer, shall in no event exceed the following:
Aggregate Maximum
Point of Delivery Daily Delivery Obligation
No. 1 23,644 dth
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT B DATED: June 1, 1993
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY
EXIT QUANTITY, DATED OCTOBER 1, 1994, TO THE SERVICE AGREEMENT UNDER
RATE SCHEDULE FT-1 BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION
("Pipeline") AND COLONIAL GAS COMPANY ("CUSTOMER"), DATED
OCTOBER 1, 1994:
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
FROM M2 TO M3: 104
[END OF EXHIBIT 10kk TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10ll TO COLONIAL GAS COMPANY
FORM 10-K FOR THE YEAR ENDED 12/31/94]
Contract #: 400505
SERVICE AGREEMENT
FOR RATE SCHEDULE FSS-1
This agreement, made and entered into this 29th day of
August, 1994, by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer," whether one
or more),
W I T N E S S E T H:
WHEREAS, Customer is a customer of Algonquin Gas
Transmission Company ("Algonquin"); and
WHEREAS, Algonquin is a customer of Pipeline under certain
of Pipeline's rate schedules and related service agreements; and
WHEREAS, pursuant to the Federal Energy Regulatory
Commission's ("Commission") order issued on July 8, 1994, in
Docket Nos. RP93-14-000, et al., and 18 C.F.R. Section 284.242,
Algonquin is assigning on a permanent basis certain of its firm
service entitlements on Pipeline to certain of Algonquin's direct
customers; and
WHEREAS, Customer's capacity entitlements on Pipeline
pursuant to this Service Agreement are a result of Algonquin's
permanent assignment to Customer as described above; and
WHEREAS, Customer and Pipeline desire to enter into this
Service Agreement to reflect such permanent assignment from
Algonquin to Customer;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof and
of Pipeline's Rate Schedule FSS-1, Pipeline agrees to provide
firm service for Customer under Rate Schedule FSS-1 and to
receive and store for Customer's account quantities of natural
gas up to the following quantity:
Maximum Daily Injection Quantity (MDIQ) 95 dth
Maximum Storage Quantity (MSQ) 18,420 dth
Pipeline agrees to withdraw from storage for Customer, at
Customer's request, quantities of gas up to Customer's Maximum
Daily Withdrawal Quantity (MDWQ) of 307 dekatherms, or such
lesser quantity as determined pursuant to Rate Schedule FSS-1,
from Customer's Storage Inventory, plus Applicable Shrinkage.
Pipeline's obligation to withdraw gas on any day is governed by
the provisions of Rate Schedule FSS-1, including but not
limited to Section 6.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on
September 1, 1994 and shall continue in force and effect until
April 30, 2012 and year to year thereafter unless this Service
Agreement is terminated as hereinafter provided. This Service
Agreement may be terminated by either Pipeline or Customer upon
five (5) years prior written notice to the other specifying a
termination date of any year occurring on or after the
expiration of the primary term. In addition to Pipeline rights under
Section 22 of Pipeline's General Terms and Conditions and without
prejudice to such rights, this Service Agreement may be
terminated at any time by Pipeline 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 (30) days after payment is
due; provided, Pipeline gives thirty (30) 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 Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT
TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER
TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL
GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION
OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S
RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS
AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
In the event there is gas in storage for Customer's account
on April 30 of the year of termination of this Service Agreement,
this Service Agreement shall continue in force and effect for the
sole purpose of withdrawal and delivery of said gas to Customer
for an additional one-hundred and twenty (120) days.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule FSS-1 and
of the General Terms and Conditions of Pipeline's FERC Gas Tariff
on file with the Federal Energy Regulatory Commission, all of
which are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered
hereunder and for the availability of such service in the period
stated, the applicable prices established under Pipeline's Rate
Schedule FSS-1 as filed with the Federal Energy Regulatory
Commission and as the same may be hereafter revised or changed.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule FSS-1, (b)
Pipeline's Rate Schedule FSS-1, pursuant to which service
hereunder is rendered or (c) any provision of the General Terms
and Conditions applicable to Rate Schedule FSS-1.
Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of
Customer subsequent to the execution of this Service Agreement
and Pipeline shall not have the right during the effectiveness of
this Service Agreement to make any filings pursuant to Section 4
of the Natural Gas Act to change the MDIQ, MSQ and MDWQ specified
in Article I, to change the term of the service agreement as
specified in Article II, to change Point(s) of Receipt specified in
Article IV, to change the Point(s) of Delivery specified in
Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest
the aforementioned filings, and Customer does not waive any
rights it may have with respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The natural gas received by Pipeline for Customer's account
for storage injection pursuant to this Service Agreement shall be
those quantities scheduled for delivery pursuant to Service
Agreements between Pipeline and Customer under Rate Schedules
CDS, FT-1, SCT, PTI or IT-1 which specify as a Point of Delivery
the "FSS-1 Storage Point". For purposes of billing of Usage
Charges under Rate Schedules CDS, FT-1, SCT, PTI or IT-1,
deliveries under Rate Schedules CDS, FT-1, SCT, PTI or IT-1 for
injection into storage scheduled directly to the "FSS-1 Storage
Point" shall be deemed to have been delivered 60% in Market Zone
2 and 40% in Market Zone 3. In addition, subject to Pipeline's
prior written consent, any positive variance between scheduled
deliveries and actual deliveries on any day (i.e. scheduled
deliveries exceed actual deliveries) at Customer's Points of
Delivery under Rate Schedules CDS, FT-1, SCT, or IT-1 shall be
deemed for billing purposes delivered at the Point of Delivery
and shall be injected into storage for Customer's account. In
addition to accepting gas for storage injection at the FSS-1
Storage Point, Pipeline will accept gas tendered at points of
interconnection between Pipeline and third party facilities at
Oakford and Leidy Storage Fields provided that such receipt does
not result in Customer tendering aggregate quantities for storage
in excess of the Customer MDIQ.
The natural gas delivered by Pipeline for Customer's account
as a result of storage withdrawal pursuant to this Service
Agreement shall be those quantities scheduled for withdrawal
hereunder and subsequent transportation pursuant to service
agreements between Pipeline and Customer under Rate Schedule CDS,
FT-1, SCT, or IT-1 which specify as a Point of Receipt the "FSS-1
Storage Point". For purpose of billing under Rate Schedules CDS,
FT-1, SCT, or IT-1, withdrawals from storage for subsequent
transportation under Rate Schedules CDS, FT-1, SCT, or IT-1 shall
be deemed to have been received 60% in Market Zone 2 and 40% in
Market Zone 3. In addition to the withdrawal of gas from storage
for delivery through a transportation service on Pipeline's
system, gas may be withdrawn for delivery into the facilities of
third parties at the points of interconnection between Pipeline
and the facilities of such third parties at Oakford and Leidy
Storage Fields provided that such withdrawals do not result in
Customer withdrawing gas in excess of his MDWQ or MSQ. A
separate transportation charge will not be applicable to these
deliveries.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform and be subject to the provisions of Section 5 of
the General Terms and Conditions. Customer agrees that in the
event Customer tenders for service hereunder and Pipeline agrees
to accept natural gas which does not comply with Pipeline's
quality specifications, as expressly provided for in Section 5 of
Pipeline's General Terms and Conditions, Customer shall pay all
costs associated with processing of such gas as necessary to
comply with such quality specifications.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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 regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: COLONIAL GAS COMPANY
P.O. Box 3064
40 Market Street
Lowell, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties
are subject to all present and future valid laws with respect to
the subject matter, State and Federal, and to all valid present
and future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
None
IN WITNESS WHEREOF, the Parties hereto have caused this
Service Agreement to be signed by their respective Presidents,
Vice Presidents, or other duly authorized agents and their
respective corporate seals to be hereto affixed and attested by
their respective Secretaries or Assistant Secretaries, the day
and year first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By: John P. Harrington
Vice President - Gas Supply
ATTEST:
Timothy A. Clark
[END OF EXHIBIT 10ll TO COLONIAL GAS COMPANY
FORM 10-K FOR THE YEAR ENDED 12/31/94]
[EXHIBIT 10mm TO COLONIAL GAS COMPANY
FORM 10-K FOR THE YEAR ENDED 12/31/94]
Contract #: 800419
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
This Service Agreement, made and entered into this 29th day
of August, 1994, by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer", whether one
or more),
W I T N E S S E T H:
WHEREAS, Customer is a customer of Algonquin Gas Transmission
Company ("Algonquin"); and
WHEREAS, Algonquin is a customer of Pipeline under certain of
Pipeline's rate schedules and related service agreements; and
WHEREAS, pursuant to the Federal Energy Regulatory
Commisssion's ("Commission") order issued on July 8, 1994, in
Docket Nos. RP93-14-000, et al., and 18 C.F.R. Section 284.242,
Algonquin is assigning on a permanent basis certain of its firm
service entitlements on Pipeline to certain of Algonquin's direct
customers; and
WHEREAS, Customer's capacity entitlements on Pipeline
pursuant to this Service Agreement are a result of Algonquin's
permanent assignment to Customer as described above; and
WHEREAS, Customer and Pipeline desire to enter into this
Service Agreement to reflect such permanent assignment from
Algonquin to Customer;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of
Pipeline's Rate Schedule CDS, and of the General Terms and
Conditions, transportation service hereunder will be firm.
Subject to the terms, conditions and limitations hereof and of
Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified
in Article IV herein or available to Customer pursuant to Section
14 of the General Terms and Conditions (hereinafter referred to
as Point(s) of Delivery), for Customer's account, as requested
for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:
Maximum Daily Quantity (MDQ) 233 dth
Subject to variances as may be permitted by Sections 2.4 of
Rate Schedule CDS or the General Terms and Conditions, Customer
shall deliver to Pipeline and Pipeline shall receive, for
Customer's account, at those points on Pipeline's system as
specified in Article IV herein or available to Customer pursuant
to Section 14 of the General Terms and Conditions (hereinafter
referred to as Point(s) of Receipt) daily quantities of gas equal
to the daily quantities delivered to Customer pursuant to this
Service Agreement up to Customer's MDQ, plus Applicable Shrinkage
as specified in the General Terms and Conditions.
Pipeline shall not be obligated to, but may at its
discretion, receive at any Point of Receipt on any day a quantity
of gas in excess of the applicable Maximum Daily Receipt
Obligation (MDRO), plus Applicable Shrinkage, but shall not
receive in the aggregate at all Points of Receipt on any day a
quantity of gas in excess of the applicable MDQ, plus Applicable
Shrinkage. Pipeline shall not be obligated to, but may at its
discretion, deliver at any Point of Delivery on any day a
quantity of gas in excess of the applicable Maximum Daily
Delivery Obligation (MDDO), but shall not deliver in the
aggregate at all Points of Delivery on any day a quantity of gas
in excess of the MDQ.
In addition to the MDQ and subject to the terms, conditions
and limitations hereof, Rate Schedule CDS and the General Terms
and Conditions, Pipeline shall deliver within the Access Area
under this and all other service agreements under Rate Schedules
CDS, FT-1, and/or SCT, quantities up to Customer's Operational
Segment Capacity Entitlements, excluding those Operational
Segment Capacity Entitlements scheduled to meet Customer's MDQ,
for Customer's account, as requested on any day.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on
September 1, 1994 and shall continue in force and effect until
10/31/2012 and year to year thereafter unless this Service
Agreement is terminated as hereinafter provided. This Service
Agreement may be terminated by either Pipeline or Customer upon
five (5) years prior written notice to the other specifying a
termination date of any year occurring on or after the expiration
of the primary term. In addition to Pipeline rights under
Section 22 of Pipeline's General Terms and Conditions and without
prejudice to such rights, this Service Agreement may be
terminated at any time by Pipeline 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 (30) days after payment is
due; provided, Pipeline gives thirty (30) 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 Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED
CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY
CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE
NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION.
PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE
GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE
TERMINATION.
Any portions of this Service Agreement necessary to correct
or cash-out imbalances under this Service Agreement as required
by the General Terms and Conditions of Pipeline's FERC Gas
Tariff, Volume No. 1, shall survive the other parts of this
Service Agreement until such time as such balancing has been
accomplished.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule CDS and of
the General Terms and Conditions of Pipeline's FERC Gas Tariff on
file with the Federal Energy Regulatory Commission, all of which
are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered
hereunder and for the availability of such service in the period
stated, the applicable prices established under Pipeline's Rate
Schedule CDS as filed with the Federal Energy Regulatory
Commission, and as same may hereafter be legally amended or
superseded.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule CDS, (b) Pipeline's
Rate Schedule CDS pursuant to which service hereunder is rendered
or (c) any provision of the General Terms and Conditions
applicable to Rate Schedule CDS. Notwithstanding the foregoing,
Customer does not agree that Pipeline shall have the unilateral
right without the consent of Customer subsequent to the execution
of this Service Agreement and Pipeline shall not have the right
during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change
the MDQ specified in Article I, to change the term of the
agreement as specified in Article II, to change Point(s) of
Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character
of the service hereunder. Pipeline agrees that Customer may
protest or contest the aforementioned filings, and Customer does
not waive any rights it may have with respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The Point(s) of Receipt and Point(s) of Delivery at which
Pipeline shall receive and deliver gas, respectively, shall be
specified in Exhibit(s) A and B of the executed service
agreement. Customer's Zone Boundary Entry Quantity and Zone
Boundary Exit Quantity for each of Pipeline's zones shall be
specified in Exhibit C of the executed service agreement.
Exhibit(s) A, B and C are hereby incorporated as part of this
Service Agreement for all intents and purposes as if fully copied
and set forth herein at length.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform to the quality specifications set forth in
Section 5 of Pipeline's General Terms and Conditions. Customer
agrees that in the event Customer tenders for service hereunder
and Pipeline agrees to accept natural gas which does not comply
with Pipeline's quality specifications, as expressly provided for
in Section 5 of Pipeline's General Terms and Conditions, Customer
shall pay all costs associated with processing of such gas as
necessary to comply with such quality specifications. Customer
shall execute or cause its supplier to execute, if such supplier
has retained processing rights to the gas delivered to Customer,
the appropriate agreements prior to the commencement of service
for the transportation and processing of any liquefiable
hydrocarbons and any PVR quantities associated with the
processing of gas received by Pipeline at the Point(s) of Receipt
under such Customer's service agreement. In addition, subject to
the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered
for transportation hereunder.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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 regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: COLONIAL GAS COMPANY
P.O. Box 3064
40 Market Street
Lowell, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it
releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and
the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties are
subject to all present and future valid laws with respect to the
subject matter, State and Federal, and to all valid present and
future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
None
IN WITNESS WHEREOF, the parties hereto have caused this
Service Agreement to be signed by their respective Presidents,
Vice Presidents or other duly authorized agents and their respec-
tive corporate seals to be hereto affixed and attested by their
respective Secretaries or Assistant Secretaries, the day and year
first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By John P. Harrington
Vice President - Gas Supply
ATTEST:
Timothy A. Clark
EXHBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED AUGUST 29, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND COLONIAL GAS COMPANY ("Customer"),
DATED AUGUST 29, 1994:
(1) Customer's firm Point(s) of Receipt:
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage)(dth) Responsibilities Owner Operator
None
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published
by Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as
set forth in Section 6 of Pipeline's General Terms and Conditions at such
Point(s) of Receipt.
Transportation
Transportation Path Path Quantity (Dth/D)
M1 to M3 233
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT A DATED:__________
EXHBIT B, POINT(S) OF DELIVERY, DATED AUGUST 29, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED AUGUST 29, 1994:
Maximum
Daily
Point Delivery Delivery Measurement
of Obligation Pressure Responsi-
Delivery Description (dth) Obligation bilities Owner Operator
1. 70087 ALGONQUIN- 233 AS REQUESTED TX EAST TX EAST ALGONQUIN
LAMBERTVILLE BY CUSTOMER, TRAN TRAN
NJ HUNTERDON, NOT TO EXCEED
CO., NJ 750 POUNDS PER
SQUARE GAUGE
2. 71078 ALGONQUIN- 233 AS REQUESTED TX EAST TX EAST ALGONQUIN
HANOVER, NH BY CUSTOMER TRAN TRAN
MORRIS CO., NJ NOT TO EXCEED
750 POUNDS PER
SQUARE GAUGE
3. 79821 AGT-COLONIAL 0 N/A N/A N/A N/A
FOR
NOMINATION
PURPOSES
4. 79560 SS STORAGE SUCH N/A N/A N/A N/A
INJECTION QUANTITIES
POINT ACCEPTED BY
PIPELINE NOT
TO EXCEED 74
5. 79513 FSS-1 95 N/A N/A N/A N/A
STORAGE 04/01-10/31
POINT 95
11/01-03/31
provided, however, that until changed by a subsequent Agreement between
Pipeline and Customer, Pipeline's aggregate maximum daily delivery
obligations under this and all other firm Service Agreements existing
between Pipeline and Customer, shall in no event exceed the following:
AGGREGATE MAXIMUM DAILY
POINT OF DELIVERY DELIVERY OBLIGATION (DTH)
No. 1 23,937
No. 2 9,739
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT B DATED:__________________
EXHBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY
EXIT QUANTITY, DATED AUGUST 29, 1994, TO THE SERVICE AGREEMENT UNDER
RATE SCHEDULE CDS BETWEEN TEXAS EASTERN TRANSMISSION COPRORATION
("Pipeline") AND COLONIAL GAS COMPANY ("CUSTOMER"), DATED
AUGUST 29, 1994:
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
FROM STX TO M1-TGC: 7
FROM ETX TO M1-24: 28
FROM ETX TO M1-TXG: 10
FROM WLA TO M1-TXG: 3
FROM WLA TO M1-TGC: 7
FROM ELA TO M1-30: 182
FROM M1-24 TO M2-24: 28
FROM M1-30 TO M2-30: 182
FROM M1-TXG TO M2-TXG: 13
FROM M1-TGC TO M2-TGC: 13
FROM M2 TO M3: 233
ZONE BOUNDARY EXIT QUANTITY
Dth/D
FROM M1-24 TO M2-24: 28
FROM M1-30 TO M2-30: 182
FROM M1-TXG TO M2-TXG: 13
FROM M1-TGC TO M2-TGC: 13
FROM M2 TO M3: 233
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT C DATED:_____________
[END OF EXHIBIT 10mm TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10nn TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Contract #: 800420
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
This Service Agreement, made and entered into this 29th day
of August, 1994 by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer", whether one
or more),
W I T N E S S E T H:
WHEREAS, Customer is a customer of Algonquin Gas Transmission
Company ("Algonquin"); and
WHEREAS, Algonquin is a customer of Pipeline under certain of
Pipeline's rate schedules and related service agreements; and
WHEREAS, pursuant to the Federal Energy Regulatory
Commisssion's ("Commission") order issued on July 8, 1994, in
Docket Nos. RP93-14-000, et al., and 18 C.F.R. Section 284.242,
Algonquin is assigning on a permanent basis certain of its firm
service entitlements on Pipeline to certain of Algonquin's direct
customers; and
WHEREAS, Customer's capacity entitlements on Pipeline
pursuant to this Service Agreement are a result of Algonquin's
permanent assignment to Customer as described above; and
WHEREAS, Customer and Pipeline desire to enter into this
Service Agreement to reflect such permanent assignment from
Algonquin to Customer;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of
Pipeline's Rate Schedule CDS, and of the General Terms and
Conditions, transportation service hereunder will be firm.
Subject to the terms, conditions and limitations hereof and of
Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified
in Article IV herein or available to Customer pursuant to Section
14 of the General Terms and Conditions (hereinafter referred to
as Point(s) of Delivery), for Customer's account, as requested
for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:
Maximum Daily Quantity (MDQ) 307 dth
Subject to variances as may be permitted by Sections 2.4 of
Rate Schedule CDS or the General Terms and Conditions, Customer
shall deliver to Pipeline and Pipeline shall receive, for
Customer's account, at those points on Pipeline's system as
specified in Article IV herein or available to Customer pursuant
to Section 14 of the General Terms and Conditions (hereinafter
referred to as Point(s) of Receipt) daily quantities of gas equal
to the daily quantities delivered to Customer pursuant to this
Service Agreement up to Customer's MDQ, plus Applicable Shrinkage
as specified in the General Terms and Conditions.
Pipeline shall not be obligated to, but may at its
discretion, receive at any Point of Receipt on any day a quantity
of gas in excess of the applicable Maximum Daily Receipt
Obligation (MDRO), plus Applicable Shrinkage, but shall not
receive in the aggregate at all Points of Receipt on any day a
quantity of gas in excess of the applicable MDQ, plus Applicable
Shrinkage. Pipeline shall not be obligated to, but may at its
discretion, deliver at any Point of Delivery on any day a
quantity of gas in excess of the applicable Maximum Daily
Delivery Obligation (MDDO), but shall not deliver in the
aggregate at all Points of Delivery on any day a quantity of gas
in excess of the MDQ.
In addition to the MDQ and subject to the terms, conditions
and limitations hereof, Rate Schedule CDS and the General Terms
and Conditions, Pipeline shall deliver within the Access Area
under this and all other service agreements under Rate Schedules
CDS, FT-1, and/or SCT, quantities up to Customer's Operational
Segment Capacity Entitlements, excluding those Operational
Segment Capacity Entitlements scheduled to meet Customer's MDQ,
for Customer's account, as requested on any day.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on
September 1, 1994 and shall continue in force and effect until
10/31/2012 and year to year thereafter unless this Service
Agreement is terminated as hereinafter provided. This Service
Agreement may be terminated by either Pipeline or Customer upon
five (5) years prior written notice to the other specifying a
termination date of any year occurring on or after the expiration
of the primary term. In addition to Pipeline rights under
Section 22 of Pipeline's General Terms and Conditions and without
prejudice to such rights, this Service Agreement may be
terminated at any time by Pipeline 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 (30) days after payment is
due; provided, Pipeline gives thirty (30) 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 Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED
CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY
CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE
NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION.
PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE
GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE
TERMINATION.
Any portions of this Service Agreement necessary to correct
or cash-out imbalances under this Service Agreement as required
by the General Terms and Conditions of Pipeline's FERC Gas
Tariff, Volume No. 1, shall survive the other parts of this
Service Agreement until such time as such balancing has been
accomplished.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule CDS and of
the General Terms and Conditions of Pipeline's FERC Gas Tariff on
file with the Federal Energy Regulatory Commission, all of which
are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered
hereunder and for the availability of such service in the period
stated, the applicable prices established under Pipeline's Rate
Schedule CDS as filed with the Federal Energy Regulatory
Commission, and as same may hereafter be legally amended or
superseded.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule CDS, (b) Pipeline's
Rate Schedule CDS pursuant to which service hereunder is rendered
or (c) any provision of the General Terms and Conditions
applicable to Rate Schedule CDS. Notwithstanding the foregoing,
Customer does not agree that Pipeline shall have the unilateral
right without the consent of Customer subsequent to the execution
of this Service Agreement and Pipeline shall not have the right
during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change
the MDQ specified in Article I, to change the term of the
agreement as specified in Article II, to change Point(s) of
Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character
of the service hereunder. Pipeline agrees that Customer may
protest or contest the aforementioned filings, and Customer does
not waive any rights it may have with respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The Point(s) of Receipt and Point(s) of Delivery at which
Pipeline shall receive and deliver gas, respectively, shall be
specified in Exhibit(s) A and B of the executed service
agreement. Customer's Zone Boundary Entry Quantity and Zone
Boundary Exit Quantity for each of Pipeline's zones shall be
specified in Exhibit C of the executed service agreement.
Exhibit(s) A and B are hereby incorporated as part of this
Service Agreement for all intents and purposes as if fully copied
and set forth herein at length.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform to the quality specifications set forth in
Section 5 of Pipeline's General Terms and Conditions. Customer
agrees that in the event Customer tenders for service hereunder
and Pipeline agrees to accept natural gas which does not comply
with Pipeline's quality specifications, as expressly provided for
in Section 5 of Pipeline's General Terms and Conditions, Customer
shall pay all costs associated with processing of such gas as
necessary to comply with such quality specifications. Customer
shall execute or cause its supplier to execute, if such supplier
has retained processing rights to the gas delivered to Customer,
the appropriate agreements prior to the commencement of service
for the transportation and processing of any liquefiable
hydrocarbons and any PVR quantities associated with the
processing of gas received by Pipeline at the Point(s) of Receipt
under such Customer's service agreement. In addition, subject to
the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered
for transportation hereunder.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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 regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: COLONIAL GAS COMPANY
P.O. Box 3064
40 Market Street
Lowell, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it
releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and
the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties are
subject to all present and future valid laws with respect to the
subject matter, State and Federal, and to all valid present and
future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
None
IN WITNESS WHEREOF, the parties hereto have caused this
Service Agreement to be signed by their respective Presidents,
Vice Presidents or other duly authorized agents and their respec-
tive corporate seals to be hereto affixed and attested by their
respective Secretaries or Assistant Secretaries, the day and year
first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By: John P. Harrington
Vice President - Gas Supply
ATTEST:
Timothy A. Clark
EXHBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED AUGUST 29, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND COLONIAL GAS COMPANY ("Customer"),
DATED AUGUST 29, 1994:
(1) Customer's firm Point(s) of Receipt:
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) (dth) Responsibilities Owner Operator
None
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published
by Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as
set forth in Section 6 of Pipeline's General Terms and Conditions at such
Point(s) of Receipt.
Transportation
Transportation Path Path Quantity (Dth/D)
M3 to M3 307
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT A DATED:__________
EXHBIT B, POINT(S) OF DELIVERY, DATED AUGUST 29, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED AUGUST 29, 1994:
Maximum
Daily
Point Delivery Delivery Measurement
of Obligation Pressure Responsi-
Delivery Description (dth) Obligation bilities Owner Operator
1. 70087 ALGONQUIN- 132 AS REQUESTED TX EAST TX EAST ALGONQUIN
LAMBERTVILLE BY CUSTOMER, TRAN TRAN
NJ HUNTERDON, NOT TO EXCEED
CO. CO., NJ 750 POUNDS PER
SQUARE GAUGE
2. 71078 ALGONQUIN- 175 AS REQUESTED TX EAST TX EAST ALGONQUIN
HANOVER, NH BY CUSTOMER TRAN TRAN
MORRIS CO. NOT TO EXCEED
CO., NJ 750 POUNDS PER
SQUARE GAUGE
3. 79821 AGT-COLONIAL 0 N/A N/A N/A N/A
FOR NOMINATION
PURPOSES
provided, however, that until changed by a subsequent Agreement between
Pipeline and Customer, Pipeline's aggregate maximum daily delivery
obligations under this and all other firm Service Agreements existing
between Pipeline and Customer, shall in no event exceed the following:
AGGREGATE MAXIMUM DAILY
POINT OF DELIVERY DELIVERY OBLIGATION (DTH)
No. 1 23,937
No. 2 9,739
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT B DATED:________________
[END OF EXHIBIT 10nn COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10oo TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Contract #: 400200
SERVICE AGREEMENT
FOR RATE SCHEDULE SS-1
This agreement, made and entered into this 30th day of
November, 1994, by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer," whether one
or more),
W I T N E S S E T H:
WHEREAS, there currently exists between Pipeline and
Customer five service agreements under Rate Schedule SS-1
(Pipeline's Contract Nos. 400142, 400143, 400144, 412006 and
400197) which specify an MDWQ of 1,115 dth and an MSQ of 131,686
dth, an MDWQ of 955 dth and an MSQ of 66,850 dth, an MDWQ of
4,381 and an MSQ of 262,860, an MDWQ of 74 and an MSQ of 5,180
and an MDWQ of 27 and an MSQ of 1,890 respectively; and
WHEREAS, Pipeline and Customer desire to enter into one
service agreement under Rate Schedule SS-1 which shall supersede
the five existing Rate Schedule SS-1 service agreements
referenced above; and
WHEREAS, withdrawal rights under the new Rate Schedule SS-1
service agreement are consistent with the existing rights of the
five existing Rate Schedule SS-1 service agreements it
supersedes;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof and
of Pipeline's Rate Schedule SS-1, Pipeline agrees to provide firm
service for Customer under Rate Schedule SS-1 and to receive and
store for Customer's account quantities of natural gas up to the
following quantity:
Maximum Daily Injection Quantity (MDIQ) 2,408 dth
Maximum Storage Quantity (MSQ) 468,466 dth
Pipeline agrees to withdraw from storage for Customer, at
Customer's request, quantities of gas up to Customer's Maximum
Daily Withdrawal Quantity (MDWQ) of 6,552 dekatherms, or such
lesser quantity as determined pursuant to Rate Schedule SS-1,
from Customer's Storage Inventory, plus Applicable Shrinkage, and
to deliver for Customer's account such quantities. Pipeline's
obligation to withdraw gas on any day is governed by the
provisions of Rate Schedule SS-1, including but not limited to
Section 6.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on
December 1, 1994 and shall continue in force and effect until
April 30, 2013 and year to year thereafter unless this Service
Agreement is terminated as hereinafter provided. This Service
Agreement may be terminated by either Pipeline or Customer upon
five (5) years prior written notice to the other specifying a
termination date of any year occurring on or after the
expiration of the primary term. Subject to Section 22 of
Pipeline's General Terms and Conditions and without prejudice to
such rights, this Service Agreement may be terminated at any time
by Pipeline 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 (30) days after payment is due; provided,
Pipeline gives thirty (30) 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 Pipeline of such
outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED
CONTRACT TERM OR THE PROVISION OF A TERMINATION NOTICE BY
CUSTOMER TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE
NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION.
PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE
GENERAL TERMS AND CONDITIONS ON THE EFFECTIVE DATE OF THE
TERMINATION.
In the event there is gas in storage for Customer's account
on April 30 of the year of termination of this Service Agreement,
this Service Agreement shall continue in force and effect for the
sole purpose of withdrawal and delivery of said gas to Customer
for an additional one-hundred and twenty (120) days.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule SS-1 and of
the General Terms and Conditions of Pipeline's FERC Gas Tariff on
file with the Federal Energy Regulatory Commission, all of which
are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered
hereunder and for the availability of such service in the period
stated, the applicable prices established under Pipeline's Rate
Schedule SS-1 as filed with the Federal Energy Regulatory
Commission and as the same may be hereafter revised or changed.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule SS-1, (b) Pipeline's
Rate Schedule SS-1, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and Conditions
applicable to Rate Schedule SS-1. Notwithstanding the foregoing,
Customer does not agree that Pipeline shall have the unilateral
right without the consent of Customer subsequent to the execution
of this Service Agreement and Pipeline shall not have the right
during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change
the MDIQ, MSQ and MDWQ specified in Article I, to change the
term of the service agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change
the Point(s) of Delivery specified in Article IV, or to change
the firm character of the service hereunder. Pipeline agrees
that Customer may protest or contest the aforementioned filings,
and Customer does not waive any rights it may have with respect
to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The natural gas received by Pipeline for Customer's account
for storage injection pursuant to this Service Agreement shall be
those quantities scheduled for delivery pursuant to Service
Agreements between Pipeline and Customer under Rate Schedules
CDS, FT-1, SCT, PTI or IT-1 which specify as a Point of Delivery
the "SS-1 Storage Point". For purposes of billing of Usage
Charges under Rate Schedules CDS, FT-1, SCT, PTI or IT-1,
deliveries under Rate Schedules CDS, FT-1, SCT, PTI or IT-1 for
injection into storage scheduled directly to the "SS-1 Storage
Point" shall be deemed to have been delivered 60% in Market Zone
2 and 40% in Market Zone 3. In addition, at Customer's request
any positive or negative variance between scheduled deliveries
and actual deliveries on any day at Customer's Points of
Delivery under Rate Schedules CDS, FT-1, SCT, or IT-1 shall be
deemed for billing purposes delivered at the Point of Delivery
and shall be injected into or withdrawn from storage for
Customer's account. In addition to accepting gas for storage
injection at the SS-1 Storage Point, Pipeline will accept gas
tendered at points of interconnection between Pipeline and third
party facilities at Oakford and Leidy Storage Fields provided
that such receipt does not result in Customer tendering aggregate
quantities for storage in excess of the Customer MDIQ.
The Point(s) of Delivery at which Pipeline shall deliver gas
shall be specified in Exhibit A of the executed service
agreement.
Exhibit A and B are hereby incorporated as part of this
Service Agreement for all intents and purposes as if fully copied
and set forth herein at length.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform and be subject to the provisions of Section 5 of
the General Terms and Conditions. Customer agrees that in the
event Customer tenders for service hereunder and Pipeline agrees
to accept natural gas which does not comply with Pipeline's
quality specifications, as expressly provided for in Section 5 of
Pipeline's General Terms and Conditions, Customer shall pay all
costs associated with processing of such gas as necessary to
comply with such quality specifications.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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 regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: Texas Eastern Transmission Corporation
5400 Westheimer Court
Houston, Texas 77056-5310
(b) Customer: COLONIAL GAS COMPANY
P O BOX 3064
40 MARKET STREET
LOWELL, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it
releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and
the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties
are subject to all present and future valid laws with respect to
the subject matter, State and Federal, and to all valid present
and future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
Service Agreements dated June 1, 1993, and
September 9, 1994 between Pipeline and Customer under Pipeline's
Rate Schedule SS-1 (Pipeline Contract Nos. 400142, 400143,
400144, 412006 and 400197).
IN WITNESS WHEREOF, the Parties hereto have caused this
Service Agreement to be signed by their respective Presidents,
Vice Presidents, or other duly authorized agents and their
respective corporate seals to be hereto affixed and attested by
their respective Secretaries or Assistant Secretaries, the day
and year first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By: John P. Harrington
Vice President - Gas Supply
ATTEST:
Susan E. Mousseau
EXHBIT A, POINT(S) OF DELIVERY, DATED NOVEMBER 30, 1994,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE SS-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED NOVEMBER 30, 1994:
Maximum
Daily
Point Delivery Delivery Measurement
of Obligation Pressure Responsi-
Delivery Description (dth) Obligation bilities Owner Operator
1. 70087 ALGONQUIN- 2,996 AS REQUESTED TX EAST TX EAST ALGONQUIN
LAMBERTVILLE BY CUSTOMER, TRAN TRAN
NJ HUNTERDON, NOT TO EXCEED
CO., NJ 750 PSIG
2. 71078 ALGONQUIN- 4,671 AS REQUESTED TX EAST TX EAST ALGONQUIN
HANOVER, NH BY CUSTOMER TRAN TRAN
MORRIS CO., NJ NOT TO EXCEED
750 PSIG
3. 79821 AGT-COLONIAL 0 N/A N/A N/A N/A
GAS-FOR
NOMINATION
PURPOSES
provided, however, that until changed by a subsequent Agreement between
Pipeline and Customer, Pipeline's aggregate maximum daily delivery
obligations at each of the Points of Delivery described above, including
Pipeline's maximum daily delivery obligation under this and all other firm
Service Agreements existing between Pipeline and Customer, shall in no event
exceed the following:
AGGREGATE MAXIMUM DAILY
POINT OF DELIVERY DELIVERY OBLIGATION (DTH)
No. 1 24,042
No. 2 9,854
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT A DATED:__________________
EXHIBIT B, WITHDRAWAL QUANTITIES, DATED NOVEMBER 30, 1994
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE SS-1
BETWEEN EASTERN TRANSMISSION CORPORATION ("PIPELINE")
AND COLONIAL GAS COMPANY ("CUSTOMER"), DATED NOVEMBER 30, 1994
Pipeline shall not be obligated to withdraw for Customer on any day
a total daily quantity in excess of the following:
(A) the MDWQ if Customer's Storage Inventory is equal to or less than
468,466 Dth, but more than 154,000 Dth;
(B) a daily entitlement of 5,822 Dth if Customer's Storage Inventory
is equal to or less than 154,000 Dth, but more than 112,100 Dth;
(C) a daily entitlement of 4,932 Dth if Customer's Storage Inventory is
equal to or less than 112,100 Dth, but more than 66,700 Dth;
(D) a daily entitlement of 1,443 Dth if Customer's Storage Inventory
is equal to or less than 66,700 Dth, but more than 29,600 Dth;
(E) a daily entitlement of 838 Dth if Customer's Storage Inventory
is equal to or less than 29,600 Dth.
If at any time during the period from November 16 through April 15 of each
contract year the aggregate storage inventory of all Customers under Rate
Schedule SS-1 equals or is less than 30% of the aggregate MSQ of all
Customers under Rate Schedule SS-1, then for the balance of the period
ending April 15 for such contract year injections into storage or
transfers of title of gas in storage inventory shall not be included in
Customer's Storage Inventory for purposes of determining Customer's daily
withdrawal rights pursuant to this Exhibit B. Pipeline shall notify
Customer verbally and then in writing when the aggregate storage
inventory of all Customers under Rate Schedule SS-1 and/or when Customer's
individual storage inventory equals or is less than 40% and 30% of the
aggregate MSQ or Customer's individual MSQ, respectively.
SIGNED FOR IDENTIFICATION
PIPELINE: Robert B. Evans
CUSTOMER: John P. Harrington
SUPERSEDES EXHIBIT B DATED:_____________
[END OF EXHIBIT 10oo TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10pp TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Contract #: 400519
SERVICE AGREEMENT
FOR RATE SCHEDULE FSS-1
This agreement, made and entered into this 30th day of
November, 1994, by and between TEXAS EASTERN TRANSMISSION
CORPORATION, a Delaware Corporation (herein called "Pipeline")
and COLONIAL GAS COMPANY (herein called "Customer," whether one
or more),
W I T N E S S E T H:
WHEREAS, there currently exists between Pipeline and
Customer two service agreements under Rate Schedule FSS-1
(Pipeline's Contract Nos. 400505 and 400518) which specify an
MDWQ of 307 dth and an MSQ of 18,420 dth and an MDWQ of 110 dth
and an MSQ of 6,600 dth respectively; and
WHEREAS, Pipeline and Customer desire to enter into one
service agreement under Rate Schedule FSS-1 which shall supersede
the two existing Rate Schedule FSS-1 service agreements
referenced above; and
WHEREAS, withdrawal rights under the new Rate Schedule FSS-1
service agreement are consistent with the existing rights of the
two existing Rate Schedule FSS-1 service agreements it
supersedes;
NOW, THEREFORE, in consideration of the premises and of the
mutual covenants and agreements herein contained, the parties do
covenant and agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof and
of Pipeline's Rate Schedule FSS-1, Pipeline agrees to provide
firm service for Customer under Rate Schedule FSS-1 and to
receive and store for Customer's account quantities of natural
gas up to the following quantity:
Maximum Daily Injection Quantity (MDIQ) 129 dth
Maximum Storage Quantity (MSQ) 25,020 dth
Pipeline agrees to withdraw from storage for Customer, at
Customer's request, quantities of gas up to Customer's Maximum
Daily Withdrawal Quantity (MDWQ) of 417 dekatherms, or such
lesser quantity as determined pursuant to Rate Schedule FSS-1,
from Customer's Storage Inventory, plus Applicable Shrinkage.
Pipeline's obligation to withdraw gas on any day is governed by
the provisions of Rate Schedule FSS-1, including but not
limited to Section 6.
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on
December 1, 1994 and shall continue in force and effect until
April 30, 2012 and year to year thereafter unless this Service
Agreement is terminated as hereinafter provided. This Service
Agreement may be terminated by either Pipeline or Customer upon
five (5) years prior written notice to the other specifying a
termination date of any year occurring on or after the
expiration of the primary term. Subject to Pipeline rights
under Section 22 of Pipeline's General Terms and Conditions and
without prejudice to such rights, this Service Agreement may be
terminated at any time by Pipeline 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 (30) days after payment is
due; provided, Pipeline gives thirty (30) 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 Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT
TERM OR THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER
TRIGGERS PREGRANTED ABANDONMENT UNDER SECTION 7 OF THE NATURAL
GAS ACT AS OF THE EFFECTIVE DATE OF THE TERMINATION. PROVISION
OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS CUSTOMER'S
RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS
AND CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
In the event there is gas in storage for Customer's account
on April 30 of the year of termination of this Service Agreement,
this Service Agreement shall continue in force and effect for the
sole purpose of withdrawal and delivery of said gas to Customer
for an additional one-hundred and twenty (120) days.
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain
subject to the applicable provisions of Rate Schedule FSS-1 and
of the General Terms and Conditions of Pipeline's FERC Gas Tariff
on file with the Federal Energy Regulatory Commission, all of
which are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered
hereunder and for the availability of such service in the period
stated, the applicable prices established under Pipeline's Rate
Schedule FSS-1 as filed with the Federal Energy Regulatory
Commission and as the same may be hereafter revised or changed.
Customer agrees that Pipeline 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 Pipeline's Rate Schedule FSS-1, (b)
Pipeline's Rate Schedule FSS-1, pursuant to which service
hereunder is rendered or (c) any provision of the General Terms
and Conditions applicable to Rate Schedule FSS-1.
Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of
Customer subsequent to the execution of this Service Agreement
and Pipeline shall not have the right during the effectiveness of
this Service Agreement to make any filings pursuant to Section 4
of the Natural Gas Act to change the MDIQ, MSQ and MDWQ specified
in Article I, to change the term of the service agreement as
specified in Article II, to change Point(s) of Receipt specified
in Article IV, to change the Point(s) of Delivery specified in
Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest
the aforementioned filings, and Customer does not waive any
rights it may have with respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The natural gas received by Pipeline for Customer's account
for storage injection pursuant to this Service Agreement shall be
those quantities scheduled for delivery pursuant to Service
Agreements between Pipeline and Customer under Rate Schedules
CDS, FT-1, SCT, PTI or IT-1 which specify as a Point of Delivery
the "FSS-1 Storage Point". For purposes of billing of Usage
Charges under Rate Schedules CDS, FT-1, SCT, PTI or IT-1,
deliveries under Rate Schedules CDS, FT-1, SCT, PTI or IT-1 for
injection into storage scheduled directly to the "FSS-1 Storage
Point" shall be deemed to have been delivered 60% in Market Zone
2 and 40% in Market Zone 3. In addition, subject to Pipeline's
prior written consent, any positive variance between scheduled
deliveries and actual deliveries on any day (i.e. scheduled
deliveries exceed actual deliveries) at Customer's Points of
Delivery under Rate Schedules CDS, FT-1, SCT, or IT-1 shall be
deemed for billing purposes delivered at the Point of Delivery
and shall be injected into storage for Customer's account. In
addition to accepting gas for storage injection at the FSS-1
Storage Point, Pipeline will accept gas tendered at points of
interconnection between Pipeline and third party facilities at
Oakford and Leidy Storage Fields provided that such receipt does
not result in Customer tendering aggregate quantities for storage
in excess of the Customer MDIQ.
The natural gas delivered by Pipeline for Customer's account
as a result of storage withdrawal pursuant to this Service
Agreement shall be those quantities scheduled for withdrawal
hereunder and subsequent transportation pursuant to service
agreements between Pipeline and Customer under Rate Schedule CDS,
FT-1, SCT, or IT-1 which specify as a Point of Receipt the "FSS-1
Storage Point". For purpose of billing under Rate Schedules CDS,
FT-1, SCT, or IT-1, withdrawals from storage for subsequent
transportation under Rate Schedules CDS, FT-1, SCT, or IT-1 shall
be deemed to have been received 60% in Market Zone 2 and 40% in
Market Zone 3. In addition to the withdrawal of gas from storage
for delivery through a transportation service on Pipeline's
system, gas may be withdrawn for delivery into the facilities of
third parties at the points of interconnection between Pipeline
and the facilities of such third parties at Oakford and Leidy
Storage Fields provided that such withdrawals do not result in
Customer withdrawing gas in excess of his MDWQ or MSQ. A
separate transportation charge will not be applicable to these
deliveries.
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account
shall conform and be subject to the provisions of Section 5 of
the General Terms and Conditions. Customer agrees that in the
event Customer tenders for service hereunder and Pipeline agrees
to accept natural gas which does not comply with Pipeline's
quality specifications, as expressly provided for in Section 5 of
Pipeline's General Terms and Conditions, Customer shall pay all
costs associated with processing of such gas as necessary to
comply with such quality specifications.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Pipeline's FERC Gas Tariff, any
notice, request, demand, statement, bill or payment provided for
in this Service 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 regular mail to the post office address of the parties hereto,
as the case may be, as follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: COLONIAL GAS COMPANY
P.O. Box 3064
40 Market Street
Lowell, MA 01853
or such other address as either party shall designate by formal
written notice.
ARTICLE VII
ASSIGNMENTS
Any Company which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
Customer, or of Pipeline, 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 Service Agreement; and either
Customer or Pipeline may assign or pledge this Service Agreement
under the provisions of any mortgage, deed of trust, indenture,
bank credit agreement, assignment, receivable sale, or similar
instrument which it has executed or may execute hereafter;
otherwise, neither Customer nor Pipeline shall assign this
Service Agreement or any of its rights hereunder unless it first
shall have obtained the consent thereto in writing of the other;
provided further, however, that neither Customer nor Pipeline
shall be released from its obligations hereunder without the
consent of the other. In addition, Customer may assign its
rights to capacity pursuant to Section 3.14 of the General Terms
and Conditions. To the extent Customer so desires, when it
releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and
the Replacement Customer, as further provided in the applicable
Capacity Release Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement
shall be in accordance with the laws of the State of Texas
without recourse to the law governing conflict of laws.
This Service Agreement and the obligations of the parties
are subject to all present and future valid laws with respect to
the subject matter, State and Federal, and to all valid present
and future orders, rules, and regulations of duly constituted
authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the
effective date of this Service Agreement, the contract(s) between
the parties hereto as described below:
Service Agreements dated, August 29, 1994 and September 9,
1994 between Pipeline and Customer under Pipeline's Rate Schedule
FSS-1 (Pipeline's Contract Nos. 400505 and 400518).
IN WITNESS WHEREOF, the Parties hereto have caused this
Service Agreement to be signed by their respective Presidents,
Vice Presidents, or other duly authorized agents and their
respective corporate seals to be hereto affixed and attested by
their respective Secretaries or Assistant Secretaries, the day
and year first above written.
TEXAS EASTERN TRANSMISSION CORPORATION
By: Robert B. Evans
Vice President
ATTEST:
Robert W. Reed
COLONIAL GAS COMPANY
By: John P. Harrington
Vice President - Gas Supply
ATTEST:
Susan E. Mousseau
[END OF EXHIBIT 10pp TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10qq TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
March 28, 1994
Gary A. Edinger
Senior Vice President-Gas Supply
New Jersey Natural Gas Company
1415 Wyckoff Road
P.O. Box 1464
Wall, NJ 07719
John P. Harrington
Vice President-Gas Supply
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
RE: Letter Agreement Regarding Transfer of
Transportation Entitlements
Gentlemen:
This letter agreement is entered into this
28th day of March, 1994, between Algonquin Gas
Transmission Company ("Algonquin"), New Jersey
Natural Gas Company ("NJN"), and Colonial Gas
Company ("Colonial"), (collectively "the Parties").
1. In consideration of the mutual promises
and considerations contained in the offer
of settlement filed in FERC Docket No.
RP93-14-000 et al. on March 1, 1994
(the "S&A"), and the mutual promises
and considerations set forth below,
the Parties agree to support prompt
FERC approval of the S&A without modification
or condition.
2. NJN agrees to release its entire right and
entitlement under Algonquin contract nos. 93009E
(6106 MMBtu/d, Rate Schedule AFT-E(F-1)) and
9W007E (1221 MMBtu/d, Rate Schedule AFT-E(WS-1)),
as well as the entirety of its entitlements and
obligations on Algonquin and Texas Eastern created
as a result of Article III, Sections 7 and 8 of
the S&A, for purposes of permanent reassignment
to Colonial. The release and permanent reassignment
of contract nos. 93009E and 9W007E shall be effective
November 1, 1994. The release of the Article III,
Sections 7 and 8 entitlements shall be effective on
the Effective Date of the S&A. These transfers of
entitlements shall be effected as prearranged
permanent releases for the remaining terms of the
agreements with no right of recall and with a
transfer to Colonial of all rights of first refusal
for the avoidance of pregranted abandonment pursuant
to Section 14 of the General Terms and Conditions of
Algonquin's tariff and Section 3.14 of the General
Terms and Conditions of the tariff of Texas Eastern
Transmission Corporation. These releases shall be
at the maximum applicable rate.
3. Colonial agrees to accept, as a permanent release at
the maximum applicable rate (AFT-E(F-1) and
AFT-E(WS-1)), assignment of the entitlements
listed in Section 2 above, with all of the rights
and obligations associated therewith.
4. Algonquin agrees to release NJN from its residual
liability under the agreements listed in Section 2
above for periods subsequent to the effective date
of the respective agreements without prejudice to
Algonquin's rights pertaining to periods prior to
the effectiveness of any release, including the
right to obtain payment of charges pertaining to
such period and without prejudice to NJN's rights
to receive refunds attributable to payments to
Algonquin for services rendered during such prior
periods. Algonquin further agrees to extend the
primary term of contract nos. 93009E and 9W007E
for Colonial to November 1, 2006 and November 16,
2006, respectively. Colonial understands its gate
stations are Secondary Points of Delivery under
the contract nos. 93009E and 9W007E. If, during
the term of these contracts, the FERC takes any
action that precludes Colonial from shipping
gas under these contracts to its gate stations
in a substantially equivalent manner as is currently
available to Shippers with Secondary Points of
Delivery, Colonial will have the option to terminate
these contracts upon 30 days prior written notice to
Algonquin. NJN shall not have any obligation to
reclaim any Algonquin or Texas Eastern entitlements
should Colonial exercise its option to terminate these
contracts.
5. The parties will execute such other documents and take
such further actions as are necessary to effect the
terms of this letter agreement.
Please indicate your consent to this agreement by
executing it in the space provided below.
Sincerely,
John J. Mullaney
Vice President, Marketing
Gary Edinger John Harrington
Senior Vice President-Gas Supply Vice President-Gas Supply
New Jersey Natural Gas Company Colonial Gas Company
[END OF EXHIBIT 10qq FOR COLONIAL GAS COMPANY]
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10rr TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
CAPACITY RELEASE UMBRELLA AGREEMENT UNDER
RATE SCHEDULES AFT-1 AND AFT-1S
(For Colonial Gas Company)
I.D. No.: 0152
Algonquin Addendum Contract No. 86009RI
Capacity Release Umbrella Agreement No.: COL
Addendum No. 01
Capacity Release
Rate Schedule AFT-1Z
Releasing Customer: New Jersey Natural Gas Company
Releasing Customer's Contract No.: 86009R1
Begin Date of Release: September 15, 1994
End Date of Release: April 30, 1999 (Permanent)
Maximum Daily Transportation Quantity 220 MMBtu
Maximum Annual Transportation Quantity 59,400 MMBtu
Is this capacity subject to right of recall? Yes___ No __X
Rates: Check all that apply:
Volumetric ________ Reservation Charge Maximum
Other (Describe) ________
Primary
Point of Maximum Daily Maximum
Receipt Receipt obligation Receipt Pressure
At any Pressure
requested by
Algonquin but
not in excess
of 750 Psig.
Primary
Point of Maximum Daily Minimum
Delivery Delivery Obligation Delivery
Pressure
Signed for Identification
Algonquin: John J. Mullaney
Customer: John P. Harrington
Vice President - Gas Supply
PCI/cl
addendum
[END OF EXHIBIT 10rr TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10ss TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Contract No. 9227
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
WHEREAS, Algonquin Gas Transmission Company ("Algonquin"),a
Delaware Corporation, and Colonial Gas
Company, ("Customer"), entered into a service agreement
dated August 1, 1993, under Algonquin's Rate Schedule AFT-
2;
WHEREAS, the Commission issued an order on July 8,
1994, approving a Stipulation and Agreement filed on
March 1, 1994, as supplemented on April 25, 1994, in
Docket Nos. RP93-14-000, et al. (the "S&A");
WHEREAS, Article III, Section 3 of the S&A provides that
a customer under Rate Schedule AFT-2 has the option
of converting such service to service under Rate Schedule
AFT-1;
WHEREAS, Article III, Section 3 of the S&A provides
that such conversion to Part 284 service shall not
affect the rate that the converting customer shall pay,
which shall be the rate the converting customer would
otherwise have paid as a result of the S&A, under its
prior service agreement;
WHEREAS, Customer provided Algonquin with written notice of
its intention to convert to Rate Schedule AFT-1;
NOW, THEREFORE, this Agreement ("Agreement") is made
and entered into this 1st day of November, 1994, by and
between Algonquin and Customer.
In consideration of the premises and of the mutual covenants
herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and
limitations hereof and of Algonquin's Rate
Schedule AFT-1, Algonquin agrees to receive from or
for the account of Customer for transportation on a
firm basis quantities of natural gas tendered by
Customer on any day at the Point(s) of Receipt;
provided, however, Customer shall not tender without
the prior consent of Algonquin, at any Point of
Receipt on any day a quantity of natural gas in
excess of the applicable Maximum Daily Receipt
Obligation for such Point of Receipt plus
the applicable Fuel Reimbursement Quantity; and
provided further that Customer shall not tender at
all Point(s) of Receipt on any day or in any year
a cumulative quantity of natural gas, without the
prior consent of Algonquin, in excess of the
following quantities of natural gas plus the
applicable Fuel Reimbursement Quantities:
Maximum Daily Transportation Quantity (MDTQ) 4,000 MMBtu
Maximum Annual Transportation Quantity (MATQ) 1,460,000 MMBtu
1.2 Algonquin agrees to transport and deliver to
or for the account of Customer at the Point(s) of
Delivery and Customer agrees to accept or cause
acceptance of delivery of the quantity received by
Algonquin on any day, less the Fuel Reimbursement
Quantities; provided, however, Algonquin shall not be
obligated to deliver at any Point of Delivery on any
day a quantity of natural gas in excess of the applicable
Maximum Daily Delivery Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective as of the
date set forth hereinabove and shall continue in effect
for a term ending on and including October 31, 2013
("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-1 as filed
with the Federal Energy Regulatory Commission and as
the same may be hereafter revised or changed. The rate
to be charged Customer for transportation hereunder
shall not be more than the maximum rate specified under
Rate Schedule AFT-1 for service resulting from the
conversion of entitlements under former Rate Schedule
AFT-2, nor less than the minimum rate under Rate
Schedule AFT-1.
3.2 This Agreement and all terms and provisions
contained or incorporated herein are subject to the
provisions of Algonquin's applicable rate schedules and
of Algonquin's General Terms and Conditions on file
with the Federal Energy Regulatory Commission, or other
duly constituted authorities having jurisdiction, and
as the same may be legally amended or superseded, which
rate schedules and General Terms and Conditions are by
this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the
unilateral right to file with the appropriate
regulatory authority and make changes effective in (a)
the rates and charges applicable to service pursuant to
Algonquin's Rate Schedule AFT-1, (b) Algonquin's Rate
Schedule AFT-1, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and
Conditions applicable to Rate Schedule AFT-1.
Algonquin agrees that Customer may protest or contest
the aforementioned filings, or may seek authorization
from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as
may be found necessary to assure that the provisions in
(a), (b), or (c) above are just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of
Customer hereunder shall be received at the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt
pressure obligation indicated for each such Primary Point of
Receipt. Natural gas to be received by Algonquin for the
account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.2 of Rate
Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of
Customer hereunder shall be delivered on the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery
pressure obligation indicated for each such Primary Point of
Delivery. Natural gas to be delivered by Algonquin for the
account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.4 of Rate
Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Algonquin's FERC Gas Tariff,
any notice, request, demand, statement, bill or payment
provided for in this Agreement, or any notice which any
party may desire to give to the other, shall be in writing
and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post
office address of the parties hereto, as the case may be, as
follows:
(a) Algonquin: 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
P. O. Box 3064
Lowell, MA 01853
Attn: John P. Harrington
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.
Service Agreement No. 9227 executed by Customer and
Algonquin under Rate Schedule AFT-2 dated August 1, 1993.
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: John J. Mullaney/RSH
Title: Vice President, Marketing
COLONIAL GAS COMPANY
By: John P. Harrington
Title: Vice President - Gas Supply
KFG/cl
Exhibit A
Point(s) of Receipt
Dated: November 1, 1994
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer) concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Mendon, MA 4,000 At any pressure
requested by
Algonquin but
not in excess of
750 Psig.
Signed for Identification
Algonquin: John P. Mullaney/RSH
Customer: John P. Harrington
Exhibit B
Point(s) of Delivery
Dated: November 1, 1994
To the service agreement under Rate Schedule AFT-1 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)
Sagamore, MA 4,000 200
Bourne, MA 4,000 200
Algonquin's Maximum Daily Delivery Obligation for the
Sagamore and Bourne delivery points under this Agreement for
service under Rate Schedule AFT-1 shall not exceed a combined
daily total of 4,000 MMBtu.
Signed for Identification
Algonquin: John J. Mullaney/RSH
Customer: John P. Harrington
KFG/cl
[END OF EXHIBIT 10ss TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10tt TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Contract No. 933003
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
WHEREAS, Algonquin Gas Transmission Company
("Algonquin"), a Delaware Corporation, and
Colonial Gas Company, ("Customer"), entered into a
service agreement dated August 1, 1993, under
Algonquin's Rate Schedule PSS-T;
WHEREAS, the Commission issued an order on July 8,
1994, approving a Stipulation and Agreement filed on
March 1, 1994, as supplemented on April 25, 1994, in
Docket Nos. RP93-14-000, et al. (the "S&A");
WHEREAS, Article III, Section 3 of the S&A provides that
a customer under Rate Schedule PSS-T has the
option of converting such service to service under Rate
Schedule AFT-1;
WHEREAS, Article III, Section 3 of the S&A provides
that such conversion to Part 284 service shall not
affect the rate that the converting customer shall pay,
which shall be the rate the converting customer would
otherwise have paid as a result of the S&A, under its
prior service agreement;
WHEREAS, Customer provided Algonquin with written notice of
its intention to convert to Rate Schedule AFT-1;
NOW, THEREFORE, this Agreement ("Agreement") is made
and entered into this 1st day of November, 1994, by and
between Algonquin and Customer.
In consideration of the premises and of the mutual covenants
herein contained, the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and
limitations hereof and of Algonquin's Rate
Schedule AFT-1, Algonquin agrees to receive from
or for the account of Customer for transportation
on a firm basis quantities of natural gas tendered
by Customer on any day at the Point(s) of Receipt;
provided, however, Customer shall not tender
without the prior consent of Algonquin, at any
Point of Receipt on any day a quantity of natural
gas in excess of the applicable Maximum Daily
Receipt Obligation for such Point of Receipt
plus the applicable Fuel Reimbursement Quantity;
and provided further that Customer shall not tender
at all Point(s) of Receipt on any day or in any
year a cumulative quantity of natural gas,
without the prior consent of Algonquin, in excess
of the following quantities of natural gas plus
the applicable Fuel Reimbursement Quantities:
Maximum Daily Transportation Quantity (MDTQ) 2,222 MMBtu
Maximum Annual Transportation Quantity (MATQ) 811,030 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 March 31, 2012
("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-1 as filed
with the Federal Energy Regulatory Commission and as
the same may be hereafter revised or changed. The rate
to be charged Customer for transportation hereunder
shall not be more than the maximum rate specified under
Rate Schedule AFT-1 for service resulting from the
conversion of entitlements under former Rate Schedule
PSS-T, nor less than the minimum rate under Rate
Schedule AFT-1.
3.2 This Agreement and all terms and provisions
contained or incorporated herein are subject to the
provisions of Algonquin's applicable rate schedules and
of Algonquin's General Terms and Conditions on file
with the Federal Energy Regulatory Commission, or other
duly constituted authorities having jurisdiction, and
as the same may be legally amended or superseded, which
rate schedules and General Terms and Conditions are by
this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the
unilateral right to file with the appropriate
regulatory authority and make changes effective in (a)
the rates and charges applicable to service pursuant to
Algonquin's Rate Schedule AFT-1, (b) Algonquin's Rate
Schedule AFT-1, pursuant to which service hereunder is
rendered or (c) any provision of the General Terms and
Conditions applicable to Rate Schedule AFT-1.
Algonquin agrees that Customer may protest or contest
the aforementioned filings, or may seek authorization
from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as
may be found necessary to assure that the provisions in
(a), (b), or (c) above are just and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of
Customer hereunder shall be received at the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt
pressure obligation indicated for each such Primary Point of
Receipt. Natural gas to be received by Algonquin for the
account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.2 of Rate
Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of
Customer hereunder shall be delivered on the outlet side of
the measuring station(s) at or near the Primary Point(s) of
Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery
pressure obligation indicated for each such Primary Point of
Delivery. Natural gas to be delivered by Algonquin for the
account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin
system, subject to reduction pursuant to Section 6.4 of Rate
Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the
General Terms and Conditions of Algonquin's FERC Gas Tariff,
any notice, request, demand, statement, bill or payment
provided for in this Agreement, or any notice which any
party may desire to give to the other, shall be in writing
and shall be considered as duly delivered when mailed by
registered, certified, or first class mail to the post
office address of the parties hereto, as the case may be, as
follows:
(a) Algonquin: 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
P. O. Box 3064
Lowell, MA 01853
Attn: John P. Harrington
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.
Service Agreement No. 933003 executed by Customer and
Algonquin under Rate Schedule PSS-T dated August 1, 1993.
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: John J. Mullaney/RSH
Title: Vice President, Marketing
COLONIAL GAS COMPANY
By: John P. Harrington
Title: Vice President - Gas Supply
KFG/cl
Exhibit A
Point(s) of Receipt
Dated: November 1, 1994
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Colonial Gas Company (Customer) concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
Lambertville, NJ 2,222 At any pressure
requested by
Algonquin but not in
excess of 750 Psig.
Signed for Identification
Algonquin: John P. Mullaney/RSH
Customer: John P. Harrington
Exhibit B
Point(s) of Delivery
Dated: November 1, 1994
To the service agreement under Rate Schedule AFT-1 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)
Bourne, MA 766 200
Sagamore, MA 1,456 200
Signed for Identification
Algonquin: John J. Mullaney/RSH
Customer: John P. Harrington
KFG/cl
[END OF EXHIBIT 10tt TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 10xx TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
Page: 1
Date: 01/01/95
COLONIAL GAS COMPANY
POLICY AND PROCEDURE
(90-085.700) ALL DIVISIONS
RATE INCREASE DEFERRAL INCENTIVE POLICY
PURPOSE
The purpose of this policy is to establish an incentive
compensation program to reward individuals who have direct
control over budgetary expenditures for each year that Colonial
is able to defer a rate increase.
SCOPE
This policy applies to regular, full-time management personnel
who hold the position of President, Corporate Vice President,
Divisional Vice President, Director or Manager who have budgetary
responsibility. This policy also applies to individuals who have
budgetary control and similar responsibilities as the positions
mentioned above but who may not have the specific title.
POLICY
The Company will pay a bonus to the individuals who are eligible
for this program in accordance with the guidelines listed below
for each year that Colonial does not file for a rate increase.
Bonuses will not be paid until the decision has been made for the
applicable fiscal year.
Guidelines for administration of this policy:
To be eligible to be considered as a participant in a category,
an individual must have been in their position for a minimum of
eight (8) months during the previous calendar year.
Anyone who has been in his/her current position for less than
eight (8) months, will be slotted in the previous bonus category.
In the event that this change results in a job category that is
not part of this program, the individual will not be eligible for
consideration during the current year.
To be eligible to receive a bonus, the individual must have received
a performance rating of at least competent (3) in his/her current
position. In the event that an individual had changed his/her
position during the previous year, has been in his/her current
position for less than eight (8)
__X__ New Superseded Page(s) to be Destroyed
_____ Revised F.L. Putnam, III
Title: President
months and for purposes of this policy has been slotted in
his/her previous category, if applicable, and it is determined
that he/she would have received at least a competent rating had
he/she not changed positions, then that individual will also be
eligible to receive a bonus.
Bonus Amounts:
Year Rate
Increase Year 5
Category Requested Year 1 Year 2 Year 3 Year 4 and on
President and $0 $0 $3,000 $5,000 $7,500 $10,000
Corporate V.P.s
Directors and $0 $0 $2,000 $3,000 $5,000 $7,500
Divisional V.P.s
Managers $0 $0 $1,000 $2,000 $3,000 $5,000
PROCEDURES
Each year a committee consisting of the President and corporate
officers from the Human Resources, Operations, Finance, and Gas
Supply Departments will meet to review the criteria and eligible
participants under this Policy.
Once a definitive decision has been made that Colonial will not be
filing for a rate increase during the applicable calendar year, a
request will be sent to payroll to issue checks in accordance with
the bonus schedule listed above for those who meet the guidelines
established in this Policy. These bonuses will be paid under the
earnings code RDI.
__X__ New Superseded Page(s) to be Destroyed
_____ Revised F.L. Putnam, III
Title: President
This Policy may be modified or rescinded at the discretion of management.
__X__ New Superseded Page(s) to be Destroyed
_____ Revised F.L. Putnam, III
Title: President
[END OF EXHIBIT 10xx TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 13a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1994]
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Share Amounts) Year Ended December 31,
1994 1993 1992
Operating Revenues $166,259 $166,261 $145,054
Cost of gas sold 87,458 90,915 75,143
Operating Margin 78,801 75,346 69,911
Operating Expenses:
Operations 32,823 32,748 31,481
Maintenance 5,996 5,631 5,477
Depreciation and amortization 9,235 6,831 5,914
Local property taxes 2,740 2,496 2,059
Other taxes 1,441 1,359 1,300
Restructuring charge 3,185 - -
Total Operating Expenses 55,420 49,065 46,231
Income Taxes:
Federal income tax 4,806 6,111 5,390
State franchise tax 1,058 1,280 1,139
Total Income Taxes 5,864 7,391 6,529
Utility Operating Income 17,517 18,890 17,151
Other Operating Income (Expense):
Truck transportation revenues 12,066 7,558 9,799
Truck transportation expenses, including
income taxes and interest (10,579) (7,163) (9,622)
Truck Transportation Net Income 1,487 395 177
Other, net of income taxes (151) (186) (141)
Total Other Operating Income 1,336 209 36
Non-Operating Income, Net of 565 1,064 922
Income Taxes
Income Before Interest and Debt 19,418 20,163 18,109
Expenses
Interest and Debt Expense 8,409 8,141 7,466
Net Income $11,009 $12,022 $10,643
Average Common Shares Outstanding 8,119 7,931 7,728
Income per Average Common Share $1.36 $1.52 $1.38
Dividends Paid per Common Share $1.255 $1.235 $1.213
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF INCOME]
CONSOLIDATED BALANCE SHEETS
Assets December 31,
(In Thousands) 1994 1993
Utility Property:
At original cost $287,158 $260,570
Accumulated depreciation (65,473) (57,857)
Net Utility Property 221,685 202,713
Non-Utility Property - Net 3,479 3,235
Net Property 225,164 205,948
Capital Leases - Net 2,948 3,914
Current Assets:
Cash and cash equivalents 9,026 5,482
Accounts receivable 13,846 16,156
Allowance for doubtful accounts (1,670) (1,682)
Accrued utility revenues 6,148 7,170
Unbilled gas costs 12,178 16,759
Fuel inventory - at average cost 12,959 13,717
Materials and supplies-at average cost 3,537 3,812
Prepayments and other current assets 9,544 6,254
Total Current Assets 65,568 67,668
Deferred Charges and Other Assets:
Unrecovered deferred income taxes 11,471 12,689
Unrecovered environmental costs incurred4,577 4,062
Unrecovered environmental costs accrued 3,800 5,300
Unrecovered transition costs accrued 4,700 2,000
Unrecovered pension costs 2,607 3,215
Excess cost of investments over net
assets acquired 2,798 2,798
Other 7,715 4,524
Total Deferred Charges and
Other Assets 37,668 34,588
Total Assets $331,348 $312,118
CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31,
(In Thousands) 1994 1993
Capitalization:
Common Equity:
Common Stock $27,397 $26,739
Premium on Common Stock 49,211 45,799
Retained earnings 22,567 21,745
Total Common Equity 99,175 94,283
Long-Term Debt 77,923 87,432
Total Capitalization 177,098 181,715
Capital Lease Obligations 2,237 3,149
Current Liabilities:
Current maturities of long-term debt 8,449 3,318
Current capital lease obligations 712 765
Notes payable 49,500 32,600
Gas inventory purchase obligations 13,860 15,233
Accounts payable 9,635 12,161
Accrued interest 1,085 1,017
Pipeline refunds due customers 2,289 2,076
Accrued pipeline charges - 305
Current deferred income taxes 2,139 2,212
Other current liabilities 3,713 3,726
Total Current Liabilities 91,382 73,413
Deferred Credits and Reserves:
Deferred income taxes - Funded 29,373 23,395
Deferred income taxes - Unfunded 11,471 12,689
Deferred income taxes - Due customers 378 1,238
Accrued environmental costs 3,800 5,300
Accrued transition costs 4,700 2,000
Unamortized investment tax credits 4,215 4,449
Pension reserve 2,973 3,586
Other deferred credits and reserves 3,721 1,184
Total Deferred Credits and
Reserves 60,631 53,841
Total Capitalization and Liabilities $331,348 $312,118
[END OF CONSOLIDATED BALANCE SHEETS]
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
(In Thousands) 1994 1993 1992
Cash Flows From Operating Activities:
Net Income $11,009 $12,022 $10,643
Adjustments to reconcile net income to net cash:
Depreciation and amortization 10,150 7,703 6,995
Deferred income taxes 3,555 2,139 6,264
Amortization of investment tax
credits (234) (255) (259)
Provision for uncollectible accounts 1,803 2,102 1,697
Other, net 811 190 832
27,094 23,901 26,172
Changes in current assets and liabilities:
Accounts receivable 495 773 (5,133)
Accrued utility revenues 1,022 (1,678) 1,366
Unbilled gas costs 4,581 2,122 (9,183)
Fuel inventory 758 (285) (1,664)
Materials and supplies 275 56 (199)
Prepayments and other current assets (3,290) 2,055 (3,027)
Accounts payable (2,526) (382) 35
Accrued interest 68 (7) (135)
Pipeline refunds due customers 213 620 (20)
Accrued pipeline charges (305) (606) (2,189)
Current deferred income taxes (73) (2,111) 4,323
Other current liabilities (13) 933 (39)
Net Cash Provided by Operating
Activities 28,299 25,391 10,307
Cash Flows From Investing Activities:
Utility capital expenditures (28,195)(25,703)(26,948)
Non-utility capital expenditures (876) (453) (218)
Sale of non-utility assets - 586 -
Change in deferred accounts (716) (354) (4,781)
Net Cash Used in Investing
Activities (29,787)(25,924)(31,947)
Cash Flows From Financing Activities:
Dividends paid on Common Stock (10,187) (9,793) (9,379)
Issuance of Common Stock 4,070 4,283 4,286
Issuance of long-term debt 741 - 45,000
Retirement of long-term debt (5,119) (1,500)(15,634)
Change in notes payable 16,900 8,100 (3,500)
Change in gas inventory purchase
obligations (1,373) 492 3,015
Net Cash Provided by Financing
Activities 5,032 1,582 23,788
Net Increase in Cash and Cash
Equivalents 3,544 1,049 2,148
Cash and Cash Equivalents at
Beginning of Year 5,482 4,433 2,285
Cash and Cash Equivalents at
End of Year $9,026 $ 5,482 $4,433
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest - net of amount capitalized $ 9,283 $8,891 $ 8,390
Income and state franchise taxes $ 7,282 $4,939 $ 3,639
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENT OF CASH FLOWS]
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31,
(In Thousands Except Per Share Amounts) 1994 1993 1992
Common Stock
$3.33 par value; authorized 15,000 shares;
outstanding, 8,227 in 1994, 8,030 in 1993,
and 7,844 in 1992
Beginning of year $26,739 $26,122 $25,391
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan (197 shares
in 1994, 186 shares in 1993 and 219
shares in 1992) 658 617 731
End of year $27,397 $26,739 $26,122
Premium on Common Stock
Beginning of year $45,799 $42,133 $38,578
Issuance of Common Stock through
Dividend Reinvestment and Common
Stock Purchase Plan and
Employee savings plan 3,412 3,666 3,555
End of year $49,211 $45,799 $42,133
Retained Earnings
Beginning of year $21,745 $19,516 $18,252
Net income 11,009 12,022 10,643
Cash dividends on Common Stock
($1.255 a share in 1994, $1.235
a share in 1993 and $1.213 a share
in 1992) (10,187) (9,793) (9,379)
End of year $22,567 $21,745 $19,516
Total Common Equity $99,175 $94,283 $87,771
The accompanying notes are an integral part of these statements.
[END OF CONSOLIDATED STATEMENTS OF COMMON EQUITY]
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A: Summary of Significant Accounting Policies
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.
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 $294,000,
$227,000 and $181,000 in 1994, 1993 and 1992, 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 was approximately 2.91% through October 31,
1993, which was increased to approximately 3.77% effective with a
rate increase as approved by the DPU on November 1, 1993. The
composite depreciation rate is applied to the utility property
balance at the beginning of each year. Depreciation on non-utility
property is computed by various methods.
Operating Revenues - Operating revenues are accrued based upon the
amount of gas delivered to utility customers through the end of
the accounting period. Accrued utility revenues of $6,148,000 and
$7,170,000, as reported in the Consolidated Balance Sheets at
December 31, 1994 and 1993, 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
programs as revenue when earned by the Company and approved by the
DPU. No lost margins or incentives have been recorded to date.
Unbilled Gas Costs - The Company charges or credits its utility
customers for increases or decreases in gas costs from those
reflected in its base tariffs by applying a cost of gas adjustment
clause (CGAC). In accordance with the CGAC, any under or over
recoveries of gas costs are charged or credited to the unbilled
gas cost account and recorded as a current asset or liability.
Such under or over recoveries are collected or refunded, with
interest accrued at the prime rate, in subsequent periods.
Pipeline Refunds Due Customers - The Company periodically receives
refunds from interstate pipeline companies related to rate
adjustments ordered by the Federal Energy Regulatory Commission
(FERC). All of the refunds are returned to utility customers under
methods approved by the DPU.
Excess Cost of Investments over Net Assets Acquired - This asset
arose principally from the pre-1971 acquisitions of utility
operations. No amortization has been provided since, in the
opinion of management, there has been no diminution in value of
the applicable investments.
Income Taxes - The Company records deferred income taxes for the
income tax effect of the difference between book and tax
depreciation and all other temporary book and tax differences, in
accordance with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" (SFAS 109). Unamortized
investment tax credits, which were allowed under Federal income
tax laws prior to 1987, have been deferred and are being amortized
as a credit to income tax expense over the estimated service lives
of the corresponding assets.
Interest and Debt Expense - Interest and debt expense includes
interest on long-term debt, interest on short-term notes payable
and regulatory interest. As approved by the DPU, regulatory
interest is interest income credited on regulatory assets or
interest expense charged on regulatory liabilities.
Pension Plans - The Company and its subsidiaries have defined
benefit pension plans covering substantially all employees. These
include two qualified union plans, one qualified plan for non-
union employees, and various unqualified individual retirement
agreements covering certain key employees and retirees. The
Company's funding policy is to contribute annually an amount at
least equal to the normal cost plus a 30-year amortization of the
unfunded actuarially calculated accrued liability and additional
contributions to fund the unqualified individual retirement
agreements.
Cash and Cash Equivalents - For the purposes of the Consolidated
Balance Sheets and Statements of Cash Flows, the Company considers
cash investments with an original maturity of three months or less
to be cash equivalents.
Fair Value of Financial Instruments - In accordance with Statement
of Financial Accounting Standards No. 107 "Disclosures About Fair
Values of Financial Instruments", the fair value amounts are
disclosed below. These fair value amounts are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.
The carrying amount of cash and cash equivalents and short-
term debt approximates fair value.
The fair value of long-term debt is estimated based on the
rates available to the Company at the end of each respective year
for debt of the same remaining maturities. The carrying amount of
long-term debt (including current maturities) was $86,372,000 and
$90,750,000 as of December 31, 1994 and 1993, respectively. The
fair value of long-term debt was $88,425,000 and $104,562,000 as of
December 31, 1994 and 1993, respectively.
Under current regulatory treatment, any premiums paid to
refinance long-term debt, would be recovered over the life of the
new debt, and would not have a significant impact on the Company's
results of operations.
Reclassifications - Reclassifications are made periodically to
previously issued financial statements to conform to the current
year presentation.
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, 1994, the Company
has a liability of $11,471,000 on the Consolidated Balance Sheet
as Deferred Income Taxes - Unfunded and a corresponding
unrecovered deferred asset. The liability represents the tax
effect of pre-1981 timing differences for which deferred income
taxes had not been provided, increased in accordance with SFAS 109
for the tax effect of future revenue requirements. The Company is
recovering these unfunded deferred taxes from utility customers
over the remaining book life of utility property.
The Company has a liability (Deferred Income Taxes- Due
Customers) of $378,000 at December 31, 1994, representing the
amount of pre-July 1, 1987 deferred income taxes that were
recorded in excess of the Federal statutory income tax rate of
34%. This liability is being returned to utility customers over
the remaining book life of utility property. This liability is
also charged for any Federal income taxes at rates above 34%.
Federal income tax expense is comprised of the following
components:
Year Ended December 31,
(In Thousands) 1994 1993 1992
Charged (credited) to operations:
Current $2,157 $5,191 $(362)
Deferred:
Unbilled gas costs (106) (1,753) 3,590
Accelerated depreciation 2,167 2,157 2,092
Cost of removal 173 190 149
Demand side management costs 1,115 - -
Early retirement pension costs (830) - -
Environmental response costs 137 (33) (223)
Pension (10) 141 131
Recovery of unfunded deferred
taxes 398 556 578
Miscellaneous (165) (93) (316)
Amortization of investment tax
credits (230) (245) (249)
Total 4,806 6,111 5,390
Charged to other income 1,014 578 486
Total Federal income tax
expense $5,820 $6,689 $5,876
The effective Federal income tax rate and the reasons for the
difference from the statutory Federal income tax rate are as
follows:
1994 1993 1992
Statutory Federal income tax rate 35% 35% 34%
Increases (reductions) in taxes resulting from:
Amortization of investment tax credits (1) (1) (2)
Recovery of unfunded deferred taxes 2 3 4
Miscellaneous items (1) (1) -
Effective Federal income tax rate 35% 36% 36%
Temporary differences which gave rise to the following deferred
tax assets (liabilities) are:
December 31,
(In Thousands) 1994 1993
Construction contributions $1,117 $ 1,176
Early retirement pension costs 995 -
Other 943 940
Total deferred tax assets 3,055 2,116
Accelerated depreciation (34,698) (32,333)
Cost of removal (2,364) (2,105)
Unbilled gas costs (2,139) (2,212)
Environmental response costs (1,839) (1,634)
Transition costs (1,045) -
Demand side management costs (1,803) -
Pension (915) -
Other (1,235) (2,128)
Total deferred tax
liabilities (46,038) (40,412)
Total deferred taxes $(42,983) $(38,296)
Note C: Capital Stock
As a result of the 3 for 2 stock split effective July 29, 1992,
the par value of the Company's Common Stock changed from $5.00 per
share to $3.33 per share. Also during 1992, the number of
authorized shares was increased from 8,000,000 to 15,000,000.
Pursuant to the Company's dividend reinvestment and common stock
purchase plan, stockholders 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.
The Company has a Shareholder Rights Plan pursuant to which one
share purchase right (a "Right") for each outstanding share of the
Company's Common Stock was issued to stockholders of record on
December 1, 1993. Each Right entitles the holder 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 exercise of the
Rights is subject to obtaining DPU approval. The description and
terms of the Rights are set forth in a Rights Agreement between
the Company and The First National Bank of Boston. The Rights
attach to each outstanding share issued and to be issued and
expire on December 1, 2003. The Rights do not carry voting or
dividend rights, have no dilutive effect and do not impact the
earnings of the Company.
The Rights only become exercisable, or separately transferable,
10 days after a person or group acquires, or announces an
intention to acquire, beneficial ownership of 20% or more of the
Company's Common Stock. The Rights are redeemable by the Board at
a price of $.01 per Right at any time prior to the expiration of
ten days after the acquisition by a person or group of beneficial
ownership of 20% or more of the Company's Common Stock.
Note D: Retained Earnings
The Company's ability to pay dividends on its Common Stock from
retained earnings is restricted by the first mortgage bond
indenture and by the bank line of credit. Under the most
restrictive covenant, approximately $19,027,000 of retained
earnings was available to pay dividends on Common Stock as of
December 31, 1994.
Note E: Long-Term Debt
The composition of long-term debt is as follows:
December 31,
(In Thousands) 1994 1993
First mortgage bonds:
14.00% Series CC due 1999 $ 500 $ 2,750
8.86% Series CD due 2001 7,000 8,000
9.40% Series CE due 1997 15,000 15,000
10.25% Series CF due 2004 18,182 20,000
8.05% Series CG due 1999 20,000 20,000
8.80% Series CH due 2022 25,000 25,000
Total 85,682 90,750
Note payable 690 -
Less: Long-term debt due within one
year (8,449) (3,318)
Total long-term debt $77,923 $87,432
The aggregate amount of maturities and sinking fund requirements
for the years 1995, 1996, 1997, 1998, and 1999 are $8,449,000,
$7,959,000, $7,970,000, $2,982,000, and $22,920,000, respectively.
The first mortgage bonds are collateralized by utility property.
The Company's first mortgage bond indenture includes, among other
provisions, limitations on the issuance of long-term debt, leases
and the payment of dividends from retained earnings. The note
payable is collateralized by equipment.
Note F: Short-Term Debt
In July 1994, the Company established a three-year bank line of
credit of $75,000,000 with a consortium of four banks. The bank
line of credit allows the Company to borrow on a demand basis up
to $75,000,000, 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, 1994, the credit available under the bank line of credit was
$11,640,000. The weighted average interest rates for short-term
debt were 6.25% and 3.59% at December 31, 1994 and 1993,
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
$30,000,000 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 1994, 1993 and
1992 approximately $504,000, $390,000 and $433,000, respectively,
of financing costs were incurred by the trust.
Note G: Lease Obligations
The Company leases certain facilities and equipment used in its
operations. In accordance with accounting for regulated public
utilities, the Company has capitalized certain of these leases and
reflects lease payments as rental expense in the periods to which
they relate. This capitalization has no impact on the Company's
net income.
Assets held under capital leases amounted to approximately
$7,230,000 and $7,475,000 at December 31, 1994 and 1993,
respectively. Accumulated amortization on assets held under
capital leases amounted to approximately $4,282,000 and $3,561,000
at December 31, 1994 and 1993, 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 1994, 1993 and 1992
approximated $2,049,000, $1,808,000 and $1,984,000, respectively.
At December 31, 1994, the future minimum payments (including
interest) under the Company's lease agreements are: $937,000 in
1995; $754,000 in 1996; $612,000 in 1997; $381,000 in 1998;
$255,000 in 1999; and $609,000 thereafter.
Note H: Employee Benefit Plans
Savings Plan - The Company sponsors an employee 401(k) Savings
Plan. The Company's matching contribution, exclusive of plan
administration costs, was $387,000, $418,000 and $316,000 for
1994, 1993 and 1992, 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) 1994 1993 1992
Benefits earned during the
period $1,195 $1,031 $958
Interest cost on projected
benefit obligation 2,803 2,690 2,500
Actual return on plan assets 77 (2,656) (469)
Net amortization and deferral (2,657) 325 (1,760)
Net periodic pension cost $1,418 $1,390 $1,229
Assumptions used in actuarial calculations were as follows:
Year Ended December 31,
1994 1993 1992
Weighted average discount rate 8.50% 7.25% 8.00%
Future compensation increases 5.00% 5.00% 5.50%
Expected long-term rate of
return on assets 9.00% 9.00% 9.00%
The funded status of the plans at December 31, 1994 and 1993 is as
follows:
1994 1993
Assets Accumu- Assets Accumu-
Exceed lated Exceed lated
Accumu- Benefits Accumu- Benefits
lated Exceed lated Exceed
Benefits Assets Benefits Assets
(In Thousands)
Projected benefit
obligations:
Vested $(21,897) $(8,544) $(23,689) $(9,208)
Nonvested (2,988) (563) (562) (356)
Accumulated (24,885) (9,107) (24,251) (9,564)
Due to recognition of
future (4,664) (42) (5,665) (6)
salary increases
Total (29,549) (9,149) (29,916) (9,570)
Plan assets at fair 27,715 5,259 28,250 5,186
value
Projected benefit
obligation
(in excess of) (1,834) (3,890) (1,666) (4,384)
less than
plan assets
Unrecognized net loss (227) 513 1,695 909
(gain)
Unrecognized 2,059 1,430 2,265 1,612
transition amount
Unrecognized prior 448 706 553 700
service cost
Additional liability - (2,607) - (3,215)
accrued
Prepaid (accrued) $446 $(3,848) $2,847 $(4,378)
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 and other short-
term debt instruments.
Additional benefits upon retirement were given to 47 employees who
accepted the voluntary early retirement program in 1994. The
additional loss of $2,537,000 as a result of this program was
recorded as a restructuring charge in the fourth quarter of 1994.
Postretirement Life and Health Benefit Plan - The Company sponsors
a postretirement benefit plan that covers substantially all
employees. The plan provides medical, dental and life insurance
benefits. The plan is contributory for retirees, with respect to
postretirement medical and dental benefits; the plan is
noncontributory with respect to life insurance benefits.
During 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). Prior to
1993, expense was recognized when benefits were paid, which was
$148,000 in 1992. In accordance with SFAS 106, the Company began
recording the cost for this plan on an accrual basis in 1993. As
permitted by SFAS 106, the Company will record the transition
obligation over a twenty-year period. The Company's cost under
this plan for 1994 and 1993 was $694,000 and $817,000,
respectively. A regulatory asset of $431,000 was recorded in 1993,
leaving a net expense of $386,000. This regulatory asset
represents the excess of postretirement benefits on the accrual
basis over the paid amounts for the period of January 1, 1993
until November 1, 1993, the effective date of the DPU's approval
of the Company's new rates. Currently, the DPU allows
Massachusetts utilities to recover the tax deductible portion of
these postretirement benefits.
Beginning in 1990, the Company has funded a portion of these
costs through the combination of a trust under Section 501(c)(9)
of the Internal Revenue Code and separate accounts of the trust
under Section 401(h) of the Internal Revenue Code. The Company is
currently funding an amount each year equal to the maximum tax
deductible amount.
The following table sets forth the plan's funded status
reconciled with the amounts recognized in the Company's financial
statements at December 31, 1994 and 1993:
(In Thousands) 1994 1993
Accumulated postretirement
benefit obligation:
Retirees $(2,416) $(2,523)
Fully eligible active plan (1,457) (1,629)
participants
Other active plan (1,782) (2,388)
participants
(5,655) (6,540)
Plan assets at fair value 3,135 2,940
Accumulated postretirement
benefit obligation (2,520) (3,600)
in excess of plan assets
Unrecognized net (gain) from
past experience
different from that assumed (1,016) (60)
and from changes in assumptions
Unrecognized transition 4,854 5,123
obligation
Prepaid postretirement benefit $1,318 $1,463
cost
Net periodic postretirement benefit cost included the following
components:
Year Ended
December 31,
(In Thousands) 1994 1993
Service cost - benefits
attributable to service $202 $268
during the period
Interest cost on accumulated
postretirement 455 478
benefit obligation
Actual return on plan assets 143 (202)
Net amortization and deferral (106) 273
Net periodic postretirement 694 817
benefit cost
Regulatory asset - (431)
Net expense $694 $386
For measurement purposes, an 8.5% (8% for medical costs after
age 65 and 4.5% for dental costs) annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1995; the rate for medical costs was assumed to decrease gradually
to 4.5% for 2001 (to 4.5% for 2004 for medical costs after age 65)
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 1% point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by
$748,000 and the aggregate of the service and the interest cost
components of net periodic postretirement benefit cost for 1994 by
$100,000.
The weighted-average discount rate used in determining the
accumulated postretirement benefit obligation was 8.5% and 7.25%
for 1994 and 1993, respectively. The expected long-term rate of
return on plan assets was 9% for assets in the Section 401(h)
accounts and, after estimated taxes, was 6% for assets in the
Section 501(c)(9) trust for all years presented.
Postemployment Benefits - During 1994, the Company adopted
Statement of Financial Accounting Standards No. 112 "Employer's
Accounting for Postemployment Benefits" (SFAS 112). This statement
requires accrual accounting for benefits to former or inactive
employees after employment but before retirement. The adoption of
SFAS 112 did not have a significant effect on the Company's
results of operations.
Note I: Other Commitments
Long-Term Obligations - The Company has contracts, which expire at
various dates through the year 2012, for the acquisition of gas
supplies and the storage and delivery of natural gas stored
underground. The contracts contain minimum payment provisions
which correspond to gas purchases that, in the opinion of
management, are not in excess of the Company's requirements.
FERC Order 636 Transition Costs - As a result of FERC Order 636,
several of 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 have been incurred but not yet recovered
by the pipelines when they were providing bundled service to local
distribution companies); (2) gas supply realignment costs (the
cost of renegotiating existing gas supply contracts with
producers); (3) stranded costs (unrecovered costs of assets that
can not be assigned to customers of unbundled services); and (4)
new facilities costs (costs of new facilities required to
physically implement Order 636).
Pipelines are expected to be allowed to recover prudently
incurred transition costs from customers such as the Company,
primarily through a demand charge, after approval by FERC. The
Company's transition cost liabilities are estimated to range from
$10,200,000 to $14,900,000, of which the Company has paid
$5,500,000 through December 31, 1994. The Company is recovering
these costs from its customers, as approved by the DPU on October
20, 1994. As of December 31, 1994, the Company has recorded on the
balance sheet a long-term liability of $4,700,000 ("Accrued
Transition Costs") and, based upon rate recovery, has recorded a
regulatory asset of $4,700,000 ("Unrecovered Transition Costs
Accrued"). Actual transition costs to be incurred depends on
various factors, and therefore future costs may differ from the
amounts discussed above.
Note J: Contingencies
Working with the Massachusetts Department of Environmental
Protection, the Company is engaged in site assessments and
evaluation of remedial options for contamination that has been
attributed to the Company's former gas manufacturing site and at
various related disposal sites. During 1990, the DPU ruled that
Colonial and eight other Massachusetts gas distribution companies
can recover environmental response costs related to former gas
manufacturing operations over a seven-year period, without
carrying costs, through the CGAC. Through December 31, 1994, the
Company had incurred environmental response costs of $2,608,000
related to the former gas manufacturing site and $6,463,000 on the
related disposal sites. The Company expects to continue incurring
costs arising from these environmental matters.
As of December 31, 1994, the Company has recorded on the balance
sheet a long-term liability of $3,800,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation, of which $2,038,000
relates to the gas manufacturing site. Based upon the DPU order
approving rate recovery of environmental response costs, a
regulatory asset of $3,800,000 has been recorded on the balance
sheet ("Unrecovered Environmental Costs Accrued"). Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
As of December 31, 1994, the Company had settled claims relating
to these matters with all liability insurers and other known
potentially responsible parties (PRP). In accordance with the DPU
order referred to above, half the costs incurred in pursuing
insurers and other PRP are recovered from the ratepayers through
the CGAC and half are initially borne by the Company. Also, per
this order, any insurance and other proceeds are applied first to
the Company's costs of pursuing recovery from insurers and other
PRP, with the remainder divided equally between the ratepayers and
shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Thousands) Response Costs Insurance and Other Proceeds
Recovered Period Recorded as Non-
from of Rate Returned to Operating Income
Year Incurred Customers Recovery Customers Net of Taxes
1988 $ 853 $ 610 1990-1997 - -
1989 4,031 2,879 1990-1997 - -
1990 639 365 1991-1998 - -
1991 374 160 1992-1999 $ 851 $ 525
1992 617 176 1993-2000 1,121 673
1993 1,236 175 1994-2001 469 290
1994 1,321 - 1995-2002 122 75
Total $9,071 $4,365 $2,563 $1,563
Note K: Quarterly Financial Data (Unaudited)
(In Thousands Except Per Share Amounts)
Income
Utility (Loss) Per
Operating Net Average Dividends
Operating Income Income Common Paid
Quarter Ended Revenues (Loss) (Loss) Share Per Share
1994
December 31 $48,077 $6,741 $4,782 $ .58 $.315
September 30 13,026 (3,132) (4,834) (.59) .315
June 30 19,073 (1,849) (3,338) (.41) .315
March 31 86,083 15,757 14,399 1.79 .310
1993
December 31 $55,289 $8,780 $6,945 $ .87 $.310
September 30 12,259 (2,738) (3,722) (.47) .310
June 30 20,587 (1,417) (3,235) (.41) .310
March 31 78,126 14,265 12,034 1.53 .305
In the opinion of management, the quarterly financial data
includes all adjustments, consisting only of normal recurring
accruals, necessary for a fair presentation of such information.
The Company typically reports profits during the first and fourth
quarters of each year while incurring losses during the second and
third quarters. This is due to significantly higher natural gas
sales during the colder months to satisfy customers' heating
needs.
Note L: Restructuring Charge
In the fourth quarter of 1994, the Company recorded a
restructuring charge of $3,185,000 ($1,965,000 after-tax or $.24
per share). This amount includes $2,537,000 for the cost of a
voluntary early retirement program which was accepted by 47
employees and $648,000 for costs accrued by the Company in
connection with the closure of two retail appliance stores.
[END OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS]
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Shareholders of Colonial Gas Company
We have audited the accompanying consolidated balance sheets of
Colonial Gas Company and subsidiaries as of December 31, 1994 and
1993, and the related consolidated statements of income, cash
flows, and common equity for each of the three years in the period
ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and the
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Colonial Gas Company and subsidiaries as of
December 31, 1994 and 1993, and the consolidated results of their
operations and their consolidated cash flows for each of the three
years in the period ended December 31, 1994, in conformity with
generally accepted accounting principles.
As discussed in Note H to the Consolidated Financial Statements,
in 1993 the Company changed its method of accounting for
postretirement benefits other than pensions.
Grant Thornton LLP
Boston, Massachusetts
January 18, 1995
[END OF REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS]
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income and Dividends
Net income and income per average common share were $11,009,000
($1.36), $12,022,000 ($1.52) and $10,643,000 ($1.38) for the three
years ended December 31, 1994, 1993, and 1992, respectively.
Before a restructuring charge after-tax of $1,965,000 or $.24 per
share, 1994 net income and income per average common share were
$12,974,000 ($1.60).
Net income was impacted by significantly colder-than-normal
temperatures in 1994, 1993 and 1992, which is summarized as
follows:
1994 1993 1992
Percent colder (warmer) than normal
Peak Season (January - April and
November - December) 4.3% 7.5% 2.2%
Off-Peak Season (May - October) 7.5% 4.2% 18.6%
Year Average 4.8% 7.0% 4.6%
Percent colder (warmer) than prior year
Peak Season (January - April and
November - December) (2.9)% 5.2% 11.7%
Off-Peak Season (May - October) 3.2% (12.1)% 39.4%
Year Average (2.1)% 2.4% 15.5%
Other items which had an impact on net income are discussed in the
following sections.
Dividends paid per common share were $1.255 in 1994, $1.235 in
1993 and $1.213 in 1992. The Company has paid dividends for 58
consecutive years, and has increased dividends each year for the
past 15 years.
Operating Revenues
Operating revenues were $166,259,000 in 1994, $166,261,000 in 1993
and $145,054,000 in 1992. 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 customers increased
by 13,459 over the last three years, an increase of 10.9%, which
increase has added to sales volume. The chart below summarizes
volumes of gas sold and transported and number of firm customers:
1994 1993 1992
(In MMcf)
Gas sold
Firm 18,716 18,935 18,542
Non-Firm 729 1,030 1,508
Gas transported
Firm 6,090 4,163 1,997
Non-Firm 4,185 4,026 2,820
Total gas sold and
transported (In MMcf) 29,720 28,154 24,867
Firm Customers 136,644 132,188 127,965
Operating revenues were unchanged from 1993 to 1994. Utility
revenues were positively impacted during 1994 by a 3.4% customer
growth and a 4.9% rate increase which became effective in November
1993. Weather, although 4.8% colder than normal, was 2.1% warmer
than 1993.
Operating revenues increased $21,207,000, or 14.6%, from 1992 to
1993. This increase resulted primarily from weather that was
colder than the prior year, a growing customer base, a 4.9% rate
increase effective November 1, 1993 and increased gas costs passed
on to customers through the CGAC. Temperatures were 2.4% colder
than the comparable 1992 period and 7.0% colder than normal. This
cooler weather pattern, together with continued customer growth,
helped raise firm gas sales by 2.1% or 393,000 Mcf.
Cost of Gas Sold
Average cost of gas sold per Mcf was $4.48 in 1994, $4.53 in 1993
and $3.73 in 1992. 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, which flow back to the
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) 1994 1993 1992
Gas purchased
Pipeline 14,392 14,983 16,633
Underground storage 3,112 3,501 2,666
LNG/Other 2,390 1,832 1,668
Total gas purchased 19,894 20,316 20,967
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 $32,823,000 in 1994, an increase of $75,000
or 0.2%, from 1993, and $32,748,000 in 1993, an increase of
$1,267,000, or 4.0%, from 1992. In 1994, the Company conducted a
self-examination to fundamentally downshift its cost structure.
The Company expects to lower its operations and maintenance costs
by approximately 6% in 1995. The increase in 1993 was primarily
due to increased labor and medical insurance costs and and an
increase in bad debt expense.
Maintenance expense increased $365,000, or 6.5%, in 1994 from
1993 and increased $154,000, or 2.8%, in 1993 from 1992. The
increase in 1994 was primarily due to increased labor resulting
from colder weather during the first quarter.
Depreciation and amortization expense increased 35.2% or
$2,404,000 in 1994 and 15.5% or $917,000 in 1993. The increase in
1994 and 1993 was primarily due to the increased depreciation
rates as a result of the Company's 1993 rate order and an increase
in utility property.
Local property and other taxes increased 8.5% in 1994 from 1993
and 14.8% in 1993 from 1992 due to higher property and payroll
taxes, and additional property subject to property taxes.
A restructuring charge of $3,185,000 ($1,965,000 after-tax or
$.24 per share) was recorded during the fourth quarter of 1994.
This amount includes $2,537,000 for the cost of a voluntary early
retirement program which was accepted by 47 employees and $648,000
for costs accrued by the Company in connection with the closure of
two retail appliance stores.
Income Taxes
Total Federal income and state franchise taxes decreased 20.7% or
$1,527,000 in 1994 as a result of less income. Total Federal
income and state franchise taxes inceased 13.2% or $862,000 in
1993 as a result of a higher level of income.
Other Operating Income (Expense)
Other operating income (expense), net of income taxes was
$1,336,000 in 1994, $209,000 in 1993 and $36,000 in 1992. Other
operating income includes results from the Company's wholly-owned
energy trucking subsidiary (Transgas) and appliance sales. As
discussed previously, the Company's retail appliance sales
operation was discontinued as of December 31, 1994.
Transgas' 1994 financial results were driven by extremely cold
weather in the first quarter of 1994 which generated a significant
increase in demand for the truck transportation of liquefied
natural gas (LNG) and propane throughout the first three quarters
of 1994.
Transgas' improved financial results in 1993 are attributable to
the closing of its unprofitable bulk cement trucking operation
during the first half of the year. The closing of this operation
permitted Transgas to reduce overhead expenses. In addition,
trucking equipment associated with this operation was sold at
prices exceeding net book value. Transgas' LNG transportation
revenue in 1993 increased due to renewed demand from natural gas
distribution companies as a result of colder than normal weather
throughout the Northeast during the winter of 1992/1993. However,
this increase was more than offset by the decline in its portable
pipeline business.
Factors affecting the future financial results of Transgas
include the amount of LNG used by local distribution companies
throughout the northeast United States to satisfy requirements of
their customers; the price of domestic and Canadian natural gas
compared to imported LNG; and the level of construction and major
maintenance projects of interstate pipeline companies which drives
the demand for portable pipeline services.
Non-Operating Income
Non-operating income, net of income taxes, was $565,000 in 1994,
$1,064,000 in 1993 and $922,000 in 1992. Non-operating income
includes interest income and miscellaneous other income. Included
in non-operating income were recoveries of $75,000, $290,000 and
$673,000 in 1994, 1993 and 1992, respectively, resulting from
settlements reached with insurers and other potentially
responsible parties relating to enviromental response costs as
described under "Environmental Matters". Also included in non-
operating income for 1993 is an insurance recovery of $509,000
relating to a line of business that was discontinued in 1979.
Interest and Debt Expense
Interest and debt expense increased 3.3% and 9.0% in 1994 and
1993, respectively. The increase in 1994 was due to increased
levels of short-term debt and higher short-term interest rates
partially offset by a decrease in interest on long-term debt due
to paydowns in 1993. The increase in 1993 was due to the issuance
of $45 million of long-term debt in June 1992 partially offset by
a decrease in interest expense on regulatory assets and decreased
levels of short-term debt and lower short-term interest rates.
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 to and perhaps beyond the year 2000.
Regulatory Matters
Environmental response 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". The Company's DSM
programs are in their third year and are expected, based on
methodology approved by the DPU, to save approximately $25.5
million in gas costs that would have been incurred over the lives
of the installed conservation measures. In order to achieve these
savings, Colonial and its participating customers will have
invested approximately $14 million over the three-year period in
customer conservation measures such as insulation, heating systems
controls and water heating conservation devices. As a result,
Colonial expects to reduce customer bills by approximately $11.5
million from the levels they would have been at if no conservation
occurred. In addition, the Company is allowed to recover the
margins lost as a result of this program and financial incentives
based on the attainment of performance goals. The Company
anticipates filing in 1995 for approximately $400,000 of financial
incentives.
In 1993, the Company applied for what was only its second base
rate increase request since 1984. Effective November 1, 1993, the
Company received DPU approval of a settlement agreement that
called for a base rate increase designed to produce additional
revenues of $6.7 million or 4.9% annually. In addition to this
rate increase, the DPU approved a proposal to expand the
eligibility criteria for Colonial's discount rate for low-income
residential heating customers and allowed the Company to retain
10% of the revenues generated from releasing the Company's
interstate pipeline transportation capacity to third parties above
an initial threshold of $2,500,000. In 1994, the Company received
$3,313,000 of capacity release revenue, $3,232,000 of which was
credited back to firm customers and $81,000 of which was retained
by the Company.
The table below summarizes the Company's recent requests to
increase base revenue:
Increase Requested Increase Approved
Date Effective Amount Percen- Amount Percen-
tage tage
November 1, 1984 $ 4.30 million 3.73% $2.8 million 2.4%
November 1, 1990 $12.80 million 9.86% $7.9 million 5.6%
November 1, 1993 $10.75 million 7.87% $6.7 million 4.9%
In 1993, Colonial began unbundling its firm sales service to
commercial and industrial customers by offering a tariffed firm
transportation-only service. Pursuant to this service, a customer
procures its own gas supply and contracts with Colonial for firm
transportation service through Colonial's distribution system. As
of December 31, 1994, six customers had opted for tariffed firm
transportation service, representing less than 1.5% of the
Company's annual firm load.
In 1994, the DPU opened two industry-wide proceedings which may
result in guidelines for the further unbundling and/or
deregulation of the Company's business. One of those proceedings
is addressing whether interruptible transportation and
interruptible sales service on local distribution company ("LDC")
systems, and the release of interstate pipeline capacity by LDCs,
should be structured or priced differently. The other is
addressing whether and how the traditional cost-of-service/rate-of-
return method of regulating gas and electric utilities might be
replaced with some type of alternative "incentive" method. The DPU
has stated that it intends to issue rulings in these two
proceedings early in 1995. The Company anticipates that, when
issued, the rulings may contain general guidelines on the matters
covered by the proceedings. Until issued, the Company cannot
predict what changes might be required or permitted in the
Company's interruptible transportation service, interruptible
sales service, capacity release policies or overall rate
practices. In the interim, the Company is analyzing specific
incentive regulation options which it could propose to the DPU as
a means of benefiting its customers and shareholders.
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, 1994, the
Company had incurred environmental response costs of $2,608,000
related to the former gas manufacturing site and $6,463,000 on the
related disposal sites. The Company expects to continue incurring
costs arising from these environmental matters.
As of December 31, 1994, the Company has recorded on the balance
sheet a long-term liability of $3,800,000 representing estimated
future response costs relating to these sites based on the
Company's preferred methods of remediation, of which $2,038,000
relates to the gas manufacturing site. Based upon the DPU order
approving rate recovery of environmental response costs, a
regulatory asset of $3,800,000 has been recorded on the balance
sheet ("Unrecovered Environmental Costs Accrued"). Actual
environmental response costs to be incurred depends on various
factors, and therefore future costs may differ from the amount
currently recorded as a liability.
As of December 31, 1994, the Company had settled claims relating
to these matters with all liability insurers and other known
potentially responsible parties (PRP). In accordance with the DPU
order referred to above, half the costs incurred in pursuing
insurers and other PRP are recovered from the ratepayers through
the CGAC and half are initially borne by the Company. Also, per
this order, any insurance and other proceeds are applied first to
the Company's costs of pursuing recovery from insurers and other
PRP, with the remainder divided equally between the ratepayers and
shareholders.
The table below summarizes the environmental response costs
incurred and insurance and other proceeds received relating to
these environmental response costs:
(In Response Costs Insurance and Other
Thousands) Proceeds
Recovered Period Returned Recorded as
from of Rate to Non-Operating
Year Incurred Customers Recovery Customers Income Net of Taxes
1988 $ 853 $ 610 1990-1997 - -
1989 4,031 2,879 1990-1997 - -
1990 639 365 1991-1998 - -
1991 374 160 1992-1999 $ 851 $ 525
1992 617 176 1993-2000 1,121 673
1993 1,236 175 1994-2001 469 290
1994 1,321 - 1995-2002 122 75
Total $9,071 $4,365 $2,563 $1,563
Accounting Standards
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, which was $148,000 in
1992. In accordance with SFAS 106, the Company began recording the
cost for this plan on an accrual basis in 1993. As permitted by
SFAS 106, the Company will record the transition obligation over a
twenty-year period. The Company's cost under this plan for 1994
and 1993 was $694,000 and $817,000, respectively. A regulatory
asset of $431,000 was been recorded in 1993, leaving a net expense
of $386,000. This regulatory asset represents the excess of
postretirement benefits on the accrual basis over the paid amounts
for the period of January 1, 1993 until November 1, 1993, the
effective date of the DPU's approval of the Company's new rates.
Currently the DPU allows Massachusetts utilities to recover the
tax deductible portion of these postretirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
The Company's liquidity is affected by its ability to generate
funds from operations and to access capital markets. The Company's
operations are seasonal with its cash flow reflecting this
seasonality. The Company typically generates approximately 70
percent of its annual operating revenues during the November
through April heating season, which results in a high level of
cash flow from operations from late winter through early summer.
As a result of this seasonality, the Company's liquidity can be
affected by significant variations in weather. Short-term
borrowings are highest during the fall and early winter months due
to the completion of the annual construction program and seasonal
working capital requirements.
Investing Activities
The Company invests in property, plant and equipment to improve
and protect its distribution system, and to expand its system to
meet customer demand. Capital expenditures were $28,195,000 in
1994, $25,703,000 in 1993 and $26,948,000 in 1992. The Company's
long-range plan calls for annual utility expenditures, of which
over 40% is budgeted for new business, averaging $27,140,000 over
the next five years as set forth below:
(In Thousands) 1995 1996 1997 1998 1999
Distribution $20,200 $20,700 $22,700 $22,300 $26,500
Production 1,000 1,400 1,000 1,000 700
Information Systems 4,200 4,300 1,000 700 500
Automated Meter 1,200 1,100 1,100 $1,100 1,100
Reading
General 200 300 700 300 400
Total Capital $26,800 $27,800 $26,500 $25,400 $29,200
Expenditures
Financing Activities
The Company has a $75 million credit facility which allows it to
meet its seasonal working capital needs. The present facility
expires in June 1997. Up to $30 million of the credit facility can
be used by the Company's gas inventory trust. The credit facility
allows the Company the option to borrow under any one of four
alternative rates.
The Company has raised permanent capital during the last three
years as follows:
(In Thousands) 1994 1993 1992
Common Stock Under
Dividend Reinvestment
and Common Stock
Purchase Plan and
Employee Savings Plan $4,070 $4,283 $ 4,286
Long-Term Debt
Series CG, 8.05%, due
entirely in 1999 - - $20,000
Series CH, 8.80%, due
entirely in 2022 - - $25,000
Note Payable $ 741 - -
The equity and debt components of the Company's capital
structure at the end of the year is shown in the table below:
1994 1993 1992
Equity 56% 52% 49%
Long-Term Debt 44% 48% 51%
As of April 1994, the quarterly dividend paid on the Company's
Common Stock was increased to $.315 per share or an annualized
dividend rate of $1.26 per share.
[END OF MANAGEMENT'S DISCUSSION AND ANALYSIS]
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1994 1993 1992 1991 1990
Balance Sheet Data:
Assets:
Utility property - net $221,685 $202,713 $183,815 $162,736 $151,480
Non-utility property - net 3,479 3,235 4,039 4,767 5,076
Capital leases - net 2,948 3,914 4,366 4,557 4,962
Current assets 65,568 67,668 71,763 53,472 46,393
Deferred charges and other 37,668 34,588 38,939 38,789 29,925
assets
Total $331,348 $312,118 $302,922 $264,321 $237,836
Capitalization and Liabilities:
Capitalization:
Common equity $ 99,175 $ 94,283 $ 87,771 $ 82,221 $ 80,109
Preferred stock - - - - -
Long-term debt 77,923 87,432 90,750 50,410 64,604
Total Capitalization 177,098 181,715 178,521 132,631 144,713
Capital lease obligations 2,237 3,149 3,591 3,838 4,233
Current liabilities 91,382 73,413 64,567 73,993 47,729
Deferred credits and reserves 60,631 53,841 56,243 53,859 41,161
Total $331,348 $312,118 $302,922 $264,321 $237,836
Income Statement Data:
Operating revenues $166,259 $166,261 $145,054 $137,719 $134,298
Cost of gas sold (87,458) (90,915) (75,143) (73,288) (78,930)
Operating margin 78,801 75,346 69,911 64,431 55,368
Operating expenses (including
income taxes) (61,284) (56,456) (52,760) (48,009) (42,853)
Utility operating income 17,517 18,890 17,151 16,422 12,515
Other income - net of income 1,901 1,273 958 36 1,625
taxes
Interest and debt expense (8,409) (8,141) (7,466) (8,141) (8,445)
Accounting change - - - - -
Preferred stock dividends - - - - -
Net income applicable to
common stock $11,009 $ 12,022 $ 10,643 $ 8,317 $ 5,695
Capitalization Ratios:
Common equity 56.0% 51.9% 49.2% 62.0% 55.4%
Preferred stock - - - - -
Long-term debt 44.0% 48.1% 50.8% 38.0% 44.6%
Common Stock Data (a):
Average shares outstanding 8,119 7,931 7,728 7,529 6,963
Income per share (b) $ 1.36 $1.52 $1.38 $1.10 $0.82
Dividends paid per share:
Common Stock $ 1.255 $1.235 $1.213 $1.193 $1.167
Class A Common Stock - - - - -
Per weighted average $ 1.255 $1.235 $1.213 $1.193 $1.167
common share
Dividend payout rate 92% 81% 88% 108% 142%
Book value per share (a) $ 12.05 $11.74 $11.19 $10.78 $10.75
Dividends as a percent of 10% 11% 11% 11% 11%
of book value
Market price per share (a) $ 19.25 $22.50 $21.25 $17.50 $15.00
Market price as a percent of
book value 160% 192% 190% 162% 139%
Return on average common equity 11.4% 13.2% 12.5% 10.2% 7.8%
___________________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992.
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.33 per share).
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1989 1988 1987
Balance Sheet Data:
Assets:
Utility property - net $139,764 $131,450 $121,034
Non-utility property - net 3,893 2,793 3,167
Capital leases - net 5,853 6,679 6,563
Current assets 56,753 50,414 36,757
Deferred charges and other assets 27,464 21,050 20,376
Total $233,727 $212,386 $187,897
Capitalization and Liabilities:
Capitalization:
Common equity $ 66,568 $ 63,027 $ 58,238
Preferred stock - - -
Long-term debt 69,512 55,102 58,572
Total Capitalization 136,080 118,129 116,810
Capital lease obligations 4,714 5,457 5,556
Current liabilities 54,590 53,375 34,781
Deferred credits and reserves 38,343 35,425 30,750
Total $233,727 $212,386 $187,897
Income Statement Data:
Operating revenues $139,892 $115,851 $117,947
Cost of gas sold (82,189) (63,401) (65,093)
Operating margin 57,703 52,450 52,854
Operating expenses (including
income taxes) (41,525) (38,844) (38,343)
Utility operating income 16,178 13,606 14,511
Other income - net of income taxes 956 1,046 233
Interest and debt expense (8,217) (7,369) (6,740)
Accounting change - 2,014 -
Preferred stock dividends - - -
Net income applicable to
common stock $ 8,917 $ 9,297 $ 8,004
Capitalization Ratios:
Common equity 48.9% 53.4% 49.9%
Preferred stock - - -
Long-term debt 51.1% 46.6% 50.1%
Common Stock Data (a):
Average shares outstanding 6,200 6,065 5,948
Income per share (b) $1.44 $1.53 $1.35
Dividends paid per share:
Common Stock $1.140 $1.113 $1.087
Class A Common Stock - $ .80 $ .76
Per weighted average common share $1.140 $1.013 $ .987
Dividend payout rate 79% 66% 73%
Book value per share (a) $10.62 $10.27 $9.69
Dividends as a percent of book value 11% 11% 11%
Market price per share (a) $14.67 $13.00 $11.83
Market price as a percent of
book value 138% 127% 122%
Return on average common equity 13.8% 15.3% 14.2%
____________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992.
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.33 per share).
SELECTED FINANCIAL DATA
(For the Years Ending December 31)
(In Thousands Except Per
Share Amounts) 1986 1985
Balance Sheet Data:
Assets:
Utility property - net $111,214 $102,959
Non-utility property - net 3,665 3,834
Capital leases - net 9,201 8,432
Current assets 37,234 45,411
Deferred charges and other assets 4,235 4,676
Total $165,549 $165,312
Capitalization and Liabilities:
Capitalization:
Common equity $ 54,569 $ 46,053
Preferred stock - 6,672
Long-term debt 47,528 40,007
Total Capitalization 102,097 92,732
Capital lease obligations 8,258 9,533
Current liabilities 41,151 50,413
Deferred credits and reserves 14,043 12,634
Total $165,549 $165,312
Income Statement Data:
Operating revenues $126,099 $128,165
Cost of gas sold (75,157) (80,623)
Operating margin 50,942 47,542
Operating expenses (including
income taxes) (37,938) (35,312)
Utility operating income 13,004 12,230
Other income - net of income taxes 383 1,201
Interest and debt expense (5,861) (6,010)
Accounting change - -
Preferred stock dividends (312) (724)
Net income applicable to common stock $7,214 $6,697
Capitalization Ratios:
Common equity 53.4% 49.7%
Preferred stock - 7.2%
Long-term debt 46.6% 43.1%
Common Stock Data (a):
Average shares outstanding 5,588 5,193
Income per share (b) $1.29 $1.29
Dividends paid per share:
Common Stock $1.060 $1.033
Class A Common Stock $ .72 $ .68
Per weighted average common share $ .960 $ .920
Dividend payout rate 74% 71%
Book value per share (a) $9.25 $8.73
Dividends as a percent of book value 11% 12%
Market price per share (a) $14.33 $11.59
Market price as a percent of
book value 155% 133%
Return on average common equity 14.3% 15.2%
_____________________________________________________________________
(a) Adjusted to reflect 3 for 2 stock split on July 29, 1992
(b) 1988 includes the cumulative effect of an accounting change
in the amount of $2,014 ($.33 per share).
[END OF SELECTED FINANCIAL DATA]
SHAREHOLDER INFORMATION
Corporate Headquarters
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853-3064
(508) 458-3171
FAX: (508) 459-2314
Stock Listing
The Company's Common Stock trades on the Nasdaq Stock
Market under the symbol: CGES. Stock trading activity is
reported in financial publications under the abbreviation of
ColGas or ClnGas.
Annual Meeting
The Annual Meeting of Stockholders will be held on April 19, 1995
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 1994 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 Lisa Lynch, Manager of
Financial Services, at the corporate headquarters address above.
Transfer Agent
The First National Bank of Boston
P.O. Box 644
Mail Stop: 45-02-09
Boston, MA 02102-0644
1-800-736-3001
1-617-575-3100
Independent Certified Public Accountants
Grant Thornton LLP
98 North Washington Street
Boston, MA 02114
(617) 723-7900
Corporate Counsel
Palmer & Dodge
One Beacon Street
Boston, MA 02108
(617) 573-0100
Dividends
The Company has paid dividends on Common Stock for 58 consecutive
years and has increased dividends each year for the past 15
years. Common Stock dividends are payable when declared by the
Board of Directors.
Anticipated Record Date Anticipated Payment Date
March 1, 1995 March 15, 1995
June 1, 1995 June 15, 1995
September 1, 1995 September 15, 1995
December 1, 1995 December 15, 1995
Dividend Reinvestment Plan
The Company's Dividend Reinvestment and Common Stock Purchase
Plan (DRIP) provides shareholders of record with an economical
and convenient method for purchasing additional shares of the
Company's Common Stock without paying any brokerage fees.
Participants in the plan may elect to purchase additional
Colonial shares at a 5% discount from the market price by
reinvesting all or a portion of their dividends with no brokerage
fees. Participants in the plan may also make optional cash
purchases of Common Stock at the market price in amounts ranging
from a minimum of $10 to a maximum of $5,000 per calendar
quarter, with no brokerage fees.
New features of the plan at no charge to shareholders include:
Direct depost of dividends by electronic deposit
Automatic monthly investments by electronic funds transfer
Additional information describing the plan, including a
prospectus and enrollment information, can be obtained by
contacting the Company's Transfer Agent or Investor Relations
Department.
Investment Dates
The investment date for optional cash investments under the DRIP
will be the fifteenth day of each month or, if that day is not a
business day, the preceding business day. Optional cash
investments must be received by the Company's Transfer Agent five
business days before the investment date. The dates below will
help you plan for any optional cash investments.
Date Investment Must Be Received By Transfer Agent
April 7, 1995
May 8, 1995
June 8, 1995
July 7, 1995
August 8, 1995
September 8, 1995
October 5, 1995
November 8, 1995
December 8, 1995
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 1994 and 1993, and the quarterly dividends paid per share.
Sales Prices Dividends
High Low Paid per Share
_________________________________________________________________
1994
-----------------------------------
The Year $23.75 $18.25 $1.255
4th Quarter 21.75 18.25 .315
3rd Quarter 22.00 20.50 .315
2nd Quarter 21.75 18.50 .315
1st Quarter 23.75 18.75 .310
1993 __________________________________
The Year $26.50 $20.00 $1.235
4th Quarter 25.00 21.75 .310
3rd Quarter 26.50 24.00 .310
2nd Quarter 25.00 20.00 .310
1st Quarter 25.25 21.25 .305
_________________________________________________________________
Shareholders and Record Holders
At December 31, 1994, there were approximately 15,000
shareholders of the Company's Common Stock, including 5,777
shareholders of record.
Market Makers
Colonial currently has the following market makers: A. G. Edwards
& Sons, Inc.; Edward D. Jones & Co.; First Albany Corporation;
Herzog, Heine, Geduld, Inc.; S.J. Wolfe & Co.; and Tucker
Anthony Incorporated.
Investment Information
Colonial Gas Company is a corporate member of the National
Association of Investors Corporation (NAIC). The Company is also
a participant in NAIC's Low Cost Investment Plan.
[END OF SHAREHOLDER INFORMATION]
[END OF EXHIBIT 13a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1994]
[EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
COLONIAL GAS COMPANY
SUBSIDIARIES OF REGISTRANT
Subsidiaries: Organized in Ownership
(a) Transgas Inc. Massachusetts 100%
(a) CGI Transport Limited (1) Canada 100%
(a) Included in consolidated financial statements.
(1) Owned by Transgas Inc.
[END OF EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
[EXHIBIT 23a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our reports dated January 18, 1995
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, 1994. We hereby consent to the incorporation
by reference of said reports in the Colonial Gas Company
Registration Statements on Forms S-8, as amended (File No. 33-
34068, File No. 33-34066, File No. 33-34067 and File No. 33-
44427) and Form S-16, as amended on Form S-3 (File No. 2-93005).
GRANT THORNTON LLP
Boston, Massachusetts
March 24, 1995
[END OF EXHIBIT 23a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED 12/31/94]
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