<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1999
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 04-3480443
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
One Beacon Street (617) 742-8400
Boston, Massachusetts 02108 (Registrant's Telephone Number)
(Address of Principal Executive
Offices)
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Title of Each Class Exchange
------------------- --------
<S> <C>
None None
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate 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.
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 1, 2000.
All common stock, 100 shares, are held by Eastern Enterprises.
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.
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<PAGE>
COLONIAL GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 1999
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Item No. Topic Page
-------- ----- ----
PART I
<C> <S> <C>
1. Business...................................................... 1
General....................................................... 1
Markets and Competition....................................... 1
Gas Throughput................................................ 2
Gas Supply.................................................... 2
Regulation.................................................... 3
Seasonality and Working Capital............................... 4
Environmental Matters......................................... 5
Employees..................................................... 5
2. Properties.................................................... 5
3. Legal Proceedings............................................. 5
4. Submission of Matters to a Vote of Security Holders........... 5
Glossary...................................................... 6
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 7
6. Selected Financial Data....................................... 7
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 7
8. Financial Statements and Supplementary Data................... 9
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 9
PART III
10. Directors and Executive Officers of the Registrant............ 10
11. Executive Compensation........................................ 10
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 10
13. Certain Relationships and Related Transactions................ 10
PART IV
14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K..................................................... 11
</TABLE>
<PAGE>
PART I
Item 1. Business.
General
Colonial Gas Company (the "Company"), a Massachusetts corporation formed in
1849, is engaged in the transportation and sale of natural gas to
approximately 158,000 residential, commercial and industrial customers in 24
municipalities located northwest of Boston ("Merrimack Valley" area) and on
Cape Cod. All of the common stock of the Company is held by Eastern
Enterprises ("Eastern"), which is headquartered in Weston, Massachusetts. On
August 31, 1999, the Company completed a merger with Eastern in a transaction
with an enterprise value of approximately $474 million. In effecting the
transaction, Eastern paid $150 million in cash, net of cash acquired and
including transaction costs, issued approximately 4.2 million shares of common
stock valued at $186 million and assumed $138 million of debt.
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides local transportation services and gas supply to all
customer classes. The Company's services are available on a firm and non-firm
basis. Firm transportation service and sales are provided under rate tariffs
and/or contracts filed with the Massachusetts Department of Telecommunications
and Energy ("Department"), that typically obligate the Company to provide
service without interruption throughout the year. Non-firm transportation
service and sales are generally provided to large commercial/industrial
customers who can use gas or another energy source interchangeably. Non-firm
services are provided through individually negotiated contracts and, in most
cases, the price charged takes into account the price of the customer's
alternative fuel.
The Company offers unbundled services to all commercial/industrial users,
who are allowed to purchase local transportation from the Company separately
from the purchase of gas supply, which the customer may buy from third party
suppliers. The Company views these third party suppliers as partners in
marketing gas and increasing throughput and expects to work closely with them
to facilitate the unbundling process and ensure a smooth transition,
especially in the tracking and processing of transactions. The Company has
also implemented a program to educate commercial/industrial customers about
the opportunity to purchase gas from third-party suppliers, while still
relying on the utility for delivery. As of December 31, 1999, the Company had
approximately 360 firm transportation customers. Service to all residential
customers currently is on a bundled basis. Unbundled service to residential
customers is expected to be offered beginning in June 2000. While the
migration of customers to transportation-only service will lower the Company's
revenues, it has no impact on its operating earnings. The Company earns all of
its margins on the local distribution of gas and none on the resale of the
commodity itself.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers
and electricity suppliers, throughout its service territory. The Company
currently serves approximately 53% of the potential customers within its
service territory.
<PAGE>
Gas Throughput
The following table in BCF provides information with respect to the volumes
of gas sold and transported by the Company during the three years 1997-1999.
<TABLE>
<CAPTION>
Years Ended
December 31,
--------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Residential................................................... 12.0 11.4 12.5
Commercial and industrial..................................... 6.8 6.2 7.6
---- ---- ----
Total sales................................................. 18.8 17.6 20.1
Transportation of customer-owned gas.......................... 6.4 7.4 7.0
---- ---- ----
Total throughput............................................ 25.2 25.0 27.1
==== ==== ====
Total firm throughput....................................... 22.1 22.4 23.3
==== ==== ====
</TABLE>
In 1999, residential customers comprised 90% of the Company's customer
base, while commercial and industrial establishments accounted for the
remaining 10%. Volumetrically, residential customers accounted for 37% of
total throughput and 42% of total firm throughput, while commercial and
industrial customers accounted for 63% of total throughput and 58% of total
firm throughput. Approximately 62% of commercial and industrial customers'
total throughput was transportation-only services.
No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 1999.
Gas Supply
The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1997-1999.
<TABLE>
<CAPTION>
Years Ended
December 31,
----------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Natural gas purchases...................................... 15.8 15.1 14.8
Underground storage withdrawal............................. 3.1 2.5 3.6
Liquefied natural gas ("LNG") purchases.................... 1.2 1.4 2.4
---- ---- ----
Total source of supply................................... 20.1 19.0 20.8
Company use, unbilled and other............................ (1.3) (1.4) (.7)
---- ---- ----
Total sales.............................................. 18.8 17.6 20.1
==== ==== ====
</TABLE>
Year to year variations in storage gas and unbilled gas reflect variations
in end-of-year customer requirements, due principally to weather. Given the
ready availability of supply, the Company purchased approximately 70% of its
peak pipeline supplies under firm short-term and spot contracts. The balance
of peak day pipeline requirements is purchased directly from producers and
marketers pursuant to long-term contracts which have been reviewed and
approved by the Department or by the Federal Energy Regulatory Commission
("FERC").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights
2
<PAGE>
under these contracts. The interstate pipeline companies that provide firm
transportation service to the Company's service territory, the peak daily and
annual capacity and the contract expiration dates are as follows:
<TABLE>
<CAPTION>
Capacity in BCF
----------------- Expiration
Pipeline Daily Annual Dates
-------- ------- -------- ----------
<S> <C> <C> <C>
Algonquin Gas Transmission Company
("Algonquin")............................... .046 14.7 2000-2012
Tennessee Gas Pipeline Company
("Tennessee")............................... .072 26.3 2003-2013
</TABLE>
In 1999, the Company restructured its long-term capacity contracts on
Tennessee Gas Pipeline. As a result, no contract expires on Tennessee before
2003. Less than 1% of the Company's capacity on Algonquin expires in 2000. In
addition, the Company has firm capacity contracts on interstate pipelines
upstream of Algonquin and Tennessee pipelines to transport natural gas
purchased by the Company from producing regions.
The Company has contracted with pipeline companies and others for the
storage of natural gas in underground storage fields located in Pennsylvania,
New York, Maryland and West Virginia. These contracts provide storage capacity
of 4.7 BCF and peak day deliverability of .044 BCF. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are purchased
from foreign and domestic sources.
In the fall of 1999, the Company, and its affiliates Boston Gas Company and
Essex Gas Company, entered into a portfolio management contract with El Paso
Energy Marketing, Inc. For a three year term commencing November 1, 1999, El
Paso will provide all of the city gate supply requirements to the three
companies at market prices and manage certain of the companies' upstream
capacity, underground storage and term supply contracts. The Department
approved the contract in October 1999.
The Company has two agreements with Distrigas of Massachusetts Corporation
that expire on October 31, 2000, which allow the Company to purchase up to
10,000 Dekatherms ("Dth") per day for 151 days and 5,000 Dth per day for 365
days of liquefied natural gas ("LNG") in either liquid or vapor form. The
Company anticipates that both agreements will be renewed. The Company may
reduce quantities purchased if normal sales fall below normal heating season
sendout.
Peak day firm throughput in BCF was 0.106 in 1999 and 0.093 in 1998 for the
Company's Merrimack Valley service area and 0.069 in 1999 and 0.060 in 1998
for the Company's Cape Cod service area. The Company provides for peak period
demand through a least cost portfolio of pipeline, storage and supplemental
supplies. Supplemental supplies include LNG and propane air, which are
vaporized at points on the Company's distribution system. The Company's
Merrimack Valley service area has on-system LNG and propane air facilities
which have an aggregate sendout capacity of approximately .080 BCF per day.
The Company also operates on-system facilities in the Cape Cod service area
capable of providing approximately .036 BCF per day. The Company considers its
peak day sendout capacity, based on its total supply resources, to be adequate
to meet the requirements of its firm customers.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause ("CGAC"), billed to firm sales
customers, allows for the semiannual adjustment of billing rates for firm gas
sales to reflect the actual cost of gas delivered to customers, including
demand charges for capacity on the interstate pipeline system. Similarly,
through its local distribution adjustment clause ("LDAC"), the Company
recovers the actual costs of approved energy efficiency programs, and the cost
of remediating former manufactured gas plant sites from all firm customers,
including those purchasing gas supply from third parties.
3
<PAGE>
In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The freeze on base rates is subject only to certain exogenous
factors, such as changes in tax laws, accounting changes, or regulatory,
judicial, or legislative changes. As a result of the rate plan, the Company
discontinued its application of SFAS No. 71, as described in Note 1 of Notes
to Consolidated Financial Statements. Many of the administrative, operations
and maintenance functions of the Company have been integrated with those of
Boston Gas.
All of the Company's 15,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had 360 firm transportation customers. Under the approved service
unbundling program, commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which LDC tariffs for all residential
customers will substantially conform. The Model Terms and Conditions approved
by the Department are consistent with the Department's order of February 1,
1999, which provided that, for a five year transition period, LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata
basis to marketers selling gas supply to the LDC's customers. The approved
mandatory assignment method eliminates the possibility that the costs of
upstream capacity purchased by the Company to serve firm customers will be
absorbed by the LDC or other customers through the transition period. The
Department also found that, through the transition period, LDC's will retain
primary responsibility for upstream capacity planning and procurement to
assure that adequate capacity is available at Massachusetts city gates to
support customer requirements and growth. In year three of the five-year
transition period, the Department intends to evaluate the extent to which the
upstream capacity market for Massachusetts is workably competitive based on a
number of factors, and accelerate or decelerate the transition period
accordingly. The Department's Model Terms and Conditions also require that
LDC's provide default and peaking supply services at cost-based rates.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years past the installation of DSM measures. This ruling changes the Company's
previous calculation method as approved by the Department. However, based on
the Department's order approving the merger and rate plan, the Company can
recover any resulting reduction in lost margins as an exogenous adjustment.
Seasonality and Working Capital
The Company's revenues, earnings and cash flow are highly seasonal as most
of its transportation services and sales are directly related to temperature
conditions. Since the majority of its revenues are billed in the November
through April heating season, significant cash flows are generated from late
winter to early summer. In addition, through the cost of gas adjustment
clause, the Company bills its customers over the heating season for the
majority of the pipeline demand charges paid by the Company over the entire
year. This difference, along with other costs of gas distributed but unbilled,
is reflected as deferred gas costs and is financed through short-term
borrowings. Short-term borrowings are also required from time to time to
finance normal business operations. As a result of these factors, short-term
borrowings are generally highest during the late fall and early winter.
4
<PAGE>
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site,
related satellite disposal sites, one non-MGP site and one federal superfund
site. Information with respect to the remediation of MGP related sites may be
found in Note 9 of Notes to Consolidated Financial Statements. Such
information is incorporated herein by reference.
Employees
As of December 31, 1999, the Company had 336 employees, 46% of whom are
organized in local unions with which the Company has collective bargaining
agreements that expire in 2001 and 2003.
Item 2. Properties.
The Company has two principal operations centers and two principal LNG
storage facilities. One of the storage facilities is located in Tewksbury,
Massachusetts and has a capacity of approximately 1.0 BCF of LNG and the other
is located in South Yarmouth, Massachusetts and has a capacity of
approximately .18 BCF of LNG. In addition, the Company owns its former
corporate headquarters, a 36,000 square foot facility located in Lowell,
Massachusetts.
On December 31, 1999, the Company's distribution system included
approximately 3,200 miles of gas mains, 139,000 services and 159,000 active
customer meters.
The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned in fee.
In 1999, the Company's capital expenditures were $20 million. Capital
expenditures were principally made for improvements to the distribution
system, for system expansion to meet customer growth and for productivity
improvements. The Company plans to spend approximately $23 million for similar
purposes in 2000.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of Security Holders in the fourth quarter
of 1999.
5
<PAGE>
Glossary
BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.
Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and peak-
shaving services.
Capacity--The capability of pipelines and supplemental facilities to deliver
and/or store gas.
City Gate--Physical interconnection between an interstate pipeline and the
local distribution company.
Core Customer--Generally, customers with no readily available energy
services alternative.
Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.
Firm Service--Sales and/or transportation service provided without
interruption throughout the year. Uninterrupted seasonal services are also
available for less than 365 days. Firm services are provided under either filed
rate tariffs or through individually negotiated contracts.
Gas Marketer (Broker)--A non-regulated buyer and seller of gas.
Interstate Transportation--Transportation of gas by an interstate pipeline
to the city gate.
Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to end-
user facilities.
Local Transportation Service--Transportation of gas by the LDC from the city
gate to the customer's burner tip.
Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.
Non-Firm Service--Sales and transportation service offered at a lower level
of reliability and cost. Under this service, the LDC can interrupt customers on
short notice, typically during the winter season. Non-firm services are
provided through individually negotiated contracts and, in most cases, the
price charged takes into account the price of the customer's energy
alternative.
Throughput--Gas volume delivered to customers through the LDC's gas
distribution system.
Unbundled Service--Service that is offered and priced separately, such as
separating the cost of gas commodity delivered to the LDC's city gate from the
cost of transporting the gas from the city gate to the end user. Unbundled
services can also include daily or monthly balancing, back-up or stand-by
services and pooling. With unbundled services, customers have the opportunity
to select only the services they desire.
6
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Eastern is the holder of record of all of the outstanding common equity
securities of the Company. Dividends paid to Eastern amounted to $2.5 million
in 1999.
Item 6. Selected Financial Data.
Not required.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
RESULTS OF OPERATIONS
1999 Compared to 1998
Weather for the four months ended December 1999 was 7% warmer than normal.
The four months ended December 1999 included amortization of goodwill of $2.0
million and interest on the $100 million advance from Eastern of $1.6 million.
Weather for the eight months ended August 1999 was 5% warmer than normal.
The eight months ended August 1999 included merger-related costs of $3.8
million incurred by the Company prior to the merger.
1998 Compared to 1997
Net earnings applicable to common stock for 1998 were $12.3 million, a
decrease of $3.7 million, or 23%, as compared to 1997.
Revenues in 1998 decreased $19.2 million or 10% compared to 1997. This
decrease resulted from weather which was 12% warmer than normal and 13% warmer
than the prior year, and lower gas costs, partially offset by customer growth
of 3%.
Operating margin decreased $4.8 million, or 6%, due to the warmer weather
referenced earlier.
Operating expenses decreased $1.7 million or 3%. The decrease in operations
expense was due primarily to an adjustment to the reserve for uncollectable
accounts of approximately $1.1 million, a result of the unbundling of the
Company's rates on November 1, 1998. As of that date, the gas cost component
of bad debt expense is being recovered through the cost of gas adjustment
clause. Other factors that impacted the decrease in operations expense were
lower pension costs and insurance expense. Depreciation and amortization
expense increased $1.4 million, or 11%, reflecting continued investment in
system expansion and replacement and the completion of software systems
projects.
YEAR 2000 ISSUE
The Company experienced no significant issues as a result of the transition
from December 31, 1999 to January 1, 2000. The Company does not expect to
incur any significant Year 2000 related costs beyond January 2000. On August
31, 1999, the Company was merged with Eastern, the parent company of Boston
Gas Company. In connection with the merger, the Company addressed any
remaining Year 2000 issues through conversion to systems operated by Boston
Gas Company.
FORWARD-LOOKING INFORMATION
This report and other Company reports and statements issued or made from
time to time contain certain "forward-looking statements" concerning projected
future financial performance, expected plans or future
7
<PAGE>
operations. The Company cautions that actual results and developments may
differ materially from such projections or expectations.
Investors should be aware of important factors that could cause actual
results to differ materially from forward-looking projections or expectations.
These factors include, but are not limited to: the effect of strategic
initiatives on earnings and cash flow, the impact of any merger-related
activities, the ability to successfully integrate natural gas distribution
operations, temperatures above or below normal, changes in economic
conditions, including interest rates, regulatory and court decisions and
developments with respect to previously disclosed environmental liabilities.
Most of these factors are difficult to predict accurately and are generally
beyond the control of the Company.
LIQUIDITY AND CAPITAL RESOURCES
The Company has a $75 million credit facility expiring in September 2000,
which allows it to meet its seasonal working capital needs. Up to $30 million
of the credit facility can be used by the Company's gas inventory trust.
The Company expects capital expenditures for 2000 to be approximately $23
million. Capital expenditures will be largely for improvements to the
distribution system and for system expansion to meet customer growth.
The Company believes that projected cash flow from operations, in
combination with currently available resources, is more than sufficient to
meet 2000 capital expenditures, working capital requirements, dividend
payments and normal debt repayments.
OTHER MATTERS
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause, billed to firm sales customers,
allows for the semiannual adjustment of billing rates for firm gas sales to
reflect the actual cost of gas delivered to customers, including demand
charges for capacity on the interstate pipeline system. Similarly, through its
local distribution adjustment clause, the Company recovers the actual costs of
approved energy efficiency programs and the cost of remediating former
manufactured gas plant sites from all firm customers, including those
purchasing gas supply from third parties.
In connection with the acquisition by Eastern Enterprises in 1999 on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The freeze on base rates is subject only to certain exogenous
factors, such as changes in tax laws, accounting changes, or regulatory,
judicial, or legislative changes. As a result of the rate plan, the Company
discontinued its application of SFAS No. 71, as described in Note 1 of Notes
to Consolidated Financial Statements. Many of the administrative, operations
and maintenance functions of the Company have been integrated with those of
Boston Gas.
All of the Company's 15,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had 360 firm transportation customers. Under the approved service
unbundling program, commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which LDC tariffs for
8
<PAGE>
all residential customers will substantially conform. The Model Terms and
Conditions approved by the Department are consistent with the Department's
order of February 1, 1999, which provided that, for a five year transition
period, LDC contractual commitments to upstream capacity will be assigned on a
mandatory, pro rata basis to marketers selling gas supply to the LDC's
customers. The approved mandatory assignment method eliminates the possibility
that the costs of upstream capacity purchased by the Company to serve firm
customers will be absorbed by the LDC or other customers through the
transition period. The Department also found that, through the transition
period, LDC's will retain primary responsibility for upstream capacity
planning and procurement to assure that adequate capacity is available at
Massachusetts city gates to support customer requirements and growth. In year
three of the five-year transition period, the Department intends to evaluate
the extent to which the upstream capacity market for Massachusetts is workably
competitive based on a number of factors, and accelerate or decelerate the
transition period accordingly. The Department's Model Terms and Conditions
also require that LDC's provide default and peaking supply services at cost-
based rates.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years past the installation of DSM measures. This ruling changes the Company's
previous calculation method as approved by the Department. However, based on
the Department's order approving the merger and rate plan, the Company can
recover any resulting reduction in lost margins as an exogenous adjustment.
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site and
related satellite disposal sites, one non-MGP site and one federal superfund
site, as described in Note 9 of Notes to Consolidated Financial Statements.
The Company has recorded a liability of approximately $850,000, which
represents its best estimate at this time of remediation costs. However, there
can be no assurance that actual costs will not vary considerably from this
estimate.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
9
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11. Executive Compensation.
Not required.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13. Certain Relationships and Related Transactions.
Not required.
10
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.
(3) List of Exhibits.
<TABLE>
<C> <S>
2 Agreement and Plan of Reorganization by and between Eastern Enterprises
and Colonial Gas Company dated as of October 17, 1998, filed as Exhibit
2.1 to the Registrant's Form 8-K Report dated October 21, 1998.*
3.1 Restated Articles of Organization for Colonial Gas Company dated August
5, 1999. (Filed herewith).
3.2 By-Laws of Colonial Gas Company dated August 5, 1999. (Filed herewith).
4.1 Second Amended and Restated First Mortgage Indenture dated as of June 1,
1992, filed as Exhibit 4(b) to Form 10-Q of the Registrant for the
quarter ended June 30, 1992.*
4.2 First Supplemental Indenture dated as of June 15, 1992, filed as Exhibit
4(c) to Form 10-Q of the Registrant for the quarter ended June 30,
1992.*
4.3 Second Supplemental Indenture dated as of September 27, 1995, filed as
Exhibit 4(c) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1995.*
4.4 Amendment to Second Supplemental Indenture dated as of October 12, 1995,
filed as Exhibit 4(d) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
4.5 Third Supplemental Indenture dated as of December 15, 1995, filed as
Exhibit 4(f) to the Registrant's Form S-3 Registration Statement dated
January 5, 1998.*
4.6 Fourth Supplemental Indenture dated as of March 1, 1998, filed as
Exhibit 4(l) to the Registrant's Form 10-Q for the quarter ended March
31, 1998.*
4.7 Form of Rights Agreement dated as of December 1, 1993, between Colonial
Gas Company and BankBoston, N.A. (f/k/a/ The First National Bank of
Boston), as Rights Agent, together with the following exhibits thereto:
(i) Form of Vote Establishing the Series A-1 Junior Participating
Preferred Stock, (ii) Form of Rights Certificate, and (iii) Summary of
Rights to Purchase Preferred Shares, filed as Exhibit 1 to the
Registrant's Registration Statement on Form 8-A filed on November 22,
1993 (File No. 0-10007).*
4.8 Amendment to Rights Agreement between Colonial Gas Company and
BankBoston, N.A. dated as of October 17, 1998, filed as Exhibit 4(h) to
the Registrant's Form 10-K for the fiscal year ended December 31, 1998.*
4.9 Revolving Credit Agreement for Colonial Gas Company dated as of
September 12, 1997, filed as Exhibit 4(e) to Form 10-Q of the Registrant
for the quarter ended September 30, 1997.*
4.10 Revolving Credit Agreement for Massachusetts Fuel Inventory Trust dated
as of September 12, 1997, filed as Exhibit 4(f) to Form 10-Q of the
Registrant for the quarter ended September 30, 1997.*
4.11 Purchase Contract dated as of June 27, 1990 between Massachusetts Fuel
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 the quarter ended June 30, 1990.*
4.12 Security Agreement and Assignment of Contracts dated as of September 12,
1997 made by Massachusetts Fuel Inventory Trust in favor of Fleet
National Bank as Agent for designated banks, filed as Exhibit 4(h) to
Form 10-Q of the Registrant for the quarter ended September 30, 1997.*
</TABLE>
11
<PAGE>
<TABLE>
<C> <S>
4.13 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company
(as Trustor) and Shawmut Bank, N.A. (as Trustee), filed as Exhibit 10
(d) to Form 8-K of the Registrant for the quarter ended June 30, 1990.*
10.1 Storage Service Agreement with Penn-York Energy Corporation, dated as of
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.*
10.2 Gas Transportation Contract for Firm Reserved Service with Iroquois,
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.*
10.3 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.4 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.5 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.6 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.7 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.8 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.9 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (v) to the Registrant's Annual Report on From 10-K
for the fiscal year ended December 31, 1993.*
10.10 Service Agreement between Texas Eastern Transmission Corporation and
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.*
10.11 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 1996 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.12 Service Agreement between Texas Eastern Transmission Corporation and
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.*
10.13 Service Agreement between Texas Eastern Transmission Corporation and
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.*
10.14 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 7,918 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.15 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 2,222 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.16 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 104 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
</TABLE>
12
<PAGE>
<TABLE>
<C> <S>
10.17 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.18 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.19 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.20 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.21 Service Agreement between CNG Transmission Corporation and 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.*
10.22 Service Agreement between CNG Transmission Corporation and 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.*
10.23 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract no. 400009, dated
November 1, 1998. (Filed herewith).
10.24 Service Agreement between Texas Eastern Transmission Corporation and
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.*
10.25 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.26 Service Agreement between National Fuel Gas Supply Corporation and
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.*
10.27 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.28 Service Agreement between Algonquin Gas Transmission Company and
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.*
10.29 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
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.*
10.30 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FT-1), dated August 18, 1994,
filed as Exhibit 10 (kk) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.31 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated August 29, 1994,
filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.32 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
filed as Exhibit 10 (mm) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
</TABLE>
13
<PAGE>
<TABLE>
<C> <S>
10.33 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.34 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule SS-1), dated November 30,
1994, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.35 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated November 30,
1994, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.36 Letter Agreement between Algonquin Gas Transmission Company and Colonial
Gas Company, Regarding transfer of transportation entitlements, dated
March 28, 1994, filed as Exhibit 10 (qq) to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994.*
10.37 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.38 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (tt) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.39 Firm Natural Gas Transportation agreement between Tennessee Gas Pipeline
and Colonial Gas Company (under Rate Schedule NET-Northeast), dated
August 1, 1995, filed as Exhibit 10 (qq) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1995.*
10.40 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated June 1, 1995,
filed as Exhibit 10 (rr) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1995.*
10.41 Amendment No. 1 (dated July 1, 1995 to Gas Storage Contract between
Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate
Schedule FS), dated December 1, 1994 (which superseded contract dated
September 1, 1993), filed as Exhibit 10 (ss) to the Registrant's Form
10-K for the fiscal year ended December 31, 1995.*
10.42 Amendment to Gas Transportation Contract for Firm Reserved Service with
Iroquois Gas Transmission System, L.P., dated September 1, 1995, filed
as Exhibit 10 (tt) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
10.43 Service Agreement between Algonquin Transmission Company and Colonial
Gas Company (Under Rate Schedule AFT-1), dated December 1, 1995, filed
as Exhibit 10 (uu) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
10.44 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated August 25, 1999.
(Filed herewith).
10.45 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract No. 300114, dated
November 1, 1998. (Filed herewith).
10.46 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract No. 300115, dated
November 1, 1998. (Filed herewith).
10.47 Amended Service Agreement between Texas Eastern Transmission Corporation
and Colonial Gas Company (under Rate Schedules CDS & FT-1) dated January
6, 1999. (Filed herewith).
10.48 Redacted Gas Resources Portfolio Management and Gas Sales Agreement
between Colonial Gas Company and El Paso Energy Marketing Company dated
September 14, 1999, as amended. (Filed herewith as Exhibit 10.1 to Form
10-K of Eastern Enterprises for the year ended December 31, 1999, and
incorporated herein by reference).
</TABLE>
14
<PAGE>
<TABLE>
<C> <S>
10.49 Contract Restructuring Agreement between Colonial Gas Company and
Tennessee Gas Pipeline dated August 2, 1999. (Filed herewith).
10.50 Form Employment Agreement dated as of October 13, 1998, for Colonial Gas
Company corporate officers, filed as Exhibit 10.l to the Registrant's
Form 10-Q for the quarter ended September 30, 1998.*
10.51 Employment Agreement dated as of October 13, 1998, by and between
Colonial Gas Company, Transgas Inc. and V.W. Baur, filed as Exhibit 10.2
to the Registrant's Form 10-Q for the quarter ended September 30, 1998.*
10.52 Colonial Gas Company Retention Bonus Plan, effective as of October 19,
1998, filed as Exhibit 10.3 to the Registrant's Form 10-Q for the
quarter ended September 30, 1998.*
10.53 Rate increase deferral incentive policy of Colonial Gas Company dated
January 1, 1995, filed as Exhibit 10 (xx) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1994.*
10.54 1997 Transitional Executive Incentive Plan of Colonial Gas Company,
filed as Exhibit 10e to the Registrant's Form 10-K for the fiscal year
ended December 31, 1997.*
10.55 Colonial Gas Company Executive Performance and Equity Incentive Plan
included as Appendix A to the Proxy Statement for the Company's 1998
Annual Meeting and to the Prospectus included in the Registration
Statement on Form S-4 of the Company's subsidiary, Colonial Energy,
filed on March 6, 1998 (Commission File No. 333-47441).*
23a Consent of Independent Certified Public Accountants.
23b Consent of Independent Certified Public Accountants.
27 Financial Data Schedule for the four months ended December 31, 1999 and
the eight months ended August 31, 1999.
</TABLE>
There were no reports on Form 8-K filed in the Fourth Quarter of 1999.
- --------
* Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
and Regulations under the Securities Exchange Act of 1934, reference is
made to the document previously filed with the Commission.
15
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
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 (Registrant)
Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza
Senior Vice President and
Treasurer
(Principal Financial and
Accounting Officer)
Date: March 14, 2000
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 indicated on the 14th day of March, 2000.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
Chester R. Messer Director and President
___________________________________________
Chester R. Messer
Anthony J. DiGiovanni Director and Senior Vice President
___________________________________________
Anthony J. DiGiovanni
Joseph F. Bodanza Director and Senior Vice President and
___________________________________________ Treasurer (Principal Financial and
Joseph F. Bodanza Accounting Officer)
J. Atwood Ives Director
___________________________________________
J. Atwood Ives
Fred C. Raskin Director
___________________________________________
Fred C. Raskin
Walter J. Flaherty Director
___________________________________________
Walter J. Flaherty
L. William Law, Jr. Director
___________________________________________
L. William Law, Jr.
</TABLE>
16
<PAGE>
COLONIAL GAS COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
<TABLE>
<S> <C>
Reports of Independent Public Accountants........................ F-18 and F-19
Consolidated Statements of Earnings for the Four Months Ended
December 31, 1999, Eight
Months Ended August 31, 1999, and Two Years Ended December 31,
1998............................................................ F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998.... F-3 and F-4
Consolidated Statements of Retained Earnings for the Four Months
Ended December 31, 1999, Eight Months Ended August 31, 1999, and
Two Years Ended December 31, 1998............................... F-5
Consolidated Statements of Cash Flows for the Four Months Ended
December 31, 1999, Eight Months Ended August 31, 1999, and Two
Years Ended December 31, 1998................................... F-6
Notes to Consolidated Financial Statements...................... F-7 to F-17
Interim Financial Information for the Two Years Ended December
31, 1999 (Unaudited)............................................ F-20
Schedules for the Three Years Ended December 31, 1999:
II--Valuation and Qualifying Accounts......................... F-21 to F-24
</TABLE>
Schedules other than those listed above have been omitted as the
information has been included in the consolidated financial statements and
related notes or is not applicable nor required.
F-1
<PAGE>
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
<TABLE>
<CAPTION>
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Operating revenues...... $54,098 $122,626 $167,978 $187,140
Cost of gas sold........ 26,087 65,320 88,127 102,455
------- -------- -------- --------
Operating margin........ 28,011 57,306 79,851 84,685
------- -------- -------- --------
Operating expenses:
Operations............ 9,101 19,818 27,793 30,044
Maintenance........... 1,151 4,835 4,794 4,503
Depreciation and
amortization......... 2,857 10,086 13,435 12,049
Amortization of
goodwill............. 2,008 -- -- --
Income taxes.......... 3,406 3,639 7,134 9,972
Taxes, other than
income............... 1,626 3,861 5,155 5,261
Merger related
expenses............. -- 3,788 1,808 --
------- -------- -------- --------
Total operating
expenses............. 20,149 46,027 60,119 61,829
------- -------- -------- --------
Operating earnings...... 7,862 11,279 19,732 22,856
Other earnings (loss),
net.................... 237 (20) 485 624
------- -------- -------- --------
Earnings before interest
expense................ 8,099 11,259 20,217 23,480
------- -------- -------- --------
Interest expense:
Long-term debt........ 2,844 5,689 8,130 8,113
Other, including
amortization of debt
expense.............. 2,569 1,244 604 (79)
Less--Interest during
construction......... (27) (194) (805) (594)
------- -------- -------- --------
Total interest
expense.............. 5,386 6,739 7,929 7,440
------- -------- -------- --------
Net earnings............ $ 2,713 $ 4,520 $ 12,288 $ 16,040
======= ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE>
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
------------------------
1999 1998
--------- -------------
(In Thousands)
(Predecessor)
<S> <C> <C>
Gas plant, at cost.................................... $ 390,447 $ 389,777
Construction work-in-progress......................... 2,914 7,136
Less-Accumulated depreciation....................... (109,628) (102,936)
--------- ---------
Net plant......................................... 283,733 293,977
--------- ---------
Non-Utility Property, Net............................. -- 6,948
--------- ---------
Current assets:
Cash................................................ 389 3,125
Accounts receivable, less reserves of $2,677 at
December 31, 1999 and $2,551 at December 31, 1998.. 15,987 13,241
Accrued utility margin.............................. 8,074 7,876
Deferred gas costs.................................. 13,803 18,195
Natural gas and other inventories, at average cost.. 11,581 12,712
Materials and supplies, at average cost............. 2,277 2,906
Current income taxes................................ 4,182 --
Prepaid expenses.................................... 330 9,513
--------- ---------
Total current assets.............................. 56,623 67,568
--------- ---------
Other assets:
Excess of cost over fair value of acquired net
assets, less amortization.......................... 239,045 --
Deferred charges and other assets................... 4,646 32,511
--------- ---------
Total other assets................................ 243,691 32,511
--------- ---------
Total assets...................................... $ 584,047 $ 401,004
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
December 31,
----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
<S> <C> <C>
Capitalization:
Common stockholder's investment--
Common stock, $1 par value--
Authorized and outstanding--100 shares at December
31, 1999............................................. $ -- $ --
Common Stock, $3.33 par value--
Authorized shares--15,000,000 at December 31, 1998;
Issued shares--8,910,000 at December 31, 1998......... -- 29,669
Amounts in excess of par value........................ 225,667 63,080
Retained earnings..................................... 229 36,173
-------- --------
Total common stockholder's investment............... 225,896 128,922
Long-term obligations, less current portion............. 121,021 120,963
-------- --------
Total capitalization................................ 346,917 249,885
-------- --------
Advances from parent company............................ 100,000 --
-------- --------
Current liabilities:
Current portion of long-term obligations.............. 646 722
Notes payable......................................... 29,000 52,000
Gas inventory financing............................... 15,009 14,125
Accounts payable...................................... 16,578 12,186
Accounts payable--affiliates.......................... 17,916 --
Accrued interest...................................... 2,936 2,698
Customer deposits..................................... 644 818
Refunds due customers................................. 5,331 --
Other................................................. 389 7,034
-------- --------
Total current liabilities........................... 88,449 89,583
-------- --------
Reserves and deferred credits:
Unrecovered deferred income taxes..................... -- 8,349
Deferred income taxes................................. 32,276 44,555
Unamortized investment tax credits.................... 2,811 3,072
Postretirement benefits obligation.................... 5,136 --
Other................................................. 8,458 5,560
-------- --------
Total reserves and deferred credits................. 48,681 61,536
-------- --------
Total capitalization and liabilities................ $584,047 $401,004
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Balance at beginning of
period................. $ -- $36,173 $ 35,924 $ 31,319
Net earnings.......... 2,713 4,520 12,288 16,040
Cash dividends on
common stock......... (2,484) (6,255) (12,039) (11,435)
------- ------- -------- --------
Balance at end of
period................. $ 229 $34,438 $ 36,173 $ 35,924
======= ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Cash flows from
operating activities:
Net earnings........... $ 2,713 $ 4,520 $ 12,288 $ 16,040
Adjustments to
reconcile net earnings
to cash provided by
operating activities:
Depreciation and
amortization......... 4,865 10,086 14,764 13,334
Deferred taxes........ 404 (12,683) 3,157 3,208
Other changes in
assets and
liabilities:
Accounts receivable.. (4,548) 1,802 5,344 (3,581)
Accrued utility
margin.............. (7,420) 7,222 (459) (1,084)
Accounts payable--
affiliates.......... 15,084 2,832 -- --
Inventories.......... 1,120 640 247 (1,001)
Deferred gas costs... (13,888) 18,280 1,071 (28)
Accounts payable..... 5,666 (1,274) (3,488) 1,130
Federal and state
income taxes........ (3,406) (776) (2,164) 2,708
Refunds due
customers........... (202) 5,533 (669) 1,445
Other................ (7,279) 17,351 (648) (538)
-------- -------- -------- --------
Cash (used for)
provided by
operating
activities......... (6,891) 53,533 29,443 31,633
-------- -------- -------- --------
Cash flows from
investing activities:
Capital expenditures... (7,105) (12,715) (31,457) (37,676)
-------- -------- -------- --------
Cash flows from
financing activities:
Changes in notes
payable, net.......... 10,000 (33,000) 2,600 (1,000)
Changes in inventory
financing............. 4,139 (3,255) (770) 1,856
Issuance of long-term
debt, net of issuance
cost.................. -- -- 39,116 14,871
Retirement of long-term
debt, including
premiums.............. -- (102) (30,568) (5,152)
Issuance of common
stock................. -- 1,399 6,541 3,621
Cash dividends paid on
common stock.......... (2,484) (6,255) (12,039) (11,435)
-------- -------- -------- --------
Cash provided by
(used for)
financing
activities......... 11,655 (41,213) 4,880 2,761
-------- -------- -------- --------
Increase (decrease) in
cash................... (2,341) (395) 2,866 (3,282)
Cash at beginning of
period................. 2,730 3,125 259 3,541
-------- -------- -------- --------
Cash at end of period... $ 389 $ 2,730 $ 3,125 $ 259
======== ======== ======== ========
Supplemental disclosure
of cash flow
information:
Cash paid during the
year for:
Interest, net of
amounts
capitalized........ $ 1,657 $ 8,434 $ 10,229 $ 9,465
Income taxes........ $ 4,376 $ 3,595 $ 7,238 $ 7,509
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
General
The Company is a gas distribution company engaged in the transportation and
sale of natural gas to residential, commercial and industrial customers. The
Company's service territory includes 24 municipalities located northwest of
Boston and on Cape Cod.
Principles of Consolidation
The Company is a wholly-owned subsidiary of Eastern Enterprises
("Eastern"). The consolidated financial statements include the accounts of the
Company and its affiliate, Massachusetts Fuel Inventory Trust and, for periods
prior to August 31, 1999 ("Predecessor Financial Statements"), the operations
of Colonial Gas Company, its affiliate, Massachusetts Fuel Inventory Trust,
and a wholly-owned subsidiary, Transgas Inc. The Predecessor Financial
Statements have been prepared using the historical cost of the Company's
assets and have not been adjusted to reflect the merger with Eastern. However,
certain accounts for the prior periods have been reclassified to conform to
the presentation as of December 31, 1999. Transgas ceased to be a subsidiary
of Colonial Gas Company and became a subsidiary of Eastern upon closing of the
merger. All material intercompany balances and transactions between the
Company and its subsidiary have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Merger
On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In
effecting the transaction, Eastern paid $150 million in cash, net of cash
acquired and including transaction costs, issued approximately 4.2 million
shares of common stock valued at $186 million and assumed $138 million of
debt.
The Colonial merger was accounted for using the purchase method of
accounting for business combinations. The purchase price was allocated to the
net assets acquired based on their fair value. The historical cost basis of
Colonial's assets and liabilities, with the exception of the adjustments
described below, was determined to represent the fair value due to the
existence of a regulatory-approved rate plan based upon the recovery of
historical costs and a fair return thereof. Most of the operations of the
Company have been integrated into the operations of its affiliate, Boston Gas,
a wholly-owned subsidiary of Eastern.
In connection with the merger, the Department of Telecommunications and
Energy (the "Department") approved a rate plan resulting in a ten year freeze
of base rates at current levels. As part of the approved rate plan, the
Company will be charged by Boston Gas for incremental costs incurred by Boston
Gas on behalf of the Company. Due to the length of the base rate freeze, the
Company was required to discontinue its application of Statement of Financial
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain
Types of Regulation".
Accordingly, as of the merger, the Company assigned no value to regulatory
assets of approximately $18 million, consisting principally of deferred demand
side management program costs, deferred environmental costs and unrecovered
deferred income taxes.
F-7
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
In addition, the Company assigned no value to information systems and
computer equipment approximating $15 million, which were no longer used or
useful, as the Company has integrated the majority of its information
technology software applications into those of Boston Gas. Also, the Company
recorded merger-related costs of approximately $10 million consisting
primarily of severance, early retirement, change in control costs, investment
banking fees and a software license termination fee, and recorded a liability
equal to the pension and other post retirement benefit obligations in excess
of the market value of plan assets of $6 million.
The allocation of the purchase price remains subject to adjustment upon
final valuation of certain acquired balances. The excess of consideration over
the fair value of the assets acquired of $241 million has been recorded as
goodwill, which is being amortized on a straight-line basis over a 40-year
period. Of the $241 million, $141 million was recorded as an increase to
common equity and $100 million as advances from the parent company.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities.
For the periods prior to the approval of the merger and rate plan, the
accounting policies conformed to generally accepted accounting principles as
applied to regulated public utilities and reflected the effects of the
ratemaking process in accordance with SFAS No. 71. Under SFAS No. 71, the
Company was allowed to defer certain costs that otherwise would be expensed in
recognition of the ability to recover them in future rates. As described
above, the Company discontinued application of SFAS No. 71 as a result of the
rate plan approved by the Department in connection with its approval of the
merger of the Company with Eastern.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years after the DSM measures are installed. The ruling will change the
Company's previous calculation method as approved by the Department in the
Company's previous filings. However, based on the Department's order approving
the merger and rate plan, the Company can recover the resulting decrease in
lost margins as an exogenous adjustment.
Gas Operating Revenues
Gas operating revenues are accrued based upon the amount of gas delivered
to customers through the end of the accounting period. Accrued Utility Margin
of $8,074,000 and $7,876,000, as reported in the Consolidated Balance Sheets
at December 31, 1999 and 1998, respectively, represents the accrual of
unbilled operating revenues net of related gas costs. The Company records lost
margins and incentives assocated with the Company's DSM programs as revenue
when earned and therefore billable by the Company.
Depreciation
Depreciation is provided at rates designed to amortize the cost of
depreciable property, plant and equipment over their estimated remaining
useful lives. The composite depreciation rate, expressed as a percentage of
the average depreciable property in service, is 3.7% for all periods
presented.
Accumulated depreciation is charged with original cost and the cost of
removal, less salvage value, of units retired. Expenditures for repairs,
upkeep of units of property and renewal of minor items of property replaced
independently of the unit of which they are a part are charged to maintenance
expense as incurred.
F-8
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
Pending Accounting Changes
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by SFAS No. 137, is effective for fiscal quarters of
all fiscal years beginning after June 15, 2000. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or a liability measured at
its fair value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting. The Company has not yet quantified the impact of adopting SFAS No.
133 on the consolidated financial statements. However, SFAS No. 133 could
increase volatility in earnings and other comprehensive income.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
(2) Cost of Gas Adjustment Clause and Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires the Company to semi-
annually adjust its rates for firm gas sales in order to track changes in the
cost of gas distributed, with an annual adjustment of subsequent rates for any
over or under recovery of actual costs incurred. As a result, the Company
defers the cost of any firm gas that has been distributed, but is unbilled at
the end of a period, to the period in which the gas is billed to customers.
In its Order of August 14, 1998, the Department modified the CGAC to
recover the gas cost portion of the Company's bad debt write-offs effective
November 1, 1998. The order also approved a local distribution adjustment
clause ("LDAC") to recover the amortization of all environmental response
costs associated with former manufactured gas plant ("MGP") sites, FERC Order
636 transition costs, and costs related to the Company's various demand side
management programs from the Company's firm sales and transportation
customers. These costs were previously recovered through the CGAC. Upon the
discontinuance of the application of SFAS No. 71, the Company records amounts
recoverable under the LDAC as revenue when billable to its customers.
(3) Income Taxes
Since its acquisition, the Company is a member of an affiliated group of
companies that files a consolidated federal income tax return. The Company's
effective income tax rate was 49% in 1999, 37% in 1998, and 38% in 1997. State
taxes and the nondeductibility of goodwill amortization after September 1,
1999, represent the majority of the difference between the effective rate and
the federal income tax rate of 35% for 1999, and state taxes represent the
majority of the difference for 1998 and 1997.
F-9
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
A summary of the provision for income taxes is as follows:
<TABLE>
<CAPTION>
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, ---------------------------
1999 1999 1998 1997
------------ ------------- ------------- -------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Current--
Federal............... $1,028 $5,344 $3,827 $5,188
State................. 180 1,046 718 1,228
------ ------ ------ ------
Total Current
Provision.......... 1,208 6,390 4,545 6,416
------ ------ ------ ------
Deferred--
Federal............... 1,800 (2,328) 2,387 3,376
State................. 398 (423) 503 480
------ ------ ------ ------
Total Deferred
Provision.......... 2,198 (2,751) 2,890 3,856
------ ------ ------ ------
Amortization of
investment tax credit.. -- -- (301) (300)
------ ------ ------ ------
Provision for income
taxes.................. $3,406 $3,639 $7,134 $9,972
====== ====== ====== ======
</TABLE>
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. Income tax
credits are deferred and credited to income over the lives of the property
giving rise to such credits.
For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives, as permitted by the Internal Revenue Code.
Deferred federal and state taxes are provided for the tax effects of all
temporary differences between financial reporting and taxable income.
Significant items making up deferred tax assets and liabilities at December
31, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
December 31,
-----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
<S> <C> <C>
Assets:
Total deferred tax assets........................... $ 1,077 $ 1,054
-------- --------
Liabilities:
Accelerated Depreciation.............................. (37,813) (43,662)
Deferred Gas Costs.................................... (748) (3,830)
Other................................................. 5,683 (10,296)
-------- --------
Total deferred tax liabilities...................... (32,878) (57,788)
-------- --------
Total net deferred taxes............................ $(31,801) $(56,734)
======== ========
</TABLE>
F-10
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Commitments
Long-term Obligations
The following table provides information on long-term obligations as of:
<TABLE>
<CAPTION>
December 31,
-----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
<S> <C> <C>
First Mortgage Bonds:
8.80%, Series CH, due 2022........................... $ 25,000 $ 25,000
6.38%--6.94%, Medium-Term Notes, Series A, due 2008--
2027................................................ 65,000 65,000
5.50%--6.86%, Medium-Term Notes, Series B, due 2003--
2028................................................ 30,000 30,000
Capital lease obligations (Note 6)..................... 1,667 1,583
Note payable........................................... -- 102
Less current portion................................... (646) (722)
-------- --------
$121,021 $120,963
======== ========
</TABLE>
The Company currently has a shelf registration covering the issuance of up
to $75,000,000 of Medium-Term Notes, of which $30,000,000 of Medium-Term
Notes, Series B have been issued.
Bonds of $10,000,000 are due in 2003. Bonds of $15,000,000 due in 2027 can
be redeemed by the holder in 2002. Bonds of $20,000,000 due in 2025 can be
redeemed by the holder in 2005. Bonds of $20,000,000 due in 2028 can be
redeemed by the holder in 2008.
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.
Annual maturities of capital lease obligations are $646,000, $499,000,
$337,000, $154,000, and $31,000 for 2000 through 2004, respectively.
Short-Term Debt and Lines of Credit
The Company maintains a bank line of credit with a consortium of four banks
which expires in September, 2000. 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 three alternative
rates: Eurodollar (LIBOR), prime, or a competitive bid option. At December 31,
1999, the credit available under the bank line of credit was $30,991,000. The
weighted average interest rate on these borrowings was 6.66% and 5.80% at
December 31, 1999 and 1998, respectively.
Gas Inventory Financing
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 financing costs incurred. 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 Department has
approved the inventory trust arrangement and has allowed the cost of such gas
inventory, including fees and financing costs, to be recovered through the
Company's CGAC.
F-11
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits
Effective January 1, 1999, the Company adopted SFAS No. 132, "Employers'
Disclosures about Pensions and Other Post-retirement Benefits," which revises
prior disclosure requirements. Previous information has been restated to
conform to the current presentation.
Pension Plans
The Company has defined benefit pension plans covering substantially all
employees. These include two qualified union plans, one qualified plan for
non-union employees, and various unqualified individual retirement agreements
covering certain key employees and retirees. The Company's funding policy for
the qualified plans 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. The net periodic pension cost was as follows:
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
<S> <C> <C> <C> <C>
<CAPTION>
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Service cost............ $ 243 $ 850 $ 1,220 $ 1,042
Interest cost on
projected benefits
obligations............ 1,239 2,447 3,492 3,427
Expected return on plan
assets................. (1,302) (2,977) (4,170) (3,638)
Amortization of prior
service cost........... -- 97 161 196
Amortization of
transitional
obligation............. -- 238 357 357
Recognized actuarial
loss................... -- 96 107 47
Curtailment............. -- 295 -- --
------- ------- ------- -------
Total net pension cost.. $ 180 $ 1,046 $ 1,167 $ 1,431
======= ======= ======= =======
</TABLE>
Postretirement Life and Health Care
The Company has 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.
Beginning in 1990, the Company has funded a portion of these costs through
the combination of trusts under Section 501(c)(9) and Section 401(h) of the
Internal Revenue Code.
Net periodic expense for postretirement benefits other than pensions was as
follows:
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
<S> <C> <C> <C> <C>
<CAPTION>
(Predecessor) (Predecessor) (Predecessor)
<S> <C> <C> <C> <C>
Service cost............ $ 39 $ 94 $ 138 $ 113
Interest cost on
accumulated benefits
obligations............ 247 400 534 477
Expected return on plan
assets................. (127) (292) (412) (375)
Amortization of
transition obligation.. -- 166 249 270
Recognized actual gain.. -- -- -- (75)
Curtailment............. -- 308 -- --
----- ----- ----- -----
Total net retiree health
care cost.............. $ 159 $ 676 $ 509 $ 410
===== ===== ===== =====
</TABLE>
F-12
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The tables above do not reflect retirement enhancements for pension and
health care of $2,667,000 and $33,000, respectively for the eight months ended
August 31, 1999.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's pension plans and
amounts recorded in the Company's balance sheet as of December 31, 1999,
August 31, 1999 and December 31, 1998. Actuarial measurement dates are October
1, 1999, August 31, 1999 and December 31, 1998, respectively.
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- -------------
(In Thousands)
(Predecessor) (Predecessor)
<S> <C> <C> <C>
Pensions
- --------
Change in benefit obligation
Balance at beginning of period....... $53,805 $53,132 $50,989
Service cost......................... 243 850 1,220
Interest cost........................ 1,239 2,447 3,492
Plan amendments...................... -- -- 177
Curtailment loss..................... -- 557 --
Special termination benefits......... -- 2,667 --
Benefits paid........................ (1,152) (2,045) (3,139)
Subsidiary spun-off.................. -- (2,557) --
Actuarial (gain) loss................ (1,149) (1,246) 393
------- ------- -------
Balance at end of period............. $52,986 $53,805 $53,132
======= ======= =======
Change in plan assets
Fair value, beginning of period...... $50,055 $51,839 $48,332
Actual return on plan assets......... (486) 1,564 5,161
Employer contributions............... 67 569 1,484
Benefits paid........................ (1,152) (2,045) (3,138)
Subsidiary spun-off.................. -- (1,872) --
------- ------- -------
Fair value at end of period.......... $48,484 $50,055 $51,839
======= ======= =======
Reconciliation of funded status
Funded status........................ $(4,502) $(3,750) $(1,293)
Contributions for fourth quarter..... 158 -- --
Unrecognized actuarial loss.......... 640 -- 102
Unrecognized transition obligation... -- -- 1,747
Unrecognized prior service........... -- -- 1,830
------- ------- -------
Net amount recognized at end of
period.............................. $(3,704) $(3,750) $ 2,386
======= ======= =======
Amounts recognized in balance sheet
Prepaid benefit cost................. $ 130 $ 92 $ 2,442
Accrued benefit liability............ (3,904) (3,842) (3,228)
Intangible asset..................... -- -- 2,126
Accumulated other comprehensive
income.............................. 70 -- 1,046
------- ------- -------
Net amount........................... $(3,704) $(3,750) $ 2,386
======= ======= =======
</TABLE>
F-13
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Assets of the employee benefit plans are invested in domestic and
international equities, domestic and international fixed income securities,
real estate and other short-term debt instruments.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's post-retirement
life and health benefit plans and amounts recorded in the Company's balance
sheet as of December 31, 1999, August 31, 1999 and December 31, 1998.
Actuarial measurement dates are October 1, 1999, August 31, 1999 and December
31, 1998, respectively.
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- -------------
(In Thousands)
(Predecessor) (Predecessor)
<S> <C> <C> <C>
Healthcare
- ----------
Change in benefit obligation
Balance at beginning of period....... $10,235 $ 8,558 $ 7,179
Service cost......................... 39 94 138
Interest Cost........................ 247 400 534
Amendments........................... -- -- (315)
Curtailment gain..................... -- (270) --
Special termination benefits......... -- 33 --
Benefits paid........................ (49) (278) (251)
Subsidiary spun-off.................. -- (586) --
Actuarial loss....................... 289 2,284 1,273
------- ------- -------
Balance at end of period............. $10,761 $10,235 $ 8,558
======= ======= =======
Change in plan assets
Fair value, beginning of period...... $ 5,363 $ 5,439 $ 5,163
Actual return on plan assets......... (141) 245 527
Employer contributions............... -- 252 --
Benefits paid........................ (50) (278) (251)
Subsidiary spun-off.................. -- (295) --
------- ------- -------
Fair value, end of period............ $ 5,172 $ 5,363 $ 5,439
======= ======= =======
Reconciliation of funded status
Funded status........................ $(5,589) $(4,872) $(3,119)
Unrecognized actuarial (gain) or
loss................................ 558 -- (193)
Unrecognized transition obligation... -- -- 3,481
Unrecognized prior service........... -- -- --
------- ------- -------
Net amount recognized at end of
period.............................. $(5,031) $(4,872) $ 169
======= ======= =======
Amounts recognized in balance sheet
Prepaid benefit cost................. $ -- $ -- $ 169
Accrued benefit liability............ (5,031) (4,872) --
------- ------- -------
Net amount........................... $(5,031) $(4,872) $ 169
======= ======= =======
</TABLE>
F-14
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
<TABLE>
<CAPTION>
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- ------------
(Predecessor) (Predecessor)
<S> <C> <C> <C>
Discount rate......................... 7.5% 7.5% 7.0%
Return on plan assets................. 8.5% 8.5% 9.5%
Increase in future compensation....... 4.5% 4.5% 4.0%
Health care inflation trend........... 8.0-10.0% 8.0-10.0% 6.0%
</TABLE>
The health care inflation rate for 2000 is assumed to be 8.0% and 10.0% for
pre-65 and post-65 health care benefits, respectively. The rate is assumed to
decrease gradually to 5.0% in 2006 for pre-65 benefits (2008 for post-65
benefits) and remain at that level thereafter. A one percentage point increase
or decrease in the assumed health care trend rate for 1999 would have the
following effects:
<TABLE>
<CAPTION>
One-Percentage One-Percentage
Point Increase Point Decrease
-------------- --------------
(In Thousands)
<S> <C> <C>
Service cost and interest cost components......... $ 39 $ (33)
Post-retirement benefit obligation................ $1,258 $(1,048)
</TABLE>
(6) Leases
The Company leases certain equipment used in its operations. The Company
has capitalized certain of these leases and reflects lease payments as rental
expense in the periods to which they relate.
Total rental expense for the four months ended December 31, 1999 and eight
months ended August 31, 1999 approximated $265,000 and $545,000, respectively.
For the years ended December 31, 1998 and 1997, total rental expense
approximated $1,150,000 and $1,527,000, respectively.
The remaining minimum rental commitment for capital leases at December 31,
1999 is as follows:
<TABLE>
<CAPTION>
Year
---- (In Thousands)
<S> <C> <C>
2000...................................................... $ 670
2001...................................................... 550
2002...................................................... 401
2003...................................................... 205
2004...................................................... 40
Later years............................................... --
--------
Total minimum lease payments.............................. 1,866
Less--Amount representing interest and executory costs.... 199
--------
Present value of minimum lease payments on capital
leases................................................... $ 1,667
========
</TABLE>
(7) Fair Values of Financial Instruments
The following methods and assumptions were used to estimate the fair values
of financial instruments:
Cash--The carrying amounts approximate fair value.
F-15
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Fair Values of Financial Instruments (Continued)
Short-term Debt--The carrying amounts of the Company's short-term debt,
including notes payable and gas inventory financing, approximate their fair
value.
Long-term Debt--The fair value of long-term debt is estimated based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term
debt at December 31, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
1999 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands)
(Predecessor)
<S> <C> <C> <C> <C>
Long-term debt........................... $121,667 $116,462 $121,685 $130,885
</TABLE>
(8) Related Party Transactions
The Company paid Eastern $240,000 in 1999 for legal, tax and corporate
services rendered.
Included in the Consolidated Balance Sheet at December 31, 1999 is an
advance payable to Eastern in the amount of $100,000,000. Interest is charged
based on the quarterly short-term applicable federal rate issued by the
Internal Revenue Service and was 5.45% as of December 31, 1999.
Substantially all of the administrative functions and supporting
information technology systems are integrated with those of Boston Gas
Company, an affiliated company. As allowed by the Department, the Company is
charged for costs incrementally incurred to provide these services.
(9) Environmental Matters
The Company, like many other companies in the natural gas industry, is
party to governmental proceedings requiring investigation and possible
remediation of former manufactured gas plant ("MGP") and related sites. The
Company may have or share responsibility under applicable environmental laws
for the remediation of one former MGP site and related satellite disposal
sites, as well as one non-MGP site and a federal superfund site. The Company
has estimated its potential share of the costs of investigating and
remediating these sites in accordance with SFAS No. 5, "Accounting for
Contingencies," and the American Institute of Certified Public Accountants
Statement of Position 96-1, "Environmental Remediation Liabilities." The
Company has recorded a liability of approximately $850,000, which represents
its best estimate at this time of remediation costs. However, there can be no
assurance that actual costs will not vary considerably from this estimate.
Factors that may bear on actual costs differing from estimates include,
without limit, changes in regulatory standards, changes in remediation
technologies and practices and the type and extent of contaminants discovered
at the sites.
The Company has received and responded to Requests for Information from the
U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the
Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), regarding one federal superfund site that the EPA is currently
investigating. It is not possible at this time to reasonably estimate the
amount of the Company's obligation for remediation of the site; however, the
Company expects that its share, if any, will be de minimis.
By a rate order issued on May 25, 1990, the Department approved recovery of
all prudently incurred environmental response costs associated with former MGP
related sites over separate, seven-year amortization periods, without a return
on the unamortized balance. The Company currently believes, in light of the
Department
F-16
<PAGE>
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Environmental Matters (Continued)
rate order, that it is not probable that actual costs will materially affect
its financial condition or results of operations.
(10) Merger
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
(11) Commitments and Contingencies
The Company maintains employment agreements with certain employees. The
pending KeySpan merger is expected to trigger the change of control provisions
under these agreements which, in the event of a termination, provide for one
to three times salary and bonus as severance and, in certain circumstances, a
tax gross-up and enhanced retirement benefits. The maximum contingent
liability under these agreements is approximately $9 million.
F-17
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Colonial Gas Company:
We have audited the accompanying consolidated balance sheet of Colonial Gas
Company (a Massachusetts Corporation and wholly-owned subsidiary of Eastern
Enterprises) and subsidiary as of December 31, 1999, and the related
consolidated statements of income, retained earnings and cash flows for the
year then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audit. The
consolidated financial statements of Colonial Gas Company and subsidiaries as
of December 31, 1998, were audited by other auditors whose report dated
January 15, 1999, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provided a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Colonial Gas Company and
subsidiary as of December 31, 1999 and the results of its operations and its
cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
As discussed in Note 1, as a result of the merger, the approved rate plan
and related discontinuance of SFAS No. 71, the Company changed certain
accounting practices to comply with generally accepted accounting principles
for non-regulated entities.
Arthur Andersen LLP
Boston, Massachusetts
January 21, 2000
F-18
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To Colonial Gas Company:
We have audited the accompanying consolidated balance sheet of Colonial Gas
Company and subsidiaries as of December 31, 1998, and the related consolidated
statements of income, cash flows, and common equity for each of the two years
in the period ended December 31, 1998. 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 significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provided 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, 1998 and the consolidated results
of their operations and their consolidated cash flows for each of the two
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
Grant Thornton LLP
Boston, Massachusetts
January 15, 1999
F-19
<PAGE>
COLONIAL GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 1999 (Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Two Months One Month Three Months
-------------------------- Ended August Ended Ended
March 31 June 30 31 Sept. 30 Dec. 31
------------- ------------ ------------ --------- ------------
(Predecessor) (Predecessor) (Predecessor)
(In Thousands)
<S> <C> <C> <C> <C> <C>
1999
Operating revenues...... $87,994 $25,580 $ 9,052 $ 4,446 $49,652
Operating margin........ $39,451 $13,648 $ 4,207 $ 2,161 $25,850
Utility operating
earnings (loss)........ $16,535 $ (385) $(4,871) $(1,018) $ 8,880
Net earnings (loss)..... $13,716 $(2,797) $(6,399) $(2,276) $ 4,989
</TABLE>
<TABLE>
<CAPTION>
Three Months Ended
---------------------------
March 31 June 30 September 30 December 31
------------- ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor) (Predecessor)
(In Thousands)
<S> <C> <C> <C> <C>
1998
Operating revenues...... $77,822 $25,684 $12,347 $52,125
Operating margin........ $36,905 $12,022 $ 6,150 $24,774
Utility operating
earnings (loss)........ $16,075 $ 256 $(3,246) $ 6,647
Net earnings (loss)..... $14,212 $(1,771) $(5,213) $ 5,060
</TABLE>
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.
F-20
<PAGE>
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Four Months Ended December 31, 1999
(In Thousands)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
September 1, (Credited) to Other from December 31,
Description 1999 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............ $3,168 $344 $ -- $ 835 $ 2,677
====== ==== ===== ===== =======
RESERVES INCLUDED IN
LIABILITIES:
Reserve for
postretirement
benefit cost........ $4,872 $159 $ -- $ -- $ 5,031
Reserve for self-
insurance........... 1,008 100 -- -- 1,108
Reserve for
environmental
expenses............ 200 -- 650 -- 850
Reserve for pension.. 3,842 180 -- 118 3,904
------ ---- ----- ----- -------
Total reserves
included in
liabilities....... $9,922 $439 $ 650 $ 118 $10,893
====== ==== ===== ===== =======
</TABLE>
F-21
<PAGE>
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Eight Months Ended August 31, 1999
(In Thousands)
(Predecessor)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from August 31,
Description 1998 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
assets:
Reserves for doubtful
accounts............ $2,551 $1,234 $ -- $ 617 $3,168
====== ====== ====== ====== ======
Reserves included in
liabilities:
Reserve for
postretirement
benefit cost........ $ -- $ 676 $4,196(1) $ -- $4,872
199
Reserve for self-
insurance........... 1,408 559 -- 760(2) 1,008
Reserve for
environmental
expenses............ 200 -- -- -- 200
Reserve for pension.. 3,228 1,046 137(1) 569 3,842
------ ------ ------ ------ ------
Total reserves
included in
liabilities....... $4,836 $2,281 $4,333 $1,528 $9,922
====== ====== ====== ====== ======
</TABLE>
- --------
(1) Recognition of added liability at acquisition, net of Transgas liability
spun off.
(2) Reserve Balance spun off from Transgas at acquisition.
F-22
<PAGE>
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
(Predecessor)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1997 to Income Accounts Reserves 1998
----------- ------------ ---------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............ $3,203 $ 654 $ -- $1,306 $2,551
====== ====== ==== ====== ======
RESERVES INCLUDED IN
LIABILITIES:
Reserve for self-
insurance........... $1,593 $ 237 $ -- $ 422 $1,408
Reserve for
environmental
expenses............ 707 -- -- 507 200
Reserve for pension.. 3,543 1,167 -- 1,482 3,228
------ ------ ---- ------ ------
Total reserves
included in
liabilities....... $5,843 $1,404 $ -- $2,411 $4,836
====== ====== ==== ====== ======
</TABLE>
F-23
<PAGE>
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
(In Thousands)
(Predecessor)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1996 to Income Accounts Reserves 1997
----------- ------------ ---------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
assets:
Reserves for doubtful
accounts............ $2,715 $1,956 $ -- $1,468 $3,203
====== ====== ===== ====== ======
Reserves included in
liabilities:
Reserve for self-
insurance........... $1,486 $ 675 $ -- $ 568 $1,593
Reserve for
environmental
expenses............ 1,183 -- -- 476 707
Reserve for pension.. 3,157 1,431 -- 1,045 3,543
------ ------ ----- ------ ------
Total reserves
included in
liabilities....... $5,826 $2,106 $ -- $2,089 $5,843
====== ====== ===== ====== ======
</TABLE>
F-24
<PAGE>
EXHIBIT 3.1
D
/s/ [ILLEGIBLE]
- --------
Examiner The Commonwealth of Massachusetts
William Francis Galvin
Secretary of the Commonwealth
One Ashburton Place, Boston, Massachusetts 02108-1512
ARTICLES OF ORGANIZATION
(General Laws, Chapter 164)
CC
- --------
Name
Approved
ARTICLE I
The exact name of the corporation is:
COLONIAL GAS COMPANY
ARTICLE II
The purpose of the corporation is to engage in the following
business activities:
See attached Continuation Sheet 2.
C |_|
P |X|
M |_|
R.A. |_|
9
- ----
P.C.
Note: If the space provided under any article or item on this form is
insufficient, additions shall be set forth on one side only of separate 8 1/2 x
11 sheets of paper with a left margin of at least 1 inch. Additions to more than
one article may be made on a single sheet so long as each article requiring each
addition is clearly indicated.
<PAGE>
ARTICLE III
State the total number of shares and par value, if any, of each class of stock
which the corporation is authorized to issue.
- --------------------------------------------------------------------------------
WITHOUT PAR VALUE WITH PAR VALUE
- --------------------------------------------------------------------------------
TYPE NUMBER OF SHARES TYPE NUMBER OF SHARES PAR VALUE
- --------------------------------------------------------------------------------
Common: Common: 200,000 $1.00
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Preferred: Preferred:
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
ARTICLE IV
If more than one class of stock is authorized, state a distinguishing
designation for each class. Prior to the issuance of any shares of a class, if
shares of another class are outstanding, the corporation must provide a
description of the preferences, voting powers, qualifications, and special or
relative rights or privileges of that class and of each other class of which
shares are outstanding and of each series then established within any class.
N/A
ARTICLE V
The restrictions, if any, imposed by the Articles of Organization upon the
transfer of shares of stock of any class are:
None.
ARTICLE VI
"Other lawful provisions, if any, for the conduct and regulation of the business
and affairs of the corporation, for its voluntary dissolution, or for limiting,
defining, or regulating the powers of the corporation, or of its directors or
stockholders, or of any class of stockholders:
See attached Continuation Sheets 6A, 6B and 6C.
**If there are no provisions state "None".
Note: The preceding six (6) articles are considered to be permanent and may ONLY
be charged by filing appropriate Articles of Amendment.
<PAGE>
CONTINUATION SHEET 2
To engage in business as a gas utility company in any city or town of the
Commonwealth of Massachusetts; to exercise any and all rights, powers, licenses,
permits, privileges, authorizations and franchises at any time possessed by the
corporation or by any predecessor or constituent corporation; to engage in any
activity in any way connected with, incident to or in furtherance of the
foregoing activities; to engage in any other activity lawful for a corporation
subject to Chapter 164 of the Massachusetts General Laws; to engage in any
business, operation or activity through a wholly or partly owned subsidiary; and
to engage in any business, operation or activity referred to above to the same
extent as might an individual, whether as principal, agent, contractor or
otherwise, and either alone or in conjunction or a joint venture or other
arrangement with any corporation, association, trust, firm or individual.
<PAGE>
CONTINUATION SHEET 6A
BY-LAWS
The directors may make, amend or repeal the by-laws in whole or in part, except
with respect to any provision thereof which by law or the by-laws requires
action by the stockholders.
STOCKHOLDERS MEETINGS
Meetings of the stockholders may be held anywhere in the United States.
RELIANCE UPON BOOKS OF ACCOUNT, ETC.
Each director and officer of the corporation shall, in the performance of his
duties, be fully protected in relying in good faith upon the books of account of
the corporation, reports made to the corporation by any of its officers or
employees or by counsel, accountants, appraisers or other experts or consultants
selected with reasonable care by the directors, or upon other records of the
corporation.
CERTAIN TRANSACTIONS
The directors shall have the power to fix from time to time their compensation.
No person shall be disqualified from holding any office by reason of any
interest. In the absence of fraud, any director, officer or stockholder of this
corporation individually, or any individual having any interest in any concern
which is a stockholder of this corporation, or any concern in which any such
directors, officers, stockholders or individuals have any interest, may be a
party to, or may be pecuniarily or otherwise interested in, any contract,
transaction or other act of this corporation, and
(1) such contract, transactions or act shall not be in any way
invalidated or otherwise affected by that fact;
(2) no such director, officer, stockholder or individual shall be liable
to account to this corporation for any profit or benefit realized
through any such contract, transaction or act; and
(3) any such director of this corporation may be counted in determining
the existence of a quorum at any meeting of the directors or of any
committee thereof which shall authorize any such contract,
transaction or act, and may vote to authorize the same;
<PAGE>
CONTINUATION SHEET 6B
provided, however, that any contract, transaction or act in which any director
or officer of this corporation is so interested individually or as a director,
officer, trustee or member of any concern which is not a subsidiary or affiliate
of this corporation, or in which any directors or officers are so interested as
holders, collectively, of a majority of shares of capital stock or other
beneficial interest at the time outstanding in any concern which is not a
subsidiary or affiliate of this corporation, shall be duly authorized or
ratified by a majority of the directors who are not so interested and to whom
the nature of such interest has been disclosed;
the term "interest" including personal interest and interest as a
director, officer, stockholder, shareholder, trustee, member or
beneficiary of any concern;
the term "concern" meaning any corporation, association, trust,
partnership, firm, person or other entity other than this corporation; and
the phrase "subsidiary or affiliate" meaning a concern in which a majority
of the directors, trustees, partners or controlling persons are elected or
appointed by the directors of this corporation, or are constituted of the
directors or officers of this corporation.
To the extent permitted by law, the authorizing or ratifying vote of a majority
in interest of each class of the capital stock of this corporation outstanding
and entitled to vote for directors at any annual meeting or a special meeting
duly called for the purpose (whether such vote is passed before or after
judgment rendered in a suit with respect to such contract, transaction or act)
shall validate any contract, transaction or act of this corporation, or of the
board of directors or any committee thereof, with regard to all stockholders of
this corporation, whether or not of record at the time of such vote, and with
regard to all creditors and other claimants under this corporation;
provided, however, that with respect to the authorization or ratification
of contracts, transactions or acts in which any of the directors, officers
or stockholders of this corporation have an interest, the nature of such
contracts, transactions or acts and the interest of any director, officer
or stockholder therein shall be summarized in the notice of any such
annual or special meeting, or in a statement or letter accompanying such
notice, and shall be fully disclosed at any such meeting;
provided, also, that stockholders so interested may vote at any such
meeting; and
<PAGE>
CONTINUATION SHEET 6C
provided, further, that any failure of the stockholders to authorize or ratify
such contract, transaction or act not be deemed in any way to invalidate the
same or to deprive this corporation, its directors, officers or employees of its
or their right to proceed with such contract, transaction or act.
No contract, transaction or act shall be avoided by reason of any provision of
this paragraph which would be valid but for those provisions.
PARTNERSHIP
The corporation may be a partner in any business enterprise which the
corporation would have power to conduct by itself.
<PAGE>
CONTINUTATION SHEET 8b
CG ACQUISITION GAS COMPANY
Officers & Director
Name Resident Address Post Office Address
---- ---------------- -------------------
President Walter J. Flaherty 76 Old Post Road Eastern Enterprises
East Walpole, MA 02032 9 Riverside Road
Weston, MA 02493
Treasurer Jean A. Scholtens 2 Rice Spring Lane Eastern Enterprises
Wayland, MA 01778 9 Riverside Road
Weston, MA 02493
Clerk L. William Law, Jr. 75 Bacon Street Eastern Enterprises
Winchester, MA 01890 9 Riverside Road
Weston, MA 02493
Assistant W. Brett Davis 6 Wellington Street Eastern Enterprises
Clerk Boston, MA 02118 9 Riverside Road
Weston, MA 02493
Director Walter J. Flaherty 76 Old Post Road Eastern Enterprises
East Walpole, MA 02032 9 Riverside Road
Weston, MA 02493
<PAGE>
ARTICLE VII
The effective date of organization of the corporation shall be the date approved
and filed by the Secretary of the Commonwealth. If a later effective date is
desired, specify such date which shall not be more than thirty days after the
date of filing.
N/A
ARTICLE VIII
The information contained in Article VIII is not a permanent part of the
Articles of Organization.
a. The street address (post office boxes are not acceptable) of the principal
office of the corporation in Massachusetts is:
c/o Boston Gas Company, One Beacon Street, Boston, MA 02108
b. The name, residential address and post office address of each director and
officer of the corporation is as follows:
NAME RESIDENTIAL ADDRESS POST OFFICE ADDRESS
President:
Treasurer:
Clerk: See attached Continuation Sheet 8b.
Directors:
c. The fiscal year (i.e., tax year) of the corporation shall end on the last day
of the month of: December
d. The name and business address of the resident agent, if any, of the
corporation is: N/A
e. The date fixed by the by-laws for the annual meeting of Stockholders is:
2nd Thursday in March unless otherwise determined by the Board of Directors.
ARTICLE IX
By-laws of the corporation have been duly adopted and the president, treasurer,
clerk and directors whose names are set forth above, have been duly elected.
IN WITNESS WHEREOF AND UNDER THE PAINS AND PENALTIES OF PERJURY, I/we, whose
signature(s) appear below as incorporator(s) and whose name(s) and business or
residential address(es) are clearly typed or printed beneath each signature do
hereby associate with the intention of forming this corporation under the
provisions of General Laws, Chapter 164 and do hereby sign these Articles of
Organization as incorporator(s) this 5th day of August, 1999.
/s/ L. William Law, Jr., Esq.
- --------------------------------------------------------------------------------
L. William Law, Jr., Esq.
- --------------------------------------------------------------------------------
c/o Eastern Enterprises
- --------------------------------------------------------------------------------
9 Riverside Road
- --------------------------------------------------------------------------------
Weston, MA 02493
- --------------------------------------------------------------------------------
Note: If an existing corporation is acting as incorporator, type in the exact
name of the corporation, the state or other jurisdiction where it was
incorporated, the name of the person signing on behalf of said corporation and
the title he/she holds or other authority by which such action is taken.
<PAGE>
THE COMMONWEALTH OF MASSACHUSETTS
ARTICLES OF ORGANIZATION
(General Laws, Chapter 164)
========================================================
I hereby certify that, upon examination of these
Articles of Organization, duly submitted to me, it
appears that the provisions of the General Laws relative
to the organization of corporations have been complied
with, and I hereby approve said articles; and the filing
fee in the amount of $200 having been paid, said
articles are deemed to have been filed with me this 6th
day of August 1999.
Effective date: ________________________________________
/s/ William Francis Galvin
WILLIAM FRANCIS GALVIN
Secretary of the Commonwealth
FILING FEE: One tenth of one percent of the total
authorized capital stock, but not less than $200.00. For
the purpose of filing, shares of stock with a par value
less than $1.00, or no par stock, shall be deemed to
have a par value of $1.00 per share.
TO BE FILLED IN BY CORPORATION
Photocopy of document to be sent to:
W. Brett Davis, Esq.
-------------------------------------------
c/o Eastern Enterprises
-------------------------------------------
9 Riverside Road
-------------------------------------------
Weston, MA 02493
-------------------------------------------
Telephone: (781) 647-2300
--------------------------------
<PAGE>
Exhibit 3.2
BY-LAWS
of
COLONIAL GAS COMPANY
Section 1. ARTICLES OF ORGANIZATION
The name and purposes of this corporation shall be set forth in the
Articles of Organization, as amended and restated from time to time. These
By-laws, the powers of the corporation and of its directors and stockholders, or
of any class of stockholders if the corporation has more than one class of
stock, and all matters concerning the conduct and regulation of the business and
affairs of the corporation shall be subject to such provisions. In regard
thereto, if any, as are set fort in the Articles of Organization as from this
to time in effect.
Section 2 STOCKHOLDERS
2.1. Annual Meeting. The annual meeting of stockholders shall be held at
ten o'clock in the forenoon on the second Thursday in March in each year
(unless that day be a legal holiday at the place where the meeting is to be
held, in which case the meeting shall be held at the same hour on the next
succeeding day not a legal holiday) or at such other date and time as shall be
determined from time to time by the board of directors. Purposes for which an
annual meeting is to be held, in addition to those prescribed by law, by the
Articles of Organization or by these By-laws, may be specified by the president
or by the directors.
No change in the date fixed in these By-laws for the annual meeting shall
be made within sixty days before the date stated herein. Notice of any change in
the date fixed in these By-laws for the annual meeting shall be given to all
stockholders at least twenty days before the new date fixed for such meeting.
2.2. Special Meeting in Place of Annual Meeting. If no annual meeting has
been held in accordance with the foregoing provisions, a special meeting of the
stockholders may be held in place thereof, and any action taken at such special
meeting shall have the same force and effect as if taken at the annual meeting,
and in such case all references in these By-laws to the annual meeting of the
stockholders shall be deemed to refer to such special meeting. Any such meeting
shall be called as provided in Section 2.3.
2.3. Special Meetings. A special meeting of the stockholders may be called
at any time by the president or by the directors. Each call of a meeting shall
state the place, date, hour end purposes of the meeting.
<PAGE>
2.4. Place of Meeting. All meetings of the stockholders shall be held at
the principal office of the corporation in Massachusetts or, to the extent
permitted by the Articles of Organization, at such other place within the
United States as shall be fixed by the president or the directors. Any adjourned
session of any meeting of the stockholders shall be held at the same city or
town as the initial session or at any other place at which meetings of the
stockholders may be held under the Articles of Organization and these By-laws,
in either case at the place designated by the vote of adjournment.
2.5. Notice of Meetings. A written notice of each meeting of
stockholders, stating the day and hour and the purposes of the meeting, shall be
given at least seven days before the meeting to each stockholder entitled to
vote at such meeting and to each stockholder who, by law, by the Articles of
Organization or by the By-laws, is entitled to notice, by leaving such notice
with such stockholder or at such stockholder's residence or usual place of
business, or by mailing it, postage prepaid, addressed to such stockholder at
such stockholder's address as it appears in the records of the corporation. Such
notice shall be given by the clerk or an assistant clerk or by an officer
designated by the director.. Whenever notice of a meeting is required to be
given to a stockholder under any provision of the Business Corporation Law of
The Commonwealth of Massachusetts or of the Articles of Organization or these
By-laws, a written waiver thereof executed before or after the meeting by such
stockholder or such stockholder's attorney thereunto authorized and filed with
the records of the meeting, shall be deemed equivalent to such notice.
2.6. Quorum of Stockholders. At any meeting of the stockholders, a
quorum as to any matter shall consist of a majority in interest of all stock
issued as outstanding and entitled to vote at the meeting; except that if two or
more classes or series of stock are entitled to vote as separate classes or
series, then in the case of each such class or series a quorum shall consists of
a majority in Interest of all stock of that class or series issued and
outstanding; and except when a larger quorum is required by law, by the Articles
of Organization or by these By-laws. Stock owned directly or indirectly by the
corporation, if any, shall not be deemed outstanding for this purpose. Any
meeting may be adjourned from time to time by a majority of the votes properly
cast upon the question, whether or not to quorum is present, and the meeting may
be held as adjourned without further notice.
2.7. Action by Vote. When a quorum is present at any meeting, a plurality
of the votes properly cast for election to any office shall elect to such
office, and a majority of the votes properly cast upon any question other than
an election to an office shall decide the question, except when a larger vote is
required by law, by the Articles of Organization or by these By-laws. No ballot
shall be required for any election unless requested by a stockholder present or
represented at the. meeting and entitled to vote in the election.
2.8. Voting. Stockholders entitled to vote shall have one vote for each
share of stock entitled to vote held by them of record according to the records
of the corporation, unless otherwise provided by the Articles of Organization.
The corporation shall not, directly or indirectly, vat any share of its own
stock.
-2-
<PAGE>
2.9. Action by Writing. Any action required or permitted to be taken at
any meeting of the stockholders may be taken without a meeting if all
stockholders entitled to vote on the matter consent to the action in writing and
the written consents are filed with the records of the meetings of stockholders.
Such consents shall be treated for all purposes as a vote at a meeting.
2.10. Proxies. To the extent permitted by law, stockholders entitled to
vote may vote either in person or by proxy In writing, which proxies shall be
filed with the clerk or other person responsible to record the proceeding, of
the meeting before being voted. Except to the extent permitted by law, no proxy
dated more than six months before the meeting named therein shall be valid.
Unless otherwise specifically limited by their terms, such proxies shall entitle
the holders of the proxies to vote at any adjournment of such meeting but shall
not be valid after the final adjournment of such meeting.
Section 3. BOARD OF DIRECTORS
3.1. Number. A board of not less than three directors shall be elected at
the annual meeting of the stockholders by such stockholders as have the right to
vote at such elections; provided, however, that the number of directors shall
be fixed at not less than two whenever the corporation shall have only two
stockholders and not less than one whenever the corporation shall have only one
stockholder. The number of directors may be increased at any time or from time
to time either by the stockholders or by the directors by vote of a majority of
the directors then in office. No director need be a stockholder.
3.2. Tenure. Except as otherwise provided by law, by the Articles of
Organization or by these By-laws, each director shall hold office until the next
annual meeting of the stockholders and until such director's successor is duly
elected and qualified, or until such director sooner dies, resigns, is removed
or becomes disqualified.
3.3. Powers. Except as reserved to the stockholders by law, by the
Articles of Organization or by these By-laws, the business of the corporation
shall be managed by the directors, who shall have and may exercise all the
powers of the corporation. In particular, and without limiting the generality of
the foregoing, the directors may at any time issue all or from time to time any
part of the unissued capital stock of the corporation from time to time
authorized under the Articles of Organization and may determine, subject to any
requirements of law, the consideration for which stock is to be issued and the
manner of allocating such consideration between capital and surplus.
3.4. Committees. The directors may, by vote of a majority of the directors
then in office, elect from their number an executive committee and other
committees and may by vote delegate to any such committee or committees some or
all of the powers of the directors except those which by law, by the Articles of
Organization or by these By-laws they are prohibited from delegating. Except as
the directors may otherwise determine, any such committee may
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<PAGE>
make rules for the conduct of its business, but unless otherwise provided by the
directors or such rules, its business shall be conducted in substantially the
same manner as is provided by these By-Laws for the conduct of business by the
directors.
3.5. Regular Meetings. Regular meetings of the directors may be held
without call or notice at such places and at such times as the directors may
from time to time determine, provided that reasonable notice of the first
regular meeting following any such determination shall be given to absent
directors. A regular meeting of the directors may be held without call or notice
immediately after and at the same place as the annual meeting of the
stockholders.
3.6 Special Meetings. Special meetings of the directors may be held at any
time and at any place designated in the call of the meeting, when called by the
chairman of the board, if any, or the president or the treasurer or by two or
more directors, reasonable notice thereof being given to each director by the
clerk or an assistant clerik, or by the officer or one of the directors calling
the meeting.
3.7. Notice. Notice to a director shall be sufficient if sent to such
director by mail at least forty-eight hours or by telegram or telecopy at least
twenty-four hours before the meeting at such director's usual or last known
business or residence address, or if given to such director in person or by
telephone at least twenty-four hours before the meeting. Notice of a meeting
need not be given to any director if a written waiver of notice, executed by
such director before or after the meeting, is filed with the records of the
meeting, or to any director who attends the meeting without protesting the lack
of notice prior to the meeting or at its commencement. Neither notice of a
meeting nor a waiver of a notice need specify the purposes of the meeting.
3.8. Quorum. At any meeting of the directors a majority of the directors
then in office shall constitute a quorum. Any meeting may be adjourned from time
to time by a majority of the votes cast upon the question, whether or not a
quorum is present, and the meeting may be held as adjourned without further
notice.
3.9. Meeting by Conference Telephone. Unless otherwise provided by law or
the Articles of Organization, members of the board of directors or any of any
committee designated thereby may participate in any meeting of such board or
committee by means of a conference telephone or similar communications equipment
by means of which all persons participating in the meeting can hear each other
at the same time and participation by such means shall constitute presence in
person at a meeting.
3.1O. Action by Vote. When a quorum is present at any meeting, a majority
of the directors present may take any action, except when a larger vote is
required by law, by the Articles of Organization or by these By-laws.
3.11. Action by Writing. Unless the Articles of Organization otherwise
provide, any action required or permitted to be taken at any meeting of the
directors may be taken without a
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<PAGE>
meeting if all the directors consent to the action in writing and the written
consents are filed with the records of the meetings of the directors. Such
consents shall be treated for all purposes as a vote taken at a meeting.
Section 4. OFFICERS AND AGENTS
4.1. Enumeration: Qualification. The officers of the corporation shall be
a president, a treasurer, a clerk and such other officers, if any, as the
incorporator or incorporators at their initial meeting, or the directors from
time to time may in their discretion elect or appoint. The corporation may also
have such agents, if any. as the incorporator or incorporators at their Initial
meeting, or the directors from time to rime, may in their discretion appoint.
Any officer may be, but none need be, a director or stockholder. The clerk shall
be a resident of Massachusetts unless the corporation has a resident agent
appointed for the purpose of service of process. Any two or more offices may be
held by the same person. Any officer may be required by the directors to give
bond for the faithful performance of such officer's duties to the corporation in
such amount and with such sureties as the directors may determine.
4.2. Powers. Subject to law, to the Articles of Organization and to the
other provisions of these By-laws, each officer shall have, in addition to the
duties and powers herein set forth such duties and powers as are commonly
incident to such officer's office and such duties and powers as the directors
may from time to time designate.
4.3. Election. The president, the treasurer and the clerk shall be elected
annually by the directors at their first meeting following the annual meeting
of the stockholders. Other officers, if any, may be elected or appointed by the
board of directors as such meeting or at any other time.
4.4. Tenure. Except as otherwise provided by law or by the Articles of
Organization or by these By-laws, the president, the treasurer and the clerk
shall hold office until the first meeting of the directors following the next
annual meeting of the stockholders and until their respective successors are
chosen and qualified, and each other officer shall hold office until the first
meeting of the directors following the next annual meeting of the stockholders
unless a shorter period shall have been specified by the terms of such officer's
election or appointment, or in each case until such officer sooner dies,
resigns, is removed or becomes disqualified. Each agent shall retain authority
at the pleasure of the directors.
4.5. The Chairman of the Board. The chairman of the board, if any, shall
have the duties and powers specified in these By-laws and shall have such other
duties and powers an may be determined by the directors- Unless the board of
directors otherwise specifies, the chairman of the board shall preside, or
designate the person who shall preside, at all meetings of the stockholders and
of the board of directors.
4.6. President and Vice Presidents. The president shall be the chief
executive officer of to corporation and shall, subject to the control of the
directors, have general charge and
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<PAGE>
supervision of the business of the corporation. Unless the board of directors
otherwise specifies, the president shall preside, or designate the person who
shall preside, at all meetings of the stockholders and of the board of
directors.
Any vice presidents shall have such duties and powers as shall be
designated from time to time by the directors.
4.7. Treasurer and Assistant Treasures. Except as the directors shall
otherwise determine, the treasurer shall be the chief financial and accounting
officer of the corporation and shall have such other duties and powers as may be
designed from time to time by the directors or by the president.
Any assistant treasurers shall have such duties and powers as shall be
designated from time to time by the directors.
4.8. Clerk and Assistant Clerks The clerk shall record all proceedings of
the stockholders and directors in a book or series of books to be kept therefor,
which book or books shall be kept at the principal office of the corporation or
at such other office permitted by law and shall be open at all reasonable times
to the inspection of any stockholder. In the absence of the clerk from any
meeting of stockholders or directors, an assistant clerk, or in the absence of
an assistant clerk, a temporary clerk chosen at the meeting, shall record the
proceedings thereof in the aforesaid book. Unless a transfer agent has been
appointed, the clerk shall keep or cause to be kept the stock and transfer
records of the corporation, which shall contain the names an record addresses
of all stockholders and the amount of stock held by each.
Any assistant clerks shall have such other duties and powers as shall be
designated from time to time by the directors.
Section 5. RESIGNATIONS AND REMOVALS
Any director or officer may resign at any time by delivering a resignation
in writing to the chairman of the board, if any, the president, the treasurer or
the clerk or to a meeting of the directors. Such resignations shall be effective
upon receipt unless specified to be effective at some other time. A director or
officer elected by the stockholders (including persons elected by directors to
fill vacancies In the board) may be removed from office (a) with or without
cause by the vote of the holders of a majority of the shares issued and
outstanding and entitled to vote in the election of such directors, provided
that the directors of a class elected by a particular class of stockholders may
be removed only by the vote of the holders of a majority of the shares of such
class, or (b) with cause by the vote of a majority of the directors then in
office. The directors may remove any officer elected by them with or without
cause by the vote of a majority of the directors then in office. A director or
officer may be removed for cause only after reasonable notice and opportunity to
be heard before the body proposing removal. No director or officer resigning,
and (except where a right to receive compensation
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<PAGE>
shall be expressly provided in a duly authorized written agreement with the
corporation) no director or officer removed, shall have any right to any
compensation as such director or officer for any period following his
resignation or removal, or any right to damages on account of such removal,
whether his compensation be by the month or the year or otherwise; unless In
the case of a resignation, the directors, or in the case of a removal, the body
acting on the removal, shall in their or its discretion provide for
compensation.
Section 6. VACANCIES
Any vacancy in any office or in the board of directors, however occurring,
including a vacancy resulting from the enlargement of the board, may be filled
by vote of the stockholders or, in the absence of stockholder action, by the
directors by vote of a majority of the directors then in office. Each such
successor chosen to fill a vacancy shall hold office for the unexpired term and,
in the case of any director, the president, treasurer and clerk, until such
officer's successor Is chosen and qualified, or in each case until such officer
sooner dies, resigns, is removed or becomes disqualified. The directors shall
have and may exercise all their powers notwithstanding the existance of one or
more vacancies in their number.
Section 7. CAPITAL STOCK
7.1. Number and Par Value. The total number of shares and the p.r value,
if any, of each class of stock which the corporation is authorized to issue
shall be as stated in the Articles of Organization.
7.2. Stock Certificates. Each stockholder shall be entitled to a
certificate stating the number and the class and the designation of the series,
if any, of the shares held by such stockholder, in such form as shall, in
conformity to law, be prescribed from time to time by the directors. Such
certificates shall be signed by the chairman of the board, if any, the president
or a vice president and by the treasurer or an assistant treasurer. Such
signatures may be facsimiles if the certificate is signed by a transfer agent,
or by a registrar, other than a director, officer or employee of the
corporation. In case any officer who has signed or whose facsimile signature has
been placed on such certificate shall have ceased to hold such office before
such certificate is issued, it may be issued by the corporation with the same
effect as if such officer still held such office at the time of its issue. The
stock and transfer records shall be kept at the corporation's principal office
or in such other office permitted by law.
7.3. Loss of Certificate. In the case of the alleged loss, destruction or
mutilation of a certificate of stock, a duplicate certificate may be issued in
place thereof, upon such terms as the directors may prescribe.
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<PAGE>
Section 8. TRANSFER OF SHARES OF STOCK
8.1. Transfer on Books. The board of directors may make such rules and
regulations not inconsistent with law, the Articles of Organization or these
By-laws as it deems expedient relative to the issue, transfer and registration
of stock certificates. Except as may be otherwise required by law, the Articles
of Organization or by these By-laws, the corporation shall be entitled to treat
the record holder of stock as shown on its books as the owner of such stock for
all purposes including the payment of dividends and the right to receive notice
and to vote with respect thereto, regardless of any transfer, pledge or other
disposition of such stock until the shares have been transfered on the books of
the corporation in accordance with the requirements of these By-laws.
Each stockholder shall have the duty to notify the corporation of such
stockholder's post office address.
8.2. Record Data and Closing transfer Books. The directors may fix in
advance a time, which shall be not more than sixty days before the date of any
meeting of stockholders or the date for the payment of any dividend or making of
any distribution to stockholders or the last day on which the consent or dissent
of stockholders may be effectively expressed for any purpose as the record date
for determining the stockholders having the right to notice of and to vote at
such meeting and any adjournment thereof or the right to receive such dividend
or distribution or the right to give such consent or dissent, and in such case
only stockholders of record on such record date shall have such right,
notwithstanding any transfer of stock on the books of the corporation after the
record date. Without fixing such record date the directors may for any of such
purposes close the transfer books for all or any part of such period. If no
record date is fixed and the transfer books are not closed:
(1) The record date for determining stockholders having the right to
notice of or to vote at a meeting of stockholders shall be at the close of
business on the dare immediately preceding the day on which notice is given.
(2) The record date for determining stockholders for any other purpose
shall be at the close of business on the day on which the board of directors
acts with respect thereto.
Section 9. INDEMNIFICATION OF DIRECTORS AND OFFICERS
The corporation shall to the extent legally permissible, indemnify each of
its directors and officers (including persons who serve at its request as
directors, officers, or trustees of another organization in which it has any
interest, as a shareholder, creditor or otherwise) against all liabilities and
expenses, Including amounts paid in satisfaction of judgments, in compromise or
as fines and penalties, and counsel fees, reasonably incurred by such person in
connection with the defense or disposition of any action, suit or other
proceeding whether civil or criminal, in which such person may be involved or
with which such person may be threatened, while in office or thereafter, by
reason of such person being or having been such a
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<PAGE>
director or officer, except with respect to any matter as to which such
person shall have been adjudicated in any proceeding not to have acted in good
faith in the reasonable belief that such person's action was in the best
interests of the corporation; provided, however, that as to any matter disposed
of by a compromise payment by such director or officer, pursuant to a consent
decree or otherwise, no indemnification either for said payment or (for any
other expenses shall be provided unless such compromise shall be approved as in
the best interests of the corporation, after notice that it involves such
indemnification, (a) by a disinterested majority of the directors then in
office; or b) by a majority of the disinterested director' then in office,
provided that there has been obtained an opinion in writing of independent legal
counsel to the effect that such director or officer appears to have acted in
good faith in the reasonable belief that such person's action was in the best
interests of the corporation; or c) by the holders of majority of the
outstanding stock at the time entitled to vote for directors, voting as a single
class, exclusive of any stock owned by an interested director or officer. In
discharging his or her duty any such director or officer, when acting in good
faith, my rely upon the books of account of the corporation or of such other
organization, reports made to the corporation or to such other organization by
any of its officers or employees or by counsel, accountants, appraisers or other
experts selected with reasonable care by the board of directors or trustees, or
upon other records of the corporation or of such other organization. Expenses
including counsel fees incurred with respect to any such action, suit or
proceeding may be paid by the corporation prior to the final disposition of such
action, suit or proceeding, upon receipt of an undertaking by or on behalf of
the recipient to repay such amount if it is ultimately determined that
indemnification for such expenses is not authorized under this Section. The
right of indemnification hereby provided shall not be exclusive of or affect any
other right to which any director or officer may be entitled. As used in this
Section, the terms `"director" and "officer" include their respective heirs,
executors and administrators, and an "interested" director or officer is one
against whom in such capacity the proceedings in question or another proceeding
on the same or similar grounds is then pending. Nothing contained in this
Section shall affect any rights to indemnification to which corporate personnel
other than directors and officers may be entitled by contract or otherwise under
law.
Section 10. CORPORATE SEAL
The seal of the corporation shall, subject to alteration by the directors,
consist of a flat-faced circular die with the word "Massachusetts" together with
the name of the corporation and the year of its organization cut or engraved
thereon.
Section 11. EXECUTION OF PAPERS
Except as the directors may generally or in particular cases authorize the
execution thereof in some other manner, all deeds, leases, transfers, contracts,
bonds, notes, checks, drafts and other obligations made, accepted or endorsed by
the corporation shall be signed by the chairman of the board, if any, the
president, a vice president or the treasurer.
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<PAGE>
Section 12. FISCAL YEAR
Except as from time to time otherwise provided by the board of directors,
the fiscal year of the corporation shall end on the last day in December in each
year.
Section 13. AMENDMENTS
These By-laws may be altered, amended or repealed at any annual or special
meeting of the stockholders called for the purpose, of which the notice shall
specify the subject matter of the proposed alteration, amendment or repeal or
the section to be affected thereby, by vote of the stockholders or if there
shall be two or more classes or series of stock entitled to vote on the
question, by vote of each such class or series. These By-laws may also be
altered, amended or repealed by vote of a majority of the directors in office,
except that the directors shall not take any action which provides for
indemnification of directors nor any action to amend this Section 13, and except
that the directors shall not take any action unless permitted by law. Not later
than the time of giving notice of the meeting of stockholders next following the
making, amending or repealing by the directors of any such by-laws, notice
thereof stating the substance of such change shall be given to all stockholders
entitled to vote on amending the by-laws.
Any by-law so altered, amended or repealed by its directors may be further
altered or amended or reinstated by the stockholders In the above manner.
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<PAGE>
EXHIBIT 10.11
Contract #: 800350
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 1st day of October,
1993, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and COLONIAL GAS COMPANY (herein called
"Customer", whether one or more),
WITNESSETH:
WHEREAS, the Federal Energy Regulatory Commission required pipeline to
restructure Pipeline's services to reflect compliance with Order Nos. 636,
636-A, and 636-B (collectively hereinafter referred to as "Order No. 636"); and
WHEREAS, by order issued January 13, 1993 (62 FERC P61,015) and order
issued April 22, 1993 (63 FERC P61,100), the Federal Energy Regulatory
Commission accepted Pipeline's revised tariff sheets filed in compliance with
Order No. 636 to become effective June 1, 1993, subject to certain conditions
set forth in the April 22, 1993 order; and
WHEREAS, CNG Transmission Corporation ("CNG") made its final Order No. 636
service elections on May 3, 1993 pursuant to the April 22, 1993 order and
Pipeline filed revised tariff sheets to become effective June 1, 1993 in
compliance with the April 22, 1993 order; and
WHEREAS, Customer is also a customer of CNG; and
WHEREAS, CNG, in compliance with Order No. 636 and Federal Energy
Regulatory Commission orders issued in Docket No. RS92-21, is assigning its firm
service rights on Pipeline directly to its customers; and
WHEREAS, Customer's service rights hereunder are part of CNG's service
rights being assigned to its customers; and
WHEREAS, Pipeline and Customer now desire to enter into this Service
Agreement to reflect the assignment of CNG's service rights 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 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
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
Customer's account quantities of natural gas up to the following quantity:
Maximum Daily Quantity (MDQ) 1,996 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, 1993 and
shall continue in force and effect until 10/31/1999 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
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
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<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 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 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.
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<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
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.
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<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
-------------------------------
Vice President
ATTEST:
- -------------------------
COLONIAL GAS COMPANY
By /s/ John P. Harrington
----------------------------------
Vice President, Gas Supply
ATTEST:
- -------------------------
7
<PAGE>
Contract #: 800350
EXHIBIT A, TRANSPORTATION PATH FOR BILLING PURPOSES DATED ___________
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED _______________________:
(1) Customer's firm Point(s) of Receipt:
<TABLE>
<CAPTION>
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) (dth) Responsibilities Owner Operator
- ------- ----------- ------------------ ---------------- ----- --------
<S> <C> <C> <C> <C> <C>
70028 SOUTHERN NATURAL (FROM T.E.) - 6 * TX EAST TRAN TX EAST SOTHN NAT GS
KOSCIUSKO, MS (TO T ATTALA CO., TRN
MS
70217 UNITED GAS ROSCIUSRO, MS ATTALA 121 * UNIT GAS PL UNIT GAS UNIT GAS PL
CO., MS PL
</TABLE>
* Included in Firm Receipt Point Entitlements as set forth in section 14 of
Pipeline's General Terms and Conditions at the Kosciusko, Mississippi
Point of Receipt.
(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 M2 1,996
SIGNED FOR IDENTIFICATION
PIPELINE:
----------------------------
CUSTOMER: /s/ John P. Harrington
----------------------------
SUPERSEDES EXHIBIT A DATED:
---------
A-1
<PAGE>
Contract #: 800350
EXHIBIT B, POINT(S) OF DELIVERY, DATED __________,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED __________________:
<TABLE>
<CAPTION>
Maximum
Daily
Point of Delivery Delivery Pressure Measurement
Delivery Description Obligation Obligation Responsibilities Owner Operator
-------- ----------- ---------- ---------------------- ---------------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C>
1. 70004 CNG TRANSMISSION - As provided in Section 6 TX EAST TRAN TX EAST TX EAST
CLARINGTON, OH MONROE of the General Terms and TRAN TRAN
CO., OH Conditions of Pipeline's
FERC Gas Tariff
2. 70051 CNG TRANSMISSION - As provided in Section 6 TX EAST TRAN TX EAST CNG TRANS
SOMERSET, PA SOMERSET of the General Terms and TRAN
CO., PA Conditions of Pipeline's
FERC Gas Tariff
3. 70372 CNG TRANSMISSION - At the operating pressure TX EAST TRAN TX EAST CNG TRANS
MOUNDSVILLE, WV MARSHALL existing at the point of TRAN
CO., WV delivery
4. 70450 CNG TRANSMISSION - At the operating pressure TX EAST TRAN TX EAST CNG TRANS
SUMMERFIELD, OH NOBLE existing at the point of TRAN
CO., OH delivery
5. 70471 CNG TRANSMISSION - 200 pounds per square TX EAST TRAN TX EAST CNG TRANS
WOODSFIELD, OH MONROE inch gauge TRAN
CO., OH
6. 70983 CNG TRANSMISSION - 300 pounds per square CNG TRANS CNG CNG TRANS
POWHATAN POINT, OH inch gauge TRANS
MONROE CO., OH
7. 72533 DAMSON (PEOPLES) MM - At the operating pressure PEOPLES PEOPLES DAMSON
SOMERSET, PA SOMERSET existing at the point of NG(PA) NG(PA) OIL
CO., PA delivery
8. 75037 CNG As provided in Section 6 TX EAST TRAN TX EAST CNG TRANS
TRANSMISSION-WAYNESBURG, of the General Terms and TRAN
PA (D70037) GREENE CO., PA Conditions of Pipeline's
FERC Gas Tariff
9. 75082 TETCO - OAKFORD STORAGE, 575 pounds per square CNG TRANS TX EAST CNG TRANS
PA-(D70082/R76082) inch gauge TRANS
WESTMORELAND CO., PA
10. 79921 COMPRESSOR STATION 21A At any pressure provided TX EAST TRAN TX EAST CNG TRANS
(UNIONTOWN) FAYETTE CO., by Texas Eastern not to TRAN
PA exceed 1,000 pounds per
square inch gauge
</TABLE>
B-1
<PAGE>
Contract #: 800350
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
COLONIAL GAS COMPANY
<TABLE>
<CAPTION>
Maximum
Daily Delivery
Point of Delivery Pressure Measurement
Delivery Description Obligation Obligation Responsibilities Owner Operator
-------- ----------- ---------- ---------- ---------------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C>
11. 79849 CNG - COLONIAL GAS 1,996 N/A N/A N/A N/A
COMPANY FOR NOMINATION
PURPOSES
</TABLE>
provided, however, that all service under this Service Agreement shall be within
the limitations set forth in the Dispatching Agreement dated _________________
between Pipeline, Customer and CNG Transmission Corporation.
SIGNED FOR IDENTIFICATION:
PIPELINE:
----------------------------
CUSTOMER: /s/ John P. Harrington
----------------------------
SUPERSEDES EXHIBIT B DATED:
---------
B-2
<PAGE>
Contract #: 800350
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED ___________________, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-l
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
COLONIAL GAS COMPANY ("CUSTOMER"), DATED_______________:
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
====================================================================================================================
FROM STX ETX WLA ELA Ml-24 Ml-30 Ml-TXG Ml-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STX 53
- --------------------------------------------------------------------------------------------------------------------
ETX 225 80
- --------------------------------------------------------------------------------------------------------------------
WLA 24 53
- --------------------------------------------------------------------------------------------------------------------
ELA 1590
- --------------------------------------------------------------------------------------------------------------------
M1-24 225
- --------------------------------------------------------------------------------------------------------------------
M1-30 1590
- --------------------------------------------------------------------------------------------------------------------
M1-TXG 105
- --------------------------------------------------------------------------------------------------------------------
M1-TGC 106
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
C-1
<PAGE>
Contract #: 800350
EXHIBIT C (Continued)
COLONIAL GAS COMPANY
ZONE BOUNDARY EXIT QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
====================================================================================================================
FROM STX ETX WLA ELA Ml-24 Ml-30 Ml-TXG Ml-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STX
- --------------------------------------------------------------------------------------------------------------------
ETX
- --------------------------------------------------------------------------------------------------------------------
WLA
- --------------------------------------------------------------------------------------------------------------------
ELA
- --------------------------------------------------------------------------------------------------------------------
M1-24 225
- --------------------------------------------------------------------------------------------------------------------
M1-30 1590
- --------------------------------------------------------------------------------------------------------------------
M1-TXG 105
- --------------------------------------------------------------------------------------------------------------------
M1-TGC 106
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION:
PIPELINE:
----------------------------
CUSTOMER: /s/ John P. Harrington
----------------------------
SUPERSEDES EXHIBIT C DATED:
---------
C-2
<PAGE>
EXHIBIT 10.14
Contract #: 800313
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 1st day of June, 1993,
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, the Federal Energy Regulatory Commission required Pipeline to
restructure Pipeline's services to reflect compliance with Order Nos. 636,
636-A, and 636-B (collectively hereinafter referred to as "Order No. 636"); and
WHEREAS, by order issued January 13, 1993 (62 FERC P61, 015) and order
issued April 22, 1993 (63 FERC P61, 100), the Federal Energy Regulatory
Commission accepted Pipeline's revised tariff sheets filed in compliance with
Order No. 636 to become effective June 1, 1993, subject to certain conditions
set forth in the April 22, 1993 order; and
WHEREAS, Algonquin Gas Transmission Company ("Algonquin") made its final
Order No. 636 service elections on May 3, 1993 pursuant to the April 22, 1993
order and Pipeline filed revised tariff sheets to become effective June 1, 1993
in compliance with the April 22, 1993 order; and
WHEREAS, Customer is also a customer of Algonquin; and
WHEREAS, Algonquin, in compliance with Order No. 636 and Federal Energy
Regulatory Commission orders issued in Docket No. RS92-28, is assigning its firm
service rights on Pipeline directly to its customers; and
WHEREAS, Customer's service rights hereunder are part of Algonquin's
service rights being assigned to its customers; and
WHEREAS, Pipeline and Customer now desire to enter into this Service
Agreement to reflect the assignment of Algonquin's service rights 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 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
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
Customer's account quantities of natural gas up to the following quantity:
Maximum Daily Quantity (MDQ) 7,918 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 June 1, 1993 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 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
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
WEE 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
4
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 0 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.
7
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 0 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.
8
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
JAN 19 1994
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
9
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
10
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
-------------------------------------
Vice President
ATTEST:
- ----------------------------------
COLONIAL GAS COMPANY
By /s/ John P. Harrington
-------------------------------------
Vice President, Gas Supply
ATTEST:
/s/ Phyllis G. Semenchuk
- ----------------------------------
11
<PAGE>
Contract #: 800313
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED June 1, 1993,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND COLONIAL GAS COMPANY ("Customer"),
DATED June 1, 1993:
(1) Customer's firm Point(s) of Receipt:
<TABLE>
<CAPTION>
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) Responsibilities Owner Operator
------- ----------- ------------------ ---------------- ----- --------
<S> <C> <C> <C> <C> <C>
None
</TABLE>
(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 7,918
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------
CUSTOMER: /s/ John P. Harrington
--------------------------
SUPERSEDES EXHIBIT A DATED:
--------
A-1
<PAGE>
Contract #: 800313
EXHIBIT B, POINT(S) OF DELIVERY, DATED June 1, 1993,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
BOSTON COLONIAL COMPANY ("Customer"),
DATED June 1, 1993:
<TABLE>
<CAPTION>
Maximum
Daily Measurement
Point of Delivery Delivery Pressure Responsi-
Delivery Description Obligation Obligation Bilities Owner Operator
- -------- ----------- ---------- ----------------- ----------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C>
1. 70087 ALGONQUIN - LAMBERTVILLE, 7,918 AS REQUESTED BY TX EAST TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ CUSTOMER, NOT TO TRAN TRAN
EXCEED 750 PSIG
2. 71078 ALGONQUIN - HANOVER, NJ 7,918 AS REQUESTED BY TX EAST TX EAST ALGONQUIN
MORRIS CO., NJ CUSTOMER, NOT TO TRAN TRAN
EXCEED 750 PSIG
3. 79513 SS-1 STORAGE POINT 2,372 N/A N/A N/A N/A
04/01-10/31
2,372
11/01-03/31
4. 79821 AGT - COLONIAL GAS - FOR 0 N/A N/A N/A N/A
NOMINATION PURPOSES
</TABLE>
provided, however, that until changed by a subsequent Agreement between Pipeline
and Customer, Pipline'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:
B-1
<PAGE>
Contract #: 800313
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
COLONIAL GAS COMPANY
AGGREGATE MAXIMUM DAILY
POINT OF DELIVERY DELIVERY OBLIGATION (DTH)
----------------- -------------------------
No. 1 21,318
No. 2 9,418
No. 3 2,372
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------
CUSTOMER: /s/ John P. Harrington
--------------------------
SUPERSEDES EXHIBIT B DATED
--------
B-2
<PAGE>
Contract #: 800313
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED June 1, 1993, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
COLONIAL GAS COMPANY ("CUSTOMER"), DATED June 1, 1993:
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
============================================================================================================
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STX 225
- ------------------------------------------------------------------------------------------------------------
ETX 954 340
- ------------------------------------------------------------------------------------------------------------
WLA 103 225
- ------------------------------------------------------------------------------------------------------------
ELA 6200
- ------------------------------------------------------------------------------------------------------------
M1-24 954
- ------------------------------------------------------------------------------------------------------------
M1-30 6200
- ------------------------------------------------------------------------------------------------------------
M1-TXG 443
- ------------------------------------------------------------------------------------------------------------
M1-TGC 449
- ------------------------------------------------------------------------------------------------------------
M2-24
- ------------------------------------------------------------------------------------------------------------
M2-30
- ------------------------------------------------------------------------------------------------------------
M2-TXG
- ------------------------------------------------------------------------------------------------------------
M2-TGC
- ------------------------------------------------------------------------------------------------------------
M2 7918
- ------------------------------------------------------------------------------------------------------------
M3
============================================================================================================
</TABLE>
C-1
<PAGE>
Contract #: 800313
EXHIBIT C (Continued)
COLONIAL GAS COMPANY
ZONE BOUNDARY EXIT QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
============================================================================================================
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STX
- ------------------------------------------------------------------------------------------------------------
ETX
- ------------------------------------------------------------------------------------------------------------
WLA
- ------------------------------------------------------------------------------------------------------------
ELA
- ------------------------------------------------------------------------------------------------------------
M1-24 954
- ------------------------------------------------------------------------------------------------------------
M1-30 6200
- ------------------------------------------------------------------------------------------------------------
M1-TXG 443
- ------------------------------------------------------------------------------------------------------------
M1-TGC 449
- ------------------------------------------------------------------------------------------------------------
M2-24
- ------------------------------------------------------------------------------------------------------------
M2-30
- ------------------------------------------------------------------------------------------------------------
M2-TXG
- ------------------------------------------------------------------------------------------------------------
M2-TGC
- ------------------------------------------------------------------------------------------------------------
M2 7918
- ------------------------------------------------------------------------------------------------------------
M3
============================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------
CUSTOMER: /s/ John P. Harrington
--------------------------
SUPERSEDES EXHIBIT C DATED
--------
C-2
<PAGE>
EXHIBIT 10.15
Contract #: 330869
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 1st day of June, 1993,
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, the Federal Energy Regulatory Commission required Pipeline to
restructure Pipeline's services to reflect compliance with Order Nos. 636,
636-A, and 636-B (collectively hereinafter referred to as "Order No. 636"); and
WHEREAS, by order issued January 13, 1993 (62 FERC P61,015) and order
issued April 22, 1993 (63 FERC P61,100), the Federal Energy Regulatory
Commission accepted Pipeline's revised tariff sheets filed in compliance with
Order No. 636 to become effective June 1, 1993, subject to certain conditions
set forth in the April 22, 1993 order; and
WHEREAS, Customer made its final Order No. 636 service elections on May 3,
1993 pursuant to the April 22, 1993 order and Pipeline filed revised tariff
sheets to become effective June 1, 1993 in compliance with the April 22, 1993
order;
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) 2,222 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),
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 June 1, 1993 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.
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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:
4
<PAGE>
Contract #:330869
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED JUNE 1, 1993,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED JUNE 1, 1993:
(1) Customer's firm Point(s) of Receipt:
<TABLE>
<CAPTION>
Maximum Daily
Receipt
Obligation (plus Measurement
Point of Applicable Responsi-
Receipt Description Shrinkage) (dth) bilities Owner Operator
- ------- ----------- ---------------- -------- ----- --------
<S> <C> <C> <C> <C> <C>
79923 COMPRESSOR STATION 23 2,222 dth TETCO TETCO CNG TRANS
FRANKLIN CO., PA
</TABLE>
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL revised and published by
Pipeline from time to time is incorporated herein by references.
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 2,222 dth
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------------------
CUSTOMER: /s/ John P. Harrington
--------------------------------------
SUPERSEDES EXHIBIT A DATED:
--------------------
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
(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.
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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, 12/19/1991 between Pipeline and Customer under
Pipeline's Rate Schedule FTS-5 (Pipeline's Contract No. 200211).
7
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
--------------------------------------
Vice President
ATTEST:
- --------------------------
COLONIAL GAS COMPANY
By /s/ John P. Harrington
--------------------------------------
Vice President, Gas Supply
ATTEST:
/s/ Phyllis G. Semenchuk
- --------------------------
8
<PAGE>
Contract #:330869
EXHIBIT B, POINT(S) OF DELIVERY, DATED June 1, 1993,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
COLONIAL GAS COMPANY ("Customer"),
DATED June 1, 1993:
<TABLE>
<CAPTION>
Maximum
Daily Measurement
Point of Delivery Delivery Pressure Responsi-
Delivery Description Obligation Obligation bilities Owner Operator
-------- ----------- ---------- ---------- -------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C> <C>
1. 70087 ALGONQUIN - LAMBERTVILLE, 2,222 dth ANY PRESSURE REQUESTED BY TX EAST TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ ALGONQUIN, PROVIDED TRAN TRAN
HOWEVER, THE MAXIMUM
DELIVERY PRESSURE SHALL
NOT EXCEED 750 POUNDS PER
SQUARE INCH GAUGE
2. 79821 AGT - COLONIAL GAS 0 dth N/A N/A N/A N/A
FOR NOMINATION PURPOSES
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------------------
CUSTOMER: /s/ John P. Harrington
--------------------------------------
SUPERSEDES EXHIBIT B DATED:
--------------------
9
<PAGE>
EXHIBIT 10.16
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.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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:
4
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
(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.
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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).
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 /s/ Robert B. Evans
---------------------------------------
Vice President
ATTEST:
/s/ Robert W. Reed
- -------------------------
ROBERT W. REED
CORPORATE SECRETARY
COLONIAL GAS COMPANY
By /s/ John P. Harrington
---------------------------------------
John P. Harrington
Vice President - Gas Supply
ATTEST:
/s/ Phyllis G. Semenchuk
- -------------------------
7
<PAGE>
Contract #:800400
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:
<TABLE>
<CAPTION>
Maximum Daily
Receipt
Obligation (plus
Point of Applicable Measurement
Receipt Description Shrinkage) Responsibilities Owner Operator
------- ----------- ---------- ---------------- ----- --------
<S> <C> <C> <C> <C> <C> <C>
1. 72822 CNG, N. Summit Storage 104 dth TETCO TETCO CNG
Fayette Co., PA
</TABLE>
(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: /s/ Robert B. Evans
------------------------------
CUSTOMER: /s/ John P. Harrington
------------------------------
SUPERSEDES EXHIBIT A DATED: June 1, 1993
------------
A-1
<PAGE>
Contract #:800400
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
<TABLE>
<CAPTION>
Maximum
Daily Measurement
Point of Delivery Delivery Pressure Responsi-
Delivery Description Obligation Obligation bilities Owner Operator
-------- ----------- ---------- ---------- -------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C> <C>
1. 70087 ALGONQUIN - 104 AT ANY PRESSURE TX EAST TRAN TX EAST ALGONQUIN
LAMBERTVILLE, NJ REQUESTED BY TRAN
HUNTERDON CO., NJ CUSTOMER,
PROVIDED, HOWEVER,
THE MAXIMUM
DELIVERY PRESSURE
SHALL NOT EXCEED
750 POUNDS PER
SQUARE INCH GAUGE
2. 79821 AGT - COLONIAL GAS - FOR 0 N/A N/A N/A N/A
NOMINATION PURPOSES
</TABLE>
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 obligations under this and all other service agreements existing
between Pipeline and Customer, shall in no event exceed the following:
B-1
<PAGE>
Contract #:800400
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
COLONIAL GAS COMPANY
Aggregate Maximum
Point of Delivery Daily Delivery Obligation
No. 1. 23,644 dth
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ Robert B. Evans
------------------------------
CUSTOMER: /s/ John P. Harrington
------------------------------
SUPERSEDES EXHIBIT B DATED: June 1, 1993
------------
B-2
<PAGE>
Contract #:800400
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
<TABLE>
<CAPTION>
===============================================================================================
FROM STX ETX WLA ELA M1-24 M1-30 M1-TXG M1-TGC M2-24 M2-30 M2-TXG M2-TGC M2 M3
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STX
- -----------------------------------------------------------------------------------------------
ETX
- -----------------------------------------------------------------------------------------------
WLA
- -----------------------------------------------------------------------------------------------
ELA
- -----------------------------------------------------------------------------------------------
M1-24
- -----------------------------------------------------------------------------------------------
M1-30
- -----------------------------------------------------------------------------------------------
M1-TXG
- -----------------------------------------------------------------------------------------------
M1-TGC
- -----------------------------------------------------------------------------------------------
M2-24
- -----------------------------------------------------------------------------------------------
M2-30
- -----------------------------------------------------------------------------------------------
M2-TXG
- -----------------------------------------------------------------------------------------------
M2-TGC
- -----------------------------------------------------------------------------------------------
M2 104
- -----------------------------------------------------------------------------------------------
M3
===============================================================================================
</TABLE>
C-1
<PAGE>
CNG Contract No. 400009
EXHIBIT 10.23
SERVICE AGREEMENT
APPLICABLE TO THE STORAGE OF NATURAL GAS
UNDER RATE SCHEDULE GSS-II
AGREEMENT made effective as of November I, 1998, by and between CNG
TRANSMISSION CORPORATION, a Delaware corporation, hereinafter called "Pipeline,"
and COLONIAL GAS COMPANY, a Massachusetts corporation, hereinafter called
"Customer."
WHEREAS, in conjunction with Article VII of the August 31, 1998
Stipulation and Agreement in Pipeline's Docket Nos. RP97-406-000, et al.,
Pipeline and Customer agree to revise and replace the Agreement Applicable To
the Storage of Natural Gas Under Rate Schedule GSS-II (Part 284) between
Pipeline and Customer dated September 1, 1997 as reflected below, effective as
of November 1, 1998.
WITNESSETH: That in consideration of the mutual covenants herein
contained, the parties hereto agree that Pipeline will store natural gas for
Customer during the term, at the rates and on the terms and conditions
hereinafter provided:
Article I. Quantities
Beginning as of November I, 1998 and thereafter for the remaining term of
this agreement, Customer agrees to deliver to Pipeline and Pipeline agrees to
receive for storage in Pipeline's underground storage properties, and Pipeline
agrees to inject or cause to be injected into storage for Customer's account,
store, withdraw from storage, and deliver to Customer and Customer agrees to
receive, quantities of natural gas as set forth on Exhibit A, attached hereto.
Article II. Rate
A. For storage service rendered by Pipeline to Customer hereunder,
Customer shall pay Pipeline the maximum rates and charges provided under Rate
Schedule GSS-II contained in Pipeline's effective FERC Gas Tariff or any
effective superseding rate schedule.
B. Pipeline shall have the right to propose, file, and make effective with
the FERC or any other body having jurisdiction, revisions to any applicable rate
schedule, or to propose, file, and make effective superseding rate schedules for
the purpose of changing the rate, charges, and other provisions thereof
effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule
GSS-II "Applicability and Character of Service," (ii) term, (iii) quantities,
and (iv) points of receipt and points of delivery shall not be subject to
unilateral change under this Article. Said rate schedule or superseding rate
schedule and any revisions thereof which shall be filed and made effective shall
apply to and become a part of this Service Agreement. The filing of such changes
and revisions to applicable rate schedule shall be without prejudice to the
right of Customer to contest or oppose such filing and its effectiveness.
- 1 -
<PAGE>
CNG Contract No. 400009
C. The Storage Demand Charge and the Storage Capacity Charge provided in
the aforesaid rate schedule shall commence on November I, 1998.
Article III. Term of Agreement
Subject to all the terms and conditions herein, this Agreement shall be
effective as of November 1, 1998, and shall continue in effect for a primary
term through and including October 31, 2002.
Article IV. Points of Receipt and Delivery
The Points of Receipt for Customer's tender of storage injection
quantities, and the Point(s) of Delivery for withdrawals from storage shall be
specified on Exhibit A, attached hereto.
Article V. Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions of this
Agreement, the following provisions of Seller's effective FERC Gas Tariff, and
any revisions thereof that may be made effective hereafter are hereby made
applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule GSS-II, or any effective
superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as
they may be revised or superseded from time to time.
Article VI. Miscellaneous
A. No change, modification or alteration of this Agreement shall be or
become effective until executed in writing by the parties hereto; provided,
however, that the parties do not intend that this Article VI.A. requires a
further written agreement either prior to the making of any request or filing
permitted under Article II hereof or prior to the effectiveness of such request
or filing after Commission approval, provided further, however, that nothing in
this Agreement shall be deemed to prejudice any position the parties may take as
to whether the request, filing or revision permitted under Article II must be
made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any
notice which either party may desire to give the other, shall be in writing and
sent to the following addresses:
Pipeline: CNG Transmission Corporation
445 West Main Street
Clarksburg, West Virginia 26301
Attention: Vice President, Wholesale Marketing
Fax: (304) 623-8323
- 2 -
<PAGE>
CNG Contract No. 400009
Customer: Colonial Gas Company
40 Market Street
Lowell, Massachusetts 01852
Attention: Senior Vice President, Gas Supply
Fax: (978) 459-2314
or at such other address as either party shall designate by formal written
notice.
C. No presumption shall operate in favor of or against either party hereto
as a result of any responsibility either party may have had for drafting this
Agreement.
Article VII. Prior Contracts
This Service Agreement shall supersede and cancel, as of the effective
date, the "Service Agreement Applicable to the Storage of Natural Gas Under Rate
Schedule GSS-II (Part 284)" between Customer and Pipeline dated September 1,
1997.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized officials as of the day and year first above
written.
CNG TRANSMISSION CORPORATION
(Pipeline)
By: /s/ George B. Carter
-----------------------------
Its: Vice President
COLONIAL GAS COMPANY
(Customer)
By: /s/ John P. Harrington
-----------------------------
Its: Senior V.P. - Gas Supply
-----------------------------
(Title)
- 3 -
<PAGE>
EXHIBIT A (Contract No. 400009).
To The GSS-II Storage Service Agreement
Dated November 1, 1998
Between CNG Transmission Corporation and
Colonial Gas Company
A. Quantities
The quantities of natural gas storage service that Customer may utilize
under this Service Agreement, as well as Customer's applicable Billing
Determinants, are as follows:
1. For the period November 1, 1998 through and including October 31,
1999:
a. A Storage Demand of 1,778 Dt per Day; and
b. A Storage Capacity of 177,760 Dt.
2. For the period November 1, 1999 through and including October 31,
2000:
a. A Storage Demand of 1,223 Dt per Day; and
b. A Storage Capacity of 122,210 Dt.
3. For the period November 1, 2000 through and including October 31,
2001:
a. A Storage Demand of 779 Dt per Day; and
b. A Storage Capacity of 77,770 Dt.
4. For the period November 1, 2001 through and including October 31,
2002:
a. A Storage Demand of 335 Dt per Day; and
b. A Storage Capacity of 33,330 Dt.
B. Points of Receipt and Delivery
1. The Points of Receipt for Customer's tender of storage injection
quantities, and the maximum quantities and character of service for
each point shall be as set forth below. Each of the parties will use
due care and diligence to assure that uniform pressures will be
maintained at the Receipt Point as reasonably may be required to
render service hereunder, but Pipeline will not be required to
accept gas at less than the minimum pressures specified herein.
a. Up to Customer's maximum daily entitlement for injection as
determined under Rate Schedule GSS-II, at an existing point of
interconnection of the facilities of Pipeline and Texas
Eastern Transmission Corporation (Texas Eastern) or
Transcontinental Gas Pipe Line Corporation, located in Clinton
County,
<PAGE>
Exhibit A (Contract No. 400009)
November 1, 1998 GSS-II Agreement
Between CNG Transmission Corporation and
Colonial Gas Company
Page 2 of 2
Pennsylvania and known as the Leidy Interconnection, at a
pressure of not less than one thousand (1,000) pounds per
square inch gauge ("psig").
b. Upon mutual agreement of Pipeline and Customer, up to
Customer's maximum daily entitlement for injection as
determined under Rate Schedule GSS-II, at other
interconnections on the system of Pipeline, at a pressure
sufficient to enter Pipeline's facilities at the point(s) of
interconnection.
2. The Points of Delivery for withdrawals from storage, and the maximum
quantities and character of service for each point, shall be as set
forth below. Each of the parties will use due care and diligence to
assure that uniform pressures will be maintained at the Delivery
Points as reasonably may be required to render service hereunder,
but Pipeline will not be required to deliver gas at greater than the
maximum pressures specified herein.
a. Up to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS-II, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern Transmission Corporation ("Texas Eastern"), in
Franklin County, Pennsylvania, known as the Chambersburg
Interconnection, at a pressure of not more than seven hundred
(700) psig.
b. Upon mutual agreement of Pipeline and Customer, up to
Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS-II, at other
interconnections between the facilities of Pipeline and Texas
Eastern, at a pressure sufficient to enter the system of Texas
Eastern.
c. Upon mutual agreement of Pipeline and Customer, up to
Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS-II, at other
interconnections on the system of Pipeline, at a pressure
sufficient to enable delivery by Pipeline.
d. On an interruptible basis if operating conditions permit, up
to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS-II, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern located in Greene County, Pennsylvania and known as
the Crayne Interconnection, at a pressure of not more than
eight hundred sixty-five (865) psig.
e. On an interruptible basis if operating conditions permit, up
to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS-II, at the interconnection
of the facilities of Pipeline and Texas Eastern located in
Westmoreland County, Pennsylvania and known as the Oakford
Interconnection, at a pressure of not less than eight hundred
fifty (850) psig.
<PAGE>
EXHIBIT 10.44
Contract #: 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 25th day of August,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Colonial Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Algonquin and Customer are currently parties to an executed agreement
dated January 6, 1999, under Algonquin's Rate Schedule AFT-1 (Algonquin's
Contract No. 97036); and
WHEREAS, Algonquin and Customer desire to enter into this Agreement to supersede
Algonquin's Contract No. 97036, dated January 6, 1999;
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 2,000 MMBtu
Maximum Annual Transportation Quantity 304,000 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.
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on November 1, 1999 and shall
continue in effect until and including March 31, 2000. The term of this
agreement shall not be extended beyond March 31, 2000. Upon expiration of
this Agreement, Customer shall have no right providing for the avoidance
of pregranted abandonment.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-1 as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate under
Rate Schedule AFT-1, nor less than the minimum rate under Rate Schedule
AFT-l.
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.
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
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.
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO 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
5400 Westheimer Court
Houston, TX 77056
(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
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.
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto:
agreement dated January 6, 1999, between Algonquin and Customer under
Algonquin's Rate Schedule AFT-1 (Pipeline's Contract No. 97036).
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed
by their respective agents thereunto duly authorized, the day and year first
above written.
ALGONQUIN GAS TRANSMISSION COMPANY
By: /s/ [ILLEGIBLE]
--------------------------- /s/ PMT
Title: Vice President
------------------------
COLONIAL GAS COMPANY
By: /s/ John P. Harrington
---------------------------
Title: Senior V.P. - Gas Supply
------------------------
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit A
Point(s) of Receipt
Dated: August 25, 1999
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 2,000 At any pressure
requested by
Algonquin not in
excess of 750 Psig.
Signed for Identification
Algonquin: /s/ [ILLEGIBLE]
------------------------------ /s/ JMM
Customer: /s/ John P. Harrington
------------------------------
<PAGE>
Contract No. 97036R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
Dated: August 25, 1999
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)
-------- ------- ------
On the outlet side
of meter station
located at:
Sagamore, MA 2,000 225
Signed for Identification
Algonquin: /s/ [ILLEGIBLE]
------------------------------ /s/ JMM
Customer: /s/ John P. Harrington
------------------------------
<PAGE>
CNG Contract No. 300114
EXHIBIT 10.45
SERVICE AGREEMENT
APPLICABLE TO THE STORAGE OF NATURAL GAS
UNDER RATE SCHEDULE GSS.
AGREEMENT made effective as of November 1, 1998, by and between CNG
TRANSMISSION CORPORATION, a Delaware corporation, hereinafter called "Pipeline,"
and COLONIAL GAS COMPANY, a Massachusetts corporation, hereinafter called
"Customer."
WHEREAS, in conjunction with Article VII of the August 31, 1998
Stipulation and Agreement in Pipeline's Docket Nos. RP97-406-000, et al.,
Pipeline and Customer have agreed to establish an agreement under Pipeline's
Rate Schedule GSS, which will ultimately supplant the "Service Agreement
Applicable To the Storage of Natural Gas Under Rate Schedule GSS-II (Part 284)"
between Pipeline and Customer dated September 1, 1997, commencing effective as
of November 1, 1998.
WITNESSETH: That in consideration of the mutual covenants herein
contained, the parties hereto agree that Pipeline will store natural gas for
Customer during the term, at the rates and on the terms and conditions
hereinafter provided:
Article I. Quantities
Beginning as of November 1, 1998 and thereafter for the remaining term of
this agreement, Customer agrees to deliver to Pipeline and Pipeline agrees to
receive for storage in Pipeline's underground storage properties, and Pipeline
agrees to inject or cause to be injected into storage for Customer's account,
store, withdraw from storage, and deliver to Customer and Customer agrees to
receive, quantities of natural gas as set forth on Exhibit A, attached hereto.
Article II. Rate
A. For storage service rendered by Pipeline to Customer hereunder,
Customer shall pay Pipeline the maximum rates and charges provided under Rate
Schedule GSS contained in Pipeline's effective FERC Gas Tariff or any effective
superseding rate schedule.
B. Pipeline shall have the right to propose, file, and make effective with
the FERC or any other body having jurisdiction, revisions to any applicable rate
schedule, or to propose, file, and make effective superseding rate schedules for
the purpose of changing the rate, charges, and other provisions thereof
effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule
GSS "Applicability and Character of Service," (ii) term, (iii) quantities, and
(iv) points of receipt and points of delivery shall not be subject to unilateral
change under this Article. Said rate schedule or superseding rate schedule and
any revisions thereof which shall be filed and made effective shall apply to and
become a part of this Service Agreement. The
- 1 -
<PAGE>
CNG Contract No. 300114
filing of such changes and revisions to applicable rate schedule shall be
without prejudice to the right of Customer to contest or oppose such filing and
its effectiveness.
C. The Storage Demand Charge and the Storage Capacity Charge provided in
the aforesaid rate schedule shall commence on November 1, 1998.
Article III. Term of Agreement
Subject to all the terms and conditions herein, this Agreement shall be
effective as of November 1, 1998, and shall continue in effect for a primary
term through and including March 31, 2012, and for subsequent annual terms of
April 1 through March 31 thereafter, until either party terminates this
Agreement by giving written notice to the other at least twenty-four months
prior to the start of an annual term.
Article IV. Points of Receipt and Delivery
The Points of Receipt for Customer's tender of storage injection
quantities, and the Point(s) of Delivery for withdrawals from storage shall be
specified on Exhibit A, attached hereto.
Article V. Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions of this
Agreement, the following provisions of Seller's effective FERC Gas Tariff, and
any revisions thereof that may be made effective hereafter are hereby made
applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule GSS, or any effective
superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as
they may be revised or superseded from time to time.
Article VI. Miscellaneous
A. No change, modification or alteration of this Agreement shall be or
become effective until executed in writing by the parties hereto; provided,
however, that the parties do not intend that this Article VI.A. requires a
further written agreement either prior to the making of any request or filing
permitted under Article II hereof or prior to the effectiveness of such request
or filing after Commission approval, provided further, however, that nothing in
this Agreement shall be deemed to prejudice any position the parties may take as
to whether the request, filing or revision permitted under Article II must be
made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any
notice which either party may desire to give the other, shall be in writing and
sent to the following addresses:
- 2 -
<PAGE>
CNG Contract No. 300114
Pipeline: CNG Transmission Corporation
445 West Main Street
Clarksburg, West Virginia 26301
Attention: Vice President, Wholesale Marketing
Fax: (304) 623-8323
Customer: Colonial Gas Company
40 Market Street
Lowell, Massachusetts 01852
Attention: Senior Vice President, Gas Supply
Fax: (978) 459-2314
or at such other address as either party shall designate by formal written
notice.
C. No presumption shall operate in favor of or against either party hereto
as a result of any responsibility either party may have had for drafting this
Agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized officials as of the day and year first above
written.
CNG TRANSMISSION CORPORATION
(Pipeline)
By: /s/ George B. Carter
-----------------------------
Its: Vice President
COLONIAL GAS COMPANY
(Customer)
By: /s/ John P. Harrington
-----------------------------
Its: Senior V.P. - Gas Supply
-----------------------------
(Title)
- 3 -
<PAGE>
EXHIBIT A (Contract No. 300114)
To The GSS Storage Service Agreement
Dated November 1, 1998
Between CNG Transmission Corporation and
Colonial Gas Company
A. Quantities
The quantities of natural gas storage service that Customer may utilize
under this Service Agreement, as well as Customer's applicable Billing
Determinants, are as follows:
1. For the period November 1, 1998 through and including October 31,
1999:
a. A Storage Demand of 444 Dt per Day; and
b. A Storage Capacity of 44,440 Dt.
2. For the period November 1, 1999 through and including October 31,
2000:
a. A Storage Demand of 999 Dt per Day; and
b. A Storage Capacity of 99,990 Dt.
3. For the period November 1, 2000 through and including October 31,
2001:
a. A Storage Demand of 1,443 Dt per Day; and
b. A Storage Capacity of 144,430 Dt.
4. For the period November 1, 2001 through and including October 31,
2002:
a. A Storage Demand of 1,887 Dt per Day; and
b. A Storage Capacity of 188,870 Dt.
5. For the period November 1, 2002 through and including the remaining
term of this Agreement:
a. A Storage Demand of 2,222 Dt per Day; and
b. A Storage Capacity of 222,200 Dt.
B. Points of Receipt
The Points of Receipt for Customer's tender of storage injection
quantities, and the maximum quantities and character of service for each point
shall be as set forth below. Each of the parties will use due care and diligence
to assure that uniform pressures will be maintained at the Receipt Point as
reasonably may be required to render service hereunder, but Pipeline will not be
required to accept gas at less than the minimum pressures specified herein.
<PAGE>
Exhibit A (Contract No. 300114)
November 1, 1998 GSS Agreement
Between CNG Transmission Corporation and
Colonial Gas Company
Page 2 of 2
1. Up to Customer's maximum daily entitlement for injection as
determined under Rate Schedule GSS, at an existing point of
interconnection of the facilities of Pipeline and Texas Eastern
Transmission Corporation (Texas Eastern) or Transcontinental Gas
Pipe Line Corporation, located in Clinton County, Pennsylvania and
known as the Leidy Interconnection, at a pressure of not less than
one thousand (1,000) pounds per square inch gauge ("psig").
2. Upon mutual agreement of Pipeline and Customer, up to Customer's
maximum daily entitlement for injection as determined under Rate
Schedule GSS, at other interconnections on the system of Pipeline,
at a pressure sufficient to enter Pipeline's facilities at the
point(s) of interconnection.
C. Points of Delivery
1. The Point(s) of Delivery for subsequent transportation to Customer
of all firm storage withdrawal quantities shall be the point(s) of
withdrawal from Pipeline's storage pool(s).
2. These Point(s) of Delivery shall only be Primary, as defined in
Pipeline's FERC Gas Tariff, to the extent that corresponding
transportation from the point(s) of withdrawal from Pipeline's
storage pool(s) is provided under the "Service Agreement Applicable
to Transportation of Natural Gas Under Rate Schedule FT (FT-GSS
Service)" between Pipeline and Customer, dated November 1, 1998.
<PAGE>
CNG Contract No. 300115
EXHIBIT 10.46
SERVICE AGREEMENT
APPLICABLE TO THE STORAGE OF NATURAL GAS
UNDER RATE SCHEDULE GSS (North Summit)
AGREEMENT made effective as of November 1, 1998, by and between CNG
TRANSMISSION CORPORATION, a Delaware corporation, hereinafter called "Pipeline,"
and COLONIAL GAS COMPANY, a Massachusetts corporation, hereinafter called
"Customer."
WHEREAS, in conjunction with Article VII of the August 31, 1998
Stipulation and Agreement in Pipeline's Docket Nos. RP97-406-000, et al.,
Pipeline and Customer have agreed to establish an agreement under Pipeline's
Rate Schedule GSS, which will ultimately supplant the "Service Agreement
Applicable To the Storage of Natural Gas Under Rate Schedule GSS-II (Part 284 --
North Summit)" between Pipeline and Customer dated September 1, 1997, commencing
effective as of November 1, 1998.
WITNESSETH: That in consideration of the mutual covenants herein
contained, the parties hereto agree that Pipeline will store natural gas for
Customer during the term, at the rates and on the terms and conditions
hereinafter provided:
Article I. Quantities
Beginning as of November 1, 1998 and thereafter for the remaining term of
this agreement, Customer agrees to deliver to Pipeline and Pipeline agrees to
receive for storage in Pipeline's underground storage properties, and Pipeline
agrees to inject or cause to be injected into storage for Customer's account,
store, withdraw from storage, and deliver to Customer and Customer agrees to
receive, quantities of natural gas as set forth on Exhibit A. attached hereto.
Article II. Rate
A. For storage service rendered by Pipeline to Customer hereunder,
Customer shall pay Pipeline the maximum rates and charges provided under Rate
Schedule GSS contained in Pipeline's effective FERC Gas Tariff or any effective
superseding rate schedule.
B. Pipeline shall have the right to propose, file, and make effective with
the FERC or any other body having jurisdiction, revisions to any applicable rate
schedule, or to propose, file, and make effective superseding rate schedules for
the purpose of changing the rate, charges, and other provisions thereof
effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule
GSS "Applicability and Character of Service," (ii) term, (iii) quantities, and
(iv) points of receipt and points of delivery shall not be subject to unilateral
change under this Article. Said rate schedule or superseding rate schedule and
any revisions thereof which shall be filed and made effective shall apply to and
become a part of this Service Agreement. The
- 1 -
<PAGE>
CNG Contract No. 300115
filing of such changes and revisions to applicable rate schedule shall be
without prejudice to the right of Customer to contest or oppose such filing and
its effectiveness.
C. The Storage Demand Charge and the Storage Capacity Charge provided in
the aforesaid rate schedule shall commence on November 1, 1998.
Article III. Term of Agreement
Subject to all the terms and conditions herein, this Agreement shall be
effective as of November 1, 1998, and shall continue in effect for a primary
term through and including March 31, 2012, and for subsequent annual terms of
April 1 through March 31 thereafter, until either party terminates this
Agreement by giving written notice to the other at least twenty-four months
prior to the start of an annual term.
Article IV. Points of Receipt and Delivery
The Points of Receipt for Customer's tender of storage injection
quantities, and the Point(s) of Delivery for withdrawals from storage shall be
specified on Exhibit A, attached hereto.
Article V. Incorporation By Reference of Tariff Provisions
To the extent not inconsistent with the terms and conditions of this
Agreement, the following provisions of Seller's effective FERC Gas Tariff, and
any revisions thereof that may be made effective hereafter are hereby made
applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule GSS, or any effective
superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as
they may be revised or superseded from time to time.
Article VI. Miscellaneous
A. No change, modification or alteration of this Agreement shall be or
become effective until executed in writing by the parties hereto; provided,
however, that the parties do not intend that this Article VI.A. requires a
further written agreement either prior to the making of any request or filing
permitted under Article II hereof or prior to the effectiveness of such request
or filing after Commission approval, provided further, however, that nothing in
this Agreement shall be deemed to prejudice any position the parties may take as
to whether the request, filing or revision permitted under Article II must be
made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any
notice which either party may desire to give the other, shall be in writing and
sent to the following addresses:
- 2 -
<PAGE>
CNG Contract No. 300115
Pipeline: CNG Transmission Corporation
445 West Main Street
Clarksburg, West Virginia 26301
Attention: Vice President, Wholesale Marketing
Fax: (304) 623-8323
Customer: Colonial Gas Company
40 Market Street
Lowell, Massachusetts 01852
Attention: Senior Vice President, Gas Supply
Fax: (978) 459-2314
or at such other address as either party shall designate by formal written
notice.
C. No presumption shall operate in favor of or against either party hereto
as a result of any responsibility either party may have had for drafting this
Agreement.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized officials as of the day and year first above
written.
CNG TRANSMISSION CORPORATION
(Pipeline)
By: /s/ George B. Carter
-----------------------------
Its: Vice President
COLONIAL GAS COMPANY
(Customer)
By: /s/ John P. Harrington
-----------------------------
Its: Senior V.P. - Gas Supply
-----------------------------
(Title)
- 3 -
<PAGE>
EXHIBIT A (Contract No. 300115)
To The GSS (North Summit) Storage Service Agreement
Dated November 1, 1998
Between CNG Transmission Corporation and
Colonial Gas Company
A. Quantities
The quantities of natural gas storage service that Customer may utilize
under this Service Agreement, as well as Customer's applicable Billing
Determinants, are as follows:
1. For the period November 1, 1998 through and including October 31,
1999:
a. A Storage Demand of 21 Dekatherms (Dt) per Day; and
b. A Storage Capacity of 2,080 Dt.
2. For the period November 1,1999 through and including October 31,
2000:
a. A Storage Demand of 47 Dt per Day; and
b. A Storage Capacity of 4,680 Dt.
3. For the period November 1, 2000 through and including October 31,
2001:
a. A Storage Demand of 67 Dt per Day; and
b. A Storage Capacity of 6,760 Dt.
4. For the period November 1, 2001 through and including October 31,
2002:
a. A Storage Demand of 87 Dt per Day; and
b. A Storage Capacity of 8,840 Dt.
5. For the period November 1, 2002 through and including the remaining
term of this Agreement:
a. A Storage Demand of 104 Dt per Day; and
b. A Storage Capacity of 10,400 Dt.
B. Points of Receipt and Delivery
1. The Point of Receipt for Customer's tender of storage injection
quantities, and the maximum quantities and character of service for
such point shall be as set forth below. Each of the parties will use
due care and diligence to assure that uniform pressures will be
maintained at the Receipt Point as reasonably may be required to
render service
<PAGE>
Exhibit A (Contract No. 300115)
November 1, 1998 GSS (North Summit) Agreement
Between CNG Transmission Corporation and
Colonial Gas Company
Page 2 of 2
hereunder, but Pipeline will not be required to accept gas at less
than the minimum pressures specified herein.
a. Up to Customer's maximum daily entitlement for injection as
determined under Rate Schedule GSS, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern Transmission Corporation (Texas Eastern) located in
Fayette County, Pennsylvania and known as the North Summit
Interconnection, at a pressure of not less than seven hundred
(700) pounds per square inch gauge ("psig").
2. The Points of Delivery for withdrawals from storage, and the maximum
quantities and character of service for each point, shall be as set
forth below. Each of the parties will use due care and diligence to
assure that uniform pressures will be maintained at the Delivery
Points as reasonably may be required to render service hereunder,
but Pipeline will not be required to deliver gas at greater than the
maximum pressures specified herein.
a. Up to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern located in Fayette County, Pennsylvania, known as the
North Summit Interconnection, at a pressure of not more than
one thousand (1,000) psig.
b. On an interruptible basis if operating conditions permit, up
to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern located in Greene County, Pennsylvania and known as
the Crayne Interconnection, at a pressure of not more than
eight hundred sixty-five (865) psig.
c. On an interruptible basis if operating conditions permit, up
to Customer's maximum daily entitlement for withdrawal as
determined under Rate Schedule GSS, at an existing point of
interconnection between the facilities of Pipeline and Texas
Eastern located in Westmoreland County, Pennsylvania and known
as the Oakford Interconnection, at a pressure of not less than
eight hundred fifty (850) psig.
<PAGE>
[LOGO]
COLONIAL
GAS COMPANY
January 12, 1999
UNITED PARCEL SERVICE
OVERNIGHT DELIVERY
Robert G. Riga, Director
East Coast Marketing
Algonquin Gas Transmission Company
1284 Soldiers Field Road
Boston, MA 02135
RE: (1) Letter Agreement sent December 11, 1998; and
(2) Service Agreement - Rate Schedule AFT-1
Dear Bob:
First, pursuant to your letter dated December 11, 1998, enclosed are two
partially executed originals of the Letter Agreement between Texas Eastern
Transmission Corporation and Colonial Gas Company. Please fully execute both
copies and return one for our files. Second, please find enclosed a fully
executed Algonquin Gas Transmission Company Service Agreement - Rate Schedule
AFT-1 (Contract No. 97036) for your files.
If you have any questions concerning the enclosed documents, please do not
hesitate to contact me directly at (978) 322-3202.
Sincerely,
/s/ Bruce B. Glendening
Bruce B. Glendening
Regulatory Counsel
BBG/gad
Enclosures
cc: John P. Harrington-Colonial Gas Company
<PAGE>
EXHIBIT 10.47
[LOGO]
Duke
Energy(SM)
Texas Eastern
Transmission Corporation
Algonquin Gas
Transmission Company
Duke Energy Companies
1284 Soldiers Field Road
Boston, MA 02135
Thomas C. O'Connor
Vice President January 6, 1999 617/560-1386 OFFICE
East Coast Marketing 617/560-1392 FAX
via Overnight Delivery
Mr. John P. Harrington
Senior Vice President
Colonial Gas Company
40 Market Street
P.O. Box 3064
Lowell, MA 01853
RE: Firm Transportation Service Agreements between
Texas Eastern Transmission Corporation and Colonial Gas Company
Dear John:
Texas Eastern Transmission Corporation ("Pipeline") and Colonial Gas
Company ("Customer") are parties to certain firm transportation service
agreements entered into pursuant to rate schedules on file as part of Pipeline's
FERC Gas Tariff (Pipeline Contract Nos. 330869, 800288, 800289, 800313, 800400,
800419, 800420, 800469, and 800470, referred to herein individually and
collectively as the ("Service Agreements")). Pursuant to Customer's request as a
result of its increasingly competitive market environment and in consideration
of the mutual covenants and agreements contained herein, Pipeline and Customer
hereby agree as follows:
1. Beginning August 1, 2001, and continuing through July 31, 2003, ("Discount
Term"), Pipeline agrees to discount the reservation charge rates
applicable to the Service Agreements by an amount calculated to achieve a
$13,639.17 per month reduction in reservation charges during the Discount
Term. The discount agreed to herein shall not be applicable to any time
period during which the rate reduction set forth in Article IV of the
Offer of Settlement filed with and approved by the Federal Energy
Regulatory Commission in Docket Nos. RP98-198-000 and RP85-177-126 is in
effect. Notwithstanding, however, in no event will Pipeline charge a rate
greater than or less than the respective maximum or minimum rates on file
with the Federal Energy Regulatory Commission ("Commission") for service
under the Service Agreements. At the expiration of the Discount Term, the
rates for service under the Service
<PAGE>
Mr. John P. Harrington
Colonial Gas Company
January 6, 1999
Page 2
Agreements will be the maximum filed tariff rates under Pipeline's
applicable rate schedules pursuant to which service under the Service
Agreements is provided, plus all applicable surcharges and Applicable
Shrinkage, unless otherwise agreed to in writing by the parties.
2. Pipeline and Customer recognize that Pipeline's rates, including current
or future surcharges, for service under the Service Agreements may be
subject to modification from time to time. With regard to the rates for
service under the Service Agreements, Pipeline and Customer expressly
agree that Customer shall be entitled to refunds of payments paid by
Customer pursuant to the Service Agreements only in the event the total
final, non-appealable maximum rates as determined by the Commission for a
given time period ("Final Maximum Rate") is lower than the total rate
actually paid by Customer during such period ("Actual Rate"). Subject to
the condition precedent set forth in the foregoing sentence, Customer's
principal refund shall be equal to the product of (i) the difference
between the Actual Rate and the Final Maximum Rate and (ii) Customer's MDQ
specified in the Service Agreements during the refund period. Customer
expressly agrees not to initiate, instigate, or otherwise participate in
any action or proceeding for the purpose of obtaining refunds in excess of
the foregoing amount.
3. Customer acknowledges and agrees that all terms and conditions of
Pipeline's FERC Gas Tariff, as effective from time to time, and applicable
form of service agreement, including provisions for filing of changes in
Pipeline's FERC Gas Tariff and in rates, which changes may affect this
Agreement, are applicable to the Service Agreements. In the event of a
conflict between this Agreement and Pipeline's FERC Gas Tariff and/or form
of service agreement, Pipeline's FERC Gas Tariff and/or the form of
service agreement shall control.
4. This Agreement shall be interpreted and performed in accordance with the
laws of the State of Texas without recourse to the law governing conflict
of laws.
5. The terms and conditions of this Agreement shall be effective only during
the period beginning August 1, 2001 and continuing through July 31, 2003
and shall apply only to the Service Agreements.
<PAGE>
Mr. John P. Harrington
Colonial Gas Company
January 6, 1999
Page 3
If the terms and conditions set forth in this Agreement are in accordance
with our understanding and agreement, please execute this Agreement in the space
provided below and return all originals to Pipeline. A fully executed original
will be returned to you for your records.
Very truly yours,
Thomas C. O'Connor
Vice President
Texas Eastern Transmission Corporation
Algonquin Gas Transmission Company
ACCEPTED AND AGREED TO
THIS 11th DAY OF JANUARY, 1999
COLONIAL GAS COMPANY
By: /s/ John P. Harrington
-----------------------------
Title: Senior V.P. - Gas Supply
--------------------------
<PAGE>
[LOGO] TENNESSEE
GAS PIPELINE
an El Paso Energy company
-------------------------------------------------------------------------
EXHIBIT 10.49
August 27, 1999
Colonial Gas Company
40 Market Street
Lowell, MA 01853-3064
Attention: Mr. Nickolas Stavropoulos via facsimile: (617) 742-0041
RE: CONTRACT RESTRUCTURING LETTER AGREEMENT
Dear Nick:
This Contract Restructuring Letter Agreement ("Letter Agreement") is
entered into between Tennessee Gas Pipeline Company ("Tennessee") and Colonial
Gas Company ("Colonial"). Whereas, Tennessee and Colonial (being hereinafter
individually referred to as a "Party" and collectively referred to as the
"Parties"), have agreed upon the terms and conditions under which to extend and
amend certain Firm Transportation and Storage Service Agreements ("Firm
Agreements") to restructure the firm services received by Colonial from
Tennessee (hereinafter referred to as "Contract Restructuring"). The Parties
wish to proceed with the Contract Restructuring based on the following terms and
principles subject to the execution and regulatory approval of final agreements
effectuating the provisions described herein.
1. Primary Point Amendment
Subject to Colonial's participation in an open season to change primary
points in accordance with Article XXVIII, Section 5.7 of the General Terms
and Conditions of Tennessee's FERC Gas Tariff, Tennessee shall allow
Colonial to amend the Firm Agreements identified below to effectuate a
change in primary receipt points from meters located in Zones 00, 0L, and
01 to meter number 07-0018, Tennessee's Northern Storage Withdrawal
(located in Tennessee's Zone 4) to be effective on November 1, 1999;
provided, however, Colonial's rights shall be limited in accordance with
the quantity limitations detailed in Appendix A attached hereto. The
reduction of primary firm receipt meter TQ by the applicable percentages
and resulting quantities from the current primary receipt points in Zones
00, 0L, and 01 shall be implemented pro-rata across the Firm Agreements
identified below at all affected meters. Thus, the currently existing
Zones 00, 0L, and 01 primary receipt points by Firm Agreement shall each
be reduced individually by the applicable amendment percentage and meter
number 07-0018
<PAGE>
Contract Restructuring Letter Agreement
August 27, 1999
Page 2
shall be increased by the like quantity so that the receipt quantity of
each Firm Agreement is thereby preserved.
In consideration of the merger of Colonial with Eastern Enterprises, Essex
County Gas Company's ("Essex") parent company, Colonial's rights to amend
the Firm Agreements identified below to effectuate a change in primary
receipt points from meters located in Zones 00, 0L, and 01 to meter number
07-0018, Tennessee's Northern Storage Withdrawal (located in Tennessee's
Zone 4) to be effective on November 1, 1999 shall be enlarged as detailed
in Appendix A subject to an election by Essex by September 30, 1999 to
extend 100% of the current MDQ of FT-A Agreement No. 8518 for a Primary
Extended Term of at least three (3) years.
K# 10/31/2003
-- ----------
Retain 100% of the Firm Agreements 2025 & 435 15%
(Identified in Item 2 below) and
Essex Retains 100% of FT-A Agreement 8518
Retain 100% of the Firm Agreements 2025 & 435 10%
(Identified in Item 2 below) and
Essex Turns back 100% of FT-A Agreement 8518
Appendix A also details the associated buyout amounts by Firm Agreement.
The buyout amounts outlined in Appendix A are equivalent to 60% of the
effective upstream (Zones 00/01 to 04) annual demand charge multiplied by
the applicable amendment quantity. The buyout payment will be due to
Tennessee prior to October 31, 1999.
2. Term
Subject to Colonial's amendment of the Firm Agreements as described in
Item 1 above, Colonial shall elect to extend 100% of the currently
existing Transportation Quantity ("TQ") or Maximum Storage Quantity
("MSQ"), as applicable, of each of the following Firm Agreements pursuant
to Article III, Section 10.5 of the General Terms and Conditions of
Tennessee's FERC Gas Tariff for a period of three years such that the
subsequent expiration date of each of the Firm Agreements is October 31,
2003: Firm Agreement Nos. 2025, 2029 and 524. Each extension shall
continue the Primary Extended Term as outlined in Section 10.5. Unless
otherwise expressly agreed by Tennessee, as applicable, Colonial's
currently existing Maximum Daily Injection Quantity, Maximum Daily
Withdrawal Quantity and ratchet levels shall remain in effect through the
Primary Extended Term.
<PAGE>
Contract Restructuring Letter Agreement
August 27, 1999
Page 3
3. Rate
Subject to Colonial's amendment of the Firm Agreements as described in
Item 1 above and to Colonial's extension of the FT-A Agreements as
described in Item 2 above and for the period commencing November 1, 1999
and extending through the Primary Extended Term, Colonial shall pay a
negotiated rate for service comprised of the following: (1) Tennessee's
Base Reservation Rate effective as of November 1, 1999; and (2)
Tennessee's Base Commodity Rate effective as of November 1, 1999. In
addition, Colonial shall pay all then-effective surcharges and applicable
fuel (The rates are therefore fixed, but the surcharges and fuel charges
are not).
Subject to Colonial's amendment of the Firm Agreements as described in
Item 1 above and to Colonial's extension of the FS-MA Agreement referenced
in Item 2 above and for the period commencing November 1, 1999 and
extending through the Primary Extended Term, Colonial shall pay a
negotiated rate for service comprised of the following: Tennessee's Tariff
Rate effective as of November 1, 1999 for deliverability, space,
injection, withdrawal and overrun. In addition, Colonial shall pay all
then-effective surcharges and applicable fuel. (The rates are therefore
fixed, but the surcharges and fuel charges are not).
During the period defined above, this Letter Agreement shall be the sole
agreement between the Parties affecting the rates for service provided
under Firm Agreement Nos. 2025, 2029, 435 and 524.
4. Buyout of Upstream/Midhaul Contracts
On or before October 1, 1999, Colonial will execute a Buyout Agreement to
effectuate early termination and the buyout of upstream/midhaul FT-A
Agreement Nos. 3894, 2521 and 2496 effective November 1, 1999. On or
before October 31, 1999, Colonial will submit buyout payment of $608,514
to Tennessee or will authorize Tennessee to reduce the refund to which
Colonial is entitled in accordance with Tennessee's GSR Stipulation and
Agreement and the Commission's June 15, 1999 order in Docket No.
RP93-151-026 ("GSR Refund") combined with any other current refunds due
Colonial in the same amount or some combination of a buyout payment and
refund credits. Colonial's execution of this Letter Agreement signifies
its consent to Tennessee's withholding the GSR Refund unless and until
Colonial advises Tennessee in writing of its decision to receive the GSR
Refund.
5. National Fuel/Tennessee Northern Storage Receipt Point Amendment
Pursuant to the NPV open season process outlined in Section 5.7 of Article
XXVIII of Tennessee's FERC Gas Tariff on or before August 31, 1999,
Colonial will submit an amendment request effective April 1, 2000 or
November 1, 2000 to amend approximately 10,000 Dth/d of receipt point
capacity on FT-A Agreement
<PAGE>
Contract Restructuring Letter Agreement
August 27, 1999
Page 4
No. 10778 from the National Fuel Andrews Settlement receipt point (meter
number 1-1693) to Tennessee Northern Storage (meter number 7-0018).
6. Letter Agreement
This Letter Agreement shall be treated as confidential and the Parties
agree not to disclose any information concerning this Letter Agreement
including, without limitation, the existence of this letter Agreement
without the prior written consent of the other Party except to employees,
consultants, agents and advisors who must be aware of the Letter Agreement
to perform the Party's obligations hereunder if these persons have agreed
to be bound by the Parties' confidentiality obligations; provided,
however, either Party may disclose the terms of this letter Agreement if:
one, such disclosure is required in a judicial or administrative process
in connection with any action, suit, proceeding, investigation, audit or
claim or otherwise by applicable law and two, the Party requests
confidential treatment of the disclosure in the judicial or administrative
process.
Notwithstanding anything herein to the contrary, this Letter Agreement and
the execution of any agreements to effectuate the arrangements proposed in
this Letter Agreement shall be in accordance with and subject to the terms
of Tennessee's FERC Gas Tariff and to all valid laws, orders, rules and
regulations of duly constituted authorities having jurisdiction as amended
from time to time and to the receipt and acceptance of all regulatory
authorizations necessary on terms acceptable to Tennessee; provided
further, if the regulatory authorizations are not received in time to
implement all of the terms of this Letter Agreement by November 1, 1999,
Tennessee shall have the right to terminate this Letter Agreement at any
time prior to November 1, 1999.
Colonial and Tennessee agree to cooperate in the preparation and filing of
all necessary applications for authorizations and to support such filings
in their entirety to effectuate the arrangements proposed in this Letter
Agreement.
This Letter Agreement supercedes the August 2, 1999 Contract Restructuring
Letter Agreement signed by the Parties on August 19, 1999.
If this Letter Agreement accurately represents your understanding of the
agreement among Tennessee and Colonial, please have the appropriate party
execute the facsimile copy of this Letter Agreement and return same to the
undersigned.
<PAGE>
Contract Restructuring Letter Agreement
August 27, 1999
Page 5
Upon execution by Tennessee, I will fax one (1) fully executed copy of the
Letter Agreement for your retention. If you have any questions, please do not
hesitate to contact me at (713) 420-3627.
Sincerely
/s/ James R. Eckert
James R. Eckert
Account Manager
Marketing Northern Accounts
AGREED TO AND ACCEPTED AGREED TO AND ACCEPTED
THIS 2ND DAY OF SEPTEMBER, 1999, THIS 2ND DAY OF SEPT, 1999,
TENNESSEE GAS PIPELINE COLONIAL GAS COMPANY
COMPANY
By: /s/ Mary M. Melendez By: /s/ Nickolas Stavropoulos
-------------------------------- ------------------------------
Name: Mary M. Melendez Name: Nickolas Stavropoulos
-------------------------------- ------------------------------
Its: Agent and Attorney-in-Fact Its:
-------------------------------- ------------------------------
<PAGE>
Contract Restructuring Letter Agreement
Between Tennessee and Colonial
Appendix A
1/ FT-A Agreement No. 435 FT-A Agreement No. 2025
Amendment -------------------------- ------------------------
Percentage Zone 0 Zone L Zone 1 Zone 0 Zone L Zone 1 Total Dth/d
- ---------- -------------------------- ------------------------ -----------
15% 1,500 1,095 - 1,323 2,457 - 8,375
10% 2/ 1,000 730 - 882 1,638 - 4,250
1/ FT-A Agreement No. 435 FT-A Agreement No. 2025
Amendment -------------------------- ------------------------ Total
Percentage Zone 0 Zone L Zone 1 Zone 0 Zone L Zone 1 Buyout
- ---------- -------------------------- ------------------------ -----------
15% 131,976 84,911 - 116,390 190,491 - $ 623,767
10% 2/ 87,984 56,607 - 77,593 126,994 - $ 349,178
Footnotes:
- ----------
1/ As detailed in the Contract Restructuring Letter Agreement,
Colonial's rights to amend the Firm Agreements identified above
shall be enlarged (to the 15% level) subject to an election by Essex
by September 30, 1999 to extend 100% of the current MDQ on Essex'
FT-A Agreement No. 8518 for a Primary Extended Term of at least 3
years.
2/ Amendment percentage and corresponding limitation assuming Essex
decides to not renew 100% of the current MDQ on Essex' FT-A
Agreement No. 8518 for a Primary Extended Term of at least 3 years.
<PAGE>
EXHIBIT 23a
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated January 21, 2000, included in this Form 10-K, into Colonial Gas
Company's previously filed Registration Statement Form S-3, File No. 333-48561.
Arthur Andersen LLP
Boston, Massachusetts
March 14, 2000
<PAGE>
EXHIBIT 23b
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our reports dated January 15, 1999, accompanying the consolidated
financial statements and schedule 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, 1998. We hereby consent to the incorporation by reference of
said reports in the Colonial Gas Company Registration Statements on Form S-3
(File No. 333-48561).
Grant Thornton LLP
Boston, Massachusetts
March 14, 2000
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