<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 2-23416
BOSTON GAS COMPANY
(Exact Name of Registrant As Specified In Its Charter)
Massachusetts 04-1103580
(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, 514,184 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>
BOSTON GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 1999
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Item
No. Topic Page
---- ----- ----
<C> <S> <C>
PART I
1. Business
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 7
Matters...........................................................
6. Selected Financial Data........................................... 7
7. Management's Discussion and Analysis of Financial Condition and 7
Results of Operations.............................................
8. Financial Statements and Supplementary Data....................... 10
9. Changes in and Disagreements with Accountants on Accounting and 10
Financial Disclosure..............................................
PART III
10. Directors and Executive Officers of the Registrant................ 11
11. Executive Compensation............................................ 11
12. Security Ownership of Certain Beneficial Owners and Management.... 11
13. Certain Relationships and Related Transactions.................... 11
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 12
</TABLE>
<PAGE>
PART I
Item 1. Business.
General
Boston Gas Company (the "Company"), is engaged in the transportation and
sale of natural gas to approximately 541,000 residential, commercial and
industrial customers in Boston, Massachusetts and 73 other communities in
eastern and central Massachusetts. The Company is the largest natural gas
distribution company in New England and has been in business for 177 years.
All of the common stock of the Company is held by Eastern Enterprises
("Eastern"), which is headquartered in Weston, Massachusetts. Eastern has
owned Boston Gas Company since 1929.
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 4,700 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,
throughout its service territory. Over the last seven years, the Company has
increased its share in the total stationary energy market from 31% to 38%.
This market share compares to the national level of approximately 43%, and
represents a growth opportunity for the Company. However, future market share
cannot be predicted with certainty, and will depend on such factors as the
price of competitive energy sources, the level of investment required and
customer perception of relative value.
1
<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.................................... 39.3 37.9 41.7
Commercial and industrial...................... 27.3 28.2 35.7
Off-system sales............................... 5.6 12.7 7.4
-------- -------- --------
Total sales.................................. 72.2 78.8 84.8
Transportation of customer-owned gas........... 56.4 65.6 80.9
Less: Off-system sales......................... (5.6) (12.7) (7.4)
-------- -------- --------
Total throughput............................. 123.0 131.7 158.3
======== ======== ========
Total firm throughput........................ 109.1 107.8 120.0
======== ======== ========
</TABLE>
The above table excludes the effect of adopting the accrual method of
revenue recognition as discussed in Note 1 of Notes to Consolidated Financial
Statements.
In 1999, residential customers comprised 92% of the Company's customer
base, while commercial and industrial establishments accounted for the
remaining 8%. Volumetrically, residential customers accounted for 32% of total
throughput and 36% of total firm throughput, while commercial and industrial
customers accounted for 68% of total throughput and 64% of total firm
throughput. Approximately 67% of commercial and industrial customers' total
throughput was transportation-only service. Sithe Energy, an independent power
generator on the Company's system, was responsible for approximately 28% of
this transportation throughput under a contract which expires in November,
2000. The Company is uncertain whether or to what extent this contract will be
renewed.
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.......................... 65.9 71.2 75.2
Underground storage withdrawal................. 9.9 10.9 14.5
Liquefied natural gas ("LNG") purchases........ 1.9 -- 1.4
-------- -------- --------
Total source of supply....................... 77.7 82.1 91.1
Company use, unbilled and other................ (5.5) (3.3) (6.3)
-------- -------- --------
Total sales.................................. 72.2 78.8 84.8
======== ======== ========
</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 two-thirds
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
2
<PAGE>
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 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")... 0.27 80.4 2000-2012
Tennessee Gas Pipeline Company ("Tennessee")....... 0.18 66.9 2003-2012
---- -----
0.45 147.3
==== =====
</TABLE>
In 1999, the Company restructured its long term capacity contracts with
Tennessee Gas Pipeline. As a result, no contracts expire 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 the 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 17.3 BCF and peak day deliverability of 0.16 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
and produced from foreign and domestic sources.
In the fall of 1999, the Company, and its affiliates Colonial 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.
Peak day firm throughput in BCF was 0.64 in 1999, 0.57 in 1998, and 0.61 in
1997. 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 owns propane air facilities and an
LNG facility in Dorchester, Massachusetts. The Company also leases two LNG
facilities sited on land owned by the Company in Salem and Lynn,
Massachusetts, and leases space in facilities located in Providence, RI and
Everett, MA. 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>
The Company's rates for local transportation service are governed by the
five year performance-based rate plan approved by the Department in 1996.
Under the plan approved by the Department, the Company's local transportation
rates are recalculated annually to reflect inflation for the previous 12
months, and reduced by a productivity factor of .50 percent. The productivity
factor will be the subject of a remand proceeding at the Department as
discussed below. The plan also provides for penalties if the Company fails to
meet specified service quality measures, with a maximum potential exposure of
$1 million, which will also be a subject in the Department's remand
proceeding. There is a margin sharing mechanism, whereby 25% of earnings in
excess of a 15% return on year-ending equity are to be passed back to
ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. The final year of the plan is November 1, 2001
through October 31, 2002. With respect to the appeal by the Company of the
Department's Order in D.P.U. 96-50, the Supreme Judicial Court issued an order
vacating: 1) the "accumulated inefficiencies" component of the productivity
factor, thereby reducing the productivity factor from 1.50 percent to .50
percent; and 2) the expansion of the service quality penalty beyond the $1
million proposed by the Company, and remanded these matters to the Department
for further proceedings, which actions were requested by the Department in its
motion for discharge of report and remand. The Department has stated that it
would consider in the remand proceedings whether there should be retroactive
recovery of those charges vacated by the court.
All of the Company's 43,000 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 approximately 4,700 firm transportation customers. Under the
February 1, 1999 Order by the Department which approved the 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 Local Distribution Companies
("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.
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 former manufactured gas plant ("MGP") operations,
including former operating plants, gas holder locations and satellite disposal
sites. Information with respect to the remediation of these sites may be found
in Note 11 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
Employees
As of December 31, 1999, the Company had approximately 1,300 employees, 70%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 2002. During 1999, the Company entered
into new three-year labor agreements with the bargaining units representing
union employees.
Item 2. Properties.
The Company operates three LNG facilities in Dorchester, Salem, and Lynn,
Massachusetts. These facilities provide the Company with local storage of gas,
as the stored LNG can be vaporized into the distribution system to supplement
pipeline gas in periods of high demand. The Company owns the Dorchester
facility. The Company owns the real property at the Salem and Lynn facilities
and rents the storage facilities under a long-term lease arrangement.
The Company owns propane-air facilities at various locations throughout its
service territory.
On December 31, 1999, the Company's distribution system included
approximately 6,000 miles of gas mains, 422,000 services and 546,000 active
customer meters. A majority of the gas mains consist of cast iron and bare
steel, which require ongoing maintenance and replacement.
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 approximately $57 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 $67
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.
Performance-Based Regulatory Plan--Incentive ratemaking mechanism, typically
a price cap plan, whereby rates are adjusted annually pursuant to a pre-
determined formula tied to a measure of inflation, less a productivity offset,
subject to the achievement of service quality measures and the incurrence of
exogenous factors.
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 on such common equity amounted to $27.3
million and $17.9 million for 1999 and 1998, respectively.
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
Net earnings applicable to common stock for 1999 were $37.9 million
compared to $44.4 million for 1998. The 1998 results include a one-time
increase in net earnings of $8.2 million due to the cumulative effect of a
change in accounting for revenue recognition. Excluding the cumulative effect
of the accounting change, net earnings applicable to common stock for 1999
increased $1.7 million or 4.6% from 1998.
Operating revenues in 1999 decreased $17.6 million, or 2.9% primarily due
to lower gas costs ($22 million), the migration of customers from sales to
transportation service ($12 million) and lower non-firm sales ($19 million).
The revenue reduction associated with lower gas costs and the migration of
customers to transportation service has no impact on earnings, as the Company
earns all of its margins on the local distribution of gas and none on the sale
of the commodity itself. Partially offsetting this decrease was increased
revenues due to colder weather ($24 million) and customer growth ($9 million).
Operating margin increased $11.9 million, or 4.2% due to weather which was
5% colder than 1998 ($7 million) and customer growth ($4 million). Weather for
1999 was 5% warmer than normal.
Operations and maintenance expenses increased $10.6 million, or 7.5%,
principally due to the absence of service contract revenue of approximately $5
million for annual contracts not renewed due to the Company's decision to exit
the gas appliance service business in 1997. In addition, the increase was due
to a charge of $2.2 million for an early retirement program and increased
maintenance, insurance and information technology expenses. These were
partially offset by lower bad debt expense reflecting improved collection
experience.
Other earnings, net increased $1.4 million due to interest income of $.8
million on a tax settlement with the Internal Revenue Service and a higher
level of short-term investments.
1998 Compared to 1997
Net earnings applicable to common stock for 1998 were $44.4 million which
includes the effect of a change in accounting for revenue recognition (see
Note 1 of Notes to The Financial Statements). This change in accounting
increased net earnings by $8.6 million, consisting of a one-time cumulative
effect for the years prior to 1998 of $8.2 million plus the impact of the
change on 1998 earnings of $.4 million. Excluding the effect of the change in
accounting, net earnings applicable to common stock were $35.8 million, a
decrease of $.8 million, or 2%, as compared to 1997.
Revenues in 1998 decreased $90.6 million or 13% compared to 1997. This
decrease reflects warmer weather ($46 million), the migration of customers
from sales to transportation service ($22 million), lower gas costs ($15
7
<PAGE>
million), the absence of a 1997 non-recurring increase in revenues of $8.9
million related to a 1996 rate ruling in the recovery mechanism for the
portion of bad debt expense associated with gas costs and lower non-firm
sales, partially offset by throughput growth and higher average rates. The
revenue decrease associated with customer migration and lower gas costs has no
impact on earnings as the Company earns all of its margins on the local
distribution of gas and none on the sale of the commodity itself.
Operating margin decreased $16.6 million, or 5.5%, principally due to
weather which was 13% warmer than 1997 ($13 million) and the absence of a 1997
non-recurring increase in revenues of $8.9 million described earlier partially
offset by customer growth ($4 million) and higher rates. Weather for 1998 was
9% warmer than normal compared to 4% colder than normal as experienced in
1997.
Operations and maintenance expenses decreased $7.9 million or 5.3%,
principally due to the recognition of service contract revenue of
approximately $5 million for annual contracts expiring in the third quarter of
1998 in addition to the reduction of related costs due to the Company's
decision to exit the gas appliance service business in 1997. Also contributing
to the decrease were warmer weather conditions and continued cost control
measures partially offset by the absence of a $2.1 million gain on the
settlement of pension obligations which occured in 1997.
Depreciation and amortization increased $2.1 million, or 5%, reflecting
continued investment in system expansion and replacement.
The absence of a 1997 restructuring charge of $8.7 million was offset by
the absence of the 1997 non-recurring revenue increase described earlier.
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.
The Company's cost to achieve Year 2000 compliance was approximately $15
million. Approximately 70% of these costs were incurred for capital projects
that resulted in added functionality.
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 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
To meet cash requirements and support its commercial paper program, the
Company has available up to $75 million of Eastern's committed credit
agreement and a $40 million uncommitted line of credit. The Company
8
<PAGE>
also maintains a credit agreement that provides for the borrowing of up to $70
million for the exclusive purpose of funding its inventory of gas supplies or
to back commercial paper issued for the same purpose.
The Company expects capital expenditures for 2000 to be approximately $67
million. Capital expenditures will be largely for improvements to the
distribution system, for system expansion to meet customer growth and for
productivity improvements.
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 collects 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.
The Company's rates for local transportation service are governed by the
five year performance-based rate plan approved by the Department in 1996.
Under the plan approved by the Department, the Company's local transportation
rates are recalculated annually to reflect inflation for the previous 12
months, and reduced by a productivity factor of .50 percent. The productivity
factor will be the subject of a remand proceeding at the Department as
discussed below. The plan also provides for penalties if the Company fails to
meet specified service quality measures, with a maximum potential exposure of
$1 million, which will also be a subject in the Department's remand
proceeding. There is a margin sharing mechanism, whereby 25% of earnings in
excess of a 15% return on year-ending equity are to be passed back to
ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. The final year of the plan is November 1, 2001
through October 31, 2002. With respect to the appeal by the Company of the
Department's Order in D.P.U. 96-50, the Supreme Judicial Court issued an order
vacating: 1) the "accumulated inefficiencies" component of the productivity
factor, thereby reducing the productivity factor from 1.50 percent to .50
percent; and 2) the expansion of the service quality penalty beyond the $1
million proposed by the Company, and remanded these matters to the Department
for further proceedings, which actions were requested by the Department in its
motion for discharge of report and remand. The Department has stated that it
would consider in the remand proceedings whether there should be retroactive
recovery of those charges vacated by the court.
All of the Company's 43,000 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 approximately 4,700 firm transportation customers. Under the
February 1, 1999 Order by the Department which approved the 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 Local Distribution Companies
("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
9
<PAGE>
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.
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of 19 sites related to former manufactured gas plant
("MGP") operations, including former operating plants, gas holder locations
and satellite disposal sites, as described in Note 11 of Notes to Consolidated
Financial Statements. A subsidiary of New England Electric System ("NEES") has
assumed responsibility for remediating 11 of these sites, subject to a limited
contribution from the Company. The Company may also have or share
responsibility for the remediation of one non-MGP site. The Company has
recorded a liability of $18 million, which represents its best estimate at
this time of remediation costs, which may reasonably be estimated to range
from $18 million to $34 million. However, there can be no assurance that
actual costs will not vary considerably from these estimates.
The Company is aware of 30 other former MGP related sites within its
service territory, nine of which were identified in 1999. The NEES subsidiary
has provided full indemnification to the Company with respect to eight of the
30 sites. At this time, there is substantial uncertainty as to whether the
Company has or shares responsibility for remediating any of these other sites.
No notice of responsibility has been issued to the Company for any of these
sites from any governmental environmental authority.
By a rate order issued on May 25, 1990, the Department approved the
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 has recognized an
insurance receivable of $3.3 million, reflecting a negotiated settlement with
an insurance carrier for environmental expense indemnity, and a regulatory
asset of $14.7 million, representing the expected rate recovery of
environmental remediation costs. In light of the indemnity agreement with the
NEES subsidiary, the Department rate order on MGP-related cost recovery, and
the expected cost of remediating the non-MGP site, the Company believes that
it is not probable that such costs will materially affect its financial
condition or results of operations.
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.
10
<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.
11
<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>
3.1 --Restated Articles of Organization, as amended (Filed as Exhibit 3.1
to the registration statement of the Company on Form S-3 (File No. 33-
48525)).*
3.2 --By-Laws of the Company as amended (Filed as Exhibit 1 to the Annual
Report of the Company on Form 10-K for the year ended December 31,
1976 (File No. 2-23416)).*
(Note: Certain instruments with respect to long-term debt of the
Company or its subsidiary are not filed herewith since no such
instrument authorizes securities in an amount greater than 10% of the
total assets of the Company and its subsidiary on a consolidated
basis. The Company agrees to furnish to the Securities and Exchange
Commission upon request a copy of any such omitted instrument of the
Company or its subsidiary.)
4.1 --Indenture dated as of December 1, 1989 between the Company and The
Bank of New York, Trustee (Filed as Exhibit 4.2 to the registration
statement of the Company on Form S-3 (File No. 33-31869)).*
4.2 --Agreement of Registration, Appointment and Acceptance dated as of
November 18, 1992 among the Company, The Bank of New York as Resigning
Trustee, and The First National Bank of Boston as Successor Trustee.
(Filed as an exhibit to registration statement of the Company on Form
S-3 (File No. 33-31869)).*
10.1 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline Company dated as of September 1, 1993 providing for
transportation of approximately 94,000 dekatherms of natural gas per
day (Filed as Exhibit 10.1 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1993).*
10.2 --Gas Transportation Contract between the Company and Texas Eastern
dated October 29, 1999 providing for transportation of approximately
48,133 dekatherms of natural gas per day (Filed herewith).
10.3 --Gas Transportation Contract between the Company and Texas Eastern
dated December 30, 1993 providing for transportation of approximately
32,000 dekatherms of natural gas per day (Filed as Exhibit 10.3 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1993).*
10.4 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 45,000
dekatherms of natural gas per day (Filed herewith).
10.5 --Gas Storage Agreement between the Company and Consolidated Gas Supply
Corporation dated
February 18, 1980 providing for storage demand of 934 dekatherms of
natural gas per day. (Filed
as Exhibit 20.3 to the Quarterly Report of the Company on Form 10-Q
for the quarter ended
March 31, 1982).*
10.6 --Gas Storage Agreement between the Company and Honeoye Storage
Corporation dated
October 11, 1985 providing for storage demand of 6,150 dekatherms of
natural gas per day.
(Filed as Exhibit 10.17 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1985).*
</TABLE>
12
<PAGE>
<TABLE>
<C> <S>
10.7 --Gas Storage Agreement between the Company and National Fuel
(formerly PennYork Energy Corporation) dated as of December 21, 1984
providing for storage demand of 6,031 dekatherms of Nataural gas per
day. (Filed as Exhibit 10.18 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1985).*
10.8 --Gas Sales Contract between the Company and Esso Resources Canada,
Limited, (now Imperial Oil of Canada, Ltd.) dated as of May 1, 1989.
(Filed as Exhibit 10.12 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1989).*
10.9 --Amendment to Exhibit 10.9, Gas Sales Contract between the Company
and Esso Resources (now Imperial Oil of Canada), dated as of November
12, 1997 and Bridge Agreement dated as of October 23, 1997, executed
pursuant to Master Agreement dated as of November 1, 1997. (Filed as
Exhibit 10.9.2 to the Annual Report of the Company on Form 10K for
the year ended December 31, 1998).*
10.10 --Gas Sales Agreement between the Company and Boundary Gas, Inc.,
dated as of September 14, 1987; and First Amendment hereto dated as
of January 1, 1990; Second Amendment thereto dated as of July 1,
1990; Third Amendment thereto dated as of 1991; Fourth Amendment
thereto dated as of June 5, 1991; Fifth Amendment thereto dated as of
May 4, 1993; Sixth Amendment thereto dated as of September 9, 1993;
Amendment thereto dated as of March 8, 1996; and Amendment thereto
dated as of August 20, 1997. (Filed as Exhibit 10.10 to the Annual
Report of the Company on Form 10K for the year ended December 31,
1994.)*
10.11 --Gas Sales Agreement between the Company and Alberta Northeast Gas,
Ltd. dated as of
February 7, 1991. (Filed as Exhibit 10.16 to the Annual Report of the
Company on Form 10-K for
the year ended December 31, 1990).*
10.12 --Amendments to Exhibit 10.12, Gas Sales Agreement between the Company
and Alberta Northeast Gas, Ltd., dated as of October 1, 1992; May 5,
1993; November 27, 1995; March 14, 1996; and November 27, 1995.
(Filed as Exhibit 10.12.1 to the Annual Report of the Company on Form
10-K For the year ended December 31, 1998).*
10.13 --Firm Gas Transportation Agreement between the Company and Iroquois
Gas Transmission System, L.P. dated as of February 7, 1991. (Filed as
Exhibit 10.17 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1990).*
10.13.1 --Agreement between the Company and Iroquois Gas Transmission System
L.P. amending Exhibit 10.13 as of November 3, 1998. (Filed herewith).
10.14 --Firm Gas Transportation Agreement between the Company and Tennessee
Gas Pipeline Company dated as of February 7, 1991. (Filed as Exhibit
10.18 to the Annual Report of the Company on Form 10-K for the year
ended December 31, 1990).*
10.15 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 29,000
dekatherms of natural gas per day. (Filed herewith).
10.16 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 96,000
dekatherms of natural gas per day. (Filed herewith).
10.17 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 20,000
dekatherms of natural gas per day. (Filed herewith).
</TABLE>
13
<PAGE>
<TABLE>
<C> <S>
10.18 --Gas Transportation Contract between the Company and Algonquin dated
December 1, 1994 providing for transportation of approximately 20,000
dekatherms of natural gas per day. (Filed as Exhibit 10.19 to the
Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.19 --Gas Transportation Contract between the Company and Algonquin dated
January 1, 1998 providing for transportation of approximately 27,000
dekatherms of natural gas per day. (Filed as Exhibit 10.20 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1997).*
10.20 --Gas Transportation Contract between the Company and CNG Transmission
dated October 1, 1993 providing for transportation of approximately
21,000 dekatherms of natural gas per day. (Filed as Exhibit 10.23 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.21 --Gas Storage Contract between the Company and CNG Transmission dated
November 1993 providing for storage demand of 42,000 dekatherms of
natural gas per day. (Filed as Exhibit 10.24 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1997).*
10.22 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 10,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.25 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.23 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 8,600 dekatherms of natural gas per day. (Filed
as Exhibit 10.28 to the Annual Report of the Company on Form 10-K for
the year ended
December 31, 1997).*
10.24 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 41,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.29 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.25 --Gas Storage Contract between the Company and Tennessee Gas Pipeline
dated December 1, 1994 providing for storage demand of approximately
71,000 dekatherms of natural gas per day. (Filed as Exhibit 10.31 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.26 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1996 providing for transportation of
approximately 13,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.32 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.27 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 39,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.33 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.27.1 --Agreement between the Company and Texas Eastern Transmission
amending Exhibit 10.27 dated as of October 29, 1998. (Filed
herewith).
10.28 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 21,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.34 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
</TABLE>
14
<PAGE>
<TABLE>
<C> <S>
10.29 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 5,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.35 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.30 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated October 29, 1999 providing for transportation of
approximately 29,000 dekatherms of natural gas per Day. (Filed
herewith).
10.31 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated October 29, 1999 providing for transportation of
approximately 3,000 dekatherms of natural gas per day. (Filed
herewith).
10.32 --Gas transportation contract between the Company and Transcontinental
Gas Pipeline dated June 1, 1993 providing for transportation of
approximately 6,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.40 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.33 --Gas Transportation Contract between the Company and Texas Gas
Transmission dated November 1, 1993 providing for transportation of
approximately 13,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.41 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.34 --Agreement between the Company and Tennessee Gas Pipeline dated as of
September 1, 1993 providing for transportation of approximately 10,500
dekatherms of natural gas per day. (Filed herewith).
10.35 --Agreement between the Company and Texas Eastern Transmission dated as
of October 29, 1999 providing for storage demand of approximately
68,700 dekatherms of natural gas per day. (Filed herewith).
10.36 --Agreement between the Company and Algonquin LNG, Corp. dated as of
October 29, 1999 providing for storage demand of approximately 35,000
dekatherms of natural gas per day. (Filed herewith).
10.37 --Contract Restructuring Agreement between the Company and Tennessee Gas
Pipeline dated as of August 2, 1999 amending Exhibits 10.1, 10.31 and
10.32. (Filed herewith).
10.38 --Redacted Gas Resource Portfolio Management and Gas Sales Agreement
between the Company, Colonial Gas Company, Essex Gas Company and El
Paso Energy Marketing Company dated as of September 14, 1999, as
amended. (Filed as Exhibit 10.1 to the Form 10-K of Eastern Enterprises
for the year ended December 31, 1999, and incorporated herein by
reference).
10.39 --Amended and Restated Lease Agreement between Industrial National
Leasing Corporation, Lessor, and Boston Gas Company, Lessee, dated as
of April 30, 1999. (Filed herewith).
10.40 --Credit Agreement dated as of December 22, 1993 by and among the
Company, Morgan Guaranty Trust Company of New York, National
Westminster Bank PLC, Shawmut Bank, N.A. and The First National Bank of
Boston. (Filed as Exhibit 10.17 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1993).*
10.41 --Sublease between the Company and Eastern Enterprises dated November 5,
1987. (Filed as Exhibit 10.20 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1987).*
18.1 --Letter from Arthur Andersen LLP regarding change in Accounting
Principle. (Filed as Exhibit 18.1 to the Annual Report of the Company
on Form 10-K for the year ended December 31, 1998).*
</TABLE>
15
<PAGE>
<TABLE>
<C> <S>
22 --Subsidiaries of the Company (Filed as Exhibit 22 to the Annual Report
of the Company on Form 10-K for the year ended December 31, 1985).*
23 --Consent of Independent Certified Public Accountants.
27 --Financial Data Schedule for the twelve months ended December 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.
16
<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.
Boston Gas Company
Registrant
Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza Senior Vice
President and Treasurer (Principal
Financial and Accounting Officer)
Dated: 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.
Signature Title
<TABLE>
<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
Joseph F. Bodanza Treasurer (Principal Financial and
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>
17
<PAGE>
BOSTON GAS COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
<TABLE>
<S> <C>
Report of Independent Public Accountants.......................... F-18
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1999.............................................. F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998.... F-3 and F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1999........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1999.............................................. 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-19
Schedule for the Three Years Ended December 31, 1999:
II--Valuation and Qualifying Accounts......................... F-20 to F-22
</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>
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Operating revenues.............................. $592,719 $610,313 $700,945
Cost of gas sold................................ 295,022 324,538 398,566
-------- -------- --------
Operating margin................................ 297,697 285,775 302,379
-------- -------- --------
Operating expenses:
Operations.................................... 128,102 120,765 129,343
Maintenance................................... 23,037 19,819 19,134
Depreciation and amortization................. 45,779 46,535 44,413
Income taxes.................................. 24,093 23,927 22,510
Taxes, other than income...................... 22,042 21,144 22,027
Restructuring charge.......................... -- (1,550) 8,692
-------- -------- --------
Total operating expenses.................... 243,053 230,640 246,119
-------- -------- --------
Operating earnings.............................. 54,644 55,135 56,260
Other earnings, net............................. 1,979 583 298
-------- -------- --------
Earnings before interest expense................ 56,623 55,718 56,558
-------- -------- --------
Interest expense:
Long-term debt................................ 16,775 16,767 16,767
Other, including amortization of debt
expense...................................... 926 1,248 1,889
Less--Interest during construction............ (852) (469) (609)
-------- -------- --------
Total interest expense...................... 16,849 17,546 18,047
-------- -------- --------
Earnings before cumulative effect of change
in accounting principle........................ 39,774 38,172 38,511
Cumulative effect of change in accounting after
tax............................................ -- 8,193 --
-------- -------- --------
Net earnings.................................... 39,774 46,365 38,511
Preferred stock dividends....................... 1,862 1,926 1,926
-------- -------- --------
Earnings applicable to common stock............. $ 37,912 $ 44,439 $ 36,585
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE>
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
--------------------
1999 1998
--------- ---------
(In Thousands)
<S> <C> <C>
Gas plant, at cost....................................... $ 963,672 $ 914,017
Construction work-in-progress............................ 16,458 11,644
Less-Accumulated depreciation.......................... (393,991) (368,609)
--------- ---------
Net plant............................................ 586,139 557,052
--------- ---------
Current assets:
Cash................................................... 172 878
Accounts receivable, less reserves of $14,816 at
December 31, 1999 and $15,651 at December 31, 1998.... 61,429 62,250
Accounts receivable--affiliates........................ 23,644 2,008
Accrued utility margin................................. 20,067 14,147
Deferred gas costs..................................... 47,872 54,292
Natural gas and other inventories, at average cost..... 45,172 41,375
Materials and supplies, at average cost................ 3,399 2,852
Prepaid expenses....................................... 1,263 2,255
--------- ---------
Total current assets................................. 203,018 180,057
--------- ---------
Other assets:
Deferred postretirement benefits cost.................. 72,760 78,567
Deferred charges and other assets...................... 40,975 43,483
--------- ---------
Total other assets................................... 113,735 122,050
--------- ---------
Total assets......................................... $ 902,892 $ 859,159
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
December 31,
-----------------
1999 1998
-------- --------
(In Thousands)
<S> <C> <C>
Capitalization:
Common stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1999 and 1998............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 189,517 178,857
-------- --------
Total common stockholder's investment.................... 284,168 273,508
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized 1,200,000 shares; outstanding--1,080,000 shares
at December 31, 1999 and 1,200,000 at December 31, 1998... 26,454 29,360
Long-term obligations, less current portion................. 224,399 210,675
-------- --------
Total capitalization..................................... 535,021 513,543
Gas inventory financing..................................... 54,020 48,299
-------- --------
Total capitalization and gas inventory financing......... 589,041 561,842
-------- --------
Current liabilities:
Current portion of long-term obligations................... 950 561
Notes payable.............................................. 51,200 28,900
Accounts payable........................................... 47,969 48,986
Accrued taxes.............................................. 1,255 959
Accrued income taxes....................................... 5,543 10,282
Accrued interest........................................... 4,354 4,414
Customer deposits.......................................... 2,060 2,187
Refunds due customers...................................... 512 140
-------- --------
Total current liabilities................................ 113,843 96,429
-------- --------
Reserves and deferred credits:
Deferred income taxes...................................... 78,921 75,981
Unamortized investment tax credits......................... 4,240 5,082
Postretirement benefits obligation......................... 77,310 81,067
Environmental liability.................................... 18,000 18,750
Other...................................................... 21,537 20,008
-------- --------
Total reserves and deferred credits...................... 200,008 200,888
-------- --------
Total capitalization and liabilities..................... $902,892 $859,159
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Balance at beginning of year..................... $178,857 $152,312 $133,980
Net earnings................................... 39,774 46,365 38,511
Preferred stock dividends ($1.61 per share in
1999, 1998 and 1997).......................... (1,862) (1,926) (1,926)
Cash dividends on common stock ($53.00 per
share in 1999, $34.80 per share in 1998, and
$35.50 per share in 1997)..................... (27,252) (17,894) (18,253)
-------- -------- --------
Balance at end of year........................... $189,517 $178,857 $152,312
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.................................... $ 39,774 $ 46,365 $ 38,511
Adjustments to reconcile net earnings to cash
provided by operating activities:
Depreciation and amortization.................. 45,779 46,535 44,413
Deferred taxes................................. 2,940 (3,147) 2,851
Other changes in assets and liabilities:
Accounts receivable........................... (20,815) 25,601 (13,027)
Accrued utility margin........................ (5,920) (14,147) --
Inventory..................................... (4,344) 3,679 5,190
Deferred gas costs............................ 6,420 12,303 8,742
Accounts payable.............................. (1,017) (12,945) (11,382)
Federal and state income taxes................ (4,739) (892) 21,585
Refunds due customers......................... 372 (2,996) (248)
Other......................................... 6,478 3,369 4,177
-------- -------- --------
Cash provided by operating activities............ 64,928 103,725 100,812
-------- -------- --------
Cash flows from investing activities:
Capital expenditures........................... (57,256) (60,266) (55,388)
Net cost of removal............................ (4,379) (5,099) (4,683)
-------- -------- --------
Cash used for investing activities............... (61,635) (65,365) (60,071)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. 22,300 (10,800) (17,300)
Changes in inventory financing................. 5,721 (7,203) (92)
Amortization of preferred stock issuance
costs......................................... 94 34 34
Redemption of preferred stock.................. (3,000) -- --
Cash dividends paid on common and preferred
stock......................................... (29,114) (19,820) (24,550)
-------- -------- --------
Cash used for financing activities............... (3,999) (37,789) (41,908)
-------- -------- --------
Increase (decrease) in cash...................... (706) 571 (1,167)
Cash at beginning of year........................ 878 307 1,474
-------- -------- --------
Cash at end of year.............................. $ 172 $ 878 $ 307
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 18,462 $ 18,879 $ 19,704
======== ======== ========
Income taxes.................................. $ 26,486 $ 34,046 $ 900
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
BOSTON 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 Boston and 73 other communities in
eastern and central Massachusetts.
The accounting policies of Boston Gas Company (the "Company") conform to
generally accepted accounting principles and reflect the effects of the rate-
making process in accordance with Statement of Financial Accounting Standards
No. 71 ("SFAS 71"), "Accounting for the Effects of Certain Types of
Regulation".
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 wholly owned subsidiary, Massachusetts LNG Incorporated, which
became inactive in 1999. 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.
Regulation
The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Telecommunications and Energy ("the Department").
Therefore, the Company accounts for the economic effects of regulation in
accordance with the provisions of SFAS 71. In the event the Company determines
that it no longer meets the criteria for following SFAS 71, the accounting
impact would be an extraordinary, non-cash charge to operations of an amount
that could be material. Criteria that give rise to the discontinuance of SFAS
71 include (1) increasing competition that restricts the Company's ability to
establish prices to recover specific costs or (2) a significant change in the
manner in which rates are set by regulators from cost-based regulation to
another form of regulation. The Company has reviewed these criteria and
believes that the continuing application of SFAS 71 is appropriate.
Regulatory assets have been established that represent probable future
revenue to the Company associated with certain costs that will be recovered
from customers through the rate-making process. Regulatory liabilities
represent probable future reductions in revenues associated with the amounts
that are to be credited to customers through the rate making process.
The following regulatory assets were reflected in the consolidated balance
sheets as of December 31:
<TABLE>
<CAPTION>
1999 1998
------- -------
(In Thousands)
<S> <C> <C>
Post-retirement benefit costs............................ $72,760 $78,567
Environmental costs...................................... 17,703 18,190
Other.................................................... 733 1,365
------- -------
$91,196 $98,122
======= =======
</TABLE>
F-7
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
Regulatory liabilities total approximately $8,586,000 and $9,479,000 at
December 31, 1999 and 1998 respectively, and relate to income taxes.
As of December 31, 1999, all of the Company's regulatory assets and
liabilities are being reflected in rates charged or credited to customers over
periods ranging from 1 to 20 years. For additional information regarding
deferred income taxes, post-retirement benefit costs and environmental costs,
see Notes 3, 6 and 11, respectively.
Gas Operating Revenues--Change in Accounting Principle
During the fourth quarter of 1998, the Company changed its method of
accounting for unbilled revenues, retroactively applied as of January 1, 1998.
Previously, substantially all revenues were recorded when billed. Under the
unbilled method, the estimated margin on unbilled sales is recorded at the end
of each accounting period. This change in accounting increased net earnings by
$8,598,000, consisting of a one-time cumulative effect for the years prior to
1998 of $8,193,000 plus the impact of the change on 1998 earnings of $405,000.
On a proforma basis, this change would have increased 1997 net earnings by
$1,590,000.
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 was 5.0% in 1999, 5.2% in 1998,
and 5.2% in 1997. Amortization is provided on intangible assets, principally
software, over the estimated useful life of the asset.
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.
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.
F-8
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(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 November 29, 1996, the Department modified the CGAC to recover
the gas cost portion of the Company's bad debt write-offs effective December
1, 1996. 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 conservation and
load management programs from the Company's firm sales and transportation
customers. These costs were previously recovered through the CGAC.
(3) Income Taxes
The Company is a member of an affiliated group of companies that files a
consolidated federal income tax return. The Company follows the policy,
established for the group, of providing for income taxes that would be payable
on a separate company basis. The Company's effective income tax rate was 38.2%
in 1999, 38.5% in 1998, and 36.9% in 1997 which includes the effect of prior
years tax benefits of 1.8%. State taxes represent the majority of the
difference between the effective rate and the federal income tax rate of 35%.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
(In Thousands)
<S> <C> <C> <C>
Current--
Federal......................................... $17,756 $21,997 $11,670
State........................................... 4,801 5,408 2,692
------- ------- -------
Total current provision....................... 22,557 27,405 14,362
Deferred--
Federal......................................... 2,244 (2,119) 6,998
State........................................... (708) (1,359) 1,150
------- ------- -------
Total deferred provision...................... 1,536 (3,478) 8,148
------- ------- -------
Provision for income taxes........................ $24,093 $23,927 $22,510
======= ======= =======
</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.
At December 31, 1999 the Company had a regulatory liability of $2,250,000
which represents the tax benefit of unamortized investment tax credits. This
benefit is being passed back to customers over the lives of property giving
rise to the investment credit. The Company also has a regulatory liability for
excess deferred taxes being returned to customers over a 30-year period
pursuant to a 1988 rate order with a balance to be refunded to customers of
$6,336,000 as of December 31, 1999.
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
F-9
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
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>
1999 1998
--------- ---------
(In Thousands)
<S> <C> <C>
Assets:
Regulatory liabilities.............................. $ 3,425 $ 3,775
Other............................................... 16,723 13,948
--------- ---------
Total deferred tax assets........................... $ 20,148 $ 17,723
--------- ---------
Liabilities:
Accelerated depreciation............................ $ (84,151) $ (82,985)
Deferred gas costs.................................. (14,183) (13,062)
Other............................................... (11,073) (14,231)
--------- ---------
Total deferred tax liabilities...................... $(109,407) $(110,278)
--------- ---------
Total net deferred taxes............................ $ (89,259) $ (92,555)
========= =========
</TABLE>
Investment tax credits are deferred and credited to income over the lives
of the property giving rise to such credits. The credit to income was
approximately $842,000 in 1999, $849,000 in 1998 and $906,000 in 1997.
(4) Commitments
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
<TABLE>
<CAPTION>
1999 1998
-------- --------
(In Thousands)
<S> <C> <C>
8.33%--9.75%, Medium-Term Notes Series A, due 2005--
2022.................................................. $100,000 $100,000
6.93%--8.50%, Medium-Term Notes, Series B, due 2006--
2024.................................................. 50,000 50,000
6.80%--7.25%, Medium-Term Notes, Series C, due 2012--
2025.................................................. 60,000 60,000
Capital lease obligations (Note 7)..................... 15,349 1,236
Less current portion................................... (950) (561)
-------- --------
$224,399 $210,675
======== ========
</TABLE>
The Company currently has a shelf registration covering the issuance of up
to $100,000,000 of Medium-Term Notes, of which $60,000,000 of Medium-Term
Notes, Series C have been issued as of December 31, 1999.
There are no sinking fund requirements for the next five years related to
the $210,000,000 of Medium-Term Notes outstanding at December 31, 1999 and
none are callable prior to maturity.
Annual maturities of capital lease obligations for the next five years are
$950,000, $408,000, $586,000, $840,000 and $891,000 for 2000 through 2004,
respectively.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department
effective October 1, 1988, the Company funds its inventory of gas supplies
through external sources. All costs related to this funding are recoverable
F-10
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Commitments (Continued)
from customers. The Company maintains a long-term credit agreement with a
group of banks which provides for the borrowing of up to $70,000,000 for the
exclusive purpose of funding its inventory of gas supplies or for backing
commercial paper issued for the same purpose. The Company had $54,020,000 and
$48,299,000 of commercial paper outstanding to fund its inventory of gas
supplies at December 31, 1999 and 1998, respectively. Because the commercial
paper is supported by the credit agreement, these borrowings have been
classified as non-current in the accompanying consolidated balance sheets. The
credit agreement includes a one-year revolving credit facility which may be
converted to a two-year term loan at the Company's option if the one-year
revolving credit facility is not renewed by the banks. The Company may select
the agent bank's prime rate or, at the Company's option, various pricing
alternatives. The agreement requires a facility fee of 8.5 basis points on the
commitment. No borrowings were outstanding under this agreement during 1999
and 1998.
Short-Term Debt and Lines of Credit
Eastern maintains a credit agreement with a group of banks which provides
for the borrowing by Eastern of up to $100,000,000 (of which up to $75,000,000
may be borrowed or used to back commercial paper issued by the Company) at any
time through December 31, 2001. The interest rate for borrowings is the agent
bank's prime rate, or at the borrower's option, various pricing alternatives.
The Company had outstanding borrowings of $20,000,000 and $28,900,000 in
commercial paper backed by this agreement at December 31, 1999 and 1998,
respectively. The weighted average interest rate on these borrowings was 6.05%
at December 31, 1999 and 5.10% at December 31, 1998.
In addition to the $75,000,000 available under the Eastern credit
agreement, the Company has an uncommitted line of credit of $40,000,000 under
which it may borrow through December 31, 2000. The interest rate for such
borrowings is a function of federal funds, money market or prime rates. The
Company had outstanding borrowings of $31,200,000 at December 31, 1999 at a
weighted average interest rate of 5.95%. There were no borrowings outstanding
under this uncommitted line at December 31, 1998.
(5) Preferred Stock
The Company has outstanding 1,080,000 shares of 6.421% Cumulative Preferred
Stock, which is non-voting and has a liquidation value of $25 per share. The
preferred stock requires 5% annual sinking fund payments beginning on
September 1, 1999 with a final redemption on September 1, 2018. At the
Company's option, the annual sinking fund payment may be increased to 10%. The
preferred stock is not callable prior to 2003. On September 1, 1999 the
Company redeemed 120,000 shares, or 10% of the outstanding shares, at the
liquidation price of $25 per share.
(6) Retiree Benefits
The Company, through participation in Eastern-administered plans and other
union retirement and welfare plans, provides retirement benefits for
substantially all of its employees. These plans include pensions, health and
life insurance benefits.
Pension benefits for salaried plans are based on salary and years of
service, while union retirement and welfare plans are based on negotiated
benefits and years of service. Employees hired before 1993 who are
participants in the pension plans become eligible for post-retirement health
care benefits if they reach retirement age while working for the Company. The
funding of retirement and employee benefit plans is in accordance with the
requirements of the plans and, where applicable, in sufficient amounts to
satisfy the "Minimum Funding Standards" of the Employee Retirement Income
Security Act ("ERISA").
F-11
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Retiree Benefits (Continued)
Effective January 1, 1998, the Company adopted SFAS No. 132, "Employers'
Disclosures about Pensions and Other Post-retirement Benefits," which revises
prior disclosure requirements. The information for 1997 has been restated to
conform to the current presentation. The net cost for these plans and
agreements charged to expense was as follows:
Pensions
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Service cost................................. $ 2,819 $ 2,676 $ 2,838
Interest cost on projected benefit
obligation.................................. 8,988 8,490 8,632
Expected return on plan assets............... (12,127) (11,488) (10,925)
Amortization of prior service cost........... 1,173 1,048 1,048
Amortization of transitional obligation...... 217 217 217
Recognized actuarial gain.................... (760) (710) (310)
Settlement and curtailment gain.............. (1,216) -- (2,003)
-------- -------- --------
Total net pension cost....................... $ (906) $ 233 $ (503)
======== ======== ========
Health Care
<CAPTION>
1999 1998 1997
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Service cost................................. $ 757 $ 828 $ 789
Interest cost on accumulated benefits
obligation.................................. 5,458 5,726 5,704
Expected return on plan assets............... (2,066) (2,029) (1,523)
Amortization of prior service cost........... (1,124) (1,190) (1,190)
Recognized actuarial gain.................... (900) (761) (484)
Regulatory deferral.......................... 5,808 5,359 4,637
-------- -------- --------
Total net retiree health care cost........... $ 7,933 $ 7,933 $ 7,933
======== ======== ========
</TABLE>
The previous tables do not reflect retirement pension enhancements of
$2,066,000 and $3,224,000 for 1999 and 1998, respectively, and retirement
health care enhancements of $143,000 for 1998.
F-12
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Retiree Benefits (Continued)
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of Company plans and amounts
recorded in the Company's balance sheet as of December 31, 1999 and 1998 using
actuarial measurement dates of October 1, 1999 and 1998:
<TABLE>
<CAPTION>
Pensions Health Care
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
(In Thousands)
<S> <C> <C> <C> <C>
Change in benefit obligation
Balance at beginning of year........... $125,161 $115,945 $ 76,774 $ 78,800
Service cost........................... 2,819 2,676 757 828
Interest cost.......................... 8,988 8,490 5,459 5,726
Plan amendments........................ -- -- 1,574 --
Settlement loss........................ 306 -- -- --
Special termination benefits........... 2,066 3,224 -- 143
Benefits paid.......................... (7,168) (7,686) (5,602) (5,019)
Settlement payments.................... (3,316) -- -- --
Actuarial (gain) or loss............... 3,017 2,512 (739) (3,704)
-------- -------- -------- --------
Balance at end of year................. $131,873 $125,161 $ 78,223 $ 76,774
======== ======== ======== ========
Change in plan assets
Fair value, beginning of year.......... $152,195 $165,857 $ 24,308 $ 23,877
Actual return on plan assets........... 12,432 (5,929) 912 431
Employer contributions................. -- -- 5,602 5,019
Benefits paid.......................... (7,168) (7,686) (5,602) (5,019)
Settlement payments.................... (3,316) -- -- --
Administrative expenses................ -- (47) -- --
-------- -------- -------- --------
Fair value at end of year.............. $154,143 $152,195 $ 25,220 $ 24,308
======== ======== ======== ========
Reconciliation of funded status
Funded status.......................... $ 22,270 $ 27,034 $(53,003) $(52,466)
Contributions for fourth quarter....... -- -- 1,401 1,254
Unrecognized actuarial (gain).......... (30,861) (32,120) (19,570) (21,018)
Unrecognized transition obligation..... 221 437 -- --
Unrecognized prior service............. 12,417 9,855 (6,138) (8,837)
-------- -------- -------- --------
Net amount recognized year end......... $ 4,047 $ 5,206 $(77,310) $(81,067)
======== ======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost................... $ 7,424 $ 8,139 $ -- $ --
Accrued benefit liability.............. (3,377) (2,933) (77,310) (81,067)
-------- -------- -------- --------
Net amount............................. $ 4,047 $ 5,206 $(77,310) $(81,067)
======== ======== ======== ========
</TABLE>
To fund health care benefits under its collective bargaining agreements,
the Company maintains a Voluntary Employee Beneficiary Association ("VEBA")
Trust to which it makes contributions from time to time. Plan assets are
invested in debt and equity marketable securities.
F-13
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
<TABLE>
<CAPTION>
1999 1998 1997
---------- --------- ----------
<S> <C> <C> <C>
Discount rate............................. 7.5% 7.25% 7.5%
Return on plan assets..................... 8.5% 8.5% 8.5%
Increase in future compensation........... 4.0 - 4.5% 4.5 - 5.0% 4.75 - 5.0%
Health care inflation trend............... 8.0 - 10.0% 8.0% 7.0%
</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- One-
Percentage- Percentage-
Point Increase Point Decrease
-------------- --------------
(In Thousands)
<S> <C> <C>
Service cost and interest cost components.... $ 449 $ (398)
Post-retirement benefit obligation........... $5,178 $(4,631)
</TABLE>
(7) Leases
The Company leases certain facilities and equipment under long-term leases
which expire on various dates through the year 2014. Total rentals charged to
income under all lease agreements were approximately $9,846,000 in 1999,
$9,367,000 in 1998, and $10,112,000 in 1997. The Company has capitalized
leases for an operations center and two LNG facilities. A summary of property
held under capital leases as of December 31 is as follows:
<TABLE>
<CAPTION>
1999 1998
------- ------
(In Thousands)
<S> <C> <C>
LNG Facilities............................................... $14,834 $ --
Buildings.................................................... 6,000 6,000
------- ------
$20,834 $6,000
Less--Accumulated depreciation............................... 5,485 4,764
------- ------
Total Capital Leases......................................... $15,349 $1,236
======= ======
</TABLE>
In April 1999 the Company entered into a 15 year lease agreement for the
LNG facilities located in Salem and Lynn, Massachusetts. The facilities had
previously been leased by the Company's subsidiary, Mass LNG, under a lease
agreement which expired in 1997.
Under the terms of SFAS 71, the timing of expense recognition on
capitalized leases conforms with regulatory rate treatment. The Company has
included the rental payments on its financing leases in its cost of service
for rate purposes. Therefore, the total depreciation and interest expense that
was recorded on the leases was equal to the rental payments included in other
operating and maintenance expense in the accompanying consolidated statements
of earnings.
F-14
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Leases (Continued)
The Company also has various operating lease agreements for office
facilities and other equipment. The remaining minimum rental commitment for
these and all other noncancellable leases, including the financing leases, at
December 31, 1999 is as follows:
<TABLE>
<CAPTION>
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
<S> <C> <C>
2000..................................................... $ 1,833 $ 4,647
2001..................................................... 1,228 3,437
2002..................................................... 1,379 2,092
2003..................................................... 1,584 436
2004..................................................... 1,584 236
Later Years.............................................. 15,048 --
------- -------
Total minimum lease payments............................. $22,656 $10,848
=======
Less--Amount representing interest and executory costs... 7,307
-------
Present value of minimum lease payments on capital
leases.................................................. $15,349
=======
</TABLE>
(8) 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.
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.
Preferred Stock--The fair value of the preferred stock is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term
debt and preferred stock at December 31, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
1999 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands) (In Thousands)
<S> <C> <C> <C> <C>
Long-term debt........................... $225,349 $219,525 $211,236 $248,341
Preferred stock.......................... $ 26,454 $ 26,730 $ 29,360 $ 30,076
</TABLE>
(9) Restructuring Charge
During the fourth quarter of 1997, the Company recorded a restructuring
charge of $8,692,000 related to its decision to exit the gas appliance repair
and service business. The charge included $5,369,000 for employee severance
and termination benefits associated with the elimination of approximately 130
bargaining unit and management positions. The remaining $3,323,000 related to
the disposition of assets, the cancellation of lease obligations,
communications, legal and other related costs. The Company completed its
restructuring plan in 1998 resulting in a $1,550,000 credit to income
reflecting the amount by which the estimated cost exceeded the actual costs of
the restructuring. The restructuring charge is reported as a component of
operating expenses in the consolidated statement of earnings.
F-15
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) Related Party Transactions
The Company paid Eastern $4,500,000 in 1999, $4,200,000 in 1998, and
$4,300,000 in 1997 for legal, tax and corporate services rendered.
In December 1996, Eastern Rivermoor Company, Inc., a wholly owned
subsidiary of Eastern, purchased the Company's primary operations center from
a third party and assumed the current lease agreement with the Company. During
1999, 1998 and 1997 the Company paid $775,000, $775,000 and $752,000,
respectively to Eastern Rivermoor Company, Inc.
(11) 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") operations, including
former operating plants, gas holder locations and satellite disposal sites.
The Company may have or share responsibility under applicable environmental
laws for the remediation of 19 such sites. The nineteenth site was identified
in 1999. A subsidiary of New England Electric System ("NEES") has assumed
responsibility for remediating 11 of these sites, subject to a limited
contribution from the Company. The Company also may have or share
responsibility for the remediation of one non-MGP site. The Company has
estimated its potential share of the costs of investigating and remediating
the former MGP related sites and the non-MGP site 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 $18 million, which
represents its best estimate at this time of remediation costs, which may
reasonably be estimated to range from $18 million to $34 million. However,
there can be no assurance that actual costs will not vary considerably from
these estimates. 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 is aware of 30 other former MGP related sites within its
service territory, nine of which were identified in 1999. The NEES subsidiary
has provided full indemnification to the Company with respect to eight of the
30 sites. At this time, there is substantial uncertainty as to whether the
Company has or shares responsibility for remediating any of these sites. No
notice of responsibility has been issued to the Company for these sites from
any governmental environmental authority.
By a rate order issued on May 25, 1990, the Department approved the
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 has recognized an
insurance receivable of $3.3 million, reflecting a negotiated settlement with
an insurance carrier for MGP-related environmental expense indemnity, and a
regulatory asset of $14.7 million, representing the expected rate recovery of
environmental remediation costs, net of the insurance settlement. In light of
the indemnity agreement with the NEES subsidiary, the Department rate order on
MGP-related cost recovery, and the expected cost of remediating the non-MGP
site, the Company believes that it is not probable that actual costs will
materially affect its financial condition or results of operations.
(12) 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.
F-16
<PAGE>
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(13) Commitments and Contingencies
Boston Gas 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 $8 million.
F-17
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Boston Gas Company:
We have audited the accompanying consolidated balance sheets of Boston Gas
Company (a Massachusetts Corporation and wholly-owned subsidiary of Eastern
Enterprises) and subsidiary as of December 31, 1999 and 1998, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1999. These consolidated
financial statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.
We conducted our audits 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 audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Boston Gas Company and
subsidiary as of December 31, 1999 and 1998 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not a part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
As explained in Note 1 to the financial statements, effective January 1,
1998, the Company changed its method of accounting for unbilled revenue.
Arthur Andersen LLP
Boston, Massachusetts
January 21, 2000
F-18
<PAGE>
BOSTON GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 1999 (Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
------------------------------------
Sept.
March 31 June 30 30 Dec. 31
-------- -------- ------- --------
(In Thousands)
<S> <C> <C> <C> <C>
1999
Operating revenues....................... $258,234 $ 96,958 $62,164 $175,363
Operating margin......................... $117,497 $ 52,460 $37,585 $ 90,155
Operating earnings (loss)................ $ 32,249 $ 1,287 $(3,548) $ 24,656
Net earnings (loss) applicable to common
stock................................... $ 27,570 $ (2,838) $(6,896) $ 20,076
1998
Operating revenues....................... $267,204 $107,763 $62,777 $172,569
Operating margin......................... $111,688 $ 53,526 $37,584 $ 82,977
Operating earnings (loss)................ $ 30,931 $ 5,229 $(2,623) $ 21,598
Cumulative effect of change in accounting
principle............................... $ 8,193 $ -- $ -- $ --
Net earnings (loss) applicable to common
stock................................... $ 34,005 $ 573 $(7,011) $ 16,872
</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-19
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1999
(In Thousands)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1998 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 15,651 $10,975 $-- $11,810 $ 14,816
======== ======= ==== ======= ========
RESERVES INCLUDED IN
LIABILITIES:
Reserve for
postretirement benefit
cost.................. $ 81,067 $ 2,579 $-- $ 6,336 $ 77,310
Reserve for self-
insurance............. 2,964 2,829 -- 1,880 3,913
Reserve for
environmental
expenses.............. 18,750 -- -- 750 18,000
Reserve for pension.... 2,933 1,661 -- 1,217 3,377
-------- ------- ---- ------- --------
Total reserves included
in liabilities........ $105,714 $ 7,069 $-- $10,183 $102,600
======== ======= ==== ======= ========
</TABLE>
F-20
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
<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.............. $ 15,783 $12,950 $-- $13,082 $ 15,651
======== ======= ==== ======= ========
RESERVES INCLUDED IN
LIABILITIES
Reserve for
postretirement benefit
cost.................. $ 83,274 $ 2,717 $-- $ 4,924 $ 81,067
Restructuring Reserve.. 6,845 (1,550) -- 5,295 --
Reserve for self-
insurance............. 2,870 1,873 -- 1,779 2,964
Reserve for
environmental
expenses.............. 19,500 -- -- 750 18,750
Reserve for pension.... 1,648 1,285 -- -- 2,933
-------- ------- ---- ------- --------
Total reserves included
in liabilities........ $114,137 $ 4,325 $ $12,748 $105,714
======== ======= ==== ======= ========
</TABLE>
F-21
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
(In Thousands)
<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.............. $15,963 $13,222 $ -- $13,402 $ 15,783
======= ======= ======= ======= ========
RESERVES INCLUDED IN
LIABILITIES:
Postretirement benefit
cost.................. $84,827 $ 3,295 $ -- $ 4,848 $ 83,274
Restructuring Reserve.. -- 8,692 -- 1,847 6,845
Reserve for self-
insurance............. 2,240 2,461 -- 1,831 2,870
Reserve for
environmental
expenses.............. -- -- 19,500 -- 19,500
Reserve for pension.... 2,992 (1,344) -- -- 1,648
------- ------- ------- ------- --------
Total reserves included
in liabilities........ $90,059 $13,104 $19,500 $ 8,526 $114,137
======= ======= ======= ======= ========
</TABLE>
F-22
<PAGE>
Exhibit 10.2
Contract #: 800285R1
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
This Service Agreement, made and entered into this 29th day of October,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and BOSTON GAS COMPANY (herein called
"Customer", whether one or more),
W I T N E S S E T H:
WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated December 30, 1993 under Pipeline's Rate Schedule FT-1 (Pipeline
Contract No. 800285);and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
to supersede Pipeline's currently effective Contract No. 800285;
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) 48,133 dth
provided, however, subject to Pipeline's receipt of one (1) year prior
written notice Customer shall have a one time election to reduce to 27,436
dth the MDQ of this Service Agreement with such reduction to be effective
on November 1, 2005.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 the later of November
1, 1999, or the in-service date of the facilities authorized by the Commission
in Docket No. CP99-113-000, and shall continue in effect for a term ending and
including October 31, 2006, and shall remain in force from 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 one
(1) year prior written notice to the other specifying a termination date of
October 31, 2006, or any October 31 thereafter. 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
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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.
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
Customer agrees that Pipeline shall have the unilateral right to file with
the appropriate regulatory authority and make changes effective in (a) the rates
and charges applicable to service pursuant to Pipeline's Rate Schedule FT-1, (b)
Pipeline's Rate Schedule FT-1 pursuant to which service hereunder is rendered or
(c) any provision of the General Terms and Conditions applicable to Rate
Schedule FT-1. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.
ARTICLE IV
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
The Point(s) of Receipt and Point(s) of Delivery at which Pipeline shall
receive and deliver gas, respectively, shall be specified in Exhibit(s) A and B
of the executed service agreement. Customer's Zone Boundary Entry Quantity and
Zone Boundary Exit Quantity for each of Pipeline's zones shall be specified in
Exhibit C of the executed service agreement.
Exhibit(s) A, B and C are hereby incorporated as part of this Service
Agreement for all intents and purposes as if fully copied and set forth herein
at length.
4
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
ARTICLE V
QUALITY
All natural gas tendered to Pipeline for Customer's account shall conform
to the quality specifications set forth in Section 5 of Pipeline's General Terms
and Conditions. Customer agrees that in the event Customer tenders for service
hereunder, and Pipeline agrees to accept natural gas which does not comply with
Pipeline's quality specifications, as expressly provided for in Section 5 of
Pipeline's General Terms and Conditions, Customer shall pay all costs associated
with processing of such gas as necessary to comply with such quality
specifications. Customer shall execute or cause its supplier to execute, if such
supplier has retained processing rights to the gas delivered to Customer, the
appropriate agreements prior to the commencement of service for the
transportation and processing of any liquefiable hydrocarbons and any PVR
quantities associated with the processing of gas received by Pipeline at the
Point(s) of Receipt under such Customer's service agreement. In addition,
subject to the execution of appropriate agreements, Pipeline is willing to
transport liquids associated with the gas produced and tendered for
transportation hereunder.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms
and Conditions of Pipeline's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Service Agreement, or any notice
which any party may desire to give to the other, shall be in writing and shall
be considered as duly delivered when mailed by registered, certified, or regular
mail to the post office address of the parties hereto, as the case may be, as
follows:
(a) Pipeline: TEXAS EASTERN TRANSMISSION CORPORATION
5400 Westheimer Court
Houston, TX 77056-5310
(b) Customer: BOSTON GAS COMPANY
ONE BEACON STREET
BOSTON, MA 02108
or such other address as either party shall designate by formal written notice.
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 dated December 30, 1993 between Pipeline and Customer
under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 800285).
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 _______________________________ PMT
ATTEST:
- ----------------------
BOSTON GAS COMPANY
By /s/ William R. Luthern
-----------------------------------
ATTEST:
/s/ [ILLEGIBLE]
- ----------------------
8
<PAGE>
Contract #: 800285R1
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED 10/29/99,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
(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 48,133
SIGNED FOR IDENTIFICATION
PIPELINE: Jmm
--------------------------------------
CUSTOMER: /s/ W.R. Luthern ED
--------------------------------------
SUPERSEDES EXHIBIT A DATED:
--------------------
A-1
<PAGE>
Contract #: 800285R1
EXHIBIT B, POINT(S) OF DELIVERY, DATED 10/29/99,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
<TABLE>
<CAPTION>
Maximum
Point Daily Delivery Measurement
of Delivery Pressure Responsi-
Delivery Description Obligation Obligation bilities Owner Operator
-------- ----------- ---------- ---------- -------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C> <C>
1. 70087 ALGONQUIN - LAMBERTVILLE, 48,133 AS REQUESTED TX EAST TRAN TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ BY CUSTOMER, TRAN
NOT TO
EXCEED 750
PSIG
2. 71078 ALGONQUIN - HANOVER, NJ 42,018 AS REQUESTED TX EAST TRAN TX EAST ALGONQUIN
MORRIS CO., NJ BY CUSTOMER, TRAN
NOT TO
EXCEED 750
PSIG
3. 79513 SS-1 STORAGE POINT 25,382 N/A N/A N/A N/A
04/01-10/31
25,382
11/01-03/31
4. 79818 AGT-BOSTON 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 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 #: 800285R1
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
BOSTON GAS COMPANY
POINT OF DELIVERY AGGREGATE MAXIMUM DAILY
----------------- DELIVERY OBLIGATION (DTH)
-------------------------
No. 1 177,070
No. 2 66,560
No. 3 25,382
SIGNED FOR IDENTIFICATION
PIPELINE: Jmm
--------------------------------------
CUSTOMER: /s/ W.R. Luthern ED
--------------------------------------
SUPERSEDES EXHIBIT B DATED:
--------------------
B-2
<PAGE>
Contract #: 800285R1
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED 10/29/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
BOSTON GAS COMPANY ("CUSTOMER"), DATED 10/29/99
ZONE BOUNDARY ENTRY QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
===================================================================================================================
FROM STX ETX WLA ELA Ml-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 6323 2065
- -------------------------------------------------------------------------------------------------------------------
WLA 58
- -------------------------------------------------------------------------------------------------------------------
ELA 40469
- -------------------------------------------------------------------------------------------------------------------
M1-24 6323
- -------------------------------------------------------------------------------------------------------------------
M1-30 40469
- -------------------------------------------------------------------------------------------------------------------
M1-TXG 2123
- -------------------------------------------------------------------------------------------------------------------
M1-TGC
- -------------------------------------------------------------------------------------------------------------------
M2-24
- -------------------------------------------------------------------------------------------------------------------
M2-30
- -------------------------------------------------------------------------------------------------------------------
M2-TXG
- -------------------------------------------------------------------------------------------------------------------
M2-TGC
- -------------------------------------------------------------------------------------------------------------------
M2 43133
- -------------------------------------------------------------------------------------------------------------------
M3
===================================================================================================================
</TABLE>
C-1
<PAGE>
Contract #: 800285R1
EXHIBIT C (Continued)
BOSTON GAS COMPANY
ZONE BOUNDARY EXIT QUANTITY
Dth/D
To
<TABLE>
<CAPTION>
===================================================================================================================
FROM STX ETX WLA ELA Ml-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 6323
- -------------------------------------------------------------------------------------------------------------------
M1-30 40469
- -------------------------------------------------------------------------------------------------------------------
M1-TXG 2123
- -------------------------------------------------------------------------------------------------------------------
M1-TGC
- -------------------------------------------------------------------------------------------------------------------
M2-24
- -------------------------------------------------------------------------------------------------------------------
M2-30
- -------------------------------------------------------------------------------------------------------------------
M2-TXG
- -------------------------------------------------------------------------------------------------------------------
M2-TGC
- -------------------------------------------------------------------------------------------------------------------
M2 43133
- -------------------------------------------------------------------------------------------------------------------
M3
===================================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE: Jmm
--------------------------------------
CUSTOMER: /s/ W.R. Luthern ED
--------------------------------------
SUPERSEDES EXHIBIT C DATED:
--------------------
C-2
<PAGE>
Exhibit 10.4
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 29th day of October,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Boston Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Customer and Algonquin currently are parties to an executed agreement
under Algonquin's Rate Schedule AFT-1 (Algonquin's Contract No. 93002C) dated
January 1, 1998; and
WHEREAS, Algonquin and Customer desire to enter into this Agreement to supersede
Algonquin's currently effective Contract No. 93002C;
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
-------------------------------------
Nov 16 - Apr 15 44,699*
Apr 16 - May 31 38,582
Jun 1 - Sep 30 26,349
Oct 1 - Nov 15 38,582
*MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 13,513,671 MMBtu
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
provided, however, subject to Algonquin's receipt of one (1) year
prior written notice Customer shall have a one time election to
reduce to 25,478 MMBtu the MDTQ of this Agreement with such
reduction to be effective on November 1, 2005.
1.2 Algonquin agrees to transport and deliver to or for the account of
Customer at the Point(s) of Delivery and Customer agrees to accept or
cause acceptance of delivery of the quantity received by Algonquin on any
day, less the Fuel Reimbursement Quantities; provided, however, Algonquin
shall not be obligated to deliver at any Point of Delivery on any day a
quantity of natural gas in excess of the applicable Maximum Daily Delivery
Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on the later of November 1, 1999, or
the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term ending
and including October 31, 2006 ("Primary Term"), and shall remain in force
from year to year thereafter unless terminated by either party by written
notice one year or more prior to the end of the Primary Term or any
successive term thereafter. Algonquin's right to cancel this Agreement
upon the expiration of the Primary Term hereof or any succeeding term
shall be subject to Customer's rights pursuant to Sections 8 and 9 of the
General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-1 as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate under
Rate Schedule AFT-1, nor less than the minimum rate under Rate Schedule
AFT-1.
3.2 This Agreement and all terms and provisions contained or incorporated
herein are subject to the provisions of Algonquin's applicable rate
schedules and of Algonquin's General Terms and Conditions on file with the
Federal Energy Regulatory Commission, or other duly constituted
authorities having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and Conditions are by
this reference made a part hereof.
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.
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer hereunder
shall be delivered on the outlet side of the measuring station(s) at or near the
Primary Point(s) of Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery pressure obligation
indicated for each such Primary Point of Delivery. Natural gas to be delivered
by Algonquin for the account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Algonquin's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Agreement, or any notice which
any party may desire to give to the other, shall be in writing and shall be
considered as duly delivered when mailed by registered, certified, or first
class mail to the post office address of the parties hereto, as the case may be,
as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Ct
Houston, TX 77056
(b) Customer: Boston Gas Company
One Beacon Street
Boston, MA 02108
or such other address as either party shall designate by formal written notice.
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in accordance with
the laws of the Commonwealth of Massachusetts, excluding conflicts of law
principles that would require the application of the laws of a different
jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto, except that in the case of conversions
from former Rate Schedules F-2 and F-3, the parties' obligations under Article
II of the service agreements pertaining to such rate schedules shall continue in
effect.
Algonquin's agreement no. 93002C dated January 1, 1998 between Algonquin
and Customer under Algonquin's Rate Schedule AFT-1.
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1
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/ DMT
Title:
------------------------------
BOSTON GAS COMPANY
By: /s/ Nicholas Stavropoulos
------------------------------
Title: Senior Vice President
------------------------------
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit A
Point(s) of Receipt
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
-------- ------------------ ----------------
Hanover, NJ (TETCO) At any pressure requested
Nov 16 - Apr 15 20,583 by Algonquin but not in
Apr 16 - May 31 17,071 excess of 750 Psig.
Jun 1 - Sep 30 10,047
Oct 1 - Nov 15 17,071
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 24,116 by Algonquin but not in
Apr 16 - May 31 21,512 excess of 750 Psig.
Jun 1 - Sep 30 16,302
Oct 1 - Nov 15 21,512
Signed for Identification
Algonquin:
--------------------------- /s/ JMM
Customer: /s/ Nicholas Stavropoulos
----------------------------
/s/ ED
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
At Customer's reduction
valves located at Everett, MA 75
Nov 16 - Apr 15 16,552
Apr 16 - May 31 14,411
Jun 1 - Sep 30 10,130
Oct 1 - Nov 15 14,411
At the property line
on the outlet side of
meter stations located at:
Waltham, MA 125
Nov 16 - Apr 15 6,733
Apr 16 - May 31 6,037
Jun 1 - Sep 30 4,643
Oct 1 - Nov 15 6,037
East Braintree, MA 125
Nov 16 - Apr 15 8,605
Apr 16 - May 31 7,697
Jun 1 - Sep 30 5,880
Oct 1 - Nov 15 7,697
Signed for Identification
Algonquin:
--------------------------- /s/ JMM
Customer: /s/ Nicholas Stavropoulos
----------------------------
/s/ ED
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
Weston, MA 100
Nov 16 - Apr 15 917
Apr 16 - May 31 752
Jun 1 - Sep 30 422
Oct 1 - Nov 15 752
Wellesley, MA 60
Nov 16 - Apr 15 11,384
Apr 16 - May 31 9,419
Jun 1 - Sep 30 5,487
Oct 1 - Nov 15 9,419
Ponkapoag, MA 200
Nov 16 - Apr 15 15,116
Apr 16 - May 31 14,523
Jun 1 - Sep 30 13,338
Oct 1 - Nov 15 14,523
Signed for Identification
Algonquin:
--------------------------- /s/ JMM
Customer: /s/ Nicholas Stavropoulos
----------------------------
/s/ ED
<PAGE>
93002CR
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
Norwood, MA 75
Nov 16 - Apr 15 1,488
Apr 16 - May 31 1,209
Jun 1 - Sep 30 651
Oct 1 - Nov 15 1,209
Potter Street
East Braintree, MA Algonquin's line
Nov 16 - Apr 15 6,664 pressure as may exist
Apr 16 - May 31 6,402 from time to time.
Jun 1 - Sep 30 5,880
Oct 1 - Nov 15 6,402
Algonquin's Maximum Daily Delivery Obligations for the East Braintree and
Potter Street Points of Delivery under Contract Nos. 93002CR, 93002ER and
99012 shall not exceed a combined daily total equal to the aggregate of
the former Maximum Daily Delivery Obligations at the East Braintree Point
of Delivery under Rate Schedules AFT-1 (F-1) and AFT-E (F-1) in the
amounts of 16,948 MMBtu and 5,238 MMBtu, respectively.
Signed for Identification
Algonquin:
--------------------------- /s/ JMM
Customer: /s/ Nicholas Stavropoulos
----------------------------
/s/ ED
<PAGE>
Exhibit 10.13.1
Bostongas Boston Gas Company
Eastern Enterprises One Beacon Street
Boston, Massachusetts 02108
Tel: 617-723-5512 Ext. 2742
Fax: 617-742-8564
Jeffrey M. Leupold
Counsel
November 12, 1998
Robin Almond, Contract Administrator
Iroquois Gas Transmission System
One Corporate Drive, Suite 600
Shelton, CT 06484-6211
Re: Amendment to R-420-01
Dear Ms. Almond:
Enclosed is a fully-executed original of the above-referenced document.
Very truly yours,
/s/ Jeffrey M. Leupold
Jeffrey M. Leupold
JML/dmo
Enclosure
<PAGE>
Contract No. R-420-01
AMENDMENT
TO GAS TRANSPORTATION CONTRACT FOR FIRM RESERVED SERVICE
THIS AMENDMENT is made and entered into this 3rd day of November, 1998, by
and between IROQUOIS GAS TRANSMISSION SYSTEM, L.P., a Delaware limited
partnership ("Transporter"), and BOSTON GAS COMPANY, a Massachusetts
corporation, (Shipper).
WHEREAS, Transporter and Shipper are parties to a Gas Transportation
Contract for Firm Reserved Service dated February 7, 1991, subsequently
designated as Transporter's Contract No. R-420-01, (the "Contract"), which
provides for transportation service by Transporter of 52,100 Mcf per day of
natural gas on behalf of Shipper between the interconnection points on
Transporter's natural gas system at Waddington, New York and Wright, New York
from approximately November 1, 1991, through November 1, 2011 and year to year
thereafter;
WHEREAS, Transporter and Shipper are parties to two multiparty agreements
dated July 1, 1991 (the "July 1 Agreements") whereby Shipper agreed to
reallocate 4,000 Mcf/d of Firm Transportation Service to Colonial Gas Company
("Colonial") and 4,500 Mcf/d of Firm Transportation Service to Commonwealth Gas
Company ("ComGas"); and
WHEREAS, those July 1 Agreements provide that Shipper will amend the
Contract to reflect the reduction in maximum daily contract quantity after
Colonial and ComGas have executed their respective agreements for Firm
Transportation Service; and
WHEREAS, Transporter filed in Docket No. CP91-2677 to partially abandon
this service to Shipper; and
WHEREAS, the Commission approved the reallocation of volumes to Colonial
and ComGas; and
WHEREAS, on November 25, 1991, Transporter and Colonial entered into a Gas
Transportation Contract for Firm Reserved Service providing for the firm
transportation of the 4,000 Mcf/d; and
WHEREAS, Transporter and Shipper are parties to a Gas Transportation
Contract for Firm Reserved Service, dated November 25, 1991, designated as
Transporter's Contract No. R-420-03, which provides for the firm transportation
of 4,500 Mcf/d on behalf of ComGas for a term terminating on the date
Transporter and ComGas enter into their own Gas Transportation Contract for Firm
Reserved Service; and
WHEREAS, Transporter and Shipper mutually desire to amend the Maximum
Daily Quantity set forth in the Contract to reflect the reallocation to Colonial
and on behalf of ComGas.
1
<PAGE>
Contract No. R-420-O1
NOW THEREFORE, in consideration of the premises and the mutual covenants
herein contained, Transporter and Shipper hereby agree to amend the Contract as
follows:
1. Effective December 1, 1991, Schedules 1 and 2 shall be deleted in their
entirety and replaced with the new Schedules 1 and 2 attached.
All other terms and conditions of the Contract shall remain the same and
continue in full force and effect.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
duly executed as of the date first above written.
ATTEST: IROQUOIS GAS TRANSMISSION SYSTEM, LP.
By its Agent
IROQUOIS PIPELINE OPERATING COMPANY
/s/ [ILLEGIBLE] By /s/ Herbert A. Rakebrand, III
- ------------------------ ------------------------------------------
Herbert A. Rakebrand, III
Vice President, Marketing & Transportation
/s/ Joan Pastore By /s/ Paul Bailey
- ------------------------ ------------------------------------------
Paul Bailey
Vice President & Chief Financial Officer
ATTEST: BOSTON GAS COMPANY
/s/ [ILLEGIBLE] By /s/ William R. Luthern
- ------------------------ ------------------------------------------
By
- ------------------------ ------------------------------------------
2
<PAGE>
Contract No. R-420-01
SCHEDULE 1
Receipt Point: Waddington
Maximum Input Quantity: 43,600 Mcf/d
Pressure: 1,440 psig, or such lesser pressure that
Transporter deems necessary.
3
<PAGE>
Contract No. R-420-01
SCHEDULE 2
Delivery Point(s): Wright
Maximum Equivalent Quantity: The thermal equivalent of 43,600 Mcf/d
Pressure: Minimum: The system operating pressure of the
downstream operator, not to exceed 1,440 psig, or
such lesser pressure that Transporter and
downstream operator deems necessary.
Maximum: 1440 psig
4
<PAGE>
Exhibit 10.15
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 29th day of October,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Boston Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Customer and Algonquin are parties to an executed agreement under
Algonquin's Rate Schedule AFT-1 (Algonquin's Contract No. 9B100) dated September
1, 1994; and
WHEREAS, Algonquin and Customer desire to enter into this Agreement to supersede
Algonquin's currently effective Contract No. 9B100;
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
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE I
SCOPE OF AGREEMENT
(Continued)
all Point(s) of Receipt on any day or in any year a cumulative quantity of
natural gas, without the prior consent of Algonquin, in excess of the
following quantities of natural gas plus the applicable Fuel Reimbursement
Quantities:
Maximum Daily Transportation Quantity (MMBtu)
Nov 16 - Apr 15 29,909*
Apr 16 - May 31 19,939
Jun 1 - Sep 30 0
Oct 1 - Nov 15 19,939
*MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 6,350,647 MMBtu
provided, however, subject to Algonquin's receipt of one (1) year
prior written notice Customer shall have a one time election to
reduce to 17,048 MMBtu the MDTQ of this Agreement with such
reduction to be effective on November 1, 2005.
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>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on the later of November 1, 1999, or
the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term ending on
and including October 31, 2006 ("Primary Term"), and shall remain in force
from year to year thereafter unless terminated by either party by written
notice one year or more prior to the end of the Primary Term or any
successive term thereafter. Algonquin's right to cancel this Agreement
upon the expiration of the Primary Term hereof or any succeeding term
shall be subject to Customer's rights pursuant to Sections 8 and 9 of the
General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-1 as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate under
Rate Schedule AFT-1, nor less than the minimum rate under Rate Schedule
AFT-1.
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE III
RATE SCHEDULE
(Continued)
3.2 This Agreement and all terms and provisions contained or incorporated
herein are subject to the provisions of Algonquin's applicable rate
schedules and of Algonquin's General Terms and Conditions on file with the
Federal Energy Regulatory Commission, or other duly constituted
authorities having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and Conditions are by
this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right to file
with the appropriate regulatory authority and make changes effective in
(a) the rates and charges applicable to service pursuant to Algonquin's
Rate Schedule AFT-1, (b) Algonquin's Rate Schedule AFT-1, pursuant to
which service hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-1. Algonquin agrees
that Customer may protest or contest the aforementioned filings, or may
seek authorization from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as may be found
necessary to assure that the provisions in (a), (b), or (c) above are just
and reasonable.
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer hereunder
shall be received at the outlet side of the measuring station(s) at or near the
Primary Point(s) of Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt pressure obligation
indicated for each such Primary Point of Receipt. Natural gas to be received by
Algonquin for the account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-1.
<PAGE>
9B100R
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer hereunder
shall be delivered on the outlet side of the measuring station(s) at or near the
Primary Point(s) of Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery pressure obligation
indicated for each such Primary Point of Delivery. Natural gas to be delivered
by Algonquin for the account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Algonquin's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Agreement, or any notice which
any party may desire to give to the other, shall be in writing and shall be
considered as duly delivered when mailed by registered, certified, or first
class mail to the post office address of the parties hereto, as the case may be,
as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
(b) Customer: Boston Gas Company
One Beacon Street
Boston, MA 02108
or such other address as either party shall designate by formal written notice.
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-B
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in accordance with
the laws of the Commonwealth of Massachusetts, excluding conflicts of law
principles that would require the application of the laws of a different
jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto, except that in the case of conversions
from former Rate Schedules F-2 and F-3, the parties' obligations under Article
II of the service agreements pertaining to such rate schedules shall continue in
effect.
Algonquin's agreement no. 9B100 dated September 1, 1994, between Algonquin
and Customer under Algonquin's Rate Schedule AFT-1.
<PAGE>
9B100R
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/ PMT
Title:
-------------------------------------
BOSTON GAS COMPANY
By: /s/ William R. Luthern
-------------------------------------
Title: Vice President
------------------------------------- /s/ ED
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit A
Point(s) of Receipt
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
-------- ------------------ ----------------
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 29,909 by Algonquin but not in
Apr 16 - May 31 19,939 excess of 750 Psig.
Jun 1 - Sep 30 0
Oct 1 - Nov 15 19,939
Signed for Identification
Algonquin:
-----------------
/s/ JMM
Customer: /s/ W.R. Luthern
-----------------
/s/ ED
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
At Customer's reduction
valves located at Everett, MA 75
Nov 16 - Apr 15 14,348
Apr 16 - May 31 9,565
Jun 1 - Sep 30 0
Oct 1 - Nov 15 9,565
At the property line
on the outlet side of
meter stations located at:
Waltham, MA 125
Nov 16 - Apr 15 4,784
Apr 16 - May 31 3,189
Jun 1 - Sep 30 0
Oct 1 - Nov 15 3,189
East Braintree, MA 125
Nov 16 - Apr 15 4,784
Apr 16 - May 31 3,189
Jun 1 - Sep 30 0
Oct 1 - Nov 15 3,189
Signed for Identification
Algonquin:
-----------------
/s/ JMM
Customer: /s/ W.R. Luthern
-----------------
/s/ ED
<PAGE>
9B100R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
Wellesley, MA 60
Nov 16 - Apr 15 4,784
Apr 16 - May 31 3,189
Jun 1 - Sep 30 0
Oct 1 - Nov 15 3,189
Norwood, MA 75
Nov 16 - Apr 15 1,209
Apr 16 - May 31 807
Jun 1 - Sep 30 0
Oct 1 - Nov 15 807
Signed for Identification
Algonquin:
-----------------
/s/ JMM
Customer: /s/ W.R. Luthern
-----------------
/s/ ED
<PAGE>
Exhibit 10.16
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
This Agreement ("Agreement") is made and entered into this 29th day of October,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Boston Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Customer and Algonquin currently are parties to an executed agreement
under Algonquin's Rate Schedule AFT-E (Algonquin's Contract No. 93002E) dated
September 1, 1994; and
WHEREAS, Algonquin and Customer desire to enter into this Agreement to supersede
Algonquin's currently effective Contract No. 93002E;
In consideration of the premises and of the mutual covenants herein contained,
the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations hereof and of Algonquin's
Rate Schedule AFT-E, Algonquin agrees to receive from or for the account
of Customer for transportation on a firm basis quantities of natural gas
tendered by Customer on any day at the Point(s) of Receipt; provided,
however, Customer shall not tender without the prior consent of Algonquin,
at any Point of Receipt on any day a quantity of natural gas in excess of
the applicable Maximum Daily Receipt Obligation for such Point of Receipt
plus the applicable Fuel Reimbursement Quantity; and provided further that
Customer shall not tender at all Point(s) of Receipt on any day or in any
year a cumulative quantity of natural gas, without the prior consent of
Algonquin, in excess of the following quantities of natural gas plus the
applicable Fuel Reimbursement Quantities:
Maximum Daily Transportation Quantity (MMBtu)
---------------------------------------------
Nov 16 - Apr 15 95,594*
Apr l6 - May 3l 85,442
Jun 1 - Sep 30 65,139
Oct 1 - Nov 15 85,442
* MDTQ to be utilized in applying monthly Reservation Charge
Maximum Annual Transportation Quantity 30,242,316 MMBtu
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
ARTICLE I
SCOPE OF AGREEMENT
(Continued)
provided, however, subject to Algonquin's receipt of one (1) year
prior written notice Customer shall have a one time election to
reduce to 54,489 MMBtu the MDTQ of this Agreement with such
reduction to be effective on November 1, 2005.
1.2 Algonquin agrees to transport and deliver to or for the account of
Customer at the Point(s) of Delivery and Customer agrees to accept or
cause acceptance of delivery of the quantity received by Algonquin on any
day, less the Fuel Reimbursement Quantities; provided, however, Algonquin
shall not be obligated to deliver at any Point of Delivery on any day a
quantity of natural gas in excess of the applicable Maximum Daily Delivery
Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on the later of November 1, 1999, or
the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term ending on
and including October 31, 2006 ("Primary Term"), and shall remain in force
from year to year thereafter unless terminated by either party by written
notice one year or more prior to the end of the Primary Term or any
successive term thereafter. Algonquin's right to cancel this Agreement
upon the expiration of the Primary Term hereof or any succeeding term
shall be subject to Customer's rights pursuant to Sections 8 and 9 of the
General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-E as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate under
Rate Schedule AFT-E, nor less than the minimum rate under Rate Schedule
AFT-E.
3.2 This Agreement and all terms and provisions contained or incorporated
herein are subject to the provisions of Algonquin's applicable rate
schedules and of Algonquin's General Terms and Conditions on file with the
Federal Energy Regulatory Commission, or other duly constituted
authorities having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and Conditions are by
this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right to file
with the appropriate regulatory authority and make changes effective in
(a) the rates and charges applicable to service pursuant to Algonquin's
Rate Schedule AFT-E, (b) Algonquin's Rate Schedule AFT-E, pursuant to
which service hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-E. Algonquin agrees
that Customer may protest or contest the aforementioned filings, or may
seek authorization from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as may be found
necessary to assure that the provisions in (a), (b), or (c) above are just
and reasonable.
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer hereunder
shall be received at the outlet side of the measuring station(s) at or near the
Primary Point(s) of Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt pressure obligation
indicated for each such Primary Point of Receipt. Natural gas to be received by
Algonquin for the account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-E.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer hereunder
shall be delivered on the outlet side of the measuring station(s) at or near the
Primary Point(s) of Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery pressure obligation
indicated for each such Primary Point of Delivery. Natural gas to be delivered
by Algonquin for the account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-E.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Algonquin's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Agreement, or any notice which
any party may desire to give to the other, shall be in writing and shall be
considered as duly delivered when mailed by registered, certified, or first
class mail to the post office address of the parties hereto, as the case may be,
as follows:
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
(b) Customer: Boston Gas Company
One Beacon Street
Boston, MA 02108
or such other address as either party shall designate by formal written notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in accordance with
the laws of the Commonwealth of Massachusetts, excluding conflicts of law
principles that would require the application of the laws of a different
jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto.
Algonquin's agreement no. 93002E dated September 1, 1994, between
Algonquin and Customer under Algonquin's Rate Schedule AFT-E.
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
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/ PMT
Title: ___________________________
BOSTON GAS COMPANY
By: /s/ William R. Luthern
------------------------------
Title: Vice President
---------------------------
/s/ ED
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit A
Point(s) of Receipt
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
-------- ------------------ ----------------
Hanover, NJ (TETCO) At any pressure requested
Nov 16 - Apr 15 41,643 by Algonquin but not in
Apr 16 - May 31 36,042 excess of 750 Psig.
Jun 1 - Sep 30 24,838
Oct 1 - Nov 15 36,042
Lambertville, NJ At any pressure requested
Nov 16 - Apr 15 53,951 by Algonquin but not in
Apr 16 - May 31 49,400 excess of 750 Psig.
Jun 1 - Sep 30 40,301
Oct 1 - Nov 15 49,400
Signed for Identification
Algonquin: ____________________ /s/ JMM
Customer: /s/ W.R. Luthern
---------------------
/s/ ED
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit B
Point(s) of Delivery
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
At Customer's reduction
valves located at Everett, MA 75
Nov 16 - Apr 15 35,824
Apr 16 - May 31 32,230
Jun 1 - Sep 30 25,044
Oct 1 - Nov 15 32,230
At the property line
on the outlet side of
meter stations located at:
Waltham, MA 125
Nov 16 - Apr 15 15,168
Apr 16 - May 31 13,939
Jun 1 - Sep 30 11,478
Oct 1 - Nov 15 13,939
East Braintree, MA 125
Nov 16 - Apr 15 13,153
Apr 16 - May 31 11,800
Jun 1 - Sep 30 9,093
Oct 1 - Nov 15 11,800
Signed for Identification
Algonquin: ____________________ /s/ JMM
Customer: /s/ W.R. Luthern
---------------------
/s/ ED
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
Weston, MA 100
Nov l6 - Apr l5 1,825
Apr l6 - May 3l 1,564
Jun 1 - Sep 30 1,043
Oct 1 - Nov 15 1,564
Wellesley, MA 60
Nov 16 - Apr 15 22,953
Apr 16 - May 31 19,824
Jun 1 - Sep 30 13,565
Oct 1 - Nov 15 19,824
Ponkapoag, MA 200
Nov 16 - Apr 15 37,368
Apr 16 - May 31 35,903
Jun 1 - Sep 30 32,975
Oct 1 - Nov 15 35,903
Signed for Identification
Algonquin: ____________________ /s/ JMM
Customer: /s/ W.R. Luthern
---------------------
/s/ ED
<PAGE>
93002ER
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-E)
Exhibit B
Point(s) of Delivery
(Continued)
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-E between
Algonquin Gas Transmission Company (Algonquin) and Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
Norwood, MA 75
Nov 16 - Apr 15 2,925
Apr l6 - May 3l 2,487
Jun 1 - Sep 30 1,611
Oct 1 - Nov 15 2,487
PotterStreet
East Braintree, MA
Nov 16 - Apr 15 9,779 Algonquin's line
Apr 16 - May 31 9,359 pressure as may
Jun 1 - Sep 30 8,629 exist from time
Oct 1 - Nov 15 9,395 to time
Algonquin's Maximum Daily Delivery Obligations for the East Braintree and
Potter Street Points of Delivery under Contract Nos. 93002ER, 93002CR and
99012 shall not exceed a combined daily total equal to the aggregate of
the former Maximum Daily Delivery Obligations at the East Braintree Point
of Delivery under Rate Schedules AFT-1 (F-1) and AFT-E (F-1) in the
amounts of 16,948 MMBtu and 5,238 MMBtu, respectively.
Signed for Identification
Algonquin: ____________________ /s/ JMM
Customer: /s/ W.R. Luthern
---------------------
/s/ ED
<PAGE>
Exhibit 10.17
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this 29th day of October,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Boston Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Customer and Algonquin are parties to an executed agreement under
Algonquin's Rate Schedule AFT-1 (Algonquin's Contract No. 934001) dated November
1, 1993; and
WHEREAS, Algonquin and Customer desire to enter into this Agreement to supersede
Algonquin's currently effective Contract No. 934001;
In consideration of the premises and of the mutual covenants herein contained,
the parties do agree as follows:
ARTICLE I
SCOPE OF AGREEMENT
1.1 Subject to the terms, conditions and limitations hereof and of Algonquin's
Rate Schedule AFT-1, Algonquin agrees to receive from or for the account
of Customer for transportation on a firm basis quantities of natural gas
tendered by Customer on any day at the Point(s) of Receipt; provided,
however, Customer shall not tender without the prior consent of Algonquin,
at any Point of Receipt on any day a quantity of natural gas in excess of
the applicable Maximum Daily Receipt Obligation for such Point of Receipt
plus the applicable Fuel Reimbursement Quantity; and provided further that
Customer shall not tender at all Point(s) of Receipt on any day or in any
year a cumulative quantity of natural gas, without the prior consent of
Algonquin, in excess of the following quantities of natural gas plus the
applicable Fuel Reimbursement Quantities:
Maximum Daily Transportation Quantity (MDTQ) 20,771 MMBtu
Maximum Annual Transportation Quantity (MATQ) 7,581,415 MMBtu
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
provided, however, subject to Algonquin's receipt of one (1) year
prior written notice Customer shall have a one time election to
reduce to 11,839 MMBtu the MDTQ of this Agreement with such
reduction to be effective on November 1, 2005.
1.2 Algonquin agrees to transport and deliver to or for the account of
Customer at the Point(s) of Delivery and Customer agrees to accept or
cause acceptance of delivery of the quantity received by Algonquin on any
day, less the Fuel Reimbursement Quantities; provided, however, Algonquin
shall not be obligated to deliver at any Point of Delivery on any day a
quantity of natural gas in excess of the applicable Maximum Daily Delivery
Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on the later of November 1, 1999, or
the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term ending on
and including October 31, 2006 ("Primary Term"), and shall remain in force
from year to year thereafter unless terminated by either party by written
notice one year or more prior to the end of the Primary Term or any
successive term thereafter. Algonquin's right to cancel this Agreement
upon the expiration of the Primary Term hereof or any succeeding term
shall be subject to Customer's rights pursuant to Sections 8 and 9 of the
General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE III
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-1 as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate specified
under Rate Schedule AFT-1 for service resulting from the conversion of
entitlements under former Rate Schedule FTP, nor less than the minimum
rate under Rate Schedule AFT-1.
3.2 This Agreement and all terms and provisions contained or incorporated
herein are subject to the provisions of Algonquin's applicable rate
schedules and of Algonquin's General Terms and Conditions on file with the
Federal Energy Regulatory Commission, or other duly constituted
authorities having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and Conditions are by
this reference made a part hereof.
3.3 Customer agrees that Algonquin shall have the unilateral right to file
with the appropriate regulatory authority and make changes effective in
(a) the rates and charges applicable to service pursuant to Algonquin's
Rate Schedule AFT-1, (b) Algonquin's Rate Schedule AFT-1, pursuant to
which service hereunder is rendered or (c) any provision of the General
Terms and Conditions applicable to Rate Schedule AFT-1. Algonquin agrees
that Customer may protest or contest the aforementioned filings, or may
seek authorization from duly constituted regulatory authorities for such
adjustment of Algonquin's existing FERC Gas Tariff as may be found
necessary to assure that the provisions in (a), (b), or (c) above are just
and reasonable.
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE IV
POINT(S) OF RECEIPT
Natural gas to be received by Algonquin for the account of Customer hereunder
shall be received at the outlet side of the measuring station(s) at or near the
Primary Point(s) of Receipt set forth in Exhibit A of the service agreement,
with the Maximum Daily Receipt Obligation and the receipt pressure obligation
indicated for each such Primary Point of Receipt. Natural gas to be received by
Algonquin for the account of Customer hereunder may also be received at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.2 of Rate Schedule AFT-1.
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer hereunder
shall be delivered on the outlet side of the measuring station(s) at or near the
Primary Point(s) of Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery pressure obligation
indicated for each such Primary Point of Delivery. Natural gas to be delivered
by Algonquin for the account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Algonquin's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Agreement, or any notice which
any party may desire to give to the other, shall be in writing and shall be
considered as duly delivered when mailed by registered, certified, or first
class mail to the post office address of the parties hereto, as the case may be,
as follows:
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
(a) Algonquin: Algonquin Gas Transmission Company
5400 Wetheimer Court
Houston, TX 77056
(b) Customer: Boston Gas Company
One Beacon Street
Boston, MA 02108
or such other address as either party shall designate by formal written notice.
ARTICLE VII
INTERPRETATION
The interpretation and performance of the Agreement shall be in accordance with
the laws of the Commonwealth of Massachusetts, excluding conflicts of law
principles that would require the application of the laws of a different
jurisdiction.
ARTICLE VIII
AGREEMENTS BEING SUPERSEDED
When this Agreement becomes effective, it shall supersede the following
agreements between the parties hereto.
Algonquin's agreement no. 934001 dated November 1, 1993, between
Algonquin and Customer under Algonquin's Rate Schedule AFT-1.
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
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/ PMT
Title:____________________________
BOSTON GAS COMPANY
By: /s/ W.R. Luthern
------------------------------
Title: Vice President
---------------------------
/s/ ED
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit A
Point(s) of Receipt
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Boston Gas Company (Customer) concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
-------- ------------------ ----------------
Lambertville, NJ 20,771 At any pressure
requested by
Algonquin but not in
excess of 750 Psig.
Signed for Identification
Algonquin: ______________________
/s/ JMM
Customer: /s/ W.R. Luthern
-----------------------
/s/ ED
<PAGE>
Contract No. 934001R
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
Dated: October 29, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Boston Gas Company (Customer) concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (PSig)
-------- ------------------- -----------------
Everett, MA 51 75
(at reduction valves)
Polaroid, Waltham, MA 10,081 Algonquin's Line
pressure as may exist
from time to time.
Medford, MA 10,639 200
Signed for Identification
Algonquin: ______________________
/s/ JMM
Customer: /s/ W.R. Luthern
-----------------------
/s/ ED
<PAGE>
Exhibit 10.27.1
Contract #: 800105R1
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE FT-1)
This Service Agreement, made and entered into this 29th day of October,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and BOSTON GAS COMPANY (herein called
"Customer", whether one or more),
W I T N E S S E T H:
WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated December 30, 1993, under Pipeline's Rate Schedule FT-1 (Pipeline
Contract No. 800105); and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
to supersede Pipeline's currently effective Contract No. 800105;
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) 39,624 dth
provided, however, subject to Pipeline's receipt of one (1) year prior
written notice Customer shall have a one time election to reduce to 22,586
dth the MDQ of this Service Agreement with such reduction to be effective
on November 1, 2005.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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 the later of November
1, 1999, or the in-service date of the facilities authorized by the Commission
in Docket No. CP99-113-000, and shall continue in force and effect until October
31, 2006, 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 one (1) year prior written notice to the other
specifying a termination date of October 31, 2006, or any October 31 thereafter.
Subject to Section 22 of Pipeline's General Terms and Conditions and without
prejudice to such rights, this Service Agreement may be terminated
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FT-1
(Continued)
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
3
<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 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.
4
<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: BOSTON GAS COMPANY
ONE BEACON STREET
BOSTON, MA 02108
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.
5
<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:
service agreement dated December 30, 1993, between Pipeline and Customer
under Pipeline's Rate Schedule FT-1 (Pipeline's Contract No. 800105).
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/ PMT
ATTEST:
- ---------------------------------------
BOSTON GAS COMPANY
By /s/ William R. Luthern
-------------------------------------
ATTEST:
/s/ [ILLEGIBLE]
- ---------------------------------------
7
<PAGE>
Contract #800105R1
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED 10/29/99,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND BOSTON GAS COMPANY ("Customer"), DATED 10/29/99:
(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.
Transport at ion
Transportation Path Path Quantity (Dth/D)
------------------- ---------------------
M1 to M3 39,624
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------/s/ JMM
CUSTOMER: /s/ W.R. Luthern
--------------------------/s/ ED
SUPERSEDES EXHIBIT A DATED:
--------
A-1
<PAGE>
Contract #: 800105R1
EXHIBIT B, POINT(S) OF DELIVERY, DATED 10/29/99,
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
<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, 39,624 As requested by TX EAST TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ customer, not to TRAN TRAN
exceed 750 PSIG
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------/s/ JMM
CUSTOMER: /s/ W.R. Luthern
--------------------------/s/ ED
SUPERSEDES EXHIBIT B DATED
--------
B-1
<PAGE>
Contract #: 800105R1
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED 10/29/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE FT-1
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
BOSTON GAS COMPANY ("CUSTOMER"), DATED 10/29/99:
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
- ------------------------------------------------------------------------------------------------------------
ETX 5205 1700
- ------------------------------------------------------------------------------------------------------------
WLA 48
- ------------------------------------------------------------------------------------------------------------
ELA 33315
- ------------------------------------------------------------------------------------------------------------
M1-24 5205
- ------------------------------------------------------------------------------------------------------------
M1-30 33315
- ------------------------------------------------------------------------------------------------------------
M1-TXG 1748
- ------------------------------------------------------------------------------------------------------------
M1-TGC
- ------------------------------------------------------------------------------------------------------------
M2-24
- ------------------------------------------------------------------------------------------------------------
M2-30
- ------------------------------------------------------------------------------------------------------------
M2-TXG
- ------------------------------------------------------------------------------------------------------------
M2-TGC
- ------------------------------------------------------------------------------------------------------------
M2 39624
- ------------------------------------------------------------------------------------------------------------
M3
============================================================================================================
</TABLE>
C-1
<PAGE>
Contract #: 800105R1
EXHIBIT C (Continued)
BOSTON 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 5205
- ------------------------------------------------------------------------------------------------------------
M1-30 33315
- ------------------------------------------------------------------------------------------------------------
M1-TXG 1748
- ------------------------------------------------------------------------------------------------------------
M1-TGC
- ------------------------------------------------------------------------------------------------------------
M2-24
- ------------------------------------------------------------------------------------------------------------
M2-30
- ------------------------------------------------------------------------------------------------------------
M2-TXG
- ------------------------------------------------------------------------------------------------------------
M2-TGC
- ------------------------------------------------------------------------------------------------------------
M2 39624
- ------------------------------------------------------------------------------------------------------------
M3
============================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE:
--------------------------/s/ JMM
CUSTOMER: /s/ W.R. Luthern
--------------------------/s/ ED
SUPERSEDES EXHIBIT C DATED
--------
C-1
<PAGE>
Exhibit 10.30
Contract #: 331009R1
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
This Service Agreement, made and entered into this 29th day of October,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and BOSTON GAS COMPANY herein called
"Customer", whether one or more),
W I T N E S S E T H:
WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated March 23, 1995 under Pipeline's Rate Schedule FTS-7 (Pipeline's
Contract No. 331009); and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
to supersede and extend Pipeline's currently effective Contract No. 331009;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements herein contained, the parties do covenant and agree as
follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof and of Pipeline's
Rate Schedule FTS-7, Pipeline agrees to deliver on a firm basis for Customer's
account quantities of gas up to following quantity:
Maximum Daily Quantity (MDQ) 29,915 dth
provided, however, subject to Pipeline's receipt of one (1) year
prior written notice Customer shall have a one time election to
reduce to 17,052 dth the MDQ of this Service Agreement with such
reduction to be effective on November 1, 2005.
Pipeline shall receive for Customer's account, at the Customer Point(s),
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 the CNG Point(s), such daily quantities tendered up to such
Customer's MDQ.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(Continued)
Pipeline shall receive for Customer's account, at the CNG Point(s), 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 the Customer Point(s), 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, as specified in
the executed service agreement. 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, as specified in the executed service agreement.
ARTICLE II
TERM OF AGREEMENT
This Service Agreement shall become effective on the later of November 1,
1999, or the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term ending and
including October 31, 2006, and shall remain in force from 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 one
(1) year prior written notice to the other specifying a termination date of
October 31, 2006, or any October 31 thereafter. 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. Notwithstanding the foregoing, service shall not be
terminated unless and until Pipeline has received abandonment authority pursuant
to Section 7 of the Natural Gas Act. Customer shall have the right to oppose
Pipeline's application to the Federal Energy Regulatory Commission, or any
successor agency, for such abandonment authority. For the 120 days following
termination
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(Continued)
of this Service Agreement, Pipeline shall utilize its best efforts to provide
Customer with such additional interruptible transportation service, to be
provided pursuant to Rate Schedule IT-1 or successor of Rate Schedule IT-1, as
is necessary for Customer to withdraw and receive delivery of all gas remaining
in storage pursuant to CNG's Rate Schedule GSS.
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 FTS-7 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 FTS-7 as filed with the Federal
Energy Regulatory Commission and as the same may be hereafter revised or
changed.
Pipeline shall have the right from time to time, by the filing of a
revised rate schedule, to increase or decrease the rates, to change the form of
the applicable rate schedule and to take such other and further action with
respect thereto without further consent by Customer and such changes in rates
and other changes shall become the Rate Schedule and Terms and Conditions under
which the gas shall be transported hereunder. Customer shall have the right to
oppose any of the foregoing and to request reduction in rates to the extent that
Customer is legally permitted to do so under the Natural Gas Act.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(Continued)
ARTICLE IV
CUSTOMER POINT(S) AND CNG POINT(S)
Natural gas to be received by Pipeline for Customer's account for service
hereunder shall be received on the outlet side of the measuring station at or
near the following designated Customer Point(s) or CNG Point(s), and natural gas
to be delivered by Pipeline for Customer's account hereunder shall be delivered
at the outlet side of the measuring stations at or near the following designated
CNG Point(s) or Customer Point(s), in accordance with the Maximum Daily Receipt
Obligation (MDRO) plus Applicable Shrinkage, Maximum Daily Delivery Obligation
(MDDO), receipt and delivery pressure obligations and measurement
responsibilities indicated below for each:
Maximum Measurement
Daily Pressure Responsi-
Customer Point Obligation Obligation bilities
-------------- ---------- ---------- --------
1. In Hunterdon 29,915 dth As requested by customer Pipeline
County, NJ, and not to exceed 750 psig
designated by
Pipeline as
Measuring Station
70087
2. In Morris County, 29,915 dth As requested by customer Pipeline
NJ, and designated not to exceed 750 psig
by Pipeline as
Measuring Station
71078
3. AGT - Boston Gas 0 N/A N/A
Company for
nomination
purposes only
79818
Maximum Measurement
Daily Pressure Responsi-
CNG Point Obligation Obligation bilities
--------- ---------- ---------- --------
1. In Westmoreland 29,915 dth At such pressure Pipeline
County, PA, and necessary to enter
designated by Pipeline's facilities
Pipeline as not to exceed the
Measuring Station Maximum Allowable
75082 Operating Pressure
2. In Clinton County, 0 dth At such pressure CNG
PA, and designated necessary to enter Transmission
by Pipeline as Pipeline's facilities
Measuring Station not to exceed the
75931 Maximum Allowable
Operating Pressure
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(Continued)
provided, however, receipt of gas by Pipeline for Customer's account at Customer
Point(s) shall be accomplished solely by the displacement of gas quantities
otherwise deliverable to Customer by Pipeline pursuant to other contractual
arrangements between Pipeline and Customer, and which quantities shall be billed
by Pipeline and paid by Customer as if such deliveries in fact occurred pursuant
to the relevant contractual arrangements;
further provided, however, that until changed by a subsequent Agreement between
Pipeline and Customer, Pipeline's aggregate maximum daily delivery obligations
at each of the Customer Points described above, including Pipeline's maximum
daily delivery obligations under this and all other firm Service Agreements
existing between Pipeline and Customer, shall in no event exceed the following:
Customer Aggregate Maximum
Point Daily Delivery Obligation
----- -------------------------
No. 1 177,070 dth
and provided further that Pipeline shall have no obligation to deliver natural
gas designated as MDQ at any Customer Point other than that listed below:
Customer Point
--------------
Measuring Station 70087, Hunterdon County, New Jersey
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.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(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: BOSTON GAS COMPANY
One Beacon Street
Boston, MA 02108
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.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE FTS-7
(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:
service agreement dated March 23, 1995 between Pipeline and Customer under
Pipeline's Rate Schedule FTS-7 (Pipeline's Contract No. 331009).
<PAGE>
Exhibit 10.31
Contract #: 820015
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
This Service Agreement, made and entered into this 29th day of October,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and BOSTON GAS COMPANY (herein called
"Customer", whether, one or more),
W I T N E S S E T H:
WHEREAS, Customer desires Pipeline to transport natural gas for Customer's
account on a firm basis pursuant to the terms and conditions of Pipeline's Rate
Schedule CDS; and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
under Rate Schedule CDS;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements herein contained, the parties do covenant and agree as
follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of Pipeline's
Rate Schedule CDS, and of the General Terms and Conditions, transportation
service hereunder will be firm. Subject to the terms, conditions and limitations
hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified in Article IV
herein or available to Customer pursuant to Section 14 of the General Terms and
Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's
account, as requested for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:
Maximum Daily Quantity (MDQ) 3,177 dth
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
Subject to variances as may be permitted by Sections 2.4 of Rate Schedule
CDS or the General Terms and Conditions, Customer shall deliver to Pipeline and
Pipeline shall receive, for Customer's account, at those points on Pipeline's
system as specified in Article IV herein or available to Customer pursuant to
Section 14 of the General Terms and Conditions (hereinafter referred to as
Point(s) of Receipt) daily quantities of gas equal to the daily quantities
delivered to Customer pursuant to this Service Agreement up to Customer's MDQ,
plus Applicable Shrinkage as specified in the General Terms and Conditions.
Pipeline shall not be obligated to, but may at its discretion, receive at
any Point of Receipt on any day a quantity of gas in excess of the applicable
Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall
not receive in the aggregate at all Points of Receipt on any day a quantity of
gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any Point of Delivery
on any day a quantity of gas in excess of the applicable Maximum Daily Delivery
Obligation (MDDO), but shall not deliver in the aggregate at all Points of
Delivery on any day a quantity of gas in excess of the MDQ.
In addition to the MDQ and subject to the terms, conditions and
limitations hereof, Rate Schedule CDS and the General Terms and Conditions,
Pipeline shall deliver within the Access Area under this and all other service
agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to
Customer's Operational Segment Capacity Entitlements, excluding those
Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for
Customer's account, as requested on any day.
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on November 1, 1999, and
shall continue in force and effect until October 31, 2000, 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 one
(1) year prior written notice to the other specifying a termination date of any
October 31 of any year occurring on or after the expiration of the primary term.
Subject to Section 22 of Pipeline's General Terms and Conditions and without
prejudice to such rights, this Service Agreement may be terminated at any time
by Pipeline in the event Customer fails to pay part or all of the amount of any
bill for service hereunder and such failure continues for thirty (30) days after
payment is due; provided, Pipeline gives thirty (30) days prior written notice
to Customer of such termination and provided further such termination shall not
be effective if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond guaranteeing
payment to Pipeline of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR
THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED
ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF
THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND
CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
Any portions of this Service Agreement necessary to correct or cash-out
imbalances under this Service Agreement as required by the General Terms and
Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other
parts of this Service Agreement until such time as such balancing has been
accomplished.
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain subject to the
applicable provisions of Rate Schedule CDS and of the General Terms and
Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy
Regulatory Commission, all of which are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered hereunder and for
the availability of such service in the period stated, the applicable prices
established under Pipeline's Rate Schedule CDS as filed with the Federal Energy
Regulatory Commission, and as same may hereafter be legally amended or
superseded.
Customer agrees that Pipeline shall have the unilateral right to file with
the appropriate regulatory authority and make changes effective in (a) the rates
and charges applicable to service pursuant to Pipeline's Rate Schedule CDS, (b)
Pipeline's Rate Schedule CDS pursuant to which service hereunder is rendered or
(c) any provision of the General Terms and Conditions applicable to Rate
Schedule CDS. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.
4
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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 Pith the gas produced and tendered for
transportation hereunder.
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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: BOSTON GAS COMPANY
One Beacon Street
Boston, MA 02108
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
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
other. In addition, Customer may assign its rights to capacity pursuant to
Section 3.14 of the General Terms and Conditions. To the extent Customer so
desires, when it releases capacity pursuant to Section 3.14 of the General Terms
and Conditions, Customer may require privity between Customer and the
Replacement Customer, as further provided in the applicable Capacity Release
Umbrella Agreement.
ARTICLE VIII
INTERPRETATION
The interpretation and performance of this Service Agreement shall be in
accordance with the laws of the State of Texas without recourse to the law
governing conflict of laws.
This Service Agreement and the obligations of the parties are subject to
all present and future valid laws with respect to the subject matter, State and
Federal, and to all valid present and future orders, rules, and regulations of
duly constituted authorities having jurisdiction.
ARTICLE IX
CANCELLATION OF PRIOR CONTRACT(S)
This Service Agreement supersedes and cancels, as of the effective date of
this Service Agreement, the contract(s) between the parties hereto as described
below:
Not Applicable
7
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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/ PMT
ATTEST:
- -------------------------
BOSTON GAS COMPANY
By /s/ William R. Luthern
----------------------------------
ATTEST:
/s/ Elizabeth [ILLEGIBLE]
- -------------------------
8
<PAGE>
Contract #: 820015
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED 10/29/99
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND BOSTON GAS COMPANY ("Customer"), DATED 10/29/99
(1) Customer's firm Point(s) of Receipt:
Maximum Daily
Point Receipt Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage) Responsibilities Owner Operator
------- ----------- ------------------ ---------------- ----- --------
None
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published by
Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as set
forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s)
of Receipt.
Transportation
Transportation Path Path Ouantity (Dth/D)
------------------- ---------------------
M2 to M3 3,177
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ JMM
----------------------------
CUSTOMER: /s/ W. R. Luthern /s/ ED
----------------------------
SUPERSEDES EXHIBIT A DATED:
---------
A-1
<PAGE>
Contract #: 820015
EXHIBIT B, POINT(S) OF DELIVERY, DATED 10/29/99
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
<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>
1. 70087 ALGONQUIN - LAMBERTVILLE 3,177 AS REQUESTED TX EAST TRAN TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ BY CUSTOMER, TRAN
NOT TO
EXCEED 750
POUNDS PER
SQUARE INCH
GUAGE
</TABLE>
provided, however, that until changed by a subsequent Agreement between Pipeline
and Customer, Pipeline's aggregate maximum daily delivery obligations under this
and all other firm Service Agreements existing between Pipeline and Customer,
shall in no event exceed the following:
B-1
<PAGE>
Contract #: 820015
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
BOSTON GAS COMPANY
Aggregate Maximum Daily
Point of Delivery Delivery Obligation (dth)
- ----------------- -------------------------
No. 1 177,070
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ JMM
----------------------------
CUSTOMER: /s/ W. R. Luthern /s/ ED
----------------------------
SUPERSEDES EXHIBIT B DATED:
---------
B-2
<PAGE>
Contract #: 820015
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED 10/29/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
BOSTON GAS COMPANY ("CUSTOMER"), DATED 10/29/99
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
- --------------------------------------------------------------------------------------------------------------------
ETX
- --------------------------------------------------------------------------------------------------------------------
WLA
- --------------------------------------------------------------------------------------------------------------------
ELA
- --------------------------------------------------------------------------------------------------------------------
M1-24
- --------------------------------------------------------------------------------------------------------------------
M1-30
- --------------------------------------------------------------------------------------------------------------------
M1-TXG
- --------------------------------------------------------------------------------------------------------------------
M1-TGC
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2 3,177
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
C-1
<PAGE>
Contract #: 820015
EXHIBIT C (Continued)
BOSTON 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
- --------------------------------------------------------------------------------------------------------------------
M1-30
- --------------------------------------------------------------------------------------------------------------------
M1-TXG
- --------------------------------------------------------------------------------------------------------------------
M1-TGC
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2 3,177
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION:
PIPELINE: /s/ JMM
----------------------------
CUSTOMER: /s/ W. R. Luthern /s/ ED
----------------------------
SUPERSEDES EXHIBIT c DATED:
---------
C-2
<PAGE>
Exhibit 10.34
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
THIS AGREEMENT is made and entered into as of the 1st day of September, 1993, by
and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter
referred to as "Transporter" and BOSTON GAS CO, a MASSACHUSETTS corporation,
hereinafter referred to as "Shipper." Transporter and Shipper shall collectively
be referred to herein as the "Parties."
ARTICLE I
DEFINITIONS
1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of
gas which Transporter agrees to receive and transport on a firm basis,
subject to Article II herein, for the account of Shipper hereunder on each
day during each year during the term hereof, which shall be 10,533
dekatherms. Any limitations of the quantities to be received from each
Point of Receipt and/or delivered to each Point of Delivery shall be as
specified on Exhibit "A" attached hereto.
1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General
Terms and conditions of Transporter's FERC Gas Tariff.
ARTICLE II
TRANSPORTATION
Transportation Service - Transporter agrees to accept and receive daily on a
firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account
such quantity of gas as Shipper makes available up to the Transportation
Quantity, and to deliver to or for the account of Shipper to the Point(s) of
Delivery an Equivalent Quantity of gas.
ARTICLE III
POINT(S) OF RECEIPT AND DELIVERY
The Primary Point(s) of Receipt and Delivery shall be those points specified on
Exhibit "A" attached hereto.
ARTICLE IV
All facilities are in place to render the service provided for in this
Agreement.
1
<PAGE>
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
ARTICLE V
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
For all gas received, transported and delivered hereunder the Parties agree to
the Quality Specifications and Standards for Measurement as specified in the
General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. To
the extent that no new measurement facilities are installed to provide service
hereunder, measurement operations will continue in the manner in which they have
previously been handled. In the event that such facilities are not operated by
Transporter or a downstream pipeline, then responsibility for operations shall
be deemed to be Shipper's.
ARTICLE VI
RATES AND CHARGES FOR GAS TRANSPORTATION
6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the
rates, charges, and surcharges to be paid by Shipper to Transporter for
the transportation service provided herein shall be in accordance with
Transporter's Rate Schedule FT-A and the General Terms and Conditions of
Transporter's FERC Gas Tariff.
6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any
filing or similar fees, which have not been previously paid for by
Shipper, which Transporter incurs in rendering service hereunder.
6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have
the unilateral right to file with the appropriate regulatory authority and
make effective changes in (a) the rates and charges applicable to service
pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s)
pursuant to which service hereunder is rendered, or (c) any provision of
the General Terms and Conditions applicable to those rate schedules.
Transporter agrees that Shipper may protest or contest the aforementioned
filings, or may seek authorization from duly constituted regulatory
authorities for such adjustment of Transporter's existing FERC Gas Tariff
as may be found necessary to assure Transporter just and reasonable rates.
ARTICLE VII
BILLINGS AND PAYMENTS
Transporter shall bill and Shipper shall pay all rates and charges in accordance
with Articles V and VI, respectively, of the General Terms and Conditions of
Transporter's FERC Gas Tariff.
2
<PAGE>
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
ARTICLE VIII
GENERAL TERMS AND CONDITIONS
This Agreement shall be subject to the effective provisions of Transporter's
Rate Schedule FT-A and to the General Terms and Conditions incorporated therein,
as the same may be changed or superseded from time to time in accordance with
the rules and regulations of the FERC.
ARTICLE IX
REGULATION
9.1 This Agreement shall be subject to all applicable and lawful governmental
statutes, orders, rules and regulations and is contingent upon the receipt
and continuation of all necessary regulatory approvals or authorizations
upon terms acceptable to Transporter. This Agreement shall be void and of
no force and effect if any necessary regulatory approval is not so
obtained or continued. All Parties hereto shall cooperate to obtain or
continue all necessary approvals or authorizations, but no Party shall be
liable to any other Party for failure to obtain or continue such approvals
or authorizations.
9.2 The transportation service described herein shall be provided subject to
Subpart G, Part 284, of the FERC Regulations.
ARTICLE X
RESPONSIBILITY DURING TRANSPORTATION
Except as herein specified, the responsibility for gas during transportation
shall be as stated in the General Terms and Conditions of Transporter's FERC Gas
Tariff Volume No. 1.
ARTICLE XI
WARRANTIES
11.1 In addition to the warranties set forth in Article IX of the General Terms
and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the
following:
(a) Shipper warrants that all upstream and downstream transportation
arrangements are in place, or will be in place as of the requested
effective date of service, and that it has advised the upstream and
downstream transporters of the receipt and delivery points under
this Agreement and any quantity limitations for each point as
specified on Exhibit "A" attached hereto. Shipper agrees to
indemnify and hold Transporter harmless for refusal to transport gas
hereunder in the
3
<PAGE>
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
event any upstream or downstream transporter fails to receive or
deliver gas as contemplated by this Agreement.
(b) Shipper agrees to indemnify and hold Transporter harmless from all
suits, actions, debts, accounts, damages, costs, losses and expenses
(including reasonable attorneys fees) arising from or out of breach
of any warranty by Shipper herein.
11.2 Transporter shall not be obligated to provide or continue service
hereunder in the event of any breach of warranty.
ARTICLE XII
TERM
12.1 This Agreement shall be effective as of the 1st day of September, 1993,
and shall remain in force and effect until the 14th day of January, 2003,
("Primary Term") and on a month to month basis thereafter unless
terminated by either Party upon at least thirty (30) days prior written
notice to the other Party; provided, however, that if the Primary Term is
one year or more, then unless Shipper elects upon one year's prior written
notice to Transporter to request a lesser extension term, the Agreement
shall automatically extend upon the expiration of the Primary Term for a
term of five years and shall automatically extend for successive five year
terms thereafter unless Shipper provides notice described above in advance
of the expiration of a succeeding term; provided further, if the FERC or
other governmental body having jurisdiction over the service rendered
pursuant to this Agreement authorizes abandonment of such service, this
Agreement shall terminate on the abandonment date permitted by the FERC or
such other governmental body.
12.2 Any portions of this Agreement necessary to resolve or cash-out imbalances
under this Agreement as required by the General Terms and Conditions of
Transporter's FERC Gas Tariff Volume No. 1, shall survive the other parts
of this Agreement until such time as such balancing has been accomplished;
provided, however, that Transporter notifies Shipper of such imbalance no
later than twelve months after the termination of this Agreement.
12.3 This Agreement will terminate automatically upon written notice from
Transporter in the event Shipper fails to pay all of the amount of any
bill for service rendered by Transporter hereunder in accord with the
terms and conditions of Article VI of the General Terms and Conditions of
Transporter's FERC Tariff.
4
<PAGE>
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
ARTICLE XIII
NOTICE
Except as otherwise provided in the General Terms and Conditions applicable to
this Agreement, any notice under this Agreement shall be in writing and mailed
to the post office address of the Party intended to receive the same, as
follows:
TRANSPORTER: Tennessee Gas Pipeline Company
P. 0. Box 2511
Houston, Texas 77252-2511
Attention: Transportation Marketing
SHIPPER:
NOTICES: BOSTON GAS CO
ONE BEACON STREET
34TH FLOOR
BOSTON, MA 02108
Attention: BILL YARDLEY
BILLING: BOSTON GAS CO
ONE BEACON STREET
34TH FLOOR
BOSTON, MA 02108
Attention: DON TULCHINSKY
or to such other address as either Party shall designate by formal written
notice to the other.
ARTICLE XIV
ASSIGNMENTS
14.1 Either Party may assign or pledge this Agreement and all rights and
obligations hereunder under the provisions of any mortgage, deed of trust,
indenture, or other instrument which it has executed or may execute
hereafter as security for indebtedness. Either Party may, without
relieving itself of its obligation under this Agreement, assign any of its
rights hereunder to a company with which it is affiliated. Otherwise,
Shipper shall not assign this Agreement or any of its rights hereunder,
except in accord with Article III, Section 11 of the General Terms and
Conditions of Transporter's FERC Gas Tariff.
14.2 Any person which shall succeed by purchase, merger, or consolidation to
the properties, substantially as an entirety, of either Party hereto shall
be entitled to the rights and shall be subject to the obligations of its
predecessor in interest under this Agreement.
5
<PAGE>
SERVICE PACKAGE NO. 256
AMENDMENT NO. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
ARTICLE XV
MISCELLANEOUS
15.1 The interpretation and performance of this Agreement shall be in
accordance with and controlled by the laws of the State of Texas, without
regard to the doctrines governing choice of law.
15.2 If any provisions of this Agreement is declared null and void, or
voidable, by a court of competent jurisdiction, then that provision will
be considered severable at either Party's option; and if the severability
option is exercised, the remaining provisions of the Agreement shall
remain in full force and effect.
15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas
Tariff, no modification of or supplement to the terms and provisions
stated in this agreement shall be or become effective until Shipper has
submitted a request for change through the TENN-SPEED 2 System and Shipper
has been notified through TENN-SPEED 2 of Transporter's agreement to such
change.
15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a
part hereof for all purposes.
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
duly executed as of the date first hereinabove written.
TENNESSEE GAS PIPELINE COMPANY
BY: /s/ Randall G. Schorre
--------------------------
Randall G. Schorre
Agent and Attorney-in-Fact
BOSTON GAS COMPANY
BY: /s/ William R. Luthern
---------------------------
TITLE: VICE PRESIDENT
---------------------------
DATE: 3 DEC 94
---------------------------
6
<PAGE>
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-A Rate Schedule)
EXHIBIT "A"
TO GAS TRANSPORTATION AGREEMENT
DATED September 1st, 1993
BETWEEN
TENNESSEE GAS PIPELINE COMPANY
AND
BOSTON GAS CO
SERVICE PACKAGE: 256
SERVICE PACKAGE TQ: 10,533
<TABLE>
<CAPTION>
MINIMUM
METER AMD METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TQ PRESSURE
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
010902 0 TRANS-NIAGARA RIVER PURCHASE TRANS CANADA PIPELINE LTD NIAGARA NY 05 R 230 10,533 700 LBS
020111 0 BOSTON-LEOMINSTER MASS BOSTON GAS CO WORCESTER MA 06 D 200 1,025 100 LBS
020115 0 BOSTON-ARLINGTON MASS BOSTON GAS CO MIDDLESEX MA 06 D 200 10,533 100 LBS
020192 0 BOSTON-LEXINGTON MASS BOSTON GAS CO MIDDLESEX MA 06 D 200 513 100 LBS
</TABLE>
NUMBER OF RECEIPT POINTS: 1
NUMBER OF DELIVERY POINTS: 3
<PAGE>
Exhibit 10.35
Contract #: 800286R1
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
This Service Agreement, made and entered into this 29TH day of October,
1999, by and between TEXAS EASTERN TRANSMISSION CORPORATION, a Delaware
Corporation (herein called "Pipeline") and BOSTON GAS COMPANY (herein called
"Customer", whether one or more),
W I T N E S S E T H:
WHEREAS, Customer and Pipeline are parties to an executed service
agreement dated June 21, 1996 under Pipeline's Rate Schedule CDS (Pipeline's
Contract No. 800286R); and
WHEREAS, Pipeline and Customer desire to enter into this Service Agreement
to supersede Pipeline's currently effective Contract No. 800286R;
NOW, THEREFORE, in consideration of the premises and of the mutual
covenants and agreements herein contained, the parties do covenant and agree as
follows:
ARTICLE I
SCOPE OF AGREEMENT
Subject to the terms, conditions and limitations hereof, of Pipeline's
Rate Schedule CDS, and of the General Terms and Conditions, transportation
service hereunder will be firm. Subject to the terms, conditions and limitations
hereof and of Sections 2.3 and 2.4 of Pipeline's Rate Schedule CDS, Pipeline
shall deliver to those points on Pipeline's system as specified in Article IV
herein or available to Customer pursuant to Section 14 of the General Terms and
Conditions (hereinafter referred to as Point(s) of Delivery), for Customer's
account, as requested for any day, natural gas quantities up to Customer's MDQ.
Customer's MDQ is as follows:
Maximum Daily Quantity (MDQ) 32,616 dth
provided, however, subject to Pipeline's receipt of one (1) year prior
written notice Customer shall have a one time election to reduce to 18,591
dth the MDQ of this Service Agreement with such reduction to be effective
on November 1, 2005.
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
Subject to variances as may be permitted by Sections 2.4 of Rate Schedule
CDS or the General Terms and Conditions, Customer shall deliver to Pipeline and
Pipeline shall receive, for Customer's account, at those points on Pipeline's
system as specified in Article IV herein or available to Customer pursuant to
Section 14 of the General Terms and Conditions (hereinafter referred to as
Point(s) of Receipt) daily quantities of gas equal to the daily quantities
delivered to Customer pursuant to this Service Agreement up to Customer's MDQ,
plus Applicable Shrinkage as specified in the General Terms and Conditions.
Pipeline shall not be obligated to, but may at its discretion, receive at
any Point of Receipt on any day a quantity of gas in excess of the applicable
Maximum Daily Receipt Obligation (MDRO), plus Applicable Shrinkage, but shall
not receive in the aggregate at all Points of Receipt on any day a quantity of
gas in excess of the applicable MDQ, plus Applicable Shrinkage. Pipeline shall
not be obligated to, but may at its discretion, deliver at any Point of Delivery
on any day a quantity of gas in excess of the applicable Maximum Daily Delivery
Obligation (MDDO), but shall not deliver in the aggregate at all Points of
Delivery on any day a quantity of gas in excess of the MDQ.
In addition to the MDQ and subject to the terms, conditions and
limitations hereof, Rate Schedule CDS and the General Terms and Conditions,
Pipeline shall deliver within the Access Area under this and all other service
agreements under Rate Schedules CDS, FT-1, and/or SCT, quantities up to
Customer's Operational Segment Capacity Entitlements, excluding those
Operational Segment Capacity Entitlements scheduled to meet Customer's MDQ, for
Customer's account, as requested on any day.
2
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
ARTICLE II
TERM OF AGREEMENT
The term of this Service Agreement shall commence on the later of November
1, 1999, or the in-service date of the facilities authorized by the Commission
in Docket No. CP99-113-OOO, and shall continue in effect for a term ending and
including October 31, 2006, and shall remain in force from 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 one
(1) year prior written notice to the other specifying a termination date of
October 31, 2006, or any October 31 thereafter. Subject to Section 22 of
Pipeline's General Terms and Conditions and without prejudice to such rights,
this Service Agreement may be terminated at any time by Pipeline in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty (30) days after payment is due;
provided, Pipeline gives thirty (30) days prior written notice to Customer of
such termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such outstanding bill
or furnishes a good and sufficient surety bond guaranteeing payment to Pipeline
of such outstanding bill.
THE TERMINATION OF THIS SERVICE AGREEMENT WITH A FIXED CONTRACT TERM OR
THE PROVISION OF A TERMINATION NOTICE BY CUSTOMER TRIGGERS PREGRANTED
ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT AS OF THE EFFECTIVE DATE OF
THE TERMINATION. PROVISION OF A TERMINATION NOTICE BY PIPELINE ALSO TRIGGERS
CUSTOMER'S RIGHT OF FIRST REFUSAL UNDER SECTION 3.13 OF THE GENERAL TERMS AND
CONDITIONS ON THE EFFECTIVE DATE OF THE TERMINATION.
Any portions of this Service Agreement necessary to correct or cash-out
imbalances under this Service Agreement as required by the General Terms and
Conditions of Pipeline's FERC Gas Tariff, Volume No. 1, shall survive the other
parts of this Service Agreement until such time as such balancing has been
accomplished.
3
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
ARTICLE III
RATE SCHEDULE
This Service Agreement in all respects shall be and remain subject to the
applicable provisions of Rate Schedule CDS and of the General Terms and
Conditions of Pipeline's FERC Gas Tariff on file with the Federal Energy
Regulatory Commission, all of which are by this reference made a part hereof.
Customer shall pay Pipeline, for all services rendered hereunder and for
the availability of such service in the period stated, the applicable prices
established under Pipeline's Rate Schedule CDS as filed with the Federal Energy
Regulatory Commission, and as same may hereafter be legally amended or
superseded.
Customer agrees that Pipeline shall have the unilateral right to file with
the appropriate regulatory authority and make changes effective in (a) the rates
and charges applicable to service pursuant to Pipeline's Rate Schedule CDS, (b)
Pipeline's Rate Schedule CDS pursuant to which service hereunder is rendered or
(c) any provision of the General Terms and Conditions applicable to Rate
Schedule CDS. Notwithstanding the foregoing, Customer does not agree that
Pipeline shall have the unilateral right without the consent of Customer
subsequent to the execution of this Service Agreement and Pipeline shall not
have the right during the effectiveness of this Service Agreement to make any
filings pursuant to Section 4 of the Natural Gas Act to change the MDQ specified
in Article I, to change the term of the agreement as specified in Article II, to
change Point(s) of Receipt specified in Article IV, to change the Point(s) of
Delivery specified in Article IV, or to change the firm character of the service
hereunder. Pipeline agrees that Customer may protest or contest the
aforementioned filings, and Customer does not waive any rights it may have with
respect to such filings.
4
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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.
5
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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: BOSTON GAS COMPANY
One Beacon Street
Boston, MA 02108
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
6
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(Continued)
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.
7
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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 dated June 21, 1996 between Pipeline and Customer under
Pipeline's Rate Schedule CDS (Pipeline's Contract No. 800286R).
8
<PAGE>
SERVICE AGREEMENT
FOR RATE SCHEDULE CDS
(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/ PMT (initials)
ATTEST:
____________________
BOSTON GAS COMPANY
By /s/ William R. Luthern
-------------------------------------
ATTEST:
/s/ [Illegible]
- --------------------
9
<PAGE>
Contract #800286R1
EXHIBIT A, TRANSPORTATION PATHS
FOR BILLING PURPOSES, DATED 10/29/99
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline")
AND BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
(1) Customer's firm Point(s) of Receipt:
Maximum Daily
Receipt
Point Obligation
of (plus Applicable Measurement
Receipt Description Shrinkage Responsibilities Owner Operator
------- ----------- ---------------- ---------------- ----- --------
None
(2) Customer shall have Pipeline's Master Receipt Point List ("MRPL").
Customer hereby agrees that Pipeline's MRPL as revised and published by
Pipeline from time to time is incorporated herein by reference.
Customer hereby agrees to comply with the Receipt Pressure Obligation as set
forth in Section 6 of Pipeline's General Terms and Conditions at such Point(s)
of Receipt.
Transportation
Transportation Path Path Quantity (Dth/D)
------------------- ---------------------
M1 to M3 32,616
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ JMM (Initials)
------------------------------
CUSTOMER: /s/ W. R. Luthern
------------------------------
SUPERSEDES EXHIBIT A DATED: ____________
/s/ ED (Initials)
A-1
<PAGE>
Contract #800286R1
EXHIBIT B, POINT(S) OF DELIVERY, DATED 10/29/99
TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("Pipeline"), AND
BOSTON GAS COMPANY ("Customer"),
DATED 10/29/99:
<TABLE>
<CAPTION>
Maximum
Point Daily Delivery
of Delivery Pressure Measurement
Delivery Description Obligation Obligation Responsibilities Owner Operator
-------- ----------- ---------- ---------- ---------------- ----- --------
(dth)
<S> <C> <C> <C> <C> <C> <C>
1. 70087 ALGONQUIN - LAMBERTVILLE, 32,616 AS REQUESTED TX EAST TX EAST ALGONQUIN
NJ HUNTERDON CO., NJ BY CUSTOMER, TRAN TRAN
NOT TO
EXCEED 750
PSIG
2. 71078 ALGONQUIN - HANOVER, NJ 32,616 AS REQUESTED TX EAST TX EAST ALGONQUIN
MORRIS CO., NJ BY CUSTOMER, TRAN TRAN
NOT TO
EXCEED 750
PSIG
3. 79513 SS-1 STORAGE POINT 25,382 N/A N/A N/A N/A
04/01-10/31
25,382
11/01-03/31
4. 79818 AGT-BOSTON 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 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 #: 800286R1
EXHIBIT B, POINT(S) OF DELIVERY (Continued)
BOSTON GAS COMPANY
AGGREGATE MAXIMUM DAILY
POINT OF DELIVERY DELIVERY OBLIGATION (DTH)
----------------- -------------------------
No. 1 177,070
No. 2 66,560
No. 3 25,382
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ JMM (Initials)
------------------------------
CUSTOMER: /s/ W. R. Luthern
------------------------------
SUPERSEDES EXHIBIT A DATED: ____________
/s/ ED (Initials)
B-2
<PAGE>
Contract #800286R1
EXHIBIT C, ZONE BOUNDARY ENTRY QUANTITY AND ZONE BOUNDARY EXIT QUANTITY,
DATED 10/29/99, TO THE SERVICE AGREEMENT UNDER RATE SCHEDULE CDS
BETWEEN TEXAS EASTERN TRANSMISSION CORPORATION ("PIPELINE") AND
BOSTON GAS COMPANY ("CUSTOMER"), DATED 10/29/99:
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
- --------------------------------------------------------------------------------------------------------------------
ETX 4284 1400
- --------------------------------------------------------------------------------------------------------------------
WLA 39
- --------------------------------------------------------------------------------------------------------------------
ELA 27422
- --------------------------------------------------------------------------------------------------------------------
M1-24 4284
- --------------------------------------------------------------------------------------------------------------------
M1-30 27422
- --------------------------------------------------------------------------------------------------------------------
M1-TXG 1439
- --------------------------------------------------------------------------------------------------------------------
M1-TGC
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2 32616
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
C-1
<PAGE>
Contract #800286R1
EXHIBIT C (Continued)
BOSTON 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 4284
- --------------------------------------------------------------------------------------------------------------------
M1-30 27422
- --------------------------------------------------------------------------------------------------------------------
M1-TXG 1439
- --------------------------------------------------------------------------------------------------------------------
M1-TGC
- --------------------------------------------------------------------------------------------------------------------
M2-24
- --------------------------------------------------------------------------------------------------------------------
M2-30
- --------------------------------------------------------------------------------------------------------------------
M2-TXG
- --------------------------------------------------------------------------------------------------------------------
M2-TGC
- --------------------------------------------------------------------------------------------------------------------
M2 32616
- --------------------------------------------------------------------------------------------------------------------
M3
====================================================================================================================
</TABLE>
SIGNED FOR IDENTIFICATION
PIPELINE: /s/ JMM (Initials)
------------------------------
CUSTOMER: /s/ W. R. Luthern
------------------------------
SUPERCEDES EXHIBIT C DATED: ____________
/s/ ED (Initials)
C-2
<PAGE>
Exhibit 10.36
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
This Agreement ("Agreement") is made and entered into this ___ day of October,
1999, by and between Algonquin Gas Transmission Company, a Delaware Corporation
(herein called "Algonquin"), and Boston Gas Company (herein called "Customer"
whether one or more persons).
WHEREAS, Customer desires Algonquin to transport natural gas for Customer's
account on a firm basis pursuant to the terms and conditions of Algonquin's Rate
Schedule AFT-1; and
WHEREAS, Algonquin and Customer desire to enter into this Service Agreement
under Rate Schedule AFT-1;
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:
For the period November 16 through the following March 15 of each year (or
March 14 in case of a leap year) during the term of this Agreement:
Maximum Daily Transportation Quantity 35,000 MMBtu; and
For the period March 16 (or March 15 in case of a leap year) through
November 15 of each year during the term of this Agreement:
Maximum Daily Transportation Quantity 0 MMBtu
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
1.2 Algonquin agrees to transport and deliver to or for the account of
Customer at the Point(s) of Delivery and Customer agrees to accept or
cause acceptance of delivery of the quantity received by Algonquin on any
day, less the Fuel Reimbursement Quantities; provided, however, Algonquin
shall not be obligated to deliver at any Point of Delivery on any day a
quantity of natural gas in excess of the applicable Maximum Daily Delivery
Obligation.
ARTICLE II
TERM OF AGREEMENT
2.1 This Agreement shall become effective on the later of November 1, 1999, or
the in-service date of the facilities authorized by the Commission in
Docket No. CP99-113-000, and shall continue in effect for a term of ten
(10) years ("Primary Term") and shall remain in force from year to year
thereafter unless terminated by either party by written notice one year or
more prior to the end of the Primary Term or any successive term
thereafter. However, Customer shall have the right to terminate such
agreement subject to twelve months prior written notice, on and after
October 31, 2007, or eight (8) complete service years, whichever is later.
Algonquin's right to cancel this Agreement upon the expiration of the
Primary Term hereof or any succeeding term shall be subject to Customer's
rights pursuant to Sections 8 and 9 of the General Terms and Conditions.
2.2 This Agreement may be terminated at any time by Algonquin in the event
Customer fails to pay part or all of the amount of any bill for service
hereunder and such failure continues for thirty days after payment is due;
provided Algonquin gives ten days prior written notice to Customer of such
termination and provided further such termination shall not be effective
if, prior to the date of termination, Customer either pays such
outstanding bill or furnishes a good and sufficient surety bond
guaranteeing payment to Algonquin of such outstanding bill; provided that
Algonquin shall not be entitled to terminate service pending the
resolution of a disputed bill if Customer complies with the billing
dispute procedure currently on file in Algonquin's tariff.
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE II
RATE SCHEDULE
3.1 Customer shall pay Algonquin for all services rendered hereunder and for
the availability of such service under Algonquin's Rate Schedule AFT-1 as
filed with the Federal Energy Regulatory Commission and as the same may be
hereafter revised or changed. The rate to be charged Customer for
transportation hereunder shall not be more than the maximum rate under
Rate Schedule AFT-1, nor less than the minimum rate under Rate Schedule
AFT-1.
3.2 This Agreement and all terms and provisions contained or incorporated
herein are subject to the provisions of Algonquin's applicable rate
schedules and of Algonquin's General Terms and Conditions on file with the
Federal Energy Regulatory Commission, or other duly constituted
authorities having jurisdiction, and as the same may be legally amended or
superseded, which rate schedules and General Terms and Conditions are by
this reference made a part hereof.
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.
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
ARTICLE V
POINT(S) OF DELIVERY
Natural gas to be delivered by Algonquin for the account of Customer hereunder
shall be delivered on the outlet side of the measuring station(s) at or near the
Primary Point(s) of Delivery set forth in Exhibit B of the service agreement,
with the Maximum Daily Delivery Obligation and the delivery pressure obligation
indicated for each such Primary Point of Delivery. Natural gas to be delivered
by Algonquin for the account of Customer hereunder may also be delivered at the
outlet side of any other measuring station on the Algonquin system, subject to
reduction pursuant to Section 6.4 of Rate Schedule AFT-1.
ARTICLE VI
ADDRESSES
Except as herein otherwise provided or as provided in the General Terms and
Conditions of Algonquin's FERC Gas Tariff, any notice, request, demand,
statement, bill or payment provided for in this Agreement, or any notice which
any party may desire to give to the other, shall be in writing and shall be
considered as duly delivered when mailed by registered, certified, or first
class mail to the post office address of the parties hereto, as the case may be,
as follows:
(a) Algonquin: Algonquin Gas Transmission Company
5400 Westheimer Court
Houston, TX 77056
(b) Customer: Boston Gas Company
One Beacon Street
Boston, MA 02108
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>
99012
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, except that in the case of conversions
from former Rate Schedules F-2 and F-3, the parties' obligations under Article
II of the service agreements pertaining to such rate schedules shall continue in
effect.
None
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
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/ PMT
Title: ___________________________
BOSTON GAS COMPANY
By: /s/ William R. Luthern
------------------------------
/s/ [ILLEGIBLE]
Title: Vice President
---------------------------
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit A
Point(s) of Receipt
Dated: _____________________, 1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Boston Gas Company (Customer)
concerning Point(s) of Receipt
Primary Maximum Daily Maximum
Point of Receipt Obligation Receipt Pressure
Receipt (MMBtu) (Psig)
-------- ------------------ ----------------
Dey Street 35,000 Algonquin's line pressure
Interconnect between 11/16 - 3/15 as may exist from time to
Algonquin and 0 time
Providence Gas Company 3/16 - 11/15
(by displacement only)
* In case of a leap year, the period during which the 35,000 MMBtu per day will
be in effect shall be reduced by one day to March 14, and the period during
which 0 MMBtu per day will be in effect shall be increased by one day so that
the specified period begins on March 15, 1999.
Signed for Identification
Algonquin: _________________________
/s/ JMM
Customer: /s/ W. R. Luthern
--------------------------
/s/ [ILLEGIBLE]
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-1)
Exhibit B
Point(s) of Delivery
Dated: _______________,1999
To the service agreement under Rate Schedule AFT-1 between
Algonquin Gas Transmission Company (Algonquin) and
Boston Gas Company (Customer)
concerning Point(s) of Delivery
Primary Maximum Daily Minimum
Point of Delivery Obligation Delivery Pressure
Delivery (MMBtu) (Psig)
-------- ------------------- -----------------
At Customer's reduction 12,961 75
valves located at:
Everett, MA
At the property line on the outlet 5,272 125
side of meter stations located at:
Waltham, MA
East Braintree, MA 6,738 125
Weston, MA 718 100
Wellesley, MA 8,914 60
Ponkapoag, MA 11,836 200
Norwood, MA 1,165 75
Potter Street 5,218 Algonquin's line
East Braintree, MA pressure
as may exist from
time to time
Algonquin's Maximum Daily Delivery Obligations for the East Braintree and Potter
Street Points of Delivery under Contract Nos. 93002CR, 93002ER and 99012 shall
not exceed a combined daily total equal to the aggregate of the former Maximum
Daily Delivery Obligations at the East Braintree Point of Delivery under Rate
Schedules AFT-1 (F-1) and AFT-E (F-1) in the amounts of 16,948 MMBtu and 5,238
MMBtu, respectively.
<PAGE>
99012
SERVICE AGREEMENT
(APPLICABLE TO RATE SCHEDULE AFT-l)
EXHIBIT B (continued)
Signed for Identification:
Algonquin: _________________________
/s/ JMM
Customer: /s/ W. R. Luthern
--------------------------
/s/ [ILLEGIBLE]
<PAGE>
Exhibit 10.37
[Tennessee Gas Pipeline Letterhead]
August 2, 1999
Boston Gas Company
One Beacon St.
Boston, Ma 02108
Attention: Mr. William R. Luthern via facsimile: (617) 742-0041
RE: CONTRACT RESTRUCTURING LETTER AGREEMENT
Dear Bill:
This Contract Restructuring Letter Agreement ("Letter Agreement") is
entered into by and between Tennessee Gas Pipeline Company ("Tennessee"), Boston
Gas Company ("Boston Gas") and Essex County Gas ("Essex") (Boston Gas and Essex
are referred to collectively as "Shippers"). Whereas, Tennessee, Boston Gas and
Essex (being hereinafter 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 Shippers 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 Shippers' 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
Shippers 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 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 2, 1999
Page 2
shall be increased by the like quantity so that the receipt quantity of
each Firm Agreement is thereby preserved.
As detailed below, Essex' decision regarding renewal of 100% of the
current MDQ on Essex' FT-A Agreement No. 8518 for a period of three years
impacts the allowable amendment percentage available to Shippers. The
table below briefly outlines the allowable amendment percentages by Firm
Agreement number:
K# 10/31/2003
-- ----------
Retain 100% of Firm Agreements 2062 15%
(Identified in Item 2 below)
Inclusive of FT-A Agreement 8518 8518 15%
Retain 100% of Firm Agreements 2062 15%
(Identified in Item 2 below)
Exclusive of FT-A Agreement 8518 8518 N/A
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 Zone 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 Shipper's amendment of the Firm Agreements as described in Item
1 above, Shippers 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: Boston
Firm Agreement Nos. 20241, 623, 2062, and 527; Essex Firm Agreement Nos.
577 and 2272. Each extension shall continue the Primary Extended Term as
outlined in Section 10.5. Unless otherwise expressly agreed by Tennessee,
as applicable, Shippers currently existing Maximum Daily Injection
Quantity, Maximum Daily Withdrawal Quantity and ratchet levels shall
remain in effect through the Primary Extended Term in each applicable Firm
Agreement.
<PAGE>
Contract Restructuring Letter Agreement
August 2, 1999
Page 3
At Essex' option, on or before September 30, 1999, Essex will submit a
rollover election pursuant to Article III, Section 10.5 of the General
Terms and Conditions of Tennessee's FERC Gas Tariff to extend up to 100%
of the current MDQ of Essex' FT-A Agreement 8518 for a period of three
years, such that the subsequent expiration date of the FT-A Agreement is
October 31, 2003. This extension shall constitute the Primary Extended
Term as outlined in Section 10.5.
In the event Essex elects by September 30, 1999 to extend 100% of the
current MDQ of the FT-A Agreement, Tennessee agrees to allow Essex to
amend its primary receipt zone in accordance with Tennessee's FERC Gas
Tariff as described in Item 1 above.
3. Rate
Subject to Shipper's amendment of the Firm Agreement as described in Item
1 above and to Shipper'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, Shippers 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, Shippers shall pay all
then-effective surcharges and applicable fuel. (The rates are therefore
fixed, but the surcharges and fuel charges are not).
Subject to Shipper's amendment of the Firm Agreements as described in Item
1 above and to Shipper's extension of the FS-MA Agreements as described in
Item 2 above and for the period commencing November 1, 1999 and extending
through the Primary Extended Term, Shippers 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, Shippers 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.
4. 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,
Shippers will submit an amendment request effective April 1, 2000 or
November 1, 2000 to amend approximately 5,945 Dth/d of receipt point
capacity on Boston Gas' FT-A Agreement No. 20241 and 807 Dth/d of receipt
point capacity on Essex's FTA Agreement No. 10788 from the National Fuel
Andrews Settlement receipt point (meter number 1-1693) to Tennessee
Northern Storage (meter number 7-0018).
<PAGE>
Contract Restructuring Letter Agreement
August 2, 1999
Page 4
5. 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.
Shippers 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.
If this Letter Agreement accurately represents your understanding of the
agreement among Tennessee and Shippers, please have the appropriate party
execute the facsimile copy of this Letter Agreement and return same to the
undersigned. Upon execution by Tennessee, I will fax two (2) fully executed
originals 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
<PAGE>
Contract Restructuring Letter Agreement
August 2, 1999
Page 5
AGREED TO AND ACCEPTED AGREED TO AND ACCEPTED
THIS 19TH DAY OF AUGUST, 1999, THIS 18TH DAY OF AUGUST, 1999,
TENNESSEE GAS PIPELINE BOSTON GAS COMPANY
COMPANY
By: /s/ Mary M. Melendez By: /s/ William R. Luthern
-------------------------------- ------------------------------
Name: Mary M. Melendez Name: William R. Luthern
-------------------------------- ------------------------------
Its: Agent and Attorney-in-Fact Its: Vice President
-------------------------------- ------------------------------
AGREED TO AND ACCEPTED
THIS 18TH DAY OF AUGUST, 1999,
ESSEX COUNTY GAS
COMPANY
By: /s/ William R. Luthern
--------------------------------
Name: William R. Luthern
--------------------------------
Its: Vice President
--------------------------------
<PAGE>
Exhibit 10.39
Execution Original
No. 2
AMENDED AND RESTATED LEASE AGREEMENT
INDUSTRIAL NATIONAL LEASING CORPORATION
Lessor
and
BOSTON GAS COMPANY
Lessee
Dated as of April 30, 1999
There are two fully executed originals of this Amended and Restated Lease
Agreement marked "Execution Original No. 1" and "Execution Original No. 2" in
the top right hand corner hereof, each of which originals is fully enforceable
by the parties hereto and their permitted successors and assigns, provided,
however, that only "Execution Original No. 1" shall be considered "chattel
paper" as defined in Chapter 106, Section 9-105(1)(b) of the Massachusetts
General Laws, as amended from time to time.
<PAGE>
AMENDED AND RESTATED LEASE AGREEMENT, dated as of April 30, 1999
("Lease"), between INDUSTRIAL NATIONAL LEASING CORPORATION, a Massachusetts
corporation (herein, together with any corporation succeeding thereto by
consolidation, merger or acquisition of its assets substantially as an entirety,
called "Lessor"), having an address c/o Fleet Capital Corporation, 50 Kennedy
Plaza, 5th Floor, Providence, Rhode Island 02903, and BOSTON GAS COMPANY, a
Massachusetts corporation (herein, together with any corporation succeeding
thereto by consolidation, merger or acquisition of its assets substantially as
an entirety, called "Lessee"), having an address at One Beacon Street, Boston,
Massachusetts 02108.
The parties hereto hereby agree that this Amended and Restated Lease
Agreement amends and restates in its entirety that certain Lease Agreement by
and between the Lessor and Massachusetts LNG Incorporated, a Massachusetts
corporation, and a wholly owned subsidiary of Lessee (herein "MLNG"), dated as
of June 1, 1972, as supplemented or amended from time to time (the "1972 Lease
Agreement"). The parties further agree that they are entering into this Lease to
make certain substantive changes to the 1972 Lease Agreement and enter into a
new lease term of fifteen (15) years from July 1, 1999 through June 30, 2014.
1. Lease. In consideration of the rents to be paid and the covenants to be
performed by Lessee pursuant hereto, Lessor leases to Lessee, and Lessee leases
from Lessor, the property consisting of (i) the Lessor's interest under the
Easement Agreements in the parcels of Land described in Schedule A hereto
(collectively the "Land Parcels" and individually each a "Land Parcel"), (ii)
the machinery, pipes, tanks, appliances, parts, instruments, valves, meters,
connections and accessories and other equipment constituting the two liquefied
natural gas facilities more particularly described in Schedule B hereto
installed in, on, upon, under or over
2
<PAGE>
the Land Parcels (such machinery, pipes, tanks, appliances, parts, instruments,
valves, meters, connections and accessories and other equipment herein, together
with all repairs and replacements thereof and modifications thereto, called the
"Equipment"), (iii) all foundations, dikes, pilings and buildings located on or
in the Land Parcels, and (iv) all other easements, rights and appurtenances
relating thereto.
2. Certain Definitions. (a) The term "Approved Lien" means any lien on or
security interest in the Leasehold Estates in connection with which the Lessee
has consented in writing to an assignment of Lessor's rights under this Lease.
(b) The term "Commonwealth Licenses" means the licenses issued by the
Commonwealth of Massachusetts permitting the respective owners of the Lynn Land
Parcel and the Salem Land Parcel to fill and build thereupon.
(c) The term "Easement Agreements" means the Lynn Easement Agreement and
the Salem Easement Agreement, collectively, and the term "Easement Agreement"
means either of the Easement Agreements, individually.
(d) The term "Ground Owner" means Lessee, as successor-in-interest to Lynn
Gas Company, as grantor, under the Lynn Easement Agreement or MLNG, as grantor,
under the Salem Easement Agreement, as the case may be, together with each such
grantor's successors and assigns.
(e) The term "Leased Properties" means the Lynn Leased Property and the
Salem Leased Property, collectively, and the term "Leased Property" means either
of the Leased Properties, individually.
3
<PAGE>
(f) The term "Leasehold Estates" means the estate, right, title and
interest of the Lessor in the Leased Properties, collectively, and the term
"Leasehold Estate" means either of the Leasehold Estates, individually.
(g) The term "Lessor's Cost" has the meaning set forth in Schedule C
hereto.
(h) The term "Lynn Easement Agreement" means the easement agreement dated
as of June 1, 1972 between Lynn Gas Company and Lessor covering the Lynn Land
Parcel, as amended by an Amendment to Declaration of Easement dated of even date
herewith, the rights and obligations of Lynn Gas Company under such easement
having been assumed by Lessee.
(i) The term "Lynn Land Parcel" means the Land Parcel located in Lynn,
Massachusetts.
(j) The term "Lynn Leased Property" means the property described in
clauses (i) through (iv) of paragraph 1 located in Lynn, Massachusetts,
excluding the Lynn Liquefaction Equipment, unless the Lynn Liquefaction
Equipment is expressly included for purposes of a particular term or provision
of this Lease.
(k) The term "Lynn Liquefaction Equipment" means that portion of the
"Equipment" (as such term was defined in the 1972 Lease Agreement) located on
the Lynn Land Parcel designed to convert (at a rate of 7.4 MMcf/day) pipeline
natural gas into liquid suitable for storage in liquefied natural gas storage
tanks, vessels, or carriers, including but not limited to, the liquefied natural
gas storage tank located on the Lynn Land Parcel.
(l) The term "Salem Easement Agreement" means the easement agreement dated
as of October 17, 1972 between MLNG and Lessor covering the Salem Land Parcel,
as amended by an Amendment to Declaration of Easement dated of even date
herewith.
4
<PAGE>
(m) The term "Salem Land Parcel" means the Land Parcel located in Salem,
Massachusetts.
(n) The term "Salem Leased Property" means the property described in
clauses (i) through (iv) in paragraph 1 located in Salem, Massachusetts.
(o) The term "Stipulated Loss Value" has the meaning set forth in Schedule
C hereto.
3. Term. Subject to the provisions of this Lease, Lessee shall have and
hold the Lynn Leased Property for a term beginning on June 1, 1972 and ending at
midnight on June 30, 2014 and the Salem Leased Property for a term beginning on
October 19, 1972 ("Second Closing Date") and ending at midnight on June 30,
2014.
4. Rent. Lessee covenants to pay to Lessor, at Lessor's address as set
forth above or at such other place or to such other person as Lessor may
designate, as rent ("Rent") for the Leased Properties in immediately available
funds (i) for the period commencing on the beginning date of the term of this
Lease and ending June 30, 1972 with respect to the Lynn Leased Property an
amount equal to 8.65% per annum of the Lessor's Cost of the Lynn Leased
Property, on July 1, 1972, (ii) for the period beginning on July 1, 1972 and
ending on December 31, 1972 with respect to the Lynn Leased Property an amount
equal to 3.72820% (subject to adjustment as may be mutually agreed upon by the
Lessor and the Lessee from time to time, provided, however, in no event shall
such adjustment result in an amount less than $392,000.00) of Lessor's Cost of
the Lynn Leased Property, on July 1, 1972, (iii) for the period commencing on
the Second Closing Date and ending on December 31, 1972 with respect to the
Salem Leased Property (in the event that this Lease shall be supplemented by a
Lease Supplement to include the Salem Leased Property) an amount equal to
3.83355% (subject to adjustment as may be
5
<PAGE>
mutually agreed upon by the Lessor and the Lessee from time to time, provided,
however, in no event shall such adjustment result in an amount less than
$179,000.00) of Lessor's Cost of the Salem Leased Property less an amount for
the period commencing July 1, 1972 and ending on the Second Closing Date equal
to 8.25% per annum of the Lessor's Cost of the Salem Leased Property, on the
Second Closing Date, (iv) for the period beginning January 1, 1973 and ending
June 30, 1997 with respect to the Lynn Leased Property and (in the event that
this Lease shall be supplemented by a Lease Supplement to include the Salem
Leased Property) the Salem Leased Property an amount equal to 3.76053% (subject
to adjustment as may be mutually agreed upon by the Lessor and the Lessee from
time to time, provided, however, in no event shall any such adjustment result in
the payment of any installment of Rent payable during the term of this Lease of
less than $392,00.00 (in the event that this Lease shall not be supplemented by
a Lease Supplement to include the Salem Leased Property) or $571,000.00 (in the
event that the Lease shall be so supplemented)) of Lessor's Cost of the Lynn
Leased Property, and (in the event that this Lease shall be supplemented by a
Lease Supplement to include the Salem Leased Property) the Salem Leased Property
in advance on January 1, 1973 and on the first day of each July and January
thereafter to and including January 1, 1997, (v) for the period July 1, 1997
through June 30, 1999 the amount of $2,346,216, due and payable on the date
hereof by Lessee (which amount, together with an additional payment of
$1,500,000 from the Lessee is being paid to Lessor contemporaneously with the
execution of this Lease, as additional consideration for Lessor's willingness to
enter into an additional lease term of fifteen (15) years from July 1, 1999
through June 30, 2014 in accordance with the terms hereof, provided, however,
that such amounts shall constitute an irrevocable payment by Lessee on the date
of this Lease, and Lessee
6
<PAGE>
shall have no claim for any credit for such amounts if this Lease is terminated
prior to June 30, 2014 pursuant to paragraphs 14, 15, 17 or 21 hereof), (vi) for
the period July 1, 1999 through June 30, 2002, six (6) consecutive, equal,
semi-annual installments of Rent in advance in the amount of $586,544 each,
commencing with a semi-annual payment on July 1, 1999, and continuing on the
first day of each July and January thereafter to and including January 1,2002,
and (vii) for the period July 1, 2002 through June 30, 2014, twenty-four (24)
consecutive, equal, semi-annual installments of Rent in advance in the amount of
$792,000 each, commencing with a semi-annual payment on July 1, 2002, and
continuing on the first day of each July and January thereafter to and including
January 1, 2014 (collectively all of the foregoing dates for payment of Rent are
referred to as "Rent Payment Dates"). Lessee agrees to pay, upon demand,
interest of 9.25% per annum on all overdue installments of Rent, from the due
date thereof until paid in full.
5. Other Charges. Lessee covenants to pay when and as the same shall
become due and payable without a penalty, all amounts which Lessee has herein
assumed or agreed to pay and every fine, penalty, interest and cost which may be
added thereto for non-payment or late payment thereof. Lessee may pay such
amounts directly to the persons entitled thereto and Lessor agrees to give
Lessee prompt notice of the receipt by Lessor of notice of the failure to make
any such payment. In case of any failure by Lessee to pay any such amount,
Lessor shall have all the same rights, powers and remedies provided for herein
or by law as in the case of failure to pay Rent.
6. Taxes; Compliance with Law. (a) Lessee shall, subject to the provisions
of subparagraphs 6(b) and 20(b), pay, indemnify and hold harmless the Lessor
against all taxes, assessments, fees, utility charges and rents, excises,
levies, license fees, permit fees, inspection
7
<PAGE>
fees and other governmental and similar charges (herein called "Impositions"),
general or special, ordinary or extraordinary, foreseen or unforeseen, of every
character, which may be levied or assessed against, or imposed on or in respect
of(i) the Leased Properties or the Leasehold Estates or any portion of either
thereof, (ii) Rent or any other amounts payable by Lessee hereunder, (iii) this
Lease or the Leasehold Estates hereby created, (iv) the possession, use or
occupancy, installation, construction, maintenance, repair, renewal or
modification of the Leased Properties or any portion thereof or (v) the gross
receipts received by the Lessee from the Leased Properties or the earnings
arising from the use or occupancy thereof, or which arise in respect of the use
or occupancy of the Leased Properties or any part thereof. If any Imposition may
be paid in installments, Lessee shall have the option to pay such Imposition in
installments except that each installment thereof, and any interest thereon,
must be paid prior to the expiration of the term of this Lease in effect on the
date of such levy or assessment. Lessor shall send to Lessee all bills or other
communications which it may receive with respect to the Impositions. Lessor
agrees that it will assist Lessee, upon at least 10 days' written notice, in
taking such lawful and reasonable steps, as may be proposed by Lessee, at
Lessee's cost and expense, to minimize the Impositions which are payable by
Lessee pursuant to this paragraph 6. All Impositions for the tax year in which
this Lease shall terminate or expire shall be apportioned between Lessor and
Lessee and the obligation of Lessee to pay the portion of the Impositions
allocated to the Lessee shall survive the expiration or earlier termination of
this Lease.
(b) Nothing in this paragraph 6 shall require the payment by Lessee of (i)
any franchise, corporate, estate, inheritance, succession, transfer, income,
profits or revenue taxes of Lessor, unless such tax is in lieu of or a
substitute for any other tax or assessment upon or with
8
<PAGE>
respect to the Leased Properties which, if such other tax or assessment were in
effect, would be payable by Lessee hereunder, except that, the net extra
Massachusetts tax cost payable by Lessor in any fiscal year (based upon tax
statutes in effect with respect to such fiscal year) by reason of the fact that
Lessor is a corporation rather than a Massachusetts trust with transferable
shares will be paid by Lessee or (ii) any sales taxes incurred as a result of
any sale of the Leased Properties (except any sale to Lessee), the Leasehold
Estates or any portion of either thereof by Lessor.
(c) Subject to the provisions of subparagraph 20(b), Lessee shall (i)
cause the Leased Properties to comply with all applicable legal requirements,
including any which require structural or extraordinary changes, and (ii)
procure, maintain and comply with all permits, licenses and other authorizations
required for any use of the Leased Properties or any part thereof then being
made, and for the proper erection, installation, operation and maintenance of
any building, structure or other improvement on the Leased Properties or any
part thereof, and comply with any instruments of record at the time in force
during the term of this Lease affecting the Leased Properties or any part
thereof. Lessor agrees to cooperate at the expense of the Lessee in making all
such filings or in taking such other steps as may be required on the part of
Lessor to comply with all such legal requirements.
(d) Lessee shall furnish to Lessor, within 30 days after demand by Lessor,
proof of the payment of any Imposition payable by Lessee pursuant to this
paragraph 6.
7. Net Lease: No Counterclaim or Abatement. (a) This is a net lease, and
the Rent and all other sums payable by Lessee hereunder shall, except as
otherwise expressly provided in this Lease, be paid without counterclaim,
setoff, deduction or defense and without abatement, suspension, deferment,
diminution or reduction, provided that, without in any way limiting the
9
<PAGE>
foregoing, this provision shall not constitute a waiver of any other rights
Lessee may have by law.
(b) Except as otherwise expressly provided in this Lease, this Lease shall
not terminate, nor shall Lessee have any right to terminate this Lease or to be
released, relieved or discharged from any obligations or liabilities under this
Lease for any reason, including, without limitations: (i) any damage to or
destruction, theft or loss of all or part of either Leased Property; (ii) any
confiscation, condemnation, requisition or other taking of all or part of either
Leased Property; (iii) any limitation, restriction, deprivation (including
eviction) or prevention of, or any interference with, any use or possession of
all or part of either Leased Property; (iv) Lessee's acquisition of ownership of
all or part of either Leased Property or either Leasehold Estate; (v) any
default or other action, omission or breach by Lessor under this Lease or any
other agreement to which Lessor and Lessee may be parties; (vi) any claim as a
result of any other business dealings of Lessor and Lessee; (vii) the breach of
any warranty of any seller or any manufacturer of any Equipment; (viii) the
expiration or termination of or any default under either Easement Agreement;
(ix) the inadequacy, incorrectness or failure of the description of either
Leased Property or any portion thereof to demise and let the property intended
to be so leased hereby; (x) the impossibility of performance by Lessor or Lessee
or both; (xi) any action or threatened or pending action of any court,
administrative agency or other governmental authority; (xii) any defect or
failure in Lessor's title to or ownership of the Leased Properties; (xiii) the
dismantling and disposal of the Lynn Liquefaction Equipment as contemplated by
subparagraph 8(d) hereof; or (xiv) any other cause, whether similar or
dissimilar to the foregoing, any present or future law to the contrary
notwithstanding, it being the intention of the parties
10
<PAGE>
hereto that the Rent, and all other sums payable by Lessee hereunder shall be
payable in all events and that the obligations of Lessee hereunder shall be
separate and independent covenants and shall continue unaffected unless
otherwise expressly provided in this Lease, provided that, without in any way
limiting the foregoing, this provision shall not constitute a waiver of any
other rights Lessee may have by law.
(c) Lessee covenants that it will remain obligated under this Lease in
accordance with its terms and will take no action (except in accordance with the
provisions of paragraphs 14, 15, 17 and 18 of this Lease) to terminate, rescind
or avoid this Lease for any reason, notwithstanding the bankruptcy, insolvency,
reorganization, composition, readjustment, liquidation, dissolution, winding up
or other proceeding affecting Lessor or either Ground Owner or any assignee of
any of them or any action which may be taken with respect to this Lease by any
trustee or receiver of Lessor or either Ground Owner or of any assignee of any
of them, or by any court, provided that, without in any way limiting the
foregoing, this provision shall not constitute a waiver of any other rights
Lessee may have by law. Except as expressly provided herein, Lessee waives all
rights which may at any time exist to quit, terminate or surrender this Lease or
all or part of either Leased Property or to any abatement, deferment, diminution
or reduction of the Rent or other sums payable under this Lease, provided that,
without in any way limiting the foregoing, this provision shall not constitute a
waiver of any other rights Lessee may have by law.
8. Title and Condition of Leased Properties. (a) The properties described
in clauses (i), (iii) and (iv) of paragraph 1 located in Lynn, Massachusetts and
Salem, Massachusetts and constituting part of the Lynn Leased Property and Salem
Leased Property, respectively, are leased subject to (i) the rights of any
parties in possession, and the existing state of the title as of
11
<PAGE>
the commencement of the term of this Lease, (ii) all applicable legal
requirements hereafter in effect and (iii) all the terms and conditions of the
Easement Agreements, without representation or warranty by Lessor. Lessee has
examined the title to the Land Parcels and has found the same satisfactory. All
rights, powers and privileges granted to Lessee under this Lease are subject to
the provisions of the Easement Agreements, and no such right, power or privilege
may be exercised or enjoyed by Lessee, and no provision or condition of this
Lease shall be operative, if and to the extent that such exercise or enjoyment
would not be permitted by, or would violate any provision of, the Easement
Agreements.
(b) Lessee acknowledges, as of the date hereof with respect to each Leased
Property, delivery of possession of the Equipment constituting a portion of such
Leased Property to it and its acceptance and possession thereof hereunder.
Lessor makes no warranty or representation, express or implied or otherwise, in
respect of such Equipment. The Equipment is leased "as is" and Lessor does not
warrant that such Equipment is of merchantable quality or that it is fit for any
particular purpose. Lessee acknowledges that as of the date hereof it has
examined such Equipment and Lessor's title thereto and has found that same
satisfactory. So long as this Lease shall be in effect and no Event of Default
shall have occurred and be continuing, Lessor agrees that Lessee shall have the
right to enforce all warranties of the manufacturers of such Equipment and any
claims which Lessor may have against such manufacturers with respect to such
Equipment. Without in any way limiting the foregoing provision which indicates
that the Equipment is leased "as is", Lessor hereby acknowledges to Lessee that,
based solely on Lessor's actual knowledge, the Equipment (other than the Lynn
Liquefaction Equipment) is, as of the date of this Lease, in the condition
required under paragraph 10 of this Lease. The foregoing sentence
12
<PAGE>
relates to the condition of the Equipment (other than the Lynn Liquefaction
Equipment) as of the date of this Lease and shall not in any way limit Lessor's
ability to notify Lessee of the occurrence of an Event of Default and enforce
its remedies under this Lease if the Equipment (other than the Lynn Liquefaction
Equipment) is not maintained as required under paragraph 10 hereof after the
date of this Lease.
(c) Title to the Equipment shall at all times remain in Lessor and at no
time shall title to the Equipment become vested in Lessee, except in accordance
with the provisions hereof. This is a lease only, and shall not give Lessee any
estate, right, title or interest in or to the Equipment, except the right to use
the same in accordance with the provisions hereof.
(d) Lessee has requested that Lessor permit Lessee to dismantle and
dispose of the Lynn Liquefaction Equipment. Lessor hereby consents to Lessee's
dismantling and disposal of the Lynn Liquefaction Equipment subject however to
all of the terms and provisions of this subparagraph 8(d), the terms and
provisions of paragraph 18 hereof if Lessee exercises its end of term purchase
option, and the terms and provisions of paragraph 25 hereof if Lessee elects to
surrender the Leased Properties to Lessor at the end of the term of this Lease.
In furtherance of the foregoing, Lessor and Lessee agree that within 120 days
after the date of this Lease, Lessee at its sole cost and expense, shall arrange
for the dismantling and disposal of the Lynn Liquefaction Equipment, such
dismantling and disposal to be completed as promptly as possible and in
accordance with all governmental requirements and consistent with prudent
industry practices. In order to induce Lessor to consent to Lessee's dismantling
and disposal of the Lynn Liquefaction Equipment, Lessee hereby agrees to
indemnify Lessor from any and all liabilities incurred, or for which a claim is
made against Lessor, in connection with the dismantling and
13
<PAGE>
disposal of the Lynn Liquefaction Equipment, including, by way of illustration
and without limitation, any and all Impositions, environmental claims or
personal injury claims. The costs and expenses incurred by Lessee in dismantling
and disposing of the Lynn Liquefaction Equipment will be the sole responsibility
of Lessee and will be paid promptly by Lessee. The net salvage proceeds, if any,
from the dismantling and disposal of the Lynn Liquefaction Equipment will be
retained by Lessee. Lessor has agreed to allow Lessee to dismantle and dispose
of the Lynn Liquefaction Equipment with the express understanding that Lessor's
willingness to permit such dismantling and disposal shall in no way limit or
adversely effect: (a) Lessor's claim for the payment of a Return Adjustment
Amount, if any, as calculated under paragraph 25 hereof if the Leased Properties
are surrendered to Lessor at the end of the term of this Lease; or (b) Lessor's
right to determination of the fair market sales value of the Leased Properties
under paragraph 18 hereof as if the Lynn Liquefaction Equipment was existing on
the Lynn Land Parcel and maintained in good operating order at the time the
purchase option is exercised. Until such time as the Lynn Liquefaction Equipment
is dismantled, disposed of and removed from the Lynn Land Parcel, the Lynn
Liquefaction Equipment will be deemed to be part of the Leased Properties for
purposes of paragraphs 12, 14, 15 and 16 hereof, and Lessor shall be entitled to
receive any net condemnation or net insurance proceeds arising out of a
condemnation or casualty involving the Lynn Liquefaction Equipment. Further,
Lessee agrees and acknowledges that the Lynn Liquefaction Equipment will be
deemed to be part of the Leased Properties for purposes of paragraphs 6 and 13
of this Lease for all claims or liabilities which accrue, arise or in any way
relate to the period prior to the dismantling and disposal of the Lynn
Liquefaction Equipment.
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<PAGE>
9. Use of Leased Properties. (a) Lessee may occupy and use the Leased
Properties or either of them for any lawful purpose. Lessee may at any time
discontinue the use of the Leased Properties or either of them provided that
Lessee complies with the provisions of paragraph 10.
(b) Lessor does not make any representations concerning title to the
Leased Properties, and the failure of Lessor's title to all or any part of the
Leased Properties shall not diminish the Rent, additional rent or any other sums
required to be paid by Lessee hereunder.
(c) If and so long as Lessee shall observe and perform all covenants,
agreements and obligations required by it to be observed and performed
hereunder, any mortgage, security interest or other lien placed on either Leased
Property by Lessor shall be subject to this Lease and the rights of Lessee
hereunder.
10. Maintenance, Modifications and Additions. (a) Lessee will maintain the
Leased Properties in good operating condition and will make all necessary
repairs, replacements and renewals thereof, whether ordinary or extraordinary,
foreseen or unforeseen. Lessee shall be entitled to the salvage value, if any,
of any items of Equipment which have been replaced pursuant to this paragraph in
connection therewith. Lessor shall not be required to make any repairs,
replacements or renewals whatsoever of the Leased Properties. All repairs,
replacements and renewals of the Leased Properties shall be the property of
Lessor and constitute part of the applicable Leased Property for all purposes of
this Lease, shall be made in a good and workmanlike manner and in compliance
with all applicable legal requirements and insurance policies and shall be free
and clear of all liens and encumbrances except any Approved Lien.
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<PAGE>
(b) Lessee may make modifications of and additions to either Leased
Property or any part thereof, provided that the value of such Leased Property
shall not be materially impaired thereby and such Leased Property may be
operated without impairment (and all service contracts with customers fulfilled)
independent of any such addition. All modifications of a Leased Property shall
be the property of Lessor and shall constitute part of such Leased Property for
all purposes of this Lease. All additions to a Leased Property shall be the
property of the owner thereof and shall not become property of Lessor or
constitute part of such Leased Property. All modifications and additions shall
be made in good and workmanlike manner and in compliance with all applicable
legal requirements and insurance policies and all modifications shall be free
and clear of all liens and encumbrances (except any Approved Lien).
(c) Lessee may install, place or erect upon the Leased Properties any
machinery, furniture, trade fixtures or other personal property, and all such
personal property (but not property which is or shall become the property of
Lessor pursuant to subparagraph 10(a) or 10(b)), installed, placed or erected on
the Leased Properties by Lessee (including any additions to the Leased
Properties), whether or not attached to a Leased Property, may be removed by
Lessee or the owner thereof at any time, and all such property shall be and
remain the property of the owner thereof and shall not become the property of
Lessor or part of such Leased Property; provided, that in removing any such
property, Lessee or such owner shall repair all damage caused by such removal
and restore such Leased Property to good condition and provided further, that
the fair market value of such Leased Property will not be thereby lessened and
such removal will not impair the operation of such Leased Property. Lessee or
the owner of such personal property may encumber such personal property at any
time and from time to time, and
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Lessor, at the request of Lessee and at Lessee's expense, will from time to time
execute and deliver, or use its best efforts to cause to be executed and
delivered, to the holder or holders of any such encumbrance any instrument
reasonably requested by Lessee or any such holder which has the legal effect
of(i) waiving any right or claim of Lessor or the holder of any mortgage or
other encumbrance created by Lessor in and to such personal property and (ii)
permitting the holder or holders of such encumbrance to enter upon the Leased
Property for the purpose of removing such personal property in accordance with
the terms of this Lease or protecting its interest in such property. The
provisions of this subparagraph 10(c) shall survive the expiration or earlier
termination of this Lease.
11. Equipment to Remain Personal Property. The parties agree that the
Equipment is personal property, and that at no time shall the Equipment become a
part of any real estate or a fixture thereto or thereon and the Equipment shall
remain personal property notwithstanding any law or custom or the provisions of
any lease, mortgage, deed to secure debt, security agreement or other instrument
applicable to such real estate.
12. Liens. Subject to the provisions of subparagraph 20(b), Lessee will
remove and discharge all liens, encumbrances and charges upon the Leased
Properties other than this Lease, the Easement Agreements, or any lien,
encumbrance or charge existing on the date of execution and delivery of this
Lease or created by, or resulting from, any act or omission of Lessor or any
person claiming by or through Lessor.
13. Indemnification by Lessee. (a) Lessee covenants to pay, and to
protect, indemnify and hold Lessor harmless from and against, all liabilities,
losses, damages, costs, expenses (including, without limitation, attorneys' fees
and expenses), claims, demands or
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judgments arising from (i) injury to or the death of any person or damage to
property on, or growing out of or connected with the occupancy, use or condition
of, either Leased Property, (ii) violation of any provisions of this Lease,
(iii) violation by Lessee of any contract or agreement to which Lessee is a
party or of any restriction or legal requirement, in each case affecting either
Leased Property or the ownership, occupancy or use thereof, or (iv) any contest
permitted by subparagraph 20(b). The obligations and liabilities of Lessee under
this subparagraph 13(a), actual or contingent, which arise on or before the
expiration or earlier termination of this Lease, shall survive the expiration or
earlier termination of this Lease.
(b) Lessor shall notify Lessee in writing within 20 days after Lessor
shall have received notice of any claim against Lessor in respect of which such
indemnity may be sought. The omission of Lessor so to notify Lessee of any such
claim shall relieve Lessee from any liability which it may have to Lessor on
account of the indemnity agreement contained in this paragraph 13 (unless Lessee
shall have had actual knowledge of such claim within or prior to such 20 day
period) but only if Lessor shall have actually received notice of such claim,
and, if Lessor shall have received notice of such claim, only to the extent that
such failure to notify Lessee shall adversely affect Lessee's rights with
respect to such claim. In case any such claim shall be made against Lessor,
Lessee shall be entitled to participate in (and, to the extent that it shall
wish, to direct) the investigation of or defense against such claim, or both, at
Lessee's own expense. The agreement contained in this paragraph 13 covers only
costs, expenses, claims, losses, damages or liabilities to which Lessor, either
Leased Property or either Leasehold Estate may become subject by virtue of
applicable law; and it does not cover any situation where the cost, expense,
loss, claim, damage or liability results from any consent or admission on the
part
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of Lessor or a voluntary payment or settlement by Lessor without written consent
of Lessee. Notice by publication or filing shall not, for purposes of this
subparagraph 13(b), be deemed to constitute actual receipt of notice by Lessor.
Lessor agrees, at the request and expense of Lessee, to cooperate in the making
of the investigation and defense of any claim and to assert any or all of the
rights and privileges and defenses which may be available to Lessor.
14. Condemnation. (a) Subject to the rights of Lessee hereinafter set
forth in this paragraph 14, Lessee hereby assigns to Lessor any award to which
Lessee may become entitled by reason of any condemnation, requisition or other
taking of either Leased Property or any portion thereof by any governmental
authority. Lessee may, subject to the approval of Lessor, appear on behalf of
Lessor in any such proceedings to negotiate, accept, file and prosecute any
claim for any such award, and to collect and receipt for any such award.
Notwithstanding any other provision of this paragraph 14, awards referred to in
this paragraph 14 for which a specific application is provided in the Easement
Agreement relating to such Leased Property (other than a payment over to the
grantee thereunder) shall be applied as herein provided. Lessee shall pay all
fees, costs and other expenses which may become payable as a result of or in
connection with the subject matter of this paragraph 14. The entire award, if
any, less any expenses incurred by Lessor in collecting such award is herein
called the "Net Award."
(b) If (i) the Leased Properties, or either of them (the "Taken Property")
or any portion thereof is condemned or taken or permanently requisitioned, in or
by condemnation or other action of a governmental authority, or any governmental
authority issues any order or decree requiring the termination of the operations
then being conducted by Lessee on the Taken Property, or (ii) less than the
entire Taken Property shall have been so condemned, taken or
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requisitioned or the operations then being conducted by Lessee thereon shall
have been so ordered to be reduced and Lessee shall determine that the Taken
Property as a result thereof is unsuitable for continued use in the business
operations of Lessee, then Lessee shall, within 120 days after such occurrence,
give notice to Lessor of Lessee's intention to either terminate this Lease with
respect to the Taken Property only or to terminate this Lease in its entirety.
Such notice shall (i) specify a termination date occurring at least 60 days
after the date on which such notice is given, (ii) contain a certification by
the president or a vice president of Lessee that the conditions precedent to
such termination have occurred, and (iii) contain the irrevocable offer of
Lessee to purchase the Leasehold Estate with respect to the Taken Property or
both Leasehold Estates, as the case may be, and the Net Award, if any, on such
termination date, at the purchase price therefor determined, subject to the
provisions of paragraph 17 to be the Stipulated Loss Value in accordance with
Schedule C. If Lessor shall reject such offer to purchase by notice given to
Lessee not later than the 40th day prior to such termination date, this Lease
shall terminate as to the Leased Property with respect to the Taken Property or
in its entirety as the case may be, on such termination date, except with
respect to obligations and liabilities of Lessee under this Lease, actual or
contingent, which have arisen on or prior to such date. The failure by Lessor to
accept or reject such offer on or before the 40th day prior to such termination
date shall constitute the acceptance by Lessor of such offer. Upon any partial
termination of this Lease, Lessor will execute any instruments deemed necessary
by Lessee to evidence such partial termination. If Lessor shall have accepted
such offer to purchase, Lessor shall, on such termination date, transfer and
convey the remaining portion of the Leasehold Estate with respect to the Taken
Property or both Leasehold Estates, as the case may be, if any, to Lessee or its
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designee upon the terms and provisions of paragraph 17, and Lessor shall assign
to Lessee or its designee all of its right, title and interest in and to the Net
Award, against payment by Lessee of the purchase price therefor as set forth
above, together with all installments of Rent payable up to and including the
day prior to such termination date and all other sums then due and payable under
this Lease to and including such termination date. In the event of the partial
or entire termination of this Lease pursuant to this subparagraph (b), and if
Lessee shall have purchased the Leasehold Estate with respect to the Taken
Property or both Leasehold Estates, as the case may be, pursuant to this
subparagraph (b) and Lessor shall have received the said purchase price
therefor, Lessee or its designee shall be entitled to the entire Net Award. In
the event of the termination of this Lease pursuant to this subparagraph (b),
and if Lessee shall not have purchased the Leasehold Estate with respect to the
Taken Property or both Leasehold Estates, as the case may be, pursuant to this
subparagraph (b), Lessor shall be entitled to the entire Net Award.
(c) Upon any temporary requisition of the Taken Property or after any
other occurrence of the character described in subparagraph 14(a), if Lessee
shall not be required by subparagraph 14(b) to give notice of termination or if
Lessee does not make a determination of the character referred to in
subparagraph 14(b) within the time permitted by subparagraph 14(b), then (i)
this Lease shall continue in effect without abatement of any Rent or other
amounts payable by Lessee hereunder and (ii) Lessee shall, promptly after any
such occurrence (A) repair and restore the Taken Property in conformity with the
requirements of paragraph 10, to the extent necessary and practicable to restore
the Taken Property to the condition and market value thereof immediately prior
to such occurrence, subject (in the case of a temporary requisition) to ordinary
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wear and tear, or (B) with respect to the Equipment, replace any condemned,
requisitioned or taken Equipment with other equipment of similar type having a
fair market value and estimated useful life of not less than that of the
replaced Equipment immediately prior to such occurrence. Lessee shall be
entitled to receive the Net Award payable in connection with any such taking,
but such payment shall be made only against certificates of Lessee, signed by
the president or a vice president of Lessee, delivered to Lessor from time to
time as such repair, restoration and replacement progresses or is completed,
each such certificate (i) describing such repair, restoration and replacement
for which Lessee is requesting payment, (ii) the cost incurred by Lessee in
connection therewith, (iii) stating that Lessee had not theretofore received
payment for such repair, restoration and replacement and (iv) stating that as of
the date thereof there does not exist an Event of Default or any event which but
for the further requirement that notice be given or time elapse, or both, would
constitute an Event of Default. If there shall have been a temporary
requisition, or if any other occurrence described in this subparagraph 14(c)
shall have happened, any proceeds of such Award remaining after the final
payment has been made for such repair, restoration and replacement shall be
retained by Lessor and Lessor shall promptly notify Lessee of the amount of such
remaining proceeds, and thereafter (i) the Stipulated Loss Value Schedule for
the Taken Property shall be recalculated and reduced by the amount of such
proceeds so retained by Lessor and (ii) each installment of Rent payable during
the term of this Lease on and after the first Rent Payment Date occurring six
months or more after the notification by Lessee to Lessor of the completion of
such repair, restoration or replacement shall be reduced by an amount determined
by multiplying the Rent by a fraction, the numerator of which fraction shall be
the amount of such proceeds so retained by Lessor and the denominator
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of such fraction shall be the Stipulated Loss Value of both Leasehold Estates on
the date of such final payment immediately prior to giving effect to said
recalculation and reduction of the Stipulated Loss Value Schedule. If the cost
of any repairs required to be made by Lessee pursuant to this subparagraph 14(c)
shall exceed the amount of such Net Award, the deficiency shall be paid by
Lessee. Pending the disbursement of the Net Award the same shall, if Lessee so
elects, be invested and reinvested in (i) obligations issued or guaranteed by
the United States or by any person acting as an instrumentality of the United
States, provided that such obligations are rated for investment purposes at not
less than "A" by Moody's Investors Service or Standard & Poor's Corp., (ii)
commercial or finance company paper that is rated "prime" by the National Credit
Office; (iii) bankers acceptances drawn on and accepted by, or certificates of
deposit issued by, any bank or trust company having total assets in excess of
$25,000,000; or (iv) repurchase agreements fully secured by any of the
foregoing. Such investments shall be made by Lessor as directed and designated
by Lessee and approved by Lessor, which approval shall not be unreasonably
withheld. Income from such investments shall become part of the Net Award.
(d) For the purposes of this Lease, all amounts payable pursuant to any
agreement with any condemning authority which has been made in settlement of or
under threat of any condemnation or other eminent domain proceedings affecting
the Leased Property shall be deemed to constitute an award made in such
proceeding.
15. Casualty. (a) If the Leased Properties or either of them (the "Damaged
Property") or any part thereof shall be damaged or destroyed by fire or other
casualty, and if the estimated cost of restoring, replacing and repairing the
same shall exceed $50,000, Lessee shall promptly notify Lessor thereof. Lessee
may, subject, in the event such estimated cost of restoring,
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replacing and repairing shall exceed $50,000, to the approval of the Lessor,
appear on behalf of Lessor to negotiate, accept, file and prosecute any claim
for any insurance proceeds or other payment, and to collect and receipt for any
such proceeds or payment, provided that Lessor may at its discretion, but at the
cost and expense of Lessee, join in any such claim.
(b) Without limiting the foregoing, if (i) the Damaged Property is totally
or substantially damaged or destroyed due to fire or other casualty and (ii)
Lessee shall determine that the Damaged Property is unsuitable for continued use
in the business operations of Lessee, then Lessee shall give notice to Lessor,
within 120 days after the occurrence of such damage or destruction, of Lessee's
intention to either terminate this Lease with respect to the Damaged Property
only or to terminate this Lease in its entirety. Such notice shall (i) specify a
termination date occurring at least 60 days after the giving of such notice by
Lessee, (ii) contain a certification by the president or a vice president of
Lessee that the conditions precedent to such termination have occurred, (iii)
contain the irrevocable offer of Lessee to purchase the Leasehold Estate with
respect to the Damaged Property or both Leasehold Estates, as the case may be,
on such termination date at a purchase price which shall equal the Stipulated
Loss Value thereof determined, subject to the provisions of paragraph 17, in
accordance with Schedule C. If Lessor shall reject such offer to purchase by
notice given to Lessee not later than the 40th day prior to such termination
date, this Lease shall terminate as to the Leased Property with respect to the
Damaged Property or in its entirety, as the case may be, on such termination
date, except with respect to obligations and liabilities of Lessee under this
Lease, actual or contingent, which have arisen on or prior to such date. The
failure by Lessor to accept or reject such offer on or before the 40th day prior
to such termination date shall constitute the acceptance by Lessor of such
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offer. Upon any partial termination of this Lease, Lessor will execute any
instruments deemed necessary by Lessee to evidence such partial termination. If
Lessor shall have accepted such offer to purchase, Lessor shall, on such
termination date, transfer and convey the Leasehold Estate with respect to the
Damaged Property or both Leasehold Estates, as the case may be, and pay over or
assign all rights to receive the proceeds of any insurance payable in connection
with such damage or destruction to Lessee or its designee upon the terms and
provisions set forth in paragraph 17, against payment by Lessee of the purchase
price therefor as set forth above, together with all installments of Rent
payable up to and including the day prior to such termination date and all other
sums then due and payable under this Lease to and including such termination
date.
(c) If Lessee shall not be required by subparagraph 15(b) to give notice
of termination or if Lessee does not make a determination of the character
referred to in subparagraph 15(b) within the time permitted by subparagraph
15(b), then (i) this Lease shall continue in effect without abatement of any
Rent or other amounts payable by Lessee hereunder, and (ii) Lessee shall,
promptly after any such occurrence (A) repair and restore the Damaged Property
in conformity with the requirements of paragraph 10, to the extent necessary and
practicable to restore the Damaged Property to the condition and market value
thereof immediately prior to such occurrence and (B) with respect to the
Equipment, replace any damaged or destroyed Equipment with other equipment of
similar type having a fair market value and estimated useful life of not less
than that of the replaced Equipment immediately prior to such occurrence. If the
entire amount of any insurance proceeds payable as a result of any damage or
destruction shall not exceed $50,000, then such proceeds shall be payable to the
Lessee. If the entire amount of
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designated by Lessee and approved by Lessor, which approval shall not be
unreasonably withheld. Income from such investments shall become part of such
insurance proceeds.
16. Insurance. (a) Lessee will, at its cost and expense, maintain
insurance of the following character:
(i) insurance against loss by fire and lightning and insurance
against risks customarily covered by extended coverage endorsements in
amount sufficient to prevent Lessor or Lessee from becoming a co-insurer
of any loss under the applicable policies, but in any event in amounts not
less than, as determined from time to time, the sum of the Stipulated Loss
Value of each Leasehold Estate;
(ii) General public liability insurance in an amount and of such
types then being carried by companies owning properties similar to each
Leased Property, but in any event at least
personal injury $100,000 each individual
$100,000 each occurrence
property damage $1,000,000 each occurrence
excess coverage $10,000,000
of above
provided that, so long as Lessee is, directly or indirectly, a wholly-owned
subsidiary of New England Electric System, Lessee will, at its own cost and
expense, maintain in addition thereto insurance on each Leased Property of such
other type or types and/or in such greater amount or amounts as are maintained
on each Leased Property on the date of the commencement of the term of this
Lease. Such insurance shall be written by companies of recognized financial
standing which are authorized to do an insurance business in Massachusetts. Such
insurance shall name as the insured parties thereunder Lessor and Lessee as
their interests may appear.
(b) Every insurance policy maintained pursuant to this paragraph 16 shall
bear an endorsement in favor of Lessor and loss proceeds under any such policy
shall be made payable to
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Lessor. Every such policy shall provide that the issuer thereof waives all
rights of subrogation against Lessor, any Ground Owner and such holder; that 10
days' prior written notice of cancellation shall be given to such holder and
that such insurance, as to the interest of such holder, shall not be invalidated
by an act or neglect of Lessor, Lessee or any Ground Owner, nor by any
foreclosure or any other proceedings or notices thereof relating to either
Leased Property, nor by any change in the title or ownership of either Leased
Property, nor by occupation of either Leased Property for purposes more
hazardous than are permitted by such policy.
(c) Lessee shall deliver to Lessor, promptly after execution and delivery
of this Lease, original or duplicate policies, or certificates of insurers,
evidencing all the insurance which is then required to be maintained by Lessee,
and Lessee shall, not later than 30 days prior to the expiration of any such
insurance, deliver other original or duplicate policies or certificates of the
insurers evidencing the renewal of such insurance.
(d) Lessee shall not obtain or carry separate insurance concurrent in form
or contributing in the event of loss with that required in this paragraph 16 to
be furnished by Lessee unless Lessor is included therein as a named insured,
with loss payable as in this Lease provided. Lessee shall immediately notify
Lessor whenever any such separate insurance is obtained and shall deliver to
Lessor the policy or policies or certificates evidencing the same.
17. Purchase by Lessee. (a) In the event of the purchase of either or both
Leasehold Estates and any Net Award by Lessee pursuant to any provision of this
Lease, Lessor, shall not be obligated to give any better title thereto than
existed at the commencement of the term of this Lease, (excluding any title to
the Lynn Liquefaction Equipment) and Lessee shall accept such title, subject,
however, to all liens, encumbrances, charges, exceptions and restrictions
attaching
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thereto after the commencement of the term of this Lease which have not been
created by any act or omission of Lessor or any person claiming by or through
Lessor, and to all applicable laws, rules, regulations, ordinances and
restrictions then in effect, but free of the Approved Lien and any other lien
created by act of the Lessor.
(b) On the date fixed for the purchase of either or both Leasehold Estates
and any Net Award by Lessee pursuant to any provision of this Lease, Lessee
shall pay to Lessor, in lawful money of the United States, at its address for
purposes of this Lease or at any other place in the United States designated by
Lessor, the purchase price therefor provided for herein, any Rent then due and
unpaid and all other sums then payable by Lessee pursuant to this Lease
(including amounts due to Lessor, if any, for any portion of the then calendar
year for the period from January 1 of such year to the date of purchase of
either or both Leasehold Estates pursuant to any provision of this Lease, in
connection with the subleasing or any comparable transaction of the Leased
Properties, as contemplated by paragraph 26 hereof, herein the "Partial Year
Payment"), and furnish to the Lessor the certificate of the Lessee described in
paragraph 23 hereof, and Lessor shall thereupon deliver to Lessee a bill of sale
and other appropriate instrument or instruments of transfer, assignment and
conveyance, with covenants against acts of Lessor, which shall transfer and
convey the title described in subparagraph 17(a). If the Partial Year Payment
cannot be calculated with certainty on the date fixed for purchase, Lessee shall
pay Lessor 100% of the estimated amount of the Partial Year Payment on the date
fixed for purchase, which estimate shall be based on the best available
information (including actual available data and projections). Within 30 days
after the date fixed for purchase, Lessee agrees to provide Lessor with final
data on which the Partial Year Payment can be calculated with certainty, and
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the parties hereto agree to make a final adjustment to the Partial Year Payment
based on such final data. All documents conveying title to Lessee will be held
by Lessor until the estimated or actual (if practicable) Partial Year Payment
and all other amounts set forth herein are paid to Lessor. Lessee shall also pay
all charges incident to such transfer, assignment and conveyance, including all
recording fees, title insurance premiums and federal, state and local taxes
(other than income, excess profits or franchise taxes attributable to any gain
realized by Lessor upon such transfer). Upon completion of such purchase, but
not prior thereto (regardless of the reason for any delay or inability to
complete such purchase which may occur in consummating such purchase and whether
or not such delay is due to the fault of Lessor or the inability to transfer,
assign and convey such title; provided, that if any such delay occurs, the
purchase, price payable by Lessee shall be computed as of the actual date of
such purchase), this Lease shall terminate with respect to the Leasehold Estate
or Leasehold Estates, as the case may be, so purchased.
(c) In the event that the Lease shall be terminated as to either of the
Leased Properties in accordance with paragraph 14 or 15 or subparagraph 17(f)
each installment of Rent payable after such termination shall be an amount equal
to (a) in the case of the termination of the Lease as to the Lynn Leased
Property, 47.28704% of the applicable installments of Rent specified in
subparagraphs (vi) and (vii) of paragraph 4 hereof or (b) in the case of the
termination of the Lease as to the Salem Leased Property, 52.71296% of the
applicable installments of Rent specified in subparagraphs (vi) and (vii) of
paragraph 4 hereof.
(d) If Lessee shall have any claim against Lessor, Lessee may offset such
claim against that portion of such purchase price which exceeds the necessary
payment or prepayment, as the case may be, and premiums, if any, of all Approved
Liens, provided, that nothing in this
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subparagraph 17(d) shall in any way interfere with the payment of any Approved
Lien. The amount of such claim shall be an amount mutually agreed upon by the
Lessor and Lessee.
(e) Lessor does not make any representations concerning title to the
Leased Properties or the validity, effectiveness or continuing effectiveness of
the Commonwealth Licenses.
(f) If Lessee determines that the costs which it will incur in making any
modifications, alterations or additions ("Modifications") to the Leased
Properties in accordance with subparagraph 6(c) (expressly excluding any costs
or expenses incurred in dismantling and disposing of the Lynn Liquefaction
Equipment pursuant to subparagraph 8(d)) after April 30, 1999, will exceed
$7,000,000, then the Lessee may, upon 50 days' written notice made before the
Lessee has made such Modifications, purchase the Leasehold Estate with respect
to which such Modifications are required to be made, or both Leasehold Estates,
as the case may be, at a purchase price equal to the Stipulated Loss Value
thereof determined, subject to the provisions of this paragraph 17, in
accordance with Schedule C, and in such event this Lease shall terminate with
respect to such Leasehold Estate or both Leasehold Estates, as the case may be.
For the purposes of satisfying the $7,000,000 threshold, the Lessee may
aggregate all Modifications made in accordance with subparagraph 6(c)
(excluding, as noted above, those relating to the Lynn Liquefaction Equipment)
after April 30, 1999, provided that before making such Modifications, Lessee has
provided written notice to Lessor as contemplated above. Lessor's failure to
object to the nature of the expenses set forth in Lessee's notices of
Modifications as contemplated above, shall not in any way constitute Lessor's
agreement that such expenses constitute expenses properly classified as
Modifications required under paragraph 6(c) hereof.
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(g) On the date of any purchase pursuant to subparagraph 17(f), Lessor
shall transfer and convey the Leasehold Estates to Lessee or its designee, in
accordance with the provisions of this paragraph 17, against payment by the
Lessee of the purchase price therefor, together with all installments of Rent
payable up to and including the day prior to such termination date and all other
sums then due and payable under this Lease.
18. Purchase Option. Unless an Event of Default (or other event which
after lapse of time or notice or both would become an Event of Default) shall
have occurred and be continuing, the Lessee shall have the option, at the end of
the term of this Lease, upon prior written notice delivered to Lessor at least
180 days before the end of the term of this Lease, to purchase both Leasehold
Estates on July 1, 2014 (the "Purchase Option Date"), at a purchase price equal
to the lesser of (i) the fair market sales value of both Leasehold Estates
(determined as hereinafter provided in this paragraph 18) as of the Purchase
Option Date or (ii) $6,000,000. On the Purchase Option Date, Lessor shall
transfer and convey the Leasehold Estates (expressly excluding the Lynn
Liquefaction Equipment) to Lessee or its designee, in accordance with the
provisions of paragraph 17, against payment by the Lessee of the purchase price
therefor, together with all installments of Rent payable up to and including the
day prior to such Purchase Option Date and all other sums then due and payable
under this Lease, including without limitation the estimated or actual (if
practicable) Partial Year Payment. Lessor and Lessee shall consult for the
purpose of determining the fair market sales value of the Leasehold Estates
promptly after Lessee delivers the purchase option notice contemplated above,
and any value agreed upon in writing shall constitute such fair market sales
value for the purposes of this paragraph 18. Solely for purposes of determining
the fair market sales value for purposes of this
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paragraph 18, it shall be assumed (notwithstanding the fact that the Lynn
Liquefaction Equipment has been dismantled and disposed of in accordance with
subparagraph 8(d) hereof) that the Lynn Liquefaction Equipment is in place on
the Lynn Land Parcel, is part of the Leasehold Estates being conveyed, and has
been maintained in good operating condition and has all necessary permits and
approvals of any applicable governmental authority (to the extent such permits
and approvals are still obtainable for liquefaction equipment generally) such
that it is immediately operable in all respects for its original intended use.
Further, the fair market sales value of the Lynn Liquefaction Equipment will be
valued at its highest and best use, and costs of removal from the location of
current use shall not be a deduction from such value. If Lessor and Lessee fail
to agree upon such value within 90 days of the date of the purchase option
notice, Lessee may either (a) request that such value be determined by the
Appraisal Procedure, or (b) agree in writing to purchase the Leased Properties
for $6,000,000. If Lessee does not request that such value be determined by the
Appraisal Procedure, or agree in writing to purchase the Leased Properties for
$6,000,000, by the date which is 60 days prior to the Purchase Option Date, then
Lessee shall be deemed to have unequivocally and unconditionally (a) elected not
to have such fair market sales value determined by the Appraisal Procedure, and
(b) elected not to purchase the Leased Properties at the end of the term of this
Lease pursuant to this paragraph 18, and will surrender and vacate the Leased
Properties at the end of the term of this Lease as contemplated by paragraph 25
hereunder, and the "Appraisal Procedure" to determine the Return Adjustment
Amount (as defined in paragraph 25), if any, will immediately commence. If
Lessee does request that such value be determined by the Appraisal Procedure,
the purchase price shall be as set forth in the first sentence of this paragraph
18 (in no event to exceed $6,000,000, plus any
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amounts contemplated by subparagraph 17(b) hereof). Lessee shall pay all costs
and expenses of any appraisal pursuant to such Appraisal Procedure. "Appraisal
Procedure" for purposes of this paragraph 18 shall mean the following procedure
for determining the fair market sales value of the Leasehold Estates: If Lessee
hereto shall have given written notice to Lessor requesting determination of
such value, the parties shall consult for the purpose of appointing a qualified
independent equipment appraiser by mutual agreement. If no such appraiser is so
appointed within five business days after such notice is given, either party may
request the American Arbitration Association to appoint such an appraiser within
20 days after such request is made, and both parties shall be bound by any
appointment so made within such 20-day period. If no such appraiser shall have
been appointed within 20 days of such request to the American Arbitration
Association or within 30 days after the original notice requesting a
determination pursuant to the Appraisal Procedure, whichever is earlier, either
party may apply to any court having jurisdiction to make such appointment, and
both parties shall be bound by any appointment made by such court. Any appraiser
appointed pursuant to the foregoing procedure shall be instructed to determine
the fair market sales value of the Leasehold Estates within 30 days after his
appointment and his determination thereof shall be final.
19. Subletting; Assignment; Lessor's Lien. Lessee may sublet either Leased
Property or any portion thereof and Lessee may assign its interest under this
Lease provided that each sublease shall expressly be made subject to the
provisions of this Lease, and provided that any assignee shall expressly assume
all obligations of Lessee hereunder in a written instrument delivered to Lessor
promptly after such assignment. No such sublease or assignment shall affect or
reduce any obligations of Lessee or rights of Lessor hereunder, and all
obligations of Lessee
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hereunder shall continue in full effect as the obligations of a principal and
not of a guarantor or surety, as though no subletting or assignment had been
made. Upon the occurrence of an Event of Default under this Lease, Lessor shall
have the right to collect and enjoy all rents and other sums of money payable
under any sublease of the Leased Property or any part thereof, and Lessee hereby
assigns such rents and money to Lessor and agrees to execute and deliver to
Lessor such additional instrument or instruments requested by Lessor more fully
to assign such rents and money to Lessor or to assist Lessor in the collection
and enjoyment thereof. Neither this Lease nor the term hereby demised shall be
mortgaged by Lessee, nor shall Lessee mortgage or pledge the interest of Lessee
in and to any sublease of either Leased Property or any portion thereof or the
rentals or any other amounts payable thereunder. Any such mortgage or pledge,
and any such sublease or assignment made otherwise than as permitted by this
paragraph 19, shall be void. Lessee shall, within 20 days after the execution
and delivery of any such sublease or assignment deliver a conformed copy thereof
to Lessor.
20. Advances by Lessor; Permitted Contests. (a) If Lessee shall fail to
make or perform any payment or act on its part to be made or performed under
this Lease, then, subject to the provisions of subparagraph 20(b), Lessor may,
upon notice to the Lessee (except that no notice shall be required in the case
of an emergency), without waiving any default or releasing Lessee from any
obligation, make such payment or perform such act for the account and at the
cost and expense of Lessee. All amounts so paid by Lessor and all necessary and
incidental costs and expenses (including attorneys' fees and expenses) incurred
in connection with the performance of any such act by Lessor shall be payable by
Lessee to Lessor on demand. In
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addition, Lessee shall pay to Lessor, on demand, interest on the amount so paid
by Lessor, at the rate provided in paragraph 4 for overdue installments of Rent.
(b) Lessee shall not be required, nor shall Lessor have the right, to pay,
discharge or remove, any tax, charge, levy, assessment or lien, or any other
imposition or encumbrance on or against either Leased Property or any portion
thereof, or to comply with any law, ordinance, rule or regulation, so long as
Lessee shall, in good faith and at its cost and expense, contest the existence,
amount or validity thereof by appropriate proceedings which shall operate to
prevent the collection of or other realization upon the tax, charge, levy,
assessment or lien, or other imposition or encumbrance or the enforcement of the
law, ordinance, rule or regulation so contested, and the sale, forfeiture or
loss of either Leased Property or any portion thereof or interest therein or of
the Rent or any amounts payable by Lessee hereunder, or any portion thereof, to
satisfy the same, and which shall not affect the payment in full of any Rent
payable hereunder or any use or disposition thereof by Lessor. Lessor agrees
that it will cooperate with Lessee, at the cost and expense of Lessee, in any
such contest.
21. Conditional Limitations - Events of Default and Remedies. (a) Any of
the following shall constitute an event of default ("Event of Default") under
this Lease: (i) if Lessee shall default in (A) making payment when due of any
Rent or of any other amount payable by Lessee hereunder, or (B) the observance
or performance of any other provision of this Lease to be observed or performed
by Lessee hereunder, and if such default shall continue as to (A), for 10 days,
or as to (B) for 30 days, in each case after Lessor shall have given Lessee
notice specifying such default and demanding that the same be cured (or, if such
default cannot be cured by the payment of money and cannot with diligence be
cured within such 30-day period by
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reason of causes beyond the control of Lessee, but Lessee shall fail to proceed
promptly to cure the same and prosecute the curing of such default with
diligence); or (ii) if Lessee shall file a petition in bankruptcy or for
reorganization or for any arrangement pursuant to the federal bankruptcy act or
any similar federal or state law, or be adjudicated a bankrupt or insolvent, or
make an assignment for the benefit of creditors or admit in writing its
inability to pay its debts generally as they become due, or be dissolved, or
suspend payment of any of its obligations, or take any corporate action in
furtherance of any of the foregoing; or (iii) if a petition or answer proposing
the adjudication of Lessee as a bankrupt or its reorganization under the federal
bankruptcy act or any similar federal or state law shall be filed in any court,
and (A) Lessee shall consent to such filing, or (B) such petition or answer
shall not be discharged or denied within 90 days after such filing; or (iv) if a
receiver, trustee or liquidator (or other similar official) shall be appointed
for or take possession or charge of Lessee or of all or substantially all of its
assets or its interest in the Leased Properties or any part thereof and shall
not be discharged within 90 days thereafter, or if Lessee shall consent to or
acquiesce in such appointment; or (v) if Lessee's interest in the Leased
Properties or any part thereof shall be levied upon or attached in any
proceeding and such process shall not be vacated or discharged or such levy or
attachments shall not be bonded within 90 days thereafter, (vi) if the Easement
Agreements shall expire or be terminated prior to the expiration of the term of
this Lease; or (vii) the happening of any default under an instrument under
which the Lessee shall have outstanding any indebtedness, or which evidences any
outstanding indebtedness, continuing beyond the applicable grace period (if any)
provided for therein. The Lessee shall deliver to the Lessor on January 1 of
each calendar year during the term of this Lease a certificate signed by the
president or a vice president of Lessee to
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the effect that Lessee is not in default in the performance and observance of
any of the terms, provisions and conditions hereof, or if Lessee shall be in
default, specifying all such defaults and the nature thereof.
(b) This Lease and the term and estates hereby granted are subject to the
limitation that whenever an Event of Default shall have occurred, Lessor may, at
its election, during the continuance of such Event of Default:
(i) proceed by appropriate judicial proceedings, either at law
or in equity, to enforce performance or observance by Lessee of the
applicable provisions of this Lease or to recover damages for the breach
thereof; or
(ii) by notice to Lessee terminate the term of this Lease on a
date specified in such notice, which shall be not less than 10 days after
the giving of such notice and upon the date so specified the term of this
Lease and the Leasehold Estates hereby granted shall expire and terminate
with the same force and effect as if the date specified in such notice
were the date hereinbefore fixed for the expiration of the term of this
Lease and all rights of Lessee hereunder shall expire and terminate, but
Lessee shall remain liable as hereinafter provided.
Should Lessor elect to reenter as herein provided, or should Lessor take
possession pursuant to legal proceedings or pursuant to any notice provided by
law, Lessor shall use commercially reasonable efforts to sell or re-let the
Leased Properties or any part thereof for such amounts (in the case of a sale),
and for such term or terms and at such rentals (in the case of a lease), and
upon such other terms and conditions as Lessor may deem advisable, with the
right to make alterations in and repairs of the Leased Properties.
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(c) In the event of any termination of this Lease as provided above in
subparagraph 21(b) or as permitted by law, Lessee shall peaceably quit and
surrender the Leased Properties to Lessor, and Lessor may without further notice
enter upon, re-enter, possess and repossess the same by summary proceedings,
ejectment or otherwise, and again have, repossess and enjoy the same as if this
Lease had not been made, and in any such event neither Lessee nor any person
claiming through or under the Lessee by virtue of any law or an order of any
court shall be entitled to possession or to remain in possession of the Leased
Properties but shall forthwith quit and surrender the Leased Properties, and
Lessor at its option shall forthwith, notwithstanding any other provision of
this Lease, be entitled to recover from Lessee (in lieu of all other claims for
damages on account of such termination) (i) any and all Rent and all other
amounts payable to Lessor hereunder which may then be due and unpaid or which
may then be accrued and unpaid and (ii) as and for liquidated damages and not as
a penalty an amount equal to the Stipulated Loss Value calculated in accordance
with Schedule C, and (iii) any amounts not paid to Lessor which Lessor would
have been entitled to received, but for the occurrence of an Event of Default
hereunder, pursuant to paragraph 26 of this Lease until such time as Lessor
actually takes possession of the Leased Properties, and (iv) any and all other
damages and expenses (including without limitation attorneys' fees and all
expenses incurred in regaining possession of the Leased Properties and in
putting in good order and repairing the Leased Properties) which Lessor shall
have sustained by the breach of any provision of this Lease. Nothing contained
herein shall limit or prejudice the right of Lessor, in any bankruptcy or
reorganization or insolvency proceeding, to prove for and obtain as liquidated
damages by reason of such termination an amount, equal to the maximum allowed by
any bankruptcy or reorganization or insolvency proceedings, or to prove
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and obtain as liquidated damages by reason of such termination an amount equal
to the maximum allowed by any statute or rule of law, whether such amount shall
be greater or less than the amounts referred to above.
(d) If, following an Event of Default, Lessor shall terminate this Lease
or re-enter and obtain possession of the Leased Properties, Lessor shall have
the right, without notice, to repair or alter the Leased Properties in such
manner as Lessor may deem necessary or advisable so as to put the Leased
Properties in good order and to make the same saleable or rentable for
reasonably similar purposes, and shall use commercially reasonable efforts to
sell or re-let the Leased Properties or a part thereof and mitigate Lessee's
damages hereunder, and Lessee agrees to pay to Lessor on demand all expenses
incurred by Lessor in obtaining possession, and in altering, repairing and
putting the Leased Properties in good order and condition and in selling or
re-letting the same, including reasonable fees of attorneys and architects, and
all other reasonable expenses and commissions. In the event Lessor takes
possession and disposes of either of the Leased Properties through a sale or
re-letting, the proceeds of any such sale or re-letting (as calculated below)
shall be applied in the following order: (i) to the extent not previously paid
to the Lessor by the Lessee, to all of Lessor's costs, charges and expenses
incurred in disassembling, taking, removing, holding, repairing and selling or
leasing the Leased Property; (ii) to the extent not previously paid to the
Lessor by the Lessee, to pay Lessor for any of Lessor's damages then remaining
unpaid hereunder; (iii) to reimburse Lessee for any sums previously paid by
Lessee as Lessor's damages hereunder; and (iv) the balance, if any, shall be
retained by Lessor. For purposes of the foregoing, (i) the proceeds of a
disposition of the Leased Properties by a sale shall be the actual proceeds
received by Lessor in connection with such sale, and (ii) the proceeds
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of a disposition of the Leased Properties by re-letting shall be the present
value of the rental payments to be paid to the Lessor over the irrevocable term
of the re-lease (using a discount rate of 8%). Notwithstanding anything to the
contrary contained in this paragraph 21, Lessor shall not be obligated to
re-lease the Leased Properties unless the proposed lessee meets the Lessor's
then current credit criteria as determined by Lessor. Lessor shall have the
right from time to time to begin and maintain successive actions or other legal
proceedings against Lessee for the recovery of Lessor's damages and to recover
the same upon the liability of Lessee herein provided, which liability it is
expressly covenanted shall survive the institution of any action to secure
possession of the Leased Properties. Nothing herein contained shall be deemed to
require Lessor to wait to begin such action or other legal proceedings until the
date when this Lease would have expired by limitation had there been no such
Event of Default.
(e) If, under any of the preceding provisions of this paragraph 21, Lessor
shall be entitled to give Lessee a notice of termination of the term of this
Lease, Lessor, without giving such notice of termination and notwithstanding the
continuance of the term of this Lease, shall have, to the extent permitted by
law, all the rights, powers and remedies given to Lessor by the preceding
provisions of this paragraph 21, and Lessee shall have the obligations imposed
upon it by such provisions. No such re-entry or taking of possession of the
Leased Properties by Lessor shall be construed as an election on Lessor's part
to terminate the term of this Lease unless a written notice of such intention be
given to Lessee or unless such termination be decreed by a court of competent
jurisdiction.
(f) In the case of an Event of Default, Lessee hereby waives and
surrenders for itself and all those claiming under it (i) any right and
privilege which it or any of them may have under
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any present or future constitution, statute or rule of law to redeem the Leased
Properties or to have a continuance of this Lease for the term hereby demised
after termination of Lessee's right of occupancy by order or judgment of any
court or by any legal process or writ, or under the terms of this Lease, or
after the termination of the term of this Lease as herein provided, and (ii) the
benefits of any present or future constitution, statute or rule of law which
exempts property from liability for debt or for distress for rent.
(g) If Lessee shall be in default in the observance or performance of any
provision of this Lease, and an action shall be brought for the enforcement
thereof in which it shall be determined that Lessee was in default, Lessee shall
pay to Lessor all costs, fees and other expenses which may become payable as a
result thereof or in connection therewith, including attorneys' fees and
expenses. If Lessor shall without fault on its part be made a party to any
litigation commenced against Lessee, and if Lessee shall not provide Lessor at
Lessee's expense with counsel satisfactory to Lessor, Lessee shall pay all costs
and attorneys' fees incurred or paid by Lessor in connection with such
litigation.
(h) Except as otherwise expressly herein provided, no right or remedy
herein conferred upon or reserved to either party is intended to be exclusive of
any right or remedy, and every right and remedy shall be cumulative and in
addition to any other legal or equitable right or remedy given hereunder, or now
or hereafter existing. The failure of either party to insist upon the strict
performance of any provision or to exercise any option, right, power or remedy
contained in this Lease shall not be construed as a waiver or a relinquishment
thereof for the future. Receipt by Lessor of any Rent or any other amounts
payable by Lessee hereunder with knowledge of the breach of any provision
contained in this Lease shall not constitute a waiver of
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such breach (other than either the prior failure to pay such Rent or any other
amounts payable by Lessee), and no waiver by either party of any provision of
this Lease shall be deemed to have been made unless made under signature of an
officer or other authorized representative of such party. Each party hereto
shall be entitled to the extent permitted by law, to injunctive relief in case
of the violation, or attempted or threatened violation, of any provision of this
Lease, or to a decree compelling observance or performance of any provision of
this Lease, or to any other legal or equitable remedy.
22. The Easement Agreements. (a) Lessee covenants and agrees that it will
duly and punctually observe and perform, at its expense, all covenants, terms
and conditions imposed by the Easement Agreements upon the grantees thereunder
(excluding the annual payment of rent due under the Easement Agreements),
whether or not Lessor has assumed such obligations by agreement with the
respective Ground Owner or the Easement Agreements provide that any assignee of
the interest of the grantees thereunder shall assume such obligations to the end
that Lessor shall have no responsibility for compliance with the provisions of
the Easement Agreements and shall be exonerated from all liability thereunder
(except for the annual payment of rent due thereunder). The provisions of this
subparagraph 22(a) shall be for the benefit of and shall be enforceable by
Lessor.
(b) If any event shall occur which, pursuant to the terms of either
Easement Agreement, with or without the passage of time, shall enable the
grantor thereunder to terminate the same or to impair or restrict the rights of
the grantee thereunder, Lessee shall notify Lessor thereof within 10 days after
Lessee shall have become aware of the occurrence thereof, and Lessee shall take
such action, if any, as shall be necessary to maintain the right of Lessor in
the
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Leased Property relating to such Easement Agreement and to enable the full
enjoyment of such rights as they existed prior to such impairment or
restriction.
23. Lessee's Certificate. The certificate of Lessee required to be
delivered pursuant to subparagraph 17(b) hereof in connection with the purchase
by Lessee of either or both Leasehold Estates, shall, as of the date thereof
(which date shall be the date on which such certificate is to be delivered) (i)
state that both Lessee and Lessor have complied with all provisions of the Lease
applicable to such purchase, (ii) state that such purchase is expressly required
or expressly permitted, as the case may be, by the terms of the lease, (iii)
identify the paragraph or paragraphs of the Lease pursuant to which such
purchase is being made, (iv) specify the Leasehold Estate being purchased or
that both Leasehold Estates are being purchased, as the case may be, and
specifying the purchase price thereof, (v) state that said purchase price is the
amount required under the applicable paragraph or paragraphs of the Lease to be
paid on account of the purchase price of such Leasehold Estate or both Leasehold
Estates, as the case may be, and (vi) state that there does not exist under the
Lease any Event of Default or any event which but for the requirement that
notice be given or time elapse, or both, would constitute an Event of Default.
24. Notices. All notices and other instruments or communications pursuant
to this Lease shall be in writing and shall be sent by registered or certified
United States mail, return receipt requested, addressed to Lessor or Lessee, as
the case may be, at its address set forth above, with copies to their respective
counsel as follows: if to Lessor with a copy to Edwards & Angell, LLP, One
BankBoston Plaza, Providence, Rhode Island 02903, Attention: David T. Miele,
Esq.; and if to Lessee with a copy addressed to Lessee and marked "Attention:
Legal Department" and with a copy to Hill & Barlow, One International Place,
Boston, Massachusetts
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02110, Attention: Gregory P. Bialecki, Esq. Lessor and Lessee shall each have
the right, from time to time, to specify as its address (or the address of its
counsel) for purposes of this Lease, any other address in the United States upon
giving 15 days' notice to the other party.
25. Surrender. (a) Subject to the provisions of paragraphs 14, 15 and 18
upon the expiration or earlier termination of the term of this Lease, Lessee
shall surrender the Leased Properties to Lessor in the same condition in which
the Leased Properties were originally leased from Lessor as of the date of this
Lease (excluding the Lynn Liquefaction Equipment), except as repaired, rebuilt,
restored or modified as permitted by any provision of this Lease, and except for
ordinary wear and tear. If the Lessee has not provided Lessor with the purchase
option notice contemplated by paragraph 18 at least 180 days before the end of
the term of this Lease, it will be deemed that Lessee has elected to surrender
the Leased Properties to Lessor at the end of the term of this Lease. If Lessee
has elected to surrender the Leased Properties at the end of the term of this
Lease (expressly excluding any surrender of the Leased Properties resulting from
an Event of Default by Lessee hereunder), Lessor and Lessee shall consult for
the purpose of determining the amount, if any, of the Return Adjustment Amount
(as herein defined) owed by Lessee to Lessor and to be paid on the last day of
the term of this Lease. For purposes hereof, the "Return Adjustment Amount"
shall be the positive difference, if any, between: (a) the fair market sales
value of the Leased Properties taken as a whole (expressly including the Lynn
Liquefaction Equipment) at the end of the term of this Lease assuming (i)
(notwithstanding the fact that the Lynn Liquefaction Equipment has been
dismantled and disposed of in accordance with subparagraph 8(d) hereof) that the
Lynn Liquefaction Equipment is in place on the Lynn Land Parcel and has been
maintained in good operating condition and has all necessary permits and
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approvals of any applicable governmental authority (to the extent such permits
and approvals are still obtainable for liquefaction equipment generally) such
that it would be immediately operable for its original intended use, (ii) the
highest and best use of the Lynn Liquefaction Equipment to a third party end
user other than Lessee, and (iii) costs of removal of the Lynn Liquefaction
Equipment from the location of current use shall not be a deduction from such
value; and (b) the fair market sales value of the Leased Properties taken as a
whole (expressly excluding the Lynn Liquefaction Equipment) at the end of the
term of this Lease. Any Return Adjustment Amount agreed upon in writing by
Lessor and Lessee shall constitute such Return Adjustment Amount and shall be
paid by Lessee to Lessor on the last day of the term of this Lease. If Lessor
and Lessee fail to agree upon such Return Adjustment Amount prior to 120 days
before the end of the term of this Lease, Lessor or Lessee may request that such
Return Adjustment Amount be determined by the Appraisal Procedure.
Alternatively, the Appraisal Procedure contemplated hereunder shall be
instituted if Lessee fails to invoke the Appraisal Procedure under paragraph 18
hereof within the time frame provided therein to determine the fair market sales
value. Lessor and Lessee shall equally share all costs and expenses of any
determination of the Return Adjustment Amount pursuant to such Appraisal
Procedure. For purposes of this subparagraph 25(a), "Appraisal Procedure" shall
mean the following procedure for determining the Return Adjustment Amount, if
any, payable by Lessee at the end of the term of this Lease: If Lessor or Lessee
hereto shall have given written notice to the other party requesting
determination of such Return Adjustment Amount by the Appraisal Procedure, the
parties shall consult for the purpose of appointing a qualified independent
equipment appraiser by mutual agreement. If no such appraiser is so appointed
within five business days after such notice is given, either party may
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request the American Arbitration Association to appoint such an appraiser within
20 days after such request is made, and both parties shall be bound by any
appointment so made within such 20-day period. If no such appraiser shall have
been appointed within 20 days of such request to the American Arbitration
Association or within 30 days after the original notice requesting a
determination of the Return Adjustment Amount pursuant to the Appraisal
Procedure, whichever is earlier, either party may apply to any court having
jurisdiction to make such appointment, and both parties shall be bound by any
appointment made by such court. Any appraiser appointed pursuant to the
foregoing procedure shall be instructed to determine the Return Adjustment
Amount (as defined above), if any, within 30 days after his appointment and his
determination thereof shall be final. The Return Adjustment Amount, if any,
determined by the Appraisal Procedure shall be paid by Lessee to Lessor on the
last day of the term of this Lease. If for any reason (other than the fact that
the determination by the appraiser of the Return Adjustment Amount, if any, has
been delayed through no fault of Lessee), the Return Adjustment Amount is not
paid by Lessee to Lessor on the last day of the term of this Lease the Return
Adjustment Amount shall accrue interest at a rate of 12% per annum until paid by
Lessee.
(b) Except for surrender upon the expiration of the term hereof or earlier
termination of the term of this Lease, no surrender to Lessor of this Lease or
of either Leased Property or any portion thereof or of any interest therein
shall be valid or effective unless agreed to and accepted under signature of an
officer or other authorized representative of Lessor and the holders of all
Approved Liens, and no act by any other representative or agent of Lessor, and
no act by Lessor, other than such an agreement and acceptance so signed, shall
constitute an acceptance of any such surrender.
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26. Ten Percent (10%) Transactions. Subject to regulatory approval,
commencing January 1, 2003, Lessor shall be entitled to ten percent (10%) of the
gross difference between the agreed upon annual rent due Lessor and any higher
amount Lessee realizes on the subleasing or any comparable transaction of the
Leased Properties, computed on a pro rata basis. Such payments shall be paid
annually in arrears on January 31 of each calendar year beginning with a payment
due on January 31, 2004 (for the 2003 calendar year) and ending with a payment
on June 30, 2014 for the six month period commencing January 1, 2014, to the
extent a sublease or comparable transaction is in place during such period. If
Lessee purchases either or both of the Leasehold Estates pursuant to paragraph
17 hereof, a Partial Year Payment as contemplated by subparagraph 17(b) shall be
due from Lessee, to the extent a sublease or comparable transaction is in place
during such period. Lessee shall, within 20 days after the execution and
delivery of any such sublease or comparable transaction, deliver a conformed
copy thereof to Lessor.
27. Representations and Warranties; Covenants of Lessee.
(a) The Lessee represents and warrants to the Lessor that:
(i) It is a corporation duly incorporated and validly existing under
the laws of the Commonwealth of Massachusetts and has corporate power and
authority to carry on its business as presently conducted, to hold under
lease the Leased Properties and to enter into this Lease and to perform
its obligations hereunder.
(ii) The execution, delivery and performance of this Lease has been
duly authorized by all necessary corporate action and does not and will
not violate any provisions of any applicable laws, orders, regulations,
rules, court decrees or
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the articles of organization or by-laws of the Lessee and does not and
will not result in the breach of, or constitute a default under, or
require any consent under, any indenture, bank loan or credit agreement,
mortgage or other agreement or instrument to which it is a party or by
which it or any of its properties may be bound or affected.
(iii) No authorization, consent or approval of, nor any registration
or filing with or notification to or taking any other action in respect of
the Massachusetts Department of Telecommunications and Energy, or other
applicable administrative agency or governmental authority is required in
connection with the execution, delivery and performance of this Lease.
(iv) There are no actions, suits or proceedings pending, or to the
knowledge of the Lessee threatened, before any court, administrative
agency, arbitrator or governmental body which will, if determined
adversely to the Lessee, adversely affect the Lessee's financial condition
or its ability to perform its obligations under this Lease.
(v) The financial statements of the Lessee for the most current
fiscal year ended, delivered simultaneously herewith to the Lessor are
correct and complete and fairly present the results of its operations for
the periods covered and its financial condition as of the date of such
statements and have been prepared in accordance with generally accepted
accounting principles applied consistently throughout the periods
involved. There are no material contingent liabilities or liability for
taxes which are not reflected in such statements or the
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notes thereto, and there have been no material adverse changes in the
financial condition, business or operations of the Lessee since the dates
of such statements.
(vi) This Lease has been duly executed and delivered by the Lessee
and constitutes the legal, valid and binding obligation of the Lessee
enforceable against the Lessee in accordance with the terms hereof.
(b) The Lessee agrees to deliver to the Lessor within 90 days after the
end of each fiscal year of the Lessee, which as of the date hereof is the
calendar year and within 60 days after the end of each first, second and third
quarter-annual period of each such fiscal year (beginning with the most recently
ended fiscal quarter of Lessee), the following financial statements, all in
reasonable detail and satisfactory in scope to the Lessor: (a) a balance sheet
of the Lessee as at such date, together with the comparative figures for the
corresponding date one fiscal year prior thereto and (b) statements of income
and of earned surplus of the Lessee for such fiscal year ended on such date or
for the quarter-annual period of the fiscal year then ended, as the case may be,
on the same basis, together with the comparative figures for the preceding
fiscal year or the corresponding quarter-annual period thereof, as the case may
be, and in the case of such annual financial statements, certified by
independent public accountants of nationally recognized standing selected by the
Lessee. The financial statements to be delivered pursuant to this subparagraph
27(b) will be correct and complete and will fairly present the result of
Lessee's operations for the period covered and its financial condition as of the
dates of such statements and will have been prepared in accordance with
generally accepted accounting principles applied consistently throughout the
periods involved. There will be no material contingent liabilities or liability
for taxes which are not reflected in such statements or the notes thereto, and
there will
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have been no material adverse changes in the financial condition, business or
operations between the dates of such statements and the delivery thereof to the
Lessor. Promptly after receipt thereof, the Lessee will deliver to the Lessor
copies of any detailed reports submitted to the Lessee in connection with each
annual or interim audit of the books of the Lessee made by such accountants.
(c) The Lessee agrees to diligently pursue the obtaining of a Disclaimer
of Interest in substantially the form of Schedule D attached hereto from any
secured party which could claim a lien on, or security interest in, the Leased
Properties, based on UCC search reports which disclose additional UCC-1
financing statements naming Lessee as debtor, which Lessor has not had an
opportunity to review prior to the date hereof. If for any reason Lessee is
unable to obtain a Disclaimer of Interest from such secured parties, Lessee
shall indemnify Lessor for any and all direct costs and liabilities incurred by
Lessor resulting from Lessee's inability to obtain the Disclaimer of Interest.
28. Separability. Each provision contained in this Lease shall for all
purposes be construed to be separate and independent and the breach of any such
provision by Lessor shall not discharge or relieve Lessee from Lessee's
obligation to observe and perform each provision of this Lease to be observed or
performed by Lessee. If any provision of this Lease or the application thereof
to any person or circumstance shall to any extent be invalid and unenforceable,
the remainder of this Lease, or the application of such provision to persons or
circumstances other than those as to which it is invalid or unenforceable, shall
not be affected thereby, and each provision of this Lease shall be valid and
shall be enforceable to the extent permitted by law.
51
<PAGE>
29. Binding Effect. All provisions contained in this Lease shall be
binding upon, inure to the benefit of and be enforceable by, the respective
successors and assigns of Lessor and Lessee to the same extent as if each such
successor or assign were named as a party to this Lease. This Lease embodies the
entire agreement between Lessor and Lessee relating to the subject matter hereof
and supersedes all prior agreements and understandings relating to such subject
matter. Neither this Lease nor any provision hereof may be amended, modified,
waived, discharged or terminated orally, but only as expressly provided herein
or by an instrument signed by Lessor and Lessee.
30. No Merger. There shall be no merger of this Lease or of either
Leasehold Estate hereby created with either Easement Agreement or the estate
thereby created or with the fee estate in either Leased Property or any part
thereof, as the case maybe, by reason of the fact that the same person may
acquire or hold, directly or indirectly, this Lease or either Leasehold Estate
hereby created or any interest in this Lease or in such Leasehold Estate and (i)
either Easement Agreement or the estate thereby created or any interest in
either Easement Agreement or such estate, and (ii) the fee estate in either
Leased Property or any part thereof or any interest in such fee estate, or (iii)
either of the foregoing, and this Lease shall not be terminated for any reason
except as expressly provided herein.
31. Access. The Lessor or its agents shall have the right to enter the
Leased Properties during reasonable hours to examine and inspect the same for
any purpose, as Lessor shall deem desirable for the protection of Lessor's
rights under this Lease.
52
<PAGE>
32. Miscellaneous. (a) The headings to the various paragraphs of this
Lease have been inserted for convenient reference only and shall not modify,
define, limit or expand the expressed provisions of this Lease.
(b) This Lease shall be deemed to be a contract made under the laws of the
Commonwealth of Massachusetts, and for all purposes shall be construed in
accordance with the laws of that State.
(c) If any payment is to be made or action to be taken on a Saturday,
Sunday or a day on which banking institutions in Boston, Massachusetts, are
authorized by law to close, then such payment must be made or such action taken
on the first succeeding day which is not a Saturday, Sunday or a day on which
banking institutions in Boston, Massachusetts, are authorized by law to close
without interest for the period from such date on which any payment is to be
made or action is to be taken to such succeeding day.
(d) As between Lessee and any third party (other than Lessor or any
successors or assigns of Lessor) nothing contained in this Lease shall be deemed
to create any liability on the part of Boston Gas Company as Lessee hereunder
for events arising prior to April 30, 1999.
[Remainder of Page Intentionally Left Blank]
53
<PAGE>
IN WITNESS WHEREOF, Lessor and Lessee have duly executed and delivered
this Amended and Restated Lease under their respective corporate seals, all as
of the day and year first above written.
Witness: INDUSTRIAL NATIONAL LEASING
CORPORATION
/s/ [ILLEGIBLE] By: /s/ Brian D. DeRusha
- -------------------------- -------------------------------
Brian D. DeRusha, Vice President
Witness: BOSTON GAS COMPANY
/s/ [ILLEGIBLE] By: /s/ Joseph F. Bodanza
- -------------------------- -------------------------------
Title: Sr. Vice President and Treasurer
Joseph F. Bodanza
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
COUNTY OF SUFFOLK
In Boston, on the 30th day of April, 1999, before me personally appeared
Brian D. DeRusha, Vice President of Industrial National Leasing Corporation, to
me known and known by me to be the person executing the foregoing instrument,
and he acknowledged said instrument by him executed to be his free act and deed
in said capacity and the free act and deed of the corporation.
/s/ Anne Mullen
---------------------------
Notary Public
My commission expires:
-----------------
ANNE MULLEN
NOTARY PUBLIC
My Commission Expires Oct. 8, 2004
COMMONWEALTH OF MASSACHUSETTS
COUNTY OF SUFFOLK
In Boston, on the 30th day of April, 1999, before me personally appeared
Joseph F. Bodanza, Sr., Vice President and Treasurer of Boston Gas Company, to
me known and known by me to be the person executing the foregoing instrument,
and he acknowledged said instrument by him executed to be his free act and deed
in said capacity and the free act and deed of the corporation.
/s/ Diane M. O'Brien
---------------------------
Notary Public Diane M. O'Brien
My commission expires: 11/23/2001
----------
<PAGE>
SCHEDULE A
Description of Lynn Land Parcel
A certain parcel of land situated in Lynn, Essex County, Massachusetts and
being more particularly bounded and described as follows:
Beginning at the northerly corner of said parcel at a point on the
westerly side of Blossom Street at land now or formerly of Massachusetts
Electric Company, said point being S. 29(degree) 58' 40" E., 415 feet distant
from a stone bound at the intersection of the southerly side of the Lynnway and
the westerly side of said Blossom Street;
thence running S. 29(degree) 58' 40" E. a total distance of 496.93 feet to
a stone bound;
thence running N. 48(degree) 14' 10" E. a distance of 37.09 feet to a
point at land now or formerly of Louis B. Frisch et ux--said last two (2)
courses and distances being by said Blossom Street;
thence running S. 41(degree) 42' 40" E. by said land of Louis B. Frisch et
ux, a distance of 300.27 feet to a stone bound on the harbor line of Lynn
Harbor, established by Chapter 313 of the Acts of 1867;
thence running S. 48(degree) 12' 12" W. by said harbor line, a distance of
145.10 feet to a point at other land now or formerly of and to be retained by
the Lynn Gas Company;
thence running N. 41(degree) 44' 14" W., a distance of 42.30 feet to the
southeasterly side or edge of a masonry wall;
thence running S. 48(degree) 05' 15" W. along said southeasterly side or
edge of said masonry wall, a distance of 551.40 feet to a point at other land
now or formerly of Massachusetts Electric Company--said last two (2) courses and
distances being by said land of and to be retained by Lynn Gas Company;
<PAGE>
thence continuing S. 48(degree) 05' 15" W. along said southeasterly side
or edge of said masonry wall, a distance of 86.63 feet to the southerly corner
of masonry walls;
thence running N. 25(degree) 17' 30" W. along the southwesterly side of
edge of said masonry wall, a distance of 278.19 feet to a spike in a corner of
masonry walls;
thence running N. 28(degree) 49' 37" E., a distance of 8.10 feet to a
spike;
thence running N. 63(degree) 26' 15" E., a distance of 96.70 feet to a
spike;
thence running N. 03(degree) 15' 04" E., a distance of 54.79 feet to a
spike;
thence running N. 26(degree) 28' 23" W., a distance of 38.04 feet to a
spike;
thence running N. 28(degree) 49' 37" E., a distance of 114.50 feet to a
bolt;
thence running N. 26(degree) 24' 58" W., a total distance of 445.22 feet
to an iron rod at other land now or formerly of Lynn Gas Company said last eight
(8) courses and distances being by said land of Massachusetts Electric Company;
thence running N. 63(degree) 22' 46" E., a distance of 10.86 feet to a
bolt;
thence running N. 42(degree) 27' 37" W., a distance of 42.08 feet to an
iron rod at said first mentioned land of Massachusetts Electric Company--said
last two (2) courses and distances being by said other land now or formerly of
Lynn Gas Company.
thence running N. 60(degree) 01' 20" E. by said land now or formerly of
Massachusetts Electric Company, a distance of 391.63 feet to the point of
beginning.
Containing 9.80 acres of land and being shown on plan entitled: "NEW
ENGLAND POWER SERVICE COMPANY PART OF NEW ENGLAND ELECTRIC SYSTEM BOSTON, MASS.
PLAN OF LAND IN LYNN, MASSACHUSETTS TO BE LEASED TO MASSACHUSETTS LNG
INCORPORATED BY LYNN GAS COMPANY SCALE 1"-80' DATE April 24, 1972 D-8414".
<PAGE>
Together with the right and easement, as appurtenant to the land herein
described, to use said Blossom Street in common with Lynn Gas Company (or any
successor thereto) and other entitled thereto, for all purposes for which
streets or ways are commonly used in said Lynn.
The premises hereinabove described are a portion of those conveyed to Lynn
Gas Company by Massachusetts Electric Company by deed dated December 9, 1970,
recorded with Essex South District Registry of Deeds, in Book 5733, Page 728,
and the Easement granted and described in the Declaration of Easement dated June
1, 1972, as amended by an Amendment to Declaration of Easement dated as of April
30, 1999, is granted by Grantor subject to the exceptions, reservations,
covenants and agreements set forth in said deed, to which reference is hereby
made.
<PAGE>
Description of Salem Land Parcel
A certain parcel of land situated in Salem, Essex County, Massachusetts,
bounded and described as follows:
Beginning at the most southwesterly corner of said parcel at a point in a
fence on the division line between land now or formerly of North Shore Gas
Company and land now or formerly of New England Power Company, said point being
the most southeasterly corner of Lot A shown on the plan hereinafter referred
to, said Lot A being land now or formerly of North Shore Gas Company;
thence running N. 28(degree) E., a distance of 275.68 feet to a point;
thence running N. 63(degree) 29' 44" W., a distance of 41.11 feet to a
point;
thence running N. 26(degree) 30' 16" E., a distance of 144.94 feet to a
point;
thence running N. 63(degree) 29' 44" W., a distance of 100 feet to a
point;
thence running N. 26(degree) 30' 16" E., a distance of 68.68 feet to a
point in the northerly side or edge of a masonry sea wall at the flats of
Beverly Harbor--said last five courses and distances being by said Lot A on said
plan;
thence running S. 62(degree) 57' 05" E., a distance of 51.81 feet to a
drill hole;
thence running N. 54(degree) 09' 43" E., a distance of 63.25 feet to a
point;
thence running S. 71(degree) 20' 37" E., a distance of 206.42 feet to a
point;
thence running N. 66(degree) 06' 14" E., a distance of 450 feet to a
corner of masonry sea walls at said Beverly Harbor--said last four courses and
distances being along the northerly side or edge of said masonry sea wall by
said flats of Beverly Harbor (which flats are hereinafter excluded from this
conveyance);
<PAGE>
thence running S. 22(degree) 56' 58" E. by the easterly side or edge of a
masonry sea wall, 159.73 feet to a corner of masonry sea walls;
thence running S. 48(degree) 09' 33" W. by the southerly side or edge of a
masonry sea wall, a distance of 400 feet to the end of said wall;
thence running in a general southwesterly direction by various courses, a
total distance of 450 feet more or less to a point at said land now or formerly
of New England Power Company-- said last three courses and distances being by
said Beverly Harbor and Collins Cove and the flats thereof (which flats are
hereinafter included in this conveyance);
thence running N. 61(degree) 00' 00" W. by said land now or formerly of
New England Power Company, 384 feet more or less to the point of beginning.
Containing 7.787 acres of land more or less and being Lot B on a plan
entitled: "PLAN OF LAND IN SALEM PREPARED FOR NORTH SHORE GAS COMPANY SCALE:
1"-100' OCT. 5, 1970 ESSEX SURVEY SERVICE INC. 47 FEDERAL STREET, SALEM", duly
recorded with Essex South District Deeds in Plan Book 119, Plan 46.
Together with that portion of the flats of Beverly Harbor and Collins
Cove, to the extent of the Lessee's interest therein, which are located between
a line delineated on said plan as "N. 67(degree) 03' 02" E. Flats Ownership
Line" and the course hereinabove described as "N. 61(degree) W. by said land now
or formerly of New England Power Company, a distance of 384 feet more or less"
extended southeasterly to the low water mark of Collins Cove.
Being the same premises conveyed to the Lessee by deed of Stephen V.
Hughes, Jr. dated August 18, 1971. This conveyance is made together with the
rights and easements appurtenant to said land and subject to the exceptions,
reservations, covenants and agreements referred to in said deed. This conveyance
is also made together with the benefit of and subject to all
<PAGE>
easements, exceptions, reservations, restrictions and agreements of record, if
any, insofar as the same are now in force and applicable.
<PAGE>
SCHEDULE B
DESCRIPTION OF THE EQUIPMENT
LYNN EQUIPMENT
That certain One Million (1,000,000) MMBTU (12,180,000 gallon) metal
liquefied natural gas storage tank and vaporization system located off Blossom
Street in Lynn, Massachusetts, including, without limitation, any and all
appliances, parts, instruments, appurtenances, valves, piping, connections and
accessories and other equipment of whatever nature from time to time having been
incorporated or installed in or attached to the aforesaid tank and vaporization
system, excluding from the foregoing, all real estate and interests therein and
all buildings and improvements thereon, including, without limitation, concrete
foundations, piers and dykes and other fixtures which constitute part of the
real estate on which the foregoing property is located.
SALEM EQUIPMENT
That certain One Million (1,000,000) MMBTU (12,180,000 gallon) metal
liquefied natural gas storage tank and vaporization system located in Salem,
Massachusetts, including, without limitation, any and all appliances, parts,
instruments, appurtenances, valves, piping, connections and accessories and
other equipment of whatever nature from time to time having been incorporated or
installed in or attached to the aforesaid tank and vaporization system,
excluding from the foregoing, all real estate and interests therein and all
buildings and improvements thereon, including, without limitation, concrete
foundations, piers and dykes and other fixtures which constitute part of the
real estate on which the foregoing property is located.
<PAGE>
SCHEDULE C
DEFINITION AND APPLICATION OF TERMS "LESSOR'S
COST" AND "STIPULATED LOSS VALUE"
The term "Lessor's Cost" shall mean (A) in the case of the Lynn Leased
Property the sum of(i) $9,989,810 paid or payable to Air Products and Chemicals,
Inc. as the manufacturer of the Lynn properties described in clauses (ii) and
(iii) of paragraph 1 of the Lease and located in Lynn, Massachusetts, on or
before the beginning date of the term of this Lease and (ii) $710,190 in
expenses incurred from time to time by Lessee in connection with the acquisition
and construction of the Lynn Leased Property, and (B) in the case of the Salem
Leased Property the sum of(i) $4,149,507 paid or payable to Pittsburgh-Des
Moines Steel Company as the manufacturer of the Salem Leased Property, and (ii)
$750,493 in expenses incurred from time to time by Lessee in connection with the
requisition and construction of the Salem Leased Property.
The term "Stipulated Loss Value" shall be calculated in accordance with
Schedule C-i attached hereto. The Discount Rate used in calculating the attached
Stipulated Loss Value Schedule is eight percent (8%).
<PAGE>
SCHEDULE C-1
STIPULATED LOSS VALUE SCHEDULE
Date on which Stipulated Loss Value is paid:
On or After On or Before Lynn Salem
----------- ------------ ---- -----
4/30/99 $9,920,144 $8,899,031
-------
4/30/99 7/1/99 $7,892,690 $7,080,269
-------
7/2/99 1/1/00 $7,886,840 $7,075,021
1/2/00 7/1/00 $7,880,756 $7,069,563
7/2/00 1/1/01 $7,874,429 $7,063,887
1/2/01 7/1/01 $7,867,848 $7,057,984
7/2/01 1/1/02 $7,861,005 $7,051,845
1/2/02 7/1/02 $7,853,887 $7,045,460
7/2/02 1/1/03 $7,733,856 $6,937,785
1/2/03 7/1/03 $7,609,025 $6,825,802
7/2/03 1/1/04 $7,479,200 $6,709,341
1/2/04 7/1/04 $7,344,181 $6,588,220
7/2/04 1/1/05 $7,203,763 $6,462,255
1/2/05 7/1/05 $7,057,727 $6,331,252
7/2/05 1/1/06 $6,905,850 $6,195,008
1/2/06 7/1/06 $6,747,898 $6,053,314
7/2/06 1/1/07 $6,583,628 $5,905,953
1/2/07 7/1/07 $6,412,787 $5,752,697
7/2/07 1/1/08 $6,235,112 $5,593,311
1/2/08 7/1/08 $6,050,330 $5,427,550
7/2/08 1/1/09 $5,858,157 $5,255,158
1/2/09 7/1/09 $5,658,298 $5,075,870
7/2/09 1/1/10 $5,450,443 $4,889,411
1/2/10 7/1/10 $5,234,275 $4,695,494
7/2/10 1/1/11 $5,009,460 $4,493,819
1/2/11 7/1/11 $4,775,652 $4,284,078
7/2/11 1/1/12 $4,532,492 $4,065,948
1/2/12 7/1/12 $4,279,606 $3,839,092
7/2/12 1/1/13 $4,016,604 $3,603,161
1/2/13 7/1/13 $3,743,082 $3,357,794
7/2/13 1/1/14 $3,458,619 $3,102,612
1/2/14 $3,162,778 $2,837,222
<PAGE>
SCHEDULE D
DISCLAIMER OF INTEREST
Industrial National Leasing Corporation
c/o Fleet Capital Corporation
50 Kennedy Plaza
Providence, Rhode Island 02903-2305
Industrial National Leasing Corporation, a Massachusetts corporation
("INLC") is about to enter into an Amended and Restated Lease Agreement (the
"Lease Agreement") with Boston Gas Company, a Massachusetts operation ("BGC"),
pursuant to which INLC will lease the property described on Schedule A attached
hereto (the "LNG Facilities") to BGC, the obligations of BGC under the Lease
Agreement are to be secured by the LNG Facilities and any proceeds thereof (the
"Proceeds" as that term is defined in Section 9-306(1) of the Uniform Commercial
Code) (the LNG Facilities and the Proceeds are collectively referred to herein
as the "Collateral"). FCC is unwilling to enter into the Lease Agreement unless
FCC has unencumbered title to or perfected first priority security interests in
the Collateral, free and clear of the security interests, liens, charges or
encumbrances of any other party. In reliance upon the existence of this
Disclaimer of Interest (this "Disclaimer), FCC will enter into the Lease
Agreement. By signing where indicated below, the undersigned creditor
("Creditog") agrees as follows:
1. Disclaimer. Creditor disclaims any present or future security interest
or any other right, title or interest in the Collateral. Creditor shall not, at
any time, assert any interest in any of the Collateral. Creditor agrees that it
will not take any action to bar, restrain or otherwise prevent FCC or any of its
agents, successors or assigns, from inspecting, removing or taking possession of
all or any portion of the Collateral. If Creditor is granted or otherwise
obtains possession of, any right, title or interest in any of the Collateral,
then Creditor shall promptly notify FCC and, in addition to any obligations or
remedies imposed or provided under applicable law, Creditor shall hold such
Collateral in trust for FCC and promptly turn over such Collateral upon FCCs
written request therefor.
2. Form of Obligations Irrelevant. This Disclaimer shall remain in full
force and effect notwithstanding that FCC or Creditor terminates or modifies, by
agreement or otherwise, any of their respective agreements with BGC.
3. Further Assurances; Binding Agreement; Governing Law. Creditor will,
upon the request and at the expense of FCC, execute and deliver to FCC such
further and additional documents as FCC may reasonably deem necessary or
desirable to effect the disclaimer of interest in the Collateral contemplated
hereby, including but not limited to appropriate UCC filings and releases in all
jurisdictions in which Creditor may have perfected security interests in all or
any portion of the
<PAGE>
Collateral. This Disclaimer shall be binding upon, and inure to the benefit of,
the successors and assigns of FCC and Creditor. This Disclaimer shall be
governed by and construed in accordance with the laws of the Commonwealth of
Massachusetts, without reference to its principles of conflict of laws.
CREDITOR:
_____________________________________
By: ______________________________
Name: ______________________________
Title: ______________________________
Date: ______________________________
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our reports dated January 21, 2000, included in this Form 10-K, into Boston Gas
Company's previously filed Registration Statement Form S-3, File No. 33-60199.
Arthur Andersen LLP
Boston, Massachusetts
March 14, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 586,139
<OTHER-PROPERTY-AND-INVEST> 2,547
<TOTAL-CURRENT-ASSETS> 203,018
<TOTAL-DEFERRED-CHARGES> 38,428
<OTHER-ASSETS> 72,760
<TOTAL-ASSETS> 902,892
<COMMON> 51,418
<CAPITAL-SURPLUS-PAID-IN> 43,233
<RETAINED-EARNINGS> 189,517
<TOTAL-COMMON-STOCKHOLDERS-EQ> 284,168
26,454
0
<LONG-TERM-DEBT-NET> 210,000
<SHORT-TERM-NOTES> 31,200
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 74,020
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 14,399
<LEASES-CURRENT> 950
<OTHER-ITEMS-CAPITAL-AND-LIAB> 261,701
<TOT-CAPITALIZATION-AND-LIAB> 902,892
<GROSS-OPERATING-REVENUE> 592,719
<INCOME-TAX-EXPENSE> 24,093
<OTHER-OPERATING-EXPENSES> 513,982
<TOTAL-OPERATING-EXPENSES> 538,075
<OPERATING-INCOME-LOSS> 54,644
<OTHER-INCOME-NET> 1,979
<INCOME-BEFORE-INTEREST-EXPEN> 56,623
<TOTAL-INTEREST-EXPENSE> 16,849
<NET-INCOME> 39,774
1,862
<EARNINGS-AVAILABLE-FOR-COMM> 37,912
<COMMON-STOCK-DIVIDENDS> 27,252
<TOTAL-INTEREST-ON-BONDS> 16,775
<CASH-FLOW-OPERATIONS> 64,928
<EPS-BASIC> 73.73
<EPS-DILUTED> 73.73
</TABLE>
