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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(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, 1998
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>
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ------------------------
<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 February 12, 1999.
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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TABLE OF CONTENTS
<TABLE>
<C> <S> <C>
PART I
Item 1. Business
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Page
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<C> <S> <C>
General.................................................... 1
Markets and Competition.................................... 1
Gas Throughput............................................. 2
Gas Supply................................................. 2
Regulation................................................. 3
Seasonality and Working Capital............................ 4
Environmental Matters...................................... 4
Employees.................................................. 4
Item 2. Properties................................................. 5
Item 3. Legal Proceedings.......................................... 5
Item 4. Submission of Matters to a Vote of Security Holders........ 5
Glossary............................................................. 6
PART II
Market for the Registrant's Common Equity and Related
Item 5. Stockholder Matters....................................... 7
Item 6. Selected Financial Data.................................... 7
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 7
Item 8. Financial Statements and Supplementary Data................ 10
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 10
PART III
Item 10. Directors and Executive Officers of the Registrant......... 11
Item 11. Executive Compensation..................................... 11
Security Ownership of Certain Beneficial Owners and
Item 12. Management................................................ 11
Item 13. Certain Relationships and Related Transactions............. 11
PART IV
Exhibits, Financial Statement Schedules and Reports on Form
Item 14. 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 535,000 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 176 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. The Company also sells gas for resale in
Massachusetts and other states. The Company has one subsidiary, Massachusetts
LNG Incorporated ("Mass LNG"), which retains the right to operate supplemental
gas facilities on the Company's behalf (see Item 2, Properties).
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides both local transportation services and gas supply for
all customer classes under tariffs or contracts approved by the Massachusetts
Department of Telecommunications and Energy, formerly the Department of Public
Utilities ("the Department"). The Company first offered to provide separate,
unbundled sales and transportation services to its largest commercial and
industrial customers in 1993. In December 1996, the Company offered unbundled
transportation service to all of its commercial and industrial customers,
numbering over 41,000. As of December 31, 1998, 4,327 customers have chosen to
purchase gas from 33 qualified third party suppliers. The Company views these
third party suppliers as trade allies in marketing gas and increasing its
throughput and expects to work closely with them to facilitate the unbundling
process and ensure a smooth transition for gas suppliers and customers alike.
The Company expects to implement residential unbundling in 1999. While the
migration of customers from firm sales to transportation-only service will
lower the Company's revenues, it has no impact on the Company's operating
earnings. The Company earns all of its margins on the local distribution of
gas and none on the resale of the commodity itself.
The Company offers both firm and non-firm services. Firm local
transportation services and sales are provided under rate tariffs or contracts
filed with the Department that typically obligate the Company to provide
service without interruption throughout the year and obligate the customer to
pay a level of fixed charges. Non-firm transportation services and sales are
generally provided to large commercial and industrial customers who can use
gas and oil interchangeably. Non-firm services, including sales to other gas
companies for resale, are provided through individually negotiated contracts
and, in most cases, the price charged takes into account the price of the
customer's alternative fuel.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. Over the last six years, the Company has
increased its share in the total stationary energy market from 31% to 37%.
This market share compares to the national level of approximately 44%, 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 by the Company
and customer perceptions of relative value.
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Gas Throughput
The following table, in BCF provides information with respect to the volumes
of gas delivered by the Company during the three years 1996-1998.
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Residential................................... 37.9 41.7 42.8
Commercial and industrial..................... 28.2 35.7 39.4
Off-system sales.............................. 12.7 7.4 12.2
-------- -------- --------
Total sales................................ 78.8 84.8 94.4
Transportation of customer-owned gas.......... 65.6 80.9 61.6
Less: Off-system sales........................ (12.7) (7.4) (12.2)
-------- -------- --------
Total throughput........................... 131.7 158.3 143.8
======== ======== ========
Total firm throughput...................... 107.8 120.0 118.7
======== ======== ========
</TABLE>
The above table excludes the cumulative effect of adopting the accrual
method of revenue recognition as discussed in Note 1 of Notes to Consolidated
Financial Statements. The one-time cumulative effect of this change increased
total firm throughput in 1998 by 5.1 Bcf.
Residential customers comprise 92% of the Company's customer base, while
commercial and industrial establishments account for the remaining 8%.
Volumetrically, residential customers account for 29% of total throughput and
35% of total firm throughput, while commercial and industrial customers
account for 71% of total throughput and 65% of total firm throughput. In 1998,
approximately 70% of commercial and industrial customers' total throughput was
local transportation-only services; Boston Edison Company, an electric utility
on the Company's system, was responsible for approximately 40% of this local
transportation throughput.
No customer, or group of customers under common control, accounted for 2% or
more of total firm revenues in 1998.
Gas Supply
The following table in BCF provides statistical information with respect to
the Company's sources of supply during 1996-1998.
<TABLE>
<CAPTION>
Years Ended December 31,
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1998 1997 1996
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<S> <C> <C> <C>
Natural gas purchases......................... 82.6 87.5 93.9
Liquefied natural gas ("LNG") purchases....... -- 1.4 3.0
-------- -------- --------
Total purchases............................. 82.6 88.9 96.9
Change in storage gas......................... (0.5) 2.2 (3.4)
Company use, unbilled and other............... (3.3) (6.3) .9
-------- -------- --------
Total sales................................. 78.8 84.8 94.4
======== ======== ========
</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 domestic
and Canadian producers and marketers pursuant to long-term contracts which
have been reviewed and approved by the Department or by the Federal Energy
Regulatory Commission ("FERC").
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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 ("Algon-
quin")..................................... 0.28 87.4 1999-2012
Tennessee Gas Pipeline Company
("Tennessee").............................. 0.18 66.9 2000-2012
------- --------
0.46 154.3
======= ========
</TABLE>
In addition, the Company has firm capacity contracts on interstate pipelines
upstream of Algonquin and Tennessee pipelines to transport natural gas
purchased by the Company from producing regions to the Algonquin and Tennessee
pipelines. In total, contracts comprising 59% of the Company's peak day
pipeline capacity entitlements expire before 2001.
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.
Peak day throughput in BCF was 0.65 in 1998, 0.66 in 1997, and 0.69 in 1996.
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. Two additional LNG facilities sited on land owned
by the Company in Salem and Lynn, Massachusetts were subject to a now-expired
lease/financing arrangement, and the Company's right to purchase these
facilities is being litigated (see item 2, Properties). The Company has
developed a contingency plan that would allow it to meet customer requirements
without the Salem and Lynn facilities. 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, 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
state-approved energy efficiency programs, working capital, 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 continue to be governed
by the five year performance-based rate plan approved by the Department in
1996 in the Company's last rate proceeding in D.P.U. 96-50. 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 1.50 percent. The plan also provides for
penalties if the Company fails to meet specified service quality measures,
with a maximum potential exposure of $5 million. There is a margin sharing
mechanism, whereby 25% of earnings in excess of a 15% return on ending equity
are to be passed back to ratepayers. Similarly, ratepayers would absorb 25% of
any shortfall below a 7% return on ending equity. The final year of the plan
is November 1, 2001 through October 31,
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2002. The Company has appealed the Department's order in D.P.U. 96-50 to the
State Supreme Judicial Court. The Company's appeal will focus primarily on the
"accumulated inefficiencies" component of the productivity factor, which
accounts for one percent of the factor, and the penalties for failure to meet
service quality measures. The Company expects a decision next year, and any
relief granted by the court will be prospective.
All of the Company's 41,000 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, 1998, the
Company had 4,327 firm transportation customers. Under the approved service
unbundling program, commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
On July 18, 1997, the Department directed all ten investor-owned gas
distribution companies in Massachusetts to undertake a collaborative process
with other stakeholders to develop common principles under which comprehensive
gas service unbundling might proceed. A settlement on model terms and
conditions for unbundled transportation service jointly entered by the LDC's
and the marketer group was approved by the Department on November 30, 1998. On
February 1, 1999, the Department issued its order on how unbundling of natural
gas services will proceed. For a five year transition period, the Department
determined that 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.
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. The majority of the Company's earnings are generated in the first
quarter with a seasonal loss occurring in the third quarter. 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.
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of former manufactured gas plant ("MGP") sites.
Information with respect to the remediation of MGP 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, 1998, the Company had approximately 1,315 employees, 72%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 1999.
4
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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 outright. Mass LNG owns the real property beneath the Salem and Lynn
facilities and rented the plants under a long-term lease/financing
arrangement. Mass LNG is litigating its purchase rights under the lease. A
stipulation with the lessor of the facilities, which expired on October 1,
1998, allowed Mass LNG to operate the facilities and provided for $2.3 million
to be held in escrow. The Company remains in possession of the facilities
pending the determination of its purchase rights on appeal (see Item 3, Legal
Proceedings).
The Company owns propane-air facilities at various locations throughout its
service territory.
On December 31, 1998, the Company's distribution system included
approximately 5,900 miles of gas mains, 419,000 services and 539,000 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 1998, the Company's capital expenditures were $60.3 million. Capital
expenditures were principally made for improvements to the distribution
system, for system expansion to meet customer demand and for productivity
improvements. The Company plans to spend approximately $61 million for similar
purposes in 1999.
Item 3. Legal Proceedings.
On May 6, 1997, Mass LNG filed suit against Industrial National Leasing
Corp. ("INLC"), a subsidiary of Fleet Bank, in Suffolk Superior Court,
Massachusetts. In dispute is Mass LNG's right to purchase the LNG plants in
Salem and Lynn, Massachusetts under a provision in the lease. The lease
governs the LNG facilities that were constructed by INLC in 1972 (see Item 2,
Properties). Mass LNG holds title to the real property, but as part of the
equipment lease transferred easements to INLC for a term of 25 years, with an
option for INLC to extend the easements for an additional six years. Before
the lease expired on June 30, 1997, INLC extended its easements for six years
and Mass LNG exercised its right to purchase the facilities under Section
17(f) of the lease.
INLC refused to sell the LNG plant pursuant to Section 17(f), and Mass LNG
sued to enforce that purchase right. In June of 1997, Mass LNG and INLC
entered a stipulation that provided for Mass LNG's occupancy of the Salem and
Lynn properties after June 30, and for Mass LNG to pay $2.3 million into an
escrow account. The stipulation expired on October 1, 1998. On July 2, 1998,
the superior court granted INLC's motion for partial summary judgment, and
found that the Section 17(f) purchase option was not available to Mass LNG in
the last six months of the lease. Mass LNG intends to appeal this order, but
the appeal cannot be filed until INLC's counterclaims have been tried and
resolved. A trial date has been set for March of 1999.
Other than the Mass LNG litigation and 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 1998.
5
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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.
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 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
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PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Eastern was the holder of record of all of the outstanding common equity
securities of the Company throughout the year ended December 31, 1998.
Dividends on such common equity amounted to $17.9 million and $18.3 million
for 1998 and 1997, 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
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
retroactive to January 1, 1998 (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. This decrease primarily reflects the impact of warmer weather, higher
depreciation expense reflecting continued investment in system expansion and
replacement and the absence of a $2.0 million gain on the settlement of
pension obligations in 1997. Offsetting were lower operating expenses,
throughput growth and higher average rates. Weather for calendar 1998 was 9%
warmer than normal and 13% warmer than 1997. The decrease in operating costs
primarily reflects weather-related reductions and continued cost control
measures as well as the absence of a 1997 restructuring charge of $8.7
million. The earnings impact of the restructuring charge was essentially
offset by the absence of a 1997 non-recurring revenue increase described
below.
Revenues in 1998 decreased $90.6 million or 13% compared to 1997. This
decrease reflects warmer weather ($45.7 million), the migration of customers
from sales to transportation service ($21.8 million), lower gas costs ($14.9
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.
1997 Compared to 1996
Net earnings applicable to common stock for 1997 were $36.6 million, an
increase of $7.5 million or 26% as compared to 1996. This increase primarily
reflects growth in throughput, lower operating expenses, the full year impact
of the 1996 rate order and a $2.0 million gain on the settlement of pension
obligations, partially offset by the margin impact of lower average customer
usage and warmer weather and a higher charge for depreciation reflecting
continued investment in system replacement and expansion. Weather for 1997 was
3% colder than normal but 2% warmer than 1996. Although weather for 1997 was
2% warmer than 1996, weather for the first quarter of 1997, when the Company
generates most of its revenues and earnings, was 9% warmer than the prior
year. The Company recorded a restructuring charge of approximately $8.7
million in the fourth quarter of 1997, reflecting management's decision to
exit the gas appliance repair and service business (see Note 9 of Notes to
Consolidated Financial Statements). The earnings impact of this non-recurring
charge was offset by a non-recurring increase in revenues as described above.
7
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Revenues in 1997 decreased by 0.6% primarily because of lower average
customer usage, the migration of customers from firm sales to transportation-
only service, and the impact of comparatively warmer weather, partially offset
by sales to new customers and the full year impact of the 1996 rate order.
YEAR 2000 ISSUES
State of Readiness
The Company has assessed the impact of the year 2000 with respect to its
Information Technology ("IT") systems and embedded chip technology systems as
well as the Company's potential exposure to significant third party risks.
Accordingly, the Company has initiated and completed substantial portions of a
plan to replace or modify existing systems and technology as required and to
assure itself that major customers and critical vendors are also addressing
these issues.
With respect to IT systems, the Company has tested and certified as year
2000 ready, five of its eleven "mission critical" business systems. Of the
remaining, two systems were installed in the fourth quarter of 1998 and are
scheduled for certification testing in the first quarter of 1999; one system
is scheduled for installation and testing in the first quarter of 1999; and
the remaining three are scheduled for replacement in the second quarter of
1999. All "less than critical" application systems will be tested and/or
upgraded by the second quarter of 1999. Conversion and testing of all
mainframe hardware and systems software has been completed and the remaining
non-compliant components of the Company's client-server and data/voice
communications infrastructure are scheduled for completion by the first
quarter of 1999. Replacements or remediation of non-compliant E-mail and
desktop hardware and software systems are scheduled for completion by the
second quarter of 1999.
With respect to embedded chip systems, the Company has completed an
inventory, assessment and remediation plan. All remediation, conversion and
testing are scheduled to be completed between the first and third quarters of
1999.
The Company has identified material third party relationships and has
completed a detailed survey of third party readiness. Final data collection
and readiness assessment will be completed by the first quarter of 1999, with
selected testing and implementation of risk mitigation strategies for
significant vendors scheduled for completion by the second quarter of 1999.
However, there can be no assurance that third party systems, on which the
Company's systems rely, will be timely converted or that any such failure to
convert by a third party would not have an adverse effect on the Company's
operations.
Cost of Year 2000 Remediation
The Company expects the cost of year 2000 compliance will approximate $13.5
million. Approximately 65% of these costs will be incurred under capital
projects that have or will result in added functionality while also addressing
year 2000 issues. As of December 31, 1998 approximately $10.2 million of year
2000 compliance costs have been incurred.
Contingency Plans
The Company has initiated the development of a business contingency plan in
the event that one or more of its internal systems, its embedded chip systems,
or its mission critical suppliers' systems experience a year 2000 failure.
Business processes are expected to be prioritized and the impact of year 2000
failure assessed by the end of the first quarter of 1999. Contingency plans
for critical business processes will be developed and tested by the end of the
third quarter of 1999.
Risks of Year 2000 Issues
The Company has assessed the most reasonably likely worst case year 2000
scenario. Given the Company's efforts to minimize the risk of year 2000
failure by its internal systems, the Company believes the worst case scenario
would involve failures by a pipeline supplier or by suppliers of
telecommunications, electricity or
8
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banking services. A short-term interruption in pipeline supplies would require
the utilization of locally-stored liquefied natural gas supplies. A
telecommunication or electric outage would require the Company to implement
business contingency and disaster recovery measures to enable the continuation
of service to its customers. Detailed plans to accommodate this worse case
scenario will be developed and tested as part of the Company's business
contingency planning process.
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 the forward-looking projections or
expectations. These factors include, but are not limited to: the effect of
strategic initiatives on earnings and cash flow, temperatures above or below
normal in the Company's service area, changes in economic conditions,
including interest rates, the timetable and cost for completing the Company's
year 2000 plans, the impact of third parties' year 2000 issues, 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 $75.0 million of Eastern's committed credit
agreement and a $40 million uncommitted line of credit. The Company also
maintains a credit agreement that provides for the borrowing of up to $70.0
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 1999 to be approximately $61
million. Capital expenditures will be largely for improvements to the
distribution system, for system expansion to meet customer demand 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 1999 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
state-approved energy efficiency programs, working capital, 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 continue to be governed
by the five year performance-based rate plan approved by the Department in
1996 in the Company's last rate proceeding in D.P.U. 96-50. 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 1.50 percent. The plan
9
<PAGE>
also provides for penalties if the Company fails to meet specified service
quality measures, with a maximum potential exposure of $5 million. There is a
margin sharing mechanism, whereby 25% of earnings in excess of a 15% return on
ending equity are to be passed back to ratepayers. Similarly, ratepayers would
absorb 25% of any shortfall below a 7% return on ending equity. The final year
of the plan is November 1, 2001 through October 31, 2002. The Company has
appealed the Department's order in D.P.U. 96-50 to the State Supreme Judicial
Court. The Company's appeal will focus primarily on the "accumulated
inefficiencies" component of the productivity factor, which accounts for one
percent of the factor, and the penalties for failure to meet service quality
measures. The Company expects a decision next year, and any relief granted by
the court will be prospective.
All of the Company's 41,000 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, 1998, the
Company had 4,327 firm transportation customers. Under the approved service
unbundling program commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
On July 18, 1997, the Department directed all ten investor-owned gas
distribution companies in Massachusetts to undertake a collaborative process
with other stakeholders to develop common principles under which comprehensive
gas service unbundling might proceed. A settlement on model terms and
conditions for unbundled transportation service jointly entered by the LDC's
and the marketer group was approved by the Department on November 30, 1998. On
February 1, 1999, the Department issued its order on how unbundling of natural
gas services will proceed. For a five year transition period, the Department
determined that 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 Company may have or share responsibility under applicable environmental
law for the remediation of 18 former manufactured gas plant ("MGP") 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 also may have or share responsibility for the remediation
of one non-MGP site. The Company has recorded a liability of $18.8 million,
which represents its best estimate at this time of remediation costs, which
may reasonably be estimated to range from $18.6 million to $36.4 million.
However, there can be no assurance that such costs will not vary considerably
from these estimates.
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 sites over separate, seven-year amortization periods, without a return on
the unamortized balance. The Company has recognized an insurance receivable of
$3.4 million, reflecting a negotiated settlement with an insurance carrier for
environmental expense indemnity, and a regulatory asset of $15.4 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)).*
4.1.1 --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 December
30, 1993 providing for transportation of approximately 83,000 dekatherms of
natural gas per day (Filed as Exhibit 10.2 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1993).*
10.3 --Gas Transportation Contract between the Company and Texas Eastern dated December
30, 1993 providing for transportation of approximately 30,000 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 December 30,
1993 providing for transportation of approximately 48,000 dekatherms of natural
gas per day (Filed as Exhibit 10.4 to the Annual Report of the Company on Form 10-
K for the year ended December 31, 1993).*
10.5 --Gas Transportation Contract between the Company and Algonquin dated December 30,
1993 providing for transportation of approximately 97,000 dekatherms of natural
gas per day (Filed as Exhibit 10.5 to the Annual Report of the Company on Form 10-
K for the year ended December 31, 1993).*
</TABLE>
12
<PAGE>
<TABLE>
<C> <S>
10.6 --Gas Storage Agreement between the Company and Consolidated Gas Supply Corporation
dated February 18, 1980 (Filed as Exhibit 20.3 to the Quarterly Report of the
Company on Form 10-Q for the quarter ended March 31, 1982).*
10.7 --Gas Storage Agreement between the Company and Honeoye Storage Corporation dated
October 11, 1985 (Filed as Exhibit 10.17 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1985).*
10.8 --Gas Storage Agreement between the Company and PennYork Energy Corporation dated
as of December 21, 1984 (Filed as Exhibit 10.18 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1985).*
10.9 --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).*
10.9.1 --Amendment to Exhibit 10.12 dated as of September 28, 1989 (Filed as Exhibit
10.12.1 to the 10.9.1 Annual Report of the Company on Form 10-K for the year ended
December 31, 1989).*
10.9.2 --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 herewith).
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 herewith.)
10.11 --Liquid Purchase Agreement between the Company and Distrigas of Massachusetts
Corporation dated as of April 14, 1989 (Filed as Exhibit 10.14 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1989).*
10.12 --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).*
10.12.1 --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 herewith.)
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).*
10.14 --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 September 1,
1994 providing for transportation of approximately 29,000 dekatherms of natural
gas per day (Filed as Exhibit 10.15 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1997)
</TABLE>
13
<PAGE>
<TABLE>
<C> <S>
10.16 --Gas Transportation Contract between the Company and Algonquin dated September 1,
1994 providing for transportation of approximately 30,000 dekatherms of natural
gas per day (Filed as Exhibit 10.16 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1997)
10.17 --Gas Transportation Contract between the Company and Algonquin dated October 1,
1994 providing for transportation of approximately 72 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, 1997)
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 10.18 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 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)
10.20 --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)
10.21 --Gas Transportation Contract between the Company and Algonquin dated January 1,
1998 providing for transportation of approximately 6,000 dekatherms of natural gas
per day (Filed as Exhibit 10.21 to the Annual Report of the Company on Form 10-K
for the year ended December 31, 1997)
10.22 --Amendment, dated as of January 1, 1998, to Exhibits 10.4 and 10.5, combining gas
transportation contracts between the Company and Algonquin (Filed as Exhibit 10.22
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 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)
10.24 --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)
10.25 --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)
10.26 --Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated
September 1, 1993 providing for transportation of approximately 3,800 dekatherms
of natural gas per day (Filed as Exhibit 10.26 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 Tennessee Gas Pipeline dated
September 1, 1993 providing for transportation of approximately 2,500 dekatherms
of natural gas per day (Filed as Exhibit 10.27 to the Annual Report of the Company
on Form 10-K for the year ended December 31, 1997)
</TABLE>
14
<PAGE>
<TABLE>
<C> <S>
10.28 --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)
10.29 --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)
10.30 --Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated
October 1, 1993 providing for transportation of approximately 3,500 dekatherms of
natural gas per day (Filed as Exhibit 10.30 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1997)
10.31 --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)
10.32 --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)
10.33 --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)
10.34 --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)
10.35 --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)
10.36 --Gas Storage Contract between the Company and Texas Eastern Transmission dated
November 29, 1994 providing for withdrawal demand of approximately 65,000
dekatherms of natural gas per day (Filed as Exhibit 10.36 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1997)
10.37 --Gas Storage Contract between the Company and Texas Eastern Transmission dated
November 29, 1994 providing for withdrawal demand of approximately 3,000
dekatherms of natural gas per day (Filed as Exhibit 10.37 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1997)
10.38 --Gas Transportation Contract between the Company and Texas Eastern Transmission
dated March 23, 1995 providing for transportation of approximately 29,000
dekatherms of natural gas per day (Filed as Exhibit 10.38 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1997)
10.39 --Gas Transportation Contract between the Company and Texas Eastern Transmission
dated May 1, 1996 providing for transportation of approximately 3,000 dekatherms
of natural gas per day (Filed as Exhibit 10.39 to the Annual Report of the Company
on Form 10-K for the year ended December 31, 1997)
</TABLE>
15
<PAGE>
<TABLE>
<C> <S>
10.40 --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)
10.41 --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)
10.42 --Lease Agreement between Industrial National Leasing Corporation, Lessor, and
Massachusetts LNG Incorporated, Lessee, dated as of June 1, 1972 (Filed as an
exhibit to Certificate of Notification by Massachusetts LNG Incorporated (and
others) dated June 9, 1972 (File No. 70-5170)).*
10.43 --Lease Supplement to Exhibit 10.12 between National Leasing Corporation and
Massachusetts LNG Incorporated dated October 19, 1972 (Filed as Exhibit 5.23.1 to
the registration statement of the Company on Form S-7 (File No. 2-52522)).*
10.44 --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).*
10.45 --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 Principal.
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).*
27 --Financial Data Schedule for the twelve months ended December 31, 1998.
27.1 --Restated Financial Data Schedule for the nine months ended September 30, 1998.
27.2 --Restated Financial Data Schedule for the six months ended June 30, 1998.
27.3 --Restated Financial Data Schedule for the three months ended March 31, 1998.
</TABLE>
There were no reports on Form 8-K filed in the Fourth Quarter of 1998.
- --------
* 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
/s/ Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza Senior Vice
President and Treasurer (Principal
Financial and Accounting Officer)
Dated: March 10, 1999
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 10th day of March, 1999.
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 AND SUBSIDIARY
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-17
Consolidated Balance Sheets as of December 31, 1998 and 1997 F-2 and F-3
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1998.............................................. F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1998........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1998.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-16
Interim Financial Information for the Two Years Ended December
31, 1998 (Unaudited)........................................... F-18
Schedule for the Three Years Ended December 31, 1998:
II--Valuation and Qualifying Accounts......................... F-19 to F-21
</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.
Separate financial statements of the Company are omitted because the Company
is primarily an operating company and its subsidiary is wholly-owned and is
not indebted to any person in an amount that is in excess of 5% of total
consolidated assets.
F-1
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
-----------------
1998 1997
-------- --------
(In Thousands)
<S> <C> <C>
Gas plant, at cost........................................... $914,017 $866,784
Construction work-in-progress................................ 11,644 2,715
Less-Accumulated depreciation............................... 368,609 329,918
-------- --------
Net plant................................................... 557,052 539,581
-------- --------
Current assets:
Cash....................................................... 878 307
Accounts receivable, less reserves of $15,651 at December
31, 1998 and $15,783 at December 31, 1997................. 64,258 89,859
Accrued utility margin..................................... 14,147 --
Deferred gas costs......................................... 54,292 66,595
Natural gas and other inventories, at average cost......... 41,375 44,590
Materials and supplies, at average cost.................... 2,852 3,316
Prepaid expenses........................................... 2,255 1,777
-------- --------
Total current assets..................................... 180,057 206,444
-------- --------
Other assets:
Deferred postretirement benefits cost...................... 78,567 83,926
Deferred charges and other assets.......................... 43,483 48,206
-------- --------
Total other assets....................................... 122,050 132,132
-------- --------
Total assets............................................. $859,159 $878,157
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDER'S INVESTMENT
<TABLE>
<CAPTION>
December 31,
-----------------
1998 1997
-------- --------
(In Thousands)
<S> <C> <C>
Capitalization:
Common stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1998 and 1997............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 178,857 152,312
-------- --------
Total common stockholder's investment.................... 273,508 246,963
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized and outstanding--1,200,000 shares at December
31, 1998 and 1997......................................... 29,360 29,326
Long-term obligations, less current portion................. 210,675 211,236
-------- --------
Total capitalization..................................... 513,543 487,525
Gas inventory financing..................................... 48,299 55,502
-------- --------
Total capitalization and gas inventory financing......... 561,842 543,027
-------- --------
Current liabilities:
Current portion of long-term obligations................... 561 507
Notes payable.............................................. 28,900 39,700
Accounts payable........................................... 48,986 61,931
Accrued taxes.............................................. 959 1,392
Accrued income taxes....................................... 10,282 11,174
Accrued interest........................................... 4,414 4,372
Customer deposits.......................................... 2,187 2,360
Refunds due customers...................................... 140 3,136
-------- --------
Total current liabilities................................ 96,429 124,572
-------- --------
Reserves and deferred credits:
Deferred income taxes...................................... 75,981 79,128
Unamortized investment tax credits......................... 5,082 5,931
Postretirement benefits obligation......................... 81,067 83,274
Other...................................................... 38,758 42,225
-------- --------
Total reserves and deferred credits...................... 200,888 210,558
-------- --------
Total liabilities and stockholder's investment........... $859,159 $878,157
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF EARNINGS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Operating revenues.............................. $610,313 $700,945 $705,462
Cost of gas sold................................ 324,538 398,566 414,254
-------- -------- --------
Operating margin................................ 285,775 302,379 291,208
-------- -------- --------
Operating expenses:
Other operating expenses...................... 138,749 148,487 156,105
Maintenance................................... 22,979 22,017 25,045
Depreciation and amortization................. 46,535 44,413 41,607
Income taxes.................................. 23,927 22,510 20,017
Restructuring charge.......................... (1,550) 8,692 --
-------- -------- --------
Total operating expenses...................... 230,640 246,119 242,774
-------- -------- --------
Operating earnings.............................. 55,135 56,260 48,434
Other earnings, net............................. 583 298 564
-------- -------- --------
Earnings before interest expense................ 55,718 56,558 48,998
-------- -------- --------
Interest expense:
Long-term debt................................ 16,767 16,767 16,769
Other, including amortization of debt
expense...................................... 1,248 1,889 1,688
Less--Interest during construction............ (469) (609) (525)
-------- -------- --------
Total interest expense........................ 17,546 18,047 17,932
-------- -------- --------
Net earnings before cumulative effect of change
In accounting principle........................ 38,172 38,511 31,066
Cumulative effect of change in accounting after
tax............................................ 8,193 -- --
-------- -------- --------
Net earnings.................................... 46,365 38,511 31,066
Preferred stock dividends....................... 1,926 1,926 1,926
-------- -------- --------
Net earnings applicable to common stock......... $ 44,439 $ 36,585 $ 29,140
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Balance at beginning of year..................... $152,312 $133,980 $119,546
Net earnings................................... 46,365 38,511 31,066
Preferred stock dividends ($1.61 per share in
1998, 1997
and 1996)..................................... (1,926) (1,926) (1,926)
Cash dividends on common stock ($34.80 per
share in 1998, $35.50 per share in 1997, and
$28.60 per share in 1996)..................... (17,894) (18,253) (14,706)
-------- -------- --------
Balance at end of year........................... $178,857 $152,312 $133,980
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.................................... $ 46,365 $ 38,511 $ 31,066
Adjustments to reconcile net earnings to cash
provided by operating activities:
Depreciation and amortization.................. 46,535 44,413 41,607
Deferred taxes................................. (3,147) 2,851 4,276
Other changes in assets and liabilities:
Accounts receivable........................... 11,454 (13,027) (2,313)
Inventory..................................... 3,679 5,190 (13,190)
Deferred gas costs............................ 12,303 8,742 (3,397)
Accounts payable.............................. (12,945) (11,382) 19,823
Federal and state income taxes................ (892) 21,585 (10,043)
Refunds due customers......................... (2,996) (248) (9,789)
Other......................................... 3,369 4,177 (2,543)
-------- -------- --------
Cash provided by operating activities............ 103,725 100,812 55,497
-------- -------- --------
Cash flows from investing activities:
Capital expenditures........................... (60,266) (55,388) (58,504)
Net cost of removal............................ (5,099) (4,683) (4,124)
-------- -------- --------
Cash used for investing activities............... (65,365) (60,071) (62,628)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. (10,800) (17,300) 5,000
Changes in inventory financing................. (7,203) (92) 9,994
Amortization of preferred stock issuance
costs......................................... 34 34 31
Cash dividends paid on common and preferred
stock......................................... (19,820) (24,550) (12,261)
-------- -------- --------
Cash (used for) provided by financing
activities...................................... (37,789) (41,908) 2,764
-------- -------- --------
Increase (decrease) in cash...................... 571 (1,167) (4,367)
Cash at beginning of year........................ 307 1,474 5,841
-------- -------- --------
Cash at end of year.............................. $ 878 $ 307 $ 1,474
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 18,879 $ 19,704 $ 18,960
Income taxes.................................. $ 34,046 $ 900 $ 26,205
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
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".
The significant accounting policies followed by the Company and its
subsidiary are described below and in the following footnotes:
Note 2--Cost of Gas Adjustment Clause and Deferred Gas Costs
Note 3--Income Taxes
Note 6--Retiree Benefits
Note 7--Leases
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 ("Mass LNG"). 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 and Operations
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 Company's operations are subject to Massachusetts's statutes applicable
to gas utilities. Its revenues, earnings and cash flows are highly seasonal,
as most of its throughput is directly related to temperature conditions.
Regulatory Assets and Liabilities
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.
F-7
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
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>
1998 1997
------- --------
(In Thousands)
<S> <C> <C>
Post-retirement benefit costs........................... $78,567 $ 83,926
Environmental costs..................................... 18,190 18,852
Other................................................... 1,365 1,998
------- --------
$98,122 $104,776
======= ========
</TABLE>
Regulatory liabilities total approximately $9,479,000 and $10,371,000 at
December 31, 1998 and 1997 respectively, and relate primarily to income taxes.
As of December 31, 1998 all of the Company's regulatory assets and
regulatory liabilities are being reflected in rates charged to customers over
periods ranging from 1 to 21 years. For additional information regarding
deferred income taxes, post-retirement benefit costs and environmental costs,
see footnotes 3, 6 and 11, respectively.
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 5.22% in 1998, 5.19% in 1997,
and 5.15% in 1996.
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.
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. As discussed
below, the Company defers the cost of any firm gas that has been distributed,
but is unbilled at the end of a period, to a period in which the gas is billed
to customers. Under the new method, the estimated margin on unbilled revenue
is recorded at the end of each accounting period. The accrual method of
accounting for revenues, that is the recording of unbilled revenues, is
preferable to the billed method and is the prevalent method in the utility
industry. The cumulative effect of this accounting change at January 1, 1998
was to increase net earnings by $8,193,000. The effect of this accounting
change was to increase net earnings before accounting changes by $405,000 for
the year ended December 31, 1998. On a proforma basis, this change would have
increased 1997 net earnings by $1,590,000 and decreased 1996 net earnings by
$52,000.
F-8
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
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 a 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 38.5%
in 1998, 36.9% in 1997, which includes the effect of prior years tax benefits
of 1.8%, and 39.2% in 1996. State taxes represent the majority of the
difference between the effective rate and the Federal income tax rate for
1998, 1997 and 1996.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
<TABLE>
<CAPTION>
1998 1997 1996
------- ------- -------
(In Thousands)
<S> <C> <C> <C>
Current--
Federal.......................................... $21,997 $11,670 $10,154
State............................................ 5,408 2,692 2,004
------- ------- -------
Total current provision........................ 27,405 14,362 12,158
Deferred--
Federal.......................................... (2,119) 6,998 6,489
State............................................ (1,359) 1,150 1,370
------- ------- -------
Total deferred provision....................... (3,478) 8,148 7,859
------- ------- -------
Provision for income taxes......................... $23,927 $22,510 $20,017
======= ======= =======
</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. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.
At December 31, 1998 the Company has a regulatory liability of $2,707,000
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
$6,772,000 as of December 31, 1998.
F-9
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives, as permitted by the Internal Revenue Code.
Deferred federal and state taxes are provided for the tax effects of all
temporary differences between financial reporting and taxable income.
Significant items making up deferred tax assets and deferred tax liabilities
at December 31, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
--------- ---------
(In Thousands)
<S> <C> <C>
Assets:
Unbilled revenues................................... $ -- $ 17,513
Regulatory liabilities.............................. 3,775 4,125
Other............................................... 13,948 15,086
--------- ---------
Total deferred tax assets........................... $ 17,723 $ 36,724
========= =========
Liabilities:
Accelerated depreciation............................ $ (82,985) $ (84,049)
Deferred gas costs.................................. (13,062) (27,418)
Other............................................... (14,231) (14,090)
--------- ---------
Total deferred tax liabilities...................... $(110,278) $(125,557)
--------- ---------
Total net deferred taxes............................ $ (92,555) $ (88,833)
========= =========
</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 $849,000 in 1998, $906,000 in 1997 and $931,000 in 1996.
(4) Commitments
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
<TABLE>
<CAPTION>
December 31,
------------------
1998 1997
-------- --------
(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)..................... 1,236 1,743
Less current portion................................... (561) (507)
-------- --------
$210,675 $211,236
======== ========
</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.
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, 1998 and
none are callable prior to maturity.
Annual maturities of capital lease obligations are $561,000, $620,000 and
$55,000 for 1999 through 2001, respectively.
F-10
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Commitments (Continued)
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 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 $48,299,000 and $55,502,000
of commercial paper outstanding to fund its inventory of gas supplies at
December 31, 1998 and 1997, respectively. Since 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 1998 and 1997.
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 $28,900,000 and $39,700,000 in
commercial paper not related to gas inventory financing at December 31, 1998
and 1997, respectively. The weighted average interest rate on these borrowings
was 5.10% at December 31, 1998 and 6.19% at December 31, 1997.
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, 1999. The interest rate for such borrowings is
a function of federal funds, money market or prime rates. There were no
borrowings outstanding under this uncommitted line at December 31, 1998 and
1997.
(5) Preferred Stock
The Company has outstanding 1,200,000 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.
(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 AND SUBSIDIARY
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 and 1996 has been
restated to conform to the 1998 presentation. The net cost for these plans and
agreements charged to expense was as follows:
Pensions
<TABLE>
<CAPTION>
1998 1997 1996
------- ------- -------
(In Thousands)
<S> <C> <C> <C>
Service cost.................................... $ 2,676 $ 2,838 $ 2,883
Interest cost on projected benefit obligation... 8,490 8,632 8,492
Expected return on plan assets.................. (11,488) (10,925) (9,705)
Amortization of prior service cost.............. 1,048 1,048 1,048
Amortization of transitional obligation......... 217 217 217
Recognized actual gain.......................... (710) (310) (62)
Settlement and curtailment gain................. -- (2,003) --
------- ------- -------
Total net pension cost.......................... $ 233 $ (503) $ 2,873
======= ======= =======
Health Care
<CAPTION>
1998 1997 1996
------- ------- -------
(In Thousands)
<S> <C> <C> <C>
Service cost.................................... $ 828 $ 789 $ 779
Interest cost on accumulated benefits
obligation..................................... 5,726 5,704 5,749
Expected return on plan assets.................. (2,029) (1,523) (1,187)
Amortization of prior service cost.............. (1,190) (1,190) (1,190)
Recognized actuarial gain....................... (761) (484) (426)
Regulatory deferral............................. 5,359 4,637 5,266
------- ------- -------
Total net retiree health care cost.............. $ 7,933 $ 7,933 $ 8,991
======= ======= =======
</TABLE>
The tables above do not reflect retirement enhancements for pension and
health care of $3,224,000 and $143,000 respectively, which were related to the
Company's decision in 1997 to exit the gas appliance repair and service
business.
F-12
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
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, 1998 and 1997 using
actuarial measurement dates of October 1, 1998 and 1997:
<TABLE>
<CAPTION>
Pensions Health Care
------------------ --------------------
1998 1997 1998 1997
-------- -------- --------- ---------
(In Thousands)
<S> <C> <C> <C> <C>
Change in benefit obligation
Balance at beginning of year......... $115,945 $117,729 $ 78,800 $ 78,943
Service cost......................... 2,676 2,838 828 789
Interest cost........................ 8,490 8,632 5,726 5,704
Settlement (gain).................... -- (2,003) -- --
Special termination benefits......... 3,224 -- 143 --
Benefits paid........................ (7,686) (5,771) (5,019) (4,848)
Settlement payments.................. -- (7,234) -- --
Actuarial (gain) or loss............. 2,512 1,754 (3,704) (1,788)
-------- -------- --------- ---------
Balance at end of year............... $125,161 $115,945 $ 76,774 $ 78,800
======== ======== ========= =========
Change in plan assets
Fair value, beginning of year........ 165,857 139,887 23,877 17,919
Actual return on plan assets......... (5,929) 38,975 431 5,958
Employer contributions............... -- -- 5,019 4,848
Benefits paid........................ (7,686) (5,771) (5,019) (4,848)
Settlement payments.................. -- (7,234) -- --
Administrative expenses.............. (47) -- -- --
-------- -------- --------- ---------
Fair value, end of year.............. $152,195 $165,857 $ 24,308 $ 23,877
======== ======== ========= =========
Reconciliation of funded status
Funded status........................ $ 27,034 $ 49,912 $ (52,466) $ (54,923)
Contributions for fourth quarter..... -- -- 1,254 1,214
Unrecognized actuarial (gain)........ (32,120) (52,805) (21,018) (19,538)
Unrecognized transition (asset)...... 437 654 -- --
Unrecognized prior service........... 9,855 10,903 (8,837) (10,027)
-------- -------- --------- ---------
Net amount recognized year end....... $ 5,206 $ 8,664 $ (81,067) $ (83,274)
======== ======== ========= =========
Amounts recognized in balance sheet
Prepaid benefit cost................. $ 8,139 $ 10,312 $ -- $ --
Accrued benefit liability............ (2,933) (1,648) (81,067) (83,274)
-------- -------- --------- ---------
Net amount........................... $ 5,206 $ 8,664 $ (81,067) $ (83,274)
======== ======== ========= =========
</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 AND SUBSIDIARY
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>
1998 1997 1996
--------- ---------- ----------
<S> <C> <C> <C>
Discount rate............................. 7.25% 7.5% 7.5%
Return on plan assets..................... 8.5% 8.5% 8.5%
Increase in future compensation........... 4.5 - 5.0% 4.75 - 5.0% 4.75 - 5.0%
Health care inflation trend............... 8.0% 7.0% 7.0%
</TABLE>
The health care inflation trend is assumed to be 8% in 1999 and decrease
gradually to 5% for 2005. A one-percentage-point increase or decrease in the
assumed health care trend rate for 1998 would have the following effects:
<TABLE>
<CAPTION>
One-Percentage One-Percentage
Point Increase Point Decrease
-------------- --------------
<S> <C> <C>
Service cost and interest cost components.... $ 473 $ (406)
Post-retirement benefit obligation........... $5,851 $(5,044)
</TABLE>
(7) Leases
The Company leases certain facilities and equipment under long-term leases
which expire on various dates through the year 2001. Total rentals charged to
income under all lease agreements were approximately $9,367,000 in 1998,
$10,112,000 in 1997, and $8,418,000 in 1996. The rental charges for 1997 and
1996 include payments under the lease for liquefied natural gas facilities in
Lynn and Salem, Massachusetts that expired June 30, 1997. On May 6, 1997, the
Company filed a civil suit to determine its purchase rights under the lease
(see Item 3 Legal Proceedings). The Company capitalizes its financing leases,
which include an operations center. A summary of property held under capital
leases as of December 31 is as follows:
<TABLE>
<CAPTION>
1998 1997
------ ------
(In
Thousands)
<S> <C> <C>
Buildings..................................................... 6,000 6,000
Less-Accumulated depreciation................................. 4,764 4,,257
------ ------
Total Capital Leases.......................................... $1,236 $1,743
====== ======
</TABLE>
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 AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Leases
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, 1998 is as follows:
<TABLE>
<CAPTION>
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
<S> <C> <C>
1999..................................................... $ 686 $ 5,092
2000..................................................... 687 3,760
2001..................................................... 57 2,603
2002..................................................... -- 1,493
2003..................................................... -- 387
Later Years.............................................. -- 236
------- -------
Total minimum lease payments............................. $ 1,430 $13,571
=======
Less-Amount representing interest and executory costs.... 194
-------
Present value of minimum lease payments on capital
leases.................................................. $ 1,236
=======
</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 for 1998 and 1997 is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands) (In Thousands)
<S> <C> <C> <C> <C>
Cash..................................... $ 878 $ 878 $ 307 $ 307
Short-term debt.......................... $ 77,199 $ 77,199 $ 95,202 $ 95,202
Long-term debt........................... $211,236 $248,341 $211,743 $236,743
Preferred stock.......................... $ 29,360 $ 30,076 $ 29,326 $ 31,525
</TABLE>
F-15
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(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.
(10) Related Party Transactions
The Company paid Eastern $4,200,000 in 1998, $4,300,000 in 1997, and
$4,048,000 in 1996 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 1998
and 1997 the Company paid $775,000 and $752,000 respectively to Eastern
Rivermoor Company, Inc.
(11) Environmental Issues
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") sites. The Company may have or share
responsibility under applicable environmental laws for the remediation of 18
such sites. 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 sites and the non-MGP site in accordance with Statement of
Financial Accounting Standards 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 $18.8 million, which represents its best estimate at this time of
remediation costs, which may reasonably be estimated to range from $18.6
million to $36.4 million. However, there can be no assurance that such costs
will not vary considerably from these estimates. Factors that may bear on
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 21 other former MGP sites within its service
territory. The NEES subsidiary has provided full indemnification to the
Company with respect to eight of these 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 sites over separate, seven-year amortization periods, without a return on
the unamortized balance. The Company has recognized an insurance receivable of
$3.4 million, reflecting a negotiated settlement with an insurance carrier for
MGP-related environmental expense indemnity, and a regulatory asset of $15.4
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 such costs will materially affect its
financial condition or results of operations.
F-16
<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, 1998 and 1997, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our 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, 1998 and 1997 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.
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 20, 1999
F-17
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 1998 (Unaudited)
During the fourth quarter of 1998, the Company changed its method of
accounting for unbilled revenues, retroactively applied as of January 1, 1998
(see Note 1, Accounting Policies). Accordingly, the following table
summarizing the Company's reported quarterly information for the years ended
December 31, 1998 and 1997 has been restated for the periods ending March 31,
June 30 and September 30 of 1998:
<TABLE>
<CAPTION>
Three Months Ended
-----------------------------------
Sept.
March 31 June 30 30 Dec. 31
-------- -------- ------- --------
(In Thousands)
<S> <C> <C> <C> <C>
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
1997
Operating revenues........................ $312,538 $139,743 $57,874 $190,790
Operating margin.......................... $115,079 $ 64,250 $37,027 $ 86,023
Operating earnings (loss)................. $ 31,663 $ 8,709 $(2,021) $ 17,909
Net earnings (loss) applicable to common
stock.................................... $ 26,338 $ 3,894 $(6,495) $ 12,848
</TABLE>
F-18
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
<TABLE>
<CAPTION>
Additions
---------------------
Charged Net
Balance, Charged (Credited) 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 NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes......... $ 79,128 $(3,853) $ 706 $ -- $ 75,981
-------- ------- ----- ------- --------
Deferred investment
tax credits.......... $ 5,931 $ (849) $ -- $ -- $ 5,082
-------- ------- ----- ------- --------
Postretirement benefit
cost................. $ 83,274 $ 2,717 $ -- $ 4,924 $ 81,067
-------- ------- ----- ------- --------
Restructuring
Reserve.............. $ 6,845 $(1,550) $ -- $ 5,295 $ --
-------- ------- ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... $ 2,870 $ 1,873 $ -- $ 1,779 $ 2,964
SFAS 109 Regulatory
Liability........... 3,255 -- -- 548 2,707
Deferred net
normalization
surplus............. 7,116 -- -- 344 6,772
Other................ 28,984 5,186 (750) 7,104 26,316
-------- ------- ----- ------- --------
Total other reserves
and deferred
credits............ $ 42,225 $ 7,059 $(750) $ 9,775 $ 38,759
-------- ------- ----- ------- --------
Total reserves not
deducted from
assets............. $217,403 $ 3,524 $ (44) $19,994 $200,889
======== ======= ===== ======= ========
</TABLE>
F-19
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
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 NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes......... $ 76,277 $ (804) $ 3,655 $ -- $ 79,128
-------- ------- ------- ------- --------
Deferred investment
tax credits.......... $ 6,836 $ (905) $ -- $ -- $ 5,931
-------- ------- ------- ------- --------
Postretirement benefit
cost................. $ 84,827 $ 3,295 $ -- $ 4,848 $ 83,274
-------- ------- ------- ------- --------
Restructuring
Reserve.............. $ -- $ 8,692 $ -- $ 1,847 $ 6,845
-------- ------- ------- ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... $ 2,240 $ 2,461 $ -- $ 1,831 $ 2,870
SFAS 109 Regulatory
Liability........... 3,839 -- -- 584 3,256
Deferred net
normalization
surplus............. 7,606 -- -- 490 7,116
Other................ 11,011 6,546 19,500 8,073 28,984
-------- ------- ------- ------- --------
Total other reserves
and deferred
credits............ $ 24,696 $ 9,007 $19,500 $10,978 $ 42,225
-------- ------- ------- ------- --------
Total reserves not
deducted from
assets............. $192,636 $19,285 $23,155 $17,673 $217,403
======== ======= ======= ======= ========
</TABLE>
F-20
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1996
(In Thousands)
<TABLE>
<CAPTION>
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1995 to Income Accounts Reserves 1996
----------- ------------ ---------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............. $ 15,324 $12,942 $ -- $12,303 $ 15,963
======== ======= ====== ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes......... $ 72,001 $(1,383) $5,659 $ -- $ 76,277
-------- ------- ------ ------- --------
Deferred investment
tax credits.......... $ 7,767 $ (931) $ -- $ -- $ 6,836
-------- ------- ------ ------- --------
Postretirement benefit
cost................. $ 86,589 $ 3,725 $ -- $ 5,487 $ 84,827
-------- ------- ------ ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... $ 2,347 $ 1,931 $ -- $ 2,038 $ 2,240
SFAS 109 Regulatory
Liability........... 4,440 -- -- 601 3,839
Deferred net
normalization
surplus............. 7,951 -- -- 345 7,606
Other................ 9,120 7,054 -- 5,163 11,011
-------- ------- ------ ------- --------
Total other reserves
and deferred
credits............ 23,858 8,985 -- 8,147 24,696
-------- ------- ------ ------- --------
Total reserves not
deducted from
assets............. $190,215 $10,396 $5,659 $13,634 $192,636
======== ======= ====== ======= ========
</TABLE>
F-21
<PAGE>
EXHIBIT 10.10
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Agreement is made as of the 14th day of September, 1987 by and
between Boundary Gas, Inc., a Delaware Corporation (herein called "Boundary"),
and those of the following fifteen (15) United States companies (which
collectively own all of the stock of Boundary) signatory hereto: The Brooklyn
Union Gas Company; Granite State Gas Transmission, Inc.; New Jersey Natural Gas
Company; Boston Gas Company; The Connecticut Light and Power Company;
Consolidated Edison Company of New York, Inc.; National Fuel Gas Supply Corp.;
Long Island Lighting Company; Connecticut Natural Gas Corporation; Essex County
Gas Company; Manchester Gas Company; Gas Service, Inc.; Valley Gas Company;
Berkshire Gas Company; and Fitchburg Gas and Electric Light Co. (herein called
individually "Repurchaser" and collectively "Repurchasers").
W I T N E S S E T H:
WHEREAS, Boundary has been formed by Repurchasers to facilitate the
purchase and importation of gas from Canada, and Boundary has entered into a
certain Phase 2 Gas Purchase Contract ("Purchase Contract") dated September
14th, 1987 which provides for the sale and delivery by TransCanada PipeLines
Limited (herein called "TransCanada") and the purchase by Boundary of
330,070,000 Mcf of gas during a period ending on or before November 1, 1996 with
said quantities of gas to be received by Tennessee Gas Pipeline Company (herein
called "Tennessee") for Boundary's account at or near the existing point of
interconnection between the
<PAGE>
pipeline systems of TransCanada and Tennessee near Niagara Falls, Ontario; and
WHEREAS, TransCanada has received and accepted all necessary permits,
licenses and authorizations to enable TransCanada to export, sell and deliver to
Boundary the quantities of gas specified in the Purchase Contract; and
WHEREAS, Boundary has received and accepted all necessary certificates,
permits, licenses and authorizations to enable Boundary to import, purchase and
accept delivery of the quantities of gas as herein provided, and to resell said
quantities to the Repurchasers signatory hereto; and
WHEREAS, Repurchasers signatory hereto have received, and each in its
sole discretion has accepted, all governmental authorizations necessary to
purchase and accept delivery of all quantities of gas sold by Boundary; and
WHEREAS, Tennessee has received and accepted all necessary
certificates, permits, licenses and authorizations to enable Tennessee to
transport the quantities of gas purchased by Boundary from TransCanada and
resold to Repurchasers; and
WHEREAS, Tennessee has agreed, subject to all necessary authorizations,
to construct or contract for facilities with the capacity to transport the
quantities of gas purchased by Boundary from TransCanada and resold to
Repurchasers; and
-2-
<PAGE>
WHEREAS, Repurchasers signatory hereto have executed or shall within
thirty (30) days hereof execute duly authorized Transportation Contracts with
Tennessee pursuant to which Tennessee agrees to transport for said Repurchasers
the quantities of gas purchased by said Repurchasers from Boundary; and
WHEREAS, it is the intention of the parties that the gas sold by
Boundary to the Repurchasers shall be sold at Boundary's cost including
Boundary's expenses and shall not produce a profit or a loss to Boundary.
NOW, THEREFORE, in consideration of the mutual covenants and benefits
herein contained, it is hereby agreed as follows:
ARTICLE I - DEFINITIONS
-----------------------
All of the terms defined in the Purchase Contract and the Memorandum of
Agreement by and among Repurchasers dated October 6, 1980, as amended April 29,
1983, February 23, 1984 and April 16, 1984 and supplemented May 31, 1985 (herein
called the "Memorandum of Agreement") shall have the same meaning wherever used
in this Agreement.
ARTICLE II - SEVERAL OBLIGATIONS OF REPURCHASERS
------------------------------------------------
The duties, obligations and liabilities of Repurchasers under this
Agreement shall be the several obligations of each Repurchaser and shall not be
the joint or collective obligations of all Repurchasers. No partnership, joint
venture, association or other relationship, other than purchasers from Boundary,
is
-3-
<PAGE>
created by this Agreement. No Repurchaser, as a result of participation in the
sale and purchase of gas under this Agreement, shall be prohibited in any manner
whatsoever from engaging in any business, in any transaction or in any
relationship with any entity.
ARTICLE III - COMMENCEMENT OF DELIVERIES
----------------------------------------
Deliveries of gas by Boundary to the Repurchasers hereunder shall
commence on the date which TransCanada commences deliveries to Boundary pursuant
to the Purchase Contract.
ARTICLE IV - POINT OF DELIVERY
------------------------------
The point at which the gas purchased hereunder is to be delivered by
Boundary to the Repurchasers shall be the point at which TransCanada delivers to
Tennessee for Boundary's account the gas purchased by Boundary pursuant to the
Purchase Contract.
ARTICLE V - TRANSPORTATION ARRANGEMENTS
---------------------------------------
Repurchasers acknowledge that Boundary owns and operates no facilities
and has no capacity or obligation to transport gas for any Repurchaser. Each
Repurchaser shall be responsible for entering into and maintaining for the term
of this Agreement the necessary arrangements with Tennessee (or other
appropriate companies) for transportation of the volumes of gas purchased by the
Repurchaser from Boundary under this Agreement.
-4-
<PAGE>
ARTICLE VI - TERM
-----------------
This Agreement shall be effective from November 1, 1987 and shall remain
in full force and effect for the entire term and duration of the Purchase
Contract.
ARTICLE VII - SALE AND PURCHASE OF GAS
--------------------------------------
1. Boundary shall sell and deliver to Repurchasers all (100%) of the
gas purchased by Boundary from TransCanada. Boundary's sale and delivery to each
Repurchaser of said Repurchaser's respective share of the gas (as set forth
below) shall be deemed to occur simultaneously with Tennessee's receipt for
Boundary's account of the gas purchased by Boundary for resale to that
Repurchaser.
2. Subject to the provisions of Article VIII below, each Repurchaser
shall be entitled to purchase and accept delivery from Boundary of the following
shares ("Percentage Entitlements") of the gas purchased by and delivered to
Boundary pursuant to the Purchase Contract:
Percentage
Repurchaser Entitlement
----------- -----------
The Brooklyn Union Gas Company ............. 32.40
Granite State Gas
Transmission, Inc. ........................ 13.51
New Jersey Natural Gas Company ............. 11.63
Boston Gas Company ......................... 11.31
The Connecticut Light and Power
Company ................................... 10.23
Consolidated Edison Company of
New York, Inc. ............................ 5.40
National Fuel Gas Supply Corp. ............. 2.70
-5-
<PAGE>
Long Island Lighting Company................ 2.70
Connecticut Natural Gas
Corporation............................... 2.16
Essex County Gas Company.................... 1.74
Manchester Gas Company...................... 1.68
Gas Service, Inc............................ 1.68
Valley Gas Company.......................... 1.15
Berkshire Gas Company....................... 1.14
Fitchburg Gas and Electric
Light Co.................................. 0.57
3. It is understood and agreed that each Repurchaser will be
scheduled to receive on a daily basis as its Scheduled Daily Delivery its entire
Percentage Entitlement of the Daily Contract Quantity of gas being purchased by
Boundary from TransCanada pursuant to the Purchase Contract. Each Repurchaser
must notify Boundary or Boundary's designee at least one (1) day in advance if
it is unable or does not intend to take its entire Scheduled Daily Delivery as
aforesaid on any day.
4. Notwithstanding the foregoing provisions of this Article VII, it
is understood that under the Purchase Contract, for the period from November 1,
1987 through October 31, 1988, the Daily Contract Quantity shall be a quantity
(not less than 40,000 Mcf of gas per day nor more than 90,000 Mcf of gas per
day) as mutually agreed to by Boundary and TransCanada until such time as the
facilities required for delivery by TransCanada, receipt by Tennessee and
receipt by the Repurchasers of 90,000 Mcf of gas per day are constructed,
installed and made available, at which time the Daily Contract Quantity shall be
a quantity of 90,000 Mcf of gas per day and that, beginning November 1, 1988,
the Daily Contract Quantity shall be a quantity of 92,500 Mcf of gas per day
provided that the facilities required for delivery by Seller,
-6-
<PAGE>
receipt by Tennessee and receipt by the Repurchasers of 92,500 Mcf of gas per
day are constructed, installed and made available. It is agreed that, during
such period when the Daily Contract Quantity is a quantity of less than 92,500
Mcf of gas per day, National Fuel Gas Supply Corporation shall not be entitled
to purchase and accept delivery of gas from Boundary and each other Repurchaser
shall be entitled to purchase and accept delivery from Boundary of a share of
the gas purchased by and delivered to Boundary pursuant to the Purchase Contract
determined by dividing the Percentage Entitlement of such Repurchaser by the sum
of the Percentage Entitlements of all Repurchasers except National Fuel Gas
Supply Corporation (such share to be such Repurchaser's Percentage Entitlement
during such period for all purposes of this Agreement except Section 2. of
Article IX).
ARTICLE VIII - ENTITLEMENT REDUCTION
------------------------------------
1. Repurchasers recognize that Boundary's Daily Contract Quantity
under the Purchase Contract is subject to reduction by TransCanada in
circumstances set forth therein. It is understood that any reduction by
TransCanada of Boundary's Daily Contract Quantity under the Purchase Contract
shall be borne by those Repurchasers whose actions caused or resulted in said
reduction, as determined by Section 2. of this Article VIII.
2. If Boundary fails to take the Annual Triggering Quantity (as
defined in the Purchase Contract) in any contract year ("Year 1") and Boundary
fails to take the Required Quantity (as defined in the Purchase Contract) in the
succeeding contract
-7-
<PAGE>
year ("Year 2") and TransCanada elects to reduce Boundary's Daily Contract
Quantity under the Purchase Contract, the Percentage Entitlement of each
Repurchaser which during Year 1 failed to take its Annual Triggering Quantity
(as hereinafter defined) for that contract year shall be subject to reduction.
The "Annual Triggering Quantity" for each Repurchaser means the product obtained
by multiplying that Repurchaser's Percentage Entitlement times the total Daily
Contract Quantity under the Purchase Contract times the number of days in the
relevant contract year times 0.60, which product shall be adjusted to reflect
the difference, if any, between the volume requested by that Repurchaser and the
actual volume delivered on any day by Boundary to that Repurchaser, if less than
the volume requested as its Scheduled Daily Delivery, as the same occurs from
time to time during the relevant contract year. In the event that a Repurchaser
accepts volumes of gas released by another Repurchaser pursuant to Article XI
hereof, sixty percent (60%) of the volumes so accepted shall be added to the
accepting Repurchaser's Annual Triggering Quantity and deducted from releasing
Repurchaser's Annual Triggering Quantity (with an appropriate adjustment for gas
requested but not delivered). Any reduction in Boundary's Daily Contract
Quantity under the Purchase Contract shall be allocated as reductions in the
Percentage Entitlement of each Repurchaser which failed to take its Annual
Triggering Quantity in Year 1 as follows:
(a) The difference between each such Repurchaser's Annual Triggering
Quantity in Year 1 and the volumes of gas
-8-
<PAGE>
actually purchased during Year 1 shall be deemed to be such
Repurchaser's "Year 1 Volume Deficiency."
(b) The difference between each such Repurchaser's Annual Triggering
Quantity in Year 2 plus its Year 1 Volume Deficiency and the
volumes of gas actually purchased during Year 2 shall be deemed
to be such Repurchaser's "Year 2 Volume Deficiency," except that,
in the event that such calculation results in a negative number,
the Year 2 Volume Deficiency shall be deemed to be zero and in
the event that such calculation results in a number greater than
the Year 1 Volume Deficiency, the Year 2 Volume Deficiency shall
be deemed to be equal to the Year 1 Volume Deficiency.
(c) The sum of each such Repurchaser's Year 1 Volume Deficiency and
Year 2 Volume Deficiency shall be deemed to be such Repurchaser's
"Total Volume Deficiency."
(d) The total Volume Deficiency of each such Repurchaser shall be
divided by the Total Volume Deficiencies of all such Repurchasers
to determine each such Repurchaser's proportionate share of the
reduction in Boundary's Daily Contract Quantity, and the
Percentage Entitlement of each such Repurchaser shall be reduced
by its proportionate share of such reduction in Boundary's Daily
Contract Quantity.
-9-
<PAGE>
Upon determination of the allocation of the reduction in Boundary's Daily
Contract Quantity, the respective Percentage Entitlements of all Repurchasers
shall be adjusted to reflect the relative interests in the reduced Daily
Contract Quantity, and the Memorandum of Agreement and this Agreement shall be
amended accordingly.
ARTICLE IX - PRICE; REPURCHASER PAYMENT OBLIGATIONS
---------------------------------------------------
1. It is understood that, pursuant to Article VII of the
Purchase Contract, the base price to be paid by Boundary to TransCanada for each
1,000,000 Btus contained in the gas delivered to Boundary by TransCanada under
the Purchase Contract shall consist of a demand charge and a seasonal commodity
charge and that the base price shall be indexed to a weighted average of
alternate fuel prices. It is further understood that, pursuant to Article VIII
of the Purchase Contract, the amount due by Boundary to TransCanada for gas
service during any contract month shall be billed to Boundary monthly by
TransCanada and shall consist of the Monthly Demand Charge and the Commodity
Charges per MMBtu of gas actually delivered during the contract month.
Consistent with the foregoing, the amount to be paid by Repurchasers to Boundary
for gas service under this Agreement shall be determined as follows:
Repurchasers in the aggregate shall pay to Boundary an amount equal to the
amount billed to Boundary by TransCanada for gas service during each contract
month. The portion to be paid by each Repurchaser to Boundary shall be equal to
the sum of (1) the product of the Monthly Demand Charge billed to Boundary by
-10-
<PAGE>
TransCanada times such Repurchaser's Percentage Entitlement and (2) the product
of the Commodity Charges billed to Boundary by TransCanada times a fraction, the
numerator of which is the quantity of gas delivered by Boundary to such
Repurchaser during such contract month and the denominator of which is the
quantity of gas delivered by Boundary to all Repurchasers during such contract
month. For purposes of the calculation in clause (1) of the preceding sentence,
the Percentage Entitlements of each Repurchaser which takes gas pursuant to
Article XI, Section 1. (or releases gas which is so taken) shall be increased
(or decreased, as appropriate) by an amount equal to the ratio of the total
volume of gas taken (or released) by such Repurchaser during such contract month
to the product of Boundary's Daily Contract Quantity under the Purchase Contract
times the number of days in such contract month. It is further understood that
pursuant to Article VIII of the Purchase Contract any differential caused by
fluctuations in the exchange rate between the amount billed to Boundary by
TransCanada for gas service during any contract month and the amount paid by
Boundary to TransCanada for that contract month shall be reflected as a credit
or debit to the amount billed to Boundary by TransCanada for gas service during
the succeeding contract months. Consistent with the foregoing, any such credit
or a debit shall be allocated to each Repurchaser in the proportion that the
amount paid by that Repurchaser bears to the total amount paid by Boundary for
the contract month for which there was the differential resulting in the credit
or debit.
-11-
<PAGE>
2. In addition to the amount payable by Repurchasers under Section
1. above, Repurchasers shall pay to Boundary all costs and expenses incurred by
Boundary in any contract month in performing this Agreement and the Purchase
Contract, including but not limited to all administrative and operating
expenses, legal fees and all taxes, including franchise taxes, sales taxes,
import duties and other taxes, duties and the like, if any, payable by Boundary
during such contract month. Each Repurchaser's shares, if any, of Boundary's
costs and expenses shall be determined by Boundary as follows:
(i) costs and expenses incurred by Boundary in any contract month
which are not directly related to the quantity of gas delivered
by Boundary to Repurchasers in that contract month shall be
allocated among all Repurchasers on the basis of their Percentage
Entitlements;
(ii) costs and expenses incurred by Boundary in any contract month
which are directly related to the quantity of gas delivered by
Boundary to Repurchasers in that contract month shall be
allocated to each Repurchaser in the proportion that the gas
delivered to that Repurchaser in such contract month bears to the
total quantity of gas delivered to all Repurchasers in such
contract month;
-12-
<PAGE>
(iii) interest expenses payable by Boundary to TransCanada in any
contract month pursuant to Article VIII of the Purchase
Contract due to late payment by Boundary shall be paid in full
by the Repurchaser(s) whose late payment to Boundary caused
such interest expenses to be incurred; and
(iv) costs and expenses incurred by Boundary in any contract month
in connection with regulatory or legal proceedings instituted
or joined in by Boundary on behalf of one or more (but not all)
Repurchasers shall be allocated to each such Repurchaser in the
proportion that its Percentage Entitlement bears to the total
Percentage Entitlements of all such Repurchasers; provided,
however, that in no event shall any costs and expenses incurred
in connection with regulatory or legal proceedings involving
cancellation of a Repurchaser's rights under this Agreement be
allocated under this subsection (iv) to the Repurchaser whose
rights are sought to be cancelled.
Boundary may include in its invoice to each Repurchaser for any contract month
that Repurchaser's share (determined in accordance with this Section 2.) of
costs and expenses which Boundary has determined will be incurred by Boundary in
the next succeeding contract month. When costs and expenses are prepaid in
accordance with this Section 2., the invoice to each Repurchaser for the next
-13-
<PAGE>
succeeding contract month shall nevertheless show that Repurchaser's share of
the costs and expenses actually incurred in that contract month but shall also
show a proper credit for the prepayment.
3. In addition to the amounts payable by Repurchasers under Sections
1. and 2. above, Boundary may assess each Repurchaser amounts determined
pursuant to Paragraph 2.5 of the Memorandum of Agreement.
4. In no event shall the amounts paid by Repurchasers to Boundary
pursuant to this Article IX result in either a profit or a loss to Boundary.
5. It is agreed that Boundary shall have the right to propose and to
file with appropriate United States regulatory authorities changes in the price
and provisions set forth in this Article, and the rate schedule and general
terms and conditions of Boundary's Gas Tariff imposed by United States
regulatory authorities; provided, however, that Repurchasers shall have the
right to approve or disapprove the selection of a new price regime, index or
formula under the Purchase Contract in accordance with Paragraph 2.7 of the
Memorandum of Agreement, to protest any such changes before the appropriate
United States regulatory authorities and to exercise any other rights which they
may have with respect thereto; and provided further that Boundary, prior to
proposing or filing any such changes, shall first have obtained the written
consent of TransCanada to such changes.
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<PAGE>
ARTICLE X - PAYMENTS
--------------------
1. Boundary shall render a monthly invoice to each Repurchaser for
all amounts due under Sections 1., 2. and 3. of Article IX of this Agreement
promptly after receipt by Boundary of its monthly statement from TransCanada for
gas service under the Purchase Contract.
2. (a) It is understood that each month Boundary may authorize one
or more suitably qualified financial institutions with which Boundary has
entered into a Forward Cover Agreement approved in writing by TransCanada and
the Repurchasers ("Approved Institutions") to effect delivery of Canadian
dollars to TransCanada on the Due Date ("Forward Cover"). Boundary's monthly
invoice to each Repurchaser shall include such Repurchaser's share of the total
amount due in United States dollars for the Forward Cover arranged by Boundary
during the month ("Forward Cover Sum").
(b) Each Repurchaser shall have the right in good faith to dispute
the amount of any invoice for such Repurchaser's proportionate share of the
Forward Cover Sum. Any Repurchaser raising such a dispute ("Responsible
Repurchaser") shall by noon Eastern Standard Time two business days prior to the
Due Date give Boundary notice of such dispute, stating the amount in dispute and
Boundary shall direct the Approved Institution(s) to adjust Forward Cover
accordingly. Promptly thereafter, Boundary shall give each Responsible
Repurchaser notice of such Repurchaser's share of the amount of the Forward
Cover Sum as adjusted ("Adjusted Forward Cover Sum"). After receipt of a
statement or
-15-
<PAGE>
statements setting forth the amount of transactional proceeds or costs of
adjusting Forward Cover ("Transaction Amount"), Boundary shall set forth on the
invoice transmitted in the succeeding month to each Responsible Repurchaser such
Repurchaser's share of the Transaction Amount. In the event that adjustment of
Forward Cover results in a Transaction Amount reflecting transactional costs,
the invoice rendered by Boundary the succeeding month to each Responsible
Repurchaser shall set forth such Repurchaser's share of the Transaction Amount
and payment shall be made by the Responsible Repurchaser to Boundary on or
before the due date indicated on that invoice. In the event that adjustment of
Forward Cover results in a Transaction Amount reflecting transactional proceeds,
the invoice rendered by Boundary the succeeding month to each Responsible
Repurchaser shall set forth such Repurchaser's share of the Transaction Amount
and payment shall be made by Boundary to the Responsible Repurchaser within
thirty days of the invoice date.
(c) Payment by each Repurchaser of such Repurchaser's share of the
Forward Cover Sum (or, in the event of a dispute, such Repurchaser's share of
the Adjusted Forward Cover Sum) shall be made before 11:00 a.m. Eastern Standard
Time on the Due Date to the Escrow Agent designated by Boundary pursuant to the
Escrow Agreement between Boundary, TransCanada and Chemical Bank dated March 6,
1984, as amended and supplemented. In the event that a Repurchaser fails to make
payment to the Escrow Agent of its share of the Forward Cover Sum (or, in the
event of a dispute, its share of the Adjusted Forward Cover Sum), or any portion
thereof, when
-16-
<PAGE>
same is due, interest thereon shall accrue at a rate of interest to be
determined in accordance with the applicable Forward Cover Agreements over the
period of time during which payment is past due, until same is paid, and any
late deposit shall include such interest as has accrued.
3. (a) In any month in which Boundary does not effect Forward Cover
pursuant to a Forward Cover Agreement or there is no such effective Forward
Cover Agreement, Boundary's monthly invoice to each Repurchaser shall include
such Repurchaser's share of the U.S. Sum, as defined in Article VIII, Section
1(c) (ii) of the Purchase Contract. Payment by each Repurchaser of such
Repurchaser's share of the U.S. Sum shall be made before 11:00 a.m. Eastern
Standard Time on the Due Date to the Escrow Agent designated by Boundary
pursuant to the Escrow Agreement between Boundary, TransCanada and Chemical Bank
dated March 6, 1984, as amended and supplemented.
(b) Each Repurchaser shall have the right in good faith to dispute
the amount of any invoice for such Repurchaser's proportionate share of the U.S.
Sum. Any Repurchaser raising such a dispute ("Responsible Repurchaser") shall
pay to the Escrow Agent such amounts as it concedes to be correct and Boundary
shall promptly declare a dispute to TransCanada in accordance with Section 2. of
Article VIII of the Purchase Contract. After a final determination of the amount
properly due and owing by Boundary to TransCanada, each Responsible Repurchaser
shall promptly pay to the Escrow Agent its share of the amount, if any, found to
be due.
-17-
<PAGE>
If, as a result of a dispute raised as aforesaid, Boundary is required to
furnish any surety bond to TransCanada, such surety bond shall be furnished
timely and directly to TransCanada by the Responsible Repurchaser.
4. On or before the Due Date, payment by each Repurchaser of the
amounts due under Sections 2. and 3. of Article IX shall be made to Boundary.
Each Repurchaser shall have the right in good faith to dispute such amounts. The
Repurchaser declaring the dispute shall pay to Boundary the full amount of the
invoice which is, in whole or in part, the subject of the dispute. Any amount
later determined not to be due to Boundary by any Repurchaser shall be
reimbursed to such Repurchaser by Boundary or, where appropriate, by such other
Repurchaser(s) as are determined to owe the amount which has been disputed.
5. If the correct amounts are not paid by any Repurchaser when due,
Boundary shall, upon twelve (12) hours prior notice to such Repurchaser, have
the right to discontinue immediately deliveries of gas to such non-paying
Repurchaser and to make such gas available as excess gas to the other
Repurchasers in accordance with Article XI below; provided, however, that
Boundary shall not discontinue such deliveries without first having obtained the
written consent of TransCanada, and Boundary shall not make such gas available
as excess gas without first having given written notice to TransCanada. The
normal scheduled delivery to such non-paying Repurchaser shall not be
reinstituted until such Repurchaser pays all amounts due but, in any case, the
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<PAGE>
right of the non-paying Repurchaser to any amount of gas discontinued and made
available as excess gas shall not be restored. If the default should continue
for thirty (30) days after notice of default from Boundary to the non-paying
Repurchaser, Boundary may cancel the rights of the non-paying Repurchaser in
accordance with Article XII; provided, however, that no such cancellation shall
be effected by Boundary without first having obtained the written consent of
TransCanada. A decision by Boundary to withhold gas from a non-paying
Repurchaser shall in no event reduce that Repurchaser's Annual Triggering
Quantity for that contract year except to the extent that, if other Repurchasers
agree to take such withheld gas as available excess gas, sixty percent (60%) of
the volumes of gas so taken shall be added to the taking Repurchasers' Annual
Triggering Quantities and deducted from the non-paying Repurchaser's Annual
Triggering Quantity.
6. Repurchasers shall have the right to audit the books and accounts
of Boundary for purposes of determining the accuracy and sufficiency of the
amounts charged to Repurchasers hereunder. In the event an error is discovered
in any invoice rendered by Boundary, said error shall be adjusted in a
subsequent invoice or with a credit or debit memo.
ARTICLE XI - AVAILABLE EXCESS GAS
---------------------------------
1. As provided in Article VII above, each Repurchaser will be
scheduled to receive on a daily basis its entire Percentage Entitlement of the
contract quantity of gas purchased by Boundary from TransCanada pursuant to the
Purchase Contract. Each
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<PAGE>
Repurchaser must notify Boundary at least one (1) day in advance if it is unable
or does not intend to take its scheduled delivery on any day. If any
Repurchaser elects not to take, or fails to take its scheduled quantity of gas,
such quantities of gas as that Repurchaser does not take shall (subject to any
limitations in the certificate of public convenience and necessity governing
Boundary's sales hereunder) be offered by Boundary to the other Repurchasers in
proportion to their respective Percentage Entitlements. However, the Annual
Triggering Quantity of any Repurchaser who elects not to take or fails to take
such gas shall not be reduced except to the extent that, if other Repurchasers
agree to take such available excess gas, sixty percent (60%) of the volumes so
taken shall be added to the taking Repurchasers' Annual Triggering Quantities
and deducted from the Annual Triggering Quantity of the Repurchaser which
elected not to take or failed to take the gas.
2. In the event that Excess Gas is made available by TransCanada to
Boundary pursuant to Sections 6. and 7. of Article II of the Purchase Contract,
Boundary shall promptly notify all Repurchasers of the availability of such
Excess Gas; provided, however, that Boundary shall give such notice at least
three (3) days in advance of the day on which such Excess Gas is intended to be
delivered. Once such notice has been given by Boundary, such Excess Gas shall be
treated for purposes of this Article XI as if it were a part of the contract
quantity. Consistent with that treatment, each Repurchaser will be scheduled to
receive its entire Percentage Entitlement of such Excess Gas and must notify
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<PAGE>
Boundary at least one (1) day in advance if it is unable or does not intend to
take its scheduled share of Excess Gas. If any Repurchaser elects not to take,
or fails to take its scheduled quantity of Excess Gas, such quantity of Excess
Gas as that Repurchaser does not take shall be offered by Boundary to the other
Repurchasers in proportion to their respective Percentage Entitlements;
provided, however, that in no event shall any Repurchaser's Annual Triggering
Quantity under this Agreement be increased as a result of its acceptance or
rejection of such Excess Gas.
3. In the event that additional gas becomes available due to an
amendment to the Purchase Contract (approved, as necessary by all appropriate
regulatory authorities) which increases the contract quantity of gas, and one or
more Repurchasers elect not to take all or part of their share of the increase
in quantity, the available excess gas resulting from such election shall be made
available to the other Repurchasers in proportion to their respective Percentage
Entitlements. Upon determination of which Repurchasers will take such available
excess gas, the respective Percentage Entitlements of all Repurchasers shall be
adjusted to reflect the relative interests in the total amended contract
quantity, and the Memorandum of Agreement and this Agreement shall be amended
accordingly.
ARTICLE XII - CANCELLATION OF RIGHTS OF A DEFAULTING REPURCHASER
----------------------------------------------------------------
In the event a Repurchaser ("Defaulting Repurchaser") fails to pay all
amounts due for gas service under this Agreement,
-21-
<PAGE>
and such failure continues for thirty (30) days after notice of default from
Boundary, Boundary may, at its option and after receipt and acceptance of any
necessary regulatory approvals, and after first having obtained the written
consent of TransCanada, cancel the rights of the Defaulting Repurchaser under
this Agreement and the Memorandum of Agreement. Boundary shall exercise its
option to cancel and shall accept the regulatory approval(s) received in
connection with such cancellation only upon the affirmative vote of 60% of the
issued and outstanding Common Stock of Boundary; provided, however, that the
shares of Common Stock held by the Defaulting Repurchaser shall be deemed to be
voted against exercise of the option to cancel and acceptance of related
regulatory approval(s). Upon exercise by Boundary of its option to cancel (after
first having obtained the written consent of TransCanada) and after receipt and
acceptance by Boundary of all necessary regulatory approvals, the Defaulting
Repurchaser shall offer to assign all of its rights, title and interest in
Boundary to the remaining Repurchasers in proportion to their respective
Percentage Entitlements or in such other proportion as may be agreed upon by the
remaining Repurchasers. No remaining Repurchaser shall be obligated to accept
any assignment from the Defaulting Repurchaser. Any remaining Repurchaser
desiring to accept an assignment from the Defaulting Repurchaser but requiring
regulatory authorization to do so shall be given a reasonable opportunity to
obtain the necessary authorization. In the event that the remaining Repurchasers
accept assignment of less than all of the Defaulting Repurchaser's rights, title
and interest in
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<PAGE>
Boundary, cancellation of the Defaulting Repurchaser's rights under this
Agreement and the Memorandum of Agreement shall be effective only to the extent
that assignments have been accepted. As to any rights, title and interest of the
Defaulting Repurchaser not assigned to the remaining Repurchasers, the
Defaulting Repurchaser shall to that extent remain a party to this Agreement and
the Memorandum of Agreement. Upon any assignment pursuant to this Article XII,
the respective Percentage Entitlements of all Repurchasers shall be adjusted to
reflect the assignment, and this Agreement and the Memorandum of Agreement shall
be amended accordingly. Exercise of the rights of Boundary under this Article
XII shall not be in lieu of or extinguish any other rights, remedies or causes
of action Boundary may have in law or in equity against the Defaulting
Repurchaser arising from or relating to the default.
ARTICLE XIII - BANKRUPTCY
-------------------------
If a Repurchaser should file a voluntary petition in bankruptcy or for
reorganization pursuant to any provision of the United States Bankruptcy Act, as
now existing or as hereafter amended, or pursuant to any other statute
applicable to such Repurchaser, or should such Repurchaser consent to the
appointment of a receiver or liquidator of such Repurchaser or of any
substantial portion of its assets, or if there should be filed a petition in
bankruptcy or reorganization, for liquidation or receivership, against such
Repurchaser pursuant to any provisions of any of said statutes and such petition
is not dismissed within
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<PAGE>
sixty (60) days after the date of such filing, then and in any of such events
Boundary shall, unless otherwise prohibited by law, have the right to terminate
such Repurchaser's participation in this Agreement by notice delivered to such
Repurchaser, whereupon all of the rights and obligations of Boundary and such
Repurchaser hereunder to each other shall cease and terminate, except with
respect to any rights and obligations accruing prior to the date of said
termination, and such Repurchaser's interest in Boundary shall be disposed of in
the same manner as specified in Article XII hereof.
ARTICLE XIV - TRANSFER OF INTERESTS
-----------------------------------
Any Repurchaser may assign all or any part of its interest in, or rights
under this Agreement; provided, however, that no assignment of this Agreement or
of any of a Repurchaser's rights hereunder shall be made by a Repurchaser unless
such Repurchaser also transfers to the assignee an interest in such
Repurchaser's stock in Boundary equal to the Percentage Entitlement of gas under
this Agreement being transferred to such assignee and such assignee first
ratifies and becomes a party to the Memorandum of Agreement and this Agreement.
In addition, any Repurchaser may sell, transfer or assign all or any part of its
shares of stock in Boundary; provided, however, that no Repurchaser shall sell,
assign or transfer any of its shares of stock in Boundary unless the purchaser,
assignee or transferee thereof first ratifies and becomes a party to the
Memorandum of Agreement and this Agreement. Upon such sale, transfer or
assignment, this Agreement and the
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<PAGE>
Memorandum of Agreement shall, subject to the provisions of Article XIX hereof,
be amended to reflect such action. To the extent that any sale, transfer or
assignment proposed to be made pursuant to this Article XIV requires regulatory
authorization, such sale, transfer or assignment shall not be effected until all
necessary regulatory authorizations have been received and accepted. In the
event regulatory authorization for a sale, transfer or assignment pursuant to
this Article XIV is required to be obtained by Boundary, Boundary shall seek
diligently to obtain such authorization and, upon its receipt, the decision of
Boundary whether to accept such authorization shall be determined by a vote of
60% of the issued and outstanding Common Stock of Boundary. The provisions of
this Article XIV shall not be deemed to apply to any pledge of, or grant of a
security interest in, this Agreement or shares of stock in Boundary by a
Repurchaser in connection with any borrowing by, or indebtedness of, such
Repurchaser or any corporate affiliate thereof (i.e., a corporation owning,
----
owned by, or under common control with such Repurchaser); provided, however,
that any interest in said shares or this Agreement transferred pursuant to
foreclosure under such pledge or security interest shall continue to be subject
to the provisions of the Memorandum of Agreement and this Agreement and any
transferee thereunder shall be deemed to be substituted in the Memorandum of
Agreement and this Agreement for the Repurchaser which granted such pledge or
security interest.
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<PAGE>
ARTICLE XV - PRESSURE MEASUREMENT AND OUALITY OF GAS
-----------------------------------------------------
The pressure and quality of gas to be sold hereunder shall be in
accordance with the standards of pressure and quality set forth in the Purchase
Contract for gas to be sold thereunder. The measurement of gas sold under the
Purchase Contract shall be used to determine the volumes of gas sold under this
Agreement.
Any information obtained by Boundary pursuant to the provisions of the
Purchase Contract with respect to measurement and quality of the gas sold under
the Purchase Contract shall be promptly transmitted by Boundary to the
Repurchasers.
ARTICLE XVI - POSSESSION OF AND TITLE TO GAS
--------------------------------------------
Upon delivery of the gas by Boundary to Repurchasers at the Point of
Delivery, title to the gas shall pass from Boundary to Repurchasers and
Repurchasers shall take possession of such gas and shall be deemed to be in
control thereof. Boundary shall not be responsible for such gas thereafter,
regardless of anything thing which may be done, happen or arise with respect to
such gas after delivery. Each Repurchaser understands that delivery of the gas
by Boundary to Repurchasers shall occur simultaneously with Tennessee's receipt
of such gas from TransCanada for Boundary's account, and that Boundary will
neither own nor construct any facilities in connection with this Agreement.
Notwithstanding the fact that Boundary will hold title to the gas for the
instant necessary to transfer title to Repurchasers, delivery of the gas by
TransCanada into Tennessee's facilities shall be deemed to be
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<PAGE>
delivery of the gas by Boundary to Repurchasers for purposes of determining as
between Boundary and Repurchasers when Repurchasers gain possession and control
of the gas.
ARTICLE XVII - WARRANTY OF TITLE TO GAS
---------------------------------------
Boundary warrants that it will, at the time of delivery, have good title
to all gas delivered by it to the Repurchasers hereunder, free and clear of all
liens, encumbrances and claims whatsoever, and that it will indemnify the
Repurchasers against and save them harmless from all suits, actions, debts,
accounts, damages, costs, losses and expenses arising from or out of adverse
claims of any or all persons with regard to said gas or to royalties, taxes,
license fees or charges thereon, which are applicable before the title to the
gas passes to the Repurchasers. Boundary further agrees that, as to the gas
delivered by Boundary to the Repurchasers hereunder, the Repurchasers shall be
entitled to all of the protections provided by the warranty of title set forth
in the Purchase Contract.
ARTICLE XVIII - FORCE MAJEURE AND REMEDIES
------------------------------------------
1. Neither Boundary nor any Repurchaser shall be liable in damages to
the other for any act, omission or circumstances occasioned by or in consequence
of any event constituting force majeure and the obligations of Boundary and
Repurchasers then existing hereunder shall be excused during the period thereof
to the extent affected by such events of force majeure. The term "force
majeure" shall mean any acts of God, strikes, lockouts,
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<PAGE>
acts of the public enemy, wars, blockades, insurrections, riots, epidemics,
landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and
restraints of rulers and peoples, civil disturbances, explosions, breakages or
accident to machinery or lines of pipe, line freeze-ups, temporary failure of
gas supply, temporary inability of Tennessee to receive gas for Boundary's
account, the binding order of any court or governmental authority which has been
resisted in good faith by all reasonable legal means, and any other cause,
whether of the kind herein enumerated, or otherwise, and whether caused or
occasioned by or happening on account of the act or omission of one of the
parties hereto which affects deliveries of gas at the Point of Delivery not
within the control of the party claiming excuse and which by the exercise of due
diligence such party is unable to prevent or overcome. A failure to settle or
prevent any strike or other controversy with employees or with anyone purporting
or seeking to represent employees shall not be considered to be a matter within
the control of the party claiming excuse. Under no circumstances will lack of
finances be construed to constitute force majeure.
2. Such causes or contingencies affecting the performance of this
Agreement by any party, however, shall not relieve it of liability in the event
of its concurring negligence or in the event of its failure to use due diligence
to remedy the situation and remove the cause in an adequate manner and with all
reasonable dispatch, nor shall such causes or contingencies affecting the
performance of this Agreement relieve any party from its obligation to make
payments of amounts then due hereunder
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<PAGE>
nor shall such causes or contingencies relieve any party of liability unless
such party shall give notice and full particulars of the same in writing or by
telegraph to the other parties as soon as possible after the occurrence relied
on.
3. If due to any cause whatsoever the capacity for deliveries from
TransCanada's transmission line is impaired so that TransCanada is unable to
deliver to Boundary the Daily Contract Quantity as provided in the Purchase
Contract, then Boundary shall not be liable to any of the Repurchasers for the
amount of gas not delivered, nor shall the Repurchasers be liable to Boundary to
pay for any volumes so curtailed.
4. If due to any cause whatsoever, the volume of gas to which a
Repurchaser is entitled under this Agreement is not delivered because of an
impairment in Tennessee's transmission line, Boundary shall not be liable for
any damages resulting from such volumes not being delivered.
5. Boundary's obligation to sell and Repurchasers' obligation to purchase
gas hereunder shall be suspended during the effectiveness of any governmental
action which results in the interruption of deliveries or which prevents,
totally or partially, the exportation of gas from Canada under the Purchase
Contract, the importation of gas into the United States under the Purchase
Contract, or the resale by Boundary to any Repurchaser under this Agreement, or
its transportation by Tennessee to any Boundary Repurchasers; provided, however,
that where the exportation, importation, resale or transportation is only
partially
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<PAGE>
prevented by the governmental action, Boundary's and Repurchaser's obligations
hereunder shall be suspended only to the extent prevented by such governmental
action.
ARTICLE XIX - ASSIGNMENT TO TRANSCANADA
---------------------------------------
1. Repurchasers expressly agree that the rights conferred by this
Agreement on Boundary may be assigned, and acknowledge and consent to Article
XVI of the Purchase Contract, pursuant to which Boundary assigns its rights to
receive payments under this Agreement for certain periods to TransCanada, and by
said assignment gives TransCanada the right to proceed directly against any
Repurchaser whose default under this Agreement has caused a default by Boundary
under the Purchase Contract. Boundary and Repurchasers further recognize,
acknowledge and agree that such assignment shall not make TransCanada
responsible or accountable for any obligations, liabilities, claims and demands
arising under the Gas Sales Agreement.
2. Boundary and Repurchasers recognize and acknowledge that the initial
and continuing effectiveness of this Agreement without amendment, modification,
or any other change during the term of the Purchase Contract and that the
various provisions of this Agreement requiring the consent of TransCanada are
deemed to be essential to the effective protection of TransCanada's rights under
Article XVI of the Purchase Contract. Accordingly, Boundary and Repurchasers
agree that any amendment, modification or other change of this Agreement,
without the prior written consent of TransCanada or any action taken pursuant to
this Agreement which
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<PAGE>
action requires the prior written consent of TransCanada and such consent has
not been obtained, shall not be effective against TransCanada and may be treated
by TransCanada as a breach of this Agreement.
ARTICLE XX - REGULATION
-----------------------
This Agreement and the respective obligations of the parties hereunder are
subject to all valid laws, orders, certificates, rules and regulations of duly
constituted authorities having jurisdiction over the parties hereto or the
subject matter hereof. Either Boundary or Repurchasers shall have the right to
contest the validity of any such law, order, certificate, rule or regulation and
the acquiescence therein or compliance therewith for any period of time shall
not be construed as a waiver of such right.
ARTICLE XXI - MEMORANDUM OF AGREEMENT
-------------------------------------
This Agreement supersedes and takes the place of the Memorandum of
Agreement only with respect to the matters specifically addressed herein, but
otherwise the Memorandum of Agreement shall remain in full force and effect.
ARTICLE XXII - NONWAIVER AND FUTURE DEFAULT
-------------------------------------------
No waiver by Boundary or any Repurchaser of any one or more defaults by the
other in the performance of any provisions of this Agreement shall operate or be
construed as a waiver of any
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<PAGE>
continuing or future default or defaults, whether of a like or of a different
character.
ARTICLE XXIII - AMENDMENT
-------------------------
No Amendment of this Agreement shall be made except in writing signed by
all parties hereto.
ARTICLE XXIV - NOTICES
----------------------
Any notice permitted or required under this Agreement shall be given in
writing and delivered by telex or certified mail, return receipt requested to
the relevant party or parties at the following addresses (unless written notice
of changes in such addresses is received by all parties):
Boundary Gas, Inc. Long Island Lighting
110 Tremont Street Company
Boston, MA 02108 175 E. Old Country Road
Attention: James A. Rooney Hicksville, NY 11801
The Brooklyn Union Gas Company Connecticut Natural Gas
195 Montague Street Corporation
Brooklyn, NY 11201 P.O. Box 1500
Hartford, CT 06144
Granite State Gas
Transmission, Inc. Essex County Gas Company
120 Royall Street Hunt Road
Canton, MA 02021 Amesbury, MA 01913
New Jersey Natural Gas Company Manchester Gas Company
P.O. Box 1468 P.O. Box 329
Wall, NJ 07719 Manchester, NH 03105
Boston Gas Company Gas Service, Inc.
One Beacon Street P.O. Box 329
Boston, MA 02108 Manchester, NH 03105
The Connecticut Light and Valley Gas Company
Power Company 1595 Mendon Road
P.O. Box 270 Cumberland, RI 02864
Hartford, CT 06141-0270
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<PAGE>
Consolidated Edison Company Berkshire Gas Company
of New York, Inc. 115 Cheshire Road
Four Irving Place Pittsfield, MA 01201
New York, NY 11801
Fitchburg Gas and Electric
National Fuel Gas Supply Light Co.
Corp. 285 John Fitch Highway
10 Lafayette Square Fitchburg, MA 01420-8570
Buffalo, NY 14203
ARTICLE XXV - GOVERNING LAW
---------------------------
This Agreement shall be governed by and construed in accordance with the
laws of the State of New York.
ARTICLE XXVI - COUNTERPART EXECUTION
------------------------------------
This Agreement may be executed in separate, individual counterparts and all
of such executed counterparts shall together constitute one and the same
instrument.
ARTICLE XXVII - PRIOR AGREEMENT SUPERSEDED
------------------------------------------
This Agreement supersedes in its entirety the Gas Sales Agreement executed
on March 6, 1984 by Boundary Gas, Inc., The Brooklyn Union Gas Company, New
Jersey Natural Gas Company, Granite State Gas Transmission, Inc. and The
Connecticut Light and Power Company.
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<PAGE>
IN WITNESS WHEREOF, this Gas Sales Agreement is executed as of the date
first above written.
ATTEST: BOUNDARY GAS, INC.
/s/ [SIGNATURE ILLEGIBLE]^^ By /s/ [SIGNATURE ILLEGIBLE]^^
- ---------------------------- -------------------------------------
(Seal)
ATTEST: THE BROOKLYN UNION GAS COMPANY
____________________________ By_____________________________________
(Seal)
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
____________________________ By_____________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
____________________________ By_____________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
____________________________ By_____________________________________
(Seal)
ATTEST: THE CONNECTICUT LIGHT AND
POWER COMPANY
____________________________ By_____________________________________
(Seal)
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<PAGE>
IN WITNESS WHEREOF, this Gas Sales Agreement is executed as of the date
first above written.
ATTEST: BOUNDARY GAS, INC.
____________________________ By_____________________________________
(Seal)
ATTEST: THE BROOKLYN UNION GAS COMPANY
____________________________ By_____________________________________
(Seal)
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
____________________________ By_____________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
____________________________ By_____________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
/s/ [SIGNATURE ILLEGIBLE]^^ By /s/ [SIGNATURE ILLEGIBLE]^^
- ---------------------------- -------------------------------------
(Seal)
ATTEST: THE CONNECTICUT LIGHT AND
POWER COMPANY
____________________________ By_____________________________________
(Seal)
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<PAGE>
FIRST AMENDMENT TO PHASE 2 GAS SALES AGREEMENT
----------------------------------------------
This Contract, to be called the First Amendment To Phase 2 Gas Sales
Agreement, is made this 1st day of January, 1990, by and between Boundary Gas,
Inc., A Delaware corporation (herein called "Boundary"); and those of the
following fifteen (15) United State companies (which collectively own all of the
stock of Boundary) signatory hereto: The Brooklyn Union Gas Company; Granite
State Gas Transmission, Inc.; New Jersey Natural Gas Company; Boston Gas
Company; Yankee Gas Services Company; Consolidated Edison Company of New York,
Inc.; National Fuel Gas Supply Corp.; Long Island Lighting Company; Connecticut
Natural Gas Corporation; Essex County Gas Company; Manchester Gas Company; Gas
Service, Inc.; Valley Gas Company; Berkshire Gas Company; and Fitchburg Gas and
Electric Light Co. (herein called individually "Repurchaser" and collectively
"Repurchasers").
W I T N E S S E T H:
WHEREAS, Boundary and the Repurchasers have entered into a Phase 2 Gas
Sales Agreement for the sale of certain quantities of natural gas ("Phase 2
Volumes") from Boundary to the Repurchasers, dated September 14, 1987 ("Sales
Agreement"); and
WHEREAS, deliveries and resale of the Phase 2 Volumes commenced on January
15, 1988, having been fully authorized by all United States and Canadian
regulatory authorities having jurisdiction; and
<PAGE>
WHEREAS, Boundary and the Repurchasers have entered into a Precedent
Agreement to First Amendment to Phase 2 Gas Sales Agreement, wherein Boundary
and the Repurchasers have agreed to use their best efforts to seek and obtain
all necessary regulatory and governmental authorizations to effectuate the terms
of this First Amendment to Phase 2 Gas Sales Agreement ("Sales Amendment"); and
WHEREAS, Boundary has received and accepted all necessary regulatory and
governmental authorizations to enable Boundary to effectuate this Gas Sales
Amendment; and
WHEREAS, the Repurchasers have received and accepted all necessary
regulatory and governmental authorizations to enable the Repurchasers to
effectuate this Gas Sales Amendment; and
WHEREAS, all other conditions of the Precedent Agreement to the Sales
Amendment have now been fulfilled; and
WHEREAS, Boundary and the Repurchasers now desire and agree to amend the
Sales Agreement in the manner set forth herein, so that the terms and conditions
of the Sales Agreement are uniform and consistent in all material respects with
all contracts and regulatory authorizations governing the resale by Boundary and
transportation by Tennessee Gas Pipeline Company of the Phase 2 Volumes.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained in the Sales Agreement and in this Sales
-2-
<PAGE>
Amendment, Boundary and the Repurchasers agree to amend said Sales Agreement as
follows:
1. Section 1 of Article IX of the Sales Agreement is amended by deleting
the last two sentences of said Section.
2. Article X of the Sales Agreement is amended by deleting Section 2 of
said Article and, as a result of such deletion, by renumbering Sections 3, 4, 5
and 6 of said Section 2 to be Sections 2, 3, 4 and 5, respectively.
3. Section 2(a) of Article X of the Sales Agreement (subsequent to its
renumbering in accordance with paragraph 2 above) is amended by deleting the
first clause of the first sentence of said Section and by deleting the words
"U.S. Sum" and "Section 1(c) (ii)" to be found at the end of said sentence, and
substituting therefore "United States Dollar Sum" and "Section 1(a),"
respectively, and by adding the words, "and as specified in Section 1 of Article
IX of this Agreement" at the end of the said first sentence so that the first
sentence of said Section shall state: "Boundary's monthly invoice to each
Repurchaser shall include such Repurchaser's share of the United States Dollar
Sum, as defined in Article VIII, Section 1(a) of the Purchase Amendment and as
specified in Section 1 of Article IX of this Agreement."
4. Section 2(b) of Article X of the Sales Agreement (subsequent to its
renumbering in accordance with paragraph 2 above) is amended by deleting the
words "U.S. Sum" to be found at
-3-
<PAGE>
the end of the first sentence of said Section and substituting therefore the
words "United States Dollar Sum" so that the relevant phrase of said sentence
shall state: " . . . the amount of any invoice for such Repurchaser's
proportionate share of the United States Dollar Sum."
5. Section 3 of Article X of the Sales Agreement (subsequent to its
renumbering in accordance with paragraph 2 above) is amended by adding the words
"of this Agreement" after the words and numbers "Sections 2 and 3 of Article IX"
to be found in the first sentence of said Section, so that the relevant phrase
of said sentence shall state " . . . amounts due under Sections 2 and 3 of
Article IX of this Agreement shall be made to Boundary."
6. This Sales Amendment shall be binding upon and inure to the benefit of
the parties hereto and their respective successors and assigns.
7. All terms and conditions of the Sales Agreement not referenced herein
shall remain in full force and effect.
-4-
<PAGE>
IN WITNESS WHEREOF, this Amendment to the Phase 2 Gas Sales Agreement is
executed as of the date first above written.
ATTEST: BOUNDARY GAS, INC.
_____________________________ _______________________________________
(Seal)
ATTEST: THE BROOKLYN UNION GAS COMPANY
_____________________________ _______________________________________
(Seal)
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
_____________________________ _______________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
_____________________________ _______________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
/s/ W. P. Luthern
_____________________________ ---------------------------------------
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
_____________________________ _______________________________________
(Seal)
-5-
<PAGE>
SECOND AMENDMENT TO
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Contract, to be called the Second Amendment To Phase 2 Gas Sales
Agreement, is made this 1st day of July, 1989, by and between Boundary Gas,
Inc., a Delaware Corporation (herein called "Boundary"); and those of the
following fifteen (15) United States companies (which collectively own all of
the stock of Boundary) signatory hereto: The Brooklyn Union Gas Company; Granite
State Gas Transmission, Inc.; New Jersey Natural Gas Company; Boston Gas
Company; Yankee Gas Services Company ("Yankee Gas"); Consolidated Edison Company
of New York, Inc.; National Fuel Gas Supply Corp.; Long Island Lighting Company;
Connecticut Natural Gas Corporation; Essex County Gas Company; Manchester Gas
Company; Gas Service, Inc.; Valley Gas Company; Berkshire Gas Company; and
Fitchburg Gas and Electric Light Co. (herein called individually "Repurchaser"
and collectively "Repurchasers").
W I T N E S S E T H :
WHEREAS, Boundary, The Connecticut Light and Power Company ("CL&P") and all
the Repurchasers except Yankee Gas have entered into a Phase 2 Gas Sales
Agreement for the sale of certain quantities of natural gas from Boundary, dated
September 14, 1987 ("Sales Agreement"), to be amended pursuant to the terms of
the Precedent Agreement To First Amendment To Phase 2 Gas Sales Agreement, dated
September 14, 1988; and
<PAGE>
WHEREAS, on or about July 1, 1989, CL&P will transfer or assign its retail
gas distribution franchises, the assets of its Gas Group, its entire interest in
the stock of Boundary, and all its interests, rights, and obligations under the
Sales Agreement to Yankee Gas, a newly formed company; and
WHEREAS, in accordance with Article XIV of the Sales Agreement, Yankee Gas
will ratify and agree to become a party to the Sales Agreement and the
Memorandum of Agreement; and
WHEREAS, Article XIV of the Sales Agreement requires that the Sales
Agreement be amended to reflect the sale, transfer or assignment to Yankee Gas;
and
WHEREAS, Article XIX of the Sales Agreement further provides for the prior
written consent of TransCanada PipeLines, Limited ("TransCanada") to such an
amendment.
NOW, THEREFORE, in accordance with Article XIV, XIX and XXIII of the Sales
Agreement, the parties hereto agree to amend the Sales Agreement, effective upon
CL&P's assignment or transfer of all of its stock and rights in the Sales
Agreement to Yankee Gas, as follows:
1. The Preamble and Article VII of the Sales Agreement are amended by
deleting the name "The Connecticut Light and Power Company" and
substituting therefor the name "Yankee Gas Services Company."
2. Article XXIV of the Sales Agreement is amended by deleting "The
Connecticut Light and Power Company, P.O. Box 270, Hartford, CT 06141-
0270" and substituting therefore the "Yankee Gas Services Company, P.O.
Box 4002, Rocky Hill, CT 06067."
-2-
<PAGE>
3. The Memorandum of Agreement is amended in all respects necessary to
reflect this transfer and, as so amended, is appended hereto.
4. The Sales Agreement, as amended, is hereby ratified and confirmed.
5. This Second Amendment shall be binding upon and inure to the benefit of
the parties hereto and their respective successors and assigns.
6. All terms and conditions of the Sales Agreement not referenced herein
shall remain in full force and effect.
7. This Second Amendment shall be effective as of the date that CL&P assigns
or transfers all of its stock and rights under the Sales Agreement to
Yankee Gas.
8. This Second Amendment may be executed by separate, individual
counterparts, and all of such counterparts together shall constitute one
and the same instrument.
IN WITNESS WHEREOF, this Second Amendment to the Phase 2 Gas Sales
Agreement is executed as of the date written above.
ATTEST: BOUNDARY GAS, INC.
_____________________________ By_____________________________________
(Seal)
ATTEST: THE BROOKLYN UNION GAS COMPANY
_____________________________ By_____________________________________
(Seal)
-3-
<PAGE>
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
_____________________________ By_____________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
_____________________________ By_____________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
/s/ [SIGNATURE ILLEGIBLE]^^ By /s/ William P. Luthern
- ----------------------------- -------------------------------------
Asst. Sec'y
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
_____________________________ By_____________________________________
(Seal)
ATTEST: CONSOLIDATED EDISON COMPANY OF
NEW YORK, INC.
_____________________________ By_____________________________________
(Seal)
ATTEST: NATIONAL FUEL GAS SUPPLY CORP.
_____________________________ By_____________________________________
(Seal)
-4-
<PAGE>
THIRD AMENDMENT TO PHASE 2 GAS SALES AGREEMENT
----------------------------------------------
This Contract, to be called the Third Amendment To Phase 2 Gas Sales
Agreement ("Third Sales Amendment"), is made this _____ day of __________, 1991,
by and between Boundary Gas, Inc., a Delaware corporation (hereinafter called
"Boundary") and those of the following fifteen (15) United States companies
(which collectively own all of the stock of Boundary) which are signatory
hereto: The Brooklyn Union Gas Company; Granite State Gas Transmission, Inc.;
New Jersey Natural Gas Company; Boston Gas Company; Yankee Gas Services Company;
Consolidated Edison Company of New York, Inc.; National Fuel Gas Supply
Corporation; Long Island Lighting Company; Connecticut Natural Gas Corporation;
Essex County Gas Company; Manchester Gas Company; Gas Service, Inc.; Valley Gas
Company; Berkshire Gas Company; and Fitchburg Gas and Electric Light Company
(herein called individually "Repurchaser" and collectively "Repurchasers").
W I T N E S S E T H:
WHEREAS, Boundary and the Repurchasers have entered into a Phase 2 Gas
Sales Agreement dated September 14, 1987, as amended effective July 1, 1989 and
January 1, 1990, ("Sales Agreement") for the sale of certain quantities of
natural gas ("Phase 2 Volumes") from Boundary to the Repurchasers; and
WHEREAS, deliveries and resale of the Phase 2 Volumes commenced on January
15, 1988, having been fully authorized by all
<PAGE>
United States and Canadian regulatory authorities having jurisdiction; and
WHEREAS, Boundary and the Repurchasers entered into a Precedent Agreement
to Third Amendment To Phase 2 Gas Sales Agreement, in which Boundary and the
Repurchasers agreed to use their best efforts to seek and obtain all necessary
regulatory and governmental authorizations to effectuate the terms of the Third
Sales Amendment; and
WHEREAS, Boundary has received and accepted all necessary regulatory and
governmental authorizations to enable Boundary to effectuate the Third Sales
Amendment; and
WHEREAS, the Repurchasers have received and accepted any necessary
regulatory and governmental authorizations to enable the Repurchasers to
effectuate the Third Sales Amendment; and
WHEREAS, all other conditions of the Precedent Agreement To Third Amendment
To Gas Sales Agreement have now been fulfilled; and
WHEREAS, Boundary and the Repurchasers now desire and agree to amend the
Sales Agreement in the manner set forth herein, in order to clarify the excess
gas pricing calculation in the Sales Agreement.
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained in the Sales Agreement, as amended, and
-2-
<PAGE>
in this Third Sales Amendment, Boundary and the Repurchasers agree to amend the
Sales Agreement as follows:
1. Article IX, Section 1., of the Sales Agreement is amended by deleting
the period (.) at the end of the fifth sentence and replacing it with a
semicolon (;), and by adding the following language: "provided, however, that if
gas released and taken pursuant to Article XI, Section 1. is taken at a price
which does not include a full aliquot share of the Monthly Demand Charge,
Boundary shall take the variation into account in performing the subject
calculation."
2. This Third Sales Amendment shall be binding upon and inure to the
benefit of the parties hereto and their respective successors and assigns.
3. All terms and conditions of the Sales Agreement not referenced herein
shall remain in full force and effect.
IN WITNESS WHEREOF, this Third Amendment To Phase 2 Gas Sales Agreement is
executed as of the date first written above.
ATTEST: BOUNDARY GAS, INC.
_______________________________ By:________________________________
(Seal)
-3-
<PAGE>
ATTEST: THE BROOKLYN UNION GAS COMPANY
_______________________________ By:________________________________
(Seal)
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
_______________________________ By:________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
_______________________________ By:________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
By: /s/ William R. Luthern
_______________________________ --------------------------------
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
_______________________________ By:________________________________
(Seal)
ATTEST: CONSOLIDATED EDISON COMPANY OF
NEW YORK, INC.
_______________________________ By:________________________________
(Seal)
-4-
<PAGE>
FOURTH AMENDMENT TO
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Contract, to be called the Fourth Amendment To Phase 2 Gas Sales
Agreement, is made this 5th day of June, 1991, by and between Boundary Gas,
Inc., a Delaware Corporation (herein called "Boundary"); and those of the
following fourteen (14) United States companies (which collectively own all of
the stock of Boundary) signatory hereto: The Brooklyn Union Gas Company; Granite
State Gas Transmission, Inc.; New Jersey Natural Gas Company; Boston Gas
Company; Yankee Gas Services Company; Consolidated Edison Company of New York,
Inc.; National Fuel Gas Supply Corp.; Long Island Lighting Company; Connecticut
Natural Gas Corporation; Essex County Gas Company; EnergyNorth Natural Gas, Inc.
("EnergyNorth"); Valley Gas Company; Berkshire Gas Company; and Fitchburg Gas
and Electric Light Co. (herein called individually "Repurchaser" and
collectively "Repurchasers").
W I T N E S S E T H :
WHEREAS, Boundary, Manchester Gas Company ("Manchester"), Gas Service, Inc.
("Gas Service") and all the Repurchasers except EnergyNorth have entered into a
Phase 2 Gas Sales Agreement for the purchase of certain quantities of natural
gas from Boundary, dated September 14, 1987 ("Sales Agreement"), as amended
effective July 1, 1989 and January 1, 1990, and as to be amended pursuant to the
terms of the Precedent Agreement to Third Amendment to Phase 2 Gas Sales
Agreement; and
<PAGE>
WHEREAS, Manchester and Gas Service have merged into EnergyNorth,
transferring their entire interest in the stock of Boundary to EnergyNorth,
effective October 1, 1988; and
WHEREAS, on October 6, 1980, all of the Stockholders of Boundary entered
into a Memorandum of Agreement, which was amended on April 29, 1983, February
23, 1984, April 16, 1984 and July 1, 1989, and supplemented on May 31, 1985; and
WHEREAS, in accordance with Article XIV of the Sales Agreement, EnergyNorth
has agreed to ratify and become a party to the Sales Agreement and the
Memorandum of Agreement; and
WHEREAS, Article XIV of the Sales Agreement requires that the Sales
Agreement be amended to reflect the transfer to EnergyNorth; and
WHEREAS, Article XIX of the Sales Agreement further provides for the prior
written consent of Trans Canada PipeLines, Limited ("TransCanada") to such an
amendment.
NOW, THEREFORE, in accordance with Article XIV, XIX and XXIII of the Sales
Agreement, the parties hereto agree to amend the Sales Agreement, effective as
of the date first written above as follows:
1. The Preamble and Article VII of the Sales Agreement are amended by
deleting the names "Manchester Gas Company" and "Gas Service, Inc." and
substituting therefor the name "EnergyNorth Natural Gas, Inc."
-2-
<PAGE>
2. Article XXIV of the Sales Agreement is amended by deleting "Manchester
Gas Company, P.O. Box 329, Manchester, NH 03105" and "Gas Service Inc.,
P.O. Box 329, Manchester, NH 03105" and substituting therefore
"EnergyNorth Natural Gas, Inc., 1260 Elm Street, Manchester, NH 03105."
3. The Memorandum of Agreement is being amended concurrently herewith.
4. The Sales Agreement, as amended, is hereby ratified and confirmed.
5. This Fourth Amendment shall be binding upon and inure to the benefit of
the parties hereto and their respective successors and assigns.
6. All terms and conditions of the Sales Agreement not referenced herein
shall remain in full force and effect.
7. This Fourth Amendment shall be effective as of the date first written
above.
8. This Fourth Amendment may be executed by separate, individual
counterparts, and all of such counterparts together shall constitute one
and the same instrument.
-3-
<PAGE>
IN WITNESS WHEREOF, this Fourth Amendment to the Phase 2 Gas Sales
Agreement is executed as of the date written above.
ATTEST: BOUNDARY GAS, INC.
_______________________________ By:________________________________
(Seal)
ATTEST: THE BROOKLYN UNION GAS COMPANY
_______________________________ By:________________________________
(Seal)
ATTEST: GRANITE STATE GAS
TRANSMISSION, INC.
_______________________________ By:________________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
_______________________________ By:________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
By: /s/ William R. Luthern
_______________________________ --------------------------------
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
_______________________________ By:________________________________
(Seal)
-4-
<PAGE>
FIFTH AMENDMENT TO
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Contract, to be called the Fifth Amendment To Phase 2 Gas Sales
Agreement, is made this 4th day of May, 1993, by and between Boundary Gas, Inc.,
a Delaware Corporation (herein called ("Boundary"); and those of the following
fourteen (14) United States companies (which collectively own all of the stock
of Boundary) signatory hereto: The Brooklyn Union Gas Company; Granite State Gas
Transmission, Inc.; New Jersey Natural Gas Company; Boston Gas Company; Yankee
Gas Services Company; Consolidated Edison Company of New York, Inc.; National
Fuel Gas Distribution Corporation (('Distribution"); Long Island Lighting
Company; Connecticut Natural Gas Corporation; Essex County Gas Company;
EnergyNorth Natural Gas, Inc.; Valley Gas Company; Berkshire Gas Company; and
Fitchburg Gas and Electric Light Company (herein called individually
"Repurchaser" and collectively "Repurchasers").
W I T N E S S E T H :
WHEREAS, Boundary, National Fuel Gas Supply Corporation ("Supply") and all
the Repurchasers except Distribution have entered into a Phase 2 Gas Sales
Agreement for the purchase of certain quantities of natural gas from Boundary,
dated September 14, 1987 ("Sales Agreement"), as amended effective July 1, 1989,
January 1, 1990, June 5, 1991 and November 6, 1991; and
<PAGE>
WHEREAS, on October 6, 1980, all of the Stockholders of Boundary entered
into a Memorandum of Agreement, which was amended on April 29, 1983, February
23, 1984, April 16, 1984, July 1, 1989 and June 5, 1991, and supplemented on May
31, 1985; and
WHEREAS, Supply is assigning its interest in the Sales Agreement and its
entire interest in the stock of Boundary to Distribution, its affiliate,
effective as of the date that the Federal Energy Regulatory Commission ("FERC")
makes Supply's restructuring effective; and
WHEREAS, in accordance with Article XIV of the Sales Agreement,
Distribution has agreed to ratify and become a party to the Sales Agreement and
the Memorandum of Agreement; and
WHEREAS, Article XIV of the Sales Agreement requires that the Sales
Agreement be amended to reflect the transfer to Distribution; and
WHEREAS, Article XIX of the Sales Agreement further provides for the prior
written consent of TransCanada PipeLines, Limited ("TransCanada") to such an
amendment.
NOW, THEREFORE, in accordance with Article XIV, XIX and XXIII of the Sales
Agreement, the parties hereto agree to amend the Sales Agreement, effective as
of the date that the FERC makes Supply's restructuring effective as follows:
-2-
<PAGE>
1. The Preamble and Article VII of the Sales Agreement are amended
by deleting the names "National Fuel Gas Supply Corporation" and
"National Fuel Gas Supply Corp.," respectively, and substituting
therefore the name "National Fuel Gas Distribution Corporation."
2. The first Whereas clause of the Sales Agreement is amended by
deleting the words "November 1, 1996" and substituting therefore
the words January 15, 2003."
3. Article I of the Sales Agreement is amended by deleting the words
"and April 16, 1984" and substituting therefore the words ",
April 16, 1984, July 1, 1989 and June 5, 1991,"
4. Article XXIV of the Sales Agreement is amended by deleting
"National Fuel Gas Supply Corp., 10 Lafayette Square, Buffalo, NY
14203" and substituting therefore "National Fuel Gas Distribution
Corporation, 10 Lafayette Square, Buffalo, NY 14203."
5. The Memorandum of Agreement is being amended concurrently
herewith.
6. The Sales Agreement, as amended, is hereby ratified and
confirmed.
-3-
<PAGE>
7. This Fifth Amendment shall be binding upon and inure to the
benefit of the parties hereto and their respective successors and
assigns.
8. All terms and conditions of the Sales Agreement not referenced
herein shall remain in full force and effect.
9. This Fifth Amendment shall be effective as of the date that the
FERC makes Supply's restructuring effective.
10. This Fifth Amendment may be executed by separate, individual
counterparts, and all of such counterparts together shall
constitute one and the same instrument.
IN WITNESS WHEREOF, this Fifth Amendment to the Phase 2 Gas Sales
Agreement is executed as of the date written above.
ATTEST: BOUNDARY GAS, INC.
/s/ [ SIGNATURE ILLEGIBLE]^^ By /s/ Michael S. Lucy
- ----------------------------- -----------------------------
(Seal)
-4-
<PAGE>
ATTEST: THE BROOKLYN UNION GAS COMPANY
_______________________________ By___________________________
(Seal)
ATTEST: GRANITE STATE GAS TRANSMISSION, INC.
_______________________________ By___________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
_______________________________ By___________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
By /s/ W. R. Luthern
_______________________________ ---------------------------
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
_______________________________ By___________________________
(Seal)
ATTEST: CONSOLIDATED EDISON COMPANY OF
NEW YORK, INC.
_______________________________ By___________________________
(Seal)
-5-
<PAGE>
SIXTH AMENDMENT TO
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Contract, to be called the Sixth Amendment To Phase 2 Gas Sales
Agreement, is made this 9th day of September, 1993, by and between Boundary Gas,
Inc., a Delaware Corporation (herein called "Boundary"); and those of the
following fifteen (15) United States companies (which collectively own all of
the stock of Boundary) signatory hereto: The Brooklyn Union Gas Company; Bay
State Gas Company ("Bay State"); Northern Utilities, Inc. ("Northern
Utilities"); New Jersey Natural Gas Company; Boston Gas Company; Yankee Gas
Services Company; Consolidated Edison Company of New York, Inc.; National Fuel
Gas Distribution Corporation; Long Island Lighting Company; Connecticut Natural
Gas Corporation; Essex County Gas Company; EnergyNorth Natural Gas, Inc.; Valley
Gas Company; Berkshire Gas Company; and Fitchburg Gas and Electric Light Company
(herein called individually "Repurchaser" and collectively "Repurchasers").
W I T N E S S E T H
WHEREAS, Boundary, Granite State Gas Transmission, Inc. ("Granite State")
and all the Repurchasers except Bay State and Northern Utilities have entered
into a Phase 2 Gas Sales Agreement for the purchase of certain quantities of
natural gas from Boundary, dated September 14, 1987 ("Sales Agreement"), as
<PAGE>
amended effective July 1, 1989, January 1, 1990, June 5, 1991, November 6, 1991
and May 4, 1993; and
WHEREAS, on October 6, 1980, all of the Stockholders of Boundary entered
into a Memorandum of Agreement, which was amended on April 29, 1983, February
23, 1984, April 16, 1984, July 1, 1989, June 5, 1991, and May 4, 1993, and
supplemented on May 31, 1985; and
WHEREAS, Granite State is assigning its interest in the Sales Agreement and
its entire interest in the stock of Boundary to its affiliates, Bay State and
Northern Utilities, effective as of the date that the Federal Energy Regulatory
Commission ("FERC") makes Granite State's restructuring effective; and
WHEREAS, in accordance with Article XIV of the Sales Agreement, Bay State
and Northern Utilities have agreed to ratify and become parties to the Sales
Agreement and the Memorandum of Agreement; and
WHEREAS, Article XIV of the Sales Agreement requires that the Sales
Agreement be amended to reflect the transfer to Bay State and Northern
Utilities; and
WHEREAS, Article XIX of the Sales Agreement further provides for the prior
written consent of TransCanada PipeLines, Limited ("TransCanada") to such an
amendment.
NOW, THEREFORE, in accordance with Article XIV, XIX and XXIII of the Sales
Agreement, the parties hereto agree to amend
2
<PAGE>
the Sales Agreement, effective as of the date that the FERC makes Granite
State's restructuring effective as follows:
1. The Preamble of the Sales Agreement is amended by (a) deleting the
words "fourteen (14)" and substituting therefore the words "fifteen
(15)", and (b) deleting the name "Granite State Gas Transmission,
Inc." and substituting therefore the names "Bay State Gas Company;
Northern Utilities, Inc.".
2. Article I of the Sales Agreement is amended by deleting the words "and
May 4, 1993" and substituting therefore the words", May 4, 1993 and
September 9, 1993,".
3. The table in Article VII, Section 2. of the Sales Agreement is amended
by (a) deleting the entry "Granite State Gas Transmission, Inc.....
13.51"; (b) inserting after the entry for Bonston Gas Company the
entry "Bay State Gas Company..... 11.00"; and (c) inserting after the
entry for EnergyNorth Natural Gas, Inc. the entry "Northern Utilities,
Inc.... 2.51".
4. Article XXIV of the Sales Agreement is amended by deleting "Granite
State Gas Transmission, Inc., 300 Friberg Parkway, Westborough, MA
01581" and substituting therefore "Bay State Gas Company, 300 Friberg
Parkway, Westborough, MA 01581" and
3
<PAGE>
"Northern utilities, Inc., 300 Friberg Parkway, Westborough, MA
01581".
5. The Memorandum of Agreement is being amended concurrently herewith.
6. The Sales Agreement, as amended, is hereby ratified and confirmed.
7. This sixth Amendment shall be binding upon and inure to the benefit
of the parties hereto and their respective successors and assigns.
8. All terms and conditions of the Sales Agreement not referenced
herein shall remain in full force and effect.
9. This Sixth Amendment may be executed by separate, individual
counterparts, and all of such counterparts together shall
constitute one and the same instrument.
IN WITNESS WHEREOF, this Sixth Amendment to the Phase 2 Gas Sales
Agreement is executed as of the date written above.
ATTEST: BOUNDARY GAS, INC.
____________________________ BY /s/ SIGNATURE ILLEGIBLE^^
------------------------
(Seal)
4
<PAGE>
ATTEST: THE BROOKLYN UNION GAS COMPANY
___________________________ By ___________________________
(Seal)
ATTEST: NEW JERSEY NATURAL GAS COMPANY
___________________________ By ___________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
___________________________ By /s/ William P. Luthern
----------------------------
(Seal)
ATTEST: YANKEE GAS SERVICES COMPANY
___________________________ By ___________________________
(Seal)
ATTEST: CONSOLIDATED EDISON COMPANY OF
NEW YORK, INC.
___________________________ By ___________________________
(Seal)
ATTEST: NATIONAL FUEL GAS DISTRIBUTION
CORPORATION
___________________________ By ___________________________
(Seal)
ATTEST: LONG ISLAND LIGHTING COMPANY
___________________________ By ___________________________
5
<PAGE>
[LOGO]
BOUNDARY GAS, INC.
ONE BOWDOIN SQUARE
BOSTON, MASSACHUSETTS 02114
TELEPHONE: (617) 227-8080
FAX: (617) 227-2690
TELEX: 95-1459
March 8,1996
William Luthem
Boston Gas Company
One Beacon Street
Boston, MA 02108
Re: Amendment to Boundary Gas Sales Agreement
-----------------------------------------
Dear Mr. Luthem:
The Gas Purchase Contract between Boundary Gas, Inc. ("Boundary") and
TransCanada PipeLines Limited ("TransCanada") dated September 14, 1987, as
amended ("Purchase Contract"), has been amended to facilitate, permanently on a
firm basis, the delivery of the daily share of the Boundary volumes of National
Fuel Gas Distribution Corporation ("National Fuel") to the point of
interconnection between TransCanada and Empire State Pipeline ("Empire") at
Chippawa, Ontario.
A copy of the March 6, 1996 Letter Amendment between Boundary and TransCanada
("Letter Amendment"), is attached hereto. This amendment to the Purchase
Contract requires corresponding amendments to the Phase 2 Gas Sales Agreement
between Boundary and Boston Gas Company ("Boston Gas") dated September 14, 1987,
as amended ("Gas Sales Agreement").
Specifically, effective upon the effectiveness of the Letter Amendment, the Gas
Sales Agreement is amended as follows:
(a) In the First Whereas Clause, the clause "and, with respect to
the quantities to be resold to National Fuel Gas Distribution
Corporation ("National Fuel"), by Empire State Pipeline ("Empire")
for Boundary's account at or near the existing point of
interconnection between the pipeline systems of TransCanada and
Empire near Chippawa, Ontario" shall be inserted immediately after
the words "Niagara Falls, Ontario."
(b) The following new Whereas Clause shall be inserted after the
present Fifth Whereas Clause: "WHEREAS, Empire has received and
accepted
<PAGE>
March 8, 1996
Page 2
all necessary certificates, permits, licenses and authorizations
to enable Empire to transport the quantities of gas purchased by
Boundary from TransCanada and resold to National Fuel; and."
(c) The following new Whereas Clause shall be inserted after the
present Seventh Whereas Clause: "WHEREAS, National Fuel has
executed a duly authorized Transportation Contract with Empire
pursuant to which Empire agrees to transport for National Fuel the
quantities of gas purchased by National Fuel from Boundary; and."
(d) In Article IV, the clause "or, in the case of National Fuel, the
point at which TransCanada delivers to Empire" shall be inserted
after the word "Tennessee."
(e) In Article V, the clause "or, in the case of National Fuel, with
Empire" shall be inserted after the word "Tennessee."
(f) In Article VII, Section 1, the word "Tennessee's" shall be deleted
and the clause "by Tennessee or, in the case of National Fuel, by
Empire" shall be inserted after the word "receipt."
(g) In Article IX, Section 1, the following proviso shall be inserted
at the end of the fourth sentence thereof: ", provided, however,
that any increase or decrease in the Monthly Demand Charge or
Commodity Charge with respect to the Chippawa Daily Contract
Quantity, pursuant to the provisos to Sections 3 and 4,
respectively, of Article VII of the Purchase Contract, shall be
paid by National Fuel to Boundary."
(h) In Article XVI, Section 1, the word "Tennessee's" shall be deleted
and the clause "by Tennessee or, in the case of National Fuel, by
Empire" shall be inserted after the word "receipt."
(i) In Article XVI, Section 1, the clause "or, in the case of National
Fuel, into Empire's facilities" shall be inserted after the words
"into Tennessee's facilities."
(j) In Article XVIII, Section 1, the clause "or, in the case of
National Fuel, of Empire" shall be inserted after the words
"inability of Tennessee."
<PAGE>
March 8,1996
Page 3
(k) In Article XVIII, Section 4, the clause "or, in the case of
National Fuel, in Empire's transmission line" shall be inserted
after the words "in Tennessee's transmission line."
(1) In Article XVIII, Section 5, the clause "or by Empire to National
Fuel" shall be inserted after the words "to any Boundary
Repurchasers."
Please acknowledge these amendments by signing in the space provided below and
returning an executed copy to me.
Sincerely,
Boundary Gas, Inc.
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
15/th/ DAY OF MARCH, 1996
BOSTON GAS COMPANY
By: /s/ [SIGNATURE ILLEGIBLE]^^
---------------------------
Title: Vice President
------------------------
<PAGE>
[LOGO]
BOUNDARY GAS, INC.
ONE BOWDOIN SQUARE
BOSTON, MASSACHUSETTS 02114
TELEPHONE: (617) 227-8080
FAX: (617) 227-2690
TELEX: 95-1459
March 6, 1996
Mr. Peter Ewing
TransCanada Gas Marketing Limited,
as Agent for
TransCanada PipeLines Limited
55 Yonge Street, 11th Floor
Toronto, Ontario M5E 1J4
Re: Fifth Amendment To TransCanada/Boundary
Phase 2 Gas Purchase Contract
---------------------------------------
Dear Mr. Ewing:
Boundary Gas, Inc. ("Boundary") and TransCanada Pipelines Limited
("TransCanada") are parties to the Phase 2 Gas Purchase Contract, dated
September 14, 1987, as amended ("Purchase Contract"), which provides, inter
-----
alia, for the delivery of gas by TransCanada to Boundary at TransCanada's point
- ----
of interconnection with Tennessee Gas Pipeline Company ("Tennessee") near
Niagara Falls, Ontario for redelivery to National Fuel Gas Distribution
Corporation ("National Fuel") and fourteen other utility companies engaged in
the distribution of gas in the Northeastern United States. This Amendment
concerns one change to the Purchase Contract. Namely, National Fuel has
requested, and TransCanada and Boundary have agreed, to amend the Purchase
Contract to facilitate, permanently on a firm basis, the delivery of National
Fuel's daily share of the Boundary volumes to the point of interconnection
between TransCanada and Empire State Pipeline ("Empire") at Chippawa, Ontario.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 2
This letter reflects our agreement to the following amendments to the
Purchase Contract:
1. The First Whereas Clause is amended as follows:
(a) by deleting the words "a point" and substituting the word
"points" therefore;
(b) by deleting the term "'Point of Interconnection'" and
substituting the term "'Tennessee Point of Interconnection'" therefore; and
(c) by adding the following clause after the new term "Tennessee
Point of Interconnection":
, and near Chippawa, Ontario, where it interconnects with the
facilities of Empire State Pipeline ("Empire"), herein called "Empire
Point of Interconnection" (the Tennessee Point of Interconnection and
the Empire Point of Interconnection together, herein called "Points of
Interconnection")
2. The Third Whereas Clause is deleted and the following clause is
substituted therefore:
WHEREAS, Tennessee and Empire (herein called "U.S. Transporters") own
and operate natural gas transmission pipeline systems in the United
States, which interconnect with Seller's pipeline system at the
aforementioned Points of Interconnection; and
3. The Fourth Whereas Clause is amended as follows:
(a) by deleting the words "Tennessee has" and substituting the
words "U.S. Transporters have" therefore; and
(b) by deleting the word "Point" and substituting the word
"Points" therefore.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 3
4. Article 1, Section 10, "Daily Contract Quantity" is amended by
adding the following sentence after the second sentence:
For the purpose of calculating the Monthly Demand Charge provided for
in Section 3 of Article VII hereof, and for the purpose of defining
the Scheduled Daily Delivery at the Points of Delivery, the Daily
Contract Quantity at the Tennessee Point of Interconnection shall be
deemed to be equal to the Daily Contract Quantity defined above less
2,497.5 Mcf (the "Niagara Daily Contract Quantity") and the Daily
Contract Quantity at the Empire Point of Interconnection shall be
deemed to be equal to 2,497.5 Mcf (the "Chippawa Daily Contract
Quantity").
5. Article III, Points of Delivery, is amended as follows:
(a) by deleting the word "POINT" in the title and substituting
the word "POINTS" therefore;
(b) by adding before the words "Point of Interconnection" in the
first sentence the words "Empire Point of Interconnection for the Chippawa
Daily Contract Quantity and shall be the Tennessee";
(c) by adding after the words "for the account of Buyer" in the
first sentence the words "for the Niagara Daily Contract Quantity";
(d) by deleting the word "Tennessee" at each place that it
appears in the second sentence and substituting the words "U.S.
Transporters" therefore; and
(e) by deleting the word "Tennessee's" in the second sentence
and substituting the word "U.S. Transporters'" therefore.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 4
6. Article IV, Delivery Pressure, is amended by adding after the words
"700 pounds per square inch gauge" the words "at the Tennessee Point of
Interconnection, and not less than 1225 pounds per square inch gauge at the
Empire Point of Interconnection."
7. Article VII, Price, Section 3 (as amended) is amended as follows:
(a) by deleting the words "point of delivery" in subsection (i) of the
first paragraph and substituting the words "Tennessee Point of Interconnection"
therefore;
(b) by deleting the "." at the end of subsection (iii) of the first
paragraph and substituting a ";" therefore;
(c) by inserting before the last sentence of the first paragraph the
following proviso:
provided, however, that the Monthly Demand Charge shall be increased
or decreased, as appropriate, by an amount equal to the product of
the Chippawa Daily Contract Quantity and the difference between the
monthly demand tolls (including the monthly demand component of the
delivery pressure tolls) per Mcf as determined by Canada's National
Energy Board and in effect on the first day of the month applicable
to the transportation of firm gas on Seller's system to the Tennessee
and Empire Points of Interconnection.;
and
(d) by inserting after the words "Demand Charge Rate" at the beginning
of the second paragraph the clause ", and, with respect to the proviso in the
preceding paragraph, the difference between the monthly demand tolls per Mcf on
Seller's system to the Tennessee and Empire Points of Interconnection,".
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 5
8. Article VII, Price, Section 4, is amended by deleting the period and
inserting the following new proviso at the end thereof:
; provided, however, that the Commodity Charge in respect of the
Chippawa Daily Contract Quantity shall be increased or decreased,
respectively, by (i) the differential calculated in accordance with
the proviso in Section 3 above, (ii) an amount equal to the amount
by which the commodity toll applicable to the firm transportation
of gas to the Empire Point of Interconnection exceeds or is less than
the commodity toll applicable to the firm transportation of gas to the
Tennessee Point of Interconnection [Niagara], (iii) an amount equal to
the amount by which the commodity component of the delivery pressure
toll applicable to the firm transportation of gas to the Empire Point
of Interconnection exceeds or is less than the commodity component of
the delivery pressure toll applicable to the firm transportation of
gas to the Tennessee Point of Interconnection and (iv) an amount equal
to the product of the commodity charge, as otherwise determined for the
Tennessee Point of Interconnection, and the differential between the
fuel requirement applicable to the firm transportation of gas to the
Empire and Tennessee Points of Interconnection, calculated per MMbtu.
9. Article VIII, Billings and Payment, is amended by adding the words "at
each Point of Delivery" after the words "daily and total quantity of gas
delivered hereunder" in the first sentence of Section 1(a) and in the second
sentence of Section 1(b).
10. Article IX, Quality, is amended by deleting the phrase "Point of
Delivery" in the first sentence of Section 1 and substituting the phrase "Points
of Delivery" therefore.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 6
11. Article X, Measurement of Gas, is amended as follows:
(a) by deleting the phrase "Point of Delivery" at each place that it
appears and substituting the phrase "Points of Delivery" therefore;
(b) by deleting the word "Tennessee" at each place that it appears
and substituting the words "U.S. Transporters" therefore; and
(c) by deleting the word "its" in Section 3. (b) and substituting the
word "their" therefore.
12. Article XII, Force Majeure, is amended as follows:
(a) by deleting the word "Tennessee" at each place that it appears
and substituting the words "U.S. Transporters" therefore;
(b) by deleting the words "the Point of Delivery" in the second
sentence of Section 1 and substituting the words "a Point of Delivery"
therefore; and
(c) by deleting the words "Point of Delivery" at both places that
they appear in Section 3 and substituting the words "Points of Delivery"
therefore.
The effectiveness of these amendments is subject to (i) obtaining such
changes as are appropriate to the long term import and export authorizations
currently held in connection with the Purchase Contract and (ii) the receipt of
any necessary approvals from the Federal Energy Regulatory Commission ("FERC")
for related changes that must be made to Boundary's FERC Gas Tariff. Boundary
and TransCanada agree that they will use their best commercially reasonable
efforts to seek to obtain and cause the other to seek to obtain the regulatory
and governmental authorizations necessary to effectuate the terms of this Fifth
Amendment.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 7
This letter agreement shall be binding upon and inure to the benefit
of the parties hereto and their respective successors and assigns.
If this letter agreement properly states our agreement, please
acknowledge that fact by signing in the space below and returning an executed
copy to me.
Sincerely,
Boundary Gas, Inc.
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
12 DAY OF March, 1996
TRANSCANADA PIPELINES LIMITED
By: /s/ Joel G. Johnson
----------------------------------
JOEL G. JOHNSON
Title: Vice President, Marketing
----------------------------------
By: /s/ G. Lawrence Spackman
----------------------------------
G. LAWRENCE SPACKMAN
Title: President
----------------------------------
<PAGE>
AMENDMENT TO
PHASE 2 GAS SALES AGREEMENT
---------------------------
This Contract, to be called Amendment to Phase 2 Gas Sales Agreement, is
made as of this 20th day of August, 1997 by and between Boundary Gas, Inc., a
Delaware corporation (herein called "Boundary") and the following fifteen (15)
United States companies signatory hereto (which collectively own all of the
stock of Boundary): The Brooklyn Union Gas Company, Bay State Gas Company,
Northern Utilities, Inc., New Jersey Natural Gas Company, Boston Gas Company,
Yankee Gas Services Company, Consolidated Edison Company of New York, Inc.,
National Fuel Gas Distribution Corporation, Long Island Lighting Company,
Connecticut Natural Gas Corporation, Essex County Gas Company, EnergyNorth
Natural Gas, Inc., Valley Gas Company, Berkshire Gas Company, and Fitchburg Gas
and Electric Light Company (herein collectively called "Repurchasers").
W I T N E S S E T H :
WHEREAS, the Gas Purchase Contract between Boundary and TransCanada
PipeLines Limited ("TransCanada") dated September 14, 1987, as amended ("Gas
Purchase Contract"), has been amended, in pertinent part, to reflect changes
agreed upon in the resolution of certain pricing disputes between Boundary and
TransCanada (a copy of which amendment is attached hereto);
<PAGE>
WHEREAS, the amendments to the Gas Purchase Contract involve the
implementation of a U.S. pipeline rate refund protocol and impose a time
limitation for adjusting overcharges and undercharges under the Gas Purchase
Contract;
WHEREAS, these amendments require corresponding amendments to the Gas Sales
Agreement among Boundary and the Repurchasers dated September 14, 1987, as
amended ("Gas Sales Agreement");
NOW THEREFORE, the parties hereto agree to amend the Gas Sales Agreement,
effective as of the date of the amendments to the Gas Purchase Contract, as
follows:
1. Article X, Section 5 shall be amended by inserting the
phrase "and claimed within twelve (12) months of the date
payment is due under the invoice containing such error"
immediately after the word "Boundary," on the penultimate
line thereof.
2. Effective as of November 1, 1995, the Gas Sales Agreement
is deemed amended as necessary to permit the implementation
of the protocol entitled "Treatment of Increases in U.S.
Pipeline Rates in the Calculation of the Price of Gas Pursuant
to Article VII" and attached to an amending agreement between
Alberta Northeast Gas Limited and TransCanada dated November
17, 1995.
IN WITNESS WHEREOF, this Amendment to the Phase 2 Gas Sales Agreement is
executed as of the date written above.
2
<PAGE>
ATTEST: FITCHBURG GAS AND ELECTRIC
LIGHT COMPANY
_______________________________ By_________________________________
(Seal)
ATTEST: BAY STATE GAS COMPANY
_______________________________ By_________________________________
(Seal)
ATTEST: NORTHERN UTILITIES, INC.
_______________________________ By_________________________________
(Seal)
ATTEST: BOSTON GAS COMPANY
By /s/ William R. Luthern
_______________________________ ---------------------------------
(Seal)
5
<PAGE>
Boston Gas 10-K
10.9.2
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.
<PAGE>
NATURAL GAS SALES - AMENDING AGREEMENT
--------------------------------------
THIS AGREEMENT, made as of the Effective Date,
BETWEEN:
IMPERIAL OIL RESOURCES, an Alberta limited partnership,
with its principal place of business in Calgary, Alberta ("Seller")
and
BOSTON GAS COMPANY, a Massachusetts Corporation with
its principal place of business in Boston, Massachusetts ("Buyer").
WHEREAS the parties desire to amend the Gas Contract to reflect the new supply,
transportation, and pricing arrangements set forth in this Agreement;
WHEREAS the Western Canada gas supply and the transportation on the NOVA, TCPL,
Iroquois and Tennessee pipeline systems associated with the Gas Contract shall
be replaced by SOEP gas supply and related transportation;
WHEREAS the timing and details of these restructured supply and transportation
arrangements are as set out herein and will apply prior to and following the
commercial start-up of SOEP gas production and the operation of a pipeline
system(s) allowing deliveries from the SOEP gas plant located at or near
Goldboro, Nova Scotia to Dracut, Massachusetts;
AND WHEREAS it is the intention of the parties that, upon MDPU Approval, the
Amended Gas Contract will be given full force and effect thereby providing
certainty and predictability of the commercial arrangements provided for therein
for its full term.
NOW, THEREFORE in consideration of the premises and mutual covenants herein
contained, the parties agree as follows:
1. DEFINITIONS
-----------
1.1 Capitalized terms used in this Agreement which are not defined herein shall
have the meanings given to them in the Gas Contract.
1.2 The following definitions, contained in the Gas Contract, are deleted:
Section 1.1(c)(i), (ii) and (iii) "Base Gas"; Section 1.1(j) "Commodity
Charge"; Section 1.1(k) "Consumption
<PAGE>
Page 2
Market"; Section 1.1(m) "Contract Year"; Section 1.1(p) "Daily
Underdelivery"; Section 1.1(r) "Demand Charge" or 'Demand Charge
Components" or "Canadian Monthly Demand Charge"; Section 1.1(u) "Excused
Performance"; Section 1.1(v) "Firm Consumption Market"; Section 1.1(w)
"Firm Direct Sale"; Section 1.1(ff) "Maximum Daily Quantity" or "MDQ";
Section 1.1(gg) "Minimum Quarterly Quantity"; Section 1.1(hh) "Minimum Take
Deficiency"; Section 1.1(mm) "Non-Excused Performance"; Section 1.1(kk)
"New Base Price"; Section 1.1(oo)(i), (ii) and (iii) "Offset Demand
Charges"; Section 1.1(pp) "Performance Calculation"; Section 1.1(uu)
"Replacement Gas Supply"; Section 1.1(yy) "Spare Capacity"; Section
1.1(ddd) "Total Usage"; Section 1.1(eee) "Transportation Charge"; Section
1.1(fff) "Unit Cost Difference"; and Section 1.1(ggg)(i), (ii), (iii), (iv)
and (v) "Unpurchased Gas".
1.3 Section 1.1(g) "Canadian Transporter(s)" of the Gas Contract is amended by
adding "or M&NP" to the end of the section.
1.4 The definition of "Commencement of Firm Deliveries" in Section 1.1(i) of
the Gas Contract is deleted and replaced with "Commencement of Firm
Deliveries means the first date on which commercial deliveries of Seller's
Gas from SOEP are received at Dracut, Massachusetts".
1.5 Section 1.1(I) "Contract Amount" is amended by deleting the phrase "and
shall be comprised of the Transportation Charge and the Commodity Charge".
1.6 The definition of "Point of Delivery" in Section 1.1(qq) of the Gas
Contract is deleted and replaced with the following:
(i) Until the Commencement of Firm Deliveries there is no point of
delivery as Seller will have no natural gas supply obligations prior
to this date.
(ii) Following the Commencement of Firm Deliveries point of delivery will
be the point of interconnection between the outlet of the SOEP
process plant located at or near Goldboro, Nova Scotia and the inlet
to the M&NP pipeline system, through which Gas will be transported to
Dracut, Massachusetts.
1.7 Section 1.1(hhh) "United States Transporter(s)" of the Gas Contract is
amended by deleting the phrase "on the pipeline system of Champlain or
other pipelines".
1.8 The following defined terms are added:
(i) "Agreement" means this amending agreement.
(ii) "Amended Gas Contract" means the Gas Contract as amended by this
Agreement.
(iii) "Billing Month" has the meaning set forth in Section 8.4 below.
<PAGE>
Page 3
(iv) "Daily Contract Quantity" or "DCQ" means the daily volume of Gas,
from any source, delivered to Buyer by Seller at the Point of
Delivery following the Commencement of Firm Deliveries. The DCQ
shall not be less than Seller's share as it exists from time to
time of Seller's daily SOEP Gas production, but in no circumstances
shall the DCQ be greater than the Max DCQ. To the extent there is a
Shortfall on any Day, Buyer has the right to purchase the Shortfall
from a third party.
(v) "Daily Undispatched Quantity" has the meaning set forth in Section
5.4 below.
(vi) "Deficiency Quantity" has the meaning set forth in Section 5.5
below.
(vii) "Effective Date" means the later of November 1, 1997, or, the first
Day of the month following MDPU Approval.
(viii) "Force Majeure" has the meaning set forth in Section 6.2 below.
(ix) "Gas Contract" means the existing natural gas sales agreement
between the parties, or their predecessors, entered into on May 1,
1989, as amended on October 30, 1992 and by amendment dated October
28, 1997.
(x) "Max DCQ" means the maximum level of the DCQ, corresponding to the
SOEP Interest, as determined in accordance with Schedule "B",
attached hereto and forming part of this Agreement.
(xi) "M&NP" means Maritimes and Northeast Pipeline, L.L.C., a limited
liability company formed under the laws of the state of Delaware,
or Maritimes & Northeast Pipeline Limited Partnership, a limited
partnership formed under the laws of the province of New Brunswick,
or both of them.
(xii) "MDPU" means the Massachusetts Department of Public Utilities.
(xiii) "MDPU Approval" means approval of this Agreement by the MDPU in
form and substance acceptable to both parties, such acceptability
to be communicated by each party to the other within five (5)
business days following receipt of such approval.
(xiv) "Price Difference" means the difference between CP2 and the volume
weighted average price received by Seller for the Daily
Undispatched Quantity or the Deficiency Quantity, as applicable.
(xv) "SOEP" means the Sable Offshore Energy Project comprising the
project lands set out in Schedule A, attached hereto and forming
part of this Agreement.
<PAGE>
Page 4
(xvi) "Shortfall"" means the positive difference, if any, resulting from
subtracting the DCQ from the Max DCQ, on any Day.
(xvii) "SOEP Interest" means Seller's, or its Affiliates', actual working
interest in SOEP, as provided for, upon the execution of the
ownership and operating agreements currently being negotiated among
the SOEP Owners.
(xviii) "SOEP Market Price" has the meaning set forth in Section 7.6(ii)
below.
(xix) "SOEP Owners" means the owners of SOEP as they may exist from time
to time, including assigns and successors. As of the date of
execution of this Agreement the SOEP Owners are Seller, or its
Affiliate, Mobil Oil Canada Properties, Shell Canada Limited, and
Nova Scotia Resources (Ventures) Limited, and if applicable,
Mosbacher Operating Ltd.
(xx) "Straddle Plant" has the meaning set forth in subsection 11.3.1
below.
(xxi) "Third Party" has the meaning set forth in Section 11.3 below.
2. INTENTIONS OF THE PARTIES
-------------------------
2.1 Article II of the Gas Contract is deleted and replaced with Articles 2 and
3 of this Agreement.
2.2 Except for matters concerning the enforcement of the Amended Gas Contract,
Buyer and Seller agree to not initiate, support or voluntarily participate,
directly or indirectly, in any processes or activities which could
reasonably be anticipated to threaten, obstruct or otherwise interfere with
the performance of the Amended Gas Contract, throughout its term.
3. REGULATORY
----------
3.1 Buyer will, in good faith, proceed diligently and expeditiously in taking
all steps as are reasonably necessary to obtain MDPU Approval of this
Agreement.
3.2 Notwithstanding anything in the Gas Contract or this Agreement, except
Sections 3.1 and 3.4 herein, this Agreement is subject to MDPU Approval. If
MDPU Approval is not received, the Gas Contract will continue to remain in
full force and effect for the duration of its term, unaltered by this
Agreement. Buyer and Seller further agree that if MDPU Approval is not
received, such non-approval shall not be, or be deemed to be, an Order, as
defined in Section 16.2(a) of the Gas Contract, for the purposes of Section
6.7(b) of the Gas Contract.
<PAGE>
Page 5
3.3 Following MDPU Approval, Buyer and Seller agree:
(i) to proceed in good faith in performing their respective obligations
as set out or contemplated in the Amended Gas Contract, throughout
its term;
(ii) that Seller will take all steps as are reasonably necessary to amend
or rescind, as appropriate, the existing export license and removal
permit; and,
(iii) subsequently to jointly apply for and hold any new NEB export license
and removal permit, as may be required.
3.4 Buyer and Seller agree that each of them shall diligently and expeditiously
take all steps and do such things as are reasonably necessary in applying
for and obtaining any and all license and/or regulatory amendments,
revisions, permits, approvals or authorizations as may be required to give
effect to the provisions of this Article 3, and the parties agree to
cooperate with, and support, each other in this regard.
4. TERM OF AGREEMENT
-----------------
4.1 Article III of the Gas Contract is deleted and replaced by this Article 4.
4.2 The Amended Gas Contract becomes effective on the Effective Date.
4.3 The Amended Gas Contract expires on March 31, 2007.
5. QUANTITY
--------
5.1 Articles IV and V of the Gas Contract are deleted and replaced by the
provisions of this Article 5.
5.2 During the term of the Amended Gas Contract prior to the Commencement of
Firm Deliveries, Seller shall have no natural gas supply or transportation
obligations under the Amended Gas Contract. Notwithstanding the above,
during this period Buyer shall pay Seller on deemed delivered volumes in
accordance with the terms of Section 7.2 below.
5.3 Subject to the provisions of this Article 5, effective with the
Commencement of Firm Deliveries, Seller shall deliver and sell and Buyer
shall receive and purchase the DCQ at the Point of Delivery.
5.3.1 if Seller cannot deliver any portion of the DCQ due to an event of
Force Majeure, Seller shall so notify Buyer in accordance with the
provisions of Section 6.3 below.
<PAGE>
Page 6
5.3.2 Subject to the provisions of subsection 5.3.3 below, to the extent
Seller is aware that the DCQ will be less than the Max DCQ, Seller
shall notify Buyer of expected Shortfall as soon as is reasonably
practicable.
5.3.3 On those Days when third party purchases by Seller constitute a
portion of the DCQ, and to the extent the DCQ is still expected to
be below the Max DCQ, Seller shall notify Buyer of the expected
Shortfall no less than five (5) business days prior to the Day in
which the Shortfall is expected to occur.
5.4 To accommodate Buyer's least cost economic dispatch requirements, Buyer has
the right on any Day to purchase quantities of Gas below the DCQ subject to
the conditions outlined in subsection 5.4.1 through 5.4.3 below. The
difference between the DCQ and the volume actually taken by Buyer each Day
is the "Daily Undispatched Quantity".
5.4.1 On each and every day that a Daily Undispatched Quantity occurs,
Buyer shall make available to Seller, Buyer's transportation from
the Point of Delivery to Buyer's distribution system at no cost to
Seller for the purpose of disposing of the Daily Undispatched
Quantity. Seller shall use reasonable efforts to sell the Daily
Undispatched Quantity at the most favourable price available to
Seller using the Buyer's transportation as required.
5.4.2 In the event the volume weighted average price realized by the
Seller at the Point of Delivery in selling the Daily Undispatched
Quantity is less than CP2, as defined in Section 7.6 below, during a
month, Buyer shall pay Seller for that month an amount equal to the
sum of the products of:
(a) the Daily Undispatched Quantity in each Day of the month; and,
(b) the Price Difference.
5.4.3 In the event the volume weighted average price realized by the
Seller at the Point of Delivery in selling the Daily Undispatched
Quantity is greater than CP2, as defined in Section 7.6 below,
during a month, Seller shall pay Buyer for that month an amount
equal to the sum of the products of:
(a) the Daily Undispatched Quantity in each Day of the month; and,
(b) the Price Difference.
5.5 If Buyer purchases on any Day a daily quantity of Gas less than the DCQ
pursuant to Section 5.3 above for any reasons other than Force Majeure, as
defined in Section 6.2 below, or Buyer's economic dispatch requirements
pursuant to Section 5.4 above, then Buyer shall pay Seller for that month
an amount equal to the sum of the products of:
(i) the difference between the DCQ, and the volume actually taken
("Deficiency Quantity") in each Day of the month; and,
(ii) the Price Difference.
<PAGE>
Page 7
5.6 For the purposes of Sections 5.4 and 5.5:
(i) Seller shall use all reasonable efforts to mitigate the Price
Difference; and,
(ii) Buyer shall pay Seller for any incremental expenses reasonably
incurred by Seller in selling the Daily Undispatched Quantity or the
Deficiency Quantity, as applicable.
6. FORCE MAJEURE
-------------
6.1 Article XV of the Gas Contract is deleted and replaced with the following
provisions.
6.2 Force Majeure means, except for and subject to the exclusions outlined
below, acts of God, strikes, lockouts, or industrial disputes or
disturbances, riots, civil disturbances, interruptions by government,
compliance with any court order, law, statute, ordinance or regulation
promulgated by a governmental authority having jurisdiction, the Nova
Scotia government taking its royalty share of natural gas in kind, failure
of transportation pipeline, failure of gas processing plant, failure of gas
gathering system, failure of gas production facilities, required plant
shut-downs for maintenance, or any other cause not reasonably within the
control of the party claiming Force Majeure and which by the reasonable
exercise of due diligence of such party could not have been prevented or is
unable to be overcome. Force Majeure specifically excludes:
(i) loss of markets;
(ii) increases or decreases in the market price of natural gas;
(iii) the loss, interruption, or curtailment of interruptible
transportation;
(iv) actions of Canadian or U.S. Regulatory Authorities of the types
contemplated under Article XVI of the Gas Contract; or,
(v) lack of funds.
6.3 In the event either party hereto is rendered unable by reason of Force
Majeure to carry out its obligations, upon such claiming party giving
notice to the other party with full particulars of such Force Majeure as
promptly as is reasonably practicable after the occurrence of the event,
the obligations of the claiming party occasioned by, or in connection with,
or in consequence of the Force Majeure shall be suspended for the duration
of the Force Majeure event. A party claiming Force Majeure shall attempt to
remedy the Force Majeure as soon as is reasonably possible. Nothing in this
Article 6 shall relieve a party of the obligation to make any outstanding
payments due under the Amended Gas Contract. As soon as possible after the
Force Majeure has been remedied, the party claiming suspension shall give
notice that the Force Majeure has been remedied and the party has resumed
or will resume the performance of its obligations.
<PAGE>
Page 8
7. COMMODITY PRICE
---------------
7.1 Sections 6.1 and 6.3 of the Gas. Contract are deleted. In addition, the
pricing provisions of subsections 6.4(a) and 6.4(b) of the Gas Contract are
deleted and replaced by the following provisions.
7.2 During the term of the Amended Gas Contract from the Effective Date and
continuing until the Commencement of Firm Deliveries, Buyer shall pay
Seller the difference between CP1 and P2 based on a deemed natural gas
volume of 38000 MMBtu/day, where
CP1 = [0.75 x P1] + [0.25 x P2], where P1 and P2 are defined as
follows:
P1 = the Henry Hub first of month index as reported in Inside
------
F.E.R.C.'s Gas Market Report in units of US$/MMBtu less $
----------------------------
US/MMB tu.
P2 = the Monthly Alberta Spot Price where the Monthly Alberta Spot
Price is the price index for firm one month intra-Alberta gas
deliveries as published in the Canadian Gas Price Reporter
under the heading "AECO & N.I.T. One Month Spot" in units of
C$/G. This price shall be converted to US$/MMBtu using the
average monthly noon-day exchange rates as published by the
Royal Bank of Canada and an energy conversion factor of
1.054615 GJ/MMBtu.
7.3 Notwithstanding anything in the Amended Gas Contract except Section 3.2 of
this Agreement, the pricing and payment obligations of Buyer outlined in
Section 7.2 above shall endure and continue in force and effect
notwithstanding Seller being unable to deliver the DCQ for any one or more
of the following, or similar, reasons:
(i) project schedule delays to the commercial start-up of SOEP facilities
or the M&NP pipeline system to Dracut, Massachusetts, for any reason;
(ii) failure of any governmental or regulatory body, having jurisdiction,
to approve any required amendments to existing export or import
licenses or authorizations held pursuant to the Gas Contract;
(iii) cancellation of any export or import license or authorization, held
pursuant to the Gas Contract or the Amended Gas Contract, by any
governmental or regulatory body having jurisdiction;
(iv) failure of any governmental or regulatory body, having jurisdiction,
to approve the export or import of SOEP Gas;
(v) failure to obtain any governmental or regulatory approvals for SOEP
on terms acceptable to the SOEP Owners;
<PAGE>
Page 9
(vi) failure to obtain any governmental or regulatory approvals of the
M&NP pipeline system(s) necessary to enable commercial delivery of
Gas from the SOEP plant gate to Dracut, Massachusetts;
(vii) the SOEP Owners determine that SOEP natural gas reserves are no
longer commercially economic to recover or produce;
(viii) failure to obtain Seller's, or its Affiliates', final management
approval to proceed with SOEP; or
(ix) subject to Sections 7.4 and 7.5 below, the divestment or transfer of
the SOEP Interest.
7.4 Subject to Section 7.5 below, if the SOEP Interest is divested or
transferred to a third party, Buyer shall have the right to elect to have
the remaining term of the Amended Gas Contract assigned to the said third
party, provided Seller is notified by Buyer of its election within fifteen
(15) days following notification by Seller to Buyer of the planned
divestment or transfer, as applicable.
7.5 If any or all of the SOEP Interest is divested or transferred, for any
reason, to one or more of the other SOEP Owners, and Buyer elects to have
the remaining term of the Amended Gas Contract assigned to the applicable
SOEP Owner(s) pursuant to Section 7.4 above, and if as a result of such
divestment or transfer Seller does not obtain sufficient consideration from
the said SOEP Owner(s) to fully compensate Seller for the full value of the
remaining term of the Amended Gas Contract, Buyer agrees to indemnify and
keep Seller whole to the full extent of the deficiency. For purposes of
this Section 7.5, full value of the remaining term of the Amended Gas
Contract shall mean the net present value, using a discount rate of six (6)
percent, of any remaining payments due from Buyer to Seller assuming full
performance under the Amended Gas Contract by both parties.
7.6 Subject to Article 10 below, from the Commencement of Firm Deliveries until
the expiration of the Amended Gas Contract, the commodity price ("CP2") of
volumes of Gas sold and purchased under the Amended Gas Contract, including
fuel gas consumed in the pipeline compressors downstream of the Point of
Delivery, shall be, in units of US$/MMBtu, the higher of:
(i) HH - BD, where HH and BD are defined as follows:
HH = Henry Hub first of month index as reported in Inside F.E.R.C.'s
-----------------
Gas Market Report,
-----------------
BD = as set out in Schedule B, attached hereto and forming part of
this Agreement; or,
<PAGE>
Page 10
(ii) the "SOEP Market Price", defined as the prevailing market price at the
SOEP plant gate as represented by the average of all first of month
price indices published for this location. In the event that no first
of month price index develops for the SOEP plant gate location then
CP2 is defined by item (i) in this Section 7.6.
7.7 In the event any one of the published price indices referenced in this
Article 7 is not available or ceases to exist, Buyer and Seller agree to
act in good faith to select a reasonable replacement price index as
required. Should the parties fail to agree on a replacement price index,
either party may, by giving written notice to the other, submit the matter
to arbitration in accordance with the arbitration provisions of Sections
6.6(b) and 6.6(c) and Article XVII of the Gas Contract and Article 10 of
this Agreement, as applicable.
8. PAYMENTS
--------
8.1 Any and all amounts payable arising out of the Amended Gas Contract shall
be made in accordance with the provisions of Article VII of the Gas
Contract as amended by this Article 8.
8.2 Sections 7.1 through 7.3 of the Gas Contract are deleted and replaced with
the following provisions.
8.3 Section 7.4 of the Gas Contract is amended by deleting the reference to
"Subsection 20.2" in the tenth line and replacing it with "Section 5.3 of
the Agreement".
8.4 As of the Effective Date, Seller shall, on or before the 15th Day of each
Month (a "Billing Month"), render to Buyer a statement showing the deemed
quantity of natural gas pursuant to Section 7.2 above, or the actual
quantity of Gas delivered during the preceding Month at the Point of
Delivery, pursuant to Section 5.3 above, as applicable, and the amounts
payable based on the applicable commodity prices pursuant to Article 7
herein. The statement shall also include and describe all other applicable
charges or credits, as applicable, pursuant to the Amended Gas Contract.
8.5 Buyer shall make payment within ten (10) Days following receipt of the
statement described in Section 8.4 above, or by the 25th Day of the Billing
Month, whichever is later. Any adjustments necessary to reflect actual
deliveries or otherwise shall be made in the following Monthly statement,
if possible, or within the period provided in Section 7.5 of the Gas
Contract in any event.
9. WAIVER OF FINANCIAL KEEP WHOLE PROVISIONS AND INDEMNIFICATION
-------------------------------------------------------------
9.1 Articles XIV and XX of the Gas Contract are deleted.
<PAGE>
Page 11
9.2 As of the Effective Date, all supply assurances and associated commodity
keep whole obligations contained in the Gas Contract will terminate. For
greater certainty, under the Amended Gas Contract Seller's only natural
gas supply obligation, will be to deliver the DCQ, subject to Sections 5.3
and 7.3 above.
9.3 As of the Effective Date and prior to the Commencement of Finn Deliveries,
Seller shall have no obligations to pay transportation demand charges, or
transportation charges of any kind, in conjunction with the Amended Gas
Contract, except that from and after the Commencement of Firm Deliveries
Seller shall be responsible for all transportation charges necessary to
deliver the DCQ to the Point of Delivery.
9.4 Buyer shall indemnify and save Seller harmless against all third party
actions, proceedings, claims (including claims of third parties for
consequential damages), debts, demands, losses, costs, damages, expenses
and liabilities which may be brought against or suffered by Seller or
which it may sustain, pay or incur by reason of Seller not delivering Gas,
so long as Seller is in compliance with its obligations under the Amended
Gas Contract, or any reason whatsoever or by reason of personal injury or
property damage sustained after Gas is delivered to the Point of Delivery.
9.5 Damages and costs resulting from Buyer purchasing on any day a daily
quantity of gas less than the DCQ are limited to those set forth in the
Amended Gas Contract. Damages and costs for other actions or non-actions
are as specified or contemplated in the Amended Gas Contract. In no event
shall either party be liable to the other for consequential, special, or
punitive damages of the other party regardless of breach of the Amended
Gas Contract.
10. PRICE REOPENER
--------------
10.1 Section 6.6(a) of the Gas Contract is deleted and replaced by this Article
10.
10.2 In order to initiate the next and only other price renegotiation for CP1
and CP2, as applicable, Buyer shall provide notice to Seller during the
period between June 1, 2002, and June 30, 2002, with any changes pursuant
to the renegotiation to become effective on November 1, 2002. The price
renegotiation shall be completed within 60 days of receipt of such notice.
Notwithstanding the above, in no event shall this price renegotiation
cause a decrease in BD. If the parties do not agree upon a renegotiated
price within the said 60 day period, either party may, by giving written
notice to the other, prior to November 1, 2002, submit the matter to
arbitration in accordance with the provisions of the Amended Gas Contract.
10.3 Throughout Sections 6.6(b) and 6.6(c) of the Gas Contract the phrase "Gas
being purchased on a competitive basis in Massachusetts under long term
firm contracts" shall be amended to read "Gas being purchased from the
U.S. Gulf Coast supply region on a competitive basis in Massachusetts
under firm contracts of term length of one year and
<PAGE>
Page 12
greater". In the absence of a threshold volume of 100,000 MMBtu/day of
such firm contracts of term length of one year or greater available in a
form reasonably suitable for use in the arbitration process as envisioned
by Section 6.6 of the Amended Gas Contract, the commodity price of Gulf
Coast gas supplies in Massachusetts for the purposes of the arbitration
process as envisioned by Section 6.6 of the Amended Gas Contract shall be
equal to the sum of:
(i) the arithmetic average variable transportation costs, including the
cost of fuel gas, incurred in delivering Gulf Coast gas to Boston by
way of the following routes: (a) Tennessee Gas Pipeline Company;
and, (b) Texas Eastern Transmission Corporation and Algonquin Gas
Transmission Company; and,
(ii) the arithmetic average of the first of Month indices as published in
Inside F.E.R.C.'s Gas Market Report for the following six locations:
-----------------------------------
Tennessee Gas Pipeline Company Zones 0 and 1; and the Texas Eastern
Transmission Corporation's Zones STX, ETX, WLA and ELA.
10.4 In establishing the average variable transportation costs pursuant to
subsection 10.3(i) above, the arbitrator shall take into account the
effects of differing rate designs on the SOEP and Gulf Coast pipelines.
Modified fixed variable rate designs, wherein fixed pipeline costs become
included in the commodity component of the transportation toll, should not
be compared with straight fixed variable designs, wherein fixed pipeline
charges are not included in the commodity component of the transportation
toll. This is to ensure that neither SOEP, nor Gulf Coast supply, are
unfairly disadvantaged by such rate design characteristics in the
competitive comparison contemplated under Section 6.6 of the Gas Contract.
10.5 Throughout Sections 6.6(b) and 6.6(c) of the Gas Contract, the term "New
Base Price" is amended to read "CP1 or CP2, as applicable".
11. TRANSPORTATION
--------------
11.1 Articles IX, X and XI of the Gas Contract are amended substituting "M&NP"
in place of "Nova" or "TCPL", as applicable, as required in the context of
those provisions.
11.2 Buyer is responsible for arranging and paying all costs associated with
holding capacity on the M&NP pipeline system to take delivery of the DCQ
at the Point of Delivery. The terms of such transportation arrangements
are left to the Buyer's discretion recognizing that Buyer remains liable
for the amounts pursuant to Sections 5.4, 5.5 and 5.6 above, should Buyer
be unable to take delivery of the DCQ, including as a result of Buyer not
holding the proper amount or type of transportation capacity.
11.3 Seller shall be free to release or assign the Canadian pipeline
transportation currently held by Seller in association with the Gas
Contract, and Buyer shall be free to release or assign
<PAGE>
Page 13
the U.S. pipeline transportation currently held by Buyer in association
with the Gas Contract, with an effective release or assignment date being
as of the Effective Date, subject to the provisions of Section 11.4 below.
Seller agrees to assign the Canadian pipeline transportation currently
held by Seller in association with the Gas Contract to Buyer, or a third
party designated by Buyer ("Third Party"), at Buyer's option, subject to
tile provisions of subsections 11.3.1 and 11.3.2 below.
11.3.1 Assignment of the transportation currently held by Seller,
pursuant to Section 11.3 above, is conditional on Seller retaining
title to the natural gas associated with the NOVA delivery
capacity, as it moves through the straddle plant facilities at
Empress, or McNeill (the "Straddle Plant"), and Seller capturing
all economic benefits thereby accruing. This condition will be
satisfied in accordance with the provisions of subsection 11.3.2
below. The arrangements contemplated in subsection 11.3.2 shall be
documented by Seller and Buyer in a separate agreement to take
effect on the Effective Date. To the extent it is necessary for
the Third Party to be party to such separate agreement, the Buyer
shall obtain the agreement of the Third Party.
11.3.2 Seller shall retain the said Empress NOVA delivery capacity and
the parties agree to implement the following purchase and re-sale
arrangement. The Third Party or Buyer, as applicable, shall sell
natural gas to Seller at an intra-Alberta delivery point for a
price equal to P2 and Seller shall re-sell said natural gas to
Third Party or Buyer, as applicable, at Empress, or McNeill, into
the TCPL system, for a price equal to P2 plus full NOVA tolls as
may be in effect from time to time for transportation between
intra-Alberta and Empress, or McNeill, delivery points,
respectively.
11.4 In the event the NOVA delivery capacity at Empress, or McNeill, and the
TCPL capacity between Empress, or McNeill, and Iroquois currently held by
Seller in association with the Gas Contract is released at a discounted
rate from the rate payable by Seller under Seller's associated NOVA and
TCPL pipeline transportation agreements, Buyer agrees to indemnify and
save Seller harmless to the full extent of such difference for the full
term of tile Amended Gas Contract. These indemnification payments shall be
made monthly in accordance with the provisions of Article VII of tile
Amended Gas Contract.
12. GOODS AND SERVICES TAX
----------------------
12.1 "GST" means the goods and services tax pursuant to the Excise Tax Act
(Canada), as amended (the "Excise Tax Act").
12.2 If Buyer intends to export from Canada any of the Gas purchased under the
Amended Gas Contract and wishes to have that Gas zero-rated for GST
purposes pursuant to the Excise Tax Act at least ten (10) Days prior to
the day when Seller is obligated to deliver an
<PAGE>
Page 14
invoice, Buyer shall advise Seller of the amount of Gas which Buyer
intends to export and represent and warrant in writing that it has
complied with all of the provisions of the Excise Tax Act required to
permit Seller to zero-rate that Gas.
12.3 Buyer shall indemnify Seller for any GST related liability incurred by
Seller which results from any breach of any of the provisions,
representations or warranties required under Section 12.2.
12.4 Notwithstanding any other provision of the Amended Gas Contract, in the
event that any amount becomes payable by a party to the Amended Gas
Contract as a result of a breach, modification or termination of the
Amended Gas Contract and Section 182 of the Excise Tax Act applies to that
amount, the amount payable shall be increased such that following the
deduction of any applicable GST, the payee shall be left with an amount
equal to the original amount payable.
13. MISCELLANEOUS
-------------
13.1 To the extent that any provisions in this Agreement conflict with those in
the Gas Contract, the provisions of this Agreement will prevail.
13.2 Each of the parties shall do all acts, including making appropriate
regulatory filings, and execute and deliver all deeds and documents as are
reasonably required in order to fully perform and carry out the terms of
this Agreement or the Amended Gas Agreement, as applicable.
13.3 Buyer and Seller agree to provide each other with any information that may
be necessary to comply with any regulatory filing requirements hereunder.
Such information shall be kept strictly confidential by the other party
and used or disclosed only to comply with said requirements or as is
otherwise required by law.
In witness whereof this Agreement is executed effective as of the day and year
first written.
IMPERIAL OIL RESOURCES BOSTON GAS COMPANY
Per: /s/ D. D. Baldwin Per: /s/ W. R. Luthern
-------------------------------- -------------------------------
Name: D. D. Baldwin Name: WILLIAM R LUTHERN
------------------------------- ------------------------------
Title: Senior Vice President Title: VICE PRESIDENT
------------------------------ -----------------------------
12 NOV 97
<PAGE>
ENFOLIO(R) MASTER FIRM PURCHASE/SALE AGREEMENT
II
Enron Capital & Trade Resources Corp., a Delaware corporation ("Company"), and
-------
Boston Gas Company, a Massachusetts corporation ("Customer"), referred to
--------
collectively as the "Parties" enter into this Master Firm Purchase/Sale
-------
Agreement (together with all Transactions, collectively, this "Agreement")
---------
effective as of the 1st Day of November, 1997 (the "Effective Date"). The
--------------
ENFOLIO General Provisions set forth in Appendix "1" shall apply to this
------------
Agreement.
ARTICLE 1. TERM This Agreement shall govern all Transactions and be in effect
- ----------------
for a term of one year from the Effective Date. It shall then continue in
effect from Month to Month, unless terminated by either Party upon 30 Days prior
written notice to the other Party; provided, this Agreement shall continue to
apply to all Transactions then in effect until Transactions are completed.
Termination of this Agreement in all instances shall be subject to Section 8.4.
-----------
ARTICLE 2. SCOPE OF AGREEMENT 2.1. Scope of Agreement. Company and Customer
- ------------------------------ ------------------
from time to time during the term hereof may, but are not obligated to, enter
into Transactions for the firm purchase and sale of Gas to which this Agreement
shall apply. Each Transaction shall be effectuated and evidenced as set forth
in this Article 2 and shall constitute a part of this Agreement and all
---------
Transactions, together with this Agreement, shall constitute a single integrated
agreement. It is acknowledged that the Parties are relying upon the fact that
all Transactions, together with this Agreement, will form a single integrated
agreement and that the Parties would not otherwise enter into any Transactions.
Each Transaction shall be construed as one with this Agreement and any
discrepancy between this Agreement and a Transaction shall be resolved in favor
of the Transaction. Each Transaction shall provide whether the Transaction is
based upon DCQ quantity obligations or MinMQ or MinDQ and MaxDQ quantity
obligations, in which case the applicable Premative definitions and provisions
set forth in this Agreement shall apply.
2.2. Transaction Procedures. It is the intent of the Parties to facilitate
----------------------
Transactions in accordance with the agreed procedures in this Article 2 and
---------
assure that such Transactions are valid and enforceable as a result of the use
of these procedures for the mutual benefit of the Parties. Any Transaction may
be formed and effectuated (i) by a written paper-based Transaction Agreement
executed by the Parties (including by facsimile and/or counterparts) or (ii) in
a recorded telephone conversation between the Parties occurring on any Business
Day during the Pricing Hours whereby an offer and acceptance shall constitute
the agreement of the Parties to a Transaction as evidenced by the Transaction
Tape; provided, each Party may stipulate by prior notice to the other Party that
any particular contemplated Transaction may be effectuated and formed only by
means of procedure (i) above. The Parties shall be legally bound by each
Transaction from the time they agree to its terms in accordance with this
Article 2 and acknowledge that each Party will rely thereon in doing business
- ---------
related to the Transaction. The Transaction Tape is adopted by the Parties as a
means by which a Transaction is reduced to tangible form, and the Parties to a
Transaction are identified and authenticate a Transaction. Any Transaction
formed and effectuated pursuant to the foregoing shall be considered to be a
"writing" or "in writing" and to have been "signed" and any Transaction Tape
shall be considered to constitute an "original" document evidencing the
Transaction. Each Party consents to the recording of its employees' telephone
conversations without any further notice. Notwithstanding the other provisions
in this agreement permitting transactions to be effectuated and formed by means
of procedure (ii) above, the Parties agree that every Transaction shall be
formed and effectuated by procedure (i) above until such time as the Parties
execute an amendment to this agreement allowing the use of procedure (ii) above
to form and effectuate a Transaction hereunder.
2.3. Equipment and Transaction Tape. Company shall at its expense maintain
------------------------------
equipment necessary to regularly record Transactions on Transaction Tapes and
retain Transaction Tapes in such manner as to protect its business records from
improper access; provided, Company shall not be liable for any malfunction of
equipment or the operation thereof in respect of any Transaction WITHOUT REGARD
TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING, WITHOUT LIMITATION, THE
NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT,
OR ACTIVE OR PASSIVE. No Transaction shall be vitiated should a malfunction
occur in equipment regularly utilized for recording Transactions or retaining
Transaction Tapes or the operation thereof, and in such event, the Transaction
shall be evidenced by the written and computer records of the Parties concerning
the Transaction made contemporaneously with the telephone conversation.
2.4. Confirmations. In addition to, but not in lieu of, the foregoing, the
-------------
Parties agree that Company may confirm a recorded telephonic Transaction by
forwarding to Customer a facsimile Confirmation and that a reasonable time for
the receipt by Customer of a Confirmation is within 24 hours of the Transaction
formation. Company does hereby adopt its letterhead, including its address, as
its signature on any Confirmation as the identification of Company and
authentication by Company of the Confirmation, and such letterhead shall be
sufficient to verify that Company originated the Confirmation. The Parties
agree that any objections to the contents of the Confirmation shall be made in
writing on or before the Confirm Deadline for all purposes hereunder and at law.
Upon issuance of a Confirmation and the passage of the Confirm Deadline, if no
objection to the Confirmation has been then received, the Confirmation shall be
conclusive evidence of the Transaction made the subject matter thereof and the
final expression of all of its terms.
2.5. Enforcement of Transactions. The Parties agree not to contest or assert a
---------------------------
defense to the validity or enforceability or telephonic Transactions entered
into in accordance with this Agreement under laws relating to (i) whether
certain agreements are to be in writing or signed by the Party to be thereby
bound or (ii) the authority of any employee of the Party if the employee name
and the Identification Code of the Party are stated in the Transaction Tape.
ARTICLE 3. QUANTITY OBLIGATIONS 3.1. Seller's Sales Obligation. Seller shall
- -------------------------------- -------------------------
Schedule, or cause to be Scheduled, at the Delivery Point(s) on a firm basis
each Gas Day a quantity of Gas equal to the quantity properly requested by Buyer
up to the DCQ or MaxDQ, if applicable ("Buyer's Requested Quantity"). Unless
--------------------------
otherwise agreed nothing in this Agreement, and in particular this Article 3,
---------
shall require or permit either Party to Schedule Gas at a point other than a
Delivery Point or in excess of the DCQ, Maximum Daily Delivery Point Quantity or
MaxDQ, as applicable.
3.2. Seller's Failure to Schedule. If on any Gas Day Seller fails to Schedule
----------------------------
Buyer's Requested Quantity, then such occurrence shall constitute a "Seller's
--------
Deficiency Default" and "Seller's Deficiency Quantity" shall be the numerical
- ------------------ ----------------------------
difference between Buyer's Requested Quantity and the amount of Gas Scheduled
for such Gas Day. In the event of a Seller's Deficiency Default, Seller shall
pay Buyer the sum of the following: (i) an amount equal to the product of the
Seller's Deficiency Quantity multiplied by the Replacement Price Differential,
plus (ii) liquidated damages equal to $0.15 multiplied by Seller's Deficiency
- ----
Quantity to cover Buyer's administrative and operational costs. During any
Month in which Seller's nonperformance continues for a period of five
consecutive Gas Days Buyer may elect upon notice to Seller, without liability,
not to recommence Scheduling Gas hereunder for the remainder of such Month, but
for no longer period. Subject to offset pursuant to Section 3.5, payment to
-----------
Buyer shall be made on the 25th Day of the Month in which Seller receives
Buyer's statement for same.
3.3. Buyer's Purchase Obligation. Buyer shall Schedule, or cause to be
---------------------------
Scheduled, at the Delivery Point(s) on a firm basis each Gas Day a quantity of
Gas equal to the DCQ ; provided, (i) if the MinMQ is applicable to a
Transaction, Buyer shall Schedule, or cause to be Scheduled, at the Delivery
Point(s) on a firm basis each Month a minimum quantity of Gas equal to the MinMQ
and (ii) if the MinDQ is applicable to a Transaction, Buyer shall Schedule, or
cause to be Scheduled, at the Delivery Point(s) on a firm basis each Day a
minimum quantity of Gas equal to the MinDQ.
3.4. Buyer's Failure to Schedule. If on any Gas Day Buyer fails to Schedule
---------------------------
the DCQ or MinDQ, if applicable, then such occurrence shall constitute a
<PAGE>
"Buyer's Deficiency Default" and "Buyer's Deficiency Quantity" shall be the
-------------------------- ---------------------------
numerical difference between the DCQ or MinDQ, if applicable, and the quantity
of Gas Scheduled for such Gas Day; provided, if the MinMQ is applicable to a
Transaction, (i) the Buyer's Deficiency Default shall occur if Buyer fails to
Schedule the MinMQ for any Month and (ii) the Buyer's Deficiency Quantity shall
be the numerical difference between the MinMQ and the quantity of Gas Scheduled
for such Month. In the event of a Buyer's Deficiency Default, Buyer shall pay
Seller the sum of the following: (i) an amount equal to the product of Buyer's
Deficiency Quantity multiplied by the Replacement Price Differential, plus (ii)
----
liquidated damages equal to $0.15 multiplied by Buyer's Deficiency Quantity to
cover Seller's administrative and operational costs. With respect to DCQ and
MinDQ obligations, during any Month in which Buyer's nonperformance continues
for a period of five consecutive Gas Days Seller may elect upon notice to Buyer,
without liability, not to recommence Scheduling Gas for the remainder of such
Month, but for no longer period. Subject to offset pursuant to Section 3.5,
-----------
payment to Seller shall be made in accordance with the Financial Matters
provisions set forth in Appendix "1."
-------------
3.5. Netting. In the event that Buyer and Seller are each required to pay an
-------
amount in the same Month hereunder, then such amounts with respect to each Party
may be aggregated and the Parties may discharge their obligations to pay through
netting, in which case the Party, if any, owing the greater aggregate amount may
pay to the other Party the difference between the amounts owed.
ARTICLE 4. DEFAULTS AND REMEDIES. 4.1. Early Termination. If a Triggering Event
- --------------------------------- -----------------
(defined in Section 4.2) occurs with respect to either Party at any time during
-----------
the term of this Agreement, the other Party (the "Notifying Party") may (i) upon
---------------
two Business Days written notice to the first Party, which notice shall be given
no later than 60 Days after the discovery of the occurrence of the Triggering
Event, establish a date on which any or all Transactions selected by it and this
Agreement in respect thereof will terminate ("Early Termination Date") except as
----------------------
provided in Section 8.4, and (ii) withhold any payments due in respect of such
-----------
Transactions; provided, upon the occurrence of any Triggering Event listed in
item (iv) of Section 4.2, as it may apply to any party, all Transactions and
-----------
this Agreement in respect thereof shall automatically terminate, without notice,
as if an Early Termination Date had been immediately declared except as provided
in Section 8.4. If an Early Termination Date occurs, the Notifying Party shall
-----------
in good faith calculate its damages, including its associated costs and
attorneys' fees, resulting from the termination of the terminated Transactions
(the "Termination Payment"). The Termination Payment will be determined by (i)
-------------------
comparing the value of (a) the remaining term, quantities and prices under each
such Transaction had it not been terminated to (b) the equivalent quantities and
relevant market prices for the remaining term either quoted by a bona fide third
party offer or which are reasonably expected to be available in the market under
a replacement contract for each such Transaction and (ii) ascertaining the
associated costs and attorneys' fees. To ascertain the market prices of a
replacement contract the Notifying Party may consider, among other valuations,
any or all of the settlement prices of NYMEX Gas futures contracts, quotations
from leading dealers in Gas swap contracts and other bona fide third party
offers, all adjusted for the length of the remaining term and the basis
deferential. All terminated Transactions shall be netted against each other and
upon the netting of all terminated Transactions, if the calculation of the
Termination Payment does not result in damages to the Notifying Party, the
Termination Payment shall be zero. The Notifying Party shall give the Affected
Party (defined in Section 4.2) written notice of the amount of the Termination
-----------
Payment, inclusive of a statement showing its determination. The Affected Party
shall pay the Termination Payment to the Notifying Party within 10 Days of
receipt of such notice. At the time for payment of any amount due under this
Article 4, each Party shall pay to the other Party all additional amounts
- ---------
payable by it pursuant to this Agreement, but all such amounts shall be netted
and aggregated with any Termination Payment payable hereunder. If the Affected
Party disagrees with the calculation of the Termination Payment, the issue shall
be submitted to arbitration pursuant to this Agreement and the resulting
Termination Payment shall be due and payable within three Days after the award.
4.2. Triggering Event shall mean, with respect to a Party (the "Affected
---------------- --------
Party"): (i) the failure by the Affected Party to make, when due, any
-----
payment required under this Agreement if such failure is not remedied
within five Business Days after written notice of such failure is given to
the Affected Party; provided, the payment is not the subject of a good
faith dispute as described in the Billing and Payment provisions or (ii)
any representation or warranty made by the Affected Party in this
Agreement shall prove to have been false or misleading in any material
respect when made or deemed to be repeated or (iii) the failure by the
Affected Party to perform any covenant set forth in this Agreement (other
than its obligations to make any payment or obligations which are
otherwise specifically covered in this Section 4.2 as a separate
-----------
Triggering Event), and such failure is not excused by Force Majeure or
-------------
cured within five Business Days after written notice thereof to the
Affected Party or (iv) the Affected Party shall (a) make an assignment or
any general arrangement for the benefit of creditors, (b) file a petition
or otherwise commence, authorize or acquiesce in the commencement of a
proceeding or cause under any bankruptcy or similar law for the protection
of creditors, or have such petition filed against it and such proceeding
remains undismissed for 30 Days, (c) otherwise become bankrupt or
insolvent (however evidenced) or (d) be unable to pay its debts as they
fall due or (v) Seller's unexcused failure to Schedule the Buyer's
Requested Quantity requested by Buyer for a cumulative period of 30 or
more Gas Days in a 12 Month period in any one Transaction or (vi) Buyer's
unexcused failure to Schedule the DCQ or MinDQ for a cumulative period of
30 or more Gas Days in a 12 Month period in any one Transaction, or, if
applicable, the MinMQ for a cumulative period of three Months in a 12
Month period in any one Transaction, or (vii) the occurrence of a Material
Adverse Change of the Affected Party; provided, such Material Adverse
Change shall not be considered if the Affected Party; establishes, and
maintains throughout the term hereof, a Letter of Credit (naming the
Notifying Party as the beneficiary) in an amount equal to the sum of (in
---
each case rounding upwards for any fractional amount to the next $100,000)
---
(a) the Notifying Party's Termination Payment plus (b) if the Notifying
----
Party is Seller, the aggregate of the amounts Seller is entitled to
receive under each Transaction for Gas Scheduled during the 60 Day period
preceding the Material Adverse Change (the amount of said Letter of Credit
to be adjusted quarterly to reflect amounts owing at that point in time)
or (viii) the Affected Party fails to establish, maintain, extend or
increase a Letter of Credit when required pursuant to this Agreement, or
after reasonable notice fails to replace the issuing bank with another
bank acceptable to the beneficiary or (ix) with respect to Company, at any
time. Enron Corp. shall have defaulted on its indebtedness to third
parties resulting in an acceleration of obligations of Enron Corp. in
excess of $50,000,000.00, or with respect to Customer, at any time.
Customer shall have defaulted on its indebtedness to third parties,
resulting in an acceleration of obligations of Customer in excess of
$50,000,000.00.
4.3. Other Events. In the event Buyer under a Transaction is regulated by a
------------
federal, state or local regulatory body, and such body shall disallow all or any
portion of any costs incurred or yet to be incurred by Buyer under any provision
of this Agreement, such action shall not operate to excuse Buyer from
performance of any obligation nor shall such action give rise to any right of
Buyer to any refund or retroactive adjustment of the Contract Price provided in
any Transaction. Notwithstanding the foregoing, if the Affected Party's
activities hereunder become subject to regulation of any kind whatsoever under
any law (other than with respect to New Taxes) to a greater or different extent
than that existing on the Effective Date and such regulation either (i) renders
this Agreement illegal or unenforceable or (ii) materially adversely affects the
business of the Affected Party, with respect to its financial position or
otherwise, then in the case of (i) above, either Party, and in the case of (ii)
above, only the Affected Party, shall at such time have the right to declare an
Early Termination Date in accordance with the provisions hereof; provided,
notwithstanding the rights of the Parties to declare an Early Termination Date
as above stated, the Affected Party shall be liable for payment of the
2
<PAGE>
Termination Payment calculated by the non-Affected Party as provided in Section
-------
4.1.
- ---
4.4. Offset. Each Party reserves to itself all rights, set-offs, counterclaims
------
and other remedies and defenses consistent with Section 8.3 (to the extent not
-----------
expressly herein waived or denied) which such Party has or may be entitled to
arising from or out of this Agreement. All outstanding Transactions and the
obligations to make payment in connection therewith or under this Agreement may
be offset against each other, set off or recouped therefrom.
ARTICLE 5. FORCE MAJEURE. This Article 5 is the sole and exclusive excuse of
- ------------------------- ---------
performance permitted under this Agreement and all other excuses at law or in
equity are WAIVED to the extent permitted by law. Except with respect to payment
obligations, in the event either Party is rendered unable, wholly or in part, by
Force Majeure to carry out its obligations hereunder, it is agreed that upon
- -------------
such Party's giving notice and full particulars of such Force Majeure to the
-------------
other Party as soon as reasonably possible (such notice to be confirmed in
writing), the obligations of the Party giving such notice, to the extent they
are affected by such event, shall be suspended from the inception and during the
continuance of the Force Majeure for a period of up to 60 Days in the aggregate
-------------
during any 12 Month period, but for no longer period. The Party receiving notice
of Force Majeure may immediately take such action as it deems necessary at its
-------------
expense for the entire 60 Day period or any part thereof. The Parties expressly
agree that upon the expiration of the 60 Day period Force Majeure shall no
-------------
longer apply to the obligations hereunder and both Buyer and Seller shall be
obligated to perform. The cause of the Force Majeure shall be remedied with all
-------------
reasonable diligence and dispatch; provided, unless otherwise agreed no
provision herein shall require or permit Seller or Buyer to Schedule quantities
of Gas (i) in excess of the DCQ, Maximum Daily Delivery Point Quantity or MaxDQ,
as applicable, or (ii) at points other than the Delivery Point(s).
ARTICLE 6. TAXES. 6.1. Allocation of and Indemnity for Taxes. The Contract
- ----------------- -------------------------------------
Price includes full reimbursement for, and Seller is liable for and shall pay,
or cause to be paid, or reimburse Buyer if Buyer has paid, all Taxes applicable
to the Gas sold upstream of the Delivery Point(s). In the event Buyer is
required to remit such Tax, the amount thereof shall be deducted from any sums
becoming due to Seller hereunder. Seller shall indemnify, defend and hold
harmless Buyer from any Claims for such Taxes. The Contract Price does not
include reimbursement for, and Buyer is liable for and shall pay, cause to be
paid, or reimburse Seller if Seller has paid, all Taxes applicable to the Gas
sold downstream of or at the Delivery Point(s), including any Taxes imposed or
collected by a taxing authority with jurisdiction over Buyer. Buyer shall
indemnify, defend and hold harmless Seller from any Claims for such Taxes.
6.2. New Taxes. A. If (i) a New Tax occurs and (ii) Buyer or Seller would be
--------- ---
responsible for such New Tax if it were a Tax under Section 6.1 and (iii) such
----------- ---
New Tax is, due to and on the basis of laws, regulations and applicable
contracts of Buyer in effect as of the effective date of the New Tax, of the
type which Buyer can pass directly through to, or be reimbursed by, another
person or entity in the chain of Gas supply, such Buyer shall pay or cause to be
paid, or reimburse Seller if Seller has paid, all such New Taxes and Buyer shall
indemnify, defend and hold harmless Seller from any Claims for such Taxes;
provided, if Buyer does not identify its contracts for long-term fixed sourcing
in the ordinary course of its business and cannot identify applicable contracts,
this Paragraph A shall not apply. B. If (i) a New Tax occurs and (ii) either
----------- ---
Buyer or Seller would be responsible for such New Tax if it were a Tax under
Section 6.1, and (iii) Paragraph A does not apply, such responsible Buyer or
- ----------- ---
Seller (the "Taxed Party") shall be entitled to declare an Early Termination
-----------
Date in accordance with the provisions of this Agreement subject to the
following conditions; provided, prior to and including the initial Agreement
Period (below defined) invoked under this Section 6.2, New Taxes shall be
-----------
allocated as if they were Taxes as provided in Section 6.1: (a) the Taxed Party
-----------
must give the non-Taxed Party at least 30 Days prior written notice (the
"Agreement Period") of its intent to declare an Early Termination Date (and
----------------
which notice shall be given no later than 90 Days after the later of the
enactment or effective date of the relevant New Tax), and prior to the proposed
Early Termination Date Buyer and Seller shall attempt to reach a mutual
agreement as to the sharing of the New Tax, (b) if a mutual sharing agreement is
not reached, the non-Taxed Party shall have the right, but not the obligation,
upon written notice to the Taxed Party within the Agreement Period, to pay the
New Tax for any continuous period it so elects on a Month to Month basis, and in
such case the Taxed Party shall not have the right during such continuous period
to declare the Early Termination Date on the basis of the New Taxes, (c) should
the non-Taxed Party at its election agree to pay the New Tax on a Month to Month
basis, then upon 30 Days prior written notice to the Taxed Party of its election
to cease payment of such New Tax, the Taxed Party shall then be liable for the
payment of the New Tax and the Parties shall again be subject to this Section
-------
6.2 as if the New Tax had an effective date as of the date the non-Taxed Party
- ---
ceases payment of such New Tax, (d) if a mutual sharing agreement is not reached
and the non-Taxed Party does not elect to pay the New Tax for any period of time
within the Agreement Period, the Early Termination Date shall take effect and
all Transactions must be terminated and be subject to the same Early Termination
Date, (e) the Early Termination Date shall be effected as if a Triggering Event
had occurred and the Termination Payment calculated as set forth in Section 4.1
-----------
shall be payable; provided, both Seller and Buyer pursuant to Section 4.1 shall
-----------
calculate their respective Termination Payments resulting from the termination
of all Transactions as if they each were a Notifying Party; provided further, if
the calculation of the Termination Payments results in either the non-Taxed
Party's or the Taxed Party's having either a gain or loss (after netting its
gains against its losses), the Parties shall share equally such net gain due, or
be responsible to pay to the Party having the net loss, one-half of the
Termination Payment and (f) such Termination Payment shall be payable as
provided in Section 4.1 and its calculation shall be subject to arbitration as
-----------
provided in the ENFOLIO General Provisions.
6.3. Cooperation. Upon request, a Party shall provide a certificate of
-----------
exemption of other evidence of exemption from any Tax and each Party agrees to
cooperate with the other in obtaining an exemption and minimizing Taxes payable
in respect of all Transactions.
ARTICLE 7. TITLE, RISK OF LOSS, INDEMNITY AND BALANCING. 7.1. Title, Risk of
- -------------------------------------------------------- --------------
Loss and Indemnity. As between the Parties, Seller shall be deemed to be in
- ------------------
exclusive control and possession of Gas Scheduled hereunder and responsible for
any damage or injury caused thereby prior to the time the same shall have been
delivered to Buyer. After delivery of Gas to Buyer at the Delivery Point(s),
Buyer shall be deemed to be in exclusive control and possession thereof and
responsible for any injury or damage caused thereby. Title to Gas Scheduled
hereunder shall pass from Seller to Buyer at the Delivery Point(s). Seller and
Buyer each assumes all liability for and shall indemnify, defend and hold
harmless the other Party from any Claims, including injury to and death of
persons, arising from any act or incident occurring when title to the Gas is
vested in the Indemnifying Party. IT IS THE INTENT OF THE PARTIES THAT THIS
INDEMNITY AND THE LIABILITY ASSUMED UNDER IT BE WITHOUT REGARD TO THE CAUSE OR
CAUSES THEREOF, INCLUDING, WITHOUT LIMITATION, THE NEGLIGENCE OF ANY INDEMNIFIED
PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR
PASSIVE; PROVIDED, NEITHER PARTY SHALL BE LIABLE IN RESPECT OF ANY CLAIM TO THE
EXTENT SAME RESULTED FROM THE GROSS NEGLIGENCE WILLFUL MISCONDUCT OR BAD FAITH
OF THE INDEMNIFIED PARTY.
7.2. Correction of Imbalances, Cashouts and Penalties. Differences between
------------------------------------------------
Scheduled quantities and actual quantities delivered and received hereunder
("Imbalances") will be corrected or settled in cash or Gas or by offset as the
----------
Parties agree. Additionally, in the event of (i) an Imbalance on Buyer's
Transporter's system caused by Seller of Seller's Transporter's delivery of less
or more than Scheduled quantity for any Gas Day (in which case Seller shall be
the "Responsible Party") or (ii) an Imbalance on Seller's Transporter's system
-----------------
caused by Buyer or Buyer's Transporter's receipt of more or less than the
Scheduled quantity for any Gas Day (in which case Buyer shall be the
"Responsible Party"), the Responsible Party shall be liable for and reimburse to
-----------------
the other Party any associated Transporter penalties or cashout costs and
3
<PAGE>
losses incurred by such other Party. In the event the tariff of either Buyer's
or Seller's Transporter provides for cashouts on the basis of the aggregation of
all overdeliveries and underdeliveries between such Transporter and Buyer or
Seller, respectively (the "Aggregate Transporter Imbalance"), and the nature of
-------------------------------
the Imbalance (overdelivery or underdelivery) attributable to the Responsible
party is the same as the Aggregate Transporter Imbalance (overdelivery or
underdelivery), the Responsible Party shall participate in the other Party's
cashout settlement of the Aggregate Transporter Imbalance on the basis of only
the Responsible Party's pro-rata share thereof.
ARTICLE 8. MISCELLANEOUS 8.1. Notices. All notices, including, without
- ------------------------ -------
limitation, consents, and communications made pursuant to this Agreement shall
be made as specified in Exhibit "A." Notices required to be in writing shall
------------
be delivered in written form by letter, facsimile or other documentary form.
Notice by facsimile or hand delivery shall be deemed to have been received by
the close of the Business Day on which it was transmitted or hand delivered
(Unless transmitted or hand delivered after close in which case it shall be
deemed received at the close of the next Business Day) or such earlier time
confirmed by the receiving Party. Notice by overnight mail or courier shall be
deemed to have been received two Business Days after it was sent or such earlier
time confirmed by the receiving Party. Any notices given hereunder in respect of
the declaration of an Early Termination Date shall be also sent to the address
of facsimile number so specified in Exhibit "A." Any Party may change its
------------
addresses by providing notice of same in accordance herewith.
8.2. Transfer. This Agreement, including, without limitation, each
--------
indemnification, shall inure to and bind the permitted successors and assigns of
the Parties: provided, neither Party shall transfer this Agreement without the
prior written approval of the other Party which may be withheld entirely at the
option of such Party; provided further, either Party may transfer its interest
to any parent or affiliate by assignment, merger or otherwise without the prior
approval of the other Party, but no such transfer shall operate to relieve the
transferor Party of its obligations hereunder. Any Party's transfer in violation
of this Section 8.2 shall be void.
-----------
8.3. Limitation of Remedies, Liability and Damages and Mitigation. THE
------------------------------------------------------------
PARTIES DO HEREBY CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES
PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF
ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS HEREIN
PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND
EXCLUSIVE REMEDY. HEREUNDER, THE OBLIGOR'S LIABILITY SHALL BE LIMITED AS SET
FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY
ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN PROVIDED, THE
OBLIGOR'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT
ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY HEREUNDER AND ALL OTHER
REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN
PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL INCIDENTAL, PUNITIVE,
EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION
DAMAGES, IN TORT, CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE.
NOTWITHSTANDING ANY OTHER PROVISION IN THIS AGREEMENT, IN NO EVENT SHALL EITHER
PARTY BE LIABLE FOR ANY PENALTIES OR CHARGES ASSESSED BY ANY TRANSPORTER OR
OTHER ENTITY FOR THE UNAUTHORIZED RECEIPT OF GAS BY THE OTHER PARTY. IT IS THE
INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE
MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO,
INCLUDING, WITHOUT LIMITATION, THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH
NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY
DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE
THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING
AN ADEQUATE REMEDY IS INCONVENIENT AND THE LIQUIDATED DAMAGES CONSTITUTE A
REASONABLE APPROXIMATION OF THE HARM OR LOSS. BUYER ACKNOWLEDGES THAT IT HAS
ENTERED INTO THIS AGREEMENT AND IS CONTRACTING FOR THE GOODS TO BE SUPPLIED BY
SELLER BASED SOLELY UPON THE EXPRESS REPRESENTATIONS AND WARRANTIES HEREIN SET
FORTH (INCLUDING, WITHOUT LIMITATION, SELLER'S REPRESENTATION THAT THE GAS TO BE
DELIVERED WILL MEET OR EXCEED THE QUALITY SPECIFICATIONS OF BUYER'S TRANSPORTER)
AND SUBJECT TO SUCH REPRESENTATIONS AND WARRANTIES, ACCEPTS SUCH GOODS, "AS-IS"
AND "WITH ALL FAULTS." SELLER EXPRESSLY NEGATES ANY OTHER REPRESENTATION OR
WARRANTY, WRITTEN OR ORAL, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION,
ANY REPRESENTATION OR WARRANTY WITH RESPECT TO CONFORMITY TO MODELS OR SAMPLES,
MERCHANTABILITY, OR FITNESS FOR ANY PARTICULAR PURPOSE. The Parties acknowledge
the duty to mitigate damages hereunder. In this connection, the Parties
recognize that the ability to effectuate arrangements for the sale or purchase
of Gas is conditioned upon the volatility of Gas markets, the creditworthiness
and reliability of potential customers, the complexity and size of the
portfolios of contracts managed by each Party and the need to conduct market
business in an orderly manner. Therefore, the Parties agree that (i) three
Business Days is a commercially reasonable period to purchase or sell Gas in
respect of a Seller's or Buyer's Deficiency Default and (ii) three Business Days
after the end of the Month in which the Early Termination Date occurs is a
commercially reasonable period after the establishment of an Early Termination
Date to determine the Termination Payment; provided, notwithstanding the
foregoing, if Gas volumes made the basis of a Seller's or Buyer's Deficiency
Default or a Party's determination of the Termination Payment are in excess or
20,000 MMBtu/Gas Day, the Parties recognize that a longer period may ordinarily
be required to effectuate cover or determine the Termination Payment in an
orderly manner so as not to adversely affect the Gas market. Each Party may
utilize its discretion, with commercially reasonable foresight, to adjust the
timing and staggering of the purchases or sales of Gas volumes in its efforts to
mitigate damages. No claim that a Party failed to mitigate damages shall be
grounded solely on the basis of counter Gas market movement.
8.4. Winding Up Arrangements. Upon the expiration of the Parties' sale and
-----------------------
purchase obligations under this Agreement, any monies, penalties or other
charges due and owing Seller shall be paid, any corrections or adjustments to
payments previously made shall be determined, and any refunds due Buyer made,
within 60 Days. Any Imbalances in receipts or deliveries shall be corrected to
zero balance within 60 Days. All indemnity and confidentially obligations and
audit rights shall survive the termination of this Agreement. The Parties'
obligations provided in this Agreement shall remain in effect for the purpose of
complying herewith.
8.5. Applicable Law. THIS AGREEMENT AND EACH TRANSACTION AND THE RIGHTS AND
--------------
DUTIES OF THE PARTIES ARISING OUT OF THIS AGREEMENT SHALL BE GOVERNED BY AND
CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF
NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. THE PARTIES AGREE
THAT THIS AGREEMENT AND ALL TRANSACTIONS SHALL BE ACCEPTED AND FORMED IN THE
STATE OF TEXAS ACCORDING TO THE PROCEDURES HEREIN SET FORTH.
8.6. Document Record Retention and Evidence. This Agreement, the Exhibits and
--------------------------------------
Appendices hereto, if any, and each Transaction, constitute the entire agreement
between the Parties relating to the subject matter contemplated by this
Agreement. There are no prior or contemporaneous agreements or representations
(whether oral or written) affecting the subject matter other than those herein
expressed. Other than with respect to Transactions entered into in accordance
with the procedures set forth in this Agreement and as otherwise herein
expressly stated (the "Transaction Procedures"), no amendment or modification to
----------------------
this Agreement shall be enforceable, unless reduced to writing and executed by
both Parties. The conduct of the Parties in accordance with the Transaction
Procedures shall evidence a course of dealing and a course of performance
accepted by the Parties in futherance of this Agreement and all Transactions
entered into by
4
<PAGE>
the Parties. The provisions of this Agreement shall not impart rights
enforceable by any person, firm or organization not a Party or not bound as a
Party, or not a permitted successor or assignee of a Party bound to this
Agreement. Except as otherwise herein stated, any provision, article or section
declared or rendered unlawful by a court of law or regulatory agency with
jurisdiction over the Parties or deemed unlawful because of a statutory change
will not otherwise affect the lawful obligations that arise under this
Agreement. The headings used for the Articles herein are for convenience and
reference purposes only. All Exhibits and Appendices referenced in this
Agreement, if any, are incorporated. Any original executed Agreement or
Transaction Agreement may be photocopied and stored on computer tapes and disks
(the "Imaged Agreement"). The Imaged Agreement, if introduced as evidence on
-----------------
paper, the Confirmation, if introduced as evidence in automated facsimile form,
and the Transaction Tape, if introduced as evidence in its original form and as
transcribed onto paper, and all computer records of the foregoing, if introduced
as evidence in printed format, in any judicial, arbitration, mediation or
administrative proceedings, will be admissible as between the Parties to the
same extent and under the same conditions as other business records originated
and maintained in documentary form. Neither Party shall object to the
admissibility of the Transaction Tape, the Confirmation or the Imaged Agreement
(or photocopies of the transcription of the Transaction Tape, the Confirmation
or the Imaged Agreement) on the basis that such were not originated or
maintained in documentary form under either the hearsay rule, the best evidence
rule or other rule of evidence.
8.7. Confidentiality. Each Party shall not disclose the terms of any
---------------
Transaction to a third party (other than the Party's and its affiliates
employees, lenders, counsel, accountants or prospective purchasers of any rights
under any Transactions who have agreed to keep such terms confidential) except
in order to comply with any applicable law, order, regulation or exchange rule;
provided, each Party shall notify the other Party of any proceeding of which it
is aware which may result in disclosure and use reasonable efforts to prevent or
limit the disclosure. The provisions of the Agreement other than the terms of
any Transaction are not subject to this confidentiality obligation. The Parties
shall be entitled to all remedies available at law or in equity to enforce, or
seek relief in connection with, this confidentiality obligation; provided, all
monetary damages shall be limited in accordance with Section 8.3.
-----------
The Parties have executed this Agreement in multiple counterparts to be
construed as one effective as of the Effective Date.
ENRON CAPITAL & TRADE RESOURCES CORP.
By: /s/ [SIGNATURE ILLEGIBLE]^^
---------------------------------
Title: Vice President
------------------------------
BOSTON GAS COMPANY
By: /s/ [SIGNATURE ILLEGIBLE]^^
--------------------------------
Title: VICE PRESIDENT
----------------------------
5
<PAGE>
APPENDIX "1"
------------
ENFOLIO GENERAL PROVISIONS
--------------------------
*Usage and Definitions. All references to Articles and Sections are to those set
---------------------
forth in this Agreement. Reference to any document means such document as
amended from time to time and reference to any Party includes any permitted
successor or assignee thereof. The following definitions and any terms defined
internally in this Agreement shall apply to this Agreement and all notices and
communications made pursuant to this Agreement.
"Btu" means the amount of energy required to raise the temperature of one
---
pound of pure water one degree Fahrenheit. The term "MMBtu" means one
-----
million Btus.
"Buyer" means the Party to a Transaction who is obligated to purchase Gas
-----
during a Period of Delivery.
"C.T." means Central Time.
----
"Claims" means all claims or actions, threatened or filed and whether
------
groundless, false or fraudulent, that directly or indirectly relate to the
subject matters of the indemnity, and the resulting losses, damages,
expenses, attorneys' fees and court costs, whether incurred by settlement
or otherwise, and whether such claims or actions are threatened or filed
prior to or after the termination of this Agreement.
"Confirmation" means a written notice confirming the specific terms of a
------------
Transaction which may be in any form adequate at law; an example of a
Confirmation which may be utilized hereunder is shown in "Exhibit B."
---------
"Confirm Deadline" means 24 hours after a Party receives a Confirmation:
----------------
provided, if the Confirmation is not received during a Business Day it
shall be deemed received at the open of the next Business Day.
"Contract Price" means the price for the purchase or sale of Gas pursuant
--------------
to a Transaction.
"Daily Contract Quantity" ("DCQ") means the quantity of Gas to be Scheduled
--------------------------------
each Gas Day pursuant to a Transaction.
"Day" means a period of 24 consecutive hours, beginning at midnight C.T. on
---
any calendar Day. "Business Day" means a Day on which Federal Reserve
------------
member banks in New York City are open for business and a Business Day
shall open at 8:00 a.m. and close at 5:00 p.m. local time.
"Gas Day" means a period of 24 consecutive hours beginning at the time of
-------
the applicable Transporter's gas day.
"Delivery Points(s)" means the agreed point(s) of delivery pursuant to a
------------------
Transaction.
"Force Majeure" means an event not anticipated as of the Effective Date,
-------------
which is not within the reasonable control of the Party, or in the case of
third party obligations or facilities, the third party, claiming
suspension, and which by the exercise of due diligence such Party, or third
party, is unable to overcome or obtain or cause to be obtained a
commercially reasonable substitute performance therefor; provided, neither
(i) the loss of Buyer's markets nor Buyer's inability economically to use
or resell Gas purchased hereunder nor (ii) the loss or failure of Seller's
Gas supply, including, without limitation, depletion of reserves or other
failure of production, nor Seller's ability to sell Gas to a market at a
more advantageous price, shall constitute an event of Force Majeure. "Force
------------- -----
Majeure" shall include an event of Force Majeure occurring with respect to
------- -------------
the facilities or services of Buyer's or Seller's Transporter.
"GAAP" means generally accepted accounting principles, consistently
----
applied.
"Gas" means methane and other gaseous hydrocarbons meeting the quality
---
standards and specifications of Buyer's Transporter.
"Identification Code" means a Party's numerical code utilized for recorded
-------------------
telephonic Transactions, as follow: Company ______ Customer _____.
"Indemnified Party" and "Indemnifying Party" mean the Party receiving and
----------------- ------------------
providing an indemnity, respectively.
"Interest Rate" means, for any date, two percent over the per annum rate of
-------------
interest announced as the "Prime Rate" from time to time for commercial
loans by Citibank. N.A. as established by the administrative body of such
bank charged with the responsibility of establishing such rate, as same may
change from time to time; provided, the Interest Rate shall never exceed
the maximum lawful rate permitted by applicable law.
"Letter of Credit" means an irrevocable standby letter of credit
----------------
established by a Party (the "Account Party") and issued or confirmed in a
-------------
form and by a commercial bank acceptable to the Party in whose favor it is
issued (the "Beneficiary Party").
-----------------
"Material Adverse Change" means (i) with respect to Customer, Customer
-----------------------
shall have long-term debt unsupported by third party credit enhancement
that is rated by Standard & Poor's Corporation below BBB- or (ii) with
respect to Company, Enron Corp. shall have long-term debt unsupported by
third party credit enhancement that is rated by Standard & Poor's
Corporation below BBB-.
"MaxDQ" means the maximum quantity of Gas that Seller is required to
-----
Schedule per Gas Day pursuant to a Transaction, if applicable.
"Maximum Daily Delivery Point Quantity" means the maximum quantity of Gas
-------------------------------------
which may be Scheduled per Gas Day at each Delivery Point where there are
multiple Delivery Points applicable to a Transaction.
"MinDQ" means the minimum quantity of Gas that Buyer is required to
-----
Schedule per Gas Day pursuant to a Transaction, if applicable.
"MinMQ" means for any Month the minimum quantity of Gas per Gas Day that
-----
Buyer is obligated to Schedule times the number of Days in the Month
pursuant to a Transaction, if applicable.
"Month" means a period of time beginning at midnight C.T. on the first Day
-----
of any calendar Month and ending at midnight C.T. on the first Day of the
following calendar Month.
"New Taxes" means (i) any Taxes enacted and effective after the Effective
---------
Date, including, without limitation, that portion of any Taxes or New Taxes
that constitutes an increase, or (ii) any law, order, rule or regulation,
or interpretation thereof, enacted and effective after the Effective Date
resulting in the application of any Taxes to a new or different class of
parties.
"Period of Delivery" means the period from the date Scheduling obligations
------------------
are to commence to the date same are to terminate under a Transaction.
"Pipeline" means a company authorized to ship Gas on behalf of itself or
--------
others on physical Gas transmission facilities.
"Pricing Hours" means the hours C.T. from 8:00 a.m. to 5:00 p.m. of each
-------------
Business Day.
"Replacement Price Differential" means (i) in the event of a Seller's
------------------------------
Deficiency Default, the positive difference, if any, obtained by
subtracting the Contract Price from the greater of (a) the cost to Buyer,
---- -------
including incremental transportation costs and other basis adjustments, to
replace Seller's Deficiency Quantity for such Gas Day or (b) the Spot Price
for the Gas Day in which Seller's Deficiency Default occurred, and (ii) in
the event of a Buyer's Deficiency Default, the positive difference, if any,
obtained subtracting the lesser of (a) the price obtained by Seller in an
------
incremental, arms-length sales(s) to a third party of a quantity equal to
Buyer's Deficiency Quantity for such Gas Day, less incremental
transportation charges to Seller, and including other basis adjustments, or
(b) the Spot Price for the Gas Day in which Buyer's Deficiency Default
occurred (or if the MinMQ is applicable, the Spot Price for the middle Gas
Day of the Month in which Buyer's Deficiency Default occurred), from the
----
Contract Price. Buyer shall use all reasonable efforts to purchase and
obtain replacement gas at a least cost basis to mitigate the costs to
Seller hereunder.
"Scheduling" or "Schedule," when used in reference to Seller, means to make
---------- ---------
Gas available, or cause Gas to be made available, at the Delivery Point(s)
for delivery to or for the account of Buyer, including making all Pipeline
nominations, and when used in reference to Buyer, means to cause Buyer's
Transporter to make available at the Delivery Point(s) transportation
capacity sufficient to permit Buyer's Transporter to receive on a firm
basis the quantities Seller has available at such Delivery Point(s),
including making all Pipeline nominations. Gas shall be deemed to have been
Scheduled when confirmed by Transporter.
"Seller" means the Party to a Transaction who is obligated to sell Gas
------
during a Period of Delivery.
"Spot Price" means the price set forth in Gas Daily(R) (Pasha Publications,
---------- ---------
Inc.), or successor publication, in the column "Daily Price Survey" under
the listing applicable to the geographic location agreed pursuant to a
Transaction for the relevant Gas Day. If there is no single price published
for that particular Gas Day, but there is published a range of prices under
<PAGE>
the above column and listing, then the Spot Price shall be the average of
such high and low prices. In the event that no price or range of prices is
published for that particular Gas Day, then the Spot Price shall be the
average of the following: the price (determined as stated above) for each
of the first Gas Day immediately preceding and following the Gas Day in
which the default occurred for which a Spot Price can be determined.
"Taxes" means any or all ad valorem, property, occupation, severance,
-----
production, extraction, first use, conservation, Btu or energy, gathering,
transport, Pipeline, utility, gross receipts, gas or oil revenue, gas or
oil import, privilege, sales, use, consumption, excise, lease, transaction,
and other or new taxes, governmental charges, licenses, fees, permits, and
assessments, or increases therein, other than taxes based on net income or
net worth.
"Transaction" means an agreement and any amendment or modification thereof
-----------
made in accordance herewith for the purchase or sale of Gas to be performed
hereunder.
"Transaction Agreement" means a written paper-based agreement executed by
---------------------
the Parties to form and effectuate a Transaction which may be substantially
in the form set forth in Exhibit "B-1."
-------------
"Transaction Tape" means the tape recording of a recorded Transaction
----------------
effectuated in accordance with Article 2.
---------
"Transporter" means either the Pipeline delivering or receiving Gas at a
-----------
Delivery Point in a Transaction.
* Representations and Warranties. As a material inducement to entering into
------------------------------
this Agreement, including each Transaction, each Party, with respect to itself,
hereby represents and warrants to the other Party continuing throughout the term
of this Agreement as follows: (i) there are no suits, proceedings, judgments,
rulings or orders by or before any court or any governmental authority that
materially adversely affect its ability to perform this Agreement or the rights
of the other Party under this Agreement, (ii) it is duly organized, validly
existing and in good standing under the laws of the jurisdiction of its
formation, and it has the legal right, power and authority and is qualified to
conduct its business, and to execute and deliver this Agreement and perform its
obligations under the same and each Transaction, and all regulatory
authorizations have been maintained as necessary for it to legally perform its
obligations hereunder, (iii) the making and performance by it of this Agreement
is within its powers, has been duly authorized by all necessary action on its
part, and does not and will not violate any provision of law of any rule,
regulation, order, writ, judgment, decree or other determination presently in
effect applicable to it or its governing documents, (iv) each of this Agreement
and each Transaction when entered into constitutes a legal, valid and binding
act and obligation of it, enforceable against it in accordance with its terms,
subject to bankruptcy, insolvency, reorganization and other laws affecting
creditor's rights generally, and with regard to equitable remedies, to the
discretion of the court before which proceedings to obtain same may be pending,
(v) there are no bankruptcy, insolvency, reorganization, receivership or other
arrangement proceedings pending or being contemplated by it, or to its knowledge
threatened against it, (vi) it has assets of $5,000,000 or more according to its
most recent financial statements prepared in accordance with GAAP and knowledge
and experience in financial matters that enable it to evaluate the merits and
risks of this Agreement, and (vii) it is not in a disparate bargaining position
with the other Party.
* Operations and Delivery Scheduling Requests. Not later than two Business Days
-------------------------------------------
prior to the earlier of Buyer's or Seller's Transporter's nomination deadline
for the first Gas Day of each Month during a Period of Delivery. Buyer agrees to
provide to Seller facsimile notice of the quantities Buyer requests Seller to
Schedule for each Gas Day of such Month. Should Buyer desire to change the
requested quantities Scheduled, Buyer shall provide to Seller facsimile notice
thereof not later than one Business Day prior to the earlier of Buyers or
Seller's Transporter's nomination deadline for the applicable Gas Day. In the
event the nomination or Scheduling deadline of a Transporter conflicts with
these notification dates, Buyer and Seller agree to modify the notification
dates accordingly. Scheduling requests to Seller will be accepted at the
telephone number and shall be confirmed by facsimile as set forth in Exhibit "A"
----------
Transportation. Seller shall obtain, or cause to be obtained, transportation
- --------------
to the Delivery Point, and Buyer shall obtain, or cause to be obtained,
transportation from the Delivery Point.
Gas Specifications. Seller represents that all Gas delivered hereunder shall
- ------------------
meet or exceed the specifications of Buyer's Transporter.
Multiple Delivery Point Utilization. In the event a Transaction shall contain
- -----------------------------------
more than one Delivery Point, the Parties shall specify a Maximum Daily Delivery
Point Quantity for each Delivery Point. The Delivery Points which shall be
utilized for delivery of Gas and the quantities of Gas to be Scheduled for
delivery at such Delivery Points shall be determined by Seller in its sole
discretion within each applicable Maximum Daily Delivery Point Quantity. Seller
shall provide to Buyer a list of Delivery Points and quantities determined by it
within a period of time necessary to permit Buyer to make nominations.
Operational Flow Orders. Should either Party receive an operational flow order
- -----------------------
or other order or notice from a Transporter requiring action to be taken in
connection with this Agreement or Gas flowing under this Agreement ("OFO"), such
---
Party shall immediately notify the other Party of the OFO and provide the other
Party a copy of same by facsimile. The Parties shall take all actions required
by the OFO within the time prescribed. Each Parties shall take all actions
required by the OFO within the time prescribed. Each Party shall indemnify,
defend and hold harmless the other Party from any Claims, including, without
limitation, all non-compliance penalties and attorney's fees, associated with an
OFO (i) of which the Indemnifying Party failed to give the Indemnifies Party the
notice required hereunder or (ii) under which the indemnifying Party failed to
take the action required by the OFO within the time prescribed.
* Financial Matters Billing, Invoice Date, Charges and Payment. By the 10th
------------------------------------------------------------
Day of each calendar Month following the Month in which Gas was Scheduled under
a Transaction, Seller shall provide Buyer with a written statement setting forth
Gas Scheduled during the preceding Month, and other charges due Seller,
including, without limitation, deficiency charges under Article 3. Billing and
---------
payment will be based on Scheduled quantities. Within five Business Days of the
request of either Party, the other Party shall provide, to the extent it has a
legal right of access thereto and/or such statement is then available, a copy of
the Transporter's allocation or imbalance statement applicable to Gas sold
hereunder for the requested period. The difference, if any, between Scheduled
and actual quantities delivered or accepted shall be treated as imbalances under
Article 7. Buyer shall remit any amount due on the 25th Day of the Month in
- ---------
which Seller's statement was received. If the due date for any payment to be
made under this Agreement is not a Business Day, the due date for such payment
shall be the following Business Day. Payment of all funds shall be made in U.S.
currency and as indicated in Exhibit "A" in such manner that funds are
-----------
immediately available to the payee on the applicable due date. Each Party shall
take all actions necessary to effect payments in accordance with process stated
in Exhibit "A." If Buyer or Seller should fail to remit any amounts in full when
------------
due hereunder, interest on the unpaid portion shall accrue from the date due at
a rate equal to the Interest Rate. Billings, payments and statements shall be
made to the accounts or the addresses/facsimiles specified in Exhibit "A."
------------
Suspension of Performance. If either Party fails to make a timely payment and
- -------------------------
such failure is not remedied within two Business Days after such Party receives
written notice of default, the nondefaulting Party, in addition to other
remedies, may suspend the Scheduling of Gas until such amount, including
interest, is paid; provided, if the defaulting Party, in good faith, shall
dispute the amount of any such billing or part thereof and shall pay such
amounts as it concedes to be correct, no suspension shall be permitted.
Audit Rights. During the term of this Agreement and for a period of two years
- ------------
from the date of termination of a Transaction, Buyer or Seller or any third
party representative thereof shall have the right upon reasonable notice and at
reasonable times, to examine the books and records of the other to the extent
reasonably necessary to verify the accuracy or any billing statement, payment
demand, charge, payment or computation made under this Agreement. The records
of the Parties shall be retained in accordance with Section 8.5 for a like
-----------
period to facilitate the audit rights of the Parties.
Financial Information. If requested by Customer, Company shall deliver (i)
- ---------------------
within 120 Days following the end of each fiscal year, a copy of the annual
report of Enron Corp. containing consolidated financial statements for such
fiscal year certified by independent certified public accountants and (ii)
within 60 Days after the end of each of its first three fiscal quarters of each
fiscal year, a copy of the quarterly report of Enron Corp. containing unaudited
consolidated financial statements for such fiscal quarter. If requested by
Company, Customer shall deliver (i) within 120 Days following the end of each
fiscal year, a copy of its annual report containing consolidated financial
statements for such
"1"-2
<PAGE>
fiscal year certified by independent certified public accountants and (ii)
within 60 Days after the end of each of its first three fiscal quarters of each
fiscal year, a copy of its quarterly report containing unaudited consolidated
financial statements for such fiscal quarter. In all cases the statements shall
be for the most recent accounting period and prepared in accordance with GAAP;
provided, should any such statements not be timely due to a delay in preparation
or certification, such delay shall not be considered a default so long as such
Party diligently pursues the preparation, certification and delivery of the
statements.
. Warranty of Title to Gas. Seller in any Transaction warrants that title to Gas
------------------------
to be Scheduled by Seller is free from all production burdens, liens and adverse
claims and warrants its right to sell the same. Seller agrees to indemnify,
defend and hold harmless Buyer against all Claims to or against the title of
said Gas. In the event any Claim is asserted to said Gas, Buyer, in addition to
other remedies, may suspend its obligation to pay for said Gas up to the amount
of such Claim.
. Alternate Price Redetermination. If any or all of the indices used to
-------------------------------
determine the Spot Price or the Contract Price are not available in the future,
the Parties agree to promptly negotiate a mutually satisfactory alternate index
for the Spot Price or Contract Price (each an "Alternate Price"). If the
---------------
Parties cannot agree by the end of the first Month for which the Spot Price or
Contract Price could not be determined, then Seller and Buyer shall each prepare
a prioritized list of up to five alternative published reference postings or
prices representative of spot prices for Gas delivered in the same geographic
area. Each Party shall submit its list to the other within 10 Days after the
end of the first Month for which the price could not be determined. The first
listed index appearing in Seller's list that also appears in Buyer's list shall
constitute the replacement index. If no common indices appear on the lists,
each Party shall submit a new list adding two indices within 10 Days. If either
Party fails to provide timely a list, such Party's list shall not be considered.
From and after the "Renegotiation Date" which shall be the date the Spot Price
------------------
or Contract Price is no longer available, until the Alternate Price is
determined, the Alternate Price shall be the average of the Spot Price(s) or
Contract Price(s) in effect during the 12 Months preceding the Month in which
the Renegotiation Date occurred, which price shall be effective until the
Alternate Price is determined. Upon determination of a new Alternate Price, the
Spot Price or Contract Price, as applicable, will be adjusted retroactively to
the Renegotiation Date.
. Effect of Waiver or Consent. No waiver or consent by either Party, express or
---------------------------
implied, or any one or more defaults by the other Party in the performance of
any provision of this Agreement shall operate or be construed as a waiver or
consent of any other default or defaults whether of a like or different nature.
Failure by a Party to complain of any act of the other Party or to declare the
other Party in default with respect to this Agreement, regardless of how long
that failure continues, shall not constitute a waiver by that Party of its
rights with respect to that default until the applicable statute of limitations
period has run.
. Indemnifications. With respect to each Indemnification included in this
----------------
agreement the indemnity is given to the extent authorized by law and the
following provisions shall be considered applicable. The indemnified Party shall
promptly notify the Indemnifying Party in writing of any Claim and the
Indemnifying Party shall have the right to assume the investigation and defense
thereof, including the employment of counsel, and shall be obligated to pay the
related attorneys' fees; provide, the Indemnified Party shall have the right to
employ separate counsel and participate in the defense of any Claim, however,
the attorneys' fees of such counsel shall be paid by the Indemnified Party
unless the employment of such counsel has been consented to in writing by the
Indemnifying Party or the Indemnifying Party has failed to assume the defense
and employ counsel in a timely manner, provided further, if the named parties to
any Claim include both Parties, and the Indemnified Party shall have been
advised by counsel that there may be a legal defense available to it which is
different from those available to the Indemnifying Party, the Indemnified Party
may elect to employ separate counsel at the expense of the Indemnifying Party,
in which case the Indemnifying Party shall pay all attorneys' fees of such
counsel and shall not have the right to assume the defense of the Claim on
behalf of the Indemnified Party. The Parties shall use reasonable efforts to
co-operate in the defense of any Claim. The Indemnifying Party shall not be
liable for any settlement of a Claim without its express written consent
thereto. The Indemnified Party shall reimburse the Indemnifying Party for
payments made or costs incurred in respect of an indemnity with the proceeds of
any judgement, insurance, bond, surety or other recovery made with respect to an
event covered by the indemnity.
. Arbitration Disputes to be Arbitrated. Any and all claims, demands, causes of
-------------------------------------
action, disputes, controversies, and other matters in question arising out of or
relating to this Agreement, any of its provisions, or the relationship between
the Parties created by this Agreement, whether sounding in contract, tort, or
otherwise, whether provided by statute or the common law, for damages or any
other relief, including, without limitation, all Claims (all of which are
referred to herein as "Disputes"), shall be resolved by binding arbitration
--------
pursuant to the Federal Arbitration Act. The arbitration may be initiated by
either Party by providing to the other a written notice of arbitration
specifying the Disputes to be arbitrated. If a Party refuses to honor its
obligations to arbitrate, the other Party may seek to compel arbitration in
either federal or state court. The arbitration proceeding shall be conducted in
Houston, Texas, or other location mutually agreed upon by the Parties. Within
30 Days of the notice initiating the arbitration procedure, each Party shall
designate one arbitrator, who need not be impartial. If a Party fails to
designate an arbitrator, the other Party may have an arbitrator appointed by
applying to the senior active United States District Judge for the Southern
District of Texas. The two arbitrators shall select a third arbitrator. If the
two arbitrators chosen by the Parties fail to agree upon the third arbitrator,
both or either of the Parties may apply to the senior active United States
District Judge for the Southern District of Texas for the appointment of a third
arbitrator. The third arbitrator shall take an oath of neutrality.
. Arbitration Procedures. The three arbitrators shall make all of their
----------------------
decisions by majority vote. The enforcement of this Agreement to arbitrate the
validity construction, and interpretation of this Agreement to arbitrate, and
all procedural aspects of the proceeding pursuant to this Agreement to
arbitrate, including, without limitation, the issues subject to arbitration, the
scope of the arbitrate issues, allegations of "fraud in the inducement" to enter
into this entire Agreement or to enter into this Agreement to arbitrate,
allegations of waiver, delay or defenses to arbitrability, and the rules
governing the conduct of the arbitration, shall be governed by and construed
pursuant to the Federal Arbitration Act. In deciding the substance of the
parties' Disputes, the arbitrators shall apply the substantive laws of the State
of Texas (excluding Texas choice-of-law principles that might call for the
application of some other State's law). The arbitration shall be conducted in
accordance with the Commercial Arbitration Rules of the American Arbitration
Association, except as modified in this Agreement. It is contemplated that
although the arbitration shall be conducted in accordance with the Commercial
Arbitration Rules of the American Arbitration Association, the arbitration
proceeding will be self-administered by the Parties; provided, if a Party
believes the process will be enhanced if it is administered by the American
Arbitration Association, such Party shall have the right to cause the process to
become administered by the American Arbitration Association by applying to the
American Arbitration Association and, thereafter, the arbitration shall be
conducted pursuant to the administration of the American Arbitration
Association. In determining the extent of discovery, the number and length of
depositions, and all other pre-hearing matters, the arbitrators shall endeavor
to the extent possible to streamline the proceedings and minimize the time and
cost of the proceedings. There shall be no transcript of the hearing. The final
hearing shall be conducted within 120 days of the selection of the third
arbitrator. The final hearing shall not exceed 10 Business Days, with each Party
to be granted one-half of the allocated time to present its case to the
arbitrators. All proceedings conducted hereunder and the decision of the
arbitrators shall be kept confidential by the Parties.
. Arbitration Award. Only damages allowed pursuant to this Agreement may be
-----------------
awarded. It is expressly agreed that the arbitrators shall have no authority to
awards treble, exemplary or punitive damages of any type under any circumstances
regardless of whether such damages may be available under Texas law, the Parties
hereby waiving their right, if any, to recover treble, exemplary or punitive
damages in connection with any Dispute, either in arbitration or in litigation.
The arbitrators shall render their final decision within 20 Days of the
completion of the final hearing resolving all of the Disputes that are the
subject of the arbitration proceeding. The arbitrators ultimate decision after
final hearing shall be in writing. The arbitrators shall certify in their
decision that no part of their award includes any amount for treble, exemplary
or punitive damages not allowed hereunder. The arbitrators'
<PAGE>
decision shall be final and non-appealable to the maximum extent permitted by
law. Any and all of the arbitrators' orders and decisions may be enforceable in,
and judgment upon any award rendered in the arbitration proceeding may be
confirmed and entered by, any federal or state court having jurisdiction.
Authority for Transactions Each Party represents to the other Party that each of
- --------------------------
its employees has authority to enter into Transactions pursuant to this
Agreement on its behalf. Identification and authority of a Party's employee
engaging in a recorded telephonic Transaction shall be conclusively established
for all purposes by a statement on the Transaction Tape by the employee of the
employee's name and the Party's Identification Code; provided, failure to state
either the employee name or the Identification Code shall not evidence any lack
of authority of the employee to effectuate and form a Transaction.
Flexible Pricing During the Period of Delivery for a Transaction expressly
- ----------------
providing for "Flexible Pricing" Customer may request a price other than the
----------------
original Contract Price, being a Fixed Price, Fixed Basis Price or Floating
Basis Price (each below defined) by contacting Company during Pricing Hours
requesting any such price for a specified quantity of Gas to be Scheduled during
selected Months within the Period of Delivery; provided, such request must be
made prior to 1:30 p.m. C.T. of the third trading Day prior to the last trading
Day of the NYMEX Gas futures contract for the selected Month. The terms of this
Agreement, including, without limitation, Article 2, shall apply to Flexible
---------
Pricing in respect of any Transaction hereunder. A Confirmation may be sent by
Company to Customer confirming the Flexible Pricing agreement in accordance with
Section 2.4. "Fixed Price" means a fixed dollar amount agreed to by the Parties.
- ------------ -----------
"Fixed Basis Price" means a price agreed to by the Parties on the basis of NYMEX
-----------------
Gas futures contracts then trading for the applicable Month, or if no such price
is agreed prior to the last three trading Days of the applicable Month, a price
equal to the sum of the average of the settlement prices of the NYMEX Gas
futures contract for the last three trading Days of the applicable Month (the
"Average Settlement Price") plus a fixed dollar amount basis adjustment agreed
------------------------- ----
to by the Parties. "Floating Basis Price" means a price equal to the sum of a
--------------------
fixed dollar amount agreed to by the Parties plus the difference between the
----
selected reference price for the Delivery Point(s) and the Average Settlement
Price for the applicable Month. The price for all Gas for which a Flexible Price
has not been agreed by the Parties shall be the original Contract Price
applicable to the Transaction.
<PAGE>
EXHIBIT "A"
ENFOlIO MASTER FIRM PURCHASE/SALE AGREEMENT
NOTICE/COMMUNICATION/PAYMENT
TO COMPANY:
Notices/Correspondence:
P.O. Box 4428
Houston, Texas 77210-4428
Attn: Documentation and Deal Clearing Desk
Facsimile No. (713)646-4816
Termination Notice Facsimile No. (713)646-4818
Invoices:
P.O. Box 4428
Houston, Texas 77210-4428
Attn: Client Services
Facsimile No. (713) 646-8420
Payments:
Enron Capital & Trade Resources Corp.
ABA Routing 111000012 NationsBank TX
Account 3750494099
Nominations: 1(800)356-9427/1(800)FLOWGAS
Confirmations: ECT Gas Trading 1(713)646-2531
TO CUSTOMER:
Notices/Correspondence:
One Beacon Street
Boston, MA 02108
Facsimile No. (617) 742-0041
Invoices:
One Beacon Street
Boston, MA 02108
Facsimile No. (617) 742-0041
Payments:
One Beacon Street
Boston, MA 02108
Nominations: Facsimile No.(617) 742-0041
Confirmations: Facsimile No.(617) 742-0041
<PAGE>
EXHIBIT "B"
ENFOLIO MASTER FIRM PURCHASE/SALE AGREEMENT
EXAMPLE OF CONFIRMATION ON COMPANY LETTERHEAD (INCLUDING NAME AND ADDRESS) TO
CONFIRM TELEPHONIC TRANSACTIONS UNDER
SECTION 2.4
-----------
This Confirmation shall confirm the Transaction agreed to on ___________ 19 and
binding between ____________________ ("Customer") and ("Company") regarding the
-------- -------
firm purchase and sale of Gas under the following terms and conditions.
______________________ to purchase and receive (Buyer) and _________________ to
sell and deliver (Seller). Transaction number __________________________
DAILY CONTRACT QUANTITY (DCQ): _____________________
MAXDQ (if applicable): _____________________
MINMQ (if applicable): _____________________
MINDQ (if applicable): _____________________
DELIVERY POINT(S): _____________________
CONTRACT PRICE (per MMBtu): _____________________
PERIOD OF DELIVERY: _____________________
SPOT PRICE LOCATION: _____________________
If this Confirmation relates to a NYMEX Exchange of Futures for Physicals
Transaction the Confirmation may include the following with respect to Contract
Price: The Contract Price shall be equal to the EFP Posted Price [plus] [minus]
$______ (the "Adjustment"). The "EFP Posted Price" shall be in accordance with
---------- ----------------
Rule 220.17 of the rules and regulations of the NYMEX pertaining to Gas futures
contracts for the Period of Delivery as set forth below:
Buyer agrees to exchange its long position in [# OF CONTRACTS, MONTH, YEAR]
NYMEX contracts with Seller for Sellers short position in [# OF CONTRACTS,
MONTH, YEAR] NYMEX contracts at a price of $____
[REPEAT TEXT AFTER = FOR EACH DELIVERY MONTH OF THE PERIOD OF DELIVERY FOR WHICH
THE EFP POSTED PRICE IS AGREED AS OF THE PREPARATION OF THIS CONFIRMATION]
In each Delivery Month for which an EFP Posted Price is not herein set forth,
the EFP Posted Price shall be the price at which the exchange is posted with
NYMEX in accordance with Rule 220.17. Notwithstanding anything herein, if no
posting is timely made for any Delivery Month in accordance with Rule 220.17 by
Buyer and Seller, then there shall be no EFP Transaction hereunder for such
Delivery Month. The Transaction for that Delivery Month shall be considered a
Transaction for the firm purchase and sale of Gas otherwise in accordance with
the provisions hereof at a Contract Price equal to the average of the
settlement prices occurring the last three Trading Days of the NYMEX Gas
contracts for the applicable Delivery Month [plus] [minus] the Adjustment For
purposes hereof, "Trading Day" means any Day for which a NYMEX Gas contract is
----------
determinable.)
This Confirmation is being provided pursuant to and in accordance with the
ENFOLIO Master Firm Purchase/Sale Agreement in effect between Customer and
Company (the "Agreement") and constitutes part of and is subject to all of the
----------
terms and provisions of such Agreement. All capitalized terms herein used, but
not defined, shall have the meanings set forth in the Agreement. Company does
hereby adopt its letterhead, including its address, as its signature in respect
of the identification of Company and the authentication by Company of this
Confirmation. Any objection of Customer to this Confirmation must be made by
written notice to Company prior to the Confirm Deadline, as agreed and defined
in the Agreement.
EXHIBIT "B-1"
ENFOLIO MASTER FIRM PURCHASE/SALE AGREEMENT
SUGGESTED FORM OF TRANSACTION AGREEMENT FOR USE WITH TRANSACTIONS FORMED UNDER
SECTION 2.2(i)
-------------
This Transaction Agreement shall form and effectuate the current proposal
between ____________________ ("Customer") and _____________ ("Company")
-------- -------
regarding the firm purchase and sale of Gas under the following terms and
conditions. ___________________ to purchase and receive (Buyer) and
________________ to sell and deliver (Seller). Transaction number
_____________________________
DAILY CONTRACT QUANTITY (DCQ): __________________________
MAXDQ (if applicable): __________________________
MINMQ (if applicable): __________________________
MINDQ (if applicable): __________________________
DELIVERY POINT(S): __________________________
CONTRACT PRICE (per MMBtu): __________________________
PERIOD OF DELIVERY: __________________________
SPOT PRICE LOCATION: __________________________
This Transaction Agreement is being provided pursuant to and in accordance with
the ENFOLIO Master Firm Purchase/Sale Agreement in effect between Customer and
Company and constitutes part of and is subject to all of the terms and
provisions of such Agreement. Please execute this Transaction Agreement and
return an executed copy to Company. Your execution should reflect the
appropriate party in your organization who has the authority to cause Customer
to enter into this Transaction. In the event Customer alters the terms of this
Transaction Agreement in any manner there will be no Transaction pursuant to
this Transaction Agreement.
SIGNATURE LINES FOR CUSTOMER AND COMPANY
<PAGE>
[LETTERHEAD OF ENRON CAPITAL & TRADE APPEARS HERE]
October 23, 1997
Boston Gas Company
One Beacon Street
MA 02108
Attn: Mr. William R. Luthern
Vice President
TRANSACTION AGREEMENT
---------------------
This Transaction Agreement shall form and effectuate the current proposal
between Boston Gas Company ("Customer") and Enron Capital & Trade Resources
--------
Corp. ("Company") regarding the firm purchase and sale of Gas under the
-------
following terms and conditions. Customer to purchase and receive (Buyer) and
Company to sell and deliver (Seller). Transaction number 1.
DAILY CONTRACT QUANTITY (DCQ): 35,000 MMBtu/day; (Firm)
DELIVERY POINT(S): Boston Gas City Gate and/or Mendon, MA (as
delivered off Tennessee Gas Pipeline
Company; provided any interruption of
deliveries at the Mendon delivery point
shall be received and purchased at the
Boston Gas City Gate delivery point.
CONTRACT PRICE (per MMBtu): 1) The TETCO M-3 Index (defined below)
plus the Boston Differential (defined
below), where:
"TETCO M-3 Index" means the price for
natural gas for the applicable delivery
Month in U.S. dollars per MMBtu published
in the first issue in that Month by Inside
------
FERC Gas Market Report in the table
----------------------
entitled "Market Center Spot Gas Prices"
in the row "Texas Eastern Transmission
Corp. Zone M-3" in the column "Index".
"Boston Differential" means the price
differential for the applicable delivery
Month in U.S. dollars per MMBtu obtained
by subtracting (ii) from (i) where: (i) is
the price agreed to by Company and
Customer for each applicable delivery
Month for delivery of 35,000 MMBtu's per
Day of physical Gas delivered to the
Boston Gas City Gate and (ii) is the TETCO
M-3 Index for that delivery Month. If, for
any reason whatsoever, the Parties cannot
agree on the Boston Differential for any
delivery Month, the Boston Differential
for such delivery Month shall be deemed to
be equal the Indicative Boston Gas City
Gate Index (defined below) for that
delivery Month minus the TETCO M-3 Index
for that delivery Month. Company will
endeavor to submit Company's proposal as
to such Boston Differential at least 3
days prior to each delivery Month.
2) Additionally, Customer agrees to pay
Company a Monthly reservation fee for the
first fifty-six (56) months of the term of
delivery under this Transaction Agreement.
Such monthly transaction fee shall be
equal to the product of $ per MMBtu times
35,000 MMBtu times the number of days in
the Month.
PERIOD OF DELIVERY: Commencing on January 1, 1998 and
continuing thereafter through March 31,
2007. Notwithstanding the foregoing, this
Transaction Agreement shall automatically
terminate as of January 1, 1996 if ECTRC
fails to obtain signed purchase and sale
transactions with Alberta producers
(including all amendments thereto and,
with all such amendments, in form and
substance acceptable to ECTRC) for the
delivery of the DCQ plus applicable fuel
gas for the term of this Transaction, and
such Alberta producer transactions
(including all amendments thereto) are in
full force and effect.
SPOT PRICE LOCATION: Texas Eastern - Zone M3
NATURAL GAS. ELECTRICITY. ENDLESS POSSIBILITIES.
<PAGE>
BOSTON GAS COMPANY
OCTOBER 23, 1997
Page 2
_______________
OTHER: 1) Option - Commencing November 1, 1999,
Customer has the sole right with ninety (90)
days prior written notice to reduce the DCQ
in increments of not less than 15,000
MMBtu/Day for the remaining term of this
Transaction Agreement. Additionally, if
Customer's purchases under its long term gas
purchase arrangements with Imperial Oil
Limited for gas originating from the Sable
Offshore Energy Project do not commence by
November 1, 2000 and if Company agrees to
redetermine the Contract Price hereunder,
then the Contract Price hereunder shall be
redetermined to a Contract Price that is
mutually agreeable to the Parties.
2) Repurchase Option - Company has the right
to repurchase quantities at the Boston Gas
City Gate delivery point with the consent of
Boston Gas; provided, however, that such
consent will not be unreasonably withheld and
that such quantities are otherwise not
encumbered by Customer's currently effective
capacity assignment procedures, a copy of
such capacity assignment procedures to be
provided by Customer to Company prior to
commencement of deliveries under this
Transaction Agreement. These quantities must
be designated at the first of the month, and
cannot be diverted from the Boston Gas City
Gate delivery point. Company shall purchase
such quantities at a $0.005 per MMBtu premium
to the calculated monthly price.
3) Future Boston Gas City Gate Index - If, at
any time during the Period of Delivery, there
is an established liquid market for natural
gas delivered to, and purchased at the Boston
Gas City Gate at a price Index which the
Parties have agreed in writing is acceptable
to each at the Parties, respectively in their
sole discretion (the "Approved Boston Gas
City Gate Index"), the Parties agree that,
commencing the first delivery Month after the
Month in which the Parties have agreed in
writing to the Approved Boston Gas City Gate
Index and for the reminder of the Period of
Delivery, the TETCO Boston Differential
Component of the Contract Price (defined
below) shall be replaced for all purposes
under this Confirmation Letter, including for
the determination of the Contract Price over
the remainder of the Period of Delivery, by
the Approved Boston Gas City Gate Index. For
certainty, the Parties acknowledge and agree
that, as of the date hereof and unless and
until accepted by the Parties as the Approved
Boston Gas City Gate Index as provided above,
the Indicative Boston Gas City Gate Index
(defined below) is not acceptable to the
Parties as the Approved Boston Gas City Gate
Index.
As used above:
TETCO + Boston Differential Component of the
Contract Price means the portion of the
Contract Price determined by the sum of: (i)
the TETCO M-3 Index; plus (ii) the Boston
Differential; and "Indicative Boston Gas City
Gate Index" means the price for natural gas
for each applicable delivery Month in U.S.
dollars per MMBtu published in the first
issue in that Month by Natural Gas Week in
----------------
the table entitled "City Gate Prices" in the
row "Boston, Mass," in the column "Bid Week"
for the applicable delivery Month.
4) True-Up Mechanism - Within Sixty Days of
each Anniversary Date (defined below), Seller
shall send Buyer a written statement showing:
(i) the monthly average of the TETCO + Boston
Differential Component of the Contract Price
for the delivery Months to which the TETCO +
Boston Differential Component of the Contract
Price is applicable (the Yearly Average
Differential Component of the Contract
Price"); and (ii) the monthly average of the
Indicative Boston Gas City Gate Index over
each of those same delivery Months (the
"Yearly Average Indicative Boston Gas City
Gate Index").
<PAGE>
BOSTON GAS COMPANY
OCTOBER 23, 1997
Page 3
________________
If the Yearly Average Differential Component
of the Contract Price is: (i) less than 96%
of the Yearly Average Indicative Boston Gas
City Gate Index: or (ii) greater than 104% of
the Yearly Average Indicative Boston Gas City
Gate Index, the amount paid or payable by
Buyer for the total volume Gas purchased and
sold over each of those same delivery Months
shall be adjusted by an amount (the amount of
such adjustment being the "Adjustment
Amount"), payable as of the next Payment
Date, obtained by multiplying: (A) the
absolute value of the difference between the
Yearly Average Differential Component of the
Contract Price and the Adjusted Yearly
Average Indicative Boston Gas City Gate Index
(defined below); by (B) the total volume of
Gas purchased and sold over each of those
same delivery Months. In the case of an
adjustment for (i) above, the Adjustment
Amount shall be payable by Customer to
Company. In the case of an adjustment for
(ii) above, the Adjustment Amount shall be
payable by Company to Customer.
As used above:
"Adjusted Yearly Average Indicative Boston
Gas City Gate Index means: (i) if the Yearly
Average Differential Component of the
Contract Price is less than 96% of the Yearly
Average Indicative Boston Gas City Gate
Index, 96% of the Yearly Average Indicative
Boston Gas City Gate Index: or (ii) if the
Yearly Average Differential Component of the
Contract Price is more than 104% of the
Yearly Average Indicative Boston Gas City
Gate Index, 104% of the Yearly Average
Indicative Boston Gas City Gate Index; and
"Anniversary Date" means, with respect to
each Contract Year, November 1, 1998;
November 1, 1999; November 1, 2000: November
1, 2001: November 1, 2002; November 1, 2003;
November 1, 2004; November 1, 2005; November
1, 2006; and April 1, 2007.
5) Regulatory Approval - Buyer agrees to use
all reasonable efforts to obtain any
approvals, consents or authorizations
("Regulatory Approval") that may be required
from the Massachusetts Department of Public
Utilities ("MDPU" herein), to allow Buyer to
enter into this Transaction with Seller, and
Buyer has advised Seller that Buyer intends
to make a regulatory filing with the MDPU to
obtain such Regulatory Approval. Buyer agrees
that if the MDPU does not issue an order
allowing Buyer's purchase of gas under the
terms and conditions of this Transaction
("Regulatory Approval") at any time prior to
January 1, 1998, then this Transaction
Agreement shall automatically terminate.
6) Force Majeure - Notwithstanding anything
to the contrary contained in the ENFOLIO
Master Firm Purchase/Sale Agreement, any
curtailments or interruptions of firm
delivery service occurring at any point
upstream of the Boston Gas City Gate delivery
point up to and including any NOVA Inventory
Transfer delivery point on NOVA Gas
Transmission Ltd.'s gas transmission system
at Alberta, Canada shall be deemed to be an
event at Force Majeure under this
Transaction.
7) Boston Canadian Transportation
Requirements, Boston U.S. Transportation
Requirements and Export/Import Requirements -
Seller and ECTRC, on behalf of Seller, shall
use all reasonable efforts to obtain all
approvals and assignments (including, without
limitation, any approvals, consents or
authorizations required from any applicable
regulatory authorities to any such
assignments), with terms and in a form
acceptable to Seller and ECTRC, for
<PAGE>
BOSTON GAS COMPANY
OCTOBER 23, 1997
Page 4
_____________
firm transportation agreements necessary to
transport the DCQ plus applicable fuel gas
for the period of delivery from (a) the NOVA
Inventory Transfer delivery point on NOVA Gas
Transmission Ltd.'s gas transmission system
at Alberta, Canada to the interconnection of
TransCanada Pipelines Limited ("TCPL") and
Iroquois Gas Transmission System, L.P.
("IGT") at Iroquois, Ontario and Waddington,
New York (the "Boston Canadian Transportation
Requirements") and (b) the interconnection of
TCPL and IGT at Iroquois, Ontario and
Waddington, New York to the Boston Gas City
Gate delivery point (the "Boston U.S.
Transportation Requirements"). Additionally,
Seller and ECTRC shall use all reasonable
efforts to obtain all regulatory approvals,
with terms and in a form acceptable to Seller
and ECTRC, necessary for the DCQ plus
applicable fuel gas to be removed from
Alberta, exported from Canada and imported
into the United States (collectively the
"Export/Import Requirements"). Buyer shall
cooperate with Seller and ECTRC in obtaining
the Boston Canadian Transportation
Requirements, the Boston U.S. Transportation
Requirements and the Export/Import
Requirements. If the Boston Canadian
Transportation Requirements have not been
obtained by January 1, 1998, then Seller, in
its sole discretion, may terminate this
Transaction at any time after January 1, 1998
but prior to the date the Boston Canadian
Transportation Requirements have been
obtained by giving written notice thereof to
Buyer. If the Boston U.S. Transportation
Requirements and the Export/Import
Requirements have not been obtained by
January 1, 1998, then Seller, in its sole
discretion, may terminate this Transaction at
any time after January 1, 1998 but prior to
the date the Boston U.S. Transportation
Requirements and the Export/Import
Requirements have been obtained by giving
written notice thereof to Buyer.
This Transaction Agreement is being provided pursuant to and in accordance with
the ENFOLIO Master Firm Purchase/Sale Agreement in effect between Customer and
Company and constitutes part of and is subject to all of the terms and
provisions of such Agreement. Please execute this Transaction Agreement and
return an executed copy to Company. Your execution should reflect the
appropriate party in your organization who has the authority to cause Customer
to enter into this Transaction. In the event Customer alters the terms of this
Transaction Agreement in any manner there will be no Transaction pursuant to
this Transaction Agreement.
BOSTON GAS COMPANY ENRON CAPITAL & TRADE RESOURCES CORP.
By: /s/ William R. Luthern By: /s/ Julie Gomez
----------------------------------- ----------------------------------
Name: William R. Luthern Name: Julie Gomez
------------------------------ -----------------------------
Title: Vice President Title: Vice President
--------------------------- ----------------------------
<PAGE>
Boston Gas 10-K
EXHIBIT 10.12.1
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 herewith.)
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
October 1, 1992
Mr. William Luthern
Boston Gas Company
One Beacon Street
Boston, MA 02108
Dear Mr. Luthern:
With regard to Gas Sales Agreement No. 1 between Alberta Northeast Gas
Limited and Boston Gas Company ("Boston Gas"), dated February 7, 1991 ("Gas
Sales Agreement No. 1"), this letter reflects our agreement to the following
amendments to Gas Sales Agreement No. 1:
1. In the first Whereas clause, the words "34,318 Mcf of gas per day
escalating to 149,635" shall be changed to "39,787 Mcf of gas per day escalating
to 159,631".
2. In Article VII, Section 1, the number 8.55% in the first sentence
shall be changed to 6.55%.
3. In Article VII, Section 2, the table setting forth each U.S.
Repurchaser's share of the Daily Contract Quantity shall be deleted and the
following table substituted therefore:
<TABLE>
<CAPTION>
Share of Daily Contract
U.S. Repurchaser Quantity ("Share")
---------------- -----------------------
<S> <C>
Long Island Lighting Company 15.20%
Yankee Gas Services Company 14.35%
New Jersey Natural Gas Company 12.60%
The Brooklyn Union Gas Company 12.00%
Southern Connecticut Gas Company 7.50%
Central Hudson Gas & Electric
Corporation 7.05%
Connecticut Natural Gas Corporation 5.75%
National Fuel Gas Supply Corporation 5.00%
</TABLE>
<PAGE>
Boston Gas Company
October 1, 1992
Page 2
Public Service Electric and
Gas Company 5.00%
Boston Gas Company 6.55%
Colonial Gas Company 3.00%
Consolidated Edison Company of
New York, Inc. 2.50%
EnergyNorth Natural Gas, Inc. 2.00%
Essex County Gas Company 1.00%
Valley Gas Company .50%
Notwithstanding the foregoing, the obligations of the parties with respect
to 4 MMcf/d of the volumes associated with Colonial Gas Company's share shall be
subject to the receipt and maintenance of any regulatory authorizations
necessary in connection therewith. The parties will use all reasonable efforts
to obtain such regulatory authorizations on a long-term basis and to continue,
in the interim, to implement and maintain temporary arrangements sufficient to
permit the ongoing delivery and purchase of such volumes. In addition, the
obligations of the parties with respect to 10 MMcf/d of the volumes associated
with Connecticut Natural Gas Corporation's Shares (on an aggregate under all ANE
Gas Purchase Contracts) shall be subject to the availability of firm capacity on
Algonquin Gas Transmission Company to transport such volumes to Connecticut
Natural Gas Corporation (the "Algonquin capacity"). The parties will use all
reasonable efforts to establish and maintain temporary arrangements sufficient
to permit the delivery and purchase of all or a portion of such volumes on an
interim basis commencing on November 1, 1992 through the date of the
availability of the Algonquin capacity.
4. Exhibit I shall be deleted in its entirety and replaced by the Exhibit
I attached to this agreement.
<PAGE>
EXHIBIT I
---------
DISTRIBUTION OF PURCHASES
Jan. 25, 1992-Mar. 31, 1992
(144,677 Mcf/d)
---------------------------
New Jersey Natural Gas Company 24,583
Boston Gas Company 13,100
Long Island Lighting Company 20,599
The Brooklyn Union Gas Company 13,047
Yankee Gas Services Company 11,302
Connecticut Natural Gas Corporation 5,666
Central Hudson Gas and Electric Corporation 11,593
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 10,290
Southern Connecticut Gas Company 6,352
Consolidated Edison Company of
New York, Inc. 5,145
EnergyNorth Natural Gas, Inc. 4,000
Colonial Gas Company 6,000
Essex County Gas Company 2,000
Valley Gas Company 1,000
DISTRIBUTION OF PURCHASES
Apr. 1, 1992-Sept. 30, 1992
(147,184 Mcf/d)
---------------------------
New Jersey Natural Gas Company 25,200
Boston Gas Company 13,100
Long Island Lighting Company 20,599
The Brooklyn Union Gas Company 13,047
Yankee Gas Services Company 12,289
Connecticut Natural Gas Corporation 6,409
Central Hudson Gas and Electric Corporation 11,593
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 10,290
Southern Connecticut Gas Company 6,512
Consolidated Edison Company of
New York, Inc. 5,145
EnergyNorth Natural Gas, Inc. 4,000
Colonial Gas Company 6,000
Essex County Gas Company 2,000
Valley Gas Company 1,000
<PAGE>
DISTRIBUTION OF PURCHASES
Oct. 1, 1992-Oct. 31, 1992
(159,631 Mcf/d)
--------------------------
New Jersey Natural Gas Company 33,138
Boston Gas Company 13,100
Long Island Lighting Company 20,599
The Brooklyn Union Gas Company 13,047
Yankee Gas Services Company 14,747
Connecticut Natural Gas Corporation 6,409
Central Hudson Gas and Electric Corporation 11,593
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 10,290
Southern Connecticut Gas Company 8,563
Consolidated Edison Company of
New York, Inc. 5,145
EnergyNorth Natural Gas, Inc. 4,000
Colonial Gas Company 6,000
Essex County Gas Company 2,000
Valley Gas Company 1,000
<PAGE>
Boston Gas Company
October 1, 1992
Page 3
If this letter properly states our agreement, please acknowledge that fact
by signing in the space provided below and returning an executed copy of this
letter to me.
Sincerely,
ALBERTA NORTHEAST GAS LIMITED
By /s/ Michael S. Lucy
--------------------------------------
Michael S. Lucy
Executive Vice President
ACKNOWLEDGED AND ACCEPTED
THIS 20TH DAY OF October, 1992
BOSTON GAS COMPANY
By /s/ William P. Luthern
-------------------------------
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
May 5, 1993
Mr. William Luthern
Boston Gas Company
One Beacon Street
Boston, MA 02108
Re: Second Amendment To ANE Gas Sales Agreement(s)
---------------------------------------------
Dear Mr. Luthern:
With regard to Gas Sales Agreement No. 1 between Alberta Northeast Gas
Limited ("ANE") and Boston Gas Company ("Boston Gas"), dated February 7, 1991
("Gas Sales Agreement No. 1"), this letter reflects our agreement to the Second
Amendment to Gas Sales Agreement No. 1, as follows:
1. Article XIV. Article XIV shall be amended by the addition of the
-----------
following sentence immediately after the first sentence of such Article XIV:
No consent shall be required for any assignment, pledge or
mortgage of, or grant of a security interest in, this Agreement
by Boston Gas in connection with any borrowing by, or
indebtedness of Boston Gas or any corporate affiliate thereof
(i.e., a corporation owning, owned by, or under common control
----
with such Repurchaser).
<PAGE>
Mr. Luthern
May 5, 1993
Page 2
2. National Fuel Assignment. ANE and Boston Gas acknowledge and consent
------------------------
to the assignment by National Fuel Gas Supply Corporation ("NFG Supply") of its
interest in, and rights and obligations under, Gas Sales Agreement No. 1 between
ANE and NFG Supply to National Fuel Gas Distribution Corporation. As of the
effective date (as determined by the Federal Energy Regulatory Commission) of
NFG Supply's FERC Order No. 636 restructuring, the phrase "National Fuel Gas
Supply Corporation" as it appears in Gas Sales Agreement No. 1 between ANE and
NFG Supply and Gas Sales Agreement No. 1 between ANE and Boston Gas and the
Exhibits to both such agreements shall be replaced with the phase "National Fuel
Gas Distribution Corporation," and all references to "National Fuel" appearing
in both such Agreements shall be deemed to refer to National Fuel Gas
Distribution Corporation. Notwithstanding the foregoing, Article VII, Section 2,
paragraph 3 shall be deleted and replaced by the following restated paragraph:
The one exception to the foregoing relates to National Fuel
Gas Supply Corporation ("NFG Supply"), which is seeking to
purchase its 10,000 Mcf/d commencing on a date prior to November
1, 1991. In the event that NFG Supply commences its purchase
prior to the commencement of purchases by the other U.S.
Repurchasers, the Daily Contract Quantity under Purchase Contract
No. 1 shall be 10,000 Mcf per day, and NFG Supply's Share shall
be 100%, for the period of such advance purchases and the term of
National Fuel's entitlement to purchase gas shall be calculated
from the date on which NFG Supply's purchases commence. In that
event, the Daily Contract Quantity for the period following the
conclusion of National Fuel's entitlement to purchase gas will be
190,000 Mcf per day, and National Fuel's share will be 0%. In any
event, however, the first contract year shall be deemed to be the
year in which Repurchasers other than NFG Supply commence
purchases.
<PAGE>
Mr. Luthern
May 5, 1993
Page 3
If this letter properly states our agreement, please acknowledge that fact
by signing in the space provided below and returning an executed copy of this
letter to me.
Sincerely,
ALBERTA NORTHEAST GAS LIMITED
By /s/ Michael S. Lucy
------------------------------------
Michael S. Lucy
Executive Vice President
ACKNOWLEDGED AND ACCEPTED
THIS 25th DAY OF Oct, 1993
Boston Gas Company
By /s/ W. R. Luthern
--------------------------
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
November 27, 1995
William Luthern
Boston Gas Company
One Beacon Street
Boston, MA 02108
Re: Amendment to Gas Sales Agreement No. 1
--------------------------------------
Dear Mr. Luthern:
Gas Purchase Contract No. 1 between Alberta Northeast Limited ("ANE") and
TransCanada Gas Marketing Limited (formerly Western Gas Marketing Limited)
("TGML"), as agent for TransCanada Pipelines Limited ("TransCanada"), dated
February 7, 1991, as amended ("Purchase Contract No. 1"), has been amended
effective November 1, 1995 to reflect changes agreed upon in the recently-
concluded price renegotiation between ANE and TGML pursuant to Article VII,
Section 7 of Purchase Contract No. 1. A copy of the amending agreement, together
with the Protocols appended thereto ("Amendment to Purchase Contract No. 1"), is
attached hereto. The amendments made effective by the Amendment to Purchase
Contract No. 1 are:
1. Certain adjustments to the base price of the gas
purchased by ANE from TGML pursuant to Purchase
Contract No. 1;
2. An increase in the Annual Triggering Quantity from 60%
to 70%;
3. An option for the sale of gas in alternative markets
and the sharing of revenues associated therewith; and
4. A refund mechanism associated with pipeline
transportation rates in effect subject to refund.
<PAGE>
These amendments to Purchase Contract No. 1 were approved by a vote of more
than sixty percent (60%) of the Repurchaser Shares under Gas Sales Agreement No.
1 between ANE and Boston Gas, dated February 7, 1991, as amended ("Gas Sales
Agreement No. 1"), and require corresponding amendments to Gas Sales Agreement
No. 1.
Specifically, effective upon the effectiveness of the Amendment to Purchase
Contract No. 1, Article VIII, Reduction of Shares, Section 2 of Gas Sales
Agreement No. 1 is amended by deleting the percentage "60%" at both places that
it appears therein and substituting the percentage "70%" therefore, and all
other provisions of Gas Sales Agreement No. 1 are deemed amended to the extent
necessary to implement the Amendment to Purchase Contract No. 1, including the
Alternative Market Sale Protocol and the Protocol for the Treatment of Increases
in U.S. Pipeline Rates.
Please acknowledge these amendments by signing in the space provided below
and returning an executed copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
6TH DAY OF DEC, 1995
BOSTON GAS COMPANY
By: /s/ William R. Luthern
-------------------------
Title: Vice President
----------------------
2
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
November 17, 1995
VIA OVERNIGHT COURIER
- ---------------------
Mr. Peter Ewing
TransCanada Gas Marketing Limited,
as agent for TransCanada
PipeLines Limited
55 Yonge Street
Toronto, Canada M5E 1J4
Re: Amendment to Gas Purchase Contract No. 1 between TGML and ANE
-------------------------------------------------------------
Dear Mr. Ewing:
Alberta Northeast Gas Limited ("ANE") and TransCanada Gas Marketing Limited
(formerly Western Gas Marketing Limited) ("TGML"), as agent for TransCanada
Pipelines Limited ("TransCanada"), are parties to Gas Purchase Contract No. 1,
dated February 7, 1991, as amended ("Purchase Contract"), which provides, inter
-----
alia, for the delivery of gas by TGML to ANE at TransCanada's points of
- ----
interconnection with Tennessee Gas Pipeline Company ("Tennessee") near Niagara
Falls, Ontario for redelivery to National Fuel Gas Distribution Corporation
("National Fuel") and with Iroquois Gas Transmission System, L.P. ("Iroquois")
near Iroquois, Ontario for redelivery to fourteen other utility companies
engaged in the distribution of natural gas in the Northeastern United States
(together with National Fuel, the "U.S. Repurchasers"). This Amendment concerns
changes to the Purchase Contract agreed upon in our recently-concluded price
renegotiation pursuant to Article VII, Section 7 of the Purchase Contract.
Specifically, this letter reflects our agreement to the following
amendments to the Purchase Contract effective November 1, 1995:
<PAGE>
Mr. Peter Ewing
November 17, 1995
Page 2
1. Article I, Definition of Terms, Section 14, "Annual Triggering
Quantity," is amended by deleting the words "sixty percent (60%)" therein and
substituting the words "seventy percent (70%)" therefore.
2. With respect to the obligation to sell and deliver gas in Article II,
Contract Quantities; Deliveries, Section 1, quantities of gas may be diverted to
alternative markets in accordance with the provisions of the Alternative Market
Sale Protocol attached hereto as Appendix A.
3. Article VII, Price, Section 6(a), is amended by deleting the price
"$3.79" and substituting the price "$3.67" therefore.
4. Article VII, Price, Section 6(a), is amended by deleting the price
"$3.38" and substituting the price "$3.26" therefore.
5. With respect to the New York Weighted Average Price in Article VII,
Price, Section 6(b), the impact of acceptance by the Federal Energy Regulatory
Commission, subject to refund, of transportation rate changes filed by Tennessee
Gas Pipeline Company, a Division of Tenneco Inc., Texas Eastern Transmission
Corporation or Transcontinental Gas Pipeline Corporation will be accounted for
in accordance with the provisions of the Protocol for the Treatment of Increases
in U.S. Pipeline Rates attached hereto as Appendix B; provided, however, that
the Refund Period (as defined therein) for any such rate in effect subject to
refund as of November 1, 1995 shall commence as of November 1, 1995.
The effectiveness of these amendments is subject to approval of this
Amendment on or before November 15, 1995, by the producers for TGML by a vote
that TGML believes to be sufficient to require the Alberta Petroleum Marketing
Commission ("APMC") to issue an unconditional finding of producer support in
accordance with the provisions of the Natural Gas Marketing Act (Alberta) and a
finding of such producer support by the APMC on or before December 15, 1995.
TGML will make its application to the APMC expeditiously in order to ensure that
the APMC's determination with respect to the finding of producer support is
issued by December 15, 1995.
The parties agree that billing and payment under the Contract shall reflect
the amendments to the Contract set forth
<PAGE>
Mr. Peter Ewing
November 17, 1995
Page 3
herein commencing with the December 1995 invoice for gas purchased during
November 1995; provided, however, that the continuing effectiveness of these
amendments is subject to obtaining such changes as are appropriate to the long
term import and export authorizations currently held in connection with the
Purchase Contract. TGML and ANE agree that they will use their best efforts to
seek to obtain and cause the other to seek to obtain the regulatory and
governmental authorizations necessary to effectuate the terms of this Amendment.
Finally, the parties agree that this letter agreement and the ballot
tendered by TGML to the TGML producers in connection therewith shall be
"communications" for purposes of Paragraph 5 of the Negotiation and
Confidentiality Agreement between the parties dated as of June 16, 1995.
This letter agreement shall be binding upon and inure to the benefit of the
parties hereto and their respective successors and assigns.
If this letter agreement properly states our agreement, please acknowledge
that fact by signing in the space below and returning an executed copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
28 DAY OF NOVEMBER, 1995
TRANSCANADA GAS MARKETING LIMITED
as Agent for
TRANSCANADA PIPELINES LIMITED
By: [SIGNATURE ILLEGIBLE]^^ BY: [SIGNATURE ILLEGIBLE]^^
--------------------- ---------------------
Title: _______________________ Title: _________________________
<PAGE>
APPENDIX A
ALTERNATIVE MARKET SALE PROTOCOL
The Alternative Market Sale Option consists of (i) ANE Repurchasers
declining to purchase their ANE volumes on certain days in order to permit (ii)
the sale by Seller of ANE volumes in alternative markets in the circumstances
and under the terms and conditions described herein. The purpose of any
transaction undertaken pursuant to the Alternative Market Sale Option shall be
to maximize the mutual economic benefits for both Seller and each of the
participating Repurchasers of the market opportunity. All capitalized terms not
defined herein shall have the meanings ascribed to them in the Gas Purchase
Contracts between ANE and Seller ("Contract(s)").
The protocol for the implementation of the Alternative Market Sale Option
shall be as follows:
1. Seller may at any time and from time to time notify ANE of its desire
to implement the Alternative Market Sale Option. Such notice shall identify the
volumes which are the subject of the potential sale, the price per MMbtu at
which such volumes can be sold in the alternative market (the "Alternative
Market Price"), the term of the potential sale, the delivery point at which the
sale will be made, and any other relevant terms and conditions of the sale,
including without limitation the projected incremental and avoided costs, if
any, to Seller of making such sale in lieu of delivering the ANE volumes to ANE
at
<PAGE>
APPENDIX A
the Delivery Points. ANE shall promptly notify the Repurchasers that Seller has
proposed a potential sale and identify the volumes which are the subject of the
potential sale, the Effective Price per MMbtu (i.e., the Alternative Market
----
Price plus or minus Seller's projected incremental or avoided costs), the term
of the potential sale and any other relevant terms and conditions of the sale.
2. Upon receipt of such notice, any Repurchaser desiring to participate
in the Alternative Market Sale Option shall so notify ANE, stating the volumes
which such Repurchaser is willing to forego purchasing, the cost per MMbtu to
the Repurchaser of obtaining natural gas (or other fuel) to replace the ANE
volumes declined (which, net of the Contract commodity charge, shall be the
"Repurchaser Replacement Cost") and the term for which the Repurchaser will
decline to purchase the volumes which are the subject of its notice.
3. The volumes which are the subject of the Alternative Market Sale
Option shall be offered to the other Repurchasers, at the Alternative Market
Price, pursuant to the reofferring provisions of the ANE Gas Sales Agreements.
All volumes not purchased following such reofferring shall be available for sale
by Seller for the agreed-upon term. To the extent that available volumes exceed
the volumes stated in Seller's notice, such volumes will be allocated to the
Alternative Market Sale giving
2
<PAGE>
APPENDIX A
priority to those volumes with the lowest Repurchaser Replacement Cost.
4. The Net Benefits of the Alternative Market Sale Option shall be
calculated on an individual Repurchaser basis and shall be distributed by Seller
as follows: 50% of the Net Benefit associated with each Repurchaser transaction
shall be retained by Seller for distribution to the TransCanada producers, and
50% of such Net Benefit shall be credited to ANE for the benefit of the
Repurchaser participating in the transaction in accordance with Paragraph 6
hereof. The Net Benefit of each transaction shall be calculated as follows:
(a) The Net Commodity Charge shall be equal to the Contract commodity
charge less all costs per MMbtu to be avoided by Seller as
identified in its notice (for example, transportation commodity
charges [including fuel] not payable as a result of not
delivering the ANE volumes to the Delivery Points) of making the
sale in the alternative market.
(b) The Revenue associated with the Alternative Market Sale Option
shall be equal to the Alternative Market Price less the Net
Commodity Charge.
(c) The Expenses associated with each Repurchaser's participation in
the Alternative Market Sale Option shall be calculated by adding
the incremental costs per MMbtu (including fuel) to be incurred
by Seller as identified in its notice in making the sale in the
alternative market, if any, and the Repurchaser Replacement Cost.
(d) The Net Benefit associated with each Repurchaser's participation
in the Alternative Market Sale Option shall consist of the
Revenue less the
3
<PAGE>
APPENDIX A
Expenses per MMbtu of gas which is the subject of the Alternative
Market Sale Option.
5. All volumes which are the subject of an Alternative Market Sale Option
shall be included in the calculation of the Annual Triggering Quantity for the
relevant year.
6. All Repurchaser Replacement Costs, together with ANE's 50% share of
the Net Benefits of an Alternative Market Sale Option transaction, shall be
credited to the Contract commodity charges otherwise payable by ANE on the
invoice for the month in which the Alternative Market Sale Option is
implemented. ANE shall in turn credit the commodity charges otherwise payable to
ANE by the ANE Repurchasers participating in the Alternative Market Sale Option.
4
<PAGE>
APPENDIX B
TREATMENT OF INCREASES IN U.S. PIPELINE RATES
IN THE CALCULATION OF THE PRICE OF GAS PURSUANT TO ARTICLE VII
The Contract provides, at Article VII, Section 6(b), that the price of gas
purchased thereunder is to be determined by reference to, among other things,
the New York City Gate price for natural gas, or "Pg", which is in turn defined
by reference to certain rates charged by Texas Eastern Transmission Company,
Tennessee Gas Pipeline Company, and TransContinental Gas Pipeline Corporation,
which collectively comprise the natural gas components of the price formula
(such pipelines and the relevant rates are further referred to herein as the
U.S. Pipelines and the U.S. Pipeline Rates). The parties understand that, when a
U.S. Pipeline files for a rate increase, the increase is generally suspended for
a period not exceeding five months, at which point, if a new rate has not been
finally approved, the proposed increased rate is placed into effect subject to
refund. The parties agree that, when any rate increase is placed into effect
subject to refund, the price of gas purchased under the Contract shall be
calculated, billed and paid as set forth in this protocol. The parties further
agree that this protocol shall govern both increases filed for in the U.S.
Pipeline Rates identified herein and increases filed for in any successor U.S.
Pipeline rate schedules which may later be adopted by the parties for purposes
of calculating the price of gas purchased under the
<PAGE>
APPENDIX B
Contract, including in both cases increases in any components or subcomponents
of those rates.
The protocol for treatment of U.S. Pipeline Rate increases in effect
subject to refund shall be as follows:
1. The period commencing on the date on which a proposed U.S. Pipeline
Rate increase (the "Proposed Rate") is placed into effect subject to refund
until the date on which a rate approved by the Federal Energy Regulatory
Commission pursuant to the rate filing (the "Approved Rate") is placed into
effect (and is not subject to refund) shall be the "Refund Period." The "Refund
Period Rate" shall be the rate established by the Federal Energy Regulatory
Commission as the rate to be utilized in calculating refunds due to U.S.
Pipeline customers for the Refund Period.
2. For each month during the Refund Period, Buyer shall calculate, and
Seller shall confirm, the commodity charge (the "Initial Commodity Charge") for
each MMbtu of gas purchased during such month on the basis of the Proposed Rate.
Seller shall bill to and collect from ANE the Initial Commodity Charge for each
MMbtu of gas purchased in each month during the Refund Period.
3. Within thirty days of the close of the Refund Period, Buyer shall
retroactively calculate, and Seller shall confirm, the commodity charge (the
"Adjusted Commodity Charge") for each
2
<PAGE>
APPENDIX B
the Refund Period, utilizing the Refund Period Rate. The difference between the
Initial Commodity Charge and the Adjusted Commodity Charge, multiplied by the
number of MMbtu's purchased by Buyer from Seller during the relevant month,
shall be the "Price Differential" for that month.
4. Seller shall refund to Buyer, by wire transfer in U.S. Dollars to an
account to be identified by Buyer, an amount equal to the Price Differential for
each month of the Refund Period together with interest on each such month's
Price Differential calculated and compounded monthly at a rate equal to the
"Prime Rate" as published by the Wall Street Journal under "Money Rates" on the
last publication date of each month. Buyer shall also refund to the U.S.
Repurchasers, for each MMbtu of gas purchased by each Repurchaser during the
Refund Period, the amount (if any) by which the Initial Commodity Charge per
MMbtu billed to and collected from the Repurchasers exceeds the Adjusted
Commodity Charge, together with each Repurchaser's proportional share of the
interest calculated as above. To the extent that Seller fails to make any wire
transfer payment required by this paragraph 5, Buyer shall be entitled to offset
as a credit the amount of such payment due from Seller against the next invoice
rendered by Seller to Buyer for the purchase of gas under the Contract, and/or
to pursue any other remedy available to Buyer under the Contract or otherwise.
3
<PAGE>
APPENDIX B
5. As of the date on which the Approved Rate goes into effect, Buyer
shall calculate, and Seller shall confirm, the commodity charge for gas
purchased under the Contract on the basis of the Approved Rate, both for the
purpose of calculating the commodity charge per MMbtu to be billed to and paid
by ANE and for the purpose of calculating the commodity charge per MMbtu to be
billed to and collected from the Repurchasers. For greater certainty, it is
confirmed that the "applicable surcharges" referenced in Article VII, Section
6(b) of the Contract will include any FERC-approved surcharge imposed as a
result of appeals by the relevant U.S. Pipeline of the Approved Rate.
6. The procedures set forth herein shall be applied to each U.S. Pipeline
Rate independently.
4
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
March 14,1996
William Luthern
Boston Gas Company
One Beacon Street
Boston, MA 02108
Re: Amendment to ANE Gas Sales Agreement No. 1
------------------------------------------
Dear Mr. Luthern:
The Gas Purchase Contract No. 1 between Alberta Northeast Limited ("ANE") and
TransCanada Gas Marketing Limited ("TGML") (formerly Western Gas Marketing
Limited ("WGML")), as agent for TransCanada PipeLines Limited ("TransCanada")
dated February 7, 1991, as amended ("Purchase Contract No. 1"), has been amended
to (1) add Commonwealth Gas Company ("Commonwealth") as a U.S. Repurchaser and
(2) facilitate, permanently on a firm basis, the delivery of the daily share of
the ANE volumes of National Fuel Gas Distribution Corporation ("National Fuel")
to the point of interconnection between TransCanada and Empire State Pipeline
("Empire") at Chippawa, Ontario.
A copy of the July 25, 1991 Letter Amendment between ANE and WGML, as agent for
TransCanada, with respect to the addition of Commonwealth as a U.S. Repurchaser,
and a copy of the March 6, 1996 Letter Amendment between ANE and TGML, as agent
for TransCanada, with respect to the delivery of National Fuel's share of the
ANE volumes to Chippawa ("1996 Letter Amendment"), are attached hereto.
These amendments require corresponding amendments to the Gas Sales Agreement
between ANE and Boston Gas Company ("Boston Gas") respecting Purchase Contract
No. 1, dated February 7, 1991, as amended ("Gas Sales Agreement No. 1").
1. Amendments related to the addition of Commonwealth as a U.S.
-----------------------------------------------------------
Repurchaser:
- -----------
Effective upon the effectiveness of the Gas Sales Agreement between ANE and
Commonwealth, Gas Sales Agreement No. 1 shall be amended as follows:
<PAGE>
March 14, 1996
Page 2
(a) In the fourth Whereas clause, the number "fourteen (14)" shall be
changed to "fifteen (15)."
(b) In Article VII, Section 1, the number "6.55%" in the first
sentence shall be changed to "4.30%."
(c) In Article VII, Section 2, the table setting forth each U.S.
Repurchaser's share of the Daily Contract Quantity shall be
deleted and the following table substituted therefore:
<TABLE>
<CAPTION>
Share of Daily Contract
U.S. Repurchaser Quantity ("Share")
- ---------------- ------------------
<S> <C>
Long Island Lighting Company 15.20
Yankee Gas Services Company 14.35
New Jersey Natural Gas Company 12.60
The Brooklyn Union Gas Company 12.00
Southern Connecticut Gas Company 7.50
Central Hudson Gas & Electric 7.05
Corporation
Connecticut Natural Gas 5.75
Corporation
National Fuel Gas Distribution 5.00
Corporation
Public Service Electric and 5.00
Gas Company
Boston Gas Company 4.30
Colonial Gas Company 3.00
Consolidated Edison Company of 2.50
New York, Inc.
Commonwealth Gas Company 2.25
</TABLE>
2
<PAGE>
March 14, 1996
Page 3
<TABLE>
<S> <C>
EnergyNorth Natural Gas, Inc. 2.00
Essex County Gas Company 1.00
Valley Gas Company 0.50
</TABLE>
(d) In Article IX, Section 1, the number "fifteen (15)" shall be
changed to "sixteen (16)" and in Article IX, Section 2, the
number "fourteen (14)" shall be changed to "fifteen (15)."
2. Amendments related to the delivery of National Fuel's share to
--------------------------------------------------------------
Chippawa:
--------
Effective upon the effectiveness of the 1996 Letter Amendment, Gas Sales
Agreement No. 1 is amended as follows:
(a) In Article IX, Section 1, the entire fifth sentence shall be
deleted and the following sentence substituted therefore: "The
portion to be paid by Boston Gas to ANE shall be equal to the sum
of (1) the product of the total Iroquois Monthly Demand Charge
billed to ANE by TransCanada in a month times a fraction, the
numerator of which is Boston Gas's Share and the denominator of
which is the sum of the Shares of all U.S. Repurchasers except
National Fuel and (2) the product of the commodity charges billed
to ANE by TransCanada with respect to deliveries to the Iroquois
Point of Delivery in a month times a fraction, the numerator of
which is the quantity of gas delivered by ANE to Boston Gas
during such contract month and the denominator of which is the
quantity of gas delivered by ANE to all U.S. Repurchasers except
National Fuel during such month."
3
<PAGE>
March 14, 1996
Page 4
Please acknowledge these amendments by signing in the space provided below and
returning an executed copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
22nd DAY OF March, 1996
BOSTON GAS COMPANY
By: /s/ [SIGNATURE ILLEGIBLE]^^
--------------------------------
Title: VICE PRESIDENT
-----------------------------
4
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
July 25, 1991
Mr. Murray Ross
Western Gas Marketing Ltd.,
as agent for
TransCanada PipeLines Limited
55 Yonge Street
11th Floor
Toronto, Ontario
CANADA M5E 1J4
Dear Mr. Ross:
With regard to the February 7, 1991 Gas Purchase Contract No. 1
between Western Gas Marketing Limited as agent for TransCanada PipeLines Limited
("Western Gas"), and Alberta Northeast Gas Limited ("ANE") ("Gas Purchase
Contract No. 1"), and to the February 7, 1991 Gas Sales Agreements No. 1 between
ANE and each of the U.S. Repurchasers ("Gas Sales Agreements No. 1"), this
letter reflects our agreement to the following prospective amendments to Gas
Purchase Contract No. 1 and to each of the Gas Sales Agreements No. 1:
Gas Purchase Contract No. 1
- ---------------------------
1. In the sixth Whereas clause, the words "fifteen (15)" shall
be changed to "sixteen (16)".
2. In the seventh Whereas clause, the words "fifteen (15)" shall
be changed to "sixteen (16)".
Gas Sales Agreements No. 1
- --------------------------
1. In the fourth Whereas clause, the words "fourteen (14)" shall
be changed to "fifteen (15)".
2. In Article VII, Section 2, the table setting forth each U.S.
Repurchaser's share of the Daily Contract Quantity shall be deleted and the
following table substituted therefore:
<PAGE>
Mr. Murray Ross
July 25, 1991
Page 2
Share of Daily Contract
U.S. Repurchaser Quantity ("Share")
---------------- ------------------
Long Island Lighting Company 15.20%
Yankee Gas Services Company 14.35%
New Jersey Natural Gas Company 12.60%
The Brooklyn Union Gas Company 12.00%
Southern Connecticut Gas Company 7.50%
Central Hudson Gas & Electric
Corporation 7.05%
Connecticut Natural Gas Corporation 5.75%
National Fuel Gas Supply Corporation 5.00%
Public Service Electric and
Gas Company 5.00%
Boston Gas Company 4.30%
Colonial Gas Company 3.00%
Consolidated Edison Company of
New York, Inc. 2.50%
Commonwealth Gas Company 2.25%
EnergyNorth Natural Gas, Inc. 2.00%
Essex County Gas Company 1.00%
Valley Gas Company .50%
3. In the fifth sentence of Article IX, Section 1, the words
"fifteen (15)" shall be changed to "sixteen (16)".
4. In the first sentence of Article IX, Section 2, the words
"fourteen (14)" shall be changed to "fifteen (15)".
5. Exhibit I shall be deleted in its entirety and replaced by
the Exhibit I attached to this agreement.
This letter reflects the express agreement of Western Gas and
ANE that the effectiveness of these prospective amendments to Gas Purchase
Contract No. 1 and Gas sales Agreements No. 1 are conditioned only upon (i) the
issuance of an order by the Department of Energy, Office of Fossil Energy,
authorizing Commonwealth Gas Company to import 4,500 Mcf of gas per day from
ANE, and (ii) receipt of any necessary regulatory approvals for the
transportation of the Daily Contract Quantity in accordance with the shares set
forth above, all in form and substance acceptable to ANE and Western Gas.
<PAGE>
Mr. Murray Ross
July 25, 1991
Page 3
If this letter properly states our agreement, please acknowledge
that fact by signing in the space provided below and returning an executed copy
of this letter to me.
Sincerely,
ALBERTA NORTHEAST GAS LIMITED
By /s/ James A. Rooney
-------------------------------
James A. Rooney, President
ACKNOWLEDGED AND ACCEPTED THIS
9th DAY OF August, 1991
WESTERN GAS MARKETING LIMITED
as agent for
TRANSCANADA PIPELINES LIMITED
By /s/ SIGNATURE ILLEGIBL^^
-------------------------
<PAGE>
EXHIBIT I
---------
DISTRIBUTION OF PURCHASES
Nov. 1, 1991-Dec. 31, 1991
(34,318 Mcf/d)
--------------------------
<TABLE>
<CAPTION>
Volume
U.S. Repurchaser (Mcf/d)
- ---------------- -------
<S> <C>
New Jersey Natural Gas Company 4,389
Long Island Lighting Company 4,309
The Brooklyn Union Gas Company 2,209
Yankee Gas Services Company 2,140
Central Hudson Gas and Electric Corporation 1,963
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 1,742
Boston Gas Company 1,497
Southern Connecticut Gas Company 1,134
Colonial Gas Company 1,045
Connecticut Natural Gas Corporation 1,018
Consolidated Edison Company
of New York, Inc. 870
Commonwealth Gas Company 784
EnergyNorth Natural Gas, Inc. 696
Essex County Gas Company 348
Valley Gas Company 174
</TABLE>
DISTRIBUTION OF PURCHASES
Jan. 1, 1992-Mar. 31, 1992
(125.268 Mcf/d)
--------------------------
<TABLE>
<S> <C>
New Jersey Natural Gas Company 20,803
Long Island Lighting Company 20,423
The Brooklyn Union Gas Company 10,469
Yankee Gas Services Company 10,145
Central Hudson Gas and Electric Corporation 9,303
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 8,255
Boston Gas Company 7,099
Southern Connecticut Gas Company 5,375
Colonial Gas Company 4,953
Connecticut Natural Gas Corporation 4,822
Consolidated Edison Company of
New York, Inc. 4,128
Commonwealth Gas Company 3,715
EnergyNorth Natural Gas, Inc. 3,302
Essex County Gas Company 1,651
Valley Gas Company 825
</TABLE>
<PAGE>
DISTRIBUTION OF PURCHASES
Apr. 1, 1992-Oct. 31, 1992
(149.635 Mcf/d)
--------------------------
<TABLE>
<S> <C>
New Jersey Natural Gas Company 25,200
Long Island Lighting Company 24,741
The Brooklyn Union Gas Company 12,682
Yankee Gas Services Company 12,289
Central Hudson Gas and Electric Corporation 11,270
National Fuel Gas Supply Corporation 10,000
Public Service Electric and Gas Company 10,000
Boston Gas Company 8,600
Southern Connecticut Gas Company 6,512
Colonial Gas Company 6,000
Connecticut Natural Gas Corporation 5,841
Consolidated Edison Company of
New York, Inc. 5,000
Commonwealth Gas Company 4,500
EnergyNorth Natural Gas, Inc. 4,000
Essex County Gas Company 2,000
Valley Gas Company 1,000
</TABLE>
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
March 6, 1996
Mr. Peter Ewing
TransCanada Gas Marketing Limited
as agent for TransCanada
PipeLines Limited
55 Yonge Street
Toronto, Canada M5E 1J4
Re: Amendment to Gas Purchase Contract
No. 1 between ANE and TGML
----------------------------------
Dear Mr. Ewing:
Alberta Northeast Limited ("ANE") and TransCanada Gas Marketing Limited
(formerly Western Gas Marketing Limited) ("TGML"), as agent for TransCanada
Pipelines Limited ("TransCanada"), are parties to Gas Purchase Contract No. 1,
dated February 7, 1991, as amended ("Purchase Contract No. 1"), which provides,
inter alia, for the delivery of gas by TGML to ANE at TransCanada's points of
- ----- ----
interconnection with Tennessee Gas Pipeline Company ("Tennessee") near Niagara
Falls, Ontario for redelivery to National Fuel Gas Distribution Corporation
("National Fuel") and with Iroquois Gas Transmission System, L.P. ("Iroquois")
near Iroquois, Ontario for redelivery to fourteen other utility companies
engaged in the distribution of natural gas in the Northeastern United States.
This Amendment concerns one change to Purchase Contract No. 1. Namely, National
Fuel has requested, and TGML and ANE have agreed, to amend Purchase Contract No.
1 to facilitate, permanently on a firm basis, the delivery of National Fuel's
daily share of the ANE volumes to the point of interconnection between
TransCanada and Empire State Pipeline ("Empire") at Chippawa, Ontario.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 2
This letter reflects our agreement to the following amendments to the
Purchase Contract No. 1:
1. The following new Whereas Clause is inserted after the Second Whereas
Clause:
WHEREAS, TransCanada owns and operates an additional extension of its
pipeline system to a point on the International Border between the United
States of America and Canada near Chippawa, Ontario, where it interconnects
with the facilities of a U.S. interstate pipeline, Empire State Pipeline
("Empire"), which point is herein called the "Chippawa Point of
Interconnection"; and
2. The Eighth Whereas Clause is amended as follows:
(a) by deleting the word "Tennessee" at each place that it appears
therein and substituting the word "Empire" therefore; and
(b) by deleting the words "Niagara Falls" therein and substituting the
word "Chippawa" therefore.
3. Article I, Definition of Terms, Section 10, is amended by deleting the
words "Niagara Falls" at each place that it appears in the second paragraph
thereof and substituting the word "Chippawa" therefore.
4. Article I, Definition of Terms, Section 11, is amended as follows:
(a) by deleting the number "16." in the first sentence thereof and
substituting the number "17." therefore; and
(b) by deleting the words "Niagara Falls" at both places that they appear
in the second sentence thereof and substituting the word "Chippawa" therefore.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 3
5. Article I, Definition of Terms, is amended by inserting the following
new Section 17. after Section 16. thereof:
17. The term "Chippawa Point of Delivery" shall mean a point on the
Canadian side of the international boundary between Canada and the United
States of America at or near the Chippawa Point of Interconnection.
6. Article I, Definition of Terms, Section 17, is renumbered Section 18.
7. Article II, Contract Quantities; Deliveries, Section 5, is amended by
deleting the word "Tennessee" at both place that it appears therein and
substituting the word "Empire" therefore.
8. Article IV, Delivery Pressure, is amended as follows:
(a) by deleting the word "Tennessee" in the second sentence thereof and
substituting the word "Empire" therefore;
(b) by deleting the word "Niagara Falls" in the second sentence thereof
and substituting the word "Chippawa" therefore; and
(c) by deleting the number "700" in the second sentence thereof and
substituting the number "1225" therefore.
9. Article VII, Price, Section 2, is amended by deleting the words
"Niagara Falls" in the first sentence thereof and substituting the word
"Chippawa" therefore.
10. Article VII, Price, Section 2(b), is amended by deleting the words
"Niagara Falls" at each place that they appear therein and substituting the word
"Chippawa" therefore.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 4
11. Article VII, Price, Section 3, is amended as follows:
(a) by deleting the words "Niagara Falls" at each place that they appear
in the definition of "DC-DPC" therein and substituting the word "Chippawa1"
therefore; and
(b) by inserting the following new provisos as full text after the
blocked definition of "DC-DPC":
provided, however, that the commodity charge in respect of gas which Buyer
requests and Seller tenders for delivery at the Chippawa Point of Delivery
shall be increased or decreased, as the case may be, by an amount equal to
(i) the amount by which the sum of the monthly demand toll per Mcf, the
DPC and TransCanada's commodity toll applicable to the firm transportation
of gas to the Chippawa Point of Delivery from time to time, calculated per
Mcf, exceeds or is less than the sum of the corresponding costs per Mcf
applicable to the firm transportation of gas to the Niagara Falls Point of
Delivery and (ii) an amount equal to the product of the commodity charge,
as otherwise determined for the Iroquois Point of Delivery, and the
differential between the fuel requirement applicable to the firm
transportation of gas to the Chippawa and Niagara Falls Points of
Delivery, calculated per MMbtu
12. Article VII, Price, Section 4, is amended by deleting the words
"Niagara Falls" in the second sentence thereof and substituting the word
"Chippawa" therefore.
13. Article VII, Price, Section 5, is amended by deleting the word "form"
in the first sentence thereof and substituting the word "from" therefore.
14. Article VIII, Billings and Payment, Section 1, is amended by inserting
the words "at each Point of Delivery" after the words "daily and total quantity
of gas delivered hereunder" in the first sentence thereof.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 5
15. Article X, Measurement of Gas, Sections 3(b) and 3(h), are amended by
deleting the word "Tennessee" at each place that it appears therein and
substituting the word "Empire" therefore.
16. Article XII, Force Majeure, Section 1, is amended by deleting the word
"Tennessee" in the second sentence thereof and substituting the word "Empire"
therefore.
17. Article XII, Force Majeure, Section 3, is amended by deleting the word
"Tennessee" at each place that it appears therein and substituting the word
"Empire" therefore.
18. Article XII, Force Majeure, Section 4, is amended by deleting the word
"Tennessee" therein and substituting the word "Empire" therefore.
The effectiveness of these amendments is subject to obtaining such changes
as are appropriate to the long term import and export authorizations currently
held in connection with the Purchase Contract No. 1. TGML and ANE agree that
they will use their best commercially reasonable efforts to seek to obtain and
cause the other to seek to obtain the regulatory and governmental authorizations
necessary to effectuate the terms of this Amendment.
This letter agreement shall be binding upon and inure to the benefit of
the parties hereto and their respective successors and assigns.
<PAGE>
Mr. Peter Ewing
March 6, 1996
Page 6
If this letter agreement properly states our agreement, please
acknowledge that fact by signing in the space below and returning an executed
copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
02 DAY OF MARCH, 1996
TRANSCANADA GAS MARKETING LIMITED
as agent for
TRANSCANADA PIPELINES LIMITED
By: /s/ Joel G. Johnson
-----------------------------
JOEL G. JOHNSON
Title: Vice President, Marketing
----------------------------
By: /s/ G. Lawrence Spackman
-----------------------------
G. LAWRENCE SPACKMAN
Title: President
__________________________
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
November 27, 1995
William Luthern
Boston Gas Company
One Beacon Street
Boston, MA 02108
Re: Amendment to Gas Sales Agreement No. 1
--------------------------------------
Dear Mr. Luthern:
Gas Purchase Contract No. 1 between Alberta Northeast Limited ("ANE")
and TransCanada Gas Marketing Limited (formerly Western Gas Marketing Limited)
("TGML"), as agent for TransCanada Pipelines Limited ("TransCanada"), dated
February 7, 1991, as amended ("Purchase Contract No. 1"), has been amended
effective November 1, 1995 to reflect changes agreed upon in the recently-
concluded price renegotiation between ANE and TGML pursuant to Article VII,
Section 7 of Purchase Contract No. 1. A copy of the amending agreement, together
with the Protocols appended thereto ("Amendment to Purchase Contract No. 1"), is
attached hereto. The amendments made effective by the Amendment to Purchase
Contract No. 1 are:
1. Certain adjustments to the base price of the gas
purchased by ANE from TGML pursuant to Purchase
Contract No. 1;
2. An increase in the Annual Triggering Quantity
from 60% to 70%;
3. An option for the sale of gas in alternative
markets and the sharing of revenues associated
therewith; and
4. A refund mechanism associated with pipeline
transportation rates in effect subject to refund.
<PAGE>
These amendments to Purchase Contract No. 1 were approved by a vote of
more than sixty percent (60%) of the Repurchaser Shares under Gas Sales
Agreement No. 1 between ANE and Boston Gas, dated February 7, 1991, as amended
("Gas Sales Agreement No. 1"), and require corresponding amendments to Gas Sales
Agreement No. 1.
Specifically, effective upon the effectiveness of the Amendment to
Purchase Contract No. 1, Article VIII, Reduction of Shares, Section 2 of Gas
Sales Agreement No. 1 is amended by deleting the percentage "60%" at both places
that it appears therein and substituting the percentage "70%" therefore, and all
other provisions of Gas Sales Agreement No. 1 are deemed amended to the extent
necessary to implement the Amendment to Purchase Contract No. 1, including the
Alternative Market Sale Protocol and the Protocol for the Treatment of Increases
in U.S. Pipeline Rates.
Please acknowledge these amendments by signing in the space provided
below and returning an executed copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
6/th/ DAY OF DEC, 1995
BOSTON GAS COMPANY
By: /s/ SIGNATURE ILLEGIBLE ^^
---------------------------
Title: Vice President
-------------------------
2
<PAGE>
[LETTERHEAD OF ALBERTA NORTHEAST GAS LIMITED APPEARS HERE]
November 17, 1995
VIA OVERNIGHT COURIER
- ---------------------
Mr. Peter Ewing
TransCanada Gas Marketing Limited,
as agent for TransCanada
PipeLines Limited
55 Yonge Street
Toronto, Canada MSE 1J4
Re: Amendment to Gas Purchase Contract
No. 1 between TGML and ANE
----------------------------------
Dear Mr. Ewing:
Alberta Northeast Gas Limited ("ANE") and TransCanada Gas Marketing
Limited (formerly Western Gas Marketing Limited) ("TGML"), as agent for
TransCanada Pipelines Limited ("TransCanada"), are parties to Gas Purchase
Contract No. 1, dated February 7, 1991, as amended ("Purchase Contract"), which
provides, inter alia, for the delivery of gas by TGML to ANE at TransCanada's
----- ----
points of interconnection with Tennessee Gas Pipeline Company ("Tennessee") near
Niagara Falls, Ontario for redelivery to National Fuel Gas Distribution
Corporation ("National Fuel") and with Iroquois Gas Transmission System, L.P.
("Iroquois") near Iroquois, Ontario for redelivery to fourteen other utility
companies engaged in the distribution of natural gas in the Northeastern United
States (together with National Fuel, the "U.S. Repurchasers"). This Amendment
concerns changes to the Purchase Contract agreed upon in our recently-concluded
price renegotiation pursuant to Article VII, Section 7 of the Purchase Contract.
Specifically, this letter reflects our agreement to the following
amendments to the Purchase Contract effective November 1, 1995:
<PAGE>
Mr. Peter Ewing
November 17, 1995
Page 2
1. Article I, Definition of Terms, Section 14, "Annual Triggering
Quantity," is amended by deleting the words "sixty percent (60%)" therein and
substituting the words "seventy percent (70%)" therefore.
2. With respect to the obligation to sell and deliver gas in Article II,
Contract Quantities; Deliveries, Section 1, quantities of gas may be diverted to
alternative markets in accordance with the provisions of the Alternative Market
Sale Protocol attached hereto as Appendix A.
3. Article VII, Price, Section 6(a), is amended by deleting the price
"$3.79" and substituting the price "$3.67" therefore.
4. Article VII, Price, Section 6(a), is amended by deleting the price
"$3.38" and substituting the price "$3.26" therefore.
5. With respect to the New York Weighted Average Price in Article VII,
Price, Section 6(b), the impact of acceptance by the Federal Energy Regulatory
Commission, subject to refund, of transportation rate changes filed by Tennessee
Gas Pipeline Company, a Division of Tenneco Inc., Texas Eastern Transmission
Corporation or Transcontinental Gas Pipeline Corporation will be accounted for
in accordance with the provisions of the Protocol for the Treatment of Increases
in U.S. Pipeline Rates attached hereto as Appendix B; provided, however, that
the Refund Period (as defined therein) for any such rate in effect subject to
refund as of November 1, 1995 shall commence as of November 1, 1995.
The effectiveness of these amendments is subject to approval of this
Amendment on or before November 15, 1995, by the producers for TGML by a vote
that TGML believes to be sufficient to require the Alberta Petroleum Marketing
Commission ("APMC") to issue an unconditional finding of producer support in
accordance with the provisions of the Natural Gas Marketing Act (Alberta) and a
finding of such producer support by the APMC on or before December 15, 1995.
TGML will make its application to the APMC expeditiously in order to ensure that
the APMC's determination with respect to the finding of producer support is
issued by December 15, 1995.
The parties agree that billing and payment under the Contract shall
reflect the amendments to the Contract set forth
<PAGE>
Mr. Peter Ewing
November 17, 1995
Page 3
herein commencing with the December 1995 invoice for gas purchased during
November 1995; provided, however, that the continuing effectiveness of these
amendments is subject to obtaining such changes as are appropriate to the long
term import and export authorizations currently held in connection with the
Purchase Contract. TGML and ANE agree that they will use their best efforts to
seek to obtain and cause the other to seek to obtain the regulatory and
governmental authorizations necessary to effectuate the terms of this Amendment.
Finally, the parties agree that this letter agreement and the ballot
tendered by TGML to the TGML producers in connection therewith shall be
"communications" for purposes of Paragraph 5 of the Negotiation and
Confidentiality Agreement between the parties dated as of June 16, 1995.
This letter agreement shall be binding upon and inure to the benefit
of the parties hereto and their respective successors and assigns.
If this letter agreement properly states our agreement, please
acknowledge that fact by signing in the space below and returning an executed
copy to me.
Sincerely,
Alberta Northeast Gas Limited
/s/ Michael S. Lucy
Michael S. Lucy
President
ACKNOWLEDGED AND ACCEPTED THIS
25 DAY OF NOVEMBER, 1995
TRANSCANADA GAS MARKETING LIMITED
as Agent for
TRANSCANADA PIPELINES LIMITED
By: /s/ [SIGNATURE ILLEGIBLE]^^ By: /s/ [SIGNATURE ILLEGIBLE]^^
---------------------------- ----------------------------
Title: ________________________ Title: ________________________
<PAGE>
APPENDIX A
ALTERNATIVE MARKET SALE PROTOCOL
The Alternative Market Sale Option consists of (i) ANE Repurchasers
declining to purchase their ANE volumes on certain days in order to permit (ii)
the sale by Seller of ANE volumes in alternative markets in the circumstances
and under the terms and conditions described herein. The purpose of any
transaction undertaken pursuant to the Alternative Market Sale Option shall be
to maximize the mutual economic benefits for both Seller and each of the
participating Repurchasers of the market opportunity. All capitalized terms not
defined herein shall have the meanings ascribed to them in the Gas Purchase
Contracts between ANE and Seller ("Contract(s) ").
The protocol for the implementation of the Alternative Market Sale
Option shall be as follows:
1. Seller may at any time and from time to time notify ANE of its
desire to implement the Alternative Market Sale Option. Such notice shall
identify the volumes which are the subject of the potential sale, the price per
NMbtu at which such volumes can be sold in the alternative market (the
"Alternative Market Price"), the term of the potential sale, the delivery point
at which the sale will be made, and any other relevant terms and conditions of
the sale, including without limitation the projected incremental and avoided
costs, if any, to Seller of making such sale in lieu of delivering the ANE
volumes to ANE at
<PAGE>
APPENDIX A
the Delivery Points. ANE shall promptly notify the Repurchasers that Seller has
proposed a potential sale and identify the volumes which are the subject of the
potential sale, the Effective Price per MMbtu (i.e., the Alternative Market
----
Price plus or minus Seller's projected incremental or avoided costs), the term
of the potential sale and any other relevant terms and conditions of the sale.
2. Upon receipt of such notice, any Repurchaser desiring to participate
in the Alternative Market Sale Option shall so notify ANE, stating the volumes
which such Repurchaser is willing to forego purchasing, the cost per MMbtu to
the Repurchaser of obtaining natural gas (or other fuel) to replace the ANE
volumes declined (which, net of the Contract commodity charge, shall be the
"Repurchaser Replacement Cost") and the term for which the Repurchaser will
decline to purchase the volumes which are the subject of its notice.
3. The volumes which are the subject of the Alternative Market Sale
Option shall be offered to the other Repurchasers, at the Alternative Market
Price, pursuant to the reofferring provisions of the ANE Gas Sales Agreements.
All volumes not purchased following such reofferring shall be available for sale
by Seller for the agreed-upon term. To the extent that available volumes exceed
the volumes stated in Seller's notice, such volumes will be allocated to the
Alternative Market Sale giving
2
<PAGE>
APPENDIX A
priority to those volumes with the lowest Repurchaser Replacement Cost.
4. The Net Benefits of the Alternative Market Sale Option shall be
calculated on an individual Repurchaser basis and shall be distributed by Seller
as follows: 50% of the Net Benefit associated with each Repurchaser transaction
shall be retained by Seller for distribution to the TransCanada producers, and
50% of such Net Benefit shall be credited to ANE for the benefit of the
Repurchaser participating in the transaction in accordance with Paragraph 6
hereof. The Net Benefit of each transaction shall be calculated as follows:
(a) The Net Commodity Charge shall be equal to the Contract
commodity charge less all costs per MMbtu to be avoided by
Seller as identified in its notice (for example, transportation
commodity charges [including fuel] not payable as a result of
not delivering the ANE volumes to the Delivery Points) of making
the sale in the alternative market.
(b) The Revenue associated with the Alternative Market Sale Option
shall be equal to the Alternative Market Price less the Net
Commodity Charge.
(c) The Expenses associated with each Repurchaser's participation in
the Alternative Market Sale Option shall be calculated by adding
the incremental costs per MMbtu (including fuel) to be incurred
by Seller as identified in its notice in making the sale in the
alternative market, if any, and the Repurchaser Replacement
Cost.
(d) The Net Benefit associated with each Repurchaser's participation
in the Alternative Market Sale Option shall consist of the
Revenue less the
3
<PAGE>
APPENDIX A
Expenses per MMbtu of gas which is the subject of the
Alternative Market Sale Option.
5. All volumes which are the subject of an Alternative Market Sale
Option shall be included in the calculation of the Annual Triggering Quantity
for the relevant year.
6. All Repurchaser Replacement Costs, together with ANE's 50% share of
the Net Benefits of an Alternative Market Sale Option transaction, shall be
credited to the Contract commodity charges otherwise payable by ANE on the
invoice for the month in which the Alternative Market Sale Option is
implemented. ANE shall in turn credit the commodity charges otherwise payable to
ANE by the ANE Repurchasers participating in the Alternative Market Sale Option.
4
<PAGE>
APPENDIX B
TREATMENT OF INCREASES IN U.S. PIPELINE RATES IN THE
CALCULATION OF THE PRICE OF GAS PURSUANT TO ARTICLE VII
The Contract provides, at Article VII, Section 6(b), that the price of
gas purchased thereunder is to be determined by reference to, among other
things, the New York City Gate price for natural gas, or "Pg", which is in turn
defined by reference to certain rates charged by Texas Eastern Transmission
Company, Tennessee Gas Pipeline Company, and TransContinental Gas Pipeline
Corporation, which collectively comprise the natural gas components of the price
formula (such pipelines and the relevant rates are further referred to herein as
the U.S. Pipelines and the U.S. Pipeline Rates). The parties understand that,
when a U.S. Pipeline files for a rate increase, the increase is generally
suspended for a period not exceeding five months, at which point, if a new rate
has not been finally approved, the proposed increased rate is placed into effect
subject to refund. The parties agree that, when any rate increase is placed into
effect subject to refund, the price of gas purchased under the Contract shall be
calculated, billed and paid as set forth in this protocol. The parties further
agree that this protocol shall govern both increases filed for in the U.S.
Pipeline Rates identified herein and increases filed for in any successor U.S.
Pipeline rate schedules which may later be adopted by the parties for purposes
of calculating the price of gas purchased under the
<PAGE>
APPENDIX B
Contract, including in both cases increases in any components or subcomponents
of those rates.
The protocol for treatment of U.S. Pipeline Rate increases in effect
subject to refund shall be as follows:
1. The period commencing on the date on which a proposed U.S. Pipeline
Rate increase (the "Proposed Rate") is placed into effect subject to refund
until the date on which a rate approved by the Federal Energy Regulatory
Commission pursuant to the rate filing (the "Approved Rate") is placed into
effect (and is not subject to refund) shall be the "Refund Period." The "Refund
Period Rate" shall be the rate established by the Federal Energy Regulatory
Commission as the rate to be utilized in calculating refunds due to U.S.
Pipeline customers for the Refund Period.
2. For each month during the Refund Period, Buyer shall calculate, and
Seller shall confirm, the commodity charge (the "Initial Commodity Charge") for
each MMbtu of gas purchased during such month on the basis of the Proposed Rate.
Seller shall bill to and collect from ANE the Initial Commodity Charge for each
MMbtu of gas purchased in each month during the Refund Period.
3. Within thirty days of the close of the Refund Period, Buyer shall
retroactively calculate, and Seller shall confirm, the commodity charge (the
"Adjusted Commodity Charge") for each
2
<PAGE>
APPENDIX B
the Refund Period, utilizing the Refund Period Rate. The difference between the
Initial Commodity Charge and the Adjusted Commodity Charge, multiplied by the
number of MMbtu's purchased by Buyer from Seller during the relevant month,
shall be the "Price Differential" for that month.
4. Seller shall refund to Buyer, by wire transfer in U.S. Dollars to an
account to be identified by Buyer, an amount equal to the Price Differential for
each month of the Refund Period together with interest on each such month's
Price Differential calculated and compounded monthly at a rate equal to the
"Prime Rate" as published by the Wall Street Journal under "Money Rates" on the
last publication date of each month. Buyer shall also refund to the U.S.
Repurchasers, for each MMbtu of gas purchased by each Repurchaser during the
Refund Period, the amount (if any) by which the Initial Commodity Charge per
MMbtu billed to and collected from the Repurchasers exceeds the Adjusted
Commodity Charge, together with each Repurchaser's proportional share of the
interest calculated as above. To the extent that Seller fails to make any wire
transfer payment required by this paragraph 5, Buyer shall be entitled to offset
as a credit the amount of such payment due from Seller against the next invoice
rendered by Seller to Buyer for the purchase of gas under the Contract, and/or
to pursue any other remedy available to Buyer under the Contract or otherwise.
3
<PAGE>
APPENDIX B
5. As of the date on which the Approved Rate goes into effect, Buyer
shall calculate, and Seller shall confirm, the commodity charge for gas
purchased under the Contract on the basis of the Approved Rate, both for the
purpose of calculating the commodity charge per MMbtu to be billed to and paid
by ANE and for the purpose of calculating the commodity charge per MMbtu to be
billed to and collected from the Repurchasers. For greater certainty, it is
confirmed that the "applicable surcharges" referenced in Article VII, Section
6(b) of the Contract will include any FERC-approved surcharge imposed as a
result of appeals by the relevant U.S. Pipeline of the Approved Rate.
6. The procedures set forth herein shall be applied to each U.S.
Pipeline Rate independently.
4
<PAGE>
Exhibit 18.1
January 20, 1999
Boston Gas Company
One Beacon Street
Boston, MA 02110
Re: Form 10-K Report for the Year Ended December 31, 1998
Ladies and Gentlemen:
This letter is written to meet the requirements of Regulation S-K calling for a
letter from a registrant's independent public accountants whenever there has
been a change in accounting principle or practice.
During the fourth quarter of 1998, the Company changed its method of accounting
for unbilled revenues, retroactively applied as of January 1, 1998, from
recording revenue when billed to its customers based on its monthly meter
reading schedule to estimating and accruing the amounts of revenues associated
with service provided after billing through the end of the accounting period.
According to management of the Company, this change was made to better match
revenues with service provided to customers and to be consistent with the
prevalent method in the utility industry.
We are of the opinion that the Company's change in method of accounting is to an
acceptable alternative method of accounting, which, based upon the reasons
stated for the change and our discussions with you, is also preferable under the
circumstances in this particular case. In arriving at this opinion, we have
relied on the business judgment and business planning of your management.
Very truly yours,
Arthur Andersen LLP
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