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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:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ------------------------
None None
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
PART I
Item 1. Business
Page
----
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
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.
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.
Years Ended December 31,
------------------------
1998 1997 1996
-------- -------- --------
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
======== ======== ========
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.
Years Ended December 31,
------------------------
1998 1997 1996
-------- -------- --------
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
======== ======== ========
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").
2
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:
Capacity in BCF
--------------- Expiration
Pipeline Daily Annual Dates
-------- ------- -------- ----------
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
======= ========
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,
3
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
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
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
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
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
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
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
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
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.
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).*
12
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)
13
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)
14
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)
15
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.
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
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
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.
17
BOSTON GAS COMPANY AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
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
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
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
-----------------
1998 1997
-------- --------
(In Thousands)
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
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDER'S INVESTMENT
December 31,
-----------------
1998 1997
-------- --------
(In Thousands)
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
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF EARNINGS
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
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
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
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
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
----------------------------
1998 1997 1996
-------- -------- --------
(In Thousands)
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
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
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
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:
1998 1997
------- --------
(In Thousands)
Post-retirement benefit costs........................... $78,567 $ 83,926
Environmental costs..................................... 18,190 18,852
Other................................................... 1,365 1,998
------- --------
$98,122 $104,776
======= ========
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
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:
1998 1997 1996
------- ------- -------
(In Thousands)
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
======= ======= =======
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
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:
1998 1997
--------- ---------
(In Thousands)
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)
========= =========
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:
December 31,
------------------
1998 1997
-------- --------
(In Thousands)
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
======== ========
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
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
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
1998 1997 1996
------- ------- -------
(In Thousands)
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
1998 1997 1996
------- ------- -------
(In Thousands)
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
======= ======= =======
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
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:
Pensions Health Care
------------------ --------------------
1998 1997 1998 1997
-------- -------- --------- ---------
(In Thousands)
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)
======== ======== ========= =========
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
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:
1998 1997 1996
--------- ---------- ----------
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%
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:
One-Percentage One-Percentage
Point Increase Point Decrease
-------------- --------------
Service cost and interest cost components.... $ 473 $ (406)
Post-retirement benefit obligation........... $5,851 $(5,044)
(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:
1998 1997
------ ------
(In
Thousands)
Buildings..................................................... 6,000 6,000
Less-Accumulated depreciation................................. 4,764 4,,257
------ ------
Total Capital Leases.......................................... $1,236 $1,743
====== ======
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
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:
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
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
=======
(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:
1998 1997
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands) (In Thousands)
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
F-15
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
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
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:
Three Months Ended
-----------------------------------
Sept.
March 31 June 30 30 Dec. 31
-------- -------- ------- --------
(In Thousands)
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
F-18
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
Additions
---------------------
Charged Net
Balance, Charged (Credited) Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1997 to Income Accounts Reserves 1998
----------- ------------ ---------- ---------- ---------- ------------
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
======== ======= ===== ======= ========
F-19
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1996 to Income Accounts Reserves 1997
----------- ------------ ---------- -------- ---------- ------------
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
======== ======= ======= ======= ========
F-20
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1996
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1995 to Income Accounts Reserves 1996
----------- ------------ ---------- -------- ---------- ------------
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
======== ======= ====== ======= ========
F-21