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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(MARK ONE)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
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, 1998.
ALL COMMON STOCK, 514,184 SHARES, ARE HELD BY EASTERN ENTERPRISES.
The registrant meets the conditions set forth in General Instruction
(J)(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................................................. 4
Item 3. Legal Proceedings.......................................... 5
Item 4. Submission of Matters to a Vote of Security Holders........ 5
Glossary............................................................ 6
PART II
Item 5. Market for the Registrant's Common Equity and Related
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................ 9
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................... 9
PART III
Item 10. Directors and Executive Officers of the Registrant......... 9
Item 11. Executive Compensation..................................... 9
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 9
Item 13. Certain Relationships and Related Transactions............. 9
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................... 10
PART I
ITEM 1. BUSINESS.
GENERAL
Boston Gas Company (the "Company"), is engaged in the transportation and
sale of natural gas to approximately 530,000 residential, commercial and
industrial customers in Boston, Massachusetts and 73 other communities in
eastern and central Massachusetts. The Company also sells gas for resale. The
Company has one subsidiary, Massachusetts LNG Incorporated ("Mass LNG"), which
held a long-term lease on two liquefied natural gas ("LNG") facilities and now
operates the facilities pursuant to an agreement (see Item 2, Properties). The
Company is the largest natural gas distribution company in New England, has
been in business for 175 years and is the second oldest gas company in the
United States. 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.
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. All residential customers currently purchase combined or
"bundled" supply and transportation services from the Company. In 1993, the
Massachusetts Department of Telecommunications and Energy, formerly the
Department of Public Utilities ("the Department") approved the Company's
proposal to unbundle local transportation service and gas sales service for
its 450 largest commercial and industrial customers. In November 1996, the
Department approved the Company's proposal to offer unbundled transportation
service to all of its commercial and industrial customers, numbering over
41,000. As of December 31, 1997, 2,174 customers have chosen to purchase gas
from 22 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, especially in the tracking and processing of
transactions. 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 has implemented a program to educate commercial
and industrial customers about the opportunity to purchase gas from third-
party suppliers, while still relying on the Company for delivery.
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. 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.
In the fourth quarter of 1997, the Company recorded $8.7 million of
restructuring charges in connection with its decision to exit the gas
appliance repair and service business. This will allow the Company to focus on
its core business of local transportation and expanding throughput on its
system.
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 may
represent a growth opportunity for the Company. However, actual experience
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 billions of cubic feet of natural gas at 1,000 Btu
per cubic foot ("BCF") provides information with respect to the volumes of gas
delivered by the Company during the three years 1995-1997.
YEARS ENDED DECEMBER 31,
----------------------------
1997 1996 1995
-------- -------- --------
Residential.................................... 41.7 42.8 39.7
Commercial and industrial...................... 35.7 39.4 48.1
Off-system sales............................... 7.4 12.2 6.6
-------- -------- --------
Total sales.................................. 84.8 94.4 94.4
Transportation of customer-owned gas........... 80.9 61.6 47.5
Less: Off-system sales......................... (7.4) (12.2) (6.6)
-------- -------- --------
Total throughput............................. 158.3 143.8 135.3
======== ======== ========
Total firm throughput........................ 120.0 118.7 94.9
======== ======== ========
Residential customers comprise 92% of its customer base, while commercial
and industrial establishments account for the remaining 8%. Volumetrically,
residential customers account for 26% of total throughput and 35% of total
firm throughput, while commercial and industrial customers account for 74% of
total throughput and 65% of total firm throughput. In 1997, 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, accounted for approximately 44% of the commercial and
industrial local transportation throughput.
No customer, or group of customers under common control, accounted for 2% or
more of total firm revenues in 1997.
GAS SUPPLY
The following table in BCF provides statistical information with respect to
the Company's sources of supply during 1995-1997.
YEARS ENDED DECEMBER 31,
----------------------------
1997 1996 1995
-------- -------- --------
Natural gas pipeline purchased................. 80.6 91.7 93.4
Liquefied natural gas ("LNG") purchases........ 8.3 5.2 3.1
-------- -------- --------
Total purchases.............................. 88.9 96.9 96.5
Change in storage gas.......................... 2.2 (3.4) 3.5
Company use, unbilled and other................ (6.3) .9 (5.6)
-------- -------- --------
Total sales.................................. 84.8 94.4 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").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights
2
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 ("Algonquin")................ 0.28 87.4 1998-2012
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 0.66 in 1997 and 0.69 in 1996 and 1995. The
Company provides for peak period demand through a least cost portfolio of
pipeline, storage and supplemental supplies. The Company considers its peak
day send out 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, gas purchases, pipeline safety regulations, issuance of
securities, and affiliate transactions are regulated by the Department. Rates
for firm transportation and sales provided by the Company are subject to
approval by, and are on file with, the Department. In addition, the Company
has a cost of gas adjustment clause that allows for the adjustment of billing
rates for firm gas sales to enable it to recover the actual cost of gas
delivered to firm customers, including the demand charges for capacity on the
interstate pipeline system.
On May 16, 1997 the Company received a response from the Department
concerning its request for reconsideration, clarification and recalculation of
the Department's November 1996 rate order. The Department granted an
additional $1.9 million in revenues (a $6.3 million increase was granted in
the November 1996 Order) and reduced the productivity offset portion of the
Performance-Based Rate ("PBR") formula established in its November 1996 Order
by 50 basis points, from 2.00% to 1.50%. Compared to the Department's original
decision these changes will add approximately $3.5 million to projected
revenue in 1998, increasing to about $8.0 million by 2002, the last year of
the plan. The Department also made modifications to the service quality
measures requested by the Company, but left unchanged the Company's maximum
annual exposure of $5.0 million for failing to achieve them. On June 5, 1997,
the Company filed a notice of appeal of the Department's orders to the
Massachusetts Supreme Judicial Court. The Company expects that the appeal will
take approximately one year, and that any relief granted by the court will be
prospective.
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. The Department deferred the second phase
of the Company's unbundling proceeding, which is to address residential
unbundling and a permanent capacity assignment method, subject to its
assessment of the progress of the collaborative discussions.
3
On November 7, 1997, the Department approved rate schedules designed to
implement the Company's $1.8 million rate increase approved by the Department
in the Company's first annual performance-based regulatory plan compliance
proceeding.
In its November 1996 order, the Department also approved the Company's
proposal to facilitate competition in the natural gas marketplace. Under the
approved service unbundling program, on an interim basis, eligible commercial
and industrial customers migrating from firm sales to firm transportation will
be assigned, at cost, a pro-rata share of the upstream pipeline capacity
purchased by the Company to serve them. At the Department's direction,
permanent assignment of upstream pipeline capacity is currently being
addressed as part of the collaborative process discussed above. The capacity
assignment method ultimately approved by the Department could permit capacity
to be acquired by marketers at less than cost. If that proves to be the case,
there can be no assurance that the Company will be permitted to recover such
costs until the Department has addressed their recoverability. The
collaborative is also examining how to extend unbundled transportation service
to residential customers.
The Company and Eastern were granted an intrastate exemption from the
provisions of the Public Utility Holding Company Act of 1935 ("the Act") under
Section 3(a)(1) thereof, pursuant to an order of the Securities and Exchange
Commission (the "SEC") dated February 28, 1955, as amended by orders dated
November 3, 1967 and August 28, 1975.
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
12 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
EMPLOYEES
As of December 31, 1997, the Company had approximately 1,440 employees, 74%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 1999.
ITEM 2. PROPERTIES.
The Company and Mass LNG operate facilities which enable them to liquefy
natural gas in periods of low demand, store the resulting LNG and vaporize it
for use in periods of high demand. The Company owns and operates such a
facility in Dorchester, Massachusetts. Mass LNG leased one such facility
located in Lynn, Massachusetts and a storage facility in Salem, Massachusetts
under a lease that expired on June 30, 1997. Negotiations for the purchase of
the facilities stalled and the matter is now in litigation (see Item 3, Legal
Proceedings). Mass LNG continues to operate the facilities pursuant to a
stipulation and agreement between the
4
parties that provides for $2.3 million to be held in escrow and suspends Mass
LNG's rent payment obligation while the stipulation and agreement is in
effect. The stipulation and agreement terminates on the earlier of the
resolution by judgment or October 1, 1998.
The Company owns propane-air facilities at several locations throughout its
service territory.
On December 31, 1997, the Company's distribution system included
approximately 5,800 miles of gas mains, 401,000 services and 534,000 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 1997, the Company's capital expenditures were $55.4 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 $59 million for similar
purposes in 1998.
ITEM 3. LEGAL PROCEEDINGS.
On May 6, 1997, Mass LNG filed suit against the Industrial National Leasing
Corp. ("INLC") in Suffolk Superior Court, Massachusetts. This action results
from the parties' being unable to reach agreement relative to Mass LNG's
purchase rights set forth in the lease agreement under which Mass LNG leased
two LNG facilities from INLC (see Item 2, Properties). The complaint seeks a
judicial determination of the parties' rights under the lease.
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 1997.
5
GLOSSARY
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, where 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 costs.
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, 1997.
Dividends on such common equity amounted to $18.3 million and $14.7 million
for 1997 and 1996, respectively.
ITEM 6. SELECTED FINANCIAL DATA.
Not required.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
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 10 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 below.
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. The
migration of customers from firm sales to transportation-only service has no
impact on the Company's earnings. The Company earns all of its margins on the
local distribution of gas and none on the sale of the commodity itself.
During the fourth quarter of 1997, the Company recorded a non-recurring
increase in revenues of approximately $8.9 million related to a change as a
result of the 1996 rate ruling in the recovery mechanism for the portion of
bad debt expense associated with gas costs.
1996 COMPARED TO 1995
Net earnings applicable to common stock for 1996 were $29.1 million, an
increase of $5.8 million or 25% from 1995. This increase primarily reflects
colder billing temperatures, increased customer demand, and the absence of
reengineering related charges. Weather for 1996 was 4% colder than normal and
5% colder than 1995. These factors were somewhat offset by higher operating
expenses, principally wages, benefits and marketing related costs. Increased
depreciation and property tax expense reflect continued investment in system
expansion and replacement.
The reduction in interest expense reflects the refinancing during the fourth
quarter of 1995 and lower borrowing requirements.
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 $40.0 million uncommitted line of credit. The Company also
maintains a bank credit agreement which provides for the borrowing of up to
$70.0 million for
7
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 1998 to be approximately $59
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 1998 capital expenditures and working capital requirements, dividends to
shareholders and normal debt repayments. The foregoing forward-looking
statement involves risks and uncertainties. The Company's actual experience
may differ materially from its current expectation for various reasons,
including unexpected capital expenditures or working capital requirements.
Moreover, there can be no assurance that the external capital resources
currently available will continue to be available or will be available on
terms and conditions advantageous to the Company.
OTHER MATTERS
On May 16, 1997 the Company received a response from the Department
concerning its request for reconsideration, clarification and recalculation of
the Department's November 1996 rate order. The Department granted an
additional $1.9 million in revenues (a $6.3 million increase was granted in
the November 1996 Order) and reduced the productivity offset portion of the
Performance-Based Rate ("PBR") formula established in its November 1996 Order
by 50 basis points, from 2.00% to 1.50%. Compared to the Department's original
decision, these changes will add approximately $3.5 million to projected
revenue in 1998, increasing to about $8.0 million by 2002, the last year of
the plan. The Department also made modifications to the service quality
measures requested by the Company, but left unchanged the Company's maximum
annual exposure of $5.0 million for failing to achieve them. On June 5, 1997,
the Company filed a notice of appeal of the Department's orders to the
Massachusetts Supreme Judicial Court. The Company expects that the appeal will
take approximately one year, and that any relief granted by the court will be
prospective.
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. The Department deferred the second phase
of the Company's unbundling proceeding, which is to address residential
unbundling and a permanent capacity assignment method, subject to its
assessment of the progress of the collaborative discussions.
On November 7, 1997, the Department approved rate schedules designed to
implement the Company's $1.8 million rate increase approved by the Department
in the Company's first annual performance-based regulatory plan compliance
proceeding.
In its November 1996 order, the Department also approved the Company's
proposal to facilitate competition in the natural gas marketplace. Under the
approved service unbundling program, on an interim basis, eligible commercial
and industrial customers migrating from firm sales to firm transportation will
be assigned, at cost, a pro-rata share of the upstream pipeline capacity
purchased by the Company to serve them. At the Department's direction,
permanent assignment of upstream pipeline capacity is currently being
addressed as part of the collaborative process discussed above. The capacity
assignment method ultimately approved by the Department could permit capacity
to be acquired by marketers at less than cost. If this proves to be the case,
there can be no assurance that the Company will be permitted to recover such
costs until the Department has addressed their recoverability. The
restructuring collaborative is also examining how to extend unbundled
transportation service to residential customers.
The Company may have or share responsibility under applicable environmental
law for the remediation of 17 former manufactured gas plant ("MGP") sites, as
described in Note 12 of Notes to Consolidated Financial Statements. A
subsidiary of New England Electric System ("NEES") has assumed responsibility
for remediating
8
10 of these sites, subject to a limited contribution from the Company. The
Company has recorded a liability of $19.5 million, which represents its best
estimate at this time of remediation costs, which may reasonably be estimated
to range from $17 million to $31 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 $16.1 million,
representing the expected rate recovery of environmental remediation costs,
net of the insurance settlement. The Company currently believes, in light of
the indemnity agreement with the NEES subsidiary and the Department rate order
on environmental cost recovery, that it is not probable that such costs will
materially affect its financial condition or results of operations.
The Company has assessed the impact of the year 2000 with respect to its
information systems and is currently modifying those systems as part of a plan
which the Company believes will provide year 2000 compliance. Anticipated
spending for these modifications is being expensed as incurred and is not
expected to have a material impact on operating results or financial
condition.
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.
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.
9
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).*
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
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).*
10.10 --Storage Service Agreement between the Company and Distrigas of
Massachusetts Corporation dated as of December 17, 1988 (Filed as
Exhibit 10.13 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1989).*
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).*
10.13 --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 herewith).
10.16 --Gas Transportation Contract between the Company and Algonquin dated
September 1, 1994 providing for transportation of approximately 80,000
dekatherms of natural gas per day (Filed herewith).
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 herewith).
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 herewith).
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 herewith).
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 herewith).
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 herewith).
10.22 --Amendment to Exhibits 10.4 and 10.5, combining gas transportation
contracts between the Company and Algonquin (Filed herewith).
11
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 herewith).
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 herewith).
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
herewith).
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 herewith).
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 herewith).
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 herewith).
10.29 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 70,000 dekatherms of natural gas per day (Filed
herewith).
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 herewith).
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 herewith).
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
herewith).
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
herewith).
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
herewith).
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 herewith).
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
herewith).
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 herewith).
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
herewith).
12
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 herewith).
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 herewith).
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
herewith).
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).*
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.
There were no reports on Form 8-K filed in the Fourth Quarter of 1997.
- --------
* 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.
13
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
By: /s/ J.F. Bodanza
-----------------------------------
J.F. BODANZA
SENIOR VICE PRESIDENT AND TREASURER
(PRINCIPAL FINANCIAL AND
ACCOUNTING OFFICER)
Dated:
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 2ND DAY OF MARCH 1998.
SIGNATURE TITLE
--------- -----
C. R. Messer Director and
- ------------------------------------- President
C. R. MESSER
A. J. DiGiovanni Director and Senior Vice
- ------------------------------------- President
A. J. DIGIOVANNI
J. F. Bodanza Director and Senior Vice President
- ------------------------------------- andTreasurer (Principal Financial
J. F. BODANZA andAccounting Officer)
J. A. Ives Director
- -------------------------------------
J. A. IVES
R. R. Clayton Director
- -------------------------------------
R. R. CLAYTON
W. J. Flaherty Director
- -------------------------------------
W. J. FLAHERTY
14
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, 1997 and 1996.... F-2 and F-3
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1997.............................................. F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1997........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1997.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-16
Interim Financial Information for the Two Years Ended December
31, 1997 (Unaudited)........................................... F-18
Schedules for the Three Years Ended December 31, 1997:
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,
-----------------
1997 1996
-------- --------
(IN THOUSANDS)
Gas plant, at cost........................................... $866,784 $812,114
Construction work-in-progress................................ 2,715 4,604
Less--Accumulated depreciation............................. 329,918 290,492
-------- --------
Net plant.................................................. 539,581 526,226
Current assets:
Cash....................................................... 307 1,474
Accounts receivable, less reserves of $15,783 at December
31, 1997 and $15,963 at December 31, 1996................. 89,859 76,832
Deferred gas costs......................................... 66,595 75,337
Natural gas and other inventories, at average cost......... 44,590 49,287
Materials and supplies, at average cost.................... 3,316 3,809
Prepaid expenses........................................... 1,777 2,759
Income taxes............................................... -- 10,411
-------- --------
Total current assets..................................... 206,444 219,909
Other assets:
Deferred postretirement benefits cost...................... 83,926 88,563
Deferred charges and other assets.......................... 48,206 42,346
-------- --------
Total other assets....................................... 132,132 130,909
-------- --------
Total assets............................................. $878,157 $877,044
======== ========
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,
-----------------
1997 1996
-------- --------
(IN THOUSANDS)
Capitalization:
Common stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1997 and 1996............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 152,312 133,980
-------- --------
Total common stockholder's investment.................... 246,963 228,631
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized and outstanding--1,200,000 shares at December
31, 1997 and 1996......................................... 29,326 29,293
Long-term obligations, less current portion................. 211,236 211,743
-------- --------
Total capitalization..................................... 487,525 469,667
Gas inventory financing..................................... 55,502 55,594
-------- --------
Total capitalization and gas inventory financing......... 543,027 525,261
Current liabilities:
Current portion of long-term obligations................... 507 1,029
Notes payable.............................................. 39,700 57,000
Accounts payable........................................... 61,931 73,313
Accrued taxes.............................................. 1,392 1,206
Accrued income taxes....................................... 11,174 --
Accrued interest........................................... 4,372 4,339
Customer deposits.......................................... 2,360 2,382
Refunds due customers...................................... 3,136 3,384
Pipeline transition costs.................................. -- 16,494
-------- --------
Total current liabilities................................ 124,572 159,147
Reserves and deferred credits:
Deferred income taxes...................................... 79,128 76,277
Unamortized investment tax credits......................... 5,931 6,836
Postretirement benefits obligation......................... 83,274 84,827
Other...................................................... 42,225 24,696
-------- --------
Total reserves and deferred credits...................... 210,558 192,636
-------- --------
Total liabilities and stockholder's investment........... $878,157 $877,044
======== ========
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,
----------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
Operating revenues................................ $700,945 $705,462 $653,073
Cost of gas sold.................................. 398,566 414,254 374,904
-------- -------- --------
Operating margin.................................. 302,379 291,208 278,169
-------- -------- --------
Operating expenses:
Other operating expenses........................ 148,487 156,105 156,794
Maintenance..................................... 22,017 25,045 21,449
Depreciation and amortization................... 44,413 41,607 38,264
Income taxes.................................... 22,510 20,017 16,258
Restructuring charge............................ 8,692 -- --
-------- -------- --------
Total operating expenses........................ 246,119 242,774 232,765
-------- -------- --------
Operating earnings................................ 56,260 48,434 45,404
Other earnings, net............................... 298 564 726
-------- -------- --------
Earnings before interest expense.................. 56,558 48,998 46,130
-------- -------- --------
Interest expense:
Long-term debt.................................. 16,767 16,769 18,633
Other, including amortization of debt expense... 1,889 1,688 2,693
Less--Interest during construction.............. (609) (525) (499)
-------- -------- --------
Total interest expense.......................... 18,047 17,932 20,827
-------- -------- --------
Net earnings...................................... 38,511 31,066 25,303
Preferred stock dividends......................... 1,926 1,926 1,926
-------- -------- --------
Net earnings applicable to common stock........... $ 36,585 $ 29,140 $ 23,377
======== ======== ========
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,
----------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
Balance at beginning of year..................... $133,980 $119,546 $108,098
Net earnings................................... 38,511 31,066 25,303
Preferred stock dividends ($1.61 per share in
1997, 1996
and 1995)..................................... (1,926) (1,926) (1,926)
Cash dividends on common stock ($35.50 per
share in 1997, $28.60 per share in 1996, and
$23.20 per share in 1995)..................... (18,253) (14,706) (11,929)
-------- -------- --------
Balance at end of year........................... $152,312 $133,980 $119,546
======== ======== ========
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,
----------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
Cash flows from operating activities:
Net earnings.................................... $ 38,511 $ 31,066 $ 25,303
Adjustments to reconcile net earnings to cash
provided by operating activities:
Depreciation and amortization.................. 44,413 41,607 38,264
Deferred taxes................................. 2,851 4,276 5,424
Other changes in assets and liabilities:
Accounts receivable........................... (13,027) (2,313) (3,111)
Inventory..................................... 5,190 (13,190) 12,001
Deferred gas costs............................ 8,742 (3,397) 17,763
Accounts payable.............................. (11,382) 19,823 10,837
Federal and state income taxes................ 21,585 (10,043) 1,039
Refunds due customers......................... (248) (9,789) (5,546)
Other......................................... 4,177 (2,543) (969)
-------- -------- --------
Cash provided by operating activities............ 100,812 55,497 101,005
-------- -------- --------
Cash flows from investing activities:
Capital expenditures........................... (55,388) (58,504) (57,322)
Net cost of removal............................ (4,683) (4,124) (6,463)
-------- -------- --------
Cash used by investing activities................ (60,071) (62,628) (63,785)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. (17,300) 5,000 (10,530)
Changes in inventory financing................. (92) 9,994 (7,978)
Proceeds from issuance of long-term debt....... -- -- 60,000
Repayment of long-term debt.................... -- -- (62,880)
Amortization of preferred stock issuance
costs......................................... 34 31 33
Cash dividends paid on common and preferred
stock......................................... (24,550) (12,261) (13,855)
-------- -------- --------
Cash provided (used) by financing activities..... (41,908) 2,764 (35,210)
-------- -------- --------
Increase (decrease) in cash...................... (1,167) (4,367) 2,010
Cash at beginning of year........................ 1,474 5,841 3,831
-------- -------- --------
Cash at end of year.............................. $ 307 $ 1,474 $ 5,841
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 19,704 $ 18,960 $ 20,752
Income taxes.................................. $ 900 $ 26,205 $ 10,128
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
ratemaking 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--Pension Benefits
Note 7--Postretirement Benefits Other Than Pensions
Note 8--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 statutes applicable to
gas utilities. Its revenues, earnings and cash flows are highly seasonal, as
most of its throughput is directly related to temperature levels.
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 regulation. The Company has reviewed these criteria and believes that
the continuing application of SFAS 71 is appropriate.
Regulatory assets have been established that represent probable future
revenue to the Company associated with certain costs that will be recovered
from customers through the ratemaking process. Regulatory liabilities
represent probable future reductions in revenues associated with the amounts
that are to be credited to customers through the ratemaking process.
F-7
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(1) ACCOUNTING POLICIES (CONTINUED)
The following regulatory assets were reflected in the Consolidated Balance
Sheets as of December 31:
1997 1996
-------- --------
(IN THOUSANDS)
Postretirement benefit costs........................... $ 83,926 $ 88,563
Deferred pipeline transition costs..................... -- 16,494
Environmental costs.................................... 18,852 2,784
Other.................................................. 1,998 2,225
-------- --------
$104,776 $110,066
======== ========
Regulatory liabilities total approximately $10,371,000 and $11,446,000 at
December 31, 1997 and 1996 and relate primarily to income taxes.
As of December 31, 1997 all of the Company's regulatory assets and
regulatory liabilities are being reflected in rates charged to customers over
periods ranging from 1 to 22 years. For additional information regarding
deferred income taxes, postretirement benefit costs, environmental costs and
Order 636 transition costs, see footnotes 3, 7, 12 and 13, respectively.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 121 ("SFAS 121") "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" which became effective for 1996, establishes accounting standards
for the impairment of long-lived assets. SFAS 121 also requires that
regulatory assets that are no longer probable of recovery through future
revenues be charged to earnings. SFAS 121 did not have an impact on the
Company's financial position or results of operations in 1997 and 1996.
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 5.19% in 1997, 5.15% in 1996
and 5.13% in 1995.
Accumulated depreciation is charged with the original cost and 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
Gas operating revenues are recorded when billed. Revenue is not recorded for
the amount of gas distributed to customers, which is unbilled at the end of
the period; however, the cost of this gas is deferred as discussed in Note 2.
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause ("CGAC") requires the Company to adjust
its rates semi-annually for firm gas sales in order to track changes in the
cost of gas distributed with an annual adjustment of subsequent rates for any
collection over or under 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 1996 Rate Order"), the Department
modified the CGAC to
F-8
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS (CONTINUED)
recover the gas cost portion of the Company's bad debt write-offs effective
December 1, 1996. The order also granted 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 36.9%
in 1997, which includes the effect of 1.8% related to prior years tax
benefits, 39.2% in 1996 and 39.1% in 1995. State taxes represent the majority
of the difference between the effective rate and the Federal income tax rate
for 1997, 1996 and 1995.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
1997 1996 1995
------- ------- -------
(IN THOUSANDS)
Current--
Federal........................................... $11,670 $10,154 $10,603
State............................................. 2,692 2,004 2,136
------- ------- -------
Total current provision......................... 14,362 12,158 12,739
Deferred--
Federal........................................... 6,998 6,489 2,896
State............................................. 1,150 1,370 623
------- ------- -------
Total deferred provision........................ 8,148 7,859 3,519
------- ------- -------
Provision for income taxes.......................... $22,510 $20,017 $16,258
======= ======= =======
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, 1997 the Company has a regulatory liability of $3,255,000
which represents the tax benefit of unamortized investment tax credits. This
benefit is being passed on 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
$7,116,000 as of December 31, 1997.
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, 1997 and 1996 are as follows:
F-9
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(3) INCOME TAXES (CONTINUED)
1997 1996
--------- ---------
(IN THOUSANDS)
ASSETS:
Unbilled revenues................................ $ 17,513 $ 22,392
Reserve for uncollectible receivables............ -- 6,261
Regulatory liabilities........................... 4,125 4,490
Other............................................ 15,086 8,925
--------- ---------
Total deferred tax assets........................ $ 36,724 $ 42,068
========= =========
LIABILITIES:
Accelerated depreciation......................... $ (84,049) $ (80,894)
Deferred gas costs............................... (27,418) (28,684)
Other............................................ (14,090) (12,932)
--------- ---------
Total deferred tax liabilities................... $(125,557) $(122,510)
--------- ---------
Total net deferred taxes......................... $ (88,833) $ (80,442)
========= =========
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 $906,000 in 1997, $931,000 in 1996, and $937,000 in 1995.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
DECEMBER 31,
------------------
1997 1996
-------- --------
(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 8).................... 1,743 2,772
Less current portion.................................. (507) (1,029)
-------- --------
$211,236 $211,743
======== ========
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, 1997 and
none are callable prior to maturity.
Annual maturities of capital lease obligations are $507,000, $561,000,
$620,000 and $55,000 for 1998 through 2001, respectively.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department effective
October 1, 1988, the Company funds its inventory of gas supplies through
external sources. All costs related to this funding are recoverable
F-10
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(4) COMMITMENTS (CONTINUED)
from its 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 $55,502,000 and
$55,594,000 of commercial paper outstanding to fund its inventory of gas
supplies at December 31, 1997 and 1996, 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 1/12 of 1% on the
commitment. No borrowings were outstanding under this agreement during 1997
and 1996.
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 $39,700,000 and $57,000,000 in
commercial paper not related to gas inventory financing at December 31, 1997
and 1996, respectively. The weighted average interest rate on these borrowings
was 6.19% at December 31, 1997 and 5.99% at December 31, 1996.
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, 1998. 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, 1997 and
1996.
(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. The preferred
stock is not callable prior to 2003.
(6) PENSION BENEFITS
The Company, through retirement plans under collective bargaining agreements
and participation in Eastern's pension plans, provides retirement benefits for
substantially all of its employees. The benefits under these plans are based
on stated amounts for years of service or employee's average compensation
during the five years prior to retirement. The Company follows a policy of
funding retirement and employee benefit plans in accordance with the
requirements of the plans and agreements in sufficient amounts to satisfy the
"Minimum Funding Standards" of the Employee Retirement Income Security Act of
1974 ("ERISA").
Net pension cost included the following components:
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
Service cost-benefits earned during the
year........................................ $ 2,838 $ 2,883 $ 2,710
Interest cost on projected benefit obliga-
tion........................................ 8,632 8,492 8,055
Actual return on plan assets................. (38,975) (11,727) (21,762)
Net amortization and deferral................ 29,005 3,225 13,773
-------- -------- --------
Net pension cost............................. $ 1,500 $ 2,873 $ 2,776
======== ======== ========
F-11
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(6) PENSION BENEFITS (CONTINUED)
For the periods 1997 and 1996, the expected long-term rate of return on
assets was 8.5% and the discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.5%. The rate of
increase in future compensation levels was 4.75%-5.0% for 1997 and 1996.
The following table sets forth the funded status of pension plans and
amounts recognized in the Company's consolidated balance sheets based on a
measurement date of October 1.
1997 1996
-------- --------
(IN THOUSANDS)
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $96,965 in 1997 and $97,180 in 1996..... $105,569 $106,180
======== ========
Projected benefit obligation for service rendered to
date................................................ (115,945) (117,729)
Plan assets at fair value, primarily listed stocks,
corporate bonds and U.S. bonds...................... 165,857 139,887
-------- --------
Plan assets in excess of projected benefit
obligation.......................................... 49,912 22,158
Unrecognized net obligation at January 1, 1986 being
recognized over 15 years............................ 654 871
Unrecognized net gain................................ (52,805) (26,820)
Unrecognized prior service cost...................... 10,903 11,952
-------- --------
Net pension asset.................................... $ 8,664 $ 8,161
======== ========
(7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company, through
participation in Eastern-administered plans and welfare plans under collective
bargaining agreements, provides certain health care and life insurance
benefits for retired employees. The expected cost of postretirement benefits
other than pensions is charged to expense during the period of the employee's
service. As of the date of adoption of Statement of Financial Accounting
Standards No. 106 ("SFAS 106"), "Employers Accounting for Postretirement
Benefits Other Than Pensions", the cumulative effect of the accounting change
("transition obligation") was $89,120,000. The 1996 Rate Order allowed
recovery of SFAS 106 costs, which includes current SFAS 106 expense and the
amortization of the regulatory asset related to the transition obligation.
Net postretirement benefit costs included the following components:
1997 1996 1995
------- ------- -------
(IN THOUSANDS)
Service cost-benefits earned during the year.... $ 789 $ 779 $ 729
Interest cost on accumulated benefit obliga-
tion........................................... 5,704 5,749 5,645
Net amortization and deferral of actuarial gains
and losses..................................... 2,761 (1,448) (4,752)
Actual return on plan assets.................... (5,958) (1,355) 2,352
------- ------- -------
Postretirement benefit cost..................... 3,296 3,725 3,974
Amortization of regulatory asset................ 4,637 5,266 3,760
------- ------- -------
Net postretirement benefit cost................. $ 7,933 $ 8,991 $ 7,734
======= ======= =======
F-12
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED)
The following table sets forth the funded status of the plans and amounts
recognized in the Company's consolidated balance sheets based on a measurement
date of October 1.
1997 1996
-------- --------
(IN THOUSANDS)
Retirees............................................... $(58,800) $(58,131)
Other fully eligible participants...................... (4,725) (5,728)
Other active participants.............................. (15,275) (15,083)
-------- --------
(78,800) (78,942)
Plan assets at fair value.............................. 23,877 17,918
-------- --------
Accumulated postretirement benefits obligation in ex-
cess of plan assets................................... (54,923) (61,024)
Unrecognized actuarial gain............................ (18,324) (12,586)
Unrecognized prior service benefits.................... (10,027) (11,217)
-------- --------
Accrued postretirement benefits........................ $(83,274) $(84,827)
======== ========
The Company established a 501(c) (9) Voluntary Employee Beneficiary
Association ("VEBA") Trust in 1991 to begin funding its postretirement benefit
obligation for collectively bargained employees. Plan assets are invested in
equity securities, fixed-income investments and money market instruments.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.5% in 1997 and 1996. A 7% annual
increase in the cost of covered health care benefits was assumed for 1997 and
1996. This rate of increase is assumed to remain at 7% through 1999 and
decrease to 6% in 2000 and 5% thereafter. A 1% increase in the assumed health
care cost trend would have increased the postretirement benefit cost by
$382,000 in 1997 and $536,000 in 1996, and the accumulated postretirement
benefit obligation by $4,258,000 in 1997 and $6,253,000 in 1996.
(8) LEASES
The Company and its subsidiary lease 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
$10,112,000 in 1997, $8,418,000 in 1996 and $8,826,000 in 1995.
The Company capitalizes its financing leases, which include liquefied
natural gas facilities and an operations center. The lease for the liquefied
natural gas facilities in Lynn and Salem expired June 30, 1997. On May 6, 1997
the Company filed a civil suit to determine its purchase rights under the
lease. Pending the court's decision or a negotiated outcome, the parties have
agreed that the Company will continue to operate and maintain the facilities.
A summary of property held under capital leases as of December 31 is as
follows:
1997 1996
------- -------
(IN THOUSANDS)
LNG facilities.............................................. $15,600 $15,600
Buildings................................................... 6,000 6,000
------- -------
21,600 21,600
Less-Accumulated depreciation............................... 19,857 18,828
------- -------
Total Capital Leases.................................... $ 1,743 $ 2,772
======= =======
F-13
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(8) LEASES (CONTINUED)
Under the terms of SFAS 71, the timing of expense recognition on capitalized
leases should conform 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.
The Company also has various operating lease agreements for office
facilities and other equipment. The remaining minimum rental commitments for
these and all other noncancelable leases, including the financing leases, at
December 31, 1997 is as follows:
CAPITAL OPERATING
YEAR LEASES LEASES
---- ------- ---------
(IN THOUSANDS)
1998..................................................... $ 684 $ 4,937
1999..................................................... 686 3,792
2000..................................................... 687 2,493
2001..................................................... 57 1,488
2002..................................................... -- 923
Later Years.............................................. -- 233
------ -------
Total minimum lease payments............................. $2,114 $13,866
====== =======
Less-Amount representing interest and executory costs.... 371
------
Present value of minimum lease payments on capital
leases.................................................. $1,743
======
(9) 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 1997 and 1996 is based on
currently quoted market prices.
F-14
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS (CONTINUED)
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1997 and 1996 are as follows:
1997 1996
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS) (IN THOUSANDS)
Cash........................................ $ 307 $ 307 $ 1,474 $ 1,474
Short-term debt............................. $ 95,202 $ 95,202 $112,594 $112,594
Long-term debt.............................. $211,743 $236,743 $212,772 $223,001
Preferred stock............................. $ 29,326 $ 31,525 $ 29,293 $ 29,586
(10) RESTRUCTURING CHARGE
During the fourth quarter of 1997, the Company recorded a restructuring
charge of $8.7 million related to its decision to exit the gas appliance
repair and service business. The charge includes $5.4 million for employee
severance and termination benefits associated with the elimination of
approximately 130 bargaining unit and management positions. The remaining $3.3
million relates to the disposition of assets, the cancellation of lease
obligations, communications, legal and other related costs. The Company
expects the restructuring plan to be complete by the end of 1998. The
restructuring charge is reported as a component of operating expenses in the
consolidated statement of earnings.
(11) RELATED PARTY TRANSACTIONS
The Company paid Eastern $4,300,000 in 1997, $4,048,000 in 1996, and
$4,117,000 in 1995 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 1997
the Company paid $752,000 to Eastern Rivermoor Company, Inc.
During 1996, Eastern entered into a joint venture with New England Electric
System ("NEES") to form AllEnergy Marketing Company, L.L.P., a new unregulated
energy marketing company. In the fourth quarter of 1997, Eastern sold its
interest to NEES. During 1997 and 1996, AllEnergy purchased gas from the
Company at prices and terms equivalent to those used in transacting business
with unrelated parties and totalled approximately $163,000 and $2,764,000,
respectively.
(12) 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 17
such sites. A subsidiary of New England Electric System ("NEES") has assumed
responsibility for remediating 10 of these sites, subject to a limited
contribution from the Company. The Company has estimated its potential share
of the costs of investigating and remediating former MGP sites 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 $19.5 million, which represents its best
estimate at this time of remediation costs, which may reasonably be estimated
to range from $17 million to $31 million. However, there can be no assurance
that such
F-15
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(12) ENVIRONMENTAL ISSUES (CONTINUED)
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
environmental expense indemnity, and a regulatory asset of $16.1 million,
representing the expected rate recovery of environmental remediation costs,
net of the insurance settlement. The Company currently believes, in light of
the indemnity agreement with the NEES subsidiary and the Department rate order
on environmental cost recovery, that it is not probable that such costs will
materially affect its financial condition or results of operations.
(13) PIPELINE TRANSITION COSTS
Pursuant to FERC Order 636, pipelines were permitted to recover prudently
incurred transition costs, including (1) gas supply realignment costs or the
costs of renegotiating existing gas supply contracts with producers; (2)
unrecovered purchased gas adjustment costs or unrecovered gas costs at the
time the pipelines ceased the merchant function; (3) stranded costs or the
unrecovered costs of assets that cannot be assigned to customers of unbundled
services; and (4) new facilities costs or the costs of new facilities required
to physically implement the order.
On March 8, 1995 the Department issued an order allowing for the recovery of
the Company's transition cost liability from customers. During 1997, the
Company's remaining obligation for transition cost liability was settled by
applying pipeline rate case refunds against such obligation.
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, 1997 and 1996, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1997. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Boston Gas
Company and subsidiary as of December 31, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1997, 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.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
January 22, 1998
F-17
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION
FOR THE TWO YEARS ENDED DECEMBER 31, 1997 (UNAUDITED)
The following table summarizes the Company's reported quarterly information
for the years ended December 31, 1997 and 1996:
THREE MONTHS ENDED
------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- --------
(IN THOUSANDS)
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
1996
Operating revenues....................... $343,341 $136,520 $59,453 $166,148
Operating margin......................... $122,174 $ 59,309 $34,733 $ 74,992
Operating earnings (loss)................ $ 30,334 $ 6,339 $(3,758) $ 15,519
Net earnings (loss) applicable to common
stock................................... $ 25,021 $ 1,842 $(8,161) $ 10,438
F-18
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED 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
-------- ------- ------- ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... $ 2,240 $ 2,461 $ -- $ 1,831 $ 2,870
SFAS 109 Regulatory
Liability........... 3,839 -- -- 584 3,255
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 $10,593 $23,155 $15,826 $210,558
======== ======= ======= ======= ========
F-19
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED 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-20
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1995
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1994 TO INCOME ACCOUNTS RESERVES 1995
----------- ------------ --------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............. $ 15,621 $14,500 $ -- $14,797 $ 15,324
======== ======= ====== ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes......... $ 66,577 $ 2,985 $2,439 $ -- $ 72,001
-------- ------- ------ ------- --------
Deferred investment
tax credits.......... $ 8,704 $ (937) $ -- $ -- $ 7,767
-------- ------- ------ ------- --------
Postretirement benefit
cost................. $ 90,214 $ 3,975 $ -- $ 7,600 $ 86,589
-------- ------- ------ ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... $ 2,258 $ 1,739 $ -- $ 1,650 $ 2,347
SFAS 109 Regulatory
Liability........... 5,045 -- -- 605 4,440
Deferred net
normalization
surplus............. 8,296 -- -- 345 7,951
Other................ 6,068 6,955 1,521 5,424 9,120
-------- ------- ------ ------- --------
Total other reserves
and deferred
credits............ $ 21,667 $ 8,694 $1,521 $ 8,024 $ 23,858
-------- ------- ------ ------- --------
Total reserves not
deducted from
assets............. $187,162 $14,717 $3,960 $15,624 $190,215
======== ======= ====== ======= ========
F-21