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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(MARK ONE)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
- --- ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
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
BOSTON, MASSACHUSETTS 02108 (617) 742-8400
(ADDRESS OF PRINCIPAL EXECUTIVE (REGISTRANT'S TELEPHONE NUMBER)
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
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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. Yes X No
--- ---
Indicate the number of shares outstanding of the registrant's class of common
stock as of March 10, 1995.
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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BOSTON GAS COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1994
PART I
ITEM 1. BUSINESS.
General
Boston Gas Company (the "Company") is engaged in the transportation,
distribution and sale of natural gas to residential, commercial, and industrial
customers in Boston, Massachusetts, and 73 other communities in eastern and
central Massachusetts. The Company also sells gas for resale in Massachusetts
and other states (see "Competition" section). The Company has one subsidiary,
Massachusetts LNG Incorporated ("Mass LNG") which holds a long-term lease on
two liquefied natural gas ("LNG") facilities. Boston Gas is the largest natural
gas distribution company in New England, has been in business for 172 years and
is the second oldest gas company in the United States. Since 1929, all of the
common stock of the Company has been owned by Eastern Enterprises ("Eastern"),
which is headquartered in Weston, Massachusetts.
GAS SALES AND TRANSPORTATION
Gas is sold and transported for "firm" and "non-firm" customers. Principal
uses of natural gas include central, space and water heating, cooking, drying,
steam generation and a variety of industrial applications.
"Firm" sales and transportation services are generally provided without
interruption throughout the year, although uninterrupted seasonal services are
available to firm customers for periods of less than 365 days. Firm services
are provided under either filed rate schedules or through individually
negotiated contracts. Firm sales and transportation of natural gas used for
central or space heating are directly related to weather conditions.
Consequently, temperature variations can have a significant impact, both
favorable and unfavorable, upon the Company's revenues and earnings. Compared
to normal, actual billing temperatures were 1% colder, 1% warmer and 4% colder
in 1994, 1993 and 1992, respectively.
"Non-firm" sales and transportation services are generally provided to large
commercial and industrial customers who can use gas and oil interchangeably or
to other gas distribution utilities for resale. Non-firm services are dependent
upon a number of factors, including the price of gas compared to competing
fuels, gas supply availability, weather conditions and system capacity, both
local and interstate. Non-firm services are provided through individually
negotiated contracts and, in most cases, the price charged takes into account
the price of the customer's alternative fuel, which is generally residual fuel
oil. Beginning November 1, 1993, gross margin from non-firm sales and
transportation services ($10.9 million in 1994 and $8.2 million in 1993) in
excess of a threshold based upon the prior season's experience are shared
between firm customers and shareholders, 75% and 25%, respectively.
The following table provides information with respect to the volumes of gas
sold and transported by the Company during the three years 1992-1994. The table
is in billions of cubic feet ("BCF") of natural gas at 1,000 B.T.U. per cubic
foot.
YEARS ENDED DECEMBER 31,
--------------------------
1994 1993 1992
-------- -------- --------
Firm Sales and Transportation
Residential Heating................................ 37.8 38.1 37.9
Residential Non-Heating............................ 3.6 3.8 3.9
Commercial......................................... 25.1 26.0 25.8
Industrial......................................... 4.8 5.0 4.9
Seasonal Firm Contracts............................ 10.4 10.0 6.4
-------- -------- --------
Total Firm Sales................................. 81.7 82.9 78.9
Firm Transportation.............................. 13.8 12.4 7.4
-------- -------- --------
Total Firm Throughput.......................... 95.5 95.3 86.3
-------- -------- --------
Non-Firm Sales and Transportation
Interruptible...................................... 6.4 8.1 14.5
Special Sales for Resale........................... 7.6 2.1 4.2
-------- -------- --------
Total Non-Firm Sales............................. 14.0 10.2 18.7
Non-Firm Transportation.......................... 34.9 39.3 27.3
-------- -------- --------
Total Non-Firm Throughput...................... 48.9 49.5 46.0
-------- -------- --------
Total Throughput..................................... 144.4 144.8 132.3
======== ======== ========
Residential heating sales include all gas sold to customers having central or
space heating. Commercial sales include all gas sold to retail establishments
and commercial properties including central-metered apartment houses and
condominiums with five or more units. Growth in the Company's firm
transportation services reflects changes in the gas industry (see "Gas Supply"
and "Competition" sections).
The Company's operations are subject to Massachusetts statues applicable to
gas utilities as described in the "Regulation" section. Facility expansion is
regulated by the Massachusetts Department of Public Utilities (the
"Department"). Municipal, state and federal authorities have jurisdiction over
the use of public ways, land and waters for gas mains and other distribution
facilities.
GAS SUPPLY
The following table provides statistical information with respect to the
Company's sources of supply during 1992-1994. The table is in BCF of natural
gas at 1,000 B.T.U. per cubic foot.
YEARS ENDED DECEMBER 31,
------------------------
1994 1993 1992
-------- -------- --------
Natural gas purchased............................... 92.2 86.3 94.1
LNG Purchases....................................... 4.2 13.4 12.4
------- ------- --------
Total Purchases................................... 96.4 99.7 106.5
Change in Storage Gas............................... 4.5 (4.0) (5.2)
Company Use, Unbilled and Other..................... (5.2) (2.6) (3.7)
------- ------- --------
Total Sales....................................... 95.7 93.1 97.6
======= ======= ========
The Company purchases approximately 70% of its pipeline gas supplies directly
from domestic and Canadian producers and marketers pursuant to long-term
contracts which have been reviewed and approved by the Department. The Company
purchases its remaining pipeline supplies from domestic sources pursuant
2
to short-term, firm winter service agreements and on a spot basis. The Company
has diversified its pipeline gas supplies across major North American producing
regions, including on and off-shore Gulf of Mexico and mid-continent areas in
the United States, as well as from western Canada.
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to transportation agreements approved by
the Federal Energy Regulatory Commission ("FERC"). The Company has also
contracted with pipeline companies and others for the storage of natural gas
and related transportation services from underground storage fields located in
West Virginia, New York and Pennsylvania. Supplemental supplies of LNG and
propane are purchased and produced from foreign and domestic sources.
All interstate pipelines serving the Company have implemented service
restructuring plans on terms and conditions approved by FERC pursuant to its
Order No. 636. Order No. 636, issued April 8, 1992, required interstate
pipeline companies to unbundle gas sales contracts into separate gas sales,
transportation and storage services. Accordingly, the Company's firm bundled
service with Algonquin Gas Transmission Company ("Algonquin"), a wholly-owned
subsidiary of Texas Eastern Transmission Corporation ("Texas Eastern"), was
converted to an annual firm transportation entitlement of 87.4 BCF. Similarly,
the Company's firm bundled sales service with Texas Eastern has been converted
into an annual firm transportation entitlement of 102.3 BCF; and its firm
bundled sales service with Tennessee Gas Pipeline Company, ("Tennessee") has
been converted to an annual transportation and storage entitlement of 79.4 BCF.
In addition, the Company has firm entitlements on interstate pipelines upstream
of Tennessee, Texas Eastern, and Algonquin, with direct access to supply areas.
Together, these transportation entitlements are used to transport natural gas
purchased by the Company from producing regions described above and from
underground storage facilities to its service territory. The Company holds
direct entitlements to 17.2 BCF of storage capacity with Tennessee, Texas
Eastern and others. The underlying transportation and storage agreements with
Algonquin, Texas Eastern, and Tennessee have terms generally expiring no
earlier than November 1996, April 2012, and November 2000, respectively. The
Company is provided rights of first refusal under Order No. 636 to extend the
terms of the majority of these transportation and storage contracts. The
Company considers the service reliability of its natural gas portfolio to be
comparable to that existing prior to Order No. 636.
In addition to its domestic supply arrangements, the Company has three
contracts for the purchase of Canadian gas supplies. The Company's contract
with Boundary, Inc. provides for the purchase of 3.8 BCF of gas annually and
expires on January 2003. The Company also has contracts with Alberta Northeast
Gas, Ltd. to purchase up to 4.8 BCF of gas annually, and with Imperial Oil of
Canada, Ltd. for the purchase of 12.8 BCF of gas annually. These contracts
expire on November 2003 and April 2007, respectively. The Company has
contracted with Iroquois Gas Transmission System, Tennessee and Algonquin to
transport these gas supplies from the Canadian border to delivery points in the
Company's service territory.
The Company has contracts, expiring in 1998, with Distrigas of Massachusetts
Corporation ("DOMAC") for the purchase of an annual quantity of up to 2.0 BCF
of LNG and for 1.0 BCF of LNG storage capacity and related vaporization
services. The Company also purchases LNG from DOMAC on a spot basis when prices
are competitive with alternative supplies. DOMAC's affiliate, Distrigas
Corporation, imports the LNG from Algeria pursuant to agreements with
Sonatrach, the Algerian National Energy Company.
The Company relies on supplemental supplies of storage gas, LNG and propane
to meet firm sendout requirements which are greater than its firm pipeline
capacity entitlements. The number of days that peak sendout can be maintained
is limited by the capacity of the Company's storage facilities for supplemental
gas supplies and the rate at which these supplies can be sent out and
subsequently replenished. The Company owns or leases facilities which enable it
to store the equivalent of 4.6 BCF of natural gas in liquid form as LNG and
vaporize it for use during periods of high demand. The inventory for these
facilities is provided by liquefaction of pipeline gas and from purchased LNG.
Over the past five years, increased pipeline capacity has reduced the Company's
dependence on these more costly supplemental supplies. The Company considers
3
its peak day sendout capability, based on its total supply resources, adequate
to meet the requirements of its firm customers.
REGULATION
The Company's operations are subject to Massachusetts statutes applicable to
gas utilities. Rates, the territorial limit of the Company's service area,
purchase of gas, pipeline safety regulations, issuance of securities and
affiliated party transactions are regulated by the Department. Rates for firm
sales and transportation 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 which 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.
On October 30, 1993, the Department allowed the Company an annual revenue
increase of $37.7 million, effective November 1, 1993, and also approved
several rate design changes that reduce the volatility of its margins
attributable to weather. The Department also ordered a four-year phase in of
postretirement benefits other than pensions. The Company began billing the
second year phase-in on November 1, 1994.
Changes stemming from FERC Order 636 are being considered at state levels.
The Department has initiated a proceeding to review alternative regulatory
approaches, including regulation that is incentive or performance based.
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. On February 7, 1989, the SEC issued a
proposed rule under the Act which would provide limits for non-utility related
diversification by intrastate public utility holding companies, such as
Eastern, that are exempt under the Act. Since its proposal in 1989, the SEC has
taken no action with respect to this proposed rule. Eastern and the Company
cannot predict whether this proposed rule will be adopted or whether it will
affect their exemption under the Act.
SEASONALITY AND WORKING CAPITAL
The Company's revenues, earnings and cash flow are highly seasonal as most of
its firm sales and transportation 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 bulk 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 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 results in
short-term borrowings. Short-term borrowings are also required from time to
time to finance normal business operations. As a result of all factors, short-
term borrowings are generally highest during the late fall and early winter.
COMPETITION
The Company competes with suppliers of fuel oil and electricity for
residential, commercial and industrial customers. In addition, the Company
faces competition from other suppliers of natural gas for large commercial and
industrial applications. The Company's marketing efforts emphasize the
continuing environmental benefits of natural gas, together with its reliability
and long-term economic value as compared to oil and electricity. The clean
burning nature of natural gas combustion and the absence of on-site fuel
storage problems are major environmental advantages for natural gas.
The Company increased annualized firm throughput by an estimated 3.8 BCF
during 1994 through volume additions of 2.3 BCF in the firm residential and
commercial/industrial markets and additions of 1.5 BCF through special
contracts and transportation arrangements.
4
Increased activity in new residential construction, together with the
accelerated marketing efforts to encourage conversion to natural gas, resulted
in the addition of 5,300 residential heating customers. Approximately 45% of
the Company's existing residential customers do not use gas for central
heating, representing a prime marketing opportunity. The Company targets this
group through special programs with an objective of increasing the rate of
conversion to natural gas.
No customer, or group of customers under common control, accounted for 3% or
more of the total firm revenues in 1994.
Considerable growth opportunities exists in the commercial and industrial
markets, where the Company's market penetration is only two-thirds the national
average due to historical capacity limitations and the relatively late
introduction of natural gas into New England. Despite low oil prices in 1994,
the environmental advantages of natural gas and customers' desire for long-term
value and price stability generated the highest level of new sales in this
market segment in the past five years.
In June 1992, FERC granted the Company the authority to make sales for resale
in interstate commerce under the terms of a blanket marketing certificate. This
additional sales authority allows the Company to maximize the use of its supply
entitlements, thereby minimizing the cost of gas to firm customers and making
its sales rates more competitive.
FERC Order No. 636 and other regulatory changes have increased competition
among existing and new suppliers of natural gas in the Company's service area,
particularly in the large commercial and industrial sectors (see "Gas Supply").
The Company provides firm and interruptible transportation-only service to
customers who may engage in direct purchases of natural gas from other
suppliers. Firm transportation tariffs provide equal gross margin opportunities
for the Company regardless of whether the customer purchases gas directly from
the Company or purchases gas from a third party and arranges for
transportation-only service on the Company's distribution system. These
services allow flexibility for customers and encourage conversions to natural
gas, while providing increased opportunities for the Company to increase
throughput on its system and generate increased margins. The Company has also
received approval from the Department to enter into contracts designed to
compete for commercial and industrial customers with alternative energy
options. As a result of these factors, the Company believes it is well
positioned to respond to such competition.
The Company continues to pursue market opportunities in natural gas-powered
vehicles as the passage of federal legislation has enhanced opportunities in
this market. The City of Boston Fire Department recently removed restrictions
which barred natural gas vehicles from city tunnels and major bridges, thus
making the use of these vehicles more practical. The Company achieved
significant progress in 1994 through cooperative efforts with state and federal
government agencies to obtain access to federal funding grants for fueling
station infrastructure development. This funding will help provide additional
commercial and municipal fleet fueling sites in the near future. The Company's
program in this market includes the installation of two Company-owned fueling
stations, conversion of 103 Company vehicles and the establishment of pilot
programs with a number of large fleet operations for on-site fueling to
demonstrate the advantage of choosing natural gas to meet alternative fuel
vehicle requirements.
ENVIRONMENTAL MATTERS
The Company may have to share responsibility for environmental remediation of
certain former manufactured gas plant sites, as described in Note 11 appearing
on page F-15. A subsidiary of New England Electric System has assumed
responsibility for remediating 11 of the 15 such sites owned by the Company,
subject to a limited contribution by the latter. A 1990 regulatory settlement
with the Department provides for recovery by the Company of environmental costs
associated with such sites over separate, seven-year amortization periods
without a return on the unamortized balance. Although the Company does not
possess at this time sufficient information to reasonably determine the
ultimate cost to it of such remediation, it believes that it is not probable
that such costs will materially affect its financial condition or results of
operations.
5
EMPLOYEES
As of December 31, 1994, the Company had 1,700 employees, 71% of whom are
organized in six local unions with which the Company has collective bargaining
agreements. In 1993, after a seventeen-week work stoppage, the Company entered
into six-year labor contracts with the bargaining units, which provided for,
among other things, annual wage increases of approximately 4%, updated work
rules and changed health care coverage to a managed care program with cost
sharing.
ITEM 2. PROPERTIES.
The Company and Mass LNG own or lease 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, and Mass LNG leases one such facility in
Lynn, Massachusetts, and a storage facility in Salem, Massachusetts. In
addition, the Company owns propane-air facilities at several locations
throughout its service territory.
On December 31, 1994, the Company's distribution system included
approximately 5,700 miles of gas mains, 397,000 services and 522,000 active
customer meters.
The Company's gas mains and services are generally located on public ways or
private property not owned by it. The Company's occupation of such property is
generally 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. A portion of the utility properties and franchises of the Company
are pledged as security for the Company's First Mortgage Bonds.
In 1994, the Company's capital expenditures were $53.5 million. Capital
expenditures were principally made for improvements to the distribution system,
for system expansion to meet customer demand and for productivity enhancement
initiatives. The Company plans to spend approximately $58 million for similar
purposes in 1995.
ITEM 3. LEGAL PROCEEDINGS.
With the resolution of the John Boyd case discussed in Note 11 appearing on
page F-15, and other than normal 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 1994.
PART II
ITEM 5. MARKET FOR THE COMPANY'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, 1994.
Dividends on such common equity amounted to $12,803,182 and $8,998,219 for 1994
and 1993, respectively. At December 31, 1994, under the most restrictive
provision limiting dividend payments in the Company's financing indentures,
there were no restrictions on retained earnings.
ITEM 6. SELECTED FINANCIAL DATA.
Not required.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
1994 COMPARED TO 1993
Net earnings applicable to common stock for 1994 were $25.2 million, an
increase of $7.2 million or 40% from 1993. An annual rate increase of $37.7
million, effective November 1, 1993, increased 1994 net earnings by $18.2
million. Net earnings also benefitted from increased sales to new and existing
customers of
6
2.3 BCF. Despite record cold temperatures in early 1994, the year averaged only
slightly colder than normal due to 18% warmer than normal fourth quarter
weather. Weather for 1993 was essentially normal. In total, the weather
decreased net earnings approximately $1.8 million after considering the higher
workload related labor and operating costs associated with the unusually cold
first quarter weather and the reduced sales margin attributable to the 18%
warmer fourth quarter.
In addition, the above were partially offset by higher charges for property
taxes, bad debts and employee benefits. Increased depreciation and amortization
reflects higher allowed depreciation rates and continued investments in system
replacement and expansion. Interest expense increased in 1994 primarily due to
the issuance of long-term debt as well as higher rates on short-term
borrowings.
1993 COMPARED TO 1992
Net earnings available to common shareholders in 1993 of $18.0 million were
$9.3 million lower than the prior year. Net earnings in 1992 reflect a one-time
increase of $7.2 million, as a result of a modification to the Company's gas
cost recovery mechanism approved by the Department in May 1992. The
modification shifted the recovery of a portion of pipeline gas costs from the
non-heating season to the heating season to more closely match revenues with
costs incurred. Excluding such modification, net earnings year to year
decreased $2.1 million. This decline in net earnings was primarily due to the
seventeen-week labor dispute and increased depreciation and amortization
expense. In addition, weather was 1.3% warmer than normal and 4.5% warmer than
1992.
LIQUIDITY AND CAPITAL RESOURCES
The Company maintains committed lines of credit totaling $40.0 million. The
Company also maintains various uncommitted lines of credit and markets its own
commercial paper. In addition, the Company may borrow up to $75.0 million under
Eastern's credit agreement.
During 1994 the Company issued $50.0 million of Medium-term Notes Series B,
with a weighted average maturity of 21 years and a coupon of 7.20% pursuant to
a $50.0 million shelf registration statement dated October 28, 1992 on file
with the SEC.
Short-term borrowings at December 31, 1994 were $62.5 million, a decrease of
$43.8 million from December 31, 1993 primarily reflecting the use of proceeds
from the Medium-term note issuance mentioned above. Cash from operations for
1994 was sufficient to cover dividends to shareholders, capital expenditures
and normal debt repayments.
The Company expects capital expenditures for 1995 to be approximately $58.0
million. Capital expenditures will be largely for improvements to the
distribution system, for system expansion to meet customer demand and for
productivity enhancement.
The Company believes that projected cash flow from operations, in combination
with currently available resources, is sufficient to meet 1995 capital
expenditure and working capital requirements, normal debt repayments and
dividends to shareholders.
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. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
7
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.
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.
8
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 by and among the
Company, The Bank of New York as Resigning Trustee, and The First
National Bank of Boston as Successor Trustee under Indenture dated as
of November 2, 1992 (Filed as an exhibit to registration statement of
the Company on Form S-3 (File No. 33-53858)).*
10.1 --Gas Transportation Contract between Boston Gas 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 Boston Gas 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 Boston Gas 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 Boston Gas 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 Boston Gas 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).*
9
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 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 --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)).*
10.16 --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)).*
10.17 --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).*
10.18 --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 1994.
- --------
* 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.
10
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
J.F. Bodanza
By: _________________________________
J.F. BODANZA
SENIOR VICE PRESIDENT AND TREASURER
(PRINCIPAL FINANCIAL AND
ACCOUNTING OFFICER)
Dated: March 16, 1995
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 16TH DAY OF MARCH 1995.
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
11
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, 1994 and 1993.... F-2 and F-3
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1994.............................................. F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1994........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1994.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-16
Interim Financial Information for the Two Years Ended December
31, 1994 (Unaudited)........................................... F-18
Schedules for the Three Years Ended December 31, 1994:
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,
-----------------
1994 1993
-------- --------
(IN THOUSANDS)
Gas Plant, at cost........................................... $704,861 $649,580
Construction work-in-progress................................ 2,070 8,131
Less--Accumulated depreciation............................. 222,460 195,284
-------- --------
Net Plant.................................................. 484,471 462,427
Current Assets:
Cash....................................................... 3,831 1,160
Accounts receivable, less reserves of $15,621 at December
31, 1994 and $13,518 at December 31, 1993................. 71,408 89,096
Deferred gas costs......................................... 66,865 65,802
Natural gas and other inventories, at average cost......... 46,844 53,152
Materials and supplies, at average cost.................... 5,063 5,019
Prepaid expenses........................................... 3,399 3,708
Income taxes............................................... 1,407 6,046
-------- --------
Total Current Assets..................................... 198,817 223,983
Other Assets:
Deferred postretirement benefits cost...................... 97,589 101,182
Deferred charges and other assets.......................... 52,759 46,848
-------- --------
Total Other Assets....................................... 150,348 148,030
-------- --------
Total Assets............................................. $833,636 $834,440
======== ========
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,
-----------------
1994 1993
-------- --------
(IN THOUSANDS)
Capitalization:
Stockholder's investment --
Common stock, $100 par value --
Authorized and outstanding -- 514,184 shares
at December 31, 1994 and 1993............................. $ 51,418 $ 51,418
Amounts in excess of par value............................. 43,233 43,233
Retained earnings.......................................... 108,098 95,680
-------- --------
Total Common Stockholder's Investment..................... 202,749 190,331
Variable-term cumulative preferred stock,
$1 par value, (liquidation preference, $25 per share) --
Authorized and outstanding -- 1,200,000 shares
at December 31, 1994 and 1993.............................. 29,229 29,197
Long-term obligations, less current portion.................. 216,680 171,345
-------- --------
Total Capitalization...................................... 448,658 390,873
Gas inventory financing...................................... 53,578 59,297
-------- --------
Total Capitalization and Gas Inventory Financing.......... 502,236 450,170
Current Liabilities:
Current portion of long-term obligations.................... 1,890 2,165
Notes payable............................................... 62,530 106,300
Accounts payable............................................ 42,653 52,773
Accrued taxes............................................... 510 161
Accrued interest............................................ 3,524 3,004
Customer deposits........................................... 2,852 2,597
Refunds due customers....................................... 18,719 8,029
Pipeline transition costs................................... 11,560 24,174
-------- --------
Total Current Liabilities................................. 144,238 199,203
Commitments and Contingencies:
Reserves and Deferred Credits:
Deferred income taxes....................................... 66,577 61,561
Unamortized investment tax credits.......................... 8,704 9,427
Postretirement benefits obligation.......................... 90,214 91,955
Other....................................................... 21,667 22,124
-------- --------
Total Reserves and Deferred Credits....................... 187,162 185,067
-------- --------
Total Liabilities and Stockholder's Investment............ $833,636 $834,440
======== ========
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,
----------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Operating Revenues................................ $660,158 $614,294 $594,330
Cost of Gas Sold.................................. 382,885 375,103 357,697
-------- -------- --------
Operating Margin.................................. 277,273 239,191 236,633
Operating Expenses:
Other operating expenses........................ 150,847 133,187 129,795
Maintenance..................................... 24,826 29,376 21,225
Depreciation and amortization................... 35,809 27,566 22,493
Income taxes.................................... 17,737 12,105 17,995
-------- -------- --------
229,219 202,234 191,508
-------- -------- --------
Operating Earnings................................ 48,054 36,957 45,125
Other Earnings, Net............................... 65 278 47
-------- -------- --------
Earnings before Interest Expense.................. 48,119 37,235 45,172
Interest Expense:
Long-term debt.................................. 17,024 15,447 15,710
Other, including amortization of debt expense... 4,841 2,957 2,577
Less-Interest during construction............... (894) (583) (823)
-------- -------- --------
20,971 17,821 17,464
-------- -------- --------
Net Earnings...................................... 27,148 19,414 27,708
Preferred Stock Dividends......................... 1,926 1,389 405
-------- -------- --------
Earnings Applicable to Common Stock............... $ 25,222 $ 18,025 $ 27,303
======== ======== ========
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,
--------------------------
1994 1993 1992
-------- ------- -------
(IN THOUSANDS)
Balance at Beginning of Year....................... $ 95,680 $86,653 $67,063
Net earnings..................................... 27,148 19,414 27,708
Preferred stock dividends ($1.61 per share in
1994, $1.16 per share in 1993 and $.34 per share
in 1992)........................................ (1,926) (1,389) (405)
Cash dividends on common stock ($24.90 per share
in 1994, $17.50 per share in 1993 and $15.00 per
share in 1992).................................. (12,804) (8,998) (7,713)
-------- ------- -------
Balance at End of Year............................. $108,098 $95,680 $86,653
======== ======= =======
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,
----------------------------
1994 1993 1992
-------- -------- --------
(IN THOUSANDS)
Cash flows from operating activities:
Net earnings.................................... $ 27,148 $ 19,414 $ 27,708
Adjustments to reconcile net earnings to cash
(used for) provided by operating activities:
Depreciation and amortization.................. 35,809 27,566 22,493
Deferred taxes................................. 5,016 8,837 (2,997)
Other changes in assets and liabilities:
Accounts receivable........................... 17,688 (15,840) (11,962)
Inventory..................................... 6,264 (10,381) (15,430)
Deferred gas costs............................ (1,063) (24,933) (26,994)
Deferred postretirement benefits.............. 1,852 312 (5,000)
Accounts payable.............................. (10,121) (198) 4,334
Accrued interest.............................. 520 (317) 271
Federal and state income taxes................ 4,639 (998) 9,083
Refunds due customers......................... 10,690 (5,032) 1,263
Other......................................... (18,046) (3,844) 3,867
-------- -------- --------
Cash (used for) provided by operating activities. 80,396 (5,414) 6,636
-------- -------- --------
Cash flows used for investing activities:
Capital expenditures........................... (53,504) (47,057) (51,136)
Net cost of removal............................ (6,412) (4,328) (8,096)
-------- -------- --------
Cash used for investing activities............... (59,916) (51,385) (59,232)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. (43,770) 52,968 (307)
Changes in inventory financing................. (5,719) 10,666 17,461
Proceeds from issuance of long-term debt....... 50,000 -- 28,000
Repayment of long-term debt.................... (3,622) (20,480) (10,030)
Proceeds/Amortization from issuance of
preferred stock............................... 32 (240) 29,436
Capital contribution from parent............... -- 20,000 --
Cash dividends paid on common and preferred
stock......................................... (14,730) (10,255) (8,089)
-------- -------- --------
Cash (used for) provided by financing activities. (17,809) 52,659 56,471
-------- -------- --------
Increase (decrease) in cash...................... 2,671 (4,140) 3,875
Cash at beginning of year........................ 1,160 5,300 1,425
-------- -------- --------
Cash at end of year.............................. $ 3,831 $ 1,160 $ 5,300
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 20,193 $ 18,559 $ 17,461
Income taxes.................................. $ 8,151 $ 7,813 $ 6,372
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 significant accounting policies followed by Boston Gas Company (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.
Regulatory Assets
The Company is subject to provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
Regulatory assets represent certain costs that will be recovered from customers
through current and future rates. The following regulatory assets were
reflected in the Consolidated Balance Sheets as of December 31:
1994 1993
-------- --------
(IN THOUSANDS)
Postretirement benefit costs............................ $ 97,589 $101,182
Deferred pipeline transition costs...................... 34,398 24,174
Deferred income taxes................................... 1,097 1,695
Environmental costs..................................... 806 3,308
Other................................................... 3,677 3,122
-------- --------
$137,567 $133,481
======== ========
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 5.16% in 1994, 3.98% in 1993 and
3.80% in 1992.
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.
F-7
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause requires the Company to adjust its rates
semiannually 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. The cost of gas
adjustment clause also recovers the amortization of all environmental response
costs associated with former manufactured gas plant ("MGP") sites and costs
related to the Company's various conservation and load management programs.
In May 1992, the Company modified the cost of gas adjustment clause by
shifting a portion of pipeline gas costs from the non-heating to the heating
season in order to more closely match revenues with the related costs.
(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 which would be payable
on a separate company basis. The Company's effective income tax rate was 39.5%
in 1994, 38.4% in 1993 and 39.4% in 1992. State taxes represent the majority,
or 4.3%, 4.3% and 4.6% of the difference between the effective rate and the
Federal income tax rate for 1994, 1993 and 1992, respectively.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
1994 1993 1992
------- ------- -------
(IN THOUSANDS)
Current --
Federal........................................... $ 7,966 $ 4,063 $12,128
State............................................. 591 771 2,410
------- ------- -------
Total current provision......................... 8,557 4,834 14,538
Deferred --
Federal........................................... 6,796 5,951 2,711
State............................................. 2,384 1,320 746
------- ------- -------
Total deferred provision........................ 9,180 7,271 3,457
------- ------- -------
Provision for income taxes.......................... $17,737 $12,105 $17,995
======= ======= =======
Effective January 1, 1992, the Company adopted Statement of Financial
Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS
109 requires adjustment of deferred tax assets and liabilities to reflect the
future tax consequences, at currently enacted rates, of items already reflected
in the financial statements. A regulatory asset of $1,880,000 was established
for the recovery of prepaid taxes established at the higher federal tax rates
in effect prior to 1988. At December 31, 1994 the balance of the regulatory
asset was $1,097,000. In its most recent rate request proceeding, the Company
received permission to recover this amount over three years. A regulatory
liability of $6,144,000 was established for the tax benefit of unamortized
investment tax credits, which SFAS 109 requires to be treated as a temporary
difference. This benefit will be passed on to customers over the lives of
property giving rise to the investment credits, consistent with the 1986 Tax
Reform Act. The balance at December 31, 1994 was $5,045,000. The regulatory
liability for excess deferred taxes being returned to customers over a 30 year
period pursuant to a 1988 rate order was similarly increased by $4,445,000 upon
the adoption of SFAS 109. At December 31, 1994 the balance to be returned to
customers was $8,296,000.
F-8
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) INCOME TAXES (CONTINUED)
The Revenue Reconciliation Act of 1993 increased the statutory Federal income
tax rate from 34% to 35%, retroactive to January 1, 1993. The provision for
income taxes in 1993 includes approximately $300,000 for the impact of the rate
change on current earnings. The effect of the rate change on deferred tax
requirements at January 1, 1993 is reflected in the regulatory asset and
liability established at the adoption of SFAS 109.
For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives permitted by the Internal Revenue Service. 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 liabilities and deferred tax assets at December 31, 1994
and 1993, are as follows:
1994 1993
-------- --------
(IN THOUSANDS)
ASSETS:
Unbilled revenues..................................... $ 30,978 $ 30,924
Reserve for uncollectible receivables................. 6,127 5,302
Regulatory liabilities................................ 5,233 5,494
Other................................................. 8,146 6,765
-------- --------
Total deferred tax assets............................. $ 50,484 $ 48,485
-------- --------
LIABILITIES:
Accelerated depreciation.............................. $ 73,277 $ 69,558
Deferred gas costs.................................... 23,455 23,861
Other................................................. 21,812 13,967
-------- --------
Total deferred tax liabilities........................ $118,544 $107,386
-------- --------
Total net deferred taxes.............................. $ 68,060 $ 58,901
======== ========
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 $724,000 in 1994, $689,000 in 1993 and $673,000 in 1992.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations, less the
current portion, as of December 31, 1994 and 1993, respectively.
DECEMBER 31,
-----------------
1994 1993
-------- --------
(IN THOUSANDS)
7.95% - 9.00%, Sinking Fund Debentures, due 1997 - 2001... $ 60,000 $ 62,775
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 --
First mortgage bonds--8.375% Series, due 1996............. 2,400 2,880
Capital lease obligations (Note 8)........................ 4,280 5,690
-------- --------
$216,680 $171,345
======== ========
The First Mortgage Bonds are secured by a first mortgage lien on a portion of
the Company's utility properties and franchises.
F-9
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
On October 28, 1992, the Company filed a Shelf registration covering the
issuance of up to $50,000,000 of additional Medium-Term Notes through December
31, 1994 for the financing of capital expenditures and the payment of related
obligations. During 1994 the Company issued all $50,000,000 of Medium-Term
Notes with a weighted average maturity of 21 years and a coupon rate of 7.20%.
The Series B Notes include $12,000,000 maturing in 2006 with a put option at
par in 1999 and an interest rate step up from 8.09% to 8.59% in 1999.
The aggregate consolidated annual sinking fund requirements, less amounts
acquired in advance, and current maturities of long-term debt for the next five
years are as follows:
YEAR AMOUNT
---- --------------
(IN THOUSANDS)
1995........................................................ 1,890
1996........................................................ 3,908
1997........................................................ 9,029
1998........................................................ 8,507
1999........................................................ 8,561
The terms of the various indentures referred to above, as supplemented,
provide that dividends may not be paid on common stock of the Company under
certain conditions. At December 31, 1994, under the most restrictive of these
provisions, there were no restrictions on retained earnings available for
payment of dividends.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department of Public
Utilities (the Department) effective October 1, 1988, the Company funds all of
its inventory of gas supplies through external sources. All costs related to
this funding are recoverable from its customers. The Company maintains a credit
agreement with a group of banks which provides for the borrowing of up to
$90,000,000 for the exclusive purpose of funding its inventory of gas supplies
or for backing commercial paper issued for the same purpose. The Company had
$53,578,000 and $59,297,000 of commercial paper outstanding at December 31,
1994 and 1993, respectively, for this purpose. 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 364 day revolving credit which may be converted to a two-
year term loan at the Company's option if the 364 day revolving credit is not
renewed by the banks. The Company may select interest rate alternatives based
on prime or Eurodollar rates and requires a facility fee of 1/10 of 1% on the
commitment. No borrowings were outstanding under this agreement at December 31,
1994 and 1993.
Notes Payable
The Company maintains committed lines of credit totaling $40,000,000 which
provide for interest based on prime or money market rates.
These lines of credit are used to back commercial paper and for short-term
borrowings. The Company pays facility fees of seven basis points related to
these lines of credit. In addition, the Company has various uncommitted lines
of credit which provide for interest at the federal funds, money market or
prime rates. These uncommitted lines of credit are used for short-term
borrowings. The Company had outstanding borrowings of $62,530,000 and
$106,300,000 in commercial paper and bank loans not related to gas inventory
financing at December 31, 1994 and 1993, respectively. The weighted average
interest rate on these borrowings at December 31, was 5.9% in 1994 and 3.5% in
1993.
F-10
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
Eastern Borrowing Arrangement
During 1994, Eastern negotiated a credit agreement with a group of banks
which provides for the borrowing by Eastern of up to $100,000,000 (of which the
Company may borrow up to $75,000,000) at any time through December 31, 1999.
The interest rate for such borrowings is the agent bank's prime rate, or at
Eastern's option, various alternatives.
(5) PREFERRED STOCK
In 1992, the Company sold 1,200,000 shares of variable-term cumulative
preferred stock, which is non-voting and has a liquidation value of $25 per
share. In 1993 the Company selected a Final Term of September 1, 2018 and fixed
the dividend rate at 6.421%, payable quarterly. The Final Term requires 5%
annual sinking fund payments beginning on September 1, 1999. The preferred
stock can not be called 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:
1994 1993 1992
------- -------- -------
(IN THOUSANDS)
Service cost-benefits earned during the year..... $ 2,637 $ 2,331 $ 2,072
Interest cost on projected benefit obligation.... 7,556 7,304 6,735
Actual return on plan assets..................... (4,431) (15,984) (9,491)
Net amortization and deferral.................... (3,281) 7,105 1,666
------- -------- -------
Net pension cost................................. $ 2,481 $ 756 $ 982
======= ======== =======
For the periods 1994, 1993 and 1992, the expected long-term rate of return on
assets was 8.5%, the discount rate used in determining the actuarial present
value of the projected benefit obligation was 7.5% and the rate of increase in
future compensation levels was 5.0%.
F-11
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(6) PENSION BENEFITS (CONTINUED)
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 as of October 1, 1994 and 1993.
1994 1993
--------- ---------
(IN THOUSANDS)
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $89,283 in 1994 and $83,759 in 1993... $ 98,248 $ 92,226
========= =========
Projected benefit obligation for service rendered
to date........................................... $(109,974) $(103,154)
Plan assets at fair value, primarily listed stocks,
corporate bonds and U.S. bonds.................... 115,080 114,711
--------- ---------
Plan assets in excess of projected benefit
obligation........................................ 5,106 11,557
Unrecognized net obligation at January 1, 1986
being recognized over 15 years.................... 1,305 1,522
Unrecognized net gain.............................. (12,377) (18,164)
Unrecognized prior service cost.................... 14,048 15,096
--------- ---------
Net pension asset.................................. $ 8,082 $ 10,011
========= =========
(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.
Effective January 1, 1991, the Company adopted Statement of Financial
Accounting Standards No. 106 ("SFAS 106"), "Employers' Accounting for
Postretirement Benefits Other Than Pensions," by immediately recognizing the
cumulative effect of the accounting change. SFAS 106 requires that the expected
cost of postretirement benefits other than pensions be charged to expense
during the period that the employee renders service. As of the date of
adoption, the cumulative effect of the accounting change ("transition
obligation") was $89,120,000. With approval by the Department, the Company has
deferred the cost of the transition obligation and the amount by which expense
under SFAS 106 exceeds amounts currently included in rates. The 1993 rate order
allows the Company to phase in incremental costs associated with SFAS 106 over
a four-year period. Each year during the phase-in, the Company will file for an
increase in rates to reflect an additional increment of SFAS 106 costs. The
difference between the incremental annual amount requested in rates during the
phase-in period and the full SFAS 106 costs will be deferred as a regulatory
asset with carrying costs.
Net postretirement benefit cost included the following components:
1994 1993 1992
------- ------- -------
(IN THOUSANDS)
Service cost-benefits earned during the year..... $ 731 $ 1,301 $ 1,096
Interest cost on accumulated benefit obligation.. 5,238 7,021 7,824
Net amortization and deferral of actuarial gains
and losses...................................... (2,617) (1,235) 239
Actual return on plan assets..................... (755) (282) (173)
------- ------- -------
Postretirement benefit cost...................... 2,597 6,805 8,986
Amortization (deferral) of regulatory asset...... 3,472 (2,275) (4,876)
------- ------- -------
Net postretirement benefit cost.................. $ 6,069 $ 4,530 $ 4,110
======= ======= =======
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 as of October 1, 1994 and October 1, 1993.
1994 1993
-------- --------
(IN THOUSANDS)
Retirees................................................ $(56,662) $(50,561)
Other fully eligible participants....................... (7,838) (7,943)
Other active participants............................... (13,043) (13,523)
-------- --------
(77,543) (72,027)
Plan assets at fair value............................... 11,611 10,856
-------- --------
Accumulated postretirement benefits obligation in excess
of plan assets......................................... (65,932) (61,171)
Unrecognized actuarial gain............................. (10,685) (15,997)
Unrecognized prior service costs........................ (13,597) (14,787)
-------- --------
Accrued postretirement benefits......................... $(90,214) $(91,955)
======== ========
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. There were no contributions to
the VEBA in 1994 or 1993. Plan assets are invested in equity securities, fixed-
income investments and money market instruments.
The weighted average discount rate used in determining the accumulated post-
retirement benefit obligation was 7.5% in 1994 and 1993. An 11% and 12% annual
increase in the cost of covered health care benefits was assumed for 1994 and
1993, respectively. This rate of increase is assumed to drop gradually to 5%
after 7 years. A 1% increase in the assumed health care cost trend would have
increased the postretirement benefit cost by $529,000 in 1994 and $489,000 in
1993, and the accumulated postretirement benefit obligation by $6,302,000 in
1994 and $5,691,000 in 1993.
(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
$6,040,000 in 1994, $7,663,000 in 1993 and $6,939,000 in 1992.
The Company capitalizes its financing leases which include liquefied natural
gas facilities and an operations center. A summary of property held under
capital leases as of December 31, 1994 and 1993 is as follows:
1994 1993
------- -------
(IN THOUSANDS)
LNG facilities............................................ $15,600 $15,600
Buildings................................................. 6,000 6,000
------- -------
21,600 21,600
Less-Accumulated depreciation............................. 15,910 14,592
------- -------
$ 5,690 $ 7,008
======= =======
Under the terms of SFAS No. 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
F-13
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) LEASES (CONTINUED)
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 commitment for these and all
other noncancellable leases, including the financing leases, at December 31,
1994 is as follows:
CAPITAL OPERATING
YEAR LEASES LEASES
---- ------- ---------
(IN THOUSANDS)
1995.................................................... 1,853 4,901
1996.................................................... 1,854 4,186
1997.................................................... 1,269 2,355
1998.................................................... 684 1,060
1999.................................................... 684 700
Later Years............................................. 746 376
------ -------
Total minimum lease payments............................ $7,090 $13,578
=======
Less-Amount representing interest and executory costs... 1,400
------
Present value of minimum lease payments on capital
leases................................................. $5,690
======
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
disclosures for 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 for similar types of borrowing arrangements.
Preferred Stock
The fair value of the preferred stock for 1994 and 1993 is based on currently
quoted market prices.
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1994 and 1993 are as follows:
1994 1993
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS) (IN THOUSANDS)
Cash..................................... $ 3,831 $ 3,831 $ 1,160 $ 1,160
Short-term debt.......................... $116,108 $116,108 $165,597 $165,597
Long-term debt........................... $218,570 $214,584 $173,510 $195,854
Preferred stock.......................... $ 29,229 $ 26,250 $ 29,197 $ 30,600
F-14
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(10) SUPPLEMENTARY INFORMATION
The Company paid Eastern $3,669,000 in 1994, $3,096,000 in 1993 and
$2,707,000 in 1992 for various legal, tax and corporate services rendered.
(11) ENVIRONMENTAL ISSUES
The Company is party to governmental actions requiring investigation and
possible remediation of former manufactured gas plant ("MGP") sites. The
Company currently owns fifteen former MGP sites. Massachusetts Electric Company
(MEC), a wholly-owned subsidiary of New England Electric System ("NEES"), has
assumed full responsibility for remediating one such MGP site in Lynn,
Massachusetts, pursuant to the decision of the First Circuit Court of Appeals
in The John S. Boyd, Inc., et al. v. Boston Gas Company, et al, which affirmed
that NEES and its subsidiaries are responsible for remediating the site as
prior owners and operators. Pursuant to a recent settlement agreement between
MEC and the Company (the "Settlement Agreement"), MEC also assumed
responsibility for remediating another ten of the sites owned by the Company,
subject to limited contribution by the Company. The Company will work with the
Massachusetts Department of Environmental Protection (the "DEP") to determine
the extent of remediation which may be required at the four remaining owned
sites not covered by the Settlement Agreement or Boyd. The Company expects to
spend approximately $1 million in 1995 for assessment and contribution costs
associated with the Company's and MEC's site investigations. Since the DEP has
not yet approved a remediation plan for any of these sites, the Company does
not possess at this time sufficient information to reasonably determine the
ultimate cost of remediation, but believes that it is not probable that such
costs will materially affect the Company's financial condition or results of
operations, particularly given the Company's limited potential responsibility
as a result of the Settlement Agreement. Company experience to date indicates
that assessment and remediation costs of approximately $15 million could be
paid by the Company with respect to these ten sites covered by the Settlement
Agreement and the four other currently owned sites.
The Company is aware of 25 other former MGP sites within the Company's
service territory which the Company does not currently own. MEC has provided
full indemnification of Boston Gas with respect to eight of these sites in the
Settlement Agreement. At this time, there is substantial uncertainty as to
whether the Company is responsible for remediating any of the other sites
either because the Company does not have successor liability for contamination
of these sites by earlier operators or site conditions do not require
remediation by the Company. The DEP has not issued a Notice of Responsibility
to the Company for any of these sites.
By a rate order issued on May 25, 1990, the Department approved the recovery
through the cost of gas adjustment clause of all environmental response costs
associated with former MGP sites over separate, seven-year amortization periods
without a return on the unamortized balance. The rate order also provides for
no further investigation of the prudency of any Massachusetts gas utility's
past MGP operations.
(12) PIPELINE TRANSITION COSTS
Pursuant to Federal Energy Regulatory Commission (FERC) Order No. 636,
pipelines are currently recovering 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 uncovered 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.
The Company's estimate of its obligation for transition costs is $41.6
million at December 31, 1994 and it has recorded this amount less actual
billings of $30.0 million as a liability in the accompanying consolidated
F-15
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) PIPELINE TRANSITION COSTS (CONTINUED)
balance sheet. As pipelines continue to file for recovery of transition costs,
the Company's obligation may increase.
The Company's obligations to Texas Eastern and Algonquin for transition costs
is $14.6 million, based on a Texas Eastern settlement agreement and filings
made by Texas Eastern and Algonquin at FERC. Payments to Texas Eastern and
Algonquin began in July 1993. The Company's obligation to Tennessee for
transition costs is $26.2 million, based on filings by Tennessee at FERC.
Payments to Tennessee for such costs commenced in October, 1993. Obligations to
other pipeline companies are approximately $.8 million.
The Department allowed recovery of the Company's transition costs liability
over a five-year period commencing in May 1994. In June 1994, the Department
opened a generic investigation to set standards for recovery of Order 636
costs. The parties involved have proposed to recover costs from both sales and
transportation customers on a current basis, with the ability to amortize costs
depending upon customer bill impact. An order is expected in 1995. Accordingly,
at December 31, 1994 the Company has recorded a regulatory asset of $34.4
million and deferred gas costs of $6.5 million which, taken together plus
recoveries to date, is equivalent to the Company's total estimated obligation
for transition costs.
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, 1994 and 1993, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1994. These consolidated
financial statements and the schedules referred to below are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Boston Gas Company and
subsidiary as of December 31, 1994 and 1993 and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1994, 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 27, 1995
F-17
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION
FOR THE TWO YEARS ENDED DECEMBER 31, 1994 (UNAUDITED)
The following table summarizes the Company's reported quarterly information
for the years ended December 31, 1994 and 1993:
THREE MONTHS ENDED
-------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- --------
(IN THOUSANDS)
1994
Operating revenues........................ $314,302 $122,807 $72,114 $150,935
Operating margin.......................... 120,886 56,109 34,703 65,575
Operating earnings (loss)................. 34,204 5,117 (2,830) 11,563
Net earnings (loss) applicable to common
stock.................................... 28,805 (132) (9,133) 5,682
1993
Operating revenues........................ $258,226 $128,567 $66,606 $160,895
Operating margin.......................... 95,282 49,209 29,047 65,653
Operating earnings (loss)................. 27,357 4,446 (5,521) 10,675
Net earnings (loss) applicable to common
stock.................................... 22,372 (182) (9,891) 5,726
F-18
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1994
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1993 TO INCOME ACCOUNTS RESERVES 1994
- ----------- ------------ --------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 13,518 $15,830 $ -- $13,727 $ 15,621
======== ======= ====== ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes.......... $ 61,561 $ 4,923 $ 93 $ -- $ 66,577
-------- ------- ------ ------- --------
Deferred investment tax
credits............... $ 9,427 $ -- $ -- $ 723 $ 8,704
-------- ------- ------ ------- --------
Postretirement benefit
cost.................. $ 91,955 $ -- $2,597 $ 4,338 $ 90,214
-------- ------- ------ ------- --------
Other reserves and de-
ferred credits--
Reserve for self-in-
surance............. 2,270 1,429 -- 1,441 2,258
FAS 109 Regulatory
Liability........... 5,512 -- -- 467 5,045
Deferred net normal-
ization surplus..... 8,494 -- -- 198 8,296
Other................ 5,848 8,634 (3,658) 4,756 6,068
-------- ------- ------ ------- --------
Total other reserves
and deferred
credits............ 22,124 10,063 (3,658) 6,862 21,667
-------- ------- ------ ------- --------
Total reserves not
deducted from
assets............. $185,067 $14,986 $ (968) $11,923 $187,162
======== ======= ====== ======= ========
F-19
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1993
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1992 TO INCOME ACCOUNTS RESERVES 1993
- ----------- ------------ --------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 11,408 $13,127 $ -- $11,017 $ 13,518
======== ======= ======= ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes.......... $ 52,724 $ 7,532 $ 3,057 $ 1,752 $ 61,561
-------- ------- ------- ------- --------
Deferred investment tax
credits............... $ 10,116 $ -- $ -- $ 689 $ 9,427
-------- ------- ------- ------- --------
Postretirement benefit
cost.................. $ 89,587 $ -- $ 6,805 $ 4,437 $ 91,955
-------- ------- ------- ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... 2,354 1,124 -- 1,208 2,270
FAS 109 Regulatory
Liability........... 6,144 (440) -- 192 5,512
Deferred net
normalization
surplus............. 11,340 (422) -- 2,424 8,494
Other................ 5,857 4,530 4,443 8,982 5,848
-------- ------- ------- ------- --------
Total other reserves
and deferred
credits............ 25,695 4,792 4,443 12,806 22,124
-------- ------- ------- ------- --------
Total reserves not
deducted from
assets............. $178,122 $12,324 $14,305 $19,684 $185,067
======== ======= ======= ======= ========
F-20
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1992
(IN THOUSANDS)
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, TO OTHER FROM DECEMBER 31,
DESCRIPTION 1991 CHARGED ACCOUNTS RESERVES 1992
- ----------- ------------ TO INCOME -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 10,020 $12,444 $ -- $11,056 $ 11,408
======== ======= ======= ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes.......... $ 55,721 $(2,997) $ -- $ -- $ 52,724
-------- ------- ------- ------- --------
Deferred investment tax
credits............... $ 10,789 $ -- $ -- $ 673 $ 10,116
-------- ------- ------- ------- --------
Postretirement benefit
cost.................. $ 89,711 $ -- $ 8,986 $ 9,110 $ 89,587
-------- ------- ------- ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... 3,199 1,732 -- 2,577 2,354
FAS 109 Regulatory
Liability........... -- -- 6,144 -- 6,144
Deferred net
normalization
surplus............. 7,164 -- 4,445 269 11,340
Other................ 5,581 9,355 -- 9,079 5,857
-------- ------- ------- ------- --------
Total other reserves
and deferred
credits............ 15,944 11,087 10,589 11,925 25,695
-------- ------- ------- ------- --------
Total reserves not
deducted from
assets............. $172,165 $ 8,090 $19,575 $21,708 $178,122
======== ======= ======= ======= ========
F-21