<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(MARK ONE)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
- ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
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)
04-1103580
MASSACHUSETTS (I.R.S. EMPLOYER IDENTIFICATION NO.)
(STATE OR OTHER JURISDICTION OF
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
- -
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this form 10-K or any
amendment to this form 10-K.
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 10, 1996.
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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<PAGE>
BOSTON GAS COMPANY
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
PART I
Item 1. Business.............................................................................. 1
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..................................................................... 4
Item 4. Submission of Matters to a Vote of Security Holders................................... 4
Glossary....................................................................................... 5
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............. 6
Item 6. Selected Financial Data............................................................... 6
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 6
Item 8. Financial Statements and Supplementary Data........................................... 7
Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure.. 7
PART III
Item 10. Directors and Executive Officers of the Registrant.................................... 7
Item 11. Executive Compensation................................................................ 7
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 7
Item 13. Certain Relationships and Related Transactions........................................ 7
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 8
</TABLE>
<PAGE>
BOSTON GAS COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1995
PART I
ITEM 1. BUSINESS.
GENERAL
Boston Gas Company (the "Company"), is engaged in the transportation and
sale of natural gas to over 515,000 residential, commercial and industrial
customers in Boston, Massachusetts and 73 other communities in eastern and
central Massachusetts. The Company also sells gas for resale in Massachusetts
and other states. The Company has one subsidiary, Massachusetts LNG
Incorporated ("Mass LNG"), which holds a long-term lease on two liquefied
natural gas ("LNG") facilities. The Company is the largest natural gas
distribution company in New England, has been in business for 173 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.
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 5.
The Company provides both local transportation services and gas supply for
all customer classes. All residential customers and most commercial/industrial
customers currently purchase combined or "bundled" supply and transportation
services from the Company. Local transportation service is offered on an
unbundled basis to large commercial/industrial customers, who may purchase gas
supply from the Company or other sources.
The Company's services are available on a firm and non-firm basis. Firm
transportation services and sales are provided under rate tariffs filed with
the Massachusetts Department of Public Utilities (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/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. Beginning in November, 1993, margin on non-firm throughput
and city gate sales in excess of a threshold based upon the prior year's non-
firm margin is shared between firm customers and the Company, 75% and 25%,
respectively. Under this sharing mechanism, the Company retained $353,000 and
$1,040,000 in 1995 and 1994, respectively.
MARKETS AND COMPETITION
The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. Over the last five years, the Company has
increased its market share of the total stationary energy market from 28% to
35%. This market share compares to the national average of approximately 43%
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 and customer perceptions of
relative value.
Residential customers comprise 92% of its customer base, while
commercial/industrial establishments account for the remaining 8%.
Volumetrically, residential customers account for 29% of total throughput and
42% of firm throughput, while commercial/industrial customers account for 71%
of total throughput and 58% of firm throughput. Approximately half of the
commercial/industrial customers' total throughput is local transportation.
<PAGE>
In 1993, the Department approved the Company's proposal to unbundle local
transportation service and gas sales service for its largest
commercial/industrial customers. Unbundling allows customers to purchase local
transportation from the Company on a basis separate from the purchase of gas
supply, which the customer may buy from the Company or third parties. This
unbundling initiative extended to eligible customers direct access to gas
supplies and interstate pipeline capacity, as authorized by the Federal Energy
Regulatory Commission ("FERC") in Order 636. As a result of Order 636, the
Company has seen increasing competition from other gas suppliers into its
service territory. In 1995, 103 of the approximately 450 eligible customers
purchased gas supplies from third parties. In response to such perceived
trends, in 1994, the Company initiated a large-scale reengineering effort to
reduce costs, increase productivity, and improve customer service.
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 gas throughput of
the Company for the three years 1993-1995.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Residential.................................... 39.7 41.4 41.9
Commercial/Industrial.......................... 48.1 46.7 49.1
Off-system sales............................... 6.6 7.6 2.1
-------- -------- --------
Total sales.................................. 94.4 95.7 93.1
Transportation of customer-owned gas........... 47.5 48.7 51.7
Less: Off-system sales......................... (6.6) (7.6) (2.1)
-------- -------- --------
Total throughput............................. 135.3 136.8 142.7
======== ======== ========
Firm throughput.............................. 94.9 95.5 95.3
======== ======== ========
</TABLE>
No customer, or group of customers under common control, accounted for 3% or
more of total firm revenues in 1995.
GAS SUPPLY
The following table in BCF provides statistical information with respect to
the Company's sources of supply for 1993-1995.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Natural gas pipeline purchases................. 93.4 92.2 86.3
Liquefied natural gas ("LNG") purchases........ 3.1 5.1 13.4
-------- -------- --------
Total purchases.............................. 96.5 97.3 99.7
Change in storage gas.......................... 3.5 0.4 (4.0)
Company use, unbilled and other................ (5.6) (2.0) (2.6)
-------- -------- --------
Total sales.................................. 94.4 95.7 93.1
======== ======== ========
</TABLE>
The Company purchases approximately 60% 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 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.
2
<PAGE>
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights under
these contracts. The interstate pipeline companies that provide firm
transportation service to the Company's service territory, the peak daily and
annual capacity and the contract expiration dates are as follows:
<TABLE>
<CAPTION>
CAPACITY IN BCF
--------------- EXPIRATION
PIPELINE DAILY ANNUAL DATES
-------- ------- -------- ----------
<S> <C> <C> <C>
Algonquin Gas Transmission Company ("Algonquin").... 0.28 87.4 1997-2012
Tennessee Gas Pipeline Company ("Tennessee")........ 0.18 66.9 2000-2012
------- --------
0.46 154.3
======= ========
</TABLE>
In addition, the Company has firm capacity contracts on interstate pipelines
upstream of Algonquin and Tennessee pipelines to transport natural gas
purchased by the Company from producing regions to the Algonquin and Tennessee
pipelines. The expiration dates for these contracts are similar to those
included in the above table.
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 for storage
capacity of 17.3 BCF and peak day capacity of 0.16 BCF. The Company utilizes
its existing capacity 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 0.69, 0.65 and 0.64 in 1995, 1994 and 1993,
respectively. The Company provides for peak period demand through a least cost
portfolio of pipeline, storage and supplemental supplies. The Company
considers its peak day sendout capacity, based on its total supply resources,
to be adequate to meet the requirements of its firm customers.
REGULATION
The Company's operations are subject to Massachusetts statutes applicable to
gas utilities. Rates, 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
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 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, including the demand charges for capacity on the interstate
pipeline system.
In February of 1995 the Department ordered all large gas and electric
utilities to file incentive rate proposals as soon as possible. The order
signaled a significant departure from established Department practice of
setting rates to reflect all allowed costs of service. In the second quarter
of 1996 the Company intends to file an incentive rate proposal consistent with
the Department's directives. As part of its rate restructuring proposal, the
Company will offer unbundled transportation and sales service to a broader
range of customers.
As more customers elect to purchase gas from third parties, a greater amount
of upstream pipeline capacity under contract may be idle, unless it can be
remarketed or assigned. The recoverability of cost for any such idle capacity
will be an issue for the Department to address for all utilities subject to
its jurisdiction. While there can be no assurance, it is the Company's
position that it should be afforded the opportunity to recover prudently
incurred, non-mitigable stranded capacity cost.
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.
3
<PAGE>
SEASONALITY AND WORKING CAPITAL
The Company's revenues, earnings and cash flows are highly seasonal as the
demand for most of its transportation services and sales is 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 is financed through short-term borrowings. Short-term borrowings are
also required from time to time to finance normal business operations. As a
result, short-term borrowings are generally highest during the late fall and
early winter.
ENVIRONMENTAL MATTERS
The Company may have to share responsibility under applicable environmental
law for the remediation of certain former manufactured gas plant ("MGP")
sites, as described in Note 11 of Notes to Financial Statements. 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. The Company does not possess at this time sufficient information to
reasonably determine the ultimate cost to it of such remediation and no
assurance can be given with respect to the future recoverability of such
costs. However, in light of the factors discussed above, the Company believes
that it is not probable that such costs will materially affect its financial
condition or results of operations.
EMPLOYEES
As of December 31, 1995, the Company had approximately 1,550 employees, 73%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 1999. The approximate 10% reduction in
staffing from the prior year was accomplished through attrition and early
retirement and severance programs for both management and union employees
associated with the Company's ongoing reengineering program.
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
numerous locations throughout its service territory.
On December 31, 1995, the Company's distribution system included
approximately 5,800 miles of gas mains, 397,000 services and 525,000 active
customer meters.
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 1995, the Company's capital expenditures were $57.3 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 $60.0
million for similar purposes in 1996.
ITEM 3. LEGAL PROCEEDINGS.
Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted to a vote of Security Holders in the fourth quarter
of 1995.
4
<PAGE>
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 from the city gate to the customer's burner tip, balancing
daily swings in customer loads, storage, and peak-shaving services.
BURNER TIP--Ultimate point of consumption of natural gas at the customer's
end-use equipment.
CAPACITY--The maximum capability of pipelines and supplemental facilities to
deliver and/or store gas at a given time.
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 natural gas.
LOCAL DISTRIBUTION COMPANY (LDC)--A utility that owns and operates a natural
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.
MERCHANT BUSINESS--Business of purchasing and selling natural gas.
NON-CORE CUSTOMERS--Generally, those customers with readily available,
economically viable alternatives to natural gas, and/or are of sufficient size
to arrange for their own energy supplies.
NON-FIRM SERVICE--Sales and transportation service that offers service at a
lower cost and level of reliability. 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
alternative fuel.
TRANSITION COSTS--Pursuant to FERC Order 636, these are costs incurred by
interstate pipelines as they unbundled their services and exited the merchant
business. Transition costs include uncovered gas costs at the time the
pipelines ceased the merchant function, stranded costs or unrecovered costs of
assets that cannot be assigned to customers of unbundled services, and gas
supply realignment costs or the costs of renegotiating existing gas supply
contracts with producers.
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 use. 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.
5
<PAGE>
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, 1995.
Dividends on such common equity amounted to $11.9 million and $12.8 million
for 1995 and 1994, respectively. At December 31, 1995, 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.
1995 COMPARED TO 1994
Net earnings applicable to common stock for 1995 were $23.4 million, a
decrease of $1.8 million or 7% from 1994. Increased throughput to new and
existing customers, the recognition of lost margins associated with
conservation programs and the reimbursement of previously incurred
environmental expenses were offset primarily by lower customer consumption in
the heating markets and to a lesser extent weather. While weather in both 1995
and 1994 was essentially normal for the year as a whole, temperatures within
the year varied widely relative to normal and from year to year.
Higher operating costs, primarily non-recurring charges associated with
early retirement and severance programs for both management and union
employees, were partially offset by related labor savings and reduced weather-
related workload during the first half of the year. Work force reductions
resulted from the Company's reengineering project which focused on improving
customer service and lowering operating costs.
Also contributing to lower earnings were increased depreciation and property
tax expenses related to continued investments in system replacement and
expansion partially offset by a reduced provision for uncollectible accounts.
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 benefited from increased sales to new and existing
customers of 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.
LIQUIDITY AND CAPITAL RESOURCES
In 1995, the Company maintained committed lines of credit totaling $40.0
million, which were not renewed when they expired on December 31, 1995. To
meet cash requirements and support it's commercial paper program, the Company
has available up to $75.0 million of Eastern's committed credit agreement and
various uncommitted lines of credit. The Company also maintains a bank credit
agreement which supports the issuance of up to $90.0 million of commercial
paper to fund its inventory of gas supplies.
6
<PAGE>
During the fourth quarter of 1995, the Company issued $60.0 million of
Medium-Term Notes, Series C pursuant to a shelf registration filed on June 13,
1995. These notes have an average maturity of 26 years and a weighted average
interest rate of 7.08%. Proceeds from this issuance were used to complete an
in-substance defeasance of all outstanding 8 3/4% and 9% Debentures due 2001
with an aggregate principal amount of $60.0 million.
In connection with the defeasance, the Company has irrevocably requested
that the 9% Debentures be called on May 15, 1996 and the 8 3/4% Debentures be
called on December 15, 1996. Under the terms of the applicable debt
instruments, the Company has deposited U.S. Government Securities in an
irrevocable trust to cover principal, call premiums and interest to the call
dates.
The Company expects capital expenditures for 1996 to be approximately $60.0
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 expects that projected cash flow from operations, in combination
with currently available resources, is sufficient to meet 1996 capital
expenditure and working capital requirements, normal debt repayments and
dividends to its shareholders. 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 which the
Company believes are currently available to it will continue to be available
or will be available on terms and conditions advantageous to the Company.
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 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.
7
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES.
Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.
(3) LIST OF EXHIBITS.
<TABLE>
<C> <S>
3.1 --Restated Articles of Organization, as amended (Filed as Exhibit 3.1 to
the registration statement of the Company on Form S-3 (File No. 33-
48525)).*
3.2 --By-Laws of the Company as amended (Filed as Exhibit 1 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1976
(File No. 2-23416)).*
(Note: Certain instruments with respect to long-term debt of the
Company or its subsidiary are not filed herewith since no such
instrument authorizes securities in an amount greater than 10% of the
total assets of the Company and its subsidiary on 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 by the Company on Form
S-3 (File No. 33-31869)).*
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).*
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).*
</TABLE>
8
<PAGE>
<TABLE>
<C> <S>
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.
</TABLE>
There were no reports on Form 8-K filed in the Fourth Quarter of 1995.
- - --------
* 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.
9
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES AND
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Boston Gas Company
Registrant
By: J.F. Bodanza
---------------------------------
J.F. BODANZA SENIOR VICE PRESIDENT
AND TREASURER (PRINCIPAL FINANCIAL
AND ACCOUNTING OFFICER)
Dated: March 18, 1996
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 18TH DAY OF MARCH 1996.
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
- - ------------------------------------- and Treasurer (Principal Financial
J. F. BODANZA and Accounting Officer)
J. A. Ives Director
- - -------------------------------------
J. A. IVES
R. R. Clayton Director
- - -------------------------------------
R. R. CLAYTON
W. J. Flaherty Director
- - -------------------------------------
W. J. FLAHERTY
10
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(INFORMATION REQUIRED BY ITEMS 8 AND 14 (A) OF FORM 10-K)
<TABLE>
<S> <C>
Report of Independent Public Accountants.......................... F-17
Consolidated Balance Sheets as of December 31, 1995 and 1994.... F-2 and F-3
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1995.............................................. F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1995........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1995.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-16
Interim Financial Information for the Two Years Ended December
31, 1995 (Unaudited)........................................... F-18
Schedules for the Three Years Ended December 31, 1995:
II--Valuation and Qualifying Accounts......................... F-19 to F-21
</TABLE>
Schedules other than those listed above have been omitted as the information
has been included in the consolidated financial statements and related notes
or is not applicable nor required.
Separate financial statements of the Company are omitted because the Company
is primarily an operating company and its subsidiary is wholly-owned and is
not indebted to any person in an amount that is in excess of 5% of total
consolidated assets.
F-1
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Gas plant, at cost........................................... $761,607 $704,861
Construction work-in-progress................................ 486 2,070
Less--Accumulated depreciation............................. 254,448 222,460
-------- --------
Net plant.................................................. 507,645 484,471
Current assets:
Cash....................................................... 5,841 3,831
Accounts receivable, less reserves of $15,324 at December
31, 1995 and $15,621 at December 31, 1994................. 74,519 71,408
Deferred gas costs......................................... 71,940 66,865
Natural gas and other inventories, at average cost......... 35,136 46,844
Materials and supplies, at average cost.................... 4,770 5,063
Prepaid expenses........................................... 3,259 3,399
Income taxes............................................... 368 1,407
-------- --------
Total current assets..................................... 195,833 198,817
Other assets:
Deferred postretirement benefits cost...................... 93,829 97,589
Deferred charges and other assets.......................... 32,180 52,759
-------- --------
Total other assets....................................... 126,009 150,348
-------- --------
Total assets............................................. $829,487 $833,636
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDER'S INVESTMENT
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Capitalization:
Stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1995 and 1994............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 119,546 108,098
-------- --------
Total common stockholder's investment.................... 214,197 202,749
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized and outstanding--1,200,000 shares at December
31, 1995 and 1994......................................... 29,262 29,229
Long-term obligations, less current portion................. 212,772 216,680
-------- --------
Total capitalization..................................... 456,231 448,658
Gas inventory financing..................................... 45,600 53,578
-------- --------
Total capitalization and gas inventory financing......... 501,831 502,236
Current liabilities:
Current portion of long-term obligations................... 1,509 1,890
Notes payable.............................................. 52,000 62,530
Accounts payable........................................... 53,490 42,653
Accrued taxes.............................................. 1,011 510
Accrued interest........................................... 3,959 3,524
Customer deposits.......................................... 2,789 2,852
Refunds due customers...................................... 13,173 18,719
Pipeline transition costs.................................. 9,510 11,560
-------- --------
Total current liabilities.................................. 137,441 144,238
Commitments and contingencies:
Reserves and deferred credits:
Deferred income taxes...................................... 72,001 66,577
Unamortized investment tax credits......................... 7,767 8,704
Postretirement benefits obligation......................... 86,589 90,214
Other...................................................... 23,858 21,667
-------- --------
Total reserves and deferred credits...................... 190,215 187,162
-------- --------
Total liabilities and stockholder's investment........... $829,487 $833,636
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF EARNINGS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues................................ $653,073 $660,158 $614,294
Cost of gas sold.................................. 374,904 382,885 375,103
-------- -------- --------
Operating margin.................................. 278,169 277,273 239,191
Operating expenses:
Other operating expenses........................ 156,794 150,847 133,187
Maintenance..................................... 21,449 24,826 29,376
Depreciation and amortization................... 38,264 35,809 27,566
Income taxes.................................... 16,258 17,737 12,105
-------- -------- --------
232,765 229,219 202,234
-------- -------- --------
Operating earnings................................ 45,404 48,054 36,957
Other earnings, net............................... 726 65 278
-------- -------- --------
Earnings before interest expense.................. 46,130 48,119 37,235
Interest expense:
Long-term debt.................................. 18,633 17,024 15,447
Other, including amortization of debt expense... 2,693 4,841 2,957
Less-Interest during construction............... (499) (894) (583)
-------- -------- --------
20,827 20,971 17,821
-------- -------- --------
Net earnings...................................... 25,303 27,148 19,414
Preferred stock dividends......................... 1,926 1,926 1,389
-------- -------- --------
Earnings applicable to common stock............... $ 23,377 $ 25,222 $ 18,025
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1995 1994 1993
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance at Beginning of Year...................... $108,098 $ 95,680 $86,653
Net earnings.................................... 25,303 27,148 19,414
Preferred stock dividends ($1.61 per share in
1995 and 1994, and $1.16 per share in 1993).... (1,926) (1,926) (1,389)
Cash dividends on common stock ($23.20 per share
in 1995, $24.90 per share in 1994, and $17.50
per share in 1993)............................. (11,929) (12,804) (8,998)
-------- -------- -------
Balance at End of Year............................ $119,546 $108,098 $95,680
======== ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1995 1994 1993
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.................................... $ 25,303 $ 27,148 $ 19,414
Adjustments to reconcile net earnings to cash
(used for) provided by operating activities:
Depreciation and amortization.................. 38,264 35,809 27,566
Deferred taxes................................. 5,424 5,016 8,837
Other changes in assets and liabilities:
Accounts receivable........................... (3,111) 17,688 (15,840)
Inventory..................................... 12,001 6,264 (10,381)
Deferred gas costs............................ 17,763 (23,901) (24,933)
Accounts payable.............................. 10,837 (10,121) (198)
Federal and state income taxes................ 1,039 4,639 (998)
Refunds due customers......................... (5,546) 10,690 (5,032)
Other......................................... (969) 7,164 (3,849)
-------- -------- --------
Cash (used for) provided by operating activities. 101,005 80,396 (5,414)
-------- -------- --------
Cash flows used for investing activities:
Capital expenditures........................... (57,322) (53,504) (47,057)
Net cost of removal............................ (6,463) (6,412) (4,328)
-------- -------- --------
Cash used for investing activities............... (63,785) (59,916) (51,385)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. (10,530) (43,770) 52,968
Changes in inventory financing................. (7,978) (5,719) 10,666
Proceeds from issuance of long-term debt....... 60,000 50,000 --
Repayment of long-term debt.................... (62,880) (3,622) (20,480)
Proceeds/Amortization from issuance of
preferred stock............................... 33 32 (240)
Capital contribution from parent............... -- -- 20,000
Cash dividends paid on common and preferred
stock......................................... (13,855) (14,730) (10,255)
-------- -------- --------
Cash (used for) provided by financing activities. (35,210) (17,809) 52,659
-------- -------- --------
Increase (decrease) in cash...................... 2,010 2,671 (4,140)
Cash at beginning of year........................ 3,831 1,160 5,300
-------- -------- --------
Cash at end of year.............................. $ 5,841 $ 3,831 $ 1,160
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 20,752 $ 20,193 $ 18,559
Income taxes.................................. $ 10,128 $ 8,151 $ 7,813
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ACCOUNTING POLICIES
The accounting policies of Boston Gas Company (the "Company") conform to
generally accepted accounting principles and reflect the effects of the
ratemaking process in accordance with Statements of Financial Accounting
Standards No. 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
the demand for most of its transportation services and sales is directly
related to temperature conditions. The Company purchases pipeline gas supplies
from a variety of domestic and Canadian producers and marketers. Gas supplies
are purchased using a combination of long-term commitments, firm winter
service agreements and spot purchases. The Company has diversified its
pipeline gas supplies across major North American producing regions, including
western Canada.
Regulatory Assets
The Company is subject to the provisions of Statement of Financial
Accounting Standards 71, ("SFAS 71") "Accounting for the Effects of Certain
Types of Regulation". Regulatory assets represent probable future revenue to
the Company associated with certain costs which will be recovered from
customers through the ratemaking process. Regulatory liabilities represent
probable future reductions in revenues associated with amounts that are to be
credited to customers through the ratemaking process. The following regulatory
assets were reflected in the Consolidated Balance Sheets as of December 31:
F-7
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) ACCOUNTING POLICIES (CONTINUED)
<TABLE>
<CAPTION>
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Postretirement benefit costs............................ $ 93,829 $ 97,589
Deferred pipeline transition costs...................... 9,510 34,398
Deferred income taxes................................... 498 1,097
Environmental costs..................................... 3,591 806
Other................................................... 2,176 2,927
-------- --------
$109,604 $136,817
======== ========
</TABLE>
Regulatory liabilities total $12,391,000 and $13,341,000 at December 31,
1995 and 1994 and relate primarily to income taxes.
As of December 31, 1995 all of the Company's regulatory assets and
regulatory liabilities are being reflected in rates charged to customers over
periods ranging from 1 to 24 years. For additional information regarding
deferred income taxes, Order 636 transition costs, environmental costs and
postretirement benefit costs, see footnotes 3, 12, 11, and 7 respectively.
If a portion of the Company's operations is no longer subject to the
provisions of SFAS 71, a write off of related regulatory assets and
liabilities would be required, unless some form of transition cost recovery
(refund) continues through rates established and collected for the Company's
remaining regulated operations.
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 5.13% in 1995, 5.16% in 1994
and 3.98% in 1993.
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 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. The cost of gas
adjustment clause also recovers 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.
F-8
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 39.1% in 1995, 39.5% in 1994, and 38.4% in 1993. State taxes represent the
majority of the difference between the effective rate and the Federal income
tax rate for 1995, 1994 and 1993.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current--
Federal........................................... $10,603 $ 7,966 $ 4,063
State............................................. 2,136 591 771
------- ------- -------
Total current provision......................... 12,739 8,557 4,834
Deferred--
Federal........................................... 2,896 6,796 5,951
State............................................. 623 2,384 1,320
------- ------- -------
Total deferred provision........................ 3,519 9,180 7,271
------- ------- -------
Provision for income taxes.......................... $16,258 $17,737 $12,105
======= ======= =======
</TABLE>
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, 1995 the balance of
the regulatory asset was $498,000. 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, 1995 was $4,440,000. 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, 1995 the balance to
be returned to customers was $7,951,000.
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 assets and deferred tax liabilities at December 31,
1995 and 1994, are as follows:
F-9
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) INCOME TAXES (CONTINUED)
<TABLE>
<CAPTION>
1995 1994
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
ASSETS:
Unbilled revenues................................. $ 24,637 $ 30,978
Reserve for uncollectible receivables............. 6,010 6,127
Regulatory liabilities............................ 4,860 5,233
Other............................................. 9,323 8,146
--------- ---------
Total deferred tax assets......................... $ 44,830 $ 50,484
--------- ---------
LIABILITIES:
Accelerated depreciation.......................... $ (78,115) $ (73,277)
Deferred gas costs................................ (16,296) (23,455)
Other............................................. (22,635) (21,812)
--------- ---------
Total deferred tax liabilities.................... $(117,046) $(118,544)
--------- ---------
Total deferred taxes.............................. $ (72,216) $ (68,060)
========= =========
</TABLE>
Investment tax credits are deferred and credited to income over the lives of
the property giving rise to such credits. The credit to income was
approximately $937,000 in 1995, $723,000 in 1994 and $689,000 in 1993.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
8.75%--9.00%, Sinking Fund Debentures due 2001.......... $ -- $ 60,000
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 --
First Mortgage Bonds--8.375% Series, due 1996........... -- 2,880
Capital lease obligations (Note 8)...................... 4,280 5,690
Less current portion.................................... (1,508) (1,890)
-------- --------
Total long-term obligations........................... $212,772 $216,680
======== ========
</TABLE>
In 1995, the Company filed a shelf registration covering the issuance
through 1997 of up to $100,000,000 of Medium-Term Notes. In October and
November 1995, the Company issued $60,000,000 of Medium-Term Notes, Series C,
with a weighted average maturity of 26 years and a coupon of 7.08%. The
proceeds from this issuance were used to complete an in-substance defeasance
of $60,000,000 principal amount of 8.75%--9.00% Debentures due 2001. In
connection with the defeasance the Company has irrevocably requested that the
Debenture Trustee call the Debentures on the first date that they can be
redeemed with lower cost debt. In December 1995, the Company deposited
$65,136,000 of U.S. government securities into an irrevocable trust to cover
the principal amount called, the call premiums of $1,161,000 and interest to
the date of call of $3,975,000. As a result of the in-substance defeasance,
the debt has been considered extinguished; accordingly, the government
securities and
F-10
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
$60,000,000 principal amount of Debentures due 2001 were removed from the
balance sheet at December 31, 1995. Pursuant to regulatory accounting, the in-
substance defeasance transaction resulted in the deferral of $2,250,000 as
debt issuance costs to be amortized over the lives of the newly issued Medium-
Term Notes.
On September 1, 1995 the Company redeemed all of the outstanding principal
amount of 8.375% First Mortgage Bonds due 1996 at a redemption price of 100%.
In 1994 the Company issued $50,000,000 of Medium-Term Notes, Series B, with
a weighted average maturity of 21 years and a coupon 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. Proceeds from the
issuance reduced current debt.
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, 1995 and
none are callable prior to maturity.
Annual maturities of capital lease obligations are $1,508,000, $1,029,000,
$507,000, $561,000 and $620,000 for 1996 through 2000, respectively.
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, 1995 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 Massachusetts
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 long-term 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 $45,600,000 and $53,578,000 of
commercial paper outstanding to fund its inventory of gas supplies at December
31, 1995 and 1994, 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
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 the agent bank's prime rate or, at the Company's option
various alternatives. The agreement requires a facility fee of 1/12 of 1% on
the commitment. No borrowings were outstanding under this agreement during
1995 and 1994.
Eastern Borrowing Arrangement
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 29, 2000. The interest rate for such borrowings is the
agent bank's prime rate, or at Eastern's option, various alternatives.
Notes Payable
In addition to the Eastern borrowing arrangement, the Company maintained
committed lines of credit totaling $40,000,000 during 1995 and 1994 which were
not renewed.
F-11
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS--(CONTINUED)
The Company has various uncommitted lines of credit which provide for
interest as a function of federal funds, money market or prime rates. These
uncommitted lines of credit are used, in conjunction with commercial paper,
for working capital needs. The Company had outstanding borrowings of
$52,000,000 and $62,530,000 in commercial paper not related to gas inventory
financing at December 31, 1995 and 1994, respectively. The weighted average
interest rate on these borrowings at December 31, was 5.93% in both 1995 and
1994.
(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:
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost-benefits earned during the year.... $ 2,710 $ 2,637 $ 2,331
Interest cost on projected benefit obligation... 8,055 7,556 7,304
Actual return on plan assets.................... (21,762) (4,431) (15,984)
Net amortization and deferral................... 13,773 (3,281) 7,105
-------- ------- --------
Net pension cost................................ $ 2,776 $ 2,481 $ 756
======== ======= ========
</TABLE>
For the periods 1995 and 1994, 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 1995 and 5% in
1994.
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.
<TABLE>
<CAPTION>
1995 1994
--------- --------
(IN THOUSANDS)
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $94,526 in 1995 and $89,283 in 1994..... $ 103,880 $ 98,248
========= ========
Projected benefit obligation for service rendered to
date................................................ (116,358) (109,974)
Plan assets at fair value, primarily listed stocks,
corporate bonds and U.S. bonds...................... 129,190 115,080
--------- --------
Plan assets in excess of projected benefit
obligation.......................................... 12,832 5,106
Unrecognized net obligation at January 1, 1986 being
recognized over 15 years............................ 1,088 1,305
Unrecognized net gain................................ (19,886) (12,377)
Unrecognized prior service cost...................... 13,000 14,048
--------- --------
Net pension asset.................................... $ 7,034 $ 8,082
========= ========
</TABLE>
F-12
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 that the employee renders service. As of the date
of adoption of Statement of Financial Accounting Standards No. 106
("SFAS106"), "Employees Accounting for Postretirement Benefits Other Than
Pensions" 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 costs included the following components:
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost-benefits earned during the year..... $ 729 $ 731 $ 1,301
Interest cost on accumulated benefit obligation.. 5,645 5,238 7,021
Net amortization and deferral of actuarial gains
and losses...................................... (4,752) (2,617) (1,235)
Actual return on plan assets..................... 2,352 (755) (282)
------- ------- -------
Postretirement benefit cost...................... 3,974 2,597 6,805
Amortization (deferral) of regulatory asset...... 3,760 3,472 (2,275)
------- ------- -------
Net postretirement benefit cost.................. $ 7,734 $ 6,069 $ 4,530
======= ======= =======
</TABLE>
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.
<TABLE>
<CAPTION>
1995 1994
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Retirees................................................ $(57,580) $(56,662)
Other fully eligible participants....................... (5,973) (7,838)
Other active participants............................... (14,671) (13,043)
-------- --------
(78,224) (77,543)
Plan assets at fair value............................... 16,563 11,611
-------- --------
Accumulated postretirement benefits obligation in excess
of plan assets......................................... (61,661) (65,932)
Unrecognized actuarial gain............................. (12,521) (10,685)
Unrecognized prior service costs........................ (12,407) (13,597)
-------- --------
Accrued postretirement benefits......................... $(86,589) $(90,214)
======== ========
</TABLE>
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. The Company contributed
$2,600,000 to the VEBA in 1995. 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 1995 and 1994. A 10% and 11% annual
increase in the cost of covered health care benefits was
F-13
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED)
assumed for 1995 and 1994, respectively. This rate of increase is assumed to
drop gradually to 5% after 5 years. A 1% increase in the assumed health care
cost trend would have increased the postretirement benefit cost by $541,000 in
1995 and $529,000 in 1994, and the accumulated postretirement benefit
obligation by $6,300,000 in 1995 and $6,302,000 in 1994.
(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
$8,826,000 in 1995, $8,323,000 in 1994 and $7,663,000 in 1993.
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 is as follows:
<TABLE>
<CAPTION>
1995 1994
------- -------
(IN THOUSANDS)
<S> <C> <C>
LNG facilities.............................................. $15,600 $15,600
Buildings................................................... 6,000 6,000
------- -------
21,600 21,600
Less-Accumulated depreciation............................... 17,320 15,910
------- -------
Total Capital Leases...................................... $ 4,280 $ 5,690
======= =======
</TABLE>
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 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 noncancelable leases, including the financing leases, at
December 31, 1995 is as follows:
<TABLE>
<CAPTION>
CAPITAL OPERATING
YEAR LEASES LEASES
---- ------- ---------
(IN THOUSANDS)
<S> <C> <C>
1996.................... $1,854 $ 4,546
1997.................... 1,269 2,886
1998.................... 684 1,398
1999.................... 686 904
2000.................... 687 323
Later Years............. 57 --
------ -------
Total minimum lease
payments............... $5,237 $10,057
=======
Less-Amount representing
interest and executory
costs.................. 957
------
Present value of minimum
lease payments on
capital leases......... $4,280
======
</TABLE>
F-14
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 1995 and 1994 is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
1995 1994
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash..................................... $ 5,841 $ 5,841 $ 3,831 $ 3,831
Short-term debt.......................... $ 97,600 $ 97,600 $116,108 $116,108
Long-term debt........................... $214,281 $241,757 $218,570 $214,584
Preferred stock.......................... $ 29,262 $ 28,829 $ 29,229 $ 26,250
</TABLE>
(10) SUPPLEMENTARY INFORMATION
The Company paid Eastern $4,117,000 in 1995, $3,669,000 in 1994, and
$3,096,000 in 1993 for various legal, tax and corporate services rendered.
(11) ENVIRONMENTAL ISSUES
The Company, like many other companies in the natural gas industry, is party
to governmental actions requiring investigation and possible remediation of
former manufactured gas plant ("MGP") sites. The Company currently owns 15
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 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 ten other sites owned by the Company, subject to limited
contribution by the Company. The Company is working with the Massachusetts
Department of Environmental Protection (the "DEP") to determine the extent of
remediation which may be required at the four former MGP sites currently owned
by the Company and not covered by the
F-15
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(11) ENVIRONMENTAL ISSUES (CONTINUED)
Settlement Agreement or the Boyd decision. The Company expects to spend
approximately $1 million in 1996 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, and no assurance can be given with respect to
the future recoverability of such costs. However, management 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 and the rate
order discussed below. 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 $44,520,000
at December 31, 1995 and it has recorded this amount less actual billings of
$35,010,000 as a liability in the accompanying consolidated balance sheet. As
pipelines continue to file for recovery of transition costs, the Company's
obligation may increase.
On March 8, 1995 the Department issued an order allowing for the recovery of
the Company's transition costs liability over one year. Accordingly, at
December 31, 1995 the Company has recorded a regulatory asset of $9,510,000
and deferred gas costs of $19,363,000 which, taken together plus recoveries to
date, is equivalent to the Company's total estimated obligation for transition
costs.
F-16
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Boston Gas Company:
We have audited the accompanying consolidated balance sheets of Boston Gas
Company (a Massachusetts Corporation and wholly-owned subsidiary of Eastern
Enterprises) and subsidiary as of December 31, 1995 and 1994, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1995. 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, 1995 and 1994 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1995, 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 23, 1996
F-17
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION
FOR THE TWO YEARS ENDED DECEMBER 31, 1995 (UNAUDITED)
The following table summarizes the Company's reported quarterly information
for the years ended December 31, 1995 and 1994:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
1995
Operating revenues........................ $294,241 $129,616 $56,957 $172,259
Operating margin.......................... 111,910 58,772 33,857 73,630
Operating earnings (loss)................. 29,306 6,888 (4,732) 13,942
Net earnings (loss) applicable to common
stock.................................... 23,197 1,678 (9,833) 8,335
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
</TABLE>
F-18
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1994 TO INCOME ACCOUNTS RESERVES 1995
- - ----------- ------------ --------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
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
FAS 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
======== ======= ====== ======= ========
</TABLE>
F-19
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1993 TO INCOME ACCOUNTS RESERVES 1994
- - ----------- ------------ --------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
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
deferred credits--
Reserve for self-
insurance........... 2,270 1,429 -- 1,441 2,258
FAS 109 Regulatory
Liability........... 5,512 -- -- 467 5,045
Deferred net
normalization
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 $16,860 $(3,565) $11,200 $187,162
======== ======= ======= ======= ========
</TABLE>
F-20
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1992 TO INCOME ACCOUNTS RESERVES 1993
- - ----------- ------------ --------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
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 $18,440 $ 7,500 $18,995 $185,067
======== ======= ======= ======= ========
</TABLE>
F-21
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 507,645
<OTHER-PROPERTY-AND-INVEST> 2,547
<TOTAL-CURRENT-ASSETS> 195,833
<TOTAL-DEFERRED-CHARGES> 29,633
<OTHER-ASSETS> 93,829
<TOTAL-ASSETS> 829,487
<COMMON> 51,418
<CAPITAL-SURPLUS-PAID-IN> 43,233
<RETAINED-EARNINGS> 119,546
<TOTAL-COMMON-STOCKHOLDERS-EQ> 214,197
29,262
0
<LONG-TERM-DEBT-NET> 210,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 97,600
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 2,772
<LEASES-CURRENT> 1,509
<OTHER-ITEMS-CAPITAL-AND-LIAB> 274,147
<TOT-CAPITALIZATION-AND-LIAB> 829,487
<GROSS-OPERATING-REVENUE> 653,073
<INCOME-TAX-EXPENSE> 16,258
<OTHER-OPERATING-EXPENSES> 156,777
<TOTAL-OPERATING-EXPENSES> 232,765
<OPERATING-INCOME-LOSS> 45,404
<OTHER-INCOME-NET> 726
<INCOME-BEFORE-INTEREST-EXPEN> 46,130
<TOTAL-INTEREST-EXPENSE> 20,827
<NET-INCOME> 25,303
1,926
<EARNINGS-AVAILABLE-FOR-COMM> 23,377
<COMMON-STOCK-DIVIDENDS> 11,929
<TOTAL-INTEREST-ON-BONDS> 18,633
<CASH-FLOW-OPERATIONS> 101,005
<EPS-PRIMARY> 45.46
<EPS-DILUTED> 45.46
</TABLE>
