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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, 1996
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:
<TABLE>
<CAPTION>
TITLE
OF EACH NAME OF EACH EXCHANGE ON
CLASS WHICH REGISTERED
------- ------------------------
<S> <C>
None None
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
Indicate by Check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this form 10-K or any
amendment to this form 10-K.
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 10, 1997.
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, 1996
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I
Item 1. Business
PAGE
----
<S> <C>
General................................................................................ 1
Markets and Competition................................................................ 1
Gas Throughput......................................................................... 1
Gas Supply............................................................................. 2
Regulation............................................................................. 3
Seasonality and Working Capital........................................................ 3
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>
PART I
ITEM 1. BUSINESS.
GENERAL
Boston Gas Company (the "Company"), is engaged in the transportation and
sale of natural gas to approximately 525,000 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 174 years and is
the second oldest gas company in the United States. All of the common stock of
the Company is held by Eastern Enterprises ("Eastern"), which is headquartered
in Weston, Massachusetts. Eastern has owned Boston Gas Company since 1929.
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 5.
The Company provides both local transportation services and gas supply for
all customer classes. All residential customers currently purchase combined or
"bundled" supply and transportation services from the Company. In 1993, the
Massachusetts Department of Public Utilities ("the Department") approved the
Company's proposal to unbundle local transportation service and gas sales
service for its largest commercial and industrial customers. In 1996, 143 of
the approximately 450 eligible customers purchased gas supplies from third
parties. In November 1996, the Department approved the Company's proposal to
offer unbundled transportation service to all of its commercial and industrial
customers, numbering over 41,000. In December 1996, an additional 129
customers chose to purchase gas from 14 third party suppliers. The Company
views these suppliers as partners in marketing gas and increasing throughput
on the Company's system and continues to work closely with them to ensure that
competitively priced gas supplies can be reliably delivered to customers.
The Company offers both firm and non-firm services. Firm local
transportation services and sales are provided under rate tariffs filed with
the Department that typically obligate the Company to provide service without
interruption throughout the year. Non-firm transportation services and sales
are generally provided to large commercial and industrial customers who can
use gas and oil interchangeably, or to other gas companies for resale.
MARKETS AND COMPETITION
The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. Over the last six years, the Company has
increased its share in the total stationary energy market from 28% to 36%.
This market share compares to the national level 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, the level of investment by the Company
and customer perceptions of relative value.
Residential customers comprise 92% of its customer base, while commercial
and industrial establishments account for the remaining 8%. Volumetrically,
residential customers account for 30% of total throughput and 36% of total
firm throughput, while commercial and industrial customers account for 70% of
total throughput and 64% of total firm throughput. In 1996, approximately 60%
of commercial and industrial customers' total throughput was local
transportation only services.
GAS THROUGHPUT
The following table, in billions of cubic feet of natural gas at 1,000 Btu
per cubic foot ("BCF") provides information with respect to the volumes of gas
delivered by the Company during the three years 1994-1996.
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Residential.................................... 42.8 39.7 41.4
Commercial and industrial...................... 39.4 48.1 46.7
Off-system sales............................... 12.2 6.6 7.6
-------- -------- --------
Total sales.................................. 94.4 94.4 95.7
Transportation of customer-owned gas........... 61.6 47.5 48.7
Less: Off-system sales......................... (12.2) (6.6) (7.6)
-------- -------- --------
Total throughput............................. 143.8 135.3 136.8
======== ======== ========
Total firm throughput........................ 118.7 94.9 95.5
======== ======== ========
</TABLE>
No customer, or group of customers under common control, accounted for 2% or
more of total firm revenues in 1996.
GAS SUPPLY
The following table in BCF provides statistical information with respect to
the Company's sources of supply during 1994-1996.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Natural gas pipeline purchased................. 91.7 93.4 92.2
Liquefied natural gas ("LNG") purchases........ 5.2 3.1 5.1
-------- -------- --------
Total purchases.............................. 96.9 96.5 97.3
Change in storage gas.......................... (3.4) 3.5 0.4
Company use, unbilled and other................ .9 (5.6) (2.0)
-------- -------- --------
Total sales.................................. 94.4 94.4 95.7
======== ======== ========
</TABLE>
Year to year variations in storage gas and unbilled gas reflects variations
in end-of-year customer requirements, due principally to weather. Given the
ready availability of supply, the Company purchased approximately two-thirds
of its peak pipeline supplies under firm short-term and spot contracts. The
balance of peak day pipeline requirements are purchased directly from domestic
and Canadian producers and marketers pursuant to long-term contracts which
have been reviewed and approved by the Department or by the Federal Energy
Regulatory Commission ("FERC").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights 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 ("Al-
gonquin")................................ 0.28 87.4 1997-2012
Tennessee Gas Pipeline Company ("Tennes-
see").................................... 0.18 66.9 2000-2012
-------- ---------
0.46 154.3
======== =========
</TABLE>
In addition, the Company has firm capacity contracts on interstate pipelines
upstream of Algonquin and Tennessee pipelines to transport natural gas
purchased by the Company from producing regions to the Algonquin and Tennessee
pipelines. In total, contracts comprising 59% of the Company's peak day
pipeline capacity entitlements expire before 2001.
2
<PAGE>
The Company has contracted with pipeline companies and others for the
storage of natural gas in underground storage fields located in Pennsylvania,
New York, Maryland and West Virginia. These contracts provide storage capacity
of 17.3 BCF and peak day deliverability of 0.16 BCF. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are purchased
and produced from foreign and domestic sources.
Peak day throughput in BCF was 0.69 in 1996 and 1995, and 0.65 in 1994. 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, gas purchases, pipeline safety regulations, issuance of
securities, and affiliate transactions are regulated by the Department. Rates
for firm transportation and sales provided by the Company are subject to
approval by, and are on file with, the Department. In addition, the Company
has a cost of gas adjustment clause that allows for the adjustment of billing
rates for firm gas sales to enable it to recover the actual cost of gas
delivered to firm customers, including the demand charges for capacity on the
interstate pipeline system.
On November 29, 1996, the Department issued its order on the Company's rate
restructuring and unbundling plan. In its order, the Department granted a $6.3
million rate increase effective December, 1996 and modified the Company's
proposed performance-based regulatory plan. The Department ordered a five year
performance-based regulatory plan that prescribes the formula for annual rate
adjustments with a 2% productivity offset and service quality penalties with a
maximum exposure of $5 million, which significantly exceeded those proposed by
the Company. The Company will likely appeal the Department's Order.
In its order, the Department approved the Company's proposal to facilitate
competition in the natural gas marketplace. Under the approved service
unbundling program, on an interim basis, eligible commercial and industrial
customers migrating from firm sales to firm transportation will be assigned,
at cost, a pro-rata share of the upstream pipeline capacity purchased by the
Company to serve them. The Department also stated that the permanent
assignment of upstream pipeline capacity would be addressed in future
regulatory proceedings. The permanent capacity assignment method approved by
the Department could permit capacity to be acquired by marketers at less than
cost. While there can be no assurance until the Department has addressed the
recoverability of such stranded costs for all gas utilities subject to its
jurisdiction, the Company is confident that it will be allowed a reasonable
opportunity to recover any non-mitigable stranded costs resulting from the
method approved.
The Company and Eastern were granted an intrastate exemption from the
provisions of the Public Utility Holding Company Act of 1935 ("the Act") under
Section 3(a)(1) thereof, pursuant to an order of the Securities and Exchange
Commission (the "SEC") dated February 28, 1955, as amended by orders dated
November 3, 1967 and August 28, 1975.
SEASONALITY AND WORKING CAPITAL
The Company's revenues, earnings and cash flow are highly seasonal as most
of its transportation services and sales are directly related to temperature
conditions. The majority of the Company's earnings are generated in the first
quarter with a seasonal loss occurring in the third quarter. Since the bulk of
its revenues are billed in
3
<PAGE>
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 of these factors, short-term borrowings are
generally highest during the late fall and early winter.
ENVIRONMENTAL MATTERS
The Company may have or share responsibility under applicable environmental
law for the remediation of 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 sites owned by the Company, subject to a limited contribution by the
Company. 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 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, 1996, the Company had approximately 1,500 employees, 73%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 1999.
ITEM 2. PROPERTIES.
The Company and Mass LNG 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. Negotiations are under way with the lessor of the Lynn and
Salem facilities in connection with the scheduled expiration of these leases
in June 1997. The Company owns propane-air facilities at several locations
throughout its service territory.
On December 31, 1996, the Company's distribution system included
approximately 5,800 miles of gas mains, 399,000 services and 529,000 active
customer meters. A majority of the gas mains consist of cast iron and bare
steel which requires ongoing maintenance and replacement.
The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned in fee.
In 1996, the Company's capital expenditures were $58.5 million. Capital
expenditures were principally made for system replacement, for system
expansion to meet customer demand and productivity enhancement initiatives.
The Company plans to spend approximately $51 million for similar purposes in
1997.
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 1996.
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.
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.
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.
PERFORMANCE-BASED REGULATORY PLAN--Incentive ratemaking mechanism, typically
a price cap plan, where rates over a specified period are adjusted annually
pursuant to a pre-determined formula tied to a measure of inflation, less a
productivity offset, subject to the achievement of service quality thresholds
and the incurrence of exogenous costs.
THROUGHPUT--volume delivered to customers through the local transportation
system.
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, 1996.
Dividends on such common equity amounted to $14.7 million and $11.9 million
for 1996 and 1995, respectively. At December 31, 1996, 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.
1996 COMPARED TO 1995
Net earnings applicable to common stock for 1996 were $29.1 million, an
increase of $5.8 million or 25% from 1995. This increase primarily reflects
colder billing temperatures ($3.0 million), increased consumption from new and
existing customers ($4.7 million) and the absence of reengineering related
charges ($3.9 million). Weather for 1996 was 5% colder than 1995 and 4% colder
than normal. These factors were somewhat offset by higher operating expenses,
principally wages, benefits and marketing related costs. Increased
depreciation charges and property tax expense reflect continued investments in
system expansion and replacement.
The reduction in interest expense reflects the refinancing during the fourth
quarter of 1995 and lower borrowing requirements.
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 primarily offset 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.
Higher operating costs, primarily non-recurring charges associated with
early retirement and severance programs for both management and union
employees, were somewhat 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.
LIQUIDITY AND CAPITAL RESOURCES
To meet cash requirements and support its commercial paper program, the
Company has available up to $75.0 million of Eastern's committed credit
agreement and an uncommitted line of credit. The Company also maintains a bank
credit agreement which supports the issuance of up to $70.0 million of
commercial paper to fund its inventory of gas supplies.
The Company expects capital expenditures for 1997 to be approximately $51.0
million. Capital expenditures will be largely for improvements to the
distribution system, for system expansion to meet customer demand and for
productivity improvements.
6
<PAGE>
The Company estimates that projected cash flow from operations, in
combination with currently available resources, is sufficient to meet 1997
capital expenditure and working capital requirements, normal debt repayments
and dividends to 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.
On November 29, 1996, the Department issued its order on the Company's rate
restructuring and unbundling plan. In its order, the Department granted a $6.3
million rate increase effective December, 1996 and modified the Company's
proposed performance-based regulatory plan. The Department ordered a five year
performance-based regulatory plan that prescribes the formula for annual rate
adjustments with a 2% productivity offset and service quality penalties with a
maximum exposure of $5 million, which significantly exceeded those proposed by
the Company. The Company will likely appeal the Department's Order.
In its order, the Department also approved the Company's proposal to
facilitate competition in the natural gas marketplace. Under the approved
service unbundling program, on an interim basis, eligible commercial and
industrial customers migrating from firm sales to firm transportation will be
assigned, at cost, a pro-rata share of the upstream pipeline capacity
purchased by the Company to serve them.
The Company may have or share responsibility under applicable environmental
law for the remediation of certain former manufactured gas plant ("MGP")
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 sites owned by the Company, subject to a limited contribution by the
Company. 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.
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 a consolidated basis.
The Company agrees to furnish to the Securities and Exchange Commission
upon request a copy of any such omitted instrument of the Company or
its subsidiary.)
4.1 --Indenture dated as of December 1, 1989 between the Company and The
Bank of New York, Trustee (Filed as Exhibit 4.2 to the registration
statement of the Company on Form S-3 (File No. 33-31869)).*
4.1.1 --Agreement of Registration, Appointment and Acceptance dated as of
November 18,1992 among the Company, The Bank of New York as Resigning
Trustee, and The First National Bank of Boston as Successor Trustee.
(Filed as an exhibit to registration statement of the Company on Form
S-3 (File No. 33-31869)).*
10.1 --Gas Transportation Contract between 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 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).*
</TABLE>
8
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<TABLE>
<C> <S>
10.7 --Gas Storage Agreement between the Company and Honeoye Storage
Corporation dated October 11, 1985 (Filed as Exhibit 10.17 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1985).*
10.8 --Gas Storage Agreement between the Company and PennYork Energy
Corporation dated as of December 21, 1984 (Filed as Exhibit 10.18 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1985).*
10.9 --Gas Sales Contract between the Company and Esso Resources Canada,
Limited, (now Imperial Oil of Canada, Ltd.) dated as of May 1, 1989
(Filed as Exhibit 10.12 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1989).*
10.9.1 --Amendment to Exhibit 10.12 dated as of September 28, 1989 (Filed as
Exhibit 10.12.1 to the 10.9.1 Annual Report of the Company on Form 10-
K for the year ended December 31, 1989).*
10.10 --Storage Service Agreement between the Company and Distrigas of
Massachusetts Corporation dated as of December 17, 1988 (Filed as
Exhibit 10.13 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1989).*
10.11 --Liquid Purchase Agreement between the Company and Distrigas of
Massachusetts Corporation dated as of April 14, 1989 (Filed as Exhibit
10.14 to the Annual Report of the Company on Form 10-K for the year
ended December 31, 1989).*
10.12 --Gas Sales Agreement between the Company and Alberta Northeast Gas,
Ltd. dated as of February 7, 1991 (Filed as Exhibit 10.16 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1990).*
10.13 --Firm Gas Transportation Agreement between the Company and Iroquois
Gas Transmission System, L.P. dated as of February 7, 1991 (Filed as
Exhibit 10.17 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1990).*
10.14 --Firm Gas Transportation Agreement between the Company and Tennessee
Gas Pipeline Company dated as of February 7, 1991 (Filed as Exhibit
10.18 to the Annual Report of the Company on Form 10-K for the year
ended December 31, 1990).*
10.15 --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 1996.
- --------
* 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
/s/ J.F. Bodanza
By: _________________________________
J.F. BODANZA SENIOR VICE PRESIDENT
AND TREASURER (PRINCIPAL FINANCIAL
AND ACCOUNTING OFFICER)
Dated: March 14, 1997
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 14TH DAY OF MARCH 1997.
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
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, 1996 and 1995.... F-2 and F-3
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1996.............................................. F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1996........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1996.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-16
Interim Financial Information for the Two Years Ended December
31, 1996 (Unaudited)........................................... F-18
Schedules for the Three Years Ended December 31, 1996:
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,
-----------------
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Gas plant, at cost........................................... $812,114 $761,607
Construction work-in-progress................................ 4,604 486
Less--Accumulated depreciation............................. 290,492 254,448
-------- --------
Net plant.................................................. 526,226 507,645
Current assets:
Cash....................................................... 1,474 5,841
Accounts receivable, less reserves of $15,963 at December
31, 1996 and $15,324 at December 31, 1995................. 76,832 74,519
Deferred gas costs......................................... 75,337 71,940
Natural gas and other inventories, at average cost......... 49,287 35,136
Materials and supplies, at average cost.................... 3,809 4,770
Prepaid expenses........................................... 2,759 3,259
Income taxes............................................... 10,411 368
-------- --------
Total current assets..................................... 219,909 195,833
Other assets:
Deferred postretirement benefits cost...................... 88,563 93,829
Deferred charges and other assets.......................... 42,346 32,180
-------- --------
Total other assets....................................... 130,909 126,009
-------- --------
Total assets............................................. $877,044 $829,487
======== ========
</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,
-----------------
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Capitalization:
Stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1996 and 1995............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 133,980 119,546
-------- --------
Total common stockholder's investment.................... 228,631 214,197
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized and outstanding--1,200,000 shares at December
31, 1996 and 1995......................................... 29,293 29,262
Long-term obligations, less current portion................. 211,743 212,772
-------- --------
Total capitalization..................................... 469,667 456,231
Gas inventory financing..................................... 55,594 45,600
-------- --------
Total capitalization and gas inventory financing......... 525,261 501,831
Current liabilities:
Current portion of long-term obligations................... 1,029 1,509
Notes payable.............................................. 57,000 52,000
Accounts payable........................................... 73,313 53,490
Accrued taxes.............................................. 1,206 1,011
Accrued interest........................................... 4,339 3,959
Customer deposits.......................................... 2,382 2,789
Refunds due customers...................................... 3,384 13,173
Pipeline transition costs.................................. 16,494 9,510
-------- --------
Total current liabilities................................ 159,147 137,441
Commitments and contingencies:
Reserves and deferred credits:
Deferred income taxes...................................... 76,277 72,001
Unamortized investment tax credits......................... 6,836 7,767
Postretirement benefits obligation......................... 84,827 86,589
Other...................................................... 24,696 23,858
-------- --------
Total reserves and deferred credits...................... 192,636 190,215
-------- --------
Total liabilities and stockholder's investment........... $877,044 $829,487
======== ========
</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,
----------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenues................................ $705,462 $653,073 $660,158
Cost of gas sold.................................. 414,254 374,904 382,885
-------- -------- --------
Operating margin.................................. 291,208 278,169 277,273
Operating expenses:
Other operating expenses........................ 156,105 156,794 150,847
Maintenance..................................... 25,045 21,449 24,826
Depreciation and amortization................... 41,607 38,264 35,809
Income taxes.................................... 20,017 16,258 17,737
-------- -------- --------
242,774 232,765 229,219
-------- -------- --------
Operating earnings................................ 48,434 45,404 48,054
Other earnings, net............................... 564 726 65
-------- -------- --------
Earnings before interest expense.................. 48,998 46,130 48,119
Interest expense:
Long-term debt.................................. 16,769 18,633 17,024
Other, including amortization of debt expense... 1,688 2,693 4,841
Less-Interest during construction............... (525) (499) (894)
-------- -------- --------
17,932 20,827 20,971
-------- -------- --------
Net earnings...................................... 31,066 25,303 27,148
Preferred stock dividends......................... 1,926 1,926 1,926
-------- -------- --------
Earnings applicable to common stock............... $ 29,140 $ 23,377 $ 25,222
======== ======== ========
</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,
----------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance at Beginning of Year..................... $119,546 $108,098 $ 95,680
Net earnings................................... 31,066 25,303 27,148
Preferred stock dividends ($1.61 per share in
1996, 1995 and 1994).......................... (1,926) (1,926) (1,926)
Cash dividends on common stock ($28.60 per
share in 1996,
$23.20 per share in 1995 and $24.90 per share
in 1994)...................................... (14,706) (11,929) (12,804)
-------- -------- --------
Balance at End of Year........................... $133,980 $119,546 $108,098
======== ======== ========
</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,
----------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from operating activities:
Net earnings.................................... $ 31,066 $ 25,303 $ 27,148
Adjustments to reconcile net earnings to cash
(used for) provided by operating activities:
Depreciation and amortization.................. 41,607 38,264 35,809
Deferred taxes................................. 4,276 5,424 5,016
Other changes in assets and liabilities:
Accounts receivable........................... (2,313) (3,111) 17,688
Inventory..................................... (13,190) 12,001 6,264
Deferred gas costs............................ (3,397) 17,763 (23,901)
Accounts payable.............................. 19,823 10,837 (10,121)
Federal and state income taxes................ (10,043) 1,039 4,639
Refunds due customers......................... (9,789) (5,546) 10,690
Other......................................... (2,543) (969) 7,164
-------- -------- --------
Cash provided by operating activities............ 55,497 101,005 80,396
-------- -------- --------
Cash flows from investing activities:
Capital expenditures........................... (58,504) (57,322) (53,504)
Net cost of removal............................ (4,124) (6,463) (6,412)
-------- -------- --------
Cash used for investing activities............... (62,628) (63,785) (59,916)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. 5,000 (10,530) (43,770)
Changes in inventory financing................. 9,994 (7,978) (5,719)
Proceeds from issuance of long-term debt....... -- 60,000 50,000
Repayment of long-term debt.................... -- (62,880) (3,622)
Amortization of preferred stock issuance
costs......................................... 31 33 32
Cash dividends paid on common and preferred
stock......................................... (12,261) (13,855) (14,730)
-------- -------- --------
Cash (used for) provided by financing activi-
ties............................................ 2,764 (35,210) (17,809)
-------- -------- --------
Increase (decrease) in cash...................... (4,367) 2,010 2,671
Cash at beginning of year........................ 5,841 3,831 1,160
-------- -------- --------
Cash at end of year.............................. $ 1,474 $ 5,841 $ 3,831
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 18,960 $ 20,752 $ 20,193
Income taxes.................................. $ 26,205 $ 10,128 $ 8,151
</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 Statement of Financial Accounting
Standards No. 71, ("SFAS 71") "Accounting for the Effects of Certain Types of
Regulation".
The significant accounting policies followed by the Company and its
subsidiary are described below and in the following footnotes:
Note 2--Cost of Gas Adjustment Clause and Deferred Gas Costs
Note 3--Income Taxes
Note 6--Pension Benefits
Note 7--Postretirement Benefits Other Than Pensions
Note 8--Leases
Principles of Consolidation
The Company is a wholly-owned subsidiary of Eastern Enterprises ("Eastern").
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiary, Massachusetts LNG Incorporated ("Mass LNG"). All
material intercompany balances and transactions between the Company and its
subsidiary have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Regulation and Operations
The Company is a gas distribution company engaged in the transportation and
sale of natural gas to residential, commercial and industrial customers. The
Company's service territory includes Boston and 73 other communities in
eastern and central Massachusetts.
The Company's operations are subject to Massachusetts statutes applicable to
gas utilities. Its revenues, earnings and cash flows are highly seasonal as
most of its throughput is directly related to temperature levels.
Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Public Utilities ("the Department"). Therefore,
the Company accounts for the economic effects of regulation in accordance with
the provisions of Statement of Financial Accounting Standards 71 ("SFAS 71")
"Accounting for the Effects of Certain Types of Regulation". In the event the
Company determines that it no longer meets the criteria for following SFAS 71,
the accounting impact would be an extraordinary, non-cash charge to operations
of an amount that could be material. Criteria that give rise to the
discontinuance of SFAS 71 include (1) increasing competition that restricts
the Company's ability to establish prices to recover specific costs and (2) a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another regulation. The Company has reviewed these
criteria in conjunction with its 1996 Rate Order and believes that the
continuing application of SFAS 71 is appropriate.
Regulatory assets have been established that represent probable future
revenue to the Company associated with certain costs which will be recovered
from customers through the ratemaking process. Regulatory liabilities
F-7
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) ACCOUNTING POLICIES (CONTINUED)
represent probable future reductions in revenues associated with the 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:
<TABLE>
<CAPTION>
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Postretirement benefit costs............................ $ 88,563 $ 93,829
Deferred pipeline transition costs...................... 16,494 9,510
Deferred income taxes................................... -- 498
Environmental costs..................................... 2,784 3,591
Other................................................... 2,225 2,176
-------- --------
$110,066 $109,604
======== ========
</TABLE>
Regulatory liabilities total approximately $11,446,000 and $12,391,000 at
December 31, 1996 and 1995 and relate primarily to income taxes.
As of December 31, 1996 all of the Company's regulatory assets and
regulatory liabilities are being reflected in rates charged to customers over
periods ranging from 1 to 23 years. For additional information regarding
deferred income taxes, postretirement benefit costs, environmental costs and
Order 636 transition costs, see footnotes 3, 7, 11, and 12 respectively.
Impairment of Long-Lived Assets
Statement of Financial Standards No. 121 ("SFAS 121") "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
which became effective for 1996 establishes accounting standards for the
impairment of long-lived assets. SFAS 121 also requires that regulatory assets
which are no longer probable of recovery through future revenues be charged to
earnings. SFAS 121 did not have an impact on financial position or results of
operations upon adoption.
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 5.15% in 1996, 5.13% in 1995,
and 5.16% in 1994.
Accumulated depreciation is charged with the original cost and cost of
removal, less salvage value, of units retired. Expenditures for repairs,
upkeep of units of property and renewal of minor items of property replaced
independently of the unit of which they are a part are charged to maintenance
expense as incurred.
Gas Operating Revenues
Gas operating revenues are recorded when billed. Revenue is not recorded for
the amount of gas distributed to customers, which is unbilled at the end of
the period; however, the cost of this gas is deferred as discussed in Note 2.
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause ("CGAC") requires the Company to adjust
its rates semi-annually for firm gas sales in order to track changes in the
cost of gas distributed with an annual adjustment of subsequent rates for any
collection over or under actual costs incurred. As a result, the Company
defers the cost of any firm
F-8
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS (CONTINUED)
gas that has been distributed, but is unbilled at the end of a period, to a
period in which the gas is billed to customers. In its order of November 29,
1996, the Department modified the CGAC to recover the gas cost portion of the
Company's bad debt write-offs effective December 1, 1996. The order also
granted a local distribution adjustment clause ("LDAC") which 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 from the Company's firm sales and transportation customers. These
costs were previously recovered through the CGAC.
(3) INCOME TAXES
The Company is a member of an affiliated group of companies that files a
consolidated federal income tax return. The Company follows the policy,
established for the group, of providing for income taxes which would be
payable on a separate company basis. The Company's effective income tax rate
was 39.2% in 1996, 39.1% in 1995, and 39.5% in 1994. State taxes represent the
majority of the difference between the effective rate and the Federal income
tax rate for 1996, 1995 and 1994.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current--
Federal........................................... $10,154 $10,603 $ 7,966
State............................................. 2,004 2,136 591
------- ------- -------
Total current provision......................... 12,158 12,739 8,557
Deferred--
Federal........................................... 6,489 2,896 6,796
State............................................. 1,370 623 2,384
------- ------- -------
Total deferred provision........................ 7,859 3,519 9,180
------- ------- -------
Provision for income taxes.......................... $20,017 $16,258 $17,737
======= ======= =======
</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, 1996 this
regulatory asset had been fully recovered from customers.
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, 1996 was $3,839,000. 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, 1996 the balance to
be returned to customers was $7,606,000.
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,
1996 and 1995, are as follows:
F-9
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) INCOME TAXES (CONTINUED)
<TABLE>
<CAPTION>
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
ASSETS:
Unbilled revenues................................. $ 22,392 $ 24,637
Reserve for uncollectible receivables............. 6,261 6,010
Regulatory liabilities............................ 4,490 4,860
Other............................................. 8,925 9,323
--------- ---------
Total deferred tax assets......................... $ 42,068 $ 44,830
--------- ---------
LIABILITIES:
Accelerated depreciation.......................... $ (80,894) $ (78,115)
Deferred gas costs................................ (28,684) (16,296)
Other............................................. (12,932) (22,635)
--------- ---------
Total deferred tax liabilities.................... $(122,510) $(117,046)
--------- ---------
Total net deferred taxes.......................... $ (80,442) $ (72,216)
========= =========
</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 $931,000 in 1996, $937,000 in 1995, and $723,000 in 1994.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
8.33%-9.75%, Medium-Term Notes, Series A, due 2005--
2022................................................. 100,000 100,000
6.93%-8.50%, Medium-Term Notes, Series B, due 2006--
2024................................................. 50,000 50,000
6.80%-7.25%, Medium-Term Notes, Series C, due 2012--
2025................................................. 60,000 60,000
Capital lease obligations (Note 8).................... 2,772 4,280
Less current portion.................................. (1,029) (1,508)
-------- --------
$211,743 $212,772
======== ========
</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 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 which have
subsequently been called.
Pursuant to regulatory accounting, the in-substance defeasance transaction
resulted in the deferral of $2,582,000 as debt issuance costs to be amortized
over the lives of the newly issued Medium-Term Notes. 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, 1996 and none are callable prior
to maturity.
Annual maturities of capital lease obligations are $1,029,000, $507,000,
$561,000, $620,000 and $55,000 for 1997 through 2001, respectively.
F-10
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
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, 1996 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 effective
October 1, 1988, the Company funds 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 $70,000,000 for the exclusive
purpose of funding its inventory of gas supplies or for backing commercial
paper issued for the same purpose. The Company had $55,594,000 and $45,600,000
of commercial paper outstanding to fund its inventory of gas supplies at
December 31, 1996 and 1995, respectively. Since the commercial paper is
supported by the credit agreement, these borrowings have been classified as
non-current in the accompanying consolidated balance sheets. The credit
agreement includes a one year revolving credit facility which may be converted
to a two-year term loan at the Company's option if the one year revolving
credit facility is not renewed by the banks. The Company may select the agent
bank's prime rate or, at the Company's option, various pricing alternatives.
The agreement requires a facility fee of 1/12 of 1% on the commitment. No
borrowings were outstanding under this agreement during 1996 and 1995.
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 31, 2001. The interest rate for such borrowings is the
agent bank's prime rate, or at Eastern's option, various alternatives.
Notes Payable
The Company has an uncommitted line of credit which provide for interest as
a function of federal funds, money market or prime rates. This uncommitted
line of credit is used, in conjunction with commercial paper, for working
capital needs. The Company had outstanding borrowings of $57,000,000 and
$52,000,000 in commercial paper not related to gas inventory financing at
December 31, 1996 and 1995, respectively. The weighted average interest rate
on these borrowings was 5.99% at December 31, 1996 and 5.93% at December 31,
1995.
(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").
F-11
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(6) PENSION BENEFITS (CONTINUED)
Net pension cost included the following components:
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost-benefits earned during the
year........................................ $ 2,883 $ 2,710 $ 2,637
Interest cost on projected benefit
obligation.................................. 8,492 8,055 7,556
Actual return on plan assets................. (11,727) (21,762) (4,431)
Net amortization and deferral................ 3,225 13,773 (3,281)
-------- -------- -------
Net pension cost............................. $ 2,873 $ 2,776 $ 2,481
======== ======== =======
</TABLE>
For the periods 1996 and 1995, 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 1996 and 1995.
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>
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $97,180 in 1996 and $94,526 in 1995.... $ 106,180 $ 103,880
========= =========
Projected benefit obligation for service rendered to
date............................................... (117,729) (116,358)
Plan assets at fair value, primarily listed stocks,
corporate bonds and U.S. bonds..................... 139,887 129,190
--------- ---------
Plan assets in excess of projected benefit
obligation......................................... 22,158 12,832
Unrecognized net obligation at January 1, 1986 being
recognized over 15 years........................... 871 1,088
Unrecognized net gain............................... (26,820) (19,886)
Unrecognized prior service cost..................... 11,952 13,000
--------- ---------
Net pension asset................................... $ 8,161 $ 7,034
========= =========
</TABLE>
(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 ("SFAS 106"), "Employers Accounting for
Postretirement Benefits Other Than Pensions" the cumulative effect of the
accounting change ("transition obligation") was $89,120,000. The 1996 rate
order allowed recovery of SFAS 106 costs which includes current SFAS 106
expense and the amortization of the regulatory asset related to the transition
obligation.
F-12
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED)
Net postretirement benefit costs included the following components:
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost-benefits earned during the year....... $ 779 $ 729 $ 731
Interest cost on accumulated benefit obligation.... 5,749 5,645 5,238
Net amortization and deferral of actuarial gains
and losses........................................ (1,448) (4,752) (2,617)
Actual return on plan assets....................... (1,355) 2,352 (755)
------ ------ ------
Postretirement benefit cost........................ 3,725 3,974 2,597
Amortization of regulatory asset................... 5,266 3,760 3,472
------ ------ ------
Net postretirement benefit cost.................... $8,991 $7,734 $6,069
====== ====== ======
</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>
1996 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Retirees............................................... $(58,131) $(57,580)
Other fully eligible participants...................... (5,728) (5,973)
Other active participants.............................. (15,083) (14,671)
-------- --------
(78,942) (78,224)
Plan assets at fair value.............................. 17,918 16,563
-------- --------
Accumulated postretirement benefits obligation in
excess of plan assets................................. (61,024) (61,661)
Unrecognized actuarial gain............................ (12,586) (12,521)
Unrecognized prior service costs....................... (11,217) (12,407)
-------- --------
Accrued postretirement benefits........................ $(84,827) $(86,589)
======== ========
</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. 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 1996 and 1995. A 7% and 10% annual
increase in the cost of covered health care benefits was assumed for 1996 and
1995, respectively. This rate of increase is assumed to remain at 7% through
1999, decrease to 6% in 2000 and 5% thereafter. A 1% increase in the assumed
health care cost trend would have increased the postretirement benefit cost by
$536,000 in 1996 and $541,000 in 1995, and the accumulated postretirement
benefit obligation by $6,253,000 in 1996 and $6,300,000 in 1995.
(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
$8,418,000 in 1996, $8,826,000 in 1995, and $8,323,000 in 1994.
The Company capitalizes its financing leases which include liquefied natural
gas facilities and an operations center. The lease for the liquefied natural
gas facilities expires in June of 1997. The Company is in the process of
evaluating its alternatives with respect to these facilities. A summary of
property held under capital leases as of December 31 is as follows:
F-13
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) LEASES (CONTINUED)
<TABLE>
<CAPTION>
1996 1995
------- -------
(IN THOUSANDS)
<S> <C> <C>
LNG facilities.............................................. $15,600 $15,600
Buildings................................................... 6,000 6,000
------- -------
21,600 21,600
Less-Accumulated depreciation............................... 18,828 17,320
------- -------
Total Capital Leases.................................... $ 2,772 $ 4,280
======= =======
</TABLE>
Under the terms of SFAS 71, the timing of expense recognition on capitalized
leases should conform with regulatory rate treatment. The Company has included
the rental payments on its financing leases in its cost of service for rate
purposes. Therefore, the total depreciation and interest expense that was
recorded on the leases was equal to the rental payments included in other
operating and maintenance expense in the accompanying consolidated statements
of earnings.
The Company also has various operating lease agreements for office
facilities and other equipment. The remaining minimum rental commitment for
these and all other noncancelable leases, including the financing leases, at
December 31, 1996 is as follows:
<TABLE>
<CAPTION>
CAPITAL OPERATING
YEAR LEASES LEASES
---- ------- ---------
(IN THOUSANDS)
<S> <C> <C>
1997..................................................... 1,269 4,548
1998..................................................... 684 3,735
1999..................................................... 686 3,385
2000..................................................... 687 2,797
2001..................................................... 57 2,119
Later Years.............................................. -- 1,108
------ -------
Total minimum lease payments............................. $3,383 $17,692
====== =======
Less-Amount representing interest and executory costs.... 611
------
Present value of minimum lease payments on capital
leases.................................................. $2,772
======
</TABLE>
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair values
of financial instruments:
Cash
The carrying amounts approximate fair value.
Short-term Debt
The carrying amounts of the Company's short-term debt, including notes
payable and gas inventory financing, approximate their fair value.
Long-term Debt
The fair value of long-term debt is estimated based on currently quoted
market prices.
F-14
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS (CONTINUED)
Preferred Stock
The fair value of the preferred stock for 1996 and 1995 is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
1996 1995
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C>
Cash........................................ $ 1,474 $ 1,474 $ 5,841 $ 5,841
Short-term debt............................. $112,594 $112,594 $ 97,600 $ 97,600
Long-term debt.............................. $212,772 $223,001 $214,281 $241,757
Preferred stock............................. $ 29,293 $ 29,586 $ 29,262 $ 28,829
</TABLE>
(10) RELATED PARTY TRANSACTIONS
The Company paid Eastern $4,048,000 in 1996, $4,117,000 in 1995, and
$3,669,000 in 1994 for legal, tax and corporate services rendered.
In December 1996, Eastern Rivermoor Company, Inc. a wholly owned subsidiary
of Eastern, purchased the Company's primary operations center from a third
party and assumed the current lease agreement with the Company. There were no
payments made during 1996 to Eastern Rivermoor Company, Inc. by the Company.
During 1996 Eastern entered into a joint venture with New England Electric
System to form AllEnergy Marketing Company, L.L.P., a new unregulated energy
marketing company. During 1996 AllEnergy purchased gas from the Company at
prices and terms equivalent to those used in transacting business with
unrelated parties. These purchases totalled $2,764,000.
(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
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 settlement
agreement between MEC and the Company (the "Settlement Agreement"), MEC
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 Settlement
Agreement or the Boyd decision. The Company expects to spend approximately
$1,000,000 in 1997 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
F-15
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(11) ENVIRONMENTAL ISSUES (CONTINUED)
discussed below. Company experience to date indicates that assessment and
remediation costs of approximately $15,000,000 could be paid by the Company
with respect to these ten sites covered by the Settlement Agreement and the
four other 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 the Company 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
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 FERC Order 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.
On March 8, 1995 the Department issued an order allowing for the recovery of
the Company's transition costs liability from customers. The Company's
estimate of its total obligation for transition costs is $58,243,000. The
Company has recorded a regulatory asset of $16,494,000 which represents the
unrecovered balance of the Company's estimated obligation.
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, 1996 and 1995, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1996. 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, 1996 and 1995 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996, 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 21, 1997
F-17
<PAGE>
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION
FOR THE TWO YEARS ENDED DECEMBER 31, 1996 (UNAUDITED)
The following table summarizes the Company's reported quarterly information
for the years ended December 31, 1996 and 1995:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
1996
Operating revenues....................... $343,341 $136,520 $59,453 $166,148
Operating margin......................... 122,174 59,309 34,733 74,992
Operating earnings (loss)................ 30,334 6,339 (3,758) 15,519
Net earnings (loss) applicable to common
stock................................... 25,021 1,842 (8,161) 10,438
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
</TABLE>
F-18
<PAGE>
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONS
------------------ NET
BALANCE, CHARGED DEDUCTIONS BALANCE,
DECEMBER 31, CHARGED TO OTHER FROM DECEMBER 31,
DESCRIPTION 1995 TO INCOME ACCOUNTS RESERVES 1996
- ----------- ------------ --------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............. $ 15,324 $12,942 $ -- $12,303 $ 15,963
======== ======= ====== ======= ========
RESERVES NOT DEDUCTED
FROM ASSETS:
Accumulated deferred
income taxes......... $ 72,001 $(1,383) $5,659 $ -- $ 76,277
-------- ------- ------ ------- --------
Deferred investment
tax credits.......... $ 7,767 $ (931) $ -- $ -- $ 6,836
-------- ------- ------ ------- --------
Postretirement benefit
cost................. $ 86,589 $ 3,725 $ -- $ 5,487 $ 84,827
-------- ------- ------ ------- --------
Other reserves and
deferred credits--
Reserve for self-
insurance........... 2,347 1,931 -- 2,038 2,240
SFAS 109 Regulatory
Liability........... 4,440 -- -- 601 3,839
Deferred net
normalization
surplus............. 7,951 -- -- 345 7,606
Other................ 9,120 7,054 -- 5,163 11,011
-------- ------- ------ ------- --------
Total other reserves
and deferred
credits............ 23,858 8,985 -- 8,147 24,696
-------- ------- ------ ------- --------
Total reserves not
deducted from
assets............. $190,215 $10,396 $5,659 $13,634 $192,636
======== ======= ====== ======= ========
</TABLE>
F-19
<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 de-
ferred credits--
Reserve for self-in-
surance............. 2,258 1,739 -- 1,650 2,347
SFAS 109 Regulatory
Liability........... 5,045 -- -- 605 4,440
Deferred net normal-
ization surplus..... 8,296 -- -- 345 7,951
Other................ 6,068 6,955 1,521 5,424 9,120
-------- ------- ------ ------- --------
Total other reserves
and deferred cred-
its................ 21,667 8,694 1,521 8,024 23,858
-------- ------- ------ ------- --------
Total reserves not
deducted from as-
sets............... $187,162 $14,717 $3,960 $15,624 $190,215
======== ======= ====== ======= ========
</TABLE>
F-20
<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 de-
ferred credits--
Reserve for self-in-
surance............. 2,270 1,429 -- 1,441 2,258
SFAS 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 cred-
its................ 22,124 10,063 (3,658) 6,862 21,667
-------- ------- ------- ------- --------
Total reserves not
deducted from as-
sets............... $185,067 $16,860 $(3,565) $11,200 $187,162
======== ======= ======= ======= ========
</TABLE>
F-21
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 526,226
<OTHER-PROPERTY-AND-INVEST> 2,547
<TOTAL-CURRENT-ASSETS> 219,909
<TOTAL-DEFERRED-CHARGES> 39,799
<OTHER-ASSETS> 88,563
<TOTAL-ASSETS> 877,044
<COMMON> 51,418
<CAPITAL-SURPLUS-PAID-IN> 43,233
<RETAINED-EARNINGS> 133,980
<TOTAL-COMMON-STOCKHOLDERS-EQ> 228,631
29,293
0
<LONG-TERM-DEBT-NET> 208,972
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 112,594
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 2,771
<LEASES-CURRENT> 1,029
<OTHER-ITEMS-CAPITAL-AND-LIAB> 293,754
<TOT-CAPITALIZATION-AND-LIAB> 877,044
<GROSS-OPERATING-REVENUE> 705,462
<INCOME-TAX-EXPENSE> 20,017
<OTHER-OPERATING-EXPENSES> 156,105
<TOTAL-OPERATING-EXPENSES> 242,774
<OPERATING-INCOME-LOSS> 48,434
<OTHER-INCOME-NET> 564
<INCOME-BEFORE-INTEREST-EXPEN> 48,998
<TOTAL-INTEREST-EXPENSE> 17,932
<NET-INCOME> 31,066
1,926
<EARNINGS-AVAILABLE-FOR-COMM> 29,140
<COMMON-STOCK-DIVIDENDS> 14,706
<TOTAL-INTEREST-ON-BONDS> 16,769
<CASH-FLOW-OPERATIONS> 55,497
<EPS-PRIMARY> 56.67
<EPS-DILUTED> 56.67
</TABLE>
