<PAGE>
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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 AUGUST 31, 1998
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 1-8154
ESSEX GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
(FORMERLY ESSEX COUNTY GAS COMPANY)
MASSACHUSETTS 04-1427020
(STATE OF ORGANIZATION) (I.R.S. EMPLOYER IDENTIFICATION NO.)
7 NORTH HUNT ROAD 01913
AMESBURY, MASSACHUSETTS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (978) 388-4000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
TITLE OF CLASS EXCHANGE
-------------- --------
<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 the 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 Registrant's Common Stock, no
par value, as of November 23, 1998.
ALL COMMON STOCK, 100 SHARES, ARE HELD BY EASTERN ENTERPRISES.
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with reduced
disclosure format.
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<PAGE>
ESSEX GAS COMPANY
FORM 10-K
ANNUAL REPORT
YEAR ENDED AUGUST 31, 1998
----------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
ITEM NO. TOPIC PAGE
-------- ----- ----
<C> <S> <C>
PART I
1. Business...................................................... 1
General....................................................... 1
Competition................................................... 1
Gas Throughput................................................ 2
Gas Supply.................................................... 2
Regulation.................................................... 3
Environmental Matters......................................... 4
Employees..................................................... 5
2. Properties.................................................... 4
3. Legal Proceedings............................................. 5
4. Submission of Matters to a Vote of Security Holders........... 5
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 7
6. Selected Financial Data....................................... 7
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 7
8. Financial Statements and Supplementary Data................... 11
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 28
PART III
10. Directors and Executive Officers of the Registrant............ 28
11. Executive Compensation........................................ 28
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 28
13. Certain Relationships and Related Transactions................ 29
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K............................................................ 29
Signatures.................................................... 30
</TABLE>
<PAGE>
PART I
ITEM 1: BUSINESS
GENERAL
Essex Gas Company ("The Company") is a regulated public utility organized
under the laws of the Commonwealth of Massachusetts in 1853 that purchases,
distributes and sells natural gas to residential, commercial and industrial
customers in northeastern Massachusetts. The Company operates in the cities of
Haverhill, Newburyport, and Amesbury and fourteen smaller municipalities
covering an area of approximately 280 square miles. The Company's service area
is primarily comprised of residential communities with a number of small
commercial and diversified industrial businesses.
As discussed in Note K to the Financial Statements, pursuant to an Agreement
and Plan of Merger dated as of December 19, 1997 by and between Essex County
Gas Company and Eastern Enterprises ("Eastern"), ECGC Acquisition Gas Company,
a wholly-owned subsidiary of Eastern, merged with and into the Company on
September 30, 1998, by an exchange of all of the Company's stock for
approximately 2,047,000 shares of Eastern stock, with the Company surviving
the merger as a wholly-owned subsidiary of Eastern (the "Acquisition"). On
November 6, 1998 the Company changed its name from Essex County Gas Company to
Essex Gas Company.
For definitions of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides both local transportation services and gas supply for
all customer classes. All residential customers currently purchase combined or
"bundled" supply and transportation services from the Company. Residential
users of natural gas generally experience their highest level of consumption
for heating purposes during the winter months. Accordingly, the Company's
sales and operating revenues are sensitive to the weather. The Company also
offers unbundled local transportation service to its commercial and industrial
customers, thereby allowing them to purchase supply from third party
marketers. Although migration from firm sales to firm transportation causes
gross revenues to decline, it has no impact on the Company's operating
earnings. The Company earns all of its margin on the local distribution of gas
and none on the resale of the commodity.
The Company offers both firm and non-firm services. Firm local
transportation services and sales are provided under rate tariffs or contracts
filed with the Massachusetts Department of Telecommunications and Energy
("MDTE") that typically obligate the Company to provide service without
interruption. Non-firm transportation services and sales are generally
provided to commercial and industrial customers who can use gas and oil
interchangeably. Non-firm services, including sales to other gas companies for
resale, are provided through individually negotiated contracts and, in most
cases, the price charged takes into account the price of the customer's
alternative fuel.
COMPETITION
The Company has no direct competition with respect to the retail
distribution of natural gas in its service territory. However, the Company
does face competition from alternative fuels in virtually every application.
The Company's gas business competes principally with oil for industrial
boiler uses and oil and electricity for residential and commercial space
heating. Competition is primarily based on price.
<PAGE>
GAS THROUGHPUT
The following table per dekatherm ("Dth") provides information with respect
to the volumes of gas delivered by the Company during the three years 1996-
1998:
<TABLE>
<CAPTION>
YEARS ENDED AUGUST 31,
-----------------------
1998 1997 1996
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Residential.......................................... 3,585 3,680 3,698
Commercial and Industrial............................ 1,983 2,062 2,068
Interruptible........................................ 55 758 893
------- ------- -------
Total Sales........................................ 5,623 6,500 6,659
Transportation of Customer-Owned Gas................. 30 -- --
------- ------- -------
Total Throughput................................... 5,653 6,500 6,659
======= ======= =======
Total Firm Throughput.............................. 5,568 5,742 5,766
======= ======= =======
</TABLE>
Residential customers comprise 90% of the customer base, while commercial
and industrial establishments account for the remaining 10%. Volumetrically,
residential customers account for 63% of total throughput and 64% of total
firm throughput, while commercial and industrial customers account for 37% of
total throughput and 36% of total firm throughput.
No customer, or group of customers under common control, accounted for 2% or
more of total firm revenues in 1998.
The Company's largest customer purchases gas on an interruptible basis and
accounted for approximately 2.7 percent of annual operating revenues on
average over the past three fiscal years ended August 31, 1998. Sales to that
customer in 1998 totaled $156,468 or .3 percent of total Company operating
revenues.
GAS SUPPLY
The following table shows the sources of the Company's gas supply
requirements for the periods indicated during 1996-1998:
<TABLE>
<CAPTION>
YEARS ENDED AUGUST 31,
-------------------------
1998 1997 1996
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Gas Supply (Dth):
Natural gas pipeline purchased.................. 4,952 5,376 5,307
Underground storage withdrawn................... 646 1,007 1,062
Liquefied natural gas produced.................. 183 253 477
------- ------- -------
Subtotal........................................ 5,781 6,636 6,846
Losses and Company Use............................ (158) (136) (187)
------- ------- -------
5,623 6,500 6,659
======= ======= =======
</TABLE>
The Company's supply requirements are purchased directly from domestic and
Canadian producers and marketers pursuant to contracts that have been approved
by the MDTE or by the Federal Energy Regulatory Commission ("FERC").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights
2
<PAGE>
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 DTH
---------------- EXPIRATION
PIPELINE DAILY ANNUAL DATES
-------- ------ --------- ----------
<S> <C> <C> <C>
Tennessee Gas Pipeline Company................... 24,969 9,113,685 11/1/2000
Tennessee Gas Pipeline Company................... 1,621 591,665 1/14/2003
Tennessee Gas Pipeline Company................... 2,000 730,000 11/30/2011
Iroquois Gas Transmission Company................ 2,000 730,000 11/30/2011
</TABLE>
The Company also has two contracts with pipeline companies for the storage
of natural gas in underground storage fields in New York and Pennsylvania.
These contracts provide storage capacity of about 1.2 million Dth and
approximately 13,700 Dth of peak day deliverability. Both contracts expire in
2000.
The Company has entered into an agreement with Distrigas of Massachusetts
Corporation which expires on October 31, 2006, that allows the Company to
purchase up to 4,000 Dth per day for 151 days of liquefied natural gas ("LNG")
in either liquid or vapor form. The Company, at its discretion, may increase
purchases under the contract by up to 2,000 Dth per day after appropriate
notice. The Company may also reduce quantities purchased if normal sales dip
below the normal 1994-95 heating season sendout.
Through a wholly-owned subsidiary, the Company owns a LNG storage facility
located in Haverhill, Massachusetts. The LNG storage facility has a storage
capacity of 410,000 Dth and has a daily sendout capacity of 30,000 Dth. At the
same location, the Company owns and operates a propane plant that has a
storage capacity equivalent of approximately 500,000 gallons with a total
daily sendout capacity of 3,500 Dth.
Based on current information concerning pipeline and supplemental gas
supplies, the Company believes that it has adequate resources 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 MDTE. Rates for
firm transportation and sales provided by the Company are subject to approval
by, and are on file with, the MDTE. In addition, the Company has a cost of gas
adjustment clause ("CGAC") 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.
As discussed in Note K to the Financial Statements, on September 30, 1998,
there was an Acquisition of the Company by Eastern, the Weston, Massachusetts
based owner of Boston Gas Company ("Boston Gas"). Boston Gas operates a local
gas distribution system serving approximately 530,000 customers that is
contiguous to the Company's system. On September 17, 1998, the MDTE approved
the Acquisition and a rate plan. Under the approved rate plan, there will be a
five percent price reduction through the CGAC mechanism, reflecting expected
gas supply cost savings, and a ten year freeze of base rates at current
levels. The freeze on base rates is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. Gas supply savings are expected to result from the
consolidation of the Essex Gas resource portfolio with the Boston Gas
portfolio. It is expected that many of the administrative, operations and
maintenance functions of the Company will be integrated with those of Boston
Gas.
In the Company's previous rate case, the MDTE approved an annualized base
rate increase of approximately $2.1 million. This increase went into effect
December 1, 1996.
On July 18, 1997, the MDTE directed all investor-owned gas distribution
companies in Massachusetts to undertake a collaborative process with other
stakeholders to develop common principles under which
3
<PAGE>
comprehensive gas service unbundling for commercial, industrial, and
residential customers might proceed. The Company participated in these
collaborative discussions, and on July 10, 1998 joined in a motion by the
local gas distributors and marketers for approval of a proposed settlement on
"model terms and conditions" for unbundled transportation service. This
settlement, presently pending before the MDTE, resolves many key issues, but
leaves for the MDTE's determination the method by which interstate pipeline
capacity currently under contract to serve customers will be assigned as
customers migrate from firm sales to firm transportation. The capacity
assignment method ultimately approved by the MDTE could permit capacity to be
acquired by marketers at less than cost. If this proves to be the case, there
can be no assurance that the Company would be permitted to recover such costs
until the MDTE has addressed their recoverability. The MDTE's decision on this
settlement, as well as the commencement of residential unbundling, is expected
in early 1999.
ENVIRONMENTAL MATTERS
The Company may have or share responsibility under applicable environmental
law for the remediation of former manufactured gas plant ("MGP") sites, and
one non-MGP site, and may share responsibility with respect to one federal
superfund site. Information with respect to these matters may be found at Note
J of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
EMPLOYEES
As of August 31, 1998, the Company had approximately 109 employees, 62% of
whom are organized in local unions with which the Company has a collective
bargaining agreement that expires in February, 1999.
ITEM 2: PROPERTIES
The Company's property consists primarily of its distribution system and
related facilities. The Company also owns a propane plant with a storage
capacity of 500,000 gallons. In addition, the Company, through its wholly-
owned subsidiary, LNG Storage, Inc., owns a LNG storage facility with a
storage capacity of 410,000 Dth.
Substantially all of the properties owned by the Company, other than
expressly exempted property, are subject to a lien under the indenture
securing the Company's First Mortgage Bonds. The indenture calls for a trustee
or receiver to take possession of the property if there is a default under its
terms. The property exempted from the lien includes cash, receivables,
supplemental fuel inventories, materials and supplies, rental appliances,
office furniture and equipment, and a LNG storage facility. The LNG storage
facility is subject to a separate mortgage note.
The Company leases its 30,000 square foot corporate headquarters building.
The lease agreement expires in October, 2005. The Company also has a division
office that is rented under an agreement scheduled to expire on February 28,
1999.
On August 31, 1998, the Company's distribution system included approximately
770 miles of gas mains, 37,350 services as well as meters and measuring and
regulator station equipment, and rental equipment on customers' premises.
The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned in fee.
In 1998, the Company's capital expenditures were $6.6 million. Capital
expenditures were principally made for improvements to the distribution
system, for system expansion to meet customer demand and for productivity
improvements. The Company plans to spend approximately $6.8 million for
similar purposes in 1999.
4
<PAGE>
ITEM 3: LEGAL PROCEEDINGS
There are certain routine non-material claims incidental to its business
pending against the Company, all of which are covered by insurance or
reserves. Management believes that the Company has adequate defenses against
these claims and it is the Company's intention to contest these claims. In
view of the insurance coverages and reserves, the potential liabilities are
not expected to materially affect the financial condition of the Company.
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
5
<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, balancing daily swings in customer loads, storage, and peak-
shaving services.
CAPACITY--The capability of pipelines and supplemental facilities to deliver
and/or store gas.
CITY GATE--Physical interconnection between an interstate pipeline and the
local distribution company.
CORE CUSTOMER--Generally, customers with no readily available energy
services alternative.
FIRM SERVICE--Sales and/or transportation service provided without
interruption throughout the year. Uninterrupted seasonal services are also
available for less than 365 days. Firm services are provided under either
filed rate tariffs or through individually negotiated contracts.
GAS MARKETER (BROKER)--A non-regulated buyer and seller of gas.
INTERSTATE TRANSPORTATION--Transportation of gas by an interstate pipeline
to the city gate.
LOCAL DISTRIBUTION COMPANY (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to
end-user facilities.
LOCAL TRANSPORTATION SERVICE--Transportation of gas by the LDC from the city
gate to end-user facilities.
NON-CORE CUSTOMERS--Generally, those customers with readily available,
economically viable alternatives to gas.
NON-FIRM SERVICE--Sales and transportation service offered at a lower level
of reliability and cost. Under this service, the LDC can interrupt customers
on short notice, typically during the winter season. Non-firm services are
provided through individually negotiated contracts and, in most cases, the
price charged takes into account the price of the customer's energy
alternative.
THROUGHPUT--Gas volume delivered to customers through the LDC's gas
distribution system.
UNBUNDLED SERVICE--Service that is offered and priced separately, such as
separating the cost of gas commodity delivered to the LDC's city gate from the
cost of transporting the gas from the city gate to the end user. Unbundled
services can also include daily or monthly balancing, back-up or stand-by
services and pooling. With unbundled services, customers have the opportunity
to select only the services they desire.
6
<PAGE>
PART II
ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock was traded on the NASDAQ/NMS through September
29, 1998 under the symbol "ECGC." On September 30, 1998, Essex Gas Company was
acquired by Eastern and continues to be held as a wholly-owned subsidiary. The
following table sets forth, for the quarters indicated, the high and low sale
prices as reported by NASDAQ/NMS, and the cash dividends per share declared in
such quarters.
<TABLE>
<CAPTION>
MARKET PRICE CASH
-------------- DIVIDENDS
HIGH LOW PER SHARE
------ ------- ---------
<S> <C> <C> <C>
Fiscal Year Ended August 31, 1997
First Quarter........................................ $27.00 $ 24.00 $0.40
Second Quarter....................................... 25.75 24.25 0.41
Third Quarter........................................ 26.00 24.25 0.41
Fourth Quarter....................................... 27.00 25.25 0.41
Fiscal Year Ended August 31, 1998
First Quarter........................................ $32.75 $ 26.00 0.41
Second Quarter....................................... 49.00 31.25 0.42
Third Quarter........................................ 47.00 44.00 0.42
Fourth Quarter....................................... 47.13 44.00 0.42
September 1 (through September 29, 1998)............... $49.25 $43.875 $0.42*
</TABLE>
- --------
* Paid on October 1, 1998 to shareholders of record on September 2, 1998.
The Company has paid regular dividends since 1914. Common Stock dividend
payments in fiscal 1998 totaled $1.67 per share, as compared to $1.63 in
fiscal 1997.
ITEM 6: SELECTED FINANCIAL DATA
Not required.
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
AUGUST 31, 1998 COMPARED TO AUGUST 31, 1997
Net earnings applicable to common stock for 1998 were $4.3 million, an
increase of $.3 million or 8% as compared to 1997. The increase primarily
reflects customer growth, the annualized effect of a base rate increase
granted by the MDTE effective December 1, 1996 and lower operations and
maintenance expense. The improvement in earnings was partially offset by
warmer weather and a higher charge for depreciation reflecting continued
investment in system replacement and expansion. Weather for 1998 was 11%
warmer than normal and 9% warmer than 1997.
AUGUST 31, 1997 COMPARED TO AUGUST 31, 1996
Net earnings applicable to common stock for 1997 were $4.0 million, an
increase of $.1 million or 3% as compared to 1996. This increase primarily
reflects customer growth and the effect of a $2.1 million annualized rate
increase granted by the MDTE effective December 1, 1996, partially offset by
higher operating and maintenance expense and increased depreciation expense.
The latter reflects continued investment in system replacement and expansion
as well as a higher depreciation rate granted in the Company's rate decision.
Weather for 1997 was 2% warmer than normal and 4% warmer than 1996.
7
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The Company believes that projected cash flow from operations, in
combination with currently available resources, is more than sufficient to
meet 1999 capital expenditures, working capital requirements, dividend
payments and normal debt repayments.
The Company expects capital expenditures for 1999 to be $6.8 million.
Capital expenditures will be largely for improvements to the distribution
system, for system expansion to meet customer demand and for productivity
improvements.
REGULATORY AND ACCOUNTING ISSUES
On September 30, 1998, there was an Acquisition of the Company by Eastern,
the Weston, Massachusetts based owner of Boston Gas. Boston Gas operates a
local gas distribution system serving approximately 530,000 customers that is
contiguous to the Essex Gas system. On September 17, 1998, the MDTE approved
the Acquisition and a rate plan. Under the approved rate plan, there will be a
five percent price reduction through the CGAC mechanism, reflecting projected
gas supply cost savings, and a ten year freeze of base rates at current
levels. The freeze on base rates is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. Gas supply savings are expected to result from the
consolidation of the Essex Gas resource portfolio with the Boston Gas
portfolio. It is expected that many of the administrative, operations and
maintenance functions of Essex Gas will be integrated with those of Boston
Gas. (See Footnote K to the Financial Statements for a description of the
merger transaction and related costs.)
On July 18, 1997, the MDTE directed all investor-owned gas distribution
companies in Massachusetts to undertake a collaborative process with other
stakeholders to develop common principles under which comprehensive gas
service unbundling for commercial, industrial, and residential customers might
proceed. The Company participated in these collaborative discussions, and on
July 10, 1998 joined in a motion by local gas distributors and marketers for
approval of a proposed settlement on "model terms and conditions" for
unbundled transportation service. This settlement, presently pending before
the MDTE, resolves many key issues, but leaves for the MDTE's determination
the method by which interstate pipeline capacity currently under contract to
serve customers will be assigned as customers migrate from firm sales to firm
transportation. The capacity assignment method ultimately approved by the MDTE
could permit capacity to be acquired by marketers at less than cost. If this
proves to be the case, there can be no assurance that the Company would be
permitted to recover such costs until the MDTE has addressed their
recoverability. The MDTE's decision on this settlement, as well as the
commencement of residential unbundling, is expected in early 1999.
NEW ACCOUNTING STANDARDS
In March 1998, the Financial Accounting Standards Board issued SFAS No. 128,
Earnings Per Share. SFAS No. 128 establishes standards for computing and
presenting earnings per share and applies to entities with publicly held
common stock or potential common stock. The statement requires restatement of
prior years' earnings per share. The Company adopted this statement for its
fiscal year ended August 31, 1998.
YEAR 2000 ISSUE
On September 30, 1998, there was an Acquisition of the Company by Eastern,
the parent company of Boston Gas. (See Note K to Financial Statements). It is
expected that the Company's Year 2000 issues will be addressed through the
integration of its operations with those of its affiliate Boston Gas. The
Company will bear the cost of integrating with the Boston Gas systems at a
cost of approximately $1 million. Boston Gas' Year 2000 plan is as follows:
8
<PAGE>
STATE OF READINESS
Boston Gas has assessed the impact of the year 2000 with respect to its
Information Technology ("IT") systems and embedded chip technology systems as
well as the potential exposure to significant third party risks. Accordingly,
Boston Gas has initiated and completed substantial portions of a plan to
replace or modify existing systems and technology as required and to assure
itself that major customers and critical vendors are also addressing these
issues.
With respect to IT systems, Boston Gas has tested and certified as year 2000
ready, four of its eleven mission critical business systems. Of the remaining,
one system is scheduled for certification in the fourth quarter of 1998; four
are scheduled for replacement in the fourth quarter of 1998; and the last two
are scheduled for replacement by the second quarter of 1999. All less than
critical application systems will be tested and/or upgraded by the second
quarter of 1999. Conversion and testing of all mainframe hardware and systems
software has been completed and the remaining non-compliant components of the
client-server and data/voice communications infrastructure are scheduled for
completion by the fourth quarter of 1998. Replacement or remediation of non-
compliance E-mail and desktop hardware and software systems are scheduled for
completion by the second quarter of 1999.
With respect to embedded chip systems, Boston Gas has completed an inventory
and expects to complete its assessment and action plan in the fourth quarter
of 1998. All remediation, conversion and testing are scheduled for completion
in the second quarter of 1999.
Boston Gas has identified material third party relationships and expects to
complete a detailed survey and assessment of third party readiness by the
fourth quarter of 1998, with selected testing and implementation of risk
mitigation strategies for significant vendors scheduled for completion by the
second quarter of 1999. However, there can be no assurance that third party
systems on which Boston Gas' systems rely will be timely converted or that any
such failure to convert by a third party would not have an adverse effect on
the Company's operations.
COST OF YEAR 2000 REMEDIATION
Boston Gas expects the cost of year 2000 compliance will approximate $13
million. Approximately 65% of these costs will be incurred under capital
projects that have or will result in added capabilities while also addressing
the year 2000 issues. As of September 30, 1998, approximately $8.3 million of
year 2000 compliance costs have been incurred.
RISKS OF YEAR 2000 ISSUES
Boston Gas has assessed the most reasonably likely worst case year 2000
scenario. Given Boston Gas' efforts to minimize the risk of year 2000 failure
by its internal systems, Boston Gas believes the worst case scenario would
occur if its primary telecommunications vendor and/or its electricity supplier
experiences a year 2000 failure which results in an outage. An outage would
require Boston Gas to enact disaster recovery measures to enable the
continuation of service to its customers. Such measures would include
utilizing the Boston Gas co-generation capability for electrical power,
relocating the customer inquiry function, and using a wireless network for
communications.
CONTINGENCY PLANS
Boston Gas expects to develop and put in place detailed business contingency
plans by the second quarter of 1999.
9
<PAGE>
FORWARD-LOOKING INFORMATION
This report and other Company reports and statements issued or made from
time to time contain certain "forward-looking statements" concerning projected
future financial performance, expected plans or future operations. The Company
cautions that actual results and developments may differ materially from such
projections or expectations.
Investors should be aware of important factors that could cause actual
results to differ materially from the forward-looking projections or
expectations. These factors include, but are not limited to: the effect of the
Acquisition by Eastern and other strategic initiatives on earnings and cash
flow, temperatures above or below normal in the Company's service area,
changes in economic conditions, including interest rates, the timetable and
cost for completing Boston Gas' Year 2000 plans, the impact of third party
Year 2000 issues, regulatory and court decisions and developments with respect
to previously disclosed environmental liabilities. Most of these factors are
difficult to predict accurately and are generally beyond the control of the
Company.
10
<PAGE>
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements Required by Regulation S-X
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
FISCAL YEARS ENDED AUGUST 31,
-------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES...................... $50,820,950 $53,534,734 $49,929,389
Less: Cost of gas....................... 24,154,488 27,272,268 24,976,802
----------- ----------- -----------
Operating margin....................... 26,666,462 26,262,466 24,952,587
----------- ----------- -----------
OPERATING EXPENSES:
Operations and maintenance expenses.... 11,772,403 12,291,661 11,976,067
Depreciation........................... 3,752,714 3,372,714 2,697,241
Taxes, other than federal income....... 2,039,653 1,986,927 1,816,929
Federal income taxes................... 1,982,723 1,889,601 1,793,360
----------- ----------- -----------
TOTAL OPERATING EXPENSES............ 19,547,493 19,540,903 18,283,597
----------- ----------- -----------
OPERATING INCOME........................ 7,118,969 6,721,563 6,668,990
OTHER INCOME, NET....................... 228,002 337,707 1,997
----------- ----------- -----------
INCOME BEFORE INTEREST CHARGES.......... 7,346,971 7,059,270 6,670,987
----------- ----------- -----------
INTEREST CHARGES:
Interest on long-term debt............. 2,515,169 2,338,112 1,967,073
Amortization of deferred debt expense.. 32,620 30,578 27,499
Other interest expense................. 554,406 750,895 873,198
Allowance for funds used during
construction.......................... (27,432) (26,834) (46,143)
----------- ----------- -----------
TOTAL INTEREST CHARGES.............. 3,074,763 3,092,751 2,821,627
----------- ----------- -----------
NET INCOME.............................. 4,272,208 3,966,519 3,849,360
ANNUAL REDEEMABLE
PREFERRED DIVIDEND REQUIREMENTS........ -- -- (13,860)
----------- ----------- -----------
INCOME AVAILABLE FOR COMMON STOCK....... $ 4,272,208 $ 3,966,519 $ 3,835,500
=========== =========== ===========
SHARES OF COMMON STOCK OUTSTANDING
(WEIGHTED AVERAGE):
Basic.................................. 1,711,379 1,664,677 1,626,315
----------- ----------- -----------
Diluted................................ 1,766,608 1,714,596 1,672,841
----------- ----------- -----------
EARNINGS PER COMMON SHARE:
Basic.................................. $ 2.50 $ 2.38 $ 2.36
----------- ----------- -----------
Diluted................................ $ 2.45 $ 2.34 $ 2.32
----------- ----------- -----------
CASH DIVIDENDS DECLARED PER COMMON
SHARE.................................. $ 1.67 $ 1.63 $ 1.59
----------- ----------- -----------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
11
<PAGE>
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
AUGUST 31, AUGUST 31,
1998 1997
------------ ------------
<S> <C> <C>
GAS PLANT, AT COST................................... $110,168,004 $104,540,111
Less: Accumulated depreciation...................... 28,151,230 25,021,795
------------ ------------
NET PLANT............................................ 82,016,774 79,518,316
------------ ------------
Other property and investments....................... 739,686 718,838
------------ ------------
Capitalized Leases (net of accumulated amortization
of $539,823 in 1998 and $518,975 in 1997)........... 550,939 604,822
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents........................... 254,493 434,930
Accounts receivable (net of allowance for
uncollectible accounts of $558,757 in 1998 and
$772,233 in 1997).................................. 1,790,833 2,664,531
Supplemental fuel inventory......................... 4,178,459 4,131,520
Materials and supplies (at average cost)............ 511,231 560,493
Prepaid deferred income taxes....................... 587,308 100,105
Prepayments and other............................... 1,720,013 622,024
Recoverable gas costs............................... -- 320,909
------------ ------------
TOTAL CURRENT ASSETS............................. 9,042,337 8,834,512
------------ ------------
DEFERRED CHARGES:
Regulatory assets................................... 1,174,601 1,790,966
Unamortized debt expense and other.................. 3,066,002 1,278,367
------------ ------------
TOTAL DEFERRED CHARGES........................... 4,240,603 3,069,333
------------ ------------
TOTAL ASSETS..................................... $ 96,590,339 $ 92,745,821
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
12
<PAGE>
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
AUGUST 31, AUGUST 31,
1998 1997
----------- -----------
<S> <C> <C>
COMMON STOCK EQUITY.................................... $38,295,586 $35,408,645
LONG-TERM DEBT, LESS CURRENT PORTION................... 28,199,000 28,799,000
----------- -----------
TOTAL CAPITALIZATION............................... 66,494,586 64,207,645
----------- -----------
NONCURRENT OBLIGATIONS UNDER CAPITAL LEASES............ 492,366 550,939
----------- -----------
CURRENT LIABILITIES:
Current portion of long-term debt..................... 675,361 960,535
Current obligation under capital leases............... 58,573 53,883
Obligations under supplemental fuel inventory......... 4,056,828 3,807,788
Notes payable, banks.................................. 6,825,000 3,313,000
Accounts payable...................................... 2,024,036 3,092,859
Accrued interest...................................... 820,116 803,237
Taxes payable......................................... 7,861 157,098
Refundable gas costs due customers.................... 721,388 --
Accrued transition costs.............................. -- 401,465
Supplier refund due customers......................... 159,243 1,567,364
Other................................................. 118,179 320,308
----------- -----------
TOTAL CURRENT LIABILITIES.......................... 15,466,585 14,477,537
----------- -----------
COMMITMENTS AND CONTINGENCIES
DEFERRED CREDITS:
Accumulated deferred income taxes..................... 9,624,844 8,941,079
Unamortized investment tax credit..................... 1,071,368 1,141,132
Deferred directors' fees.............................. 951,219 1,106,358
Regulatory liabilities................................ 1,270,808 1,187,310
Other................................................. 1,218,563 1,133,821
----------- -----------
TOTAL DEFERRED CREDITS............................. 14,136,802 13,509,700
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES............... $96,590,339 $92,745,821
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
13
<PAGE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
FISCAL YEARS ENDED AUGUST 31,
-----------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR............... $15,094,008 $13,833,767 $12,576,695
Net income................................ 4,272,208 3,966,519 3,849,360
----------- ----------- -----------
TOTAL.................................. 19,366,216 17,800,286 16,426,055
----------- ----------- -----------
Cash dividends declared:
Redeemable preferred stock................ -- -- 13,860
Common stock.............................. 2,851,660 2,706,278 2,578,428
----------- ----------- -----------
TOTAL.................................. 2,851,660 2,706,278 2,592,288
----------- ----------- -----------
BALANCE AT END OF YEAR..................... $16,514,556 $15,094,008 $13,833,767
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
14
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
FISCAL YEARS ENDED AUGUST 31,
-------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
NET INCOME............................. $ 4,272,208 $ 3,966,519 $ 3,849,360
----------- ----------- -----------
Adjustments to reconcile net income to
net cash:
Depreciation and amortization,
including amounts related to non-
utility operations................... 4,167,438 3,787,613 3,138,655
Provisions for uncollectible
accounts............................. (213,476) 119,441 57,792
Deferred income taxes................. 178,884 (812,633) 1,950,962
Noncash compensation associated with
ESOP................................. -- 75,000 150,000
Changes in current assets and
liabilities:
Accounts receivable................... 1,087,174 (899,975) (242,390)
Inventories including fuel............ 2,323 (132,262) 2,512,221
Prepayments and other................. (1,097,989) 478 (271,842)
Accounts payable...................... (1,068,823) (970,970) 1,077,522
Supplier refund obligations........... (1,408,121) 1,291,720 (2,179,095)
Taxes payable/receivable.............. (149,237) 1,019,266 (802,472)
Recoverable (refundable) gas costs.... 1,042,297 149,857 (2,960,944)
Deferred merger costs................. (1,666,378) -- --
Other, net............................ (132,238) 469,023 (53,011)
----------- ----------- -----------
Total adjustments..................... 741,854 4,096,558 2,377,398
----------- ----------- -----------
NET CASH PROVIDED BY OPERATING
ACTIVITIES.......................... 5,014,062 8,063,077 6,226,758
----------- ----------- -----------
INVESTING ACTIVITIES:
Utility capital expenditures........... (6,591,302) (6,894,633) (8,027,623)
Payments for retirements of property,
plant and equipment, net.............. (74,466) (99,602) (258,352)
Purchase of investment................. -- (570,113) --
Sale of investment..................... -- 570,113 --
----------- ----------- -----------
NET CASH USED IN INVESTING
ACTIVITIES.......................... (6,665,768) (6,994,235) (8,285,975)
----------- ----------- -----------
FINANCING ACTIVITIES:
Dividends paid......................... (2,851,660) (2,706,278) (2,592,288)
Issuance of common stock............... 1,447,063 1,048,703 856,007
Issuance of long-term debt............. -- 9,827,190 --
Retirements of preferred stock......... -- -- (336,000)
Principal retired on long-term debt.... (885,l74) (854,831) (828,758)
Changes in supplemental fuel
inventory............................. 249,040 449,778 (1,773,143)
Changes in notes payable, banks........ 3,512,000 (8,627,000) 7,050,000
Payment of ESOP debt................... -- (75,000) (150,000)
----------- ----------- -----------
NET CASH PROVIDED BY (USED IN)
FINANCING ACTIVITIES................ 1,471,269 (937,438) 2,225,818
----------- ----------- -----------
Net increase (decrease) in cash and cash
equivalents............................ (180,437) 131,404 166,601
Cash and cash equivalents at beginning
of year................................ 434,930 303,526 136,925
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF
YEAR................................... $ 254,493 $ 434,930 $ 303,526
=========== =========== ===========
SUPPLEMENTAL DISCLOSURES:
Cash paid during the year for:
Interest (net of amount capitalized).. $ 3,057,884 $ 3,227,502 $ 2,708,961
Income taxes.......................... $ 3,518,822 $ 2,682,465 $ 1,407,476
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
15
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
AUGUST 31, AUGUST 31,
1998 1997
----------- -----------
<S> <C> <C>
COMMON STOCK EQUITY:
Common stock, no par value, 5,000,000 authorized
shares. Issued and outstanding 1,729,007 shares at
August 31, 1998 and 1,685,318 issued and
outstanding at August 31, 1997.................... $21,805,225 $20,320,890
Unrealized gain (loss) on investments available for
sale, net......................................... (24,195) (6,253)
Retained earnings.................................. 16,514,556 15,094,008
----------- -----------
38,295,586 35,408,645
----------- -----------
LONG-TERM DEBT:
FIRST MORTGAGE BONDS:
10 1/4 percent, due serially from 1994 to 2003..... 3,600,000 4,200,000
10.10 percent, due serially from 2010 to 2020...... 8,000,000 8,000,000
7.28 percent due serially from 2008 to 2017........ 10,000,000 10,000,000
----------- -----------
21,600,000 22,200,000
----------- -----------
MORTGAGE NOTE:
8 1/2 percent, due serially from 1976 to 1998...... 75,361 360,535
----------- -----------
DEBENTURES:
8 5/8 percent, due 2006............................ 2,245,000 2,245,000
8.15 percent, due 2017............................. 4,954,000 4,954,000
----------- -----------
7,199,000 7,199,000
----------- -----------
TOTAL DEBT....................................... 28,874,361 29,579,535
Less: Current portion maturing and payable......... 675,361 960,535
----------- -----------
TOTAL LONG-TERM DEBT................................. 28,199,000 28,799,000
----------- -----------
TOTAL CAPITALIZATION............................. $66,494,586 $64,207,645
=========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
16
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
Essex Gas is a public utility engaged in the distribution and sale of
natural gas for residential, commercial and industrial uses. Its service area
is northeastern Massachusetts.
REGULATION
The Company is subject to regulation by the MDTE with respect to its rates
and accounting practices. For the periods presented, the accounting policies
conform to generally accepted accounting principles as applied to regulated
public utilities and reflect the effects of the ratemaking process in
accordance with Statement of Financial Accounting Standard No. ("SFAS") 71,
"Accounting for Certain Types of Regulation". Under SFAS No. 71, a utility is
allowed to defer certain costs that otherwise would be expensed in recognition
of the ability to recover them in future rates.
The Company has established regulatory assets in cases where the MDTE has
permitted or is expected to permit the recovery of specific costs over time.
As of August 31, 1998, regulatory assets include approximately $440,000 for
environmental costs, $260,000 related to a settlement payment for a
supplemental retirement plan, and $389,000 related to deferred income taxes.
Included in deferred credits is a regulatory liability of $665,000 related to
deferred income taxes. Assuming a cost-of-service based regulatory structure,
regulators may permit incurred costs, normally treated as expenses, to be
deferred and recovered through future rates. Through their actions, regulators
may also reduce or eliminate the value of an asset, or create a liability. As
described in Footnote K to the Financial Statements, the Company will be
unable to continue its application of SFAS No. 71 effective with the
Acquisition by Eastern Enterprises.
PRINCIPLES OF CONSOLIDATION AND PRESENTATION
The consolidated financial statements include the accounts of LNG Storage,
Inc., a wholly owned subsidiary. All material intercompany balances and
transactions have been eliminated.
Cash equivalents are defined as investments with an original maturity of
three months or less.
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 below at
Cost of Gas Adjustment Clause and Deferred Gas Costs.
COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause ("CGAC") requires the Company to adjust
its rates semi-annually for firm gas sales in order to track changes in the
cost of gas distributed with an annual adjustment of subsequent rates for any
collection over or under actual costs incurred. As a result, the Company
defers the cost of any firm gas that has been distributed, but is unbilled at
the end of a period, to a period in which the gas is billed to customers.
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 3.70 percent in 1998, 3.53
percent in 1997 and 3.03 percent in 1996.
17
<PAGE>
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.
ESTIMATES
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.
EARNINGS PER SHARE
In March 1997, the Financial Accounting Standards Board issued SFAS No. 128,
Earnings Per Share. SFAS No. 128 established standards for computing and
presenting earnings per share and applies to entities with publicly held
common stock or potential common stock. This statement is effective for fiscal
years ending after December 15, 1997 and early adoption is not permitted. The
statement requires restatement of prior years' earnings per share. The company
has adopted this statement for its fiscal year ended August 31, 1998.
RECLASSIFICATIONS
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
B. SUPPLEMENTAL FUEL INVENTORY
The Company, with MDTE approval, finances its supplemental gas inventory
through a single purpose financing arrangement extending through December 31,
2000. The credit agreement provides for a total commitment of up to
$10,000,000 and is secured by storage gas. All costs related to the financing
are recoverable from customers. The effective interest cost of the financing
was 6.20% in 1998 and 6.1% in 1997.
C. COMMON STOCK
Common Stock activity for the three-year period ended August 31, 1998, is as
follows:
<TABLE>
<CAPTION>
ADDITIONAL
NUMBER OF COMMON PAID-IN
SHARES STOCK CAPITAL
--------- ----------- -----------
<S> <C> <C> <C>
BALANCE, AUGUST 31, 1995.. 1,607,061 4,017,653 14,311,026
Dividend reinvestment
plan................... 19,754 366,787 100,916
Amortization of capital
stock expense.......... -- 50,229 --
Employee stock plans.... 11,319 226,881 52,370
Sale of common stock.... 4,356 97,283 11,770
Conversion to no par
value.................. -- 14,476,082 (14,476,082)
--------- ----------- -----------
BALANCE, AUGUST 31, 1996.. 1,642,490 19,234,915 --
Dividend reinvestment
plan................... 19,733 475,380 --
Amortization of capital
stock expense.......... -- 37,272 --
Employee stock plans.... 17,794 438,252 --
Sale of common stock.... 5,301 135,071 --
--------- ----------- -----------
BALANCE, AUGUST 31, 1997.. 1,685,318 $20,320,890 --
Dividend reinvestment
plan................... 12,652 476,579 --
Amortization of capital
stock expense.......... -- 37,272 --
Employee stock plans.... 27,967 865,061 --
Sale of common stock.... 3,070 105,423 --
--------- ----------- -----------
BALANCE, AUGUST 31, 1998.. 1,729,007 $21,805,225 $ --
========= =========== ===========
</TABLE>
18
<PAGE>
CONVERSION OF STOCK TO NO PAR VALUE
The shareholders approved conversion of Common Stock from $2.50 par value to
no par value effective September 15, 1995.
D. RESTRICTION ON RETAINED EARNINGS
Under the terms of the indenture securing the First Mortgage Bonds, retained
earnings in the amount of $6,680,789 as of August 31, 1998, were unrestricted
as to the payment of cash dividends on common stock and the purchase,
redemption or retirement of shares of common stock.
E. INTERIM FINANCING AND LONG-TERM DEBT
The Company periodically borrows from banks on an unsecured, short-term
basis. At August 31, 1998, the Company had $6,825,000 of outstanding notes
payable with a weighted average interest rate of 6.45 percent under available
lines of credit totaling $17,000,000. The annual commitment fees related to
these lines of credit are between 1/8 percent and 3/8 percent on the total
amount of the line.
Substantially all plant assets are pledged as collateral under the terms of
the indenture of First Mortgage Bonds. The 8 1/2 percent Mortgage Note
represents an obligation secured by the liquefied gas storage facility in
Haverhill, Massachusetts. In accordance with the terms of the indenture of
First Mortgage Bonds, the Note Purchase Agreement of the sinking fund notes
and the Mortgage Note, the Company is required to make specified sinking fund
payments and other maturities of long-term debt of $675,631 in 1999, $600,000
in 2000, $600,000 in 2001, $600,000 in 2002 and $26,399,000 thereafter.
F. DISCLOSURE ABOUT FAIR VALUES OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's long-term debt at August 31, 1998
and 1997 are $37,772,562 and $35,202,321, respectively, as compared to the
carrying value of $28,199,000 and $28,799,000, respectively. The estimated
fair value of the Company's long-term debt is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered
to the Company for debt of the same remaining maturity. The fair value shown
above does not purport to represent the amount at which these obligations
could be settled.
The carrying value of cash approximates fair value.
G. INCOME TAXES
The components of the provision for income taxes are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
FEDERAL
Current.............................. $1,948,230 $2,258,000 $ 294,144
Deferred............................. 104,257 (298,635) 1,569,000
Amortization of investment tax
credit.............................. (69,764) (69,764) (69,784)
---------- ---------- ----------
TOTAL FEDERAL...................... 1,982,723 1,889,601 1,793,360
---------- ---------- ----------
STATE
Current.............................. 395,957 454,643 58,643
Deferred............................. 20,686 (64,000) 321,000
---------- ---------- ----------
TOTAL STATE........................ 416,643 390,643 379,643
---------- ---------- ----------
TOTAL INCOME TAXES................. $2,399,366 $2,280,244 $2,173,003
========== ========== ==========
</TABLE>
19
<PAGE>
A reconciliation of federal income taxes calculated at the statutory rate
with income tax expense shown in the financial statements for each of the
three years ended August 31, is as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
Federal statutory rate................. 34.0% 34.0% 34.0%
========== ========== ==========
Federal income tax expense at statutory
rates................................. $2,265,922 $2,117,753 $2,048,628
Increase (decrease) in taxes resulting
from:
Amortization of investment tax
credit.............................. (69,764) (69,764) (69,784)
State taxes, net of federal benefit.. 274,984 257,824 250,564
Other................................ (71,776) (25,569) (56,405)
---------- ---------- ----------
TOTAL INCOME TAX EXPENSE........... $2,399,366 $2,280,244 $2,173,003
========== ========== ==========
EFFECTIVE INCOME TAX RATE.............. 36.0% 36.6% 36.1%
========== ========== ==========
</TABLE>
The Company follows the provisions of Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" ("SFAS No. 109"). SFAS No.
109 requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns. Under this method, deferred tax assets
and liabilities are determined based on the difference between the financial
statement and tax basis of assets and liabilities using enacted tax rates in
effect in the year in which the differences are expected to reverse. A
regulatory asset of $389,000 was established for deferred taxes not previously
recovered as a result of the flow through to customers for temporary timing
differences in prior years. This balance is being recovered over the estimated
remaining lives of the property. A regulatory liability of $665,000 was
established for the tax benefit of unamortized investment tax credits, which
SFAS No. 109 requires to be treated as a temporary difference. This benefit is
being passed on to customers over the lives of property giving rise to the
investment credits. Significant items making up deferred tax assets and
liabilities at August 31, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
----------- -----------
<S> <C> <C>
Liabilities
Utility Plant--primarily depreciation............. $11,698,486 $11,399,390
Other............................................. 310,250 476,162
----------- -----------
TOTAL LIABILITIES............................... $12,008,736 $11,875,552
----------- -----------
Assets
Investment tax credits............................ 664,765 708,053
Deferred directors fees........................... 364,222 423,624
Unbilled revenue.................................. 243,418 317,513
Reserve for uncollectible receivables............. 213,948 295,688
Deferred Gas Costs................................ 276,219 --
Supplier refund................................... -- 600,144
Capitalized cost--inventory....................... 928,282 443,739
Other............................................. 280,346 245,817
----------- -----------
TOTAL ASSETS.................................... 2,971,200 3,034,578
----------- -----------
ACCUMULATED DEFERRED INCOME TAXES, NET.............. $ 9,037,536 $ 8,840,974
=========== ===========
</TABLE>
The net year-end deferred income tax liabilities above are net of current
deferred tax assets of $587,308 and $100,105 respectively, which are included
in prepaid deferred income taxes in the accompanying Consolidated Balance
Sheets.
20
<PAGE>
H. LEASES
The Company is obligated under various lease agreements for certain
facilities and equipment used in operations. Total expenditures under
operating leases were $285,211 in 1998, $298,789 in 1997 and $315,152 in 1996.
A summary of property classified as capital leases as of August 31, 1998 and
1997 is as follows:
<TABLE>
<CAPTION>
1998 1997
---------- ----------
<S> <C> <C>
Buildings............................................. $1,123,796 $1,123,796
Less: Accumulated depreciation........................ 572,857 518,974
---------- ----------
$ 550,939 $ 604,822
========== ==========
</TABLE>
In accordance with the rate treatment allowed by the MDTE, depreciation
expense of $53,883, $49,568 and $45,600, along with interest of $48,617,
$52,931, $56,850 related to the capital lease, is included in other operating
expenses for the years ended August 31, 1998, 1997 and 1996, respectively.
The Company also has various operating lease agreements for equipment,
vehicles and office space. The remaining minimum annual rental commitment for
these and all other non-cancelable leases is as follows:
<TABLE>
<CAPTION>
CAPITAL LEASES OPERATING LEASES
-------------- ----------------
<S> <C> <C>
1999......................................... $102,500 121,726
2000......................................... 102,500 78,111
2001......................................... 102,500 22,569
2002......................................... 102,500 2,012
Thereafter................................... 324,406 --
-------- --------
Total minimum lease payments................. $734,406 $224,418
========
Less: Amount representing interest........... 183,467
--------
$550,939
========
</TABLE>
I. EMPLOYEE BENEFITS
PENSION PLANS
The Company has two pension plans covering substantially all employees.
Net pension cost included the following components:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ------------ -----------
<S> <C> <C> <C>
Service cost--benefits earned during
the year........................... $ 318,872 $ 286,362 $ 268,542
Interest cost on projected benefit
obligations........................ 778,479 752,921 722,354
Actual return on plan assets........ (1,700,203) (1,741,366) (1,125,838)
Net amortization and deferral....... 928,453 1,134,587 609,010
----------- ------------ -----------
NET PENSION COST.................. $ 325,601 $ 432,504 $ 474,068
=========== ============ ===========
</TABLE>
The expected long-term rate of return on assets was 9.0 percent in 1998 and
8.5 percent in both 1997 and 1996. The discount rate used in determining the
actuarial present value of the projected obligation was 7.0 percent in 1998,
7.5 percent in 1997 and 8.0 percent in 1996. The expected rate of pay increase
was 5.0 percent in 1998, 5.0 percent in 1997 and 6.0 percent in 1996.
21
<PAGE>
The following table sets forth the funding status of pension plans and
amounts recognized in the Company's balance sheets based on a measurement date
of August 31:
<TABLE>
<CAPTION>
1998 1997
------- -------
(IN THOUSANDS)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation.............................. $10,168 $ 9,257
======= =======
Accumulated benefit obligation........................... $10,791 $ 9,817
======= =======
Projected benefit obligation for service rendered to
date.................................................... $11,721 $10,689
Plan assets, primarily listed stocks, corporate bonds and
U.S. bonds, at fair value............................... 11,459 10,212
------- -------
Projected benefit obligation in excess of plan assets.... (262) (477)
Unrecognized net gain.................................... (1,765) (1,586)
Unrecognized prior service cost.......................... 1,472 1,635
Adjustment required to recognize additional minimum
liability............................................... (35) (44)
Unrecognized net obligation at transition................ (16) (7)
------- -------
Accrued pension liability................................ $ (606) $ (479)
======= =======
</TABLE>
Assets in the pension plan are currently held in mutual funds.
EMPLOYEE STOCK OWNERSHIP PLAN
On September 1, 1986, the Company created an Employee Stock Ownership Plan
and Trust ("ESOP"). The Company contributes annually to a trust an amount
equal to principal plus interest and any other fees net of interest income
earned by the trust and dividends on unallocated shares. The Trust was created
primarily to acquire shares of the Company's common stock for the exclusive
benefit of the participants (substantially all nonbargaining employees).
During fiscal 1987, the Trust borrowed $1,500,000 and acquired 82,800 shares,
as adjusted for a two-for-one stock split effective April 1, 1987, of the
Company's previously unissued common stock. The Company gaurantees the loan
and final payment of $75,000 was due in October, 1996. The ESOP was recorded
as a liability and the offsetting debit was accounted for as a reduction of
common stock equity in the accompanying consolidated balance sheets. Interest
was payable monthly at a floating rate, which was 80 percent of the current
prime rate. The charge to income, which equals the Company's contribution, for
1998 was $335,576, for 1997 was $174,006, and for 1996 was $223,477. Interest
on ESOP debt was $-0- for 1998, $839 for 1997 and $17,365 for 1996. Dividends
on unallocated ESOP shares used to pay debt service for all periods presented
was $0 for 1998, $5,699 for 1997 and $12,738 for 1996.
SAVINGS PLAN
The Company has a thrift savings plan in which the Company matches one-half
of employee contributions with the match capped at three percent. The Company
contributed $164,000, $169,000 and $132,000 to the Plan in 1998, 1997 and
1996, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The Company follows the provisions of Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions ("SFAS No. 106"). This standard requires the accrual of the
expected cost of such benefits during the employee's years of service and the
recognition of an actuarially determined postretirement benefit obligation
earned by existing retirees. The assumptions and calculations involved in
determining the accrual and the accumulated postretirement benefit obligation
closely parallel pension accounting requirements. Prior to 1994, the cost of
postretirement benefits was recognized on a pay as you go basis. The
cumulative effect of the implementation of SFAS No. 106 as of September 1,
1994 is being amortized over 20 years. The Company is recovering the full SFAS
No. 106 cost in rates.
22
<PAGE>
Net postretirement benefit cost included the following components:
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Service cost................................... $113,555 $103,140 $104,469
Interest cost.................................. 359,141 345,298 316,398
(Return) loss on plan assets................... (53,026) (35,551) (22,610)
Net amortization and deferral.................. 154,998 177,071 189,435
-------- -------- --------
NET POSTRETIREMENT BENEFIT COST.............. $574,668 $589,958 $587,692
======== ======== ========
</TABLE>
The following table sets forth the funded status of the plan and amounts
recognized in the Company's consolidated balance sheets based on a measurement
date of July 1.
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Accumulated postretirement benefit
obligation:
Retirees.......................... $(3,407,660) $(3,213,120) $(2,834,211)
Fully eligible active Plan
participants..................... (283,163) (162,946) (108,839)
Other active Plan participants.... (1,548,137) (1,481,702) (1,274,960)
----------- ----------- -----------
(5,238,960) (4,857,768) (4,218,010)
Plan assets at fair value......... 1,754,391 1,386,073 886,580
----------- ----------- -----------
Accumulated postretirement
obligation greater than Plan
assets............................. (3,484,569) (3,471,695) (3,331,430)
Unrecognized transition obligation.. 3,058,012 3,261,880 3,465,748
Unrecognized (gain) loss............ 221,700 8,588 (310,951)
----------- ----------- -----------
ACCRUED POSTRETIREMENT BENEFIT
COST............................. $ (204,857) $ (201,227) $ (176,633)
=========== =========== ===========
</TABLE>
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.25 percent in 1998 and 7.5 percent in
1997 and 1996. The annual increase in the cost of covered health care benefits
for 1998 was 7.75 percent for participants under age 65 and 6.5 percent for
over age 65, in 1997 was 8.75 percent for participants under age 65 and 7.0
percent for over age 65, and for 1996 was 9.5 percent for participants under
age 65 and 7.5 percent for over age 65. This increase gradually decreases to 5
percent in the year 2007 and thereafter. A 1.0 percent increase in the assumed
health care cost trend rate would have increased the cost computed under SFAS
No. 106 by $36,447 and increased the accumulated postretirement benefit by
$376,704 as of August 31, 1998.
The Company has established two Voluntary Employee Beneficiary Associations
("VEBA") trusts pursuant to section 501(c)9 of the Internal Revenue Code to
fund these benefits. The Company also created a subaccount to its pension plan
pursuant to section 401(h) of the Internal Revenue Code to satisfy a portion
of its obligation. The Company made contributions to the trusts and the
subaccount during 1998 and 1997 totaling $566,334 and $560,241, respectively.
Assets in the VEBA trusts are held in cash reserve accounts. Assets in the
subaccount to the pension plan are currently held in listed stocks, corporate
bonds and government bonds.
STOCK OPTION PLANS
In 1995 the Company adopted an Incentive Stock Option Plan and a Non-
Qualified Stock Option Plan (the Plans) under which options may be granted to
officers and key employees. Options for an aggregate of 100,000 shares may be
granted under the Plans with not more than 25,000 shares granted during any
one year to any individual. During 1995, the Company granted a total of 20,000
shares under the Incentive Stock Option Plan and 4,000 shares under the Non-
Qualified Stock Option Plan at a price of $24.25 with exercise dates beginning
February 9, 1996 and ending February 9, 2000. No options were granted,
exercised or expired during either 1997
23
<PAGE>
or 1998. At August 31, 1998, options covering 24,000 shares were outstanding
and 9,600 were exercisable under the Plans. In addition, 76,000 shares under
the Plans are available for future grants.
In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock-Based Compensation, which sets forth a fair market
value based method of recognizing stock-based compensation expense. As
permitted by SFAS No. 123, the Company has elected to continue to apply APB
No. 25 to account for its stock option plans. Had compensation cost for awards
in fiscal 1996, 1997 and 1998 under the Company's Incentive Stock Option Plan
and Non-Qualified Stock Option Plan been determined based on the fair market
value at the grant dates consistent with the method set forth under SFAS No.
123, the effect would have been as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
Net income:
As reported............................... $4,272,208 $3,966,519 $3,835,500
Pro forma................................. $4,267,492 $3,958,518 $3,821,855
Earnings per share:
As reported............................... $ 2.50 $ 2.38 $ 2.36
Pro forma................................. $ 2.48 $ 2.37 $ 2.35
</TABLE>
The fair value of each option granted is estimated on the grant date using
the Black-Scholes option pricing model. The weighted average grant date fair
value of options granted was $1.88. In computing the above pro forma amounts
the Company has assumed a risk-free interest rate of 6.2 percent, an expected
life of 4 years, an expected volatility of 11.5 percent and an expected
dividend yield of 6.2 percent.
J. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION EXPENDITURES
The Company's construction expenditures in connection with its continuing
construction program are presently estimated at $6,800,000 for 1999, and
approximately $7,000,000 in each of the following three years.
GAS SUPPLY, TRANSPORTATION AND STORAGE
The Company has various long-term gas supply, transportation and storage
contracts with minimum cost provisions. Under these contracts, the Company is
obligated to make specified minimum payments. Based on current rates and/or
agreements, the minimum annual payments under these contracts are as follows:
<TABLE>
<CAPTION>
1998 TO 2000
------------
<S> <C>
Pipeline Transportation Demand.................................. $3,870,792
Underground Storage Demand...................................... 495,072
Underground Storage Transportation.............................. 707,928
Pipeline Gas Inventory Charge................................... 2,703,564
----------
$7,777,356
==========
</TABLE>
FERC Order 636 allows the pipeline companies to recover transition costs
created as they buy out of long-term, fixed price contracts. Tennessee Gas
Pipeline Company began direct billing these costs to the Company on September
1, 1993 as a component of the demand charges. At August 31, 1998, the
transition cost obligation has been fully recovered through the CGAC as
allowed by the MDTE.
24
<PAGE>
LITIGATION MATTERS
The Company is a defendant in various civil actions, which are covered by
insurance and reserves. Based on the advice of legal counsel, management
believes that the Company has adequate defenses against these claims and, in
view of the insurance coverage and reserves, the potential liability would not
materially affect the financial condition or the results of operations of the
Company.
ENVIRONMENTAL MATTERS
The Company, like many other companies in the natural gas industry, is party
to governmental proceedings requiring investigation and possible remediation
of former manufactured gas plant ("MGP") sites. The Company may have or share
responsibility under applicable environmental laws for the remediation of 4
such sites, as well as for one non-MGP site. The Company has estimated its
potential share of the costs of investigating and remediating these sites in
accordance with Statement of Financial Accounting Standards No. 5, "Accounting
for Contingencies," and the American Institute of Certified Public Accountants
Statement of Position 96-1, "Environmental Remediation Liabilities." The
Company's best estimate at this time of remediation costs is approximately
$400,000. However, there can be no assurance that such cost will not vary
considerably from this estimate. Factors that may bear on costs differing from
estimates include, without limit, changes in regulatory standards, changes in
remediation technologies and practices and the type and extent of contaminants
discovered at the sites.
The Company is aware of one other former MGP site within its service
territory. At this time, there is substantial uncertainty as to whether the
Company has or shares responsibility for remediating this site. No notice of
responsibility has been issued to the Company for this site from any
governmental authority.
The Company has received and responded to a Request for Information from the
U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the
Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), regarding a federal superfund site which the EPA is currently
investigating. It is not possible at this time to reasonably estimate the
amount of the Company's obligation for remediation of the site; however, the
Company expects that its share, if any, will be de minimis.
By a rate order issued on May 25, 1990, the Department approved recovery of
all prudently incurred environmental response costs associated with former MGP
sites over separate, seven-year amortization periods, without a return on the
unamortized balance. The Company currently believes, in light of the MDTE rate
order on environmental cost recovery, that it is not probable that such costs
will materially affect its financial condition or results of operations.
K. SUBSEQUENT EVENT
On September 30, 1998, Essex Gas Company was merged with ECGC Acquisition
Gas Company, a wholly-owned subsidiary of Eastern Enterprises, by an exchange
of all of the Company's stock for approximately 2,047,000 shares of Eastern
Enterprises common stock, with the Company surviving as a wholly-owned
subsidiary of Eastern (the "Acquisition"). Eastern Enterprises also owns
Boston Gas Company, which operates a natural gas distribution system for
approximately 530,000 customers that is contiguous to Essex Gas. Boston Gas
Company will integrate many of Essex Gas' administrative and operating
functions with its own, and will serve the customers of both companies with a
consolidated supply portfolio.
Nonrecurring integration and transaction costs from the Acquisition are
expected to total approximately $6.5 million, of which approximately $1.7
million has been incurred and recorded as a deferred charge on the balance
sheet as of August 31, 1998. These costs, net of any related tax benefits,
will be recorded as a charge to earnings in the period ended September 30,
1998. Integration and transaction costs from the Acquisition primarily include
investment banking fees, employee separation costs and other professional
fees. In addition, as a result of the rate plan described below, the Company
will be required to record an extraordinary charge of approximately
25
<PAGE>
$5.1 million, pretax, to reflect the discontinuance of the application of SFAS
No. 71 Accounting for the Effects of Certain Types of Regulation.
In accordance with the merger and rate plan approved on September 17, 1998,
Essex Gas customers will receive a five percent reduction through the CGAC
mechanism, reflecting expected gas supply cost savings. In addition, base
rates are frozen for a period of ten years. As a result of the rate reduction
and the ten year freeze in base rates, Essex Gas is required to discontinue
its application of SFAS No. 71. Effective September 30, 1998, Essex Gas will
write-off approximately $5.1 million primarily consisting of previously
deferred post-retirement health care costs and other regulatory assets.
26
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Essex County Gas Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Essex County Gas Company (a Massachusetts corporation) as
of August 31, 1998 and 1997, and the related consolidated statements of
income, retained earnings and cash flows for each of the three years in the
period ended August 31, 1998. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Essex
County Gas Company as of August 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the period ended
August 31, 1998, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the index to
consolidated financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not a part of the basic
financial statements. The schedule has 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
October 23, 1998
27
<PAGE>
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(b) Selected Quarterly Financial Data
YEAR ENDED AUGUST 31, 1998
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-------------------------------------------------------------
NOVEMBER 30, FEBRUARY 28, MAY 31, AUGUST 31,
1997 1998 1998 1998 TOTAL
------------ ------------ ----------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Operating revenues...... $9,034,815 $23,027,508 $14,154,192 $4,604,435 $50,820,950
Operating income........ 940,911 3,901,570 1,683,374 593,114 7,118,969
Income (loss) applicable
to common shares....... 176,528 3,246,456 999,650 (150,426) 4,272,208
Earnings (loss) per
common share........... .10 1.91 .58 (.09) 2.50
Dividends declared per
common share .41 .42 .42 .42 1.67
Stock price range:
High.................. 32.75 49.00 47.00 47.13
Low................... 26.00 31.25 44.00 44.00
</TABLE>
YEAR ENDED AUGUST 31, 1997
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-------------------------------------------------------------
NOVEMBER 30, FEBRUARY 28, MAY 31, AUGUST 31,
1996 1997 1997 1997 TOTAL
------------ ------------ ----------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Operating revenues...... $8,142,501 $23,220,840 $16,659,598 $5,511,795 $53,534,734
Operating income........ 471,157 3,814,227 1,971,507 464,672 6,721,563
Income (loss) applicable
to common shares....... (260,669) 3,131,438 1,256,125 (160,375) 3,966,519
Earnings (loss) per
common share........... (.16) 1.89 .75 (.10) 2.38
Dividends declared per
common share........... .40 .41 .41 .41 1.63
Stock price range:
High.................. 27.00 25.75 26.00 27.00
Low................... 24.00 24.25 24.25 25.25
</TABLE>
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Not required.
ITEM 11: EXECUTIVE COMPENSATION
Not required.
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not required.
28
<PAGE>
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not required.
PART IV
ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
A) Documents filed as part of this report:
1. The Financial Statements of the Company, on pages 10 through 26, and
the Report of Arthur Andersen LLP on page 27 therein.
2. Financial Statement Schedules.
The following supplementary financial statement schedules required by Rule
5-04 of Regulation S-X, and report thereon, are filed as part of this Form 10-
K on the page indicated below:
<TABLE>
<CAPTION>
SCHEDULE PAGE NO. IN
NUMBER DESCRIPTION THIS REPORT
-------- ----------- -----------
<C> <S> <C>
II Consolidated Valuation and Qualifying Accounts for the
three years ended August 31, 1998 29
Report of Independent Public Accountants 27
</TABLE>
Schedules other than the one listed above are either not required or not
applicable, or the required information is shown in the financial statements
or notes thereto.
3. Exhibits required by Item 601 of Regulation S-K.
See Exhibit Index on pages 31 through 33.
B) Reports on Form 8-K.
Form 8-K filed on June 29, 1998
Form 8-K filed on October 14, 1998
C) Exhibits required by Item 601 of Regulation S-K.
See Exhibit Index on pages 44 through 47.
D) Financial Statement Schedules.
CONSOLIDATION VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
Reserves which are deducted in the balance sheets from assets to that they
supply
<TABLE>
<CAPTION>
CHARGED CHARGED
BALANCE AT TO TO BALANCE
YEAR ENDED BEGINNING COSTS AND OTHER AT END OF
AUGUST 31 DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(1) DEDUCTIONS PERIOD
- ---------- ------------------------------- ---------- --------- ----------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998.................... Allowance for doubtful accounts $772 $431 $110 $754 $559
1997.................... Allowance for doubtful accounts $653 $614 $167 $662 $772
1996.................... Allowance for doubtful accounts $595 $613 $164 $719 $653
</TABLE>
- --------
(1) Represents recoveries on accounts previously written off
29
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.
Essex Gas Company
(Registrant)
/s/ J.F. Bodanza
By: _________________________________
J.F. BODANZA SR. VICE PRESIDENT
AND TREASURER (PRINCIPAL FINANCIAL
AND ACCOUNTING OFFICER)
Date: November 30, 1998
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 30TH DAY OF NOVEMBER 1998.
<TABLE>
<S> <C>
SIGNATURE TITLE
/s/ C.R. Messer, II
- ------------------------------------- Director and
C.R. MESSER, II President
/s/ J.F. Bodanza Director and Senior Vice
- ------------------------------------- President and Treasurer
J.F. BODANZA (Principal Financial and
Accounting Officer)
/s/ J.A. Ives Director
- -------------------------------------
J.A. IVES
/s/ F.C. Raskin Director
- -------------------------------------
F.C. RASKIN
/s/ W.J. Flaherty Director
- -------------------------------------
W.J. FLAHERTY
/s/ A.J. DiGiovanni Director
- -------------------------------------
A.J. DIGIOVANNI
/s/ L.W. Law, Jr. Director
- -------------------------------------
L.W. LAW, JR.
</TABLE>
30
<PAGE>
EXHIBIT INDEX
The exhibits listed below are filed herewith or are incorporated by reference
to other filings.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 Restated Articles of Organization of Essex County Gas Company.(10)
3.2 Bylaws of Essex County Gas Company.(11)
4.1 Indenture dated as of June 1, 1986 between the Company and Centerre
Trust Company of St. Louis, Trustee.(2)
4.2 Eleventh Supplemental Indenture dated as of September 15, 1988,
providing for a 10 1/4 percent Series due 2003.(1)
4.3 Twelfth Supplemental Indenture dated as of December 1, 1990, providing
for a 10.10 percent Deries due 2020.(4)
4.4 Revolving Credit Agreement dated November 14, 1995 between Essex
County Gas Company and the First National Bank of Boston.(12)
4.5 Fifteenth Supplemental Indenture dated as of December 1, 1996
providing for a 7.28 percent Series due 2017.(13)
10.1 LNG Storage, Inc., Lease Indenture of Mortgage and Deed of Trust dated
April 10, 1972.(1)
10.2 Haverhill Familee Investment Corporation--Lease of Corporate
Headquarters dated November 1, 1975.(1)
10.3 Arlington Trust Company--Purchase Contract, Credit Agreement, Trust
Agreement and Storage Agreement dated October 1, 1980.(1)
10.4 Consolidated Gas Supply Corporation--Underground Storage Contract
dated February 18, 1980.(1)
10.5 Penn-York Energy Corporation--Storage Services Agreement dated
December 21, 1984.(1)
10.6 Canadian Gas Transportation Contract between Tennessee Gas Pipeline
Company and Essex County Gas Company dated December 1, 1987.(3)
10.7 Phase 2 Gas Sales Agreement between Boundary Gas and Essex County Gas
Company dated September 14, 1987.(3)
10.8 Amendment to the Agreement for the Sale of Gas between Bay State Gas
Company and Essex County Gas Company dated May 6, 1988.(3)
10.9 Agreement for the Liquefaction of Gas between Bay State Gas Company
and Essex County Gas Company dated March 14, 1988.(3)
10.10 Bond Purchase Agreement dated December 1, 1990, between Allstate Life
Insurance Company of New York, and Essex County Gas Company.(4)
10.11 Iroquois Gas Transmission System, L.P. Gas Transportation Contract for
Firm Reserved Service dated February 7, 1991.(3)
10.12 Alberta Northeast Gas Limited (ANE), Gas Sales Contract Agreement No.
1 dated February 7, 1991.(5)
10.13 Aquila Energy Marketing Corporation Gas Sales Agreement dated June 5,
1992.(5)
10.14 Natural Gas Clearinghouse Gas Sales Agreement dated June 8, 1992.(5)
10.15 Tennessee Gas Pipeline Transportation Contract dated February 7,
1991.(6)
10.16 Tennessee Gas Pipeline Company Gas Storage Contract (SS-NE)
TGP002099STO dated November 10, 1991.(6)
10.17 Tennessee Gas Pipeline Company Storage Service Transportation Contract
TF-4175 dated October 28, 1991.(6)
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.18 Form of employment agreement between the Company and each of the
following officers: Wayne I. Brooks, Vice President; John W. Purdy,
Jr., Vice President; James H. Hastings, Vice President and Treasurer;
Allen R. Neale, Vice President; and Cathy E. Brown, Clerk. These
contracts are identical to those submitted with the Annual Report for
each with the exception of compensation amounts.(2)*
10.19 Employment Agreement between the Company and Philip H. Reardon,
President, dated November 19, 1992.(7)*
10.20 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule)
dated September 1, 1993.(8)
10.21 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule)
dated August 25, 1993.(8)
10.22 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under Transportation Service
"CGT-NE" Rate Schedule) dated September 1, 1993.(8)
10.23 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule)
dated September 1, 1993.(8)
10.24 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under Rate Schedule FS) dated
September 1, 1993.(8)
10.25 Amendment to Employment Agreement between the Company and Philip H.
Reardon, President, dated March 3, 1994.*
10.26 Amendment to Employment Agreement between the Company and John W.
Purdy, Jr., Vice President, dated March 3, 1994.*
10.27 Amendment to Employment Agreement between the Company and Wayne I.
Brooks, Vice President, dated March 3, 1994.*
10.28 Amendment to Employment Agreement between the Company and Allen R.
Neale, Vice President, dated March 3, 1994.*
10.29 Amendment to Employment Agreement between the Company and James H.
Hastings, Vice President and Treasurer, dated March 3, 1994.*
10.30 Amendment to Employment Agreement between the Company and Cathy E.
Brown, Corporate Clerk, dated March 3, 1994.*
10.31 Essex County Gas Company Supplemental Retirement Plan for Philip H.
Reardon effective January 1, 1994.*
10.32 Employment Agreement between the Company and William T. Beaton, Vice
President, dated June 7, 1995.*
27 Financial Data Schedule.
B) Reports on Form 8-K.
Form 8-K filed on June 29, 1998.
Form 8-K filed on October 14, 1998.
</TABLE>
- --------
* Denotes Management Contract.
(1) Previously filed as an exhibit to Registrant's Registration Statement on
Form S-7, filed October 23, 1981, File No. 2-74531 and is incorporated
herein by this reference.
(2) Previously filed as an exhibit to Registrant's Registration Statement on
Form S-2, filed June 19, 1986, File No. 33-6597 and are incorporated
herein by this reference.
(3) Previously filed as an exhibit to Registrant's 10-Q filed for the quarter
ended February 29, 1996, and is incorporated herein by this reference.
32
<PAGE>
(4) Previously filed as an exhibit to Registrant's 10-Q filed for the quarter
ended February 28, 1991, and is incorporated herein by this reference.
(5) Previously filed as an exhibit to Registrant's 10-Q filed for the quarter
ended May 31, 1992, and is incorporated herein by this reference.
(6) Previously filed as an exhibit to Registrant's 10-K filed for the fiscal
year ended August 31, 1992, and are incorporated herein by this reference.
(7) Previously filed as an exhibit to Registrant's Form S-3, No. 33-69736,
filed on September 30, 1993, and is incorporated herein by this reference.
(8) Previously filed as an exhibit to Registrant's Form 10-K filed for the
fiscal year ended August 31, 1993, and is incorporated herein by this
reference.
(9) Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended May 31, 1996 and is incorporated herein by this reference.
(10 Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended February 28, 1995 and is incorporated herein by this
reference.
(11) Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended May 31, 1998 and is incorporated herein by this reference.
(12) Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended November 30, 1996 and is incorporated herein by this
reference.
(13) Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended February 28, 1998 and is incorporated herein by this
reference.
33
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE
SHEET, STATEMENT OF INCOME AND STATEMENT OF CASH FLOWS CONTAINED IN FORM 10-K OF
ESSEX COUNTY GAS COMPANY FOR THE TWELVE MONTHS ENDED AUGUST 31, 1998 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
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0
0
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0
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