<PAGE> 1
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, 1996.
/ / 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 COUNTY GAS COMPANY
(Exact name of Registrant as specified in its charter)
Massachusetts 04-1427020
(State of organization) (IRS Employer Identification No.)
7 North Hunt Road, Amesbury, Massachusetts 01913
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(508)388-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of Class Exchange
Common Stock, No Par Value NASDAQ/NMS
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. /X/
The aggregate market value of the voting stock held by
non-affiliates on October 31, 1996 based upon the last sales
price on that date was approximately $41,682,978. The number of
shares outstanding of the registrant's common stock, no par
value was 1,650,847 at October 31, 1996.
<PAGE> 2
DOCUMENTS INCORPORATED BY REFERENCE: Part III hereof
incorporates by reference portions of the definitive Proxy
Statement dated December 2, 1996, for the Annual Meeting of
Stockholders to be held January 21, 1997. Part IV hereof
incorporates by reference certain of the Exhibits to the
following documents: Registration Statement No. 2-74531 on Form
S-7, filed October 23, 1981, Registration Statement No. 33-6597
on Form S-2 filed on June 19, 1986, Registration Statement No.
33-69736 on Form S-3, filed on September 30, 1993, Registrant's
Annual Report on Form 10-K for fiscal 1988, Registrant's Annual
Report on Form 10-K for fiscal 1992, Registrant's Annual Report
on Form 10-K for fiscal 1993, Registrant's Quarterly Report on
Form 10-Q for the Quarter ended February 28, 1991, Registrant's
Quarterly Report on Form 10-Q for the Quarter ended May 31, 1992,
Registrant's Quarterly Report on Form 10-Q for the Quarter ended
February 28, 1995 and Registrant's Quarterly Report on Form 10-Q
for the Quarter ended May 31, 1995.
<PAGE> 3
ESSEX COUNTY GAS COMPANY
FORM 10-K
Annual Report
Year Ended August 31, 1996
---------------------------
Table of Contents
Item No. Topic Page
PART I
1. Business 1
2. Properties 10
3. Legal Proceedings 10
4. Submission of Matters to a Vote of Security Holders 10
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters 11
6. Selected Financial Data 12
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
8. Financial Statements and Supplementary Data 19
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 36
PART III
10. Directors and Executive Officers of the Registrant 37
11. Executive Compensation 37
12. Security Ownership of Certain Beneficial Owners and
Management 37
13. Certain Relationships and Related Transactions 37
PART IV
Signatures 38
14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K 40
<PAGE> 4
PART I
Item 1: Business
General
The Company, a regulated public utility organized under the
laws of the Commonwealth of Massachusetts in 1853, purchases,
distributes and sells natural gas to residential, commercial and
light industrial customers in northeastern Massachusetts. The
Company operates in the cities of Haverhill, Newburyport,
Amesbury and fourteen smaller municipalities covering an area
of approximately 280 square miles. The year-round population of
the Company's service area was approximately 165,000 in the
1990 Census.
The Company's service area is primarily comprised of
residential communities with a number of small commercial and
diversified light industrial businesses. The local economy, not
unlike economic conditions in general, had been weak with a
resultant slowdown in new construction, especially commercial
construction during the early 1990s. However, during the last few
years there has been a significant increase in new residential
construction. New home construction activity significantly
impacts the degree to which the Company is able to grow its
customer base.
Sales and Customer Data
The Company sells natural gas to over approximately 42,000
customers in its service area. 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 severity of the
weather. The Company's rates are designed to recover added costs
associated with peak operations during the winter months. In
fiscal 1996, the Company's total operating revenues were
$49,929,389 of which approximately 63.8% was derived from
residential customers, 29.7% from commercial and industrial
customers, 4.5% from interruptible customers and 2.0% from other
sources. During this period, the Company sold 6,561,365 thousand
cubic feet of gas (Mcf), of which approximately 55.5% was
purchased by residential customers, 31.1% by commercial and
industrial customers and 13.5% by interruptible customers.
Losses and company use amounted to 87,501 Mcf for 1996.
Set forth in the following table is information by customer
classification showing operating revenues, gas delivered and
number of customers for the periods indicated.
<PAGE> 5
Fiscal Year Ended August 31,
1996 1995 1994 1993 1992
(Dollars and Mcfs in Thousands)
Operating Revenues:
Residential-general $ 2,208 $ 2,159 $ 2,291 $ 2,160 $ 2,070
Residential-heating 29,644 26,589 29,245 27,218 25,150
Commercial and Industrial 14,838 13,353 15,000 14,006 13,432
Interruptible 2,216 1,933 888 653 1,316
Other 1,023 1,016 1,112 979 945
------- ------- ------- ------- -------
Total $49,929 $45,050 $48,536 $45,016 $42,913
======= ======= ======= ======= =======
Gas Delivered (Mcf):
Residential-general 151 148 159 158 158
Residential-heating 3,489 3,045 3,325 3,228 3,083
Commercial and Industrial 2,038 1,843 2,014 1,948 1,927
Interruptible 883 915 389 273 669
------- ------- ------- ------- -------
Total Sales 6,561 5,951 5,887 5,607 5,837
Losses and Company Use 88 86 79 89 101
Total 6,649 6,037 5,966 5,696 5,938
======= ======= ======= ======= =======
Number of Customers at Year-End:
Residential-general 7,328 7,369 7,560 7,439 6,776
Residential-heating 30,025 29,028 28,093 27,434 27,522
Commercial and Industrial 4,173 4,125 3,961 3,884 3,863
Interruptible 2 2 2 2 2
------- ------- ------- ------- -------
Total 41,528 40,524 39,616 38,759 38,163
======= ======= ======= ======= =======
Effective Degree Days
(20-Year Average: 6,813) 6,947 6,258 7,012 6,956 6,750
The Company's residential customers are classified as either
general or heating customers. In fiscal 1996,
residential-heating customers accounted for approximately 59.4%
of total operating revenues, while residential-general customers
accounted for approximately 4.4% of total operating revenues.
Operating revenues from residential customers increased
approximately 10.8% to $31,852,683 in fiscal 1996 from
$28,747,790 in fiscal 1995. The sales increase was attributable
to the relatively colder winter in fiscal 1996 compared to fiscal
1995 as residential volumes increased 14.0%. The average rate
charged to residential customers per Mcf of gas was $8.75 and
$9.00 in fiscal 1996 and 1995, respectively. The decrease in fiscal
1996 was primarily attributable to lower gas costs incurred by the
Company due to the return to customers of pipeline supplier refund
and previously overcollected gas costs.
<PAGE> 6
The Company's commercial and industrial firm revenues
increased approximately 11.1% to $14,837,612 in fiscal 1996 from
$13,353,053 in fiscal 1995. The increase was attributable to a
10.6% volume increase and a 0.4% increase in the average price
charged per Mcf of gas from $7.25 to $7.28. The sales increases
were largely attributable to colder weather experienced during
the winter in fiscal 1996 as compared to fiscal 1995.
The Company has two interruptible customers, only one of
which purchased significant amounts of gas from the Company in
fiscal 1996. Total interruptible revenues in fiscal 1996 were
$2,215,677 compared to $1,932,751 in fiscal 1995. Sales of gas
to interruptible customers do not materially affect the Company's
operating income because the Company is required to return all
gross profit on such sales to the Company's firm customers unless
interruptible volumes exceed a certain threshold specified by the
Massachusetts Department of Public Utilities ("MDPU"). Once that
threshold is attained, the Company may retain 10% of gross
profits. The threshold was attained in fiscal 1996 with
approximately $5,000 retained by the Company. Any gross profit
returned to the customers is returned through a Cost of Gas
Adjustment ("CGA") under which the Company is permitted to
recover its gas costs. The average price charged by the Company
to interruptible customers was $2.51 per Mcf and $2.11 per Mcf in
1996 and 1995, respectively.
The Company's largest customer purchases gas on an
interruptible basis and accounted for approximately 3.0% of
operating revenues on average over the past three fiscal years
ended August 31, 1996. Sales to that customer in 1996 totaled
$2,201,142 or 4.4% of total Company operating revenues. Since
most of the gross profit earned on interruptible sales is
returned to firm customers, the Company believes that the loss of
its largest on any single customer would not have a material effect
on the Company's results of operations.
In addition to its principal business of gas sales, the
Company rents water heaters and conversion burners and performs
service work. Net revenues from rental operations and service
work represented less than 2.2% of the total operating revenues
of the Company over the past three years ended August 31, 1996.
During 1996, the Company added over 1,200 new customers. In
fiscal 1995 and 1994, new customer additions (which
approximated gross additions) were 1168 and 1013, respectively.
Gas Supply
The Company contracts for its gas supply on the basis of
forecasted demand which is derived from historical weather
patterns recorded since 1960. The maximum peak day demand
during the last five fiscal years was 46,768 Mcf on February 6,
1995. Maximum peak day demand for 1996 was 46,017 Mcf and on
February 4, 1996 peak day demand was 45,500 Mcf.
The Company has the ability to meet a peak day demand of
<PAGE> 7
approximately 65,000 Mcf. peak day demand for gas is affected
by numerous factors, including the severity of the weather and
the number of firm customers. Total gas sendout by the Company
in fiscal 1996 was 6,648,866 Mcf compared to 6,037,442 Mcf in
1995 and 5,965,627 in fiscal 1994.
The following table shows the sources of the Company's gas
supply requirements for the periods indicated.
Fiscal Years Ended August 31,
1996 1995 1994 1993 1992
Gas Supply (Mcf):
Natural gas delivered
directly by pipeline 5,172,708 4,844,912 4,780,294 4,222,801 5,344,754
Underground storage
withdrawn 1,035,011 820,493 820,102 1,271,670 459,594
Liquefied natural gas
produced 441,147 372,037 365,231 201,439 133,171
--------- --------- --------- --------- ---------
Total 6,648,866 6,037,442 5,965,627 5,695,910 5,937,519
========= ========= ========= ========= =========
For the year ended August 31, 1996, approximately 77.8% of
the Company's gas supply was delivered by Tennessee Gas Pipeline
Company ("TGPC"), a division of Tenneco, with supplemental
sources supplying the remainder.
The Company has a firm transportation contract with TGPC
which provides for daily delivery of 15,728 dekatherms ("DTH")
(each DTH is approximately 0.975 Mcf) through November 1, 2000.
TGPC is currently delivering such quantities on a firm basis as
authorized by the Federal Energy Regulatory Commission ("FERC").
In connection with the implementation of FERC Order 636, the
Company has converted its natural gas purchase contract with TGPC
into several firm gas supply contracts directly with other gas
suppliers. These long-term contracts have been approved by the
MDPU. All contracts are with major suppliers that have a
demonstrated track record of performance and are at market
sensitive prices. In addition to contracts with Aquila Energy
and Natural Gas Clearinghouse for 2,500 DTH each per day for nine
years, the Company, through the efforts of the Mansfield
Consortium, negotiated contracts with Tenngasco for 4,410 DTH per
day expiring October 31, 1999; Enron for 4,409 DTH per day
expiring October 31, 1999; and Natural Gas Clearinghouse for an
additional 1,909 DTH per day expiring September 1, 2002, to
complete its transition under FERC Order 636. See "Item 1:
Business--Regulatory Matters--FERC Matters".
The Company also purchases gas from Boundary Gas, Inc.
("Boundary"). Pursuant to a supply contract with Boundary
expiring on January 15, 2003, the
<PAGE> 8
Company may take up to a maximum of 1,610 Mcf per day from
Boundary and may purchase up to 587,650 Mcf per year, the annual
quantity limitation for the contract. The Company began in
January 1988 taking up to a maximum of 1,610 Mcf per day.
Pursuant to a supply contract with Boundary, the Company is
required to purchase 75% of this maximum amount per year or its
daily capacity will be reduced proportionately based on the level
actually taken by the Company during such year. The Company
purchased 569,346 Mcf in fiscal 1996 or 96.9% of the annual
quantity limitation. The Company has a firm transportation
contract with TGPC for the delivery of the Boundary supply.
The Company also purchases gas from Alberta Northeast Limited
("ANE"). In December 1991, the Company began to receive
deliveries of 2,000 Mcf per day (approximately 2,051 DTH per day)
of this Canadian gas from ANE after ANE received approvals from
the National Energy Board of Canada and the Economic Regulatory
Administration of the United States. Under its contract with
ANE, the Company may purchase up to 717,193 Mcf per year
(approximately 735,583 DTH per year), the annual quantity
limitation for the contract. The contract requires the Company
to purchase at least 60% of the annual quantity limitation per
year or its daily capacity will be reduced proportionately based
on the level actually taken by the Company during such year. The
Company purchased approximately 710,085 Mcf in fiscal 1996 or
99.0% of the contracted amount in fiscal year 1996. The Company
has firm transportation contracts with the Iroquois Pipeline and
TGPC for the delivery of the above-mentioned volumes.
The Company has three contracts for underground storage with
a total storage capacity of approximately 1,461,868 Mcf. The
Company used a total of 1,035,011 Mcf, including 37,308 Mcf of
fuel gas, of its total underground storage in fiscal 1996.
Under a contract expiring November 1, 2000, the Company
assumed its pro rata share of TGPC underground storage. The
Company received storage capacity of 780,928 DTH and 5,172 DTH
per day of deliverability, as well as the ability to fill the
storage with gas obtained from any supplier. This service
augments the Company's ability to meet high delivery demand in
the winter and to take advantage of lower off-season gas prices.
The Company also has a contract expiring April 1, 2000 for
underground storage with Consolidated Supply Corporation for
a total volume of 359,450 DTH. The contract is backed by a
transportation contract with TGPC for the same period, which
provides for the withdrawal from storage and delivery to the
Company of up to 3,268 DTH per day (approximately 3,186 Mcf per
day) on a firm basis.
The Company's third contract for underground storage is with
National Fuel Gas Supply ("National Fuel") and extends through
March 31, 1997. The total storage volume under this contract is
350,000 Mcf, and the maximum daily withdrawal is 3,182 Mcf. The
contract is backed by a transportation contract with TGCP which
has been authorized by FERC to deliver to the Company
approximately 787 Mcf per day from this storage facility on a
firm basis and the balance on a "best efforts" basis. The
Company has notified National Fuel that it is terminating the
contract as of March 31, 1997. In order to replace the capacity
of the National Fuel contract, the Company has entered into an
agreement with Distrigas of Massachusetts Corporation ("DOMAC"),
which expires
<PAGE> 9
October 31, 2006, that allows the Company to purchase up to 4,000
DTH/day for 151 days of Liquid Natural Gas as either a liquid or
a vapor. The Company, at its discretion, may increase purchases
under the contract by up to an additional 2,000 DTH/day after
appropriate notice. The Company may also reduce quantities
purchased if normal sales dip below the normal 1994-95 heating
season sendout.
These underground storage arrangements allow the Company to
maximize firm gas supply purchases while allowing the Company to
take full advantage of the spot market gas prices during the
summer and other periods when such gas is not required to meet
customer demands. The stored gas is withdrawn during periods of
high demand to assist the Company in meeting firm delivery
requirements.
Through a wholly owned subsidiary, the Company owns a
liquefied natural gas ("LNG") storage facility located in
Haverhill, Massachusetts. The LNG storage facility has a storage
capacity of 400,000 Mcf and has a daily sendout capacity of
30,000 Mcf. In fiscal 1996, sendout of LNG totaled 441,147 Mcf.
At the same location, the Company owns and operates a propane
plant that has a storage capacity equivalent of approximately
40,000 Mcf with a total daily sendout capacity of 7,000 Mcf. In
fiscal 1996, there was no sendout of propane. Due to the
comparible cost of LNG and propane compared to pipeline and
underground storage, the Company uses these fuels primarily to
satisfy peak winter demand.
Under an agreement with Bay State Gas Company which expired
October 31, 1996, the Company was required to purchase 50,000 Mcf
of LNG during each summer period and approximately 110,000 Mcf
during each winter period with an option to purchase an
additional 37,000 Mcf during each winter period. This contract
was replaced by the contract with DOMAC discussed above.
Based on current information concerning pipeline and
supplemental gas supplies, the Company expects to meet the gas
requirements of its firm customers for the foreseeable future.
Competition
The Company has no direct competition with respect to the
retail distribution of natural gas by pipeline in its service
territory. Massachusetts law effectively protects gas companies
from such competition. Where a gas company exists in active
operation in Massachusetts, no other person may construct
underground gas mains in the public ways without the approval,
after notice and hearing, of the municipal authorities and, in
certain circumstances, the MDPU. If a municipality desires to
enter the gas business, it must take certain procedural steps,
including obtaining a favorable vote by a majority of the voters
at its town meeting. The municipality would then be required to
purchase the utility plant of any gas company operating in the
area at an agreed-upon price. If no agreement was reached, the
MDPU would make the final determination. Management of the
Company is not aware of any municipality in its service area
which currently desires to enter the gas distribution business.
<PAGE> 10
The Company faces a changing competitive market for natural
gas. 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. In addition, the MDPU required the Company to submit, for
approval, rates dealing with transportation of third-party gas
which will enable large volume customers to acquire natural gas
from sources other than Essex County Gas. Although the Company
has received approval for these rates, to date no customer has
selected this option.
While the current retail price of natural gas is equal to or
slightly higher than the retail price of oil for residential
space heating customers, natural gas is the fuel of choice for
most new residential construction. Natural gas has significant
environmental, operational and maintenance advantages over oil.
Additionally, most of the Company supply of natural gas is from
North American sources. Since the mid-1970's, the retail cost of
heating residential space by natural gas in the Company's service
territory has been approximately the same, or slightly higher
than, the comparable cost of heating by oil. There is no
assurance what, if any, the relative price differential between
natural gas and oil will be in the future. Natural gas has a
significant price advantage over electricity supplied by
investor-owned and municipal electric utilities in the Company's
service territory.
In the Company's service territory, the cost of heating with
natural gas for commercial and industrial customers is relatively
competitive with the cost of heating with oil. Approximately 50
of the Company's commercial and industrial customers have dual
heating facilities that enable them to switch freely between
natural gas and oil. As of August 31, 1996, the majority of the
Company's dual fuel customers were using oil.
Regulatory Matters
State
The Company is subject to the regulatory authority of the
MDPU with respect to the issuance of securities, accounting
practices, rates, service, contracts for the purchase of gas,
territories served and related matters.
Since 1987, the Company has filed five requests for rate
increases and has been granted a total of $8,030,791 in rate
relief by the MDPU, which amounts to 61.7% of the total
requested. The Company's most recent rate increase request was
filed in fiscal 1996 and approved in fiscal 1997. The Company's
fiscal 1996 rate increase request was for an annualized increase
of approximately $3,400,000 and the MDPU approved an annualized
rate increase of approximately $2,100,000. The rate increase
will be effective December 1, 1996.
The MDPU permits Massachusetts gas companies to utilize a
CGA that permits a gas company to pass on to firm customers (on a
current basis) increases or decreases in the cost of gas
supplies. Profits from interruptible sales and gas supplier
refunds are also passed on to firm customers through the CGA and
no portion of the interruptible profits are retained by the
Company unless certain volumes are sold. Supplemental fuel
<PAGE> 11
inventory and related administrative and carrying costs are also
recovered through the CGA. In addition, the MDPU allows recovery
of the following through the CGA: (1) working capital costs
associated with purchased gas costs; (2) clean-up costs
associated with waste materials from former gas manufacturing
sites; and (3) interest on the over or under collected gas costs.
The Company has the ability to release any of its unused capacity
on the Tennessee Gas Pipeline with net proceeds being returned to
firm customers through the CGA.
Changes in rates charged to customers which are not
incorporated in the CGA must be approved by the MDPU. Some
relief with respect to rate changes, such as adjustments in the
allowed rates of return on common equity, granting of inflation
adjustments, and the use of year-end rate base calculations in
rate proceedings, have been granted in the past by the MDPU to
remedy the financial burden resulting from the lag between the
historic period upon which rate decisions are based and the date
when the rates actually become effective. By law, the MDPU must
act on a rate proceeding within six months of filing and may
grant relief during the interim period.
FERC
The Company is not subject to direct regulation by FERC, but
is significantly affected by FERC orders that regulate interstate
pipelines serving the Company.
Pursuant to FERC Order No. 636, as supplemented by FERC
Order No. 636A ("FERC Order 636"), TGPC is primarily a
transportation pipeline and has discontinued nearly all of its
activities as a FERC certificated merchant of gas. TGPC has
previously received approval for the conversion of certain of its
sales service to the Company. See "Item 1: Business--Gas
Supply." The Company believes that the unbundling of these sales
service arrangements will not result in material adverse changes
in its business and that it will be able to recover, through
rates, costs incurred in connection with the implementation of
FERC Order 636.
Certain issues are still pending before FERC, such as the
manner in which TGPC may pass on a portion of its transition
costs associated with Order 636. The MDPU allows the Company to
recover any of the transition costs allowed by FERC through the
CGA.
Certain other aspects of FERC Order 636 which affect or may
affect the Company are pending before FERC or are subject to
review by the courts. These include, among other things, (i)
rules for "capacity brokering" or "capacity reassignment"; (ii)
rules for the manner in which capacity is allocated on various
pipelines for transportation purposes; and (iii) rules governing
changes in ratemaking methodologies which create uncertainty as
to future transportation costs. Until the regulatory treatment
of these issues is clarified, the Company cannot predict the
effect of such issues on its business.
<PAGE> 12
Environmental Matters
The Company is subject to local, state and federal
regulations through, among others, the Massachusetts Department
of Environmental Protection ("MDEP"), the United States
Environmental Protection Agency ("EPA"), the United States
Department of Transportation ("DOT"), and the MDPU.
The Company, or its predecessors, previously operated four
manufactured gas plants and one storage facility (collectively,
"MGPs") at sites in Massachusetts. Each of these facilities has
been out of operation for more than 25 years. It is possible
that, during the manufacturing process, some or all of the MGPs
may have discharged certain substances on the sites which may now
be deemed hazardous. The Company has not ascertained the extent
of any hazardous substance contamination on these sites from the
MGP operations. The Environmental Protection Agency ("EPA") and
Massachusetts Department of Environmental Protection ("MDEP") are
focusing on the potential environmental hazards of MGPs. To the
Company's knowledge, neither the EPA nor the MDEP have issued any
orders to clean up any of the Company's MGP sites. Investigations
which reported the presence of certain compounds were conducted
at two of the Company's MGP sites. As a result, a second, more
intensive investigation will be conducted in 1996 to determine
the level of contamination and to assess whether any remediation
is required. The Company has also been informed that certain
materials have been discovered on properties adjacent to a second
site currently owned by the Company. These adjacent properties
have been classified by the MDEP as a location to be
investigated. Based on preliminary investigation, the Company
currently believes that it may not be liable for cleanup costs
associated at the adjacent properties unless such liability is
based on down-gradient status; however, the Company may be liable
for cleanup costs associated with the parcel presently owned by
the Company. The Company does not currently possess sufficient
information to determine the probability or the cost of the
potential remediation, however, the MDPU provides for the
recovery through the CGA of all environmental response costs
associated with this and any other MGP sites over seven-year
amortization periods without a return on the unamortized balance.
A 1990 MDPU agreement also provides for no further investigation
of the prudency of any Massachusetts gas utility's past MGP
operations.
In 1990, the Company received notification from the MDEP
that the MDEP has reason to believe that the Company may be a
potentially responsible party, along with several others, with
respect to certain metal salvaging sites. See the Footnotes to
the Company's Financial Statements.
Pipeline Safety Matters
The DOT's Office of Pipeline Safety, from time to time,
issues safety regulations pertaining to the installation, testing
and repair of underground gas mains and related gas distribution
facilities by pipeline and gas distribution companies. While the
regulations may increase the Company's expenses, the Company does
not believe such regulations will have a material adverse effect
on its operating expenses or its construction plans for the
foreseeable future.
<PAGE> 13
Construction by a Massachusetts gas company of any
manufacturing or storage facility or pipeline having a pressure
in excess of 100 pounds per square inch and a length greater than
one mile requires approval by the Energy Facilities Siting Board,
a division of the MDPU created for the purpose of implementing
energy policies designed to provide energy supply with a minimum
impact on the environment and at the lowest possible cost.
Compliance with the procedures of this Board and other
environmental laws and regulations may result in construction
delays or increased costs with respect to future expansion. The
Company does not presently have any construction plans that would
require the approval of the Board.
Personnel
On August 31, 1996, the Company had 127 permanent employees,
including two part time, 74 of whom were represented by the
United Steelworkers of America, AFL-CIO-CLC, Local 12086. The
current three-year labor contract with the Steelworkers covering
all hourly workers extends through February 4, 1999.
Item 2: Properties
The Company's property consists primarily of its
distribution system and related facilities. As of August 31,
1996, the Company had approximately 750 miles of gas mains and
37,500 gas services as well as meters, measuring and regulator
station equipment, and rental equipment on customers' premises.
The Company also owns a propane plant with a storage capacity of
40,000 Mcf. In addition, the Company, through its wholly owned
subsidiary, LNG Storage, Inc., owns an LNG storage facility with
a storage capacity of 400,000 Mcf.
On August 31, 1996, the Company's gross utility plant amounted
to $98,603,784 at historical cost.
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 Company's gas supply contracts have also been assigned as
collateral security for 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 an LNG storage facility. The
LNG storage facility, while unencumbered with respect to the
Company's First Mortgage Bonds, is encumbered by a separate
mortgage note.
The Company leases its corporate headquarters building and
distribution facilities. The lease agreement is scheduled to
expire in October 2005. Annual rental payments amount to
$102,500. The Company also has a division office that is rented
under an agreement scheduled to expire on May 31, 1997.
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
<PAGE> 14
these claims and it is the Company's intention to contest these
claims. In view of the insurance coverages, 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.
PART II
Item 5: Market for Registrant's Common Equity and Related
Stockholder Matters
The Company's Common Stock is traded on the Nasdaq/NMS under
the symbol "ECGC." On October 1, 1996, the Common Stock was
held by 1,336 stockholders of record. 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.
Cash
Dividends
Market Price Per Share
High Low
Fiscal Year Ended August 31, 1995
First Quarter $25.50 $24.25 $0.38
Second Quarter 25.25 23.50 0.39
Third Quarter 25.50 22.50 0.39
Fourth Quarter 25.50 22.50 0.39
Fiscal Year Ended August 31, 1996
First Quarter 25.50 24.25 0.39
Second Quarter 26.75 25.00 0.40
Third Quarter 26.25 23.50 0.40
Fourth Quarter 25.50 23.50 0.40
Fiscal Year Ending August 31, 1997
First Quarter 27.00 24.50 0.40*
(through November 10, 1996)
*Paid on October 1, 1996 to shareholders of record on September
14, 1996.
The Company has paid regular dividends since 1914. Common
Stock dividend payments in fiscal 1996 totaled $1.59 per share,
as compared to $1.55 in fiscal 1995. Although the Company
expects to continue to pay dividends at or near the current rate
for the foreseeable future, the declaration of future dividends
will be at the direction of the Company's Board of Directors and
dependent on business conditions, earnings, contractual
restrictions and cash requirements of the Company.
<PAGE> 15
Item 6: Selected Financial Data
The following table sets forth certain selected consolidated
financial data of the Company and its subsidiaries and the ratio
of earnings to fixed charges for, or as of the end of, the five
fiscal years ended August 31, 1996. Due to the seasonal nature
of the Company's business, a substantial portion of the Company's
operating revenues are derived from operations during the second
and third quarters of each fiscal year. The selected
consolidated financial data are qualified by reference to the
consolidated financial statements and the notes thereto and other
information and data set forth elsewhere in this Annual Report or
incorporated by reference herein.
SELECTED CONSOLIDATED FINANCIAL DATA
Fiscal Years Ended August 31,
1996 1995 1994 1993 1992
(000s omitted, except for per share and ratio information)
Income Statement Data:
Operating revenues $49,929 $45,050 $48,536 $45,016 $42,913
Operating income 6,669 5,909 5,794 5,766 5,243
Income available for
common stock 3,836 3,180 3,302 2,880 2,331
Shares of common stock
outstanding, weighted
average 1,626 1,591 1,559 1,475 1,306
Earnings per common
share $ 2.36 $ 2.00 $ 2.12 $ 1.95 $ 1.79
Cash dividends declared
per common share $ 1.59 $ 1.55 $ 1.51 $ 1.47 $ 1.43
Ratio of earnings to
fixed charges (1) 2.83x 2.54x 2.83x 2.45x 2.11x
Balance Sheet Data:
Long-term debt (excluding
current portion) $19,765 $20,689 $21,713 $22,148 $21,031
Redeemable preferred
stock - 336 350 364 378
Common stock equity 33,023 30,709 28,870 26,985 20,982
------- ------- ------- ------- -------
Total capitalization $52,788 $51,734 $50,933 $49,497 $42,391
======= ======= ======= ======= =======
Capital lease (excluding
current portion) $ 605 $ 654 $ 700 $ 742 $ 781
======= ======= ====== ======= =======
Total assets $89,772 $86,582 $83,511 $76,535 $73,157
======= ======= ======= ======= =======
(1)In computing the ratio of earnings to fixed charges, "earnings"
are defined as income before income taxes and "fixed charges".
Fixed charges consist of interest, including the amount
capitalized, interest on the obligation under the supplemental
fuel inventory, amortization of debt expense and the estimated
interest portion (one third) of rental payments.
<PAGE> 16
Item 7: Management's Discussion and Analysis of Financial
Condition and Results of Operations
Results of Operations
Fiscal Years Ended August 31, 1996 and 1995
Revenues
The Company's sales are responsive to colder weather as the
majority of its customers use natural gas for space heating
purposes. The Company measures weather through the use of
effective degree days. An effective degree day is calculated by
subtracting the average temperature for the day, adjusted for
wind and cloud cover, from 65 degrees Fahrenheit.
Using a twenty-year average, the Company's service territory
incurs 6,813 effective degree days in one year. Fiscal 1996 had
6,947 effective degree days compared to 6,258 in fiscal 1995. As
a result, the volume of sales to the Company's two major firm
customer classes, residential and commercial and industrial,
increased by 12.7% from 5,036,056 Mcf in 1995 to 5,678,115 Mcf in
the current year. The colder weather, coupled with a 0.7%
increase in price, resulted in revenues of $49,929,389 in 1996
compared to $45,049,573 in the prior year. Revenues consist of
three components: firm gas revenues (whereby the Company must
supply the customer on demand), interruptible revenues (whereby
the Company may curtail gas supplies to large industrial
customers during the peak winter season), and other revenues
(primarily appliance rentals and service work). Firm revenues in
fiscal 1996 were 10.9% higher than in fiscal 1995. The increase
was attributable to the weather and price factors discussed
previously and an increase of nearly 3.0 % in the Company's
customer base. The average unit price of gas sold to all
customers, including interruptible customers, increased 0.7% in
1996 to $7.45 from $7.40 in fiscal 1995. For firm customers, the
average unit price decreased to $8.22 from $8.36 in the prior
year. The Company's interruptible revenues increased 14.6% as
the unit price increased by $0.40 to $2.51 over the same period.
This price increase was offset by a volume decrease in
interruptible sales by 31,749 Mcf to 883,250 Mcf. If
interruptible volumes exceed a threshold based on sales during
the last four years, the Company may retain 10% of the gross
profit on interruptible sales and refund the remaining 90% to the
Company's firm customers. In fiscal 1996, the required volumes
of interruptible sales were obtained, and the Company retained
approximately $5,000, returning the balance of all gross profit
on interruptible sales to its firm customers. The decrease in
interruptible volumes did not significantly impact the Company's
earnings. Other revenues increased slightly to $1,023,417 in
fiscal 1996 from $1,015,979 in fiscal 1995.
During fiscal 1996, the Company added over 1,200 new
customers. The Company's ability to attract customers has been
assisted by the improving economy and resultant new construction.
Although there is a slight unfavorable price comparison with oil,
which is the Company's primary competition in the area of space
heating, the environmental advantages and convenience of natural
gas allow the Company to compete favorably.
<PAGE> 17
Operating Expenses
The Company's major operating expense is its cost of gas
which increased 10.9% to $24,976,802 in fiscal 1996 from
$22,525,442 in fiscal 1995. This increase was primarily due to
an increase of 12.7% in firm volumes of gas sold. The unit price
of gas increased 0.7% from 1995 to 1996. These gas costs are
recovered from the Company's firm customers through a Cost of Gas
Adjustment ("CGA") which is adjusted semi-annually to reflect any
changes in gas costs.
Operations and maintenance expenses increased 8.1% to
$11,976,067 in fiscal 1996 from $11,078,029 in fiscal 1995. This
increase was mainly attributable to: an increase of $285,000 in
employee benefits other than pensions, $267,000 in pension
expense and an increase of approximately $190,000 in
uncollectible accounts. The increase in employee benefits, other
than pensions, is due to approximately $143,000 in additional
medical expense due to higher utilization of the Company's self-
insured medical plan. In addition, the Company increased its
Employee Stock Ownership Plan contribution by $82,000 and a
$25,000 increase in the Company's Thrift Savings Plan as more
employees participated in the Company program and received
matching funds. The increase in the pension expense is primarily
due to an additional contribution to the Company's pension trust
and the increase in uncollectible accounts is primarily due to
the higher revenues recorded during the fiscal year. The Company
also incurred a one-time additional regulatory expense of
approximately $225,000 for conservation and load management
programs and performance based ratemaking. These increases were
offset by $80,000 of reduced rate case expense as the 1993 rate
case expenditures were fully amortized in December 1995.
Utility Plant depreciation expense increased 7.9 % to
$2,697,241 in fiscal 1996 from $2,500,585 in fiscal 1995,
reflecting the ongoing investment in upgrading and expanding the
Company's distribution system.
Taxes, other than federal income, increased 11.1% to
$1,816,929 in fiscal 1996 from $1,634,216 in fiscal 1995. This
increase was primarily related to an increase in real estate
taxes due to assessments on the Company's additions to its
utility plant and state income taxes resulting from higher
pre-tax earnings.
Federal income taxes increased 28.0% to $1,793,360 in fiscal
1996 from $1,401,858 in fiscal 1995, also reflecting the increase
in the Company's pre-tax earnings. The Company's combined
effective tax rate for both federal and state income taxes was
36.1%.
Interest on long-term debt decreased 4.0% to $1,967,073 in
fiscal 1996 from $2,048,959 in fiscal 1995. This decrease was
related to the sinking fund payments of long-term debt. Other
interest expense increased 19.1% to $873,198 in fiscal 1996 from
$732,941 in fiscal 1995. This increase was primarily
attributable to higher levels of short-term debt outstanding and
higher interest rates in fiscal 1996 as compared to fiscal 1995.
Income available for common stock increased 20.6% to
$3,835,500, or $2.36 per share, in fiscal 1996 from $3,179,778,
or $2.00 per share, in fiscal 1995. Dividends per share declared
and paid for fiscal 1996 and 1995 were $1.59 and $1.55,
respectively.
<PAGE> 18
Fiscal Years Ended August 31, 1995 and 1994
Revenues
The Company experienced only 6,258 effective degree days in
fiscal 1995 compared to 7,012 in fiscal 1994. As a result, the
volume of unit sales in the Company's two major customer classes,
residential and commercial and industrial, decreased by 8.4% from
5,497,235 Mcf in 1994 to 5,036,056 Mcf in the current year. The
warmer than normal weather resulted in decreased firm revenues
from $46,536,115 to $42,100,843. Firm revenues decreased nearly
9.5% over fiscal 1994, primarily due to the weather as the
Company's customer base increased by only 2.3%. The average unit
price of all gas sold to customers, including interruptible
customers, decreased 8.2% to $7.40 in fiscal 1995 from $8.06 in
fiscal 1994. For firm customers only, the average unit price
decreased to $8.36 from $8.47 in the prior year. The Company's
interruptible revenues increased 117.6% as interruptible volumes
increased 525,651 Mcf. The increase in interruptible volumes was
primarily due to the availability of natural gas on a low cost,
spot market basis. The increase in volumes did not impact the
Company's earnings since the Company did not meet the
interruptible threshold requirement discussed above. Other
revenues decreased slightly to $1,015,929 from $1,111,654 in
1994.
Operating Expenses
The Company's major operating expense is its cost of gas,
which decreased 9.9% to $22,525,442 in fiscal 1995 from
$25,000,794 in fiscal 1994. This decrease was due to less
volumes of gas sold.
Operations and maintenance expenses decreased 9.2% to
$11,078,029 in fiscal 1995 from $12,206,720 in fiscal 1994. This
decrease was mainly attributable to: decreases of approximately
$600,000 in outside services, $220,000 in medical expenses, and a
decrease of approximately $340,000 in uncollectible accounts.
The reduction in outside service expense was primarily related to
one-time items such as actuarial services relating to employee
benefits, including medical costs for current and future
retirees; legal and other consulting services relating primarily
to regulatory affairs such as interruptible and firm
transportation rates; general comments on utility mergers and
acquisitions; and other regulatory items incurred in fiscal 1994.
The decrease in employee benefits was primarily related to
reduced medical costs for current and future retirees as medical
utilization decreased.
Utility Plant depreciation increased 6.8% to $2,500,585 in
fiscal 1995 from $2,341,381 in fiscal 1994, reflecting the
investment in the Company's utility plant.
Taxes, other than federal income, decreased 2.4% to
$1,634,216 in fiscal 1995 from $1,675,782 in fiscal 1994. This
decrease was due to a decrease in state income taxes resulting
from the lower pre-tax earnings.
Federal income taxes decreased 7.6% to $1,401,858 in fiscal
1995 from $1,517,130 in fiscal 1994, also reflecting the decrease
in the Company's pre-tax earnings. The Company's combined
effective tax rate for both federal and state income tax purposes
was 34.6%.
<PAGE> 19
Interest on long-term debt decreased 3.5% to $2,048,959 in
fiscal 1995 from $2,124,058 in fiscal 1994. This decrease was
related to the sinking fund payments on long-term debt. Other
interest expense increased 108.8% to $732,941 in fiscal 1995 from
$351,088 in fiscal 1994. This increase was primarily attributable
to higher levels of short-term debt outstanding and higher
interest rates in fiscal 1995 as compared to fiscal 1994.
Income available for common stock decreased 3.7% to
$3,179,778 or $2.00 per share in 1995, from $3,301,711 or $2.12
per share in 1994. Dividends per share declared and paid for
fiscal 1995 and 1994 were $1.55 and $1.51, respectively.
Liquidity and Capital Resources
Net cash provided by operating activities decreased
$4,480,556 to $6,226,758 for the fiscal year ended August 31,
1996. The decrease was primarily due to a return in supplier
refund obligations of $2,179,095 compared to an increase during
the fiscal year ended August 31, 1995 of $792,927. Additionally,
the Company decreased its recoverable gas cost position by
$2,960,944 whereas in the prior year the Company increased its
position by $1,719,994. These uses of cash were offset by an
increase in deferred taxes of $1,950,962 and a decrease in
inventories of $2,512,221.
Occasionally the Company receives refunds from its pipeline
supplier as a result of regulatory action by the Federal Energy
Regulatory Commission ("FERC".) The supplier refunds are
returned by the Company to customers over a twelve month period.
The Company periodically borrows from banks on an unsecured,
short-term basis. At August 31, 1996, the Company had
$11,940,000 of outstanding notes payable under available lines of
credit totaling $16,650,000 with six different banks. In
addition, for the sole purpose of financing the Supplemental Fuel
Inventory, the Company has a $10,000,000 line of credit. Due to
the seasonal nature of the Company's business, the Company
customarily draws upon its credit lines since both sales and
construction activity are affected by seasonal weather
conditions. Short-term financing is typically used to satisfy
seasonal cash requirements while, on an annual basis, operating
requirements are satisfied by cash flows from operations.
Funding for the Company's construction program has
traditionally been generated by operations and, on a temporary
basis, through short-term bank borrowings. These short-term
borrowings are periodically repaid with proceeds from the
issuance of long-term debt and equity. Management anticipates
that these and other sources will remain available and continue
to adequately serve the Company's needs.
During fiscal 1996, the Company's construction expenditures
were approximately $8,000,000. This compares to approximately
$7,000,000 in fiscal 1995. The Company has sought approval from
the Massachusetts Department of Public Utilities ("MDPU") for a
private placement of First Mortgage Bonds in the amount of
approximately $10,000,000 during fiscal 1997. The Company's
higher construction expenditures in fiscal 1996 were primarily
attributable to additional construction requirements to bring on
new customers, continued upgrading of the Company's existing
<PAGE> 20
infrastructure and expenditures related to the Company's automated
meter reading program. These capital expenditures were funded
primarily from short-term debt and operations. Capital expenditures
for fiscal 1997 are expected to be approximately $6,400,000.
Regulatory and Accounting Issues
The Company's revenues are based on rates regulated by the
MDPU. These rates are designed to allow the Company to recover
its operating costs and provide an opportunity to earn a
reasonable rate of return on investor supplied funds. Once
approved, the Company's rates are adjusted by a CGA which,
subject to approval by the MDPU, permits the Company to change
rates to recover its gas costs and certain other costs on a
dollar-for-dollar basis. The CGA is also used as the mechanism
to reduce charges to firm customers by the margin earned on sales
to interruptible customers. In September 1996 the Company
received approval for a rate increase of $2,100,000 which is
scheduled to be effective December 1, 1996. As part of a
settlement approved by the MDPU, the Company will increase its
depreciation rate to an average rate of 3.7% effective December
1, 1996 based on a depreciation study. The effect of the change
in the depreciation rate is to increase, on an annual basis,
depreciation expense in 1997 by approximately $600,000.
The Company, or its predecessors, previously operated four
manufactured gas plants and one storage facility (collectively,
"MGPs") at sites in Massachusetts. Each of these facilities has
been out of operation for more than 25 years. It is possible
that, during the manufacturing process, some or all of the MGPs
may have discharged certain substances on the sites which may now
be deemed hazardous. The Company has not ascertained the extent
of any hazardous substance contamination on these sites from the
MGP operations. The Environmental Protection Agency ("EPA") and
Massachusetts Department of Environmental Protection ("MDEP") are
focusing on the potential environmental hazards of MGPs. To the
Company's knowledge, neither the EPA nor the MDEP have issued any
orders to clean up any of the Company's MGP sites. In 1995 an
investigation which reported the presence of certain compounds
was conducted at one of the Company's MGP sites. As a result, a
second, more intensive investigation will be conducted in fiscal
1997 to determine the level of contamination and to assess
whether any remediation is required. The Company has also been
informed that certain materials have been discovered on
properties adjacent to a second site currently owned by the
Company. These adjacent properties have been classified by the
MDEP as a location to be investigated. Based on preliminary
investigation, the Company currently believes that it may not be
liable for cleanup costs associated at the adjacent properties
unless such liability is based on down-gradient status; however,
the Company may be liable for cleanup costs associated with the
parcel presently owned by the Company. The Company does not
currently possess sufficient information to determine the
probability on the cost of the potential remediation, however,
the MDPU provides for the recovery through the CGA of all
environmental response costs associated with this and any other
MGP sites over seven-year amortization periods without a return
on the unamortized balance. The settlement agreement also
provides for no further investigation of the prudency of any
Massachusetts gas utility's past operations.
<PAGE> 21
The natural gas industry is in the process of transitioning
from a highly regulated environment to a competitive environment.
Pursuant to FERC Order 636, as supplemented by Order 636A,
pipeline companies have unbundled pipeline sales, storage and
transportation services. FERC Order 636 was implemented by the
Company's pipeline supplier, Tennessee Gas Pipeline Company
("TGPC"), on September 1, 1993. As a result, TGPC is
providing transportation service only. The Company now contracts
for its own gas supply through a consortium of gas companies and
pays monthly demand charges to TGPC for the availability of
pipeline capacity and transportation charges for gas transport.
The Company pays charges for the cost of gas delivered and for
gas inventory charges to reserve volumes of gas inventory in
connection with substantially all of its long-term firm gas
purchase agreements.
FERC Order 636 has also required pipelines to adopt a new
rate design that has shifted the recovery of the pipeline's fixed
costs to a monthly demand charge for firm transportation service
and away from recovery of costs of service on a volumetric basis.
FERC Order 636 also allows the pipeline companies to recover
transition costs incurred as they restructure their services.
TGPC began direct billing these costs to the Company on
September 1, 1993 as a component of the demand charges. The
Company's current estimate of its obligation for transition costs
is approximately $900,000 and is based upon FERC approved
filings. This estimated liability has been included in the
Company's financial statements at August 31, 1996, together with
the related regulatory asset. The MDPU has approved the recovery
of Gas Supply Realignment costs from all firm customers.
The MDPU has received comments and proposals from interested
persons on how incentive regulation could improve upon the
existing framework of utility regulation. Although to date the
MDPU has not issued directives, it is expected that in the near
future, incentive ratemaking, in some form, will be instituted in
the Commonwealth of Massachusetts.
<PAGE> 22
Item 8: Financial Statements and Supplementary Data
CONSOLIDATED STATEMENTS OF INCOME
Fiscal Years Ended August 31,
1996 1995 1994
OPERATING REVENUES $49,929,389 $45,049,573 $48,536,005
Less: Cost of gas 24,976,802 22,525,442 25,000,794
----------- ----------- -----------
Operating margin 24,952,587 22,524,131 23,535,211
----------- ----------- -----------
OPERATING EXPENSES:
Operations and maintenance expenses 11,976,067 11,078,029 12,206,720
Depreciation 2,697,241 2,500,585 2,341,381
Taxes, other than federal income 1,816,929 1,634,216 1,675,782
Federal income taxes 1,793,360 1,401,858 1,517,130
----------- ----------- -----------
TOTAL OPERATING EXPENSES 18,283,597 16,614,688 17,741,013
----------- ----------- -----------
OPERATING INCOME 6,668,990 5,909,443 5,794,198
OTHER INCOME (EXPENSE), NET 1,997 6,202 (7,828)
----------- ----------- -----------
INCOME BEFORE INTEREST CHARGES 6,670,987 5,915,645 5,786,370
----------- ----------- -----------
INTEREST CHARGES:
Interest on long-term debt 1,967,073 2,048,959 2,124,058
Amortization of deferred debt expense 27,499 27,081 26,697
Other interest expense 873,198 732,941 351,088
Allowance for funds used
during construction (46,143) (92,428) (37,268)
----------- ----------- -----------
TOTAL INTEREST CHARGES 2,821,627 2,716,553 2,464,575
----------- ----------- -----------
NET INCOME 3,849,360 3,199,092 3,321,795
ANNUAL REDEEMABLE
PREFERRED DIVIDEND REQUIREMENTS (13,860) (19,314) (20,084)
------------ ---------- -----------
INCOME AVAILABLE FOR COMMON STOCK $ 3,835,500 $ 3,179,778 $ 3,301,711
============ =========== ===========
SHARES OF COMMON STOCK OUTSTANDING
(WEIGHTED AVERAGE) 1,626,315 1,591,372 1,558,574
------------ ----------- -----------
EARNINGS PER COMMON SHARE $ 2.36 $ 2.00 $ 2.12
------------ ----------- -----------
CASH DIVIDENDS DECLARED PER
COMMON SHARE $ 1.59 $ 1.55 $ 1.51
------------ ----------- -----------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Fiscal Years Ended August 31,
1996 1995 1994
BALANCE AT BEGINNING OF YEAR $12,576,695 $11,857,299 $10,903,703
Net income 3,849,360 3,199,092 3,321,795
----------- ----------- -----------
TOTAL 16,426,055 15,056,391 14,225,498
----------- ----------- -----------
Cash dividends declared:
Redeemable preferred stock 13,860 19,314 20,084
Common stock 2,578,428 2,460,382 2,348,115
----------- ----------- -----------
TOTAL 2,592,288 2,479,696 2,368,199
----------- ----------- -----------
BALANCE AT END OF YEAR $13,833,767 $12,576,695 $11,857,299
=========== =========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 23
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, August 31,
1996 1995
UTILITY PLANT, AT COST $ 98,603,784 $ 91,462,732
Less: Accumulated depreciation 22,290,175 20,304,386
------------ ------------
NET UTILITY PLANT 76,313,609 71,158,346
------------ ------------
Other property and investments 633,515 570,620
------------ ------------
CAPITALIZED LEASE (NET OF ACCUMULATED
AMORTIZATION OF $469,406 1N 1996 AND
$423,806 IN 1995) 654,391 699,991
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 303,526 136,925
Accounts receivable:
Customers (net of allowance for
uncollectible accounts of $653,000
in 1996 and $595,000 in 1995) 1,654,808 1,418,510
Other 229,189 280,889
Income tax refunds receivable 874,000 200,000
Supplemental fuel inventory 4,047,421 6,477,155
Materials and supplies (at average cost) 512,330 594,817
Prepaid deferred income taxes 328,066 1,397,422
Prepayments and other 622,502 350,660
Recoverable gas costs 470,766 -
----------- -----------
TOTAL CURRENT ASSETS 9,042,608 10,856,378
----------- -----------
DEFERRED CHARGES:
Regulatory assets 2,464,691 2,267,954
Unamortized debt expense and other 663,119 1,028,319
----------- -----------
TOTAL DEFERRED CHARGES 3,127,810 3,296,273
----------- -----------
$ 89,771,933 $ 86,581,608
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 24
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
August 31, August 31,
1996 1995
COMMON STOCK EQUITY $33,022,947 $30,709,276
----------- -----------
REDEEMABLE PREFERRED STOCK - 336,000
----------- -----------
LONG-TERM DEBT, LESS CURRENT PORTION 19,765,535 20,689,366
----------- -----------
TOTAL CAPITALIZATION 52,788,482 51,734,642
----------- -----------
NONCURRENT OBLIGATIONS UNDER CAPITAL LEASE 604,823 654,390
----------- -----------
CURRENT LIABILITIES:
Current portion of long-term debt 923,831 978,758
Current obligation under capital lease 49,568 45,599
Obligations under supplemental
fuel inventory 3,358,010 5,131,153
Notes payable, banks 11,940,000 4,890,000
Accounts payable 4,063,829 2,986,307
Accrued interest 937,988 825,322
Refundable gas costs - 2,490,178
Accrued transition costs 890,432 858,715
Supplier refund due customers 275,644 2,454,739
Other 188,513 850,404
----------- -----------
TOTAL CURRENT LIABILITIES 22,627,815 21,511,175
COMMITMENTS AND CONTINGENCIES ----------- -----------
DEFERRED CREDITS:
Accumulated deferred income taxes 9,951,085 9,092,349
Unamortized investment tax credit 1,210,896 1,280,680
Deferred directors' fees 991,503 879,009
Other 1,597,329 1,429,363
----------- -----------
TOTAL DEFERRED CREDITS 13,750,813 12,681,401
----------- -----------
$89,771,933 $86,581,608
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 25
CONSOLIDATED STATEMENTS OF CASH FLOWS
Fiscal Years Ended August 31,
1996 1995 1994
OPERATING ACTIVITIES:
NET INCOME $ 3,849,360 $ 3,199,092 $ 3,321,795
Adjustments to reconcile net ----------- ----------- -----------
income to net cash:
Depreciation, including
amounts related to non-utility
operations 3,130,712 2,920,476 2,754,465
Provisions for uncollectible
accounts 57,792 (208,797) 761,385
Deferred income taxes 1,950,962 40,876 1,006,618
Amortization 7,943 8,390 7,305
Noncash compensation associated
with ESOP 150,000 225,000 150,000
Cash (used in) provided by
working capital:
(Increase) decrease in accounts
receivable (242,390) 546,304 (912,662)
Decrease (increase) in inventories
including fuel 2,512,221 294,854 (462,827)
(Increase) decrease in prepayments
and other (271,842) (33,922) 185,674
Increase in accounts payable 1,077,522 55,729 104,406
(Decrease) increase in supplier
refund obligations (2,179,095) 792,927 1,661,812
(Increase) decrease in taxes
receivable (802,472) 488,000 (374,323)
(Decrease) increase in recoverable
(refundable) gas costs (2,960,944) 1,719,994 (154,584)
Other, net (53,011) 658,391 (837,888)
----------- ----------- -----------
Total adjustments 2,377,398 7,508,222 3,889,381
NET CASH PROVIDED BY ----------- ----------- -----------
OPERATING ACTIVITIES 6,226,758 10,707,314 7,211,176
INVESTING ACTIVITIES: ----------- ----------- -----------
Utility capital expenditures (8,027,623) (6,967,340) (6,131,471)
Payments for retirements of property,
plant and equipment, net (258,352) (66,497) (183,999)
NET CASH USED IN INVESTING ----------- ----------- -----------
ACTIVITIES (8,285,975) (7,033,837) (6,315,470)
FINANCING ACTIVITIES: ----------- ----------- -----------
Dividends paid (2,592,288) (2,479,696) (2,368,199)
Issuance of common stock 856,007 814,126 730,874
Retirements of preferred stock (336,000) (14,000) (14,000)
Principal retired on
long-term debt (828,758) (855,304) (193,340)
(Decrease) increase in supplemental
fuel inventory (1,773,143) (1,297,617) 862,068
Increase in notes payable,
banks 7,050,000 390,000 300,000
Payment of ESOP debt (150,000) (225,000) (150,000)
NET CASH PROVIDED BY (USED ----------- ----------- ----------
IN) FINANCING ACTIVITIES 2,225,818 (3,667,491) (832,597)
Net increase in cash and cash ----------- ----------- ----------
equivalents 166,601 5,986 63,109
Cash and cash equivalents at
beginning of year 136,925 130,939 67,830
CASH AND CASH EQUIVALENTS AT ----------- ----------- -----------
END OF YEAR $ 303,526 $ 136,925 $ 130,939
============ ============ ============
SUPPLEMENTAL DISCLOSURES:
Cash paid during the year for:
Interest (net of
amount capitalized) $ 2,708,961 $ 2,517,015 $ 2,449,138
============ ============ ===========
Income taxes $ 1,407,476 $ 1,743,197 $ 1,196,360
============ ============ ===========
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 26
CONSOLIDATED STATEMENTS OF CAPITALIZATION
August 31, August 31,
1996 1995
COMMON STOCK EQUITY:
Common stock, no par value, 5,000,000
authorized shares, Issued and $19,234,915
outstanding 1,642,490 shares
at August 31, 1996.
Common stock, $2.50 par value, 5,000,000
authorized shares, Issued and outstanding,
1,607,061 at August 31, 1995. $ 4,017,653
Additional paid-in capital 14,311,026
Unrealized gain on investments available
for sale, net 29,265 28,902
Retained earnings 13,833,767 12,576,695
----------- -----------
33,097,947 30,934,276
Less: Shares held by ESOP purchased with debt 75,000 225,000
----------- -----------
TOTAL COMMON STOCK EQUITY 33,022,947 30,709,276
----------- -----------
REDEEMABLE PREFERRED STOCK:
5.50% series, $100 par value, 7,000
authorized shares
Outstanding, 3,360 at August 31, 1995 - 336,000
----------- -----------
LONG-TERM DEBT:
FIRST MORTGAGE BONDS:
10 1/4%, due serially from 1994 to 2003 4,800,000 5,400,000
10.10%, due serially from 2010 to 2020 8,000,000 8,000,000
----------- -----------
12,800,000 13,400,000
MORTGAGE NOTE: ----------- -----------
8 1/2%, due serially from 1976 to 1997 609,366 838,124
DEBENTURES: ----------- -----------
8 5/8%, due 2006 2,245,000 2,245,000
8.15%, due 2017 4,960,000 4,960,000
----------- -----------
7,205,000 7,205,000
ESOP LOAN GUARANTEE: ----------- -----------
7.0%, due serially from 1987 to 1996 75,000 225,000
----------- -----------
TOTAL DEBT 20,689,366 21,668,124
Less: Current portion maturing and payable 923,831 978,758
----------- -----------
TOTAL LONG-TERM DEBT 19,765,535 20,689,366
----------- -----------
TOTAL CAPITALIZATION $52,788,482 $51,734,642
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE> 27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
General
Essex County Gas Company is a public utility engaged in the
distribution and sale of natural gas for residential, commercial
and industrial uses. Its service area is located in northeastern
Massachusetts.
Regulation
The Company is subject to regulation by the Massachusetts
Department of Public Utilities ("MDPU") with respect to its rates
and accounting practices. The accounting policies conform to
generally accepted accounting principles as applied to regulated
public utilities and reflects the effects of the ratemaking
process in accordance with Statement of Financial Accounting,
Standard No. 71, "Accounting for Certain Types of Regulation
("SFAS 71"). Under SFAS 71, a utility is allowed to defer 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 MDPU has permitted or is expected to permit the recovery of
specific costs over time. As of August 31, 1996, principal
regulatory assets include (1) approximately $890,000 for
transition costs associated with Federal Energy Regulatory Commission
("FERC") Order 636, (2) $435,000 related to a settlement payment
for a supplemental retirement plan, and (3) $425,000 related to
deferred income taxes. Included in deferred credits is a
regulatory liability of $751,000 related to deferred income taxes.
Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and
Long-Lived Assets to be Disposed of" ("SFAS 121") was issued in
March 1995 and is effective for the Company on September 1, 1996.
SFAS 121 establishes accounting standards for the impairment of
long lived assets. It requires that regulatory assets which are
no longer probable of being recovered be written off. Based upon
the current regulatory environment in the Company's service
territory, it is not expected that the adoption of SFAS 121 will
have a material impact on the Company's financial position or
results of operations.
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.
Operating Revenues
Revenues from the sale of gas are based on rates authorized
by the MDPU and are recorded in the period the bill is rendered.
Meters are read and bills are rendered on a cycle basis
throughout the month. As a result, the
<PAGE> 28
volumes of gas delivered to customers in any period may be more
or less than the usage for which customers are billed.
The Company's rates include a Cost of Gas Adjustment Factor
which permits the Company to recover the difference between gas
costs incurred by the Company and gas costs billed to customers.
The amount of the difference is deferred for accounting purposes
and expensed when reflected in billings in subsequent periods.
Utility Plant
Utility plant and other property are stated at original
cost. The cost of additions to utility plant includes
contracted work, direct labor and material, allocable overhead,
allowance for funds used during construction and indirect charges
for engineering and supervision. Expenditures for ordinary
maintenance and repairs are charged to expense as incurred.
Depreciation for financial reporting purposes is calculated
on a straight-line basis. The annual provision for depreciation,
based on the average depreciable property, was equivalent to a
composite depreciation rate of 3.03% for fiscal 1996, 1995, and
1994. The cost of Utility Plant retired or otherwise disposed of,
in the ordinary course of business, together with costs of
removal less salvage, is charged to accumulated depreciation.
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.
Reclassifications
Certain prior year financial statement amounts have been
reclassified for consistent presentation with the current year.
B. Supplemental Fuel Inventory
The Company, with MDPU 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. Financing resulted in an effective
interest cost to the Company of 6.5% for 1996 and 5.9% in 1995
based on average borrowing.
<PAGE> 29
C. Common Stock
Common stock activity for the three-year period ended August
31, 1996, is as follows:
Additional
Number of Common Paid-in
Shares Stock Capital
BALANCE, AUGUST 31, 1993 1,544,045 $ 3,860,113 $12,820,750
Dividend reinvestment plan 15,452 38,631 359,647
Amortization of capital
stock expense - - 51,408
Employee stock plans 10,397 25,991 247,775
Sale of common stock 2,168 5,420 53,410
--------- ----------- -----------
BALANCE, AUGUST 31, 1994 1,572,062 3,930,155 13,532,990
Dividend reinvestment
plan 19,276 48,190 389,246
Amortization of capital
stock expense - - 51,408
Employee stock plans 13,054 32,635 280,208
Sale of common stock 2,669 6,673 57,174
--------- ----------- -----------
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 $ -
========= =========== ===========
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.
<PAGE> 30
D. Restriction on Retained Earnings
Under the terms of the indenture securing the First Mortgage
Bonds, retained earnings in the amount of $6,447,424 as of August
31, 1996, 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, 1996, the Company had
$11,940,000 of outstanding notes payable with a weighted average
interest rate of 5.9% under available lines of credit totaling
$16,650,000. The annual commitment fees related to these lines
of credit are between 1/4% and 3/8% 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% 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
$923,831 in 1997, $960,535 in 1998, $600,000 in 1999, $600,000 in
2000, $600,000 in 2001 and $17,005,000 thereafter.
F. Disclosure About Fair Values of Financial Instruments
The estimated fair values of the Company's financial
instruments are as follows:
Carrying Amount Fair Value
Cash $ 303,526 $ 303,526
Long-term debt $19,765,535 $22,901,111
The carrying value of cash approximates fair value because
of the short maturity of those instruments.
The estimated fair value of the Company's long-term debt is
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 would
be settled.
<PAGE> 31
G. Income Taxes
The components of the provision for income taxes are as follows:
1996 1995 1994
FEDERAL
Current $ 294,144 $1,469,957 $ 796,930
Deferred 1,569,000 2,000 791,000
Amortization of
investment tax credit (69,784) (70,099) (70,800)
---------- ---------- ---------
TOTAL FEDERAL 1,793,360 1,401,858 1,517,130
---------- ---------- ---------
STATE
Current 58,643 292,615 173,459
Deferred 321,000 445 162,000
---------- ---------- ---------
TOTAL STATE 379,643 293,060 335,459
---------- ---------- ---------
TOTAL INCOME TAXES $ 2,173,003 $1,694,918 $1,852,589
=========== ========== ==========
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:
1996 1995 1994
FEDERAL STATUTORY RATE 34.0% 34.0% 34.0%
===== ===== =====
Federal income tax
expense at statutory rates $2,048,628 $1,663,963 $1,759,260
Increase (decrease) in taxes resulting
from:
Amortization of investment
tax credit (69,784) (70,099) (70,800)
State taxes, net of
federal benefit 250,564 199,980 221,403
Other (56,405) (98,926) (57,274)
---------- ---------- ----------
TOTAL INCOME TAX EXPENSE $2,173,003 $1,694,918 $1,852,589
========== ========== ==========
EFFECTIVE INCOME TAX RATE 36.1% 34.6% 35.8%
===== ===== =====
<PAGE> 32
Effective September 1, 1993, the Company adopted the
provisions of Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("SFAS 109"). The adoption of
SFAS 109 had no earnings impact on the Company. SFAS 109
requires the recognition of deferred tax liabilities and assets
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 $425,000 was established for the deferred
taxes not previously recovered as a result of the flow through to
customers for temporary differences in prior years. This balance
is being recovered over the estimated lives of the property. A
regulatory liability of $751,000 was established for the tax
benefit of unamortized investment tax credits, which SFAS 109
requires to be treated as a temporary difference. This benefit
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 deferred tax liabilities at August 31,
1996 and 1995 are as follows:
1996 1995
LIABLILTIES
Utility plant-primarily depreciation $10,779,608 $ 9,957,069
Other 602,814 332,912
----------- -----------
TOTAL LIABILITIES 11,382,422 10,289,981
ASSETS ----------- -----------
Investment tax credits 751,340 794,403
Other 1,008,063 1,800,651
----------- -----------
TOTAL ASSETS 1,759,403 2,595,054
----------- -----------
ACCUMULATED DEFERRED INCOME TAXES, NET $ 9,623,019 $ 7,694,927
=========== ===========
The net year-end deferred income tax liabilities above are net of
current deferred tax assets of $328,066 and $1,397,422
respectively, which are included in prepaid income taxes in the
accompanying Consolidated Balance Sheets.
H. Leases
The Company is obligated under various lease agreements for
certain facilities and equipment used in operations. Total
expenditures under operating leases were $315,152 in 1996,
$289,721 in 1995, and $309,992 in 1994. A summary of property
classified as capital leases as of August 31, 1996 and 1995 is as
follows:
1996 1995
Buildings $1,123,797 $1,123,797
Less: Accumulated depreciation 469,406 423,806
---------- ----------
$ 654,391 $ 699,991
========== ==========
In accordance with the rate treatment allowed by the MDPU, the
depreciation expense of $45,600, $41,948, and $38,540 , along
with interest of $56,850, $60,502, and $63,910 related to the
capital lease, is included in other operating expenses for the
years ended August 31, 1996, 1995 and 1994, respectively.
<PAGE> 33
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:
Capital Leases Operating Leases
1997 $102,500 $237,989
1998 102,500 198,218
1999 102,500 47,373
2000 102,500 23,476
2001 102,500 -
Thereafter 427,084 -
------- --------
Total minimum lease payments 939,584 $507,056
========
Less: Amount representing
interest 285,193
--------
$654,391
========
I. Employee Benefits
Pension Plans
The Company has two pension plans covering substantially all
employees. The actuarial method for determining annual pension cost
is the Projected Unit Credit method.
Net pension cost for 1996, 1995 and 1994 consist of the following
components:
1996 1995 1994
Service cost -- benefits
earned during the year $ 268,542 $ 231,741 $ 212,190
Interest cost on projected
benefit obligations 722,354 668,107 617,749
Actual return on plan assets (1,125,838) (887,022) (74,969)
Net amortization and deferral 609,010 412,504 (444,131)
---------- --------- ---------
NET PENSION COST $ 474,068 $ 425,330 $ 310,839
========== ========= =========
The expected long-term rate of return on assets was 8.5% in 1996,
1995 and 1994. The discount rate used in determining the
actuarial present value of the projected obligation was 8.0% in
1996, 1995 and 1994. The expected rate of pay increase was 6.0%
in 1996, 1995 and 1994.
<PAGE> 34
The following table sets forth the funding status of the pension
plans and amounts recognized in the Company's balance sheet based
on measurement dates of August 31, 1996 and 1995:
1996 1995
Actuarial present value of benefit
obligations (in thousands):
Vested benefit obligation $ 8,198 $ 7,960
======= =======
Accumulated benefit obligation $ 8,734 $ 8,433
======= =======
Projected benefit obligation
for service rendered to date $ 9,708 $ 9,329
Plan assets 9,083 8,034
------- -------
Projected benefit obligation in excess
of plan assets (625) (1,295)
Unrecognized net gain (776) (321)
Unrecognized prior service cost 1,399 1,537
Adjustment required to recognize
additional minimum liability - (330)
Unrecognized net obligation at transition - 10
------- -------
Accrued pension liability $ (2) $ (399)
======= =======
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 loan is guaranteed by the Company and
the final payment of $75,000 is due in October, 1996. The ESOP
is recorded as a liability and the offsetting debit is accounted
for as a reduction of common stock equity in the accompanying
consolidated balance sheets. Interest is payable monthly at a
floating rate which is 80% of the current prime rate. The charge
to income, which equals the Company's contribution, for 1996 was
$223,477, which includes 6,000 additional shares to be issued in
early 1997, for 1995 was $141,359, and for 1994 was $223,349.
Interest on ESOP debt was $8,055 for 1996, $17,365 for 1995, and
$37,023 for 1994. Dividends on unallocated ESOP shares used to
pay debt service was $12,738 for 1996, $27,193 for 1995, $41,352
for 1994.
<PAGE> 35
Savings Plan
The Company has a thrift savings plan in which the Company
matches a portion of employee contributions up to six percent of
a participant's wages. The Company contributed approximately
$142,000 to the Plan in 1996, $119,000 to the plan in 1995, and
$108,000 to the plan in 1994.
Postretirement Benefits Other Than Pension
On September 1, 1993, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 106, Employers'
Accounting for Postretirement Benefits Other Than Pensions ("SFAS
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. The cumulative effect of the
implementation of SFAS 106 as of September 1, 1994 is being
amortized over 20 years. Prior to 1994, the cost of
postretirement benefits was recognized on a pay-as-you-go basis.
The Company is currently recovering the full SFAS 106 cost in
rates.
The net periodic postretirement benefit cost for the year ended
August 31, 1996, 1995 and 1994 is as follows:
1996 1995 1994
Service cost $104,469 $ 84,550 $110,691
Interest cost 316,398 284,861 296,310
(Return) loss on plan assets (22,610) 13,066 -
Net amortization and deferral 189,435 157,634 203,868
-------- -------- --------
TOTAL POSTRETIREMENT BENEFIT COST $587,692 $540,111 $610,869
======== ======== ========
The funded status of the Company's postretirement benefit plan
using a measurement date of July 1, 1996, 1995 and 1994 is as
follows:
1996 1995 1994
Accumulated postretirement benefit obligation:
Retirees $(2,834,211) $(2,972,713) $(2,714,112)
Fully eligible active Plan
participants (108,839) (118,200) (168,942)
Other active Plan
participants (1,274,960) (1,264,135) (1,183,982)
----------- ----------- -----------
(4,218,010) (4,355,048) (4,067,036)
Plan assets at fair value 886,580 557,939 229,781
----------- ----------- -----------
Accumulated postretirement
obligation greater than
Plan assets (3,331,430) (3,797,109) (3,837,255)
Unrecognized transition
obligation 3,465,748 3,669,616 3,873,484
Unrecognized (gain) loss (310,951) (3,021) (141,261)
---------- ---------- ----------
ACCRUED POSTRETIREMENT
BENEFIT COST $ (176,633) $ (130,514) $ (105,032)
============ ============ ============
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5% in 1996,
1995 and 1994. The annual increase in the cost of covered health
care benefits for 1996 and 1995 was 9.5% and 7.5% for
participants under age 65 and over age 65, respectively, and for
1994 was 13% and 8% for participants under 65 and over 65,
respectively. This increase gradually decreases to 5% in the
year 2007 and thereafter. A 1% increase in the
<PAGE> 36
assumed health care cost trend rate would have increased the cost
computed under SFAS 106 by $32,648 and increased the accumulated
postretirement benefit by $327,934 as of August 31, 1996.
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
postretirement benefit obligation. The Company made
contributions to the VEBA trusts and the subaccount during 1996
and 1995 totaling $541,483 and $514,629, respectively. Assets in
the VEBA trusts are held in cash reserve accounts. Assets in
the subaccount to the pension plan are currently held in
mutual funds.
Incentive Stock Option Plan
In 1995 the Company adopted a Stock Option Plan ("Plan"). In
accordance with the Plan, options may be granted from time to
time but the total number of shares subject to the Plan shall not
exceed 100,000 with not more than 25,000 shares granted during
any one year to any individual. The Plan is considered an
Incentive Stock Option Plan under Internal Revenue Code Section
422. No options were granted or exercised during fiscal 1996.
During 1995, a total of 24,000 shares were granted at a price of
$24.50 with exercise dates beginning February 9, 1996 and ending
February 9, 2000. No options were exercised during 1995.
J. Commitments and Contingencies
Construction Expenditures
The Company's construction expenditures in connection with its
continuing construction program are presently estimated at
$6,400,000 for 1997 and approximately $6,200,000 in each of the
four following years.
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, 1996, the transition
costs are estimated at $890,000 and will be billed over a period
of approximately three years subject to modification and/or refund
based on final FERC approval of pipeline transition costs to be
recovered. Negotiations are continuing with the pipeline of
several other issues. As a result, the Company is unable to
predict its final obligation at this time; however, based on
these and subsequent settlement activities, the Company will
adjust its regulatory assets and liability accounts accordingly.
The MDPU has allowed recovery of these transition costs through
the CGA.
<PAGE> 37
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:
1997 to 2001
Pipeline transportation demand $ 5,124,156
Underground storage demand 946,344
Underground storage transportation 1,011,780
Pipeline gas inventory charge 2,924,352
Gas supply realignment charges 890,424
-----------
$10,897,056
===========
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, the potential liability would not materially effect
the financial condition or the results of operations of the Company.
Environmental Matters
The Company has received notification that the Massachusetts
Department of Environmental Protection ("MDEP"), has reason to
believe that the Company may be a potentially responsible party,
along with several other parties, with respect to alleged release
of hazardous materials at sites in Plympton, Massachusetts. The
Company does not currently have sufficient information to
reasonably estimate the amount of the final liability for cleanup
costs or other damages or expenses at such sites. The Company
believes it should be permitted to recover these costs through
rates. The Company or its predecessors previously operated four
manufactured gas plants and one storage facility (collectively,
"MGPs") at sites in Massachusetts. It is possible that in the
manufacturing process some or all of the MGPs may have discharged
certain substances on the sites which may now be deemed to be
hazardous. The Company has not ascertained the extent of any
hazardous substance contamination on these sites from the MGP
operations. The Environmental Protection Agency ("EPA") and MDEP
have recently begun to focus on the potential environmental
hazards of MGPs. To the Company's knowledge, neither the EPA
nor the MDEP have issued any orders to clean up any of the
Company's MGP sites. In 1995 an investigation which reported
the presence of certain compounds was conducted at one of the
Company's MGP sites. As a result, a second, more intensive
investigation is to be conducted to determine the level of
contamination and to assess whether any
<PAGE> 38
remediation is required. The Company has also been informed that
certain materials have been discovered on properties adjacent to
a second site currently owned by the Company. These adjacent
properties have been classified by the MDEP as a location to be
investigated. Based on preliminary investigation, the Company
currently believes that it may not be liable for cleanup costs
associated at the adjacent properties unless such liability is
based on down-gradient status; however, the Company may be liable
for cleanup costs associated with the parcel presently owned by
the Company. The Company does not currently possess sufficient
information to determine the probability or the cost of the
potential remediation, however, the MDPU provides for the
recovery through the CGA of all environmental response costs
associated with this and any other MGP sites over seven-year
amortization periods without a return on the unamortized balance.
The settlement agreement also provides for no further
investigation on the prudency of any Massachusetts gas utility's
past MGP operations.
K. Subsequent Events
In September 1996 the Company received approval for a rate increase
of $2,100,000 which is scheduled to be effective December 1,
1996. As part of the settlement approved by the MDPU, the
Company will increase its depreciation rate to an average rate of
3.70% effective December 1, 1996 based on a depreciation study.
The effect of the change in the depreciation rate is to increase,
on an annual basis, depreciation expense in 1997 by approximately
$600,000.
The Company has sought MDPU approval of the private placement of
First Mortgage Bonds in the amount of approximately $10,000,000.
<PAGE> 39
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, 1996 and 1995, and
the related consolidated statements of income, retained earnings
and cash flows for each of the three years in the period ended
August 31, 1996. 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,
1996 and 1995, and the results of its operations and its cash
flows for each of the three years in the period ended August 31,
1996, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts,
October 21, 1996
<PAGE> 40
PART III
Item 9: Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
Item 10: Directors and Executive Officers of the Registrant
The information required by Item 401 and 405 of Regulation
S-K is herein incorporated by reference to Registrant's Proxy
Statement dated December 5, 1995, for the Annual Meeting of
Stockholders to be held on January 21, 1997.
Item 11: Executive Compensation
The information required by Item 402 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 5, 1995, for the Annual Meeting of Stockholders to
be held on January 21, 1997.
Item 12: Security Ownership of Certain Beneficial Owners and
Management
The information required by Item 403 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 2, 1996, for the Annual Meeting of Stockholders to
be held on January 21, 1997.
Item 13: Certain Relationships and Related Transactions
The information required by Item 404 of Regulation S-K is
herein incorporated by reference to Registrant's Proxy Statement
dated December 2, 1996, for the Annual Meeting of Stockholders to
be held on January 21, 1997.
<PAGE> 41
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
ESSEX COUNTY GAS COMPANY
(Registrant)
Date: November 25, 1996 by /s/ James H. Hastings
Vice President and Treasurer
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, this report has been signed below by the
following persons in the capacities and on the dates indicated.
Signature Title Date
/s/ Charles E. Billups Chairman of the Board 11/25/96
/s/ Philip H. Reardon President and Chief 11/25/96
Executive Officer
/s/ James H. Hastings Vice President and 11/25/96
Treasurer (Principal
Financial and Accounting
Officer)
/s/ Benjamin C. Bixby Director 11/20/96
/s/ Daniel A. Burkhardt Director 11/25/96
/s/ Edward J. Curtis Director 11/21/96
/s/ Dorothy J. Dotson Director 11/20/96
/s/ Richard P. Hamel Director 11/20/96
/s/ Robert S. Jackson Director 11/25/96
/s/ Eric H. Jostrom Director 11/21/96
/ / Robert L. Meade Director
<PAGE> 42
Signature Title Date
/ / Kenneth L. Paul Director
/s/ Richard L. Wellman Director 11/20/96
<PAGE> 43
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 22
through 38, and the Report of Arthur Andersen LLP on page
39 herein.
2. Schedules.
None.
3. Exhibits
Exhibit
Number Description
3.1 Restated Articles of Organization of Essex County
Gas Company.3
3.2 Bylaws of Essex County Gas Company.3
4.1 The rights of holders of Redeemable Preferred
Stock, 5.50% Series and the rights of holders of
Common Stock, are defined in the Bylaws and the
Restated Articles of Organization of the Registrant.
See Exhibit 3.1.
4.2 Indenture dated as of June 1, 1986 between the Company and
Centerre Trust Company of St. Louis, Trustee.2
4.3 Eleventh Supplemental Indenture dated as of September 15,
1988, providing for a 10 1/4% Series due 2003.1
4.4 Twelfth Supplemental Indenture dated as of December 1,
1990, providing for a 10.10% series due 2020.4
4.5 Revolving credit agreement.9
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
<PAGE> 44
Exhibit
Number Description
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, among
Allstate Life Insurance Company of New York, and
Essex County Gas Company.4
10.11 Iroquois Gas Transmission System, L.P. Gas Transpor-
tation 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
<PAGE> 45
Exhibit
Number Description
10.17 Tennessee Gas Pipeline Company Storage Service
Transportation Contract TF-4175 dated October
28, 1991.6
10.18 The Company has entered into an amended employment
contract with Charles E. Billups, Chairman of the
Board.2*
10.19 Form of employment contract 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*
10.20 Employment Agreement between the Company and Philip
H. Reardon, President, dated November 19, 1992.7*
10.22 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
10.23 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
10.24 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
10.25 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
10.26 Gas Transportation Agreement between Essex County
Gas Company and Tennessee Gas Pipeline Company (for
use under Rate Schedule FS) dated September 1,
1993.8
10.27 Amendment to Employment Agreement between the
Company and Philip H. Reardon, President, dated
March 3, 1994.*
<PAGE> 46
Exhibit
Number Description
10.28 Amendment to Employment Agreement between the
Company and John W. Purdy, Jr., Vice President,
dated March 3, 1994.*
10.29 Amendment to Employment Agreement between the
Company and Wayne I. Brooks, Vice President,
dated March 3, 1994.*
10.30 Amendment to Employment Agreement between the
Company and Allen R. Neale, Vice President,
dated March 3, 1994.*
10.31 Amendment to Employment Agreement between the
Company and James H. Hastings, Vice President
and Treasurer, dated March 3, 1994.*
10.32 Amendment to Employment Agreement between the
Company and Cathy E. Brown, Corporate Clerk,
dated March 3, 1994.*
10.33 Essex County Gas Company Supplemental Retirement
Plan for Philip H. Reardon effective January 1, 1994.*
10.34 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.
No reports on Form 8-K have been filed during the
quarter ended August 31, 1995.
*Denotes Management Contract.
1Previously 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.
2Previously filed as an exhibit to Registrant's Registration Statement on
Form S-2 filed June 19, 1986, File No. 33-6597 and is incorporated herein
by this reference.
3Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter year ended February 29, 1996, and is incorporated herein by this
reference.
4Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter ended February 28, 1991, and is incorporated herein by this
reference.
<PAGE> 47
5Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter ended May 31, 1992, and is incorporated herein by this reference.
6Previously filed as an exhibit to Registrant's 10-K filed for the
fiscal year ended August 31, 1992, and is incorporated herein by this
reference.
7Previously 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.
8Previously 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.
9Previously filed as an exhibit to Registrant's Form 10-Q filed for the
quarter ended May 31, 1996 and incorporated herein by this reference.
<PAGE> 1
EMPLOYMENT AGREEMENT
THIS AGREEMENT between Essex County Gas Company, a Massachusetts corporation
(the "Corporation"), and William T. Beaton, (the "Executive"), dated this 7th
day of June 1995,
WITNESSETH THAT:
WHEREAS, the Corporation wishes to attract and retain well-qualified
executives and key personnel and to assure both itself and the Executive of
continuity of management in the event of any actual or threatened Change of
Control (as defined in Section 2) of the Corporation;
NOW, THEREFORE, it is hereby agreed by and between the parties as
follows:
1. Operation of Agreement. The "effective date of this Agreement" shall be
the date on which a Change of Control occurs.
2. Change of Control. For the purposes of this Agreement, a "Change of
Control" means:
(a) the acquisition by an individual, entity or group (within the meaning
of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as
amended (the "Exchange Act") (a "Person") of beneficial ownership (within
the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or
more of the combined voting power of the then outstanding voting securties
of the Corporation entitled to vote generally in the election of directors
(the "Outstanding Corporation Voting Securities"); provided, however, that
for purposes of this subsection (a), the following acquisitions shall not
constitute a Change of Control; (i) any acquisition direction from the
Corporation, (ii) any acquisition by the Corporation; (iii) any acquisition
by any employee benefit plan (or related trust) sponsored or maintained by
the Corporation or any corporation controlled by the Corporation or (iv)
any acquisition that complies with clauses (i), (ii) and (iii) of sub-
section (c) below; or
<PAGE> 2
(b) individuals who, as of the date hereof, constitute the Board (the
"Incumbent Board") cease for any reason to constitute at least a majority of
the Board; provided, however, that any individual becoming a director sub-
sequent to the date hereof whose election, or nomination for election by
the Corporation's shareholders, was approved by a vote of at least a
majority of the directors then comprising the Incumbent Board shall be
considered as though such individual were a member of the Incumbent Board,
but excluding, for this purpose any such individual whose initial assumption
of office occurs as a result of an actual or threatened election contest
with respect to the election or removal of directors or other actual or
threatened solicitation of proxies or consents by or on behalf of a Person
other than the Board; or
(c) the approval by the shareholders of the Corporation of a reorganization,
merger or consolidation or sale or other disposition of all or substantially
all of the assets of the Corporation ("Business Combination") or, if con-
summation of such Business Combination is subject, at the time of such
approval by shareholders, to the consent of any government or governmental
agency, the obtaining of such consent (either explicitly or implicitly by
consummation); excluding, however, such a Business Combination pursuant to
which (i) all or substantially all of the individuals and entities who were
the beneficial owners of the outstanding Corporation Voting Securities
immediately prior to such Business Combination beneficially own, directly or
indirectly, more than 60% of, respectively, the then outstanding shares of
common stock and the combined voting power of the then outstanding voting
securities entitled to vote generally in the election of directors, as the
case may be, of the corporation resulting from such Business Combination
(including, without limitation, a corporation that as a result of such
transaction owns the Corporation or all or substantially all of the Corpora-
tion's assets either directly or through one or more subsidiaries) in sub-
<PAGE> 3
stantially the same proportions as their ownership, immediately prior to
such Business Combination of the Outstanding Corporation Voting Securities,
(ii) no Person (excluding any employee benefit plan (or related trust) of
the Corporation or such corporation resulting from such Business Combina-
tion) beneficially owns, directly or indirectly, 20% or more of, respectively,
the then outstanding shares of common stock of the corporation resulting
from such Business Combination or the combined voting power of the then out-
standing voting securities of such corporation except to the extent that such
ownership existed prior to the Business Combination and (iii) at least a
majority of the members of the board of directors of the corporation resulting
from such Business Combination were members of the Incumbent Board at the time
of the execution of the initial agreement, or of the action of the Board,
providing for such Business Combination; or
(d) approval by the shareholders of the Corporation of a complete liquidation
or dissolution of the Corporation.
3. Employment. The Corporation hereby agrees to continue the Executive in
its employ, and the Executive hereby agrees to remain in the employ of the
Corporation, for the period commencing on the effective date of this
Agreement andmending on the earlier to occur of the second anniversary of
such date or the Executive's normal retirement date under the Corporation's
retirement plans (the "employment period"), to exercise such authority and
perform such executive duties as are commensurate with the authority being
exercised and duties being performed by the Executive immediately prior to
the effective date of this Agreement, which services shall be performed at
the location where Agreement. The Executive agrees that during the
<PAGE> 4
employment period he shall devote his full business time exclusively to his
executive duties as described herein and perform such duties faithfully and
efficiently.
4. Compensation, Compensation Plans, Perquisites. During the employment
period, the Executive shall be compensated as follows:
(a) He shall receive an annual salary at a rate which is not less than his
rate of annual salary immediately prior to the effective date of this
Agreement, with the opportunity for increases, from time to time
thereafter, which are in accordance with the corporation's regular
practices.
(b) He shall be eligible to participate on a reasonable basis in bonus,
stock option, restricted stock, performance award and other incentive
compensation plans which provide opportunities to receive compensation
which are the greater of the opportunities provided by the Corporation
for executives with comparable duties or the opportunities under any
such plans under which he was participating immediately prior to the
effective date of this Agreement.
(c) He shall be entitled to receive employee benefits (including, but not
limted to, medical, insurance and split-dollar life insurance benefits)
and perquisites which are the greater of the employee benefits and
perquisites provided by the Corporation to executives with comparable
duties or the employee benefits and perquisites to which he was entitled
immediately prior to the effective date of this Agreement.
5. Termination. The term "termination" shall mean termination by the
Corporaion of the employment of the Executive with the Corporation for any
reason other than death, disability or cause (as defined below), or
resignation of the Executive upon the occurence of either of the following
events:
<PAGE> 5
(a) Any signficant change in the nature or scope of the Executive's
authorities or duties from those described in Section 3, any reduction
in total compensation from that provided in Section 4, or the breach by
the Corporation of any other provision of this Agreement; or
(b) A reasonable determination by the Executive that, as a result of a Change
of Control and a change in circumstances thereafter significantly
affecting his position, he is unable to exercise the authorities,
powers, functions or duties attached to his position and contemplated
by Section 3 of this Agreement.
The term "cause" means fraud, misappropriation or intentional material damage
to the property or business of the Corporation or commission of a felony.
A termination shall also include resignation of the Executive for any reason
during the 30-day period immediately following the first anniversary of the
effective date of this Agreement.
6. Severance Allowance. In the event of termination of the Executive during
the employment period, the Executive shall be paid a lump sum severance
allowance in an amount which is equal to the sum of the amounts determined in
accordance with the following paragraphs (a) and (b):
(a) An amount equivalent to the salary payments for the number of calendar
months during the remainder of the employment period at the rate required
by Section 4(a), as in effect immediately before the resignation as
described in Section 5(a)), plus a pro rata share of the estimated
amount of any bonus which would have been payable for the bonus period
which includes the termination date; and
<PAGE> 6
(b) An amount equivalent to the number of calendar months of bonus during the
remainder of the employment period at the geater of (i) the monthly rate
of the bonus payment for the bonus period immediately prior to his
termination date, or (ii) the estimated amount of the bonus for the
period which includes his termination date.
In addition to such amount, he shall receive continuation for the remainder of
the employment period of the employee welfare benefits (including, but not
limited to, coverage under any medical, insurance and split-dollar life
insurance arrangements or programs) to which he would have been entitled under
all employee welfare benefit plans, programs or arrangements maintained by the
Corporation if he had remained in the employ of the Corporation for the
remainder of the employment period, or, at the Company's option, a cash
payment equal to the cost to the Executive of purchasing replacement benefits,
determined and paid as soon as it is reasonably possible.
7. Limitation.
(a) Notwithstanding any other provision of this Agreement, in the event it
shall be determined that any payment or distribution by the Corporation
or to or for the benefit of the Executive (whether paid or payable or
distributed or distributable pursuant to the terms of this Agreement or
otherwise) (a "Payment") would be nondeductible by the Corporation for
Federal income tax purposes because of Section 280G of the Internal
Revenue Code of 1986, as amended (the"Code"), then the aggregate present
value of amounts payable or distributable to or for the benefit of the
Executive pursuant to this Agreement (such payments or distributions
pursuant to this Agreement are hereinafter referred to as "Agreement
Payments") shall be reduced (but not below zero) to the Reduced
Amount. The "Reduced Amount" shall be an amount expressed in present
<PAGE> 7
value that maximizes the aggregate present value of Agreement Payments
without causing any Payment to be nondeductible by the Corporation
because of Section 280G of the Code. For purposes of this Section 7,
present value shall be determined in accordance with Section 280G(d)(4)
of the Code.
(b) All determinations required to be made under this Section 7 shall be made
by the accounting firm last appointed as auditors of the Corporation by
the Board of Directors before the Change of Control (the "Accounting
Firm"), which shall provide detailed supporting calculations to both the
Corporation and the Executive within 30 business days of the date of the
Change of Control or such earlier time as is required by the Corporation.
Any such determination by the Accounting Firm shall be binding upon the
Corporation and the Executive. The Executive shall determine which and
how much of the Agreement Payments (or, at the election of the Executive,
other Payments) shall be eliminated or reduced consistant with the
requirements of this Section 7, provided that, if the Executive does not
make such determination within ten business days of the receipt of the
calculations made by the Acccounting Firm, the Corporation shall elect
which and how much of the Agreement Payments shall be eliminated or
reduced consistent with the requirements of this Section 7 and shall
notify the Executive promptly of such election. Within five business
days thereafter, the Corporation shall pay to or distribute to or for
the benefit of the Executive such amounts as are then due to the
Executive under this Agreement.
(c) As a result of the uncertainty in the application of Section 280G of the
Code at the time of the initial determination by the Accounting Firm
hereunder, it is possible that Agreement Payments will have been made by
the Corporation that should not have been made ("Overpayment") or that
addtional Agreement Payments that will have not been made by the
Corporation could have been made ("Underpayment"), in each case,
consistent with the calculations required to be made hereunder. In the
event that the Accounting Firm determines that an Overpayment has been
made, any such Overpayment shall be treated for all purposes asa loan to
the Executive, which the Executive shall repay to the Corporation
together with interest at the applicable Federal rate provided for in
<PAGE> 8
Section 7872(f)(2) of the Code; provided, however, that no amount shall
be payable by the Executive to the Corporation (or if paid by the
Executive to the Corporation shall be returned to the Executive) if and
to the extent such payment would not In the event that the Accounting
firm determines that an Underpayment has occurred, any such Underpayment
shall be promptly paid by the Corporation to or for the benefit of the
Executive together with interest at the applicable Federal rate provided
for in Section 7872(f)(2) of the Code.
8. Indemnification. If litigation shall be brought to enforce, interpret or
challenge any provision hereof, the Corporation hereby indemnifies the
Executive for his reasonable attorney's fees and disbursements incurred in
such litigation.
9. Notices. Any notices, requests, demands and other communications provided
for by this Agreement shall be sufficient if in writing and if sent by
registered mail to the Executive at the last address he has filed in writing
with the Corporation, or in the case of the Corporation, at its principal
executive offices.
10. Non-Alienation. The Executive shall not have any right to pledge,
hypothecate, anticipate or in any way create a lien upon any amounts provided
under this Agreement; and not benefits payable hereunder shall be assignable
in anticipation of payment either by voluntary or involuntary acts, or by
operation of law, except by will or the laws of descent and distribution.
11. Governing Law. The provisions of this Agreement shall be construed to
be in accordance with the laws of the Commonwealth of Massachusetts.
<PAGE> 9
12. Amendment. This Agreement may be amended or canceled by mutual agreement
of the parties in writing without the consent of any other person and so long
as the Executive lives, no person, other than the parties hereto, shall have
any rights under or interet in this Agreement or the subject matter hereof.
Provided, further, that in the event any law, rule or regulation hereafter
passed or promulgated shall require that this contract be submitted to the
shareholders for their consideration, then, and in that event, the parties do
hereby covenant that if they do not mutually agree to submit this contract to
the shareholders in accordance with such law, rule or regulation, they will
amend this contract so as to make submission to the shareholders unnecessary
under said law, rule or regulation.
13. Successor to the Corporation. Except as otherwise provided herein, this
Agrement shall be binding upon and inure to the benefit or the Corporation
and any sucessor of the Corporation.
14. Severability. In the event that any provision or portion of this Agree-
ment shall be determined to be invalid or unenforceable for any reason, the
remaining provisions of this Agreement shall be unaffected thereby and shall
remain in full force and effect.
<PAGE> 10
IN WITNESS WHEREOF, the Executive has hereunder set his hand and,
pursuant to the authorization from its Board of Directors, the Corporation
has caused these present to be executed in its name and behalf, all as of
the day and year first above written.
/s/ William T. Beaton
ESSEX COUNTY GAS COMAPNY
by: /s/ Charles E. Billups
Its Chairman
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000046189
<NAME> ESSEX COUNTY GAS COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> AUG-31-1996
<PERIOD-END> AUG-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 76,314
<OTHER-PROPERTY-AND-INVEST> 634
<TOTAL-CURRENT-ASSETS> 9,043
<TOTAL-DEFERRED-CHARGES> 3,128
<OTHER-ASSETS> 654
<TOTAL-ASSETS> 89,772
<COMMON> 19,235
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 13,834
<TOTAL-COMMON-STOCKHOLDERS-EQ> 33,069
0
0
<LONG-TERM-DEBT-NET> 19,766
<SHORT-TERM-NOTES> 11,940
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 924
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 50
<OTHER-ITEMS-CAPITAL-AND-LIAB> 23,554
<TOT-CAPITALIZATION-AND-LIAB> 89,772
<GROSS-OPERATING-REVENUE> 49,929
<INCOME-TAX-EXPENSE> 1,793
<OTHER-OPERATING-EXPENSES> 41,467
<TOTAL-OPERATING-EXPENSES> 43,260
<OPERATING-INCOME-LOSS> 6,669
<OTHER-INCOME-NET> 2
<INCOME-BEFORE-INTEREST-EXPEN> 6,671
<TOTAL-INTEREST-EXPENSE> 3,849
<NET-INCOME> 3,836
14
<EARNINGS-AVAILABLE-FOR-COMM> 3,836
<COMMON-STOCK-DIVIDENDS> 2,578
<TOTAL-INTEREST-ON-BONDS> 1,967
<CASH-FLOW-OPERATIONS> 6,227
<EPS-PRIMARY> 2.36
<EPS-DILUTED> 2.36
</TABLE>
