[LIVE]
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
________________________
Form 10-K
(Mark One)
/X/ Annual report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934.
For the fiscal year ended August 31, 1995.
/ / 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, $2.50 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, 1995 based upon the last sales price on that date was
approximately $40,367,000.
DOCUMENTS INCORPORATED BY REFERENCE: Part III hereofincorporates by
reference portions of the definitive Proxy Statement dated
December 5, 1995, for the Annual Meeting of Stockholders to be held
January 16, 1996. Part IV hereofincorporates 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.
2
ESSEX COUNTY GAS COMPANY
FORM 10-K
Annual Report
Year Ended August 31, 1995
---------------------------
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 11
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 47
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 and Newburyport, the towns of Amesbury and Ipswich, and thirteen
other 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 fiscal
1995 there was a slight increase in new residential construction. New home
construction activity significantly impacts the degree to which the Company
is able to grow itscustomer base.
Sales and Customer Data
The Company sells natural gas to over 40,000 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 1995,
the Company's total operating revenues were $45,049,573 of which
approximately 63.9% was derived from residential customers, 29.5% from
commercial and industrial customers, 4.3% from interruptible customers
and 2.3% from other sources. During this period, the Company sold
5,951,055 thousand cubic feet of gas (Mcf), of which approximately 53.7%
was purchased byresidential customers, 31.0% by commercial and industrial
customers and 15.3% by interruptible customers. Losses and company use
amounted to 86,387 Mcf for 1995.
Set forth in the following table is information by customer classification
showing operating revenues, gas delivered and number of customers for the
periods indicated.
Fiscal Years Ended August 31,
1995 1994 1993 1992 1991
(Dollars and Mcfs in Thousands)
Operating Revenues:
Residential-general $ 2,159 $ 2,291 $ 2,160 $ 2,070 $ 2,107
Residential-heating 26,589 29,245 27,218 25,150 21,666
Commercial and Industrial 13,353 15,000 14,006 13,432 12,001
Interruptible 1,933 888 653 1,316 1,724
Other 1,016 1,112 979 945 859
Total $45,050 $48,536 $45,016 $42,913 $38,357
======= ======= ======= ======= =======
Gas Delivered (Mcf):
Residential-general 148 159 158 158 171
Residential-heating 3,045 3,325 3,228 3,083 2,651
Commercial and Industrial 1,843 2,014 1,948 1,927 1,730
Interruptible 915 389 273 669 850
Total Sales 5,951 5,887 5,607 5,837 5,402
Losses and Company Use 86 79 89 101 78
Total 6,037 5,966 5,696 5,938 5,480
====== ====== ====== ====== ======
Number of Customers at Year-End:
Residential-general 7,369 7,560 7,439 6,776 6,965
3,884 3,863 3,941
Interruptible 2 2 2 2 2
Total 40,524 39,616 38,759 38,163 38,076
====== ====== ====== ====== ======
Effective Degree Days
(20-Year Average: 6,772) 6,258 7,012 6,956 6,750 5,843
The Company's residential customers are classified as either general or
heating customers. In fiscal 1995, residential-heating customers
accounted for approximately 59.0% of total operating revenues, while
residential-general customers accounted for approximately 4.8% of total
operating revenues. Operating revenues from residential customers decreased
approximately 8.8% to $28,747,790 in fiscal 1995 from $31,535,901 in fiscal
1994. The sales decrease was attributable to the relatively warmer winter in
fiscal 1995 compared to fiscal 1994 as residential volumes decreased 8.3%.
The average rate charged to residential customers per Mcf of gas was $9.00
and $9.05 in fiscal 1995 and 1994, respectively. The decrease was primarily
attributable to lower gas costs incurred by the Company.
The Company's commercial and industrial firm revenues decreased
approximately 10.9% to $13,353,053 in fiscal 1994 from $15,000,214 in
fiscal 1994. The decrease was attributable to a 8.5% volume decrease and
a 2.7% decrease in the average price charged per Mcf of gas from $7.45 to
$7.25. The sales decreases were largely attributable to warmer weather
experienced during the winter in fiscal 1995 as compared to fiscal 1994.
The Company has two interruptible customers, only one of which purchased
significant amounts of gas from the Company in fiscal 1995. Total
interruptible revenues in fiscal 1995 were $1,932,751 compared to $888,236
in fiscal 1994. 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 directly 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 not attained in fiscal 1995. Any gross profit
returned to the customers are returned through a Standard Cost of Gas
Adjustment ("SCGA") under which the Company is permitted to recover its
gas costs. The average price charged by the Company to interruptible
customers was $2.11 per Mcf and $2.28 per Mcf in 1995 and 1994, respectively.
The Company's largest customer purchases gas on an interruptible basis and
accounted for approximately 2.5% of operating revenues on average over the
past three fiscal years ended August 31, 1995. Sales to that customer in
1995 totaled $1,890,561 or 4.2% 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 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% of the total
operating revenues of the Company over the past three years ended
August 31, 1995.
During 1995, the Company added 955 new customers. In fiscal 1994 and 1993,
net new customer additions (which approximated gross additions) were 857
and 596, 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 single-day demand during the last five fiscal years was
46,768 Mcf on February 6, 1995. Maximum single-day demand for 1994 and
1993 were 45,500 and 40,852 respectively. The Company has the ability
to meet a single-day demand of approximately 65,000 Mcf. Single-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 1995 was 6,037,442 Mcf compared to 5,965,627 Mcf in 1994 and
5,695,910 in fiscal 1993.
The following table shows the sources of the Company's gas supply
requirements for the periods indicated.
Fiscal Years Ended August 31,
1995 1994 1993 1992 1991
Gas Supply (Mcf):
Natural gas
from pipeline 4,844,912 4,780,294 4,222,801 5,344,754 4,719,549
Underground
storage
withdrawn 820,493 820,103 1,271,670 459,594 569,458
Liquefied natural
gas produced 372,037 361,440 201,439 132,965 190,508
Propane air
produced - 3,791 - 206 288
Total 6,037,442 5,965,628 5,695,910 5,937,519 5,479,803
========= ========= ========= ========= =========
For the year ended August 31, 1995, approximately 80.2% 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 are subject to approval 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 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 569,828 Mcf
in fiscal 1995 or 97.0% 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 706,742 Mcf in fiscal 1995
or 98.5% of the contracted amount in fiscal year 1995. 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 842,205 Mcf, including 21,712 Mcf of fuel gas, of its total underground
storage in fiscal 1995.
Under a contract expiring November 1, 2000, the Company obtained 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 for underground storage with Consolidated
Supply Corporation for a total volume of 359,450 DTH expiring April 1,
2000. 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 Penn-York
Energy Corporation and extends through March 31, 1996. It is expected
that the contract will be renewed on an annual basis. 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. If the need develops, the Company
will seek a firm transportation contract with TGPC for delivery of the full
volume under the contract with Penn-York Energy Corporation.
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 1995, sendout of LNG
totaled 372,037 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
1995, there was no sendout of propane. Due to the relatively high cost
of LNG and propane, the Company uses these fuels primarily to
satisfy peak winter demand.
Under an agreement with Bay State Gas Company expiring October 31, 1996,
the Company is 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.
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 distri-
bution 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.
The Company faces a changing competitive market for natural gas. Although
it has no direct competition in its territory, 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 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 that the relative price differ-
ential between natural gas and oil will diminish 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, 1995, 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 four requests for rate increases and has
been granted a total of $5,930,791 in rate relief by the MDPU, which
amounts to 61.6% of the total requested. The Company's most recent rate
increase request was filed in fiscal 1993 and approved in fiscal 1994.
The Company's fiscal 1993 rate increase request was for an annualized
increase of approximately $3,000,000 and the MDPU approved an annualized
rate increase of approximately $1,730,000. The rate increase was
effective December 1, 1993.
The MDPU permits Massachusetts gas companies to utilize a SCGA 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
SCGA and no portion of the interruptible profits are retained by the
Company unless certain volumes are sold. Supplemental fuel inventory and
related administrative and carrying costs are also recovered through the SCGA.
In addition, the MDPU allows recovery of the following through the SCGA:
(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 SCGA. The Company has also incurred costs
associated with MDPU Energy Conservation Load Management programs and the
Company expects to recover these costs through the SCGA.
Changes in rates charged to customers which are not incorporated in the SCGA
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 final 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 signifi-
cantly 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 SCGA.
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.
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. 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 1996 to determine the
level of contamination and to assess whether any remediation is required.
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 SCGA 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 Footnote I of 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.
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 (psi) 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, 1995, the Company had 128 permanent employees, 76 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, 1995, the Company had approximately
744 miles of gas mains and 37,124 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, 1995 the Company's gross utility plant amounted to
$91,462,732 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 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, 1996.
Item 3: Legal Proceedings
There are certain non material routine claims incidental to its business
pending against the Company, all of which are covered by insurance or
reserves. Management believes that the Company has adequate defenses
against these claims and it is the Company's intention to contest these
claims. In view of the insurance coverages, 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 31, 1995, the Common Stock was held by 1,383
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, 1994
First Quarter $30.50 $29.00 $0.37
Second Quarter 29.50 26.75 0.38
Third Quarter 28.00 24.75 0.38
Fourth Quarter 25.75 24.25 0.38
Fiscal Year Ended August 31, 1995
First Quarter 25.50 24.25 0.38
Second Quarter 25.25 23.50 0.39
Third Quarter 24.75 22.00 0.39
Fourth Quarter 25.50 22.50 0.39
Fiscal Year Ending August 31, 1996
First Quarter
(through November 10, 1995) 25.25 24.25 0.39*
*Paid on October 1, 1995 to shareholders of record on
September 18, 1995.
The Company has paid regular dividends since 1914. Common Stock
dividend payments in fiscal 1995 totaled $1.55 per share, as compared to
$1.51 in fiscal 1994. 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.
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, 1995. 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,
1995 1994 1993 1992 1991
(000s omitted, except for per share and ratio information)
Income Statement Data:
Operating revenues $45,050 $48,536 $45,016 $42,913 $38,357
Operating income 5,909 5,794 5,766 5,243 4,741
Income available for
common stock 3,180 3,302 2,880 2,331 1,895
Shares of common stock
outstanding,
weighted average 1,591 1,559 1,475 1,306 1,281
Earnings per common share $2.00 $2.12 $1.95 $1.79 $1.48
Cash dividends declared
per common share $1.55 $1.51 $1.47 $1.43 $1.40
Ratio of earnings to fixed
charges (1) 2.54x 2.83x 2.45x 2.11x 1.86x
Balance Sheet Data:
Long-term debt (excluding
current portion) $20,689 $21,713 $22,148 $21,031 $23,011
Redeemable preferred
stock 336 350 364 378 392
Common stock equity 30,709 28,870 26,985 20,982 19,782
Total capitalization $51,734 $50,933 $49,497 $42,391 $43,185
====== ====== ====== ====== ======
Capital lease (excluding
current portion) $ 654 $ 700 $ 742 $ 781 $ 816
====== ====== ====== ====== ======
Total assets $86,582 $83,511 $76,535 $73,157 $65,737
====== ====== ====== ====== ======
_______________________
(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 trust, amortization
of debt expense and the estimated interest portion (one-third) of rental
payments.
Item 7:Management's Discussion and Analysis of Financial Condition and
Results of Operations
Fiscal Years Ended August 31, 1995 and 1994
Revenues
Using a twenty-year average, the Company's service territory incurs
6,772 effective degree days in one year. Fiscal 1995 had 6,258 effective
degree days compared to 7,012 in fiscal 1994. As a result, the volume of
sales to the Company's two major firm customer classes, residential heating
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 weather, coupled with a
1.2% decrease in price, resulted in revenues of $45,049,573 compared to
$48,536,005 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 1995 were 9.5% lower than in fiscal 1994. The decrease was
attributable to the weather and price factors discussed previously, as
the Company's customer base increased by nearly 3.0%. The average unit
price of gas sold to all customers, including interruptible customers,
decreased 8.2% to $7.40 from $8.06 in fiscal 1994. For firm customers,
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
sales volumes increased 525,651 Mcf. The increase in interruptible
sales volumes and revenues was primarily a result of the Company's
ability to purchase natural gas on a low cost spot market basis.
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 1995, the required volumes of interruptible sales
were not obtained, and the Company returned all gross profit on
interruptible sales to its firm customers. Therefore, the increase in
volumes did not significantly impact the Company's earnings. Other
revenues decreased slightly to $1,105,979 from $1,111,654 in fiscal
1994.
During fiscal 1995, the Company added 955 new customers. The Company's
ability to attract customers has been assisted by the improving economy
and resultant new construction. Although there was an unfavorable price
comparison with oil, which is the Company's primary competition in the
area of space heating, the environmental and convenience advantages
of natural gas allow the Company to compete on a favorable footing.
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 primarily due to a decrease of 8.4% in firm volumes of
gas sold. These gas costs are recovered from the Company's firm customers
through a Standard Cost of Gas Adjustment ("SCGA") which is adjusted
semi-annually to reflect any changes in gas costs.
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 $340,000 in uncollectible
accounts. The reduction in outside services expense was primarily
related to the cost of 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 expense increased 6.8% to $2,500,585 in
fiscal 1995 from $2,341,381 in fiscal 1994, reflecting the ongoing
investment in upgrading and expanding the Company's distribution system.
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 related to a
decrease in state income taxes resulting from 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 taxes was 34.6%.
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 of 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 fiscal 1995 from $3,301,711, or $2.12 per share, in fiscal
1994. Dividends per share declared and paid for fiscal 1995 and 1994 were
$1.55 and $1.51, respectively.
Fiscal Years Ended August 31, 1994 and 1993
Revenues
The Company experienced 7,012 effective degree days in fiscal 1994
compared to only 6,956 in fiscal 1993. As a result, the volume of unit
sales in the Company's two major customer classes, residential heating
and commercial and industrial, increased by 3.1% from 5,175,765 Mcf in
1993 to 5,338,422 Mcf in the current year. The colder than normal
weather, plus a 4.2% increase in rates approved by the DPU effective
December 1, 1991, resulted in increased revenues from $45,016,043 to
$48,536,005. Firm revenues increased nearly 7.3% over fiscal 1993,
primarily due to the weather and rate factors indicated above, as the
Company's customer base increased by only 2.2%. The average unit price
of all gas sold to customers, including interruptible customers,
increased 2.7% to $8.06 from $7.85 in fiscal 1993. For firm customers
only, the average unit price increased to $8.47 from $8.13 in the prior
year. The Company's interruptible revenues increased 36.0% as
interruptible volumes increased 116,679 Mcf. The increase in
interruptible volumes was primarily due to the availability of natural
gas at a more favorable price than oil. The increase in volumes did not
significantly impact the Company's earnings due to the accounting
treatment discussed above. Other revenues increased slightly to
$1,111,654 from $978,764 in 1993.
Operating Expenses
The Company's major operating expense is its cost of gas, which
increased 6.6% to $25,000,794 in fiscal 1994 from $23,456,542 in
fiscal 1993. This increase was due to additional volumes of gas sold.
Operations and maintenance expenses increased 10.0% to $12,206,720 in
fiscal 1994 from $11,097,811 in fiscal 1993. This increase was mainly
attributable to: increases of approximately $500,000 in outside
services, $250,000 in medical expenses, $120,000 in regulatory expenses,
$105,000 in legal and consulting costs related to Order 636, and an
increase of approximately $60,000 related to additional volumes of LNG
vaporized. The additional outside service expense was primarily
related to 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.
The increase in employee benefits was primarily related to $600,000
for additional medical costs for current and future retirees as the
Company has commenced recognizing these expenses over a twenty-year
period. These costs were offset by a reduction of approximately $350,000
in medical expenses for current employees.
Utility Plant depreciation increased 7.6% to $2,341,381 in fiscal 1994
from $2,175,693 in fiscal 1993, reflecting the increase in the Company's
utility plant.
Taxes, other than federal income, increased 38.7% to $1,675,782 in
fiscal 1994 from $1,208,506 in fiscal 1993. This increase was due to an
increase in real estate and property taxes associated with the Company's
increased investment in utility plant and an increase in state income
taxes resulting from the increase in the Company's pre-tax earnings.
Federal income taxes increased 15.7% to $1,517,130 in fiscal 1994 from
$1,311,456 in fiscal 1993, also reflecting the increase in the Company's
pre-tax earnings. The Company's combined effective tax rate for both
federal and state income tax purposes was 35.8%.
Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994
from $2,442,345 in fiscal 1993. This decrease was related to the
prepayment in 1993 of long-term debt. Other interest expense increased
74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993. Other
interest expense increased 74.5% to $351,088 in fiscal 1994 from
$201,208 in fiscal 1993. This increase was primarily attributable to
higher levels of short-term debt outstanding and higher interest rates
in fiscal 1994 as compared to fiscal 1993.
Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994
from $2,442,345 in fiscal 1993. This decrease was related to the
prepayment in 1993 of long-term debt. Other interest expense increased
74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993. This
increase was primarily attributable to higher levels of short-term debt
outstanding and higher interest rates in fiscal 1994 as compared to
fiscal 1993.
Income available for common stock increased 14.6% to $3,301,711 or
$2.12 per share in 1994, from $2,880,490 or $1.95 per share in 1993.
Dividends per share declared and paid for fiscal 1994 and 1993 were
$1.51 and $1.47, respectively.
Liquidity and Capital Resources
The Company periodically borrows from banks on an unsecured, short-term
basis. At August 31, 1995, the Company had $4,890,000 of outstanding
notes payable under available lines of credit totaling $16,500,000 with
five different banks. In addition, for the sole purpose of financing
the Supplemental Fuel Inventory, the Company has a $7,000,000 line of
credit. The Supplemental Fuel Inventory line of credit expired
October 31, 1995 and the Company has a bridge loan in place until it
receives Massachusetts Department of Public Utilities ("MDPU") approval
for a new, long-term financing. MDPU approval is expected in late fall
or early winter 1995. 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 1995,
the Company's construction expenditures were approximately $7,000,000.
This compares to $6,100,000 in fiscal 1994. These capital expenditures
were funded primarily from short-term debt and operations. The Company's
higher construction expenditures in fiscal 1995 were primarily
attributable to additional construction requirements to bring on new
customers and major upgrading of the Company's existing infrastructure.
Capital expenditures for fiscal 1996 are expected to be approximately
$7,000,000.
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 SCGA 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 SCGA is also used as the
mechanism to reduce charges to firm customers by the margin earned on
sales to interruptible customers.
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 investi-
gation 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 1996 to determine the level of
contamination and to assess whether any remediation is required. 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 SCGA 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 MDPU agreement also provides for no further investigation
of the prudency of any Massachusetts gas utility's past MGP operations.
The natural gas industry is in the process of transitioning from a
highly regulated environment to a competitive environment. Pursuant to
Federal Energy Regulatory Commission ("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, Tennessee 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. Tennessee 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, 1995, together with
the related regulatory asset. The MDPU has approved the recovery of GSR
costs from all firm customers.
The MDPU had previously sought comments from interested persons on how
incentive regulation could improve upon the existing framework of utility
regulation. As a result, as part of any general rate filing, companies
must provide the MDPU with recommendations.
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, 1995
and 1994, and the related consolidated statements of income,
retained earnings and cash flows for each of the three years
in the period ended August 31, 1995. 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, 1995 and 1994, and the results of its operations
and its cash flows for each of the three years in the period
ended August 31, 1995, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts,
October 30, 1995
Item 8: Financial Statements and Supplementary Data
CONSOLIDATED STATEMENTS OF INCOME
Fiscal Years Ended August 31,
1995 1994 1993
Operating revenues
$45,049,573 $48,536,005 $45,016,043
Less: Cost of gas 22,525,442 25,000,794 23,456,542
Operating margin 22,524,131 23,535,211 21,559,501
Operating expenses:
Operations and
maintenance expenses 11,078,029 12,206,720 11,097,811
Depreciation 2,500,585 2,341,381 2,175,693
Taxes, other than federal
income 1,634,216 1,675,782 1,208,506
Federal income taxes 1,401,858 1,517,130 1,311,456
Total operating expenses 16,614,688 17,741,013 15,793,466
Operating income
5,909,443 5,794,198 5,766,035
Other income (expense), net 6,202 (7,828) (184,152)
Income before interest charges 5,915,645 5,786,370 5,581,883
Interest charges:
Interest on long-term debt 2,048,959 2,124,058 2,442,345
Amortization of deferred
debt expense 27,081 26,697 84,323
Other interest expense 732,941 351,088 201,208
Allowance for funds used
during construction (92,428) (37,268) (47,337)
Total interest charges 2,716,553 2,464,575 2,680,539
Net income 3,199,092 3,321,795 901,344
Annual redeemable
preferred dividend requirements (19,314) (20,084) (20,854)
Income available for
common stock $3,179,778 $ 3,301,711 $ 2,880,490
========== =========== ===========
Shares of common stock outstanding
(weighted average) 1,591,372 1,558,574 1,475,313
Earnings per common share $ 2.00 $ 2.12 $ 1.95
Cash dividends declared
per common share $ 1.55 $ 1.51 $ 1.47
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Fiscal Years Ended August 31,
1995 1994 1993
Balance at beginning of year $11,857,299 $10,903,703 $10,198,858
Net income 3,199,092 3,321,795 2,901,344
Total 15,056,391 14,225,498 13,100,202
Cash dividends declared:
Redeemable preferred stock 19,314 20,084 20,854
Common stock 2,460,382 2,348,115 2,175,645
Total 2,479,696 2,368,199 2,196,499
Balance at end of year $12,576,695 $11,857,299 $10,903,703
=========== =========== ===========
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, August 31,
1995 1994
Utility plant, at cost $ 91,462,732 $ 85,564,414
Less: Accumulated depreciation 20,304,386 18,519,429
Net utility plant 71,158,346 67,044,985
Other property and investments 570,620 499,439
Capitalized lease (net of accumulated
amortization of$423,806 in 1995 and
$381,858 in 1994) 699,991 741,939
Current assets:
Cash and cash equivalents 136,925 130,939
Accounts receivable:
Customers (net of allowance for
uncollectible accounts of $595,000
in 1995 and $804,000 in 1994) 1,418,510 1,629,383
Other 280,889 407,523
Income tax refunds receivable 200,000 688,000
Supplemental fuel inventory 6,477,155 6,783,404
Materials and supplies (at average cost) 594,817 583,422
Prepaid deferred income taxes 1,397,422 816,445
Prepayments and other 350,660 316,738
Total current assets 10,856,378 11,355,854
Deferred charges:
Unamortized debt expense and other 1,028,319 1,231,689
Regulatory assets 2,267,954 2,636,658
Total deferred charges 3,296,273 3,868,347
$ 86,581,608 $ 83,510,564
============ ==========
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
August 31, August 31,
1995 1994
Common stock equity $30,709,276 $28,870,444
Redeemable preferred stock 336,000 350,000
Long-term debt, less current portion 20,689,366 21,713,124
Total capitalization 51,734,642 50,933,568
Noncurrent obligations under capital lease 654,390 699,991
Current liabilities:
Current portion of long-term debt 978,758 1,035,304
Current obligation under capital lease 45,599 41,948
Obligations under supplemental fuel
inventory trust 5,131,153 6,428,770
Notes payable, banks 4,890,000 4,500,000
Accounts payable 2,986,307 2,930,578
Accrued interest 825,322 625,784
Refundable gas costs 2,490,178 770,184
Accrued transition costs 858,715 1,018,531
Supplier refund due customers 2,454,739 1,661,812
Other 850,404 852,259
Total current liabilities 21,511,175 19,865,170
Commitments and contingencies
Deferred credits:
Accumulated deferred income taxes 9,092,349 8,452,562
Unamortized investment tax credit 1,280,680 1,350,779
Deferred directors' fees 879,009 777,871
Other 1,429,363 1,430,623
Total deferred credits 12,681,401 12,011,835
$86,581,608 $83,510,564
=========== ===========
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Fiscal Years Ended August 31,
1995 1994 1993
Operating activities:
Net income $ 3,199,092 $ 3,321,795 $ 2,901,344
Adjustments to reconcile net
income to net cash:
Depreciation, including amounts
related to non-utility operations 2,920,476 2,754,465 2,589,867
Provisions for uncollectible
accounts (208,797) 761,385 741,431
Deferred income taxes 40,876 1,006,618 706,519
Amortization 8,390 7,305 96,032
Noncash compensation associated
with ESOP 225,000 150,000 150,000
Cash (used in) provided by working capital:
Decrease (increase) in
accounts receivable 546,304 (912,662) (430,151)
Decrease (increase) in inventories
including fuel 294,854 (462,827) 777,064
Decrease (increase) in prepayments
and other (33,922) 185,674 58,740
Increase in accounts payable 55,729 104,406 167,653
Increase in supplier refund
obligations 792,927 1,661,812 -
(Increase) decrease in taxes
payable/receivable 488,000 (374,323) (313,677)
(Decrease) increase in recoverable
(refundable) gas costs 1,719,994 (154,584) (84,886)
Other, net 658,391 (837,888) 273,654
Total adjustments 7,508,222 3,889,381 4,732,246
Net cash provided by operating
activities 10,707,314 7,211,176 7,633,590
Investing activities:
Utility capital expenditures (6,967,340) (6,131,471) (6,671,526)
Payments for retirements of property,
plant and equipment, net (66,497) (183,999) (78,401)
Net cash used in investing
activities (7,033,837) (6,315,470) (6,749,927)
Financing activities:
Dividends paid (2,479,696) (2,368,199) (2,196,499)
Issuance of common stock 814,126 730,874 5,106,677
Issuance of long-term debt - - 4,661,445
Retirements of preferred stock (14,000) (14,000) (14,000)
Principal retired on long-term debt (855,304) (193,340) (4,219,742)
(Decrease) increase in supplemental
fuel inventory trust (1,297,617) 862,068 (1,278,003)
(Decrease) increase in notes
payable, banks 390,000 300,000 (3,250,000)
Payment of ESOP debt (225,000) (150,000) (150,000)
Net cash used in financing
activities (3,667,491) (832,597) (1,340,122)
Net (decrease) increase in cash
and cash equivalents 5,986 63,109 (456,459)
Cash and cash equivalents at
beginning of year 130,939 67,830 524,289
Cash and cash equivalents at
end of year $ 136,925 $ 130,939 $ 67,830
=========== =========== =============
Supplemental disclosures:
Cash paid during the year for:
Interest (net of amount
capitalized) $ 2,517,015 $ 2,449,138 $ 2,650,475
============ =========== ============
Income taxes $ 1,743,197 $ 1,196,360 $ 1,305,394
============ ============ ============
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
August 31, August 31,
1995 1994
Common stock equity:
Common stock, $2.50 par value,
5,000,000 authorized shares
Issued and outstanding,
1,607,061 at August 31, 1995
and 1,572,062 at August 31, 1994 $ 4,017,653 $ 3,930,155
Additional paid-in capital 14,311,026 13,532,990
Unrealized gain on investments
available for sale, net 28,902 -
Retained earnings 12,576,695 11,857,299
30,934,276 29,320,444
Less: Shares held by ESOP purchased
with debt 225,000 450,000
Total common stock equity 30,709,276 28,870,444
Redeemable preferred stock:
5.50% series, $100 par value, 7,000 authorized shares
Outstanding, 3,360 at August 31, 1995
and 3,500 at August 31, 1994 336,000 350,000
Long-term debt:
First Mortgage Bonds:
10 1/4%, due serially from 1994 to 2003 5,400,000 6,000,000
10.10%, due serially from 2010 to 2020 8,000,000 8,000,000
13,400,000 14,000,000
Mortgage Note:
8 1/2%, due serially from 1976 to 1997 838,124 1,048,428
Debentures:
8 5/8%, due 2006 2,245,000 2,250,000
8.15%, due 2017 4,960,000 5,000,000
7,205,000 7,250,000
ESOP Loan Guarantee:
7.0% due serially from 1987 to 1996 225,000 450,000
Total debt 21,668,124 22,748,428
Less: Current portion maturing and payable 978,758 1,035,304
Total long-term debt 20,689,366 21,713,124
Total capitalization $ 51,734,642 $ 50,933,568
============= ============
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
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, 1995, principal regulatory assets include
(1) approximately $860,000 for transition costs associated with FERC
Order 636, (2) $520,000 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 $794,000 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 established 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 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 1995, 1994, and 1993. 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.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
B. Supplemental Fuel Inventory Trust
The Company, with MDPU approval, finances its supplemental gas inventory
through a single purpose trust which purchases gas with funds loaned to
the trust by a bank. As required, the Company repurchases gas from the
trust at prices based on original product cost, financing and trust fees.
The credit agreement between the trust and the bank provides for a total
commitment of up to $7,000,000. Financing and trust fees resulted in an
effective interest cost to the Company of 5.9% for 1995 and 4.6% in 1994
based on average borrowing. Upon termination of the plan by either party,
the Company is obligated to reimburse the trust in an amount equal to the
investment in the trust not previously reimbursed plus any other
obligations incurred by the trust. The Company has 240 days (60 days in
the event of default) to reimburse the trust upon termination.
C. Common Stock
Common stock activity for the three-year period ended August 31, 1995,
is as follows:
Additional
Number of Common Paid-in
Shares Stock Capital
Balance, August 31, 1992 1,317,805 $3,294,513 $ 8,238,964
Dividend reinvestment plan 15,042 37,605 321,702
Amortization of capital
stock expense --- --- 40,709
Various employee stock plans 7,564 18,910 165,627
Sale of common stock 203,634 509,085 4,053,748
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
Various 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
Various 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
========== ========== ===========
D. Redeemable Preferred Stock and Restriction on Retained
Earnings
The preferred stock is currently redeemable, in whole or in part, at
the option of the Company, by a payment to the holder of $100 per share
plus accrued dividends in the event of involuntary liquidation. This
payment requirement increases fifty cents per share plus accrued dividends
in the event of voluntary liquidation.
A purchase agreement provides that the Company will annually offer to
purchase and retire up to, but not in excess of, 140 shares of redeemable
preferred stock at $100 per share plus accrued dividends. Payment of
dividends on, or acquisition of, common stock is prohibited if the Company
fails to cumulatively offer to purchase 280 shares of preferred stock.
Required offers were made, and the Company redeemed, 140 shares during
each of the three fiscal years ending August 31, 1995.
Dividends on redeemable preferred stock are at a stated rate of 5.50%
cumulative, payable quarterly January 1, April 1, July 1 and October 1.
Under the terms of the indenture securing the First Mortgage Bonds,
retained earnings in the amount of $5,192,475 as of August 31, 1995,
were unrestricted as to the payment of cash dividends on common stock and
the purchase, redemption or retirement of shares of capital stock.
E. Interim Financing and Long-term Debt
The Company periodically borrows from banks on an unsecured, short-term
basis. At August 31, 1995, the Company had $4,890,000 of outstanding
notes payable with a weighted average interest rate of 6.4% under
available lines of credit totaling $16,500,000. 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 liquified 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 $978,758 in 1996,
$923,830 in 1997, $960,536 in 1998, $600,000 in 1999, $600,000 in 2000 and
$17,605,000 thereafter.
F. Income Taxes
The components of the provision for income taxes are as follows:
1995 1994 1993
Federal
Current $1,469,957 $ 796,930 $1,054,220
Deferred 2,000 791,000 330,000
Amortization of investment
tax credit (70,099) (70,800) (72,764)
1,401,858 1,517,130 1,311,456
State
Current 292,615 173,459 213,603
Deferred 445 162,000 67,000
293,060 335,459 280,603
Total income taxes $1,694,918 $1,852,589 $1,592,059
========== =========== ===========
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:
1995 1994 1993
Federal statutory rate 34.0% 34.0% 34.0%
====== ====== ======
Federal income tax
expense at statutory rates $1,663,963 $1,759,260 $1,527,756
Increase (decrease) in taxes resulting
from:
Amortization of investment
tax credit (70,099) (70,800) (72,764)
State taxes, net of
federal benefit 199,980 221,403 185,596
Other (98,926) (57,274) (48,529)
Total income tax expense $1,694,918 $1,852,589 $1,592,059
=========== =========== ===========
Effective income
tax rate 34.6% 35.8% 35.4%
====== ====== ======
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 recovery of deficiencies in deferred
taxes as a result of the net effect of establishing some deferred taxes
for temporary differences using the flow-through method. Recovery of this
amount will be addressed in the Company's next rate filing with the MDPU.
A regulatory liability of $794,000 was established for the tax benefit of
unamortized investment tax credits, which SFAS 109 requires to be
treated as a temporary difference. This benefit will be passed on to
customers over the lives of property giving rise to the investment credits.
Significant items making up deferred tax assets and deferred tax
liabilities at August 31, 1995 and 1994 are as follows:
1995 1994
Liabilities
Utility Plant-primarily depreciation $ 9,957,069 $ 9,237,890
Other 332,912 425,099
10,289,981 9,662,989
Assets
Investment tax credits 794,403 827,152
Other 1,800,651 1,199,720
2,595,054 2,026,872
Accumulated deferred income taxes, net $ 7,694,927 $ 7,636,117
=========== ===========
The net year-end deferred income tax liabilities above are net of current
deferred tax assets of $1,397,422 and $816,445, respectively, which
is included in prepaid income taxes in the accompanying Consolidated
Balance Sheets.
Deferred federal income tax expense results from differences in the
timing of recognition of certain items for tax and financial statement
purposes. The components of the deferred income tax provision are as
follows:
1995 1994 1993
Excess tax depreciation
over book depreciation $ 593,030 $575,050 $459,099
Uncollectible accounts 70,990 (48,535) (52,768)
Rate case expenses (40,939) (48,813) 56,145
Gas adjustment factor (584,798) 52,558 28,862
Other deferred charges
and credits (63,865) 282,763 (52,817)
Unbilled revenues 33,890 (25,033) 26,798
Deferred state taxes - (55,080) (22,780)
Medical insurance reserves 4,925 - (62,458)
Other (11,233) 58,090 (50,081)
Deferred federal
income taxes $ 2,000 $791,000 $330,000
========== ========= =========
The tax effect of the cumulative amount of timing differences at
August 31, 1995 for which deferred federal income taxes have not been
provided is not significant.
G. Leases
The Company is obligated under various lease agreements for certain
facilities and equipment used in operations. Total expenditures under
operating leases for each period were $289,721 in 1995, $309,992 in
1994, and $287,736 in 1993. A summary of property classified as
capital leases as of August 31, 1995 and 1994 is as follows:
1995 1994
Buildings $1,123,797 $1,123,797
Less: Accumulated depreciation 423,806 381,858
$ 699,991 $ 741,939
========== ==========
In accordance with the rate treatment allowed by the MDPU, the
depreciation expense of $41,948, $38,540 and $35,500, along with
interest of $60,502, $63,910 and $67,000 related to the capital lease,
is included in other operating expenses for the years ended August 31,
1995 and 1994 and 1993, respectively.
The Company also has various operating lease agreements for equipment,
vehicles and office space. The remaining minimum annual rental
commitment for these and all other non-cancellable leases is as follows:
Capital Leases Operating Leases
1996 $102,500 $297,599
1997 102,500 254,357
1998 102,500 184,384
1999 102,500 26,644
2000 102,500 3,387
Thereafter 529,584 3,543
1,042,084
Total minimum lease payments $769,914
========
Less: Amount representing
interest 342,093
$699,991
========
H. Employee Benefits
Pension Plans
The Company has two principal pension plans covering substantially all
employees. The actuarial method for determining annual pension cost is
the Projected Unit Credit method.
Net pension cost for 1995, 1994 and 1993 consist of the following components:
1995 1994 1993
Service cost -- benefits
earned during the year $231,741 $212,190 $ 175,000
Interest cost on projected
benefit obligations 668,107 617,749 568,000
Actual return on plan assets (887,022) (74,969) (933,000)
Net amortization and deferral 412,504 (444,131) 476,000
Net pension cost $425,330 $310,839 $286,000
========= ========= =========
The expected long-term rate of return on assets was 8.5% in 1995
and 1994, the discount rate used in determining the actuarial present
value of the projected obligation was 8.0% in 1995 and 1994 and the
expected rate of pay increase was 6.0% in 1995 and 1994.
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, 1995 and 1994:
1995 1994
Actuarial present value of benefit
obligations (in thousands)
Vested benefit obligation $ 7,960 $ 7,476
======== ========
Accumulated benefit obligation $ 8,433 $ 7,884
======== ========
Projected benefit obligation
for service rendered to date $ 9,329 $ 8,634
Plan assets, primarily listed stocks,
corporate bonds and U.S. bonds,
at fair value 8,034 7,467
Projected benefit obligation in excess
of plan assets (1,295) (1,167)
Unrecognized net gain (321) (437)
Unrecognized prior service cost 1,537 1,633
Adjustment required to recognize
additional minimum liability (330) (465)
Unrecognized net obligation at transition 10 20
Net pension liability $ 399 $ 416
======== ========
Assets in the pension plan are currently held in listed stocks,
corporate bonds and government bonds.
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 is payable in 10 equal
annual installments of $150,000 through 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 1995 was $141,359, for 1994 was $223,349, and for 1993
was $152,949. Interest on ESOP debt was $17,365 for 1995, $37,023 for
1994, and $51,758 for 1993. Dividends on unallocated ESOP shares used
to pay debt service for all periods presented was $27,193 for 1995,
$41,352 for 1994, and $52,439 for 1993.
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 $118,939 to the plan in 1995,
$108,000 to the plan in 1994, and $63,500 in 1993.
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 cost of retiree medical and life insurance
benefits under the traditional pay-as-you-go basis was $223,000 for 1993.
The Company is currently recovering the full SFAS 106 cost in rates.
The net periodic postretirement benefit cost for the year ended
August 31, 1995 and 1994 were as follows:
1995 1994
Service cost $ 84,550 $110,691
Interest cost 284,861 296,310
Loss on plan assets 13,066 -
Net amortization and deferral 157,634 203,868
Total postretirement benefit cost $540,111 $610,869
======== =========
The funded status of the Company's postretirement benefit plan using
a measurement date of July 1, 1995 and 1994, is as follows:
1995 1994
Accumulated postretirement
benefit obligation:
Retirees $(2,972,713) $(2,714,112)
Fully eligible active
Plan participants (118,200) (168,942)
Other active Plan participants (1,264,135) (1,183,982)
(4,355,048) (4,067,036)
Plan assets at fair value 557,939 229,781
Accumulated postretirement obligation
greater than Plan assets (3,797,109) (3,837,255)
Unrecognized transition obligation 3,669,616 3,873,484
Unrecognized (gain) loss (3,021) (141,261)
Accrued postretirement
benefit cost $ (130,514) $ (105,032)
============ ===========
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.5% in 1995 and 1994.
The annual increase in the cost of covered health care benefits for
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 assumed
health care cost trend would have increased the cost computed under
SFAS 106 by $27,444 and increased the accumulated postretirement
benefit by $309,465 as of August 31, 1995.
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 trusts
and the subaccount during 1995 and 1994 totaling $514,629 and
$506,000, respectively. Assets in the VEBA trusts are held in cash
reserve accounts. Assets in the subaccount to the pension plan are
currently held in listed stocks, corporate bonds and government bonds.
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. 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 fiscal 1995.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock Based
Compensation" ("SFAS 123"). The Company will be required to adopt this
standard effective September 1, 1996. SFAS 123 establishes a fair value
based method of accounting for stock based compensation plans. SFAS 123
allows companies to either measure compensation using the fair value
method or to continue to apply the provisions of APB Opinion No. 23,
"Accounting for Stock Issued to Employees" and include footnote
disclosure of pro forma net income and earnings per share calculated as if
the fair value method had been applied. The Company expects to adopt the
latter method and concludes that the adoption of this standard will not
have a material impact on the results of operations or its financial
condition.
I. Commitments and Contingencies
Construction Expenditures
The Company's construction expenditures in connection with its continuing
construction program are presently estimated at $7,000,000 for 1996
and approximately $6,000,000 in each of the four following years.
Gas Supply, Transportation and Storage
The Company has various long-term gas supply, transportation and storage
contracts with minimum cost provisions. Under these contracts, the
Company is obligated to make specified minimum payments. Based on current
rates and/or agreements, the minimum annual payments under these contracts
are as follows:
1996 to 2000
Pipeline Transportation Demand $5,182,643
Underground Storage Demand 979,608
Underground Storage Transportation 1,004,011
Pipeline Gas Inventory Charge 1,662,951
GSR Charges 858,715
$9,687,928
===========
FERC Order 636 also 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, 1995,
the transition costs are estimated at $860,000 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
cost-of-gas adjustment clause.
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. Each of these facilities has been out of operation for
more than 25 years. 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 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
will be conducted in 1996 to determine the level of contamination and to
assess whether any remediation is required. 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 SCGA 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 MDPU agreement also
provides for no further investigation of the prudency of any Massachusetts
gas utility's past MGP operations.
Subsequent Events
On September 15, 1995 the MDPU approved the Company's petition to change
the par value of the Company's common stock from $2.50 par value to no par
value. The change was effective October 5, 1995.
The Company has petitioned the MDPU for a new supplemental fuel agreement
replacing the one that expired October 31, 1995. Financing from the
expiration of the original arrangement to approval from the MDPU has been
accomplished by a $7,000,000 floating rate bridge loan which expires
December 31, 1995. The Company expects MDPU approval for the supplemental
fuel agreement in December 1995.
Item 9: Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
PART III
Item 10: Directors and Executive Officers of the Registrant
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 16, 1996.
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 16, 1996.
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 5, 1995, for the Annual Meeting of Stockholders to be held on
January 16, 1996.
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 5, 1995, for
the Annual Meeting of Stockholders to be held on January 16, 1996.
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 , 1995
by
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 11/28/95
/s/ Philip H. Reardon President and Chief 11/28/95
Executive Officer
/s/ James H. Hastings Vice President and 11/28/95
Treasurer (Principal
Financial and Accounting
Officer)
/s/ Benjamin C. Bixby Director 11/28/95
/s/ Daniel A. Burkhard Director 11/28/95
/s/ Edward J. Curtis Director 11/28/95
/s/ Dorothy J. Dotson Director 11/28/95
/s/ Richard P. Hamel Director 11/28/95
/s/ Robert S. Jackson Director 11/28/95
/s/ Eric H. Jostrom Director 11/28/95
/s/ Robert L. Meade Director 11/28/95
/s/ Kenneth L. Paul Director 11/28/95
/s/ Richard L. Wellman Director 11/28/95
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
20 through 36, and the Report of Arthur Andersen LLP on page 19
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.4
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 Com-
pany and Centerre Trust Company of St. Louis, Trustee.2
Exhibit
Number Description
4.3 Eleventh Supplemental Indenture dated as of Septem-
ber 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
10.1 LNG Storage, Inc., Lease Indenture of Mortgage
and Deed of Trust dated April 10, 1972.1
10.2 Haverhill Familee Investment Corporation - Lease
of Corporate Headquarters dated November 1,
1975.1
10.3 Arlington Trust Company - Purchase Contract,
Credit Agreement, Trust Agreement and Storage
Agreement dated October 1, 1980.1
10.4 Consolidated Gas Supply Corporation - Underground
Storage Contract dated February 18, 1980.1
10.5 Penn-York Energy Corporation - Storage Services
Agreement dated December 21, 1984.1
10.6 Canadian Gas Transportation Contract between
Tennessee Gas Pipeline Company and Essex County
Gas Company dated December 1, 1987.3
10.7 Phase 2 Gas Sales Agreement between Boundary Gas
and Essex County Gas Company dated September 14,
1987.3
10.8 Amendment to the Agreement for the Sale of Gas
between Bay State Gas Company and Essex County Gas
Company dated May 6, 1988.3
10.9 Agreement for the Liquefaction of Gas between Bay
State Gas Company and Essex County Gas Company
dated March 14, 1988.3
10.10 Bond Purchase Agreement dated December 1, 1990, 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
Exhibit
Number Description
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 Con-
tract (SS-NE) TGP002099STO dated November 10,
1991.6
10.17 Tennessee Gas Pipeline Company Storage Service
Transportation Contract TF-4175 dated October
28, 1991.6
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 sub-
mitted 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
Exhibit
Number Description
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.*
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.*
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.
1 Previously filed as an exhibit to Registrant's Registration
Statement on Form S-7, filed October 23, 1981, File No. 2-74531 and
is incorporated herein by this reference.
2 Previously filed as an exhibit to Registrant's Registration
Statement on Form S-2, filed June 19, 1986, File No. 33-6597
and is incorporated herein by this reference.
3 Previously filed as an exhibit to Registrant's 10-K filed for
the fiscal year ended August 31, 1988, and is incorporated herein by
this reference.
4 Previously filed as an exhibit to Registrant's 10-Q filed for
the quarter ended February 28, 1991, and is incorporated herein by
this reference.
5 Previously filed as an exhibit to Registrant's 10-Q filed for
the quarter ended May 31, 1992, and is incorporated herein
by this reference.
6 Previously filed as an exhibit to Registrant's 10-K filed for
the fiscal year ended August 31, 1992, and is incorporated herein
by this reference.
7 Previously filed as an exhibit to Registrant's Form S-3, No.
33-69736, filed on September 30, 1993, and is incorporated herein by
this reference.
8 Previously filed as an exhibit to Registrant's Form 10-K filed
for the fiscal year ended August 31, 1993, and is incorporated herein
by this reference.
[CIK] 0000046189
[NAME] ESSEX COUNTY GAS COMPANY
[MULTIPLIER] 1,000
<PERIOD TYPE> 12-MOS
<FISCAL YEAR END> AUG-31-1995
<PERIOD END> AUG-31-1995
<BOOK VALUE> PER-BOOK
[TOTAL-NET-UTILITY-PLANT] 71,158
[OTHER-PROPERTY-AND-INVEST] 524
[TOTAL-CURRENT-ASSETS] 10,856
<TOTAL-DEFERRED-ASSETS> 3,296
[OTHER-ASSETS] 700
[TOTAL-ASSETS] 86,535
[COMMON] 4,018
[CAPITAL-SURPLUS-PAID-IN] 14,086
[RETAINED-EARNINGS] 12,577
[TOTAL-COMMON-STOCKHOLDERS-EQ] 30,680
[PREFERRED-MANDATORY] 336
[PREFERRED] 0
[LONG-TERM-DEBT-NET] 20,689
[SHORT-TERM-NOTES] 4,890
[LONG-TERM-NOTES-PAYABLE] 0
[COMMERCIAL-PAPER-OBLIGATIONS] 0
<LONG-TERM-DEBT-CURR-PORTION> 979
[LEASES-CURRENT] 46
[OTHER-ITEMS-CAPITAL-AND-LIAB] 28,915
<TOTAL-CAPITALIZATION-AND-LIAB> 86,535
[GROSS-OPERATING-REVENUE] 45,050
[INCOME-TAX-EXPENSE] 1,402
[OTHER-OPERATING-EXPENSES] 37,738
[TOTAL-OPERATING-EXPENSES] 39,140
[OPERATING-INCOME-LOSS] 5,910
[OTHER-INCOME-NET] 6
[INCOME-BEFORE-INTEREST-EXPEN] 5,916
[TOTAL-INTEREST-EXPENSE] 2,717
[NET-INCOME] 3,199
<PREFERRED-STOCK-DIVIDEND> 19
[EARNINGS-AVAILABLE-FOR-COMM] 3,180
[COMMON-STOCK-DIVIDENDS] 2,460
[TOTAL-INTEREST-ON-BONDS] 2,049
[CASH-FLOW-OPERATIONS] 10,707
[EPS-PRIMARY] 2.00
[EPS-DILUTED] 2.00