1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
________________________
Form 10-K
(Mark One)
/X/ Annual report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934.
For the fiscal year ended August 31, 1997.
/ / 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: (978) 388-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of Class Exchange
Common Stock, No Par Value NASDAQ/NMS
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes / X / No / /
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of the registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. / /
The aggregate market value of the voting stock held by
non-affiliates on October 31, 1997 based upon the last sales
price on that date was approximately $52,483,062.
The number of shares outstanding of Registrant's Common
Stock, no par value, was 1,693,002 at October 31, 1997.
2
DOCUMENTS INCORPORATED BY REFERENCE: Part III hereof
incorporates by reference portions of the definitive Proxy
Statement dated December 1, 1997, for the Annual Meeting of
Stockholders to be held January 20, 1998. Part IV hereof
incorporates by reference certain of the Exhibits to the
following documents: Registration Statement No. 2-74531 on Form
S-7, filed October 23, 1981, Registration Statement No. 33-6597
on Form S-2 filed on June 19, 1986, Registration Statement No.
33-69736 on Form S-3, filed on September 30, 1993, Registrant's
Annual Report on Form 10-K for fiscal 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, Registrant's Quarterly Report on
Form 10-Q for the Quarter ended November 30, 1995, Registrant's
Quarterly Report on Form 10-Q for the Quarter ended February 29,
1996, Registrant's Quarterly Report on Form 10-Q for the Quarter
ended May 31, 1996, Registrant's Quarterly Report on Form 10-Q
for the quarter ended February 28, 1997 and Registrant's
Quarterly Report on Form 10-Q for the quarter ended May 31, 1997.
3
ESSEX COUNTY GAS COMPANY
FORM 10-K
Annual Report
Year Ended August 31, 1997
---------------------------
Table of Contents
Item No. Topic Page
PART I
1. Business 4
2. Properties 11
3. Legal Proceedings 12
4. Submission of Matters to a Vote of Security Holders 12
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters 13
6. Selected Financial Data 13
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 14
8. Financial Statements and Supplementary Data 23
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 41
PART III
10. Directors and Executive Officers of the Registrant 41
11. Executive Compensation 41
12. Security Ownership of Certain Beneficial Owners and
Management 41
13. Certain Relationships and Related Transactions 41
PART IV
14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K 41
Signatures 43
4
PART I
Item 1: Business
General
The Company, a regulated public utility organized under the
laws of the Commonwealth of Massachusetts in 1853, purchases,
distributes and sells natural gas to residential, commercial and
light industrial customers in northeastern Massachusetts. The
Company operates in the cities of Haverhill, Newburyport, and
Amesbury and fourteen 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 the last
few years there has been a significant increase in new
residential construction. New home construction activity
significantly impacts the degree to which the Company is able to
grow its customer base.
Sales and Customer Data
The Company sells natural gas to approximately 42,000
customers in its service area. Residential users of natural gas
generally experience their highest level of consumption for
heating purposes during the winter months. Accordingly, the
Company's sales and operating revenues are sensitive to the
severity of the weather. The Company's rates are designed to
recover added costs associated with peak operations during the
winter months. In fiscal 1997, the Company's total operating
revenues were $53,534,734 of which approximately 64.6 percent was
derived from residential customers, 30.1 percent from commercial
and industrial customers, 3.5 percent from interruptible
customers and 1.8 percent from other sources. During this
period, the Company sold 6,500,009 Dekatherms ("Dth"), of which
approximately 56.7 percent was purchased by residential
customers, 31.7 percent by commercial and industrial customers
and 11.6 percent by interruptible customers. Losses and company
use amounted to 136,156 Dth for fiscal 1997.
Set forth in the following table is information by customer
classification showing operating revenues, gas delivered and
number of customers for the periods indicated.
5
Fiscal Year Ended August 31,
1997 1996 1995 1994 1993
(Dollars and Dths in Thousands)
Operating Revenues:
Residential-general $ 1,907 $ 2,208 $ 2,159 $ 2,291 $ 2,160
Residential-heating 32,681 29,644 26,589 29,245 27,218
Commercial and Industrial 16,129 14,838 13,353 15,000 14,006
Interruptible 1,888 2,216 1,933 888 653
Other 930 1,023 1,016 1,112 979
------- ------- ------- ------- -------
Total $53,535 $49,929 $45,050 $48,536 $45,016
======= ======= ======= ======= =======
Gas Delivered (Dth):
Residential-general 152 153 150 161 160
Residential-heating 3,528 3,545 3,100 3,367 3,268
Commercial and Industrial 2,062 2,068 1,874 2,039 1,972
----- ----- ----- ----- -----
Total Firm 5,742 5,766 5,124 5,567 5,400
Interruptible 758 893 926 393 275
----- ----- ----- ----- -----
Total Sales 6,500 6,659 6,050 5,960 5,675
Losses and Company Use 136 187 90 81 92
----- ----- ----- ----- -----
Total 6,636 6,846 6,140 6,041 5,767
===== ===== ===== ===== =====
Number of Customers at year-end:
Residential-general 7,464 7,328 7,369 7,560 7,439
Residential-heating 30,639 30,025 29,028 28,093 27,434
Commercial and Industrial 4,243 4,173 4,125 3,961 3,884
Interruptible 2 2 2 2 2
------ ------ ------ ------ ------
Total 42,348 41,528 40,524 39,616 38,759
Effective Degree Days ====== ====== ====== ====== ======
(20-Year Average: 6,787) 6,656 6,947 6,258 7,012 6,956
The Company's residential customers are classified as either
general or heating customers. Residential general customers are
those who do not use natural gas for space heating. In fiscal
1997, residential-heating customers accounted for approximately
61.0 percent of total operating revenues, while
residential-general customers accounted for approximately 3.6
percent of total operating revenues. Operating revenues from
residential customers increased approximately 8.6 percent to
$34,588,306 in fiscal 1997 from $31,852,683 in fiscal 1996. The
increase in revenues was attributable to the higher prices in
fiscal 1997 compared to fiscal 1996 as residential volumes
decreased 0.5 percent. The average rate charged to residential
customers per Dth of gas was $9.40 and $8.61 in fiscal 1997 and
1996, respectively. The increase in fiscal 1997 was primarily
due to a Massachusetts Department of Public Utilities ("MDPU")
approved rate increase effective December 1, 1996 and higher gas
costs incurred by the Company. The lower price in 1996 was
primarily due to the return to customers of pipeline supplier
refund and previously overcollected gas costs.
6
The Company's commercial and industrial firm revenues
increased approximately 8.7 percent to $16,128,685 in fiscal 1997
from $14,837,612 in fiscal 1996. The increase was attributable
to a 8.9 percent increase in the average price charged per Dth of
gas from $7.18 in 1996 to $7.82 in 1997 offset by a 0.3 percent
volume decrease. The volume decrease was largely attributable to
warmer weather experienced during the winter in fiscal 1997 as
compared to fiscal 1996.
The Company has two interruptible customers, only one of
which purchased significant amounts of gas from the Company in
fiscal 1997. Total interruptible revenues in fiscal 1997 were
$1,888,416 compared to $2,215,677 in fiscal 1996. Sales of gas
to interruptible customers do not materially affect the Company's
operating income because the Company is required to return all
gross profit on such sales to the Company's firm customers unless
interruptible volumes exceed a certain threshold specified by the
MDPU. Once that threshold is attained, the Company may retain 25
percent of incremental gross profits. The threshold was not
attained in fiscal 1997. Any gross profit returned to the
customers is returned through a Cost of Gas Adjustment ("CGA")
under which the Company is permitted to recover its gas costs.
The average price charged by the Company to interruptible
customers was $2.49 per Dth and $2.48 per Dth in 1997 and 1996,
respectively.
The Company's largest customer purchases gas on an
interruptible basis and accounted for approximately 3.9 percent
of operating revenues on average over the past three fiscal years
ended August 31, 1997. Sales to that customer in 1997 totaled
$1,845,369 or 3.5 percent of total Company operating revenues.
Since, as discussed above, most of the gross profit earned on
interruptible sales is returned to firm customers, the Company
believes that the loss of its largest or any other 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 1.4 percent of the total operating
revenues of the Company over the past three years ended August
31, 1997.
During 1997, the Company added gross 1,119 new customers.
In fiscal 1996 and 1995, gross new customer additions were 1,120
and 1,168, respectively.
Gas Supply
The Company contracts for its gas supply on the basis of
forecasted demand which is derived from historical weather
patterns recorded since 1960. The maximum peak-day demand during
the last five fiscal years was 47,483 Dth on January 18, 1997.
The Company has the ability to meet a single-day demand of
approximately 66,000 Dth. Peak-day demand for gas is affected by
numerous factors, including the severity of the weather and the
number of firm customers. Total gas sendout by the Company in
fiscal 1997 was 6,636,165 Dth compared to 6,845,964 Dth in fiscal
1996 and 6,139,559 Dth in fiscal 1995.
The following table shows the sources of the Company's gas
supply requirements for the periods indicated.
7
Fiscal Years Ended August 31,
(in thousands)
1997 1996 1995 1994 1993
Gas Supply (Dth):
Natural gas delivered directly
by pipeline 5,376 5,307 4,923 4,837 4,273
Underground storage withdrawn 1,007 1,062 837 833 1,290
Liquefied natural gas produced 253 477 380 371 204
----- ----- ----- ----- -----
Total 6,636 6,846 6,140 6,041 5,767
===== ===== ===== ===== =====
For the year ended August 31, 1997, approximately 85.0
percent 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 Dth through November
1, 2000. TGPC is currently delivering such quantities on a firm
basis as authorized by the Federal Energy Regulatory Commission
("FERC"). In connection with the implementation of FERC Order
636, the Company has converted its natural gas purchase contract
with TGPC into several firm gas supply contracts directly with
other gas suppliers. These long-term contracts have been
approved by the MDPU. All contracts are with major suppliers
that have a demonstrated track record of performance and are at
market sensitive prices. In addition to contracts with Aquila
Energy and Natural Gas Clearinghouse for 2,500 Dth expiring
November 1, 2002, 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 Dth per day from Boundary and may purchase up to
587,650 Dth per year, the annual quantity limitation for the
contract. The Company began in January 1988 taking up to
a maximum of 1,610 Dth per day. Pursuant to a supply contract
with Boundary, the Company is required to purchase 75 percent
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 578,026 Dth
in fiscal 1997 or 98.4 percent 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 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 730,000 Dth per year, the annual quantity limitation for the
contract. The contract requires the Company to purchase at least
60 percent 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 660,768 Dth in fiscal 1997 or 90.5
percent of the contracted amount in fiscal year 1997. The
8
Company has firm transportation contracts with the Iroquois
Pipeline and TGPC for the delivery of the above-mentioned
volumes.
The Company has two contracts for underground storage with a
total storage capacity of approximately 1,140,378 Dth. The
Company used a total of 1,005,957 Dth of its total underground
storage in fiscal 1997.
Under a contract expiring November 1, 2000, the Company
assumed its pro rata share of TGPC underground storage. The
Company received storage capacity of 780,928 Dth and 5,172 Dth
per day of deliverability, as well as the ability to fill the
storage with gas obtained from any supplier. This service
augments the Company's ability to meet high delivery demand in
the winter and to take advantage of lower off-season gas prices.
The Company also has a contract expiring April 1, 2000 with
Consolidated Supply Corporation for underground storage for a
total volume of 359,450 Dth. The contract is backed by a
transportation contract with TGPC for the same period, which
provides for the withdrawal from storage and delivery to the
Company of up to 4,000 Dth per day on a firm basis.
The Company has entered into an agreement with Distrigas of
Massachusetts Corporation ("DOMAC"), which expires on October 31,
2006, that allows the Company to purchase up to 4,000 Dth per day
for 151 days of Liquefied Natural Gas as either a liquid or a
vapor. The Company, at its discretion, may increase purchases
under the contract by up to an additional 2,000 Dth per day after
appropriate notice. The Company may also reduce quantities
purchased if normal sales dip below the normal 1994-95 heating
season sendout.
These underground storage arrangements allow the Company to
maximize firm gas supply purchases while allowing the Company to
take full advantage of the spot market gas prices during the
summer and other periods when such gas is not required to meet
customer demands. The stored gas is withdrawn during periods of
high demand to assist the Company in meeting firm delivery
requirements.
Through a wholly-owned subsidiary, the Company owns a
liquefied natural gas ("LNG") storage facility located in
Haverhill, Massachusetts. The LNG storage facility has a storage
capacity of 410,000 Dth and has a daily sendout capacity of
30,000 Dth. In fiscal 1997, sendout of LNG totaled 325,026 Dth.
At the same location, the Company owns and operates a propane
plant that has a storage capacity equivalent of approximately
500,000 gallons with a total daily sendout capacity of 3,500 Dth.
In fiscal 1997, there was no sendout of propane. Due to the
comparable cost of LNG and propane compared to pipeline and
underground storage, the Company uses these fuels primarily to
satisfy peak winter demand.
Based on current information concerning pipeline and
supplemental gas supplies, the Company expects to meet the gas
requirements of its firm customers for the foreseeable future.
Competition
The Company has no direct competition with respect to the
retail distribution of natural gas by pipeline in its service
territory. Massachusetts law effectively protects gas companies
from such competition. Where a gas company exists in active
operation in Massachusetts, no other person may construct
underground gas mains in the public ways without the approval,
after notice and hearing, of the municipal authorities and, in
certain circumstances, the MDPU. If a municipality desires to
enter the gas business, it must take certain procedural steps,
including obtaining a favorable vote by a majority of the voters
at its town meeting. The municipality would then be required to
9
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. 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
received approval for these rates, no customer selected this
option during fiscal 1997. The Company converted its first
transportation customer in September 1997 and has received
inquiries from approximately 30 additional transportation
customers in October 1997.
While the current retail price of natural gas is equal to or
slightly higher than the retail price of oil for residential
space heating customers, natural gas is the fuel of choice for
most new residential construction. Natural gas has significant
environmental, operational and maintenance advantages over oil.
Additionally, most of the Company supply of natural gas is from
North American sources. Since the mid-1970's, the retail cost of
heating residential space by natural gas in the Company's service
territory has been approximately the same, or slightly higher
than, the comparable cost of heating by oil. There is no
assurance what, if any, the relative price differential between
natural gas and oil will be in the future. Natural gas has a
significant price advantage over electricity supplied by
investor-owned and municipal electric utilities in the Company's
service territory.
In the Company's service territory, the cost of heating with
natural gas for commercial and industrial customers is relatively
competitive with the cost of heating with oil. Approximately 50
of the Company's commercial and industrial customers have dual
heating facilities that enable them to switch freely between
natural gas and oil. As of August 31, 1997, the majority of the
Company's dual fuel customers were using oil.
Regulatory Matters
State
The Company is subject to the regulatory authority of the
MDPU with respect to the issuance of securities, accounting
practices, rates, service, contracts for the purchase of gas,
territories served and related matters.
Since 1987, the Company has filed five requests for rate
increases and has been granted a total of $8,030,791 in rate
relief by the MDPU, which amounts to 61.7 percent of the total
requested. The Company's most recent rate increase request was
filed in fiscal 1996 and approved in fiscal 1997. The Company's
fiscal 1997 rate increase request was for an annualized increase
of approximately $3,400,000 and the MDPU approved an annualized
rate increase of approximately $2,100,000. The rate increase was
effective December 1, 1996.
The MDPU permits Massachusetts gas companies to utilize a
Cost of Gas Adjustment ("CGA") that permits a gas company to pass
on to firm customers (on a current basis) increases or decreases
in the cost of gas supplies. Profits from interruptible sales
and gas supplier refunds are also passed on to firm customers
through the CGA and no portion of the interruptible profits are
retained by the Company unless certain volumes are sold.
10
Supplemental fuel inventory and related administrative and carrying
costs are also recovered through the CGA. In addition, the MDPU
allows recovery of the following through the CGA: (1) working
capital costs associated with purchased gas costs; (2) clean-up
costs associated with waste materials from former gas manufacturing
sites; and (3) interest on the over or under collected gas costs.
The Company has the ability to release any of its unused capacity
on the Tennessee Gas Pipeline with net proceeds being returned to
firm customers through the CGA.
Changes in rates charged to customers which are not
incorporated in the CGA must be approved by the MDPU. Some
relief with respect to rate changes, such as adjustments in the
allowed rates of return on common equity, granting of inflation
adjustments, and the use of year-end rate base calculations in
rate proceedings, have been granted in the past by the MDPU to
remedy the financial burden resulting from the lag between the
historic period upon which rate decisions are based and the date
when the rates actually become effective. By law, the MDPU must
act on a rate proceeding within six months of filing and may
grant relief during the interim period.
FERC
The Company is not subject to direct regulation by FERC, but
is significantly affected by FERC orders that regulate interstate
pipelines serving the Company.
Pursuant to FERC Order No. 636, as supplemented by FERC
Order No. 636A ("FERC Order 636"), TGPC is primarily a
transportation pipeline and has discontinued nearly all of its
activities as a FERC certificated merchant of gas. TGPC has
previously received approval for the conversion of certain of its
sales service to the Company. See "Item 1: Business--Gas
Supply." The Company believes that the unbundling of these sales
service arrangements will not result in material adverse changes
in its business and that it will be able to recover, through
rates, costs incurred in connection with the implementation of
FERC Order 636.
Certain issues are still pending before FERC, such as the
manner in which TGPC may pass on a portion of its transition
costs associated with Order 636. The MDPU allows the Company to
recover any of the transition costs allowed by FERC through the
CGA.
Certain other aspects of FERC Order 636 which affect or may
affect the Company are pending before FERC or are subject to
review by the courts. These include, among other things, (i)
rules for "capacity brokering" or "capacity reassignment"; (ii)
rules for the manner in which capacity is allocated on various
pipelines for transportation purposes; and (iii) rules governing
changes in ratemaking methodologies which create uncertainty as
to future transportation costs. Until the regulatory treatment
of these issues is clarified, the Company cannot predict the effect
of such issues on its business.
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. See "Item 7:
Management's Discussion and Analysis of Financial Condition and
Result of Operation- Regulatory and Accounting Issues.
11
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 and a length greater than
one mile requires approval by the Energy Facilities Sitting
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, 1997, the Company had 127 permanent employees
(including four part-time) 74 of whom were represented by the
United Steelworkers of America, AFL-CIO-CLC, Local 12086. The
current three-year labor contract with the Steelworkers covering
all hourly workers extends through February 4, 1999.
Item 2: Properties
The Company's property consists primarily of its
distribution system and related facilities. As of August 31,
1997, the Company had approximately 750 miles of gas mains and
36,000 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
500,000 gallons. In addition, the Company, through its wholly-
owned subsidiary, LNG Storage, Inc., owns an LNG storage facility
with a storage capacity of 410,000 Dth.
On August 31, 1997, the Company's gross utility plant
amounted to $104,540,111 at historical cost.
Substantially all of the properties owned by the Company,
other than expressly exempted property, are subject to a lien
under the indenture securing the Company's First Mortgage Bonds.
The Company's gas supply contracts have also been assigned as
collateral security for the Company's First Mortgage Bonds. The
indenture calls for a trustee or receiver to take possession of
the property if there is a default under its terms. The property
exempted from the lien includes cash, receivables, supplemental
fuel inventories, materials and supplies, rental appliances,
office furniture and equipment, and an LNG storage facility. The
LNG storage facility, while unencumbered with respect to the
Company's First Mortgage Bonds, is encumbered by a separate
mortgage note.
The Company leases its 30,000 square foot corporate
headquarters building. 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, 1998.
12
Item 3: Legal Proceedings
There are certain routine non-material claims incidental to
its business pending against the Company, all of which are
covered by insurance or reserves. Management believes that the
Company has adequate defenses against
these claims and it is the Company's intention to contest these
claims. In view of the insurance coverages, 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.
Executive Officers of the Registrant
The following sets forth certain information as of August
31, 1997 with respect to Essex County Gas Company's executive
officers. These officers have been elected or appointed to terms
which will expire January 20, 1998:
First
Served as
Name Position Age Officer
Charles E. Billups* Chairman of the Board 68 1971
Philip H. Reardon* President and Chief Executive
Officer 61 1992
William T. Beaton Vice President, Human Resources
and Customer Services 41 1995
Wayne I. Brooks Vice President, Distribution
and Engineering 50 1985
James H. Hastings Vice President and Treasurer 51 1985
Allen R. Neale Vice President, Supply Planning 46 1985
John W. Purdy, Jr. Vice President, Marketing and
Public Affairs 61 1987
*Also chairman and/or members of certain committees of the Board
of Directors.
There are no family relationships among any of the executive
officers and directors.
Each of the above has served as an officer or in a supervisory
capacity with Essex County Gas Company for the last five years.
13
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 17, 1997, the Common Stock was
held by 1,314 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, 1996
First Quarter $25.50 $24.25 $0.39
Second Quarter 26.75 25.00 0.40
Third Quarter 26.25 23.50 0.40
Fourth Quarter 25.50 23.50 0.40
Fiscal Year Ended August 31, 1997
First Quarter $27.00 $24.00 $0.40
Second Quarter 25.75 24.25 0.41
Third Quarter 26.00 24.25 0.41
Fourth Quarter 27.00 25.25 0.41
Fiscal Year Ending August 31, 1998
First Quarter (through
November 10, 1997) $31.50 $31.50 $0.41*
*Paid on October 1, 1997 to shareholders of record on September 15, 1997.
The Company has paid regular dividends since 1914. Common
Stock dividend payments in fiscal 1997 totaled $1.63 per share,
as compared to $1.59 in fiscal 1996. 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, 1997. 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.
14
Income Statement Data
For fiscal years ended August 31, 1997 1996 1995 1994 1993
(000'S omitted, except for per share and ratio information)
Operating revenues $53,535 $49,929 $45,050 $48,536 $45,016
Operating income $ 6,722 $ 6,669 $ 5,909 $ 5,794 $ 5,766
Income available for common stock $ 3,967 $ 3,836 $ 3,180 $ 3,302 $ 2,880
Shares of common stock outstanding,
weighted average 1,665 1,626 1,591 1,559 1,475
Earnings per common share $ 2.38 $ 2.36 $ 2.00 $ 2.12 $ 1.95
Cash dividends declared
per common share $ 1.63 $ 1.59 $ 1.55 $ 1.51 $ 1.47
Ratio of earnings
to fixed charges(1) 2.87x 2.83x 2.54x 2.83x 2.45x
_________________________________________________________________
Balance Sheet Data
1997 1996 1995 1994 1993
Long-term debt
(excluding current portion) $28,799 $19,765 $20,689 $21,713 $22,148
Redeemable preferred stock - - 336 350 364
Common stock equity 35,409 33,023 30,709 28,870 26,985
------- ------- ------- ------- -------
TOTAL CAPITALIZATION: $64,208 $52,788 $51,734 $50,933 $49,497
======= ======= ======= ======= =======
CAPITAL LEASE
(EXCLUDING CURRENT PORTION) $ 551 $ 605 $ 654 $ 700 $ 742
======= ======= ======= ======= =======
TOTAL ASSETS $92,746 $89,772 $86,582 $83,511 $76,535
======= ======= ======= ======= =======
_________________________________________________________________
(1)In computing the ratio of earnings to fixed charges,
"earnings" are defined as income before income taxes and fixed
charges. "Fixed charges" consist of interest, including the
amount capitalized, interest on the obligation under the
supplemental fuel inventory, amortization of debt expense and the
estimated interest portion (one third) of rental payments.
Item 7: Management's Discussion and Analysis of Financial
Condition and Results of Operations
Results of Operations
Fiscal Years Ended August 31, 1997 and 1996
Revenues
The Company's sales are responsive to colder weather as the
majority of its customers use natural gas for space heating
purposes. The Company measures weather through the use of
effective degree days. An effective degree day is calculated by
subtracting the average temperature for the day, adjusted for
wind and cloud cover, from 65 degrees Fahrenheit.
15
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).
Using a twenty-year average, the Company's service territory
incurs 6,787 effective degree days in one year. Fiscal 1997 had
6,656 effective degree days compared to 6,947 in fiscal 1996. As
a result, the volume of sales to the Company's two major firm
customer classes, residential and commercial and industrial,
decreased by 0.4 percent from 5,766,690 Dth in fiscal 1996 to
5,741,885 Dth in the current fiscal year. The volume decrease
was offset by a 9.1 percent increase in the unit price and firm
gas revenues increased to $50,716,991 in fiscal 1997 compared to
$46,690,295 in the prior fiscal year. The higher price was
attributable to a Massachusetts Department of Public Utilities
annualized rate increase of $2,100,000 effective December 1, 1996
and higher gas costs. Firm revenues in fiscal 1997 were 8.6
percent higher than in fiscal 1996. The increase was
attributable to the price factors discussed previously and an
increase of over 2.1 percent in the Company's customer base. The
average unit price of gas sold to all customers, including
interruptible customers, increased 10.2 percent to $8.09 in
fiscal 1997 from $7.34 in fiscal 1996. For firm customers, the
average unit price increased 9.0 percent to $8.83 in fiscal 1997
from $8.10 in the prior year. The Company's interruptible
revenues decreased 15.1 percent as volumes decreased in
interruptible sales to 758,124 Dth compared to 892,702 Dth. The
unit price increased by $0.01 to $2.49 for fiscal 1997. If
interruptible volumes exceed a threshold based on sales during
the prior four years, the Company may retain 25 percent of the
incremental gross profit on interruptible sales and refund the
remaining 75 percent to the Company's firm customers. In fiscal
1997, the required volumes of interruptible sales were not
obtained, and the Company returned all gross profit on
interruptible sales to its firm customers. The decrease in
interruptible volumes did not significantly impact the Company's
earnings. Other revenues decreased 9.2 percent to $929,327 in
fiscal 1997 from $1,023,417 in fiscal 1996.
During fiscal 1997, the Company added 1,119 new customers.
The Company's ability to attract customers has been assisted by
the improving economy and resulting new construction. Although
there is a slightly unfavorable price comparison with oil, which
is the Company's primary competition in the area of space
heating, the environmental advantages and convenience of natural
gas allow the Company to compete favorably.
Operating Expenses
The Company's major operating expense is its cost of gas
which increased 9.2 percent to $27,272,268 in fiscal 1997 from
$24,976,802 in fiscal 1996. The unit price of gas increased 12.0
percent from 1996 to 1997. This increase was offset by a
decrease of 0.4 percent in firm volumes of gas sold. The
increased gas costs for sales to the Company's firm customers are
recovered from those customers through a Cost of Gas Adjustment
("CGA") which is adjusted semi-annually to reflect any changes in
gas costs.
Operations and maintenance expenses increased $315,594 or
2.6 percent to $12,291,661 in fiscal 1997 from $11,976,067 in
fiscal 1996. This increase was mainly attributable to an
increase in meter and house regulator expense of approximately
$107,000; demonstrating and selling expense of $76,000;
administrative and general salaries of $202,000; environmental
costs of $80,000; and $91,000 in regulatory commission expense.
The increase in meter and house regulator expense is due to the
Company's aggressive meter exchange program in which older meters
16
are exchanged for newer remote-read meters. The increase in
demonstrating and selling expense is mainly attributable to cash
incentives paid to customers switching to natural gas from
alternative fuels and the increase in administrative and general
salaries expense is mainly due to filling positions previously
left unfilled and pay increases granted to management personnel.
The increase in environmental costs is due to an on going
remediation of a site in Plympton, Massachusetts. See "Item 1:
Enviromental Matters." The increase in regulatory commission
expense is due to the amortization of the Company's December 1,
1996 rate case expense which will continue to be amortized
through December 1, 1998. These expenses were partially offset
by a decrease in pension expense of $351,000 as the Company reduced
its pension contribution for fiscal 1997.
Utility Plant depreciation expense increased 25.0 percent to
$3,372,714 in fiscal 1997 from $2,697,241 in fiscal 1996 as the
Company received regulatory approval for increasing its utility
plant depreciation rate to 3.70 percent from the previous year's
rate of 3.03 percent.
Taxes, other than federal income, increased 9.3 percent to
$1,986,927 in fiscal 1997 from $1,816,929 in fiscal 1996. This
increase was primarily related to an increase in real estate
taxes due to assessments on the Company's additions to its
utility plant.
Federal income taxes increased 5.4 percent to $1,889,601 in
fiscal 1997 from $1,793,360 in fiscal 1996, also reflecting the
increase in the Company's pre-tax earnings. The Company's
combined effective tax rate for both federal and state income
taxes was 36.6 percent.
Other income, net increased by $308,923. This increase was
primarily attributable to higher interest income on the Company's
undercollected gas costs and a gain on the sale of the Company's
investments.
Interest on long-term debt increased 18.9 percent to
$2,338,112 in fiscal 1997 from $1,967,073 in fiscal 1996. This
increase was primarily related to the January 1997 issue of
$10,000,000 in 7.28 percent First Mortgage Bonds due 2017. Other
interest expense decreased 14.0 percent to $750,895 in fiscal
1997 from $873,198 in fiscal 1996. This decrease was primarily
attributable to lower levels of short-term debt outstanding in
fiscal 1997 as compared to fiscal 1996. The lower level of short-
term debt is a direct result of the Company's long-term
borrowing.
Income available for common stock increased 3.4 percent to
$3,966,519, or $2.38 per share, in fiscal 1997 from $3,835,500,
or $2.36 per share, in fiscal 1996. Dividends per share declared
and paid for fiscal 1997 and 1996 were $1.63 and $1.59,
respectively.
Fiscal Years Ended August 31, 1996 and 1995
Revenues
Fiscal 1996 had 6,947 effective degree days compared to
6,258 in fiscal 1995. As a result, the volume of sales to the
Company's two major firm customer classes, residential and
commercial and industrial, increased by 12.6 percent from
5,123,661 Dth in 1995 to 5,766,690 Dth in fiscal 1996. The
colder weather, coupled with a 0.7 percent increase in price,
resulted in revenues of $49,929,389 in 1996 compared to
$45,049,573 in the prior year. Firm revenues in 1996 were 10.9
percent higher than in fiscal 1995. The increase was also
attributable to an increase of nearly 3.0 percent in the
Company's customer base. The average unit price of gas sold to
17
all customers, including interruptible customers, increased 0.7
percent in 1996 to $7.45 from $7.40 in fiscal 1995. For firm
customers, the average unit price decreased to $8.22 from $8.36
in the prior year. The Company's interruptible revenues
increased 14.6 percent as the unit price increased by $0.40 to
$2.51 over the same period. This price increase was offset by a
volume decrease in interruptible sales by 32,928 Dth to 892,702
Dth. Under rates in effect in fiscal 1996, if interruptible
volumes exceed a threshold based on sales during the last four
years, the Company may retain 10 percent of the gross profit on
interruptible sales and refund the remaining 90 percent to the
Company's firm customers. In fiscal 1996, the required volumes
of interruptible sales were obtained, and the Company retained
approximately $5,000, returning the balance of all gross profit
on interruptible sales to its firm customers. The decrease in
interruptible volumes did not significantly impact the Company's
earnings. Other revenues increased slightly to $1,023,417 in
fiscal 1996 from $1,015,979 in fiscal 1995.
Operating Expenses
The Company's major operating expense is its cost of gas,
which increased 10.9 percent to $24,976,802 in fiscal 1996 from
$22,525,442 in fiscal 1995. This increase was due to additional
volumes of gas sold.
Operations and maintenance expenses increased 8.1 percent to
$11,976,067 in fiscal 1996 from $11,078,029 in fiscal 1995. This
increase was mainly attributable to: an increase of $285,000 in
employee benefits, other than pensions; $267,000 in pension
expense and an increase of approximately $190,000 in
uncollectible accounts. The increase in employee benefits, other
than pensions, is due to approximately $143,000 in additional
medical expense due to higher utilization of the Company's self-
insured medical plan. In addition, the Company increased its
Employee Stock Ownership Plan contribution by $82,000 as well as
a $25,000 increase in the Company's Thrift Savings Plan due to
more employees participating in the Company program and receiving
matching funds. The increase in the pension expense is primarily
due to an additional contribution to the Company's pension trust
and the increase in uncollectible accounts is primarily due to
the higher revenues recorded during the fiscal year. The Company
also incurred a one-time additional regulatory expense of
approximately $225,000 for conservation and load management
programs and performance based ratemaking. These increases were
offset by $80,000 of reduced rate case expense as the 1993 rate
case expenditures were fully amortized in December 1995.
Utility Plant depreciation expense increased 7.9 percent to
$2,697,241 in fiscal 1996 from $2,500,585 in fiscal 1995,
reflecting the ongoing investment in upgrading and expanding the
Company's distribution system.
Taxes, other than federal income, increased 11.2 percent to
$1,816,929 in fiscal 1996 from $1,634,216 in fiscal 1995. This
increase was primarily related to an increase in real estate
taxes due to assessments on the Company's additions to its
utility plant and state income taxes resulting from higher
pre-tax earnings.
Federal income taxes increased 28.0 percent to $1,793,360 in
fiscal 1996 from $1,401,858 in fiscal 1995, also reflecting the
increase in the Company's pre-tax earnings. The Company's
combined effective tax rate for both federal and state income tax
purposes was 36.1 percent.
Interest on long-term debt decreased 4.0 percent to
$1,967,073 in fiscal 1996 from $2,048,959 in fiscal 1995. This
decrease was related to the sinking fund payments of long-term
debt. Other interest expense increased 19.1 percent to $873,198
18
in fiscal 1996 from $732,941 in fiscal 1995. This increase was
primarily attributable to higher levels of short-term debt
outstanding and higher interest rates in fiscal 1996 as compared
to fiscal 1995.
Income available for common stock increased 20.6 percent to
$3,835,500, or $2.36 per share, in fiscal 1996, from $3,179,778,
or $2.00 per share, in 1995. Dividends per share declared and
paid for fiscal 1996 and 1995 were $1.59 and $1.55, respectively.
Liquidity and Capital Resources
Net cash provided by operating activities was $8,063,077 for
the fiscal year ended August 31, 1997. Cash flows were generated
primarily from net income of $3,966,519, depreciation expense of
$3,789,528, a decrease in taxes payable of $1,019,266, and a
supplier refund due customers in the amount of $1,291,720. These
sources of cash were offset primarily by cash used for deferred
income taxes in the amount of $812,633, an increase in accounts
receivable of $899,975 and a decrease in accounts payable in the
amount of $970,970. The cash used for refundable gas costs to
customers represents savings in gas costs which are returned to
the Company's firm customers as discussed below. The increase in
accounts receivable is due to the seasonal nature of the
Company's business.
Occasionally the Company receives refunds from its pipeline
supplier as a result of regulatory action by the Federal Energy
Regulatory Commission ("FERC".) The supplier refunds are
returned by the Company to customers over a twelve month period.
During the twelve months ended August 31, 1997, the Company
received $1,567,364 in supplier refunds.
Due to the seasonal nature of the Company's operations,
the Company periodically borrows from banks on an unsecured short-
term basis. Borrowings against lines of credit during fiscal
1997 ranged from $55,000 to a high of $18,670,000. At August 31,
1997, the available lines of credit were $19,000,000 with
$3,313,000 outstanding. In addition, a credit line of
$10,000,000 was available at August 31, 1997 for the sole purpose
of financing the Supplemental Fuel Inventory. At August 31,
1997, the Company's Supplemental Fuel Inventory was $4,131,520
with outstanding obligations under this credit agreement of
$3,807,788. 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.
The Company continues to invest a significant amount of
capital in its distribution system to satisfy current and future
customer demand. 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, including additional
shares of common stock through the Company's Dividend
Reinvestment and Common Stock Purchase Plan. In fiscal 1997, the
Company raised $610,451 of common stock through its Dividend
Reinvestment and Common Stock Purchase Plan (including $135,071
from the cash infusion portion of the Plan) and $438,252 of
common stock through the Company's employee stock plan. In
January 1997, the Company sold $10,000,000 aggregate principal
amount of First Mortgage Bonds, providing the Company with
proceeds of $9,827,190 net of underwriting fees. Management
anticipates that these financing sources and other sources will
remain available and continue to adequately serve the Company's
needs.
The Company's major uses of cash in fiscal 1997 were
construction expenditures of $6,894,633, retirement of long-term
debt of $854,831, and net repayment of notes payable of
19
$8,627,000. In addition, dividend payments totaled $2,706,278 in
fiscal 1997. The Company's construction expenditures decreased
to $6,894,633 in fiscal 1997 from $8,027,623 in fiscal 1996. The
Company's lower construction expenditures in fiscal 1997 were
primarily attributable to the completion in 1996 of a major
transmission line north along Route 1 from Wenham to Newburyport.
Capital expenditures for fiscal 1998 are expected to be
approximately $7,000,000 and annual sinking fund requirements and
maturities of long-term debt are scheduled to be $960,536 in
fiscal 1998. The Company's planned construction expenditures and
long-term debt repayments have been, and the Company expects them
to continue to be, funded through cash generated by operations
and short-term bank borrowings, which the Company anticipates
will be replaced from time to time with equity and long-term debt
financings.
On August 31, 1997, the Company's capitalization consisted
of 49.0 percent common stock equity and 51.0 percent debt,
including short-term debt and obligations under the supplemental
fuel inventory credit agreement. In order to contribute to both
stability and the ability to market new securities when
appropriate, the Company attempts to maintain a balanced capital
structure.
Regulatory and Accounting Issues
The Company's revenues are based on rates regulated by the
MDPU. These rates are designed to allow the Company to recover
its operating costs and provide an opportunity to earn a
reasonable rate of return on investor supplied funds. Once
approved, the Company's rates are adjusted by a CGA which,
subject to approval by the MDPU, permits the Company to change
rates to recover gas costs and certain other costs on a dollar-
for-dollar basis. The CGA is also used as a mechanism to reduce
charges to firm customers by the margin earned on sales to
interruptible customers. In September 1996 the Company received
approval for a rate increase of $2,100,000 which became effective
December 1, 1996. As part of a settlement approved by the MDPU,
the Company has increased its depreciation rate to an average
rate of 3.70 percent effective December 1, 1996 based on a
depreciation study. The effect of this change in the
depreciation rate increased, on an annual basis, depreciation
expense in fiscal 1997 by approximately $600,000.
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.
20
The Company or its predecessors previously operated four
manufactured gas plants and one storage facility (collectively,
"MGPs") at sites in Massachusetts. It is possible that in the
manufacturing process some or all of the MGPs may have discharged
certain substances on the sites which may now be deemed to be
hazardous. The Company has not ascertained the extent of any
hazardous substance contamination on these sites from the MGP
operations. The Environmental Protection Agency ("EPA") and MDEP
have recently begun to focus on the potential environmental
hazards of MGPs. To the Company's knowledge, neither the EPA nor
the MDEP have issued any orders to clean up any of the Company's
MGP sites. In 1995 an investigation which reported the presence
of certain compounds was conducted at one of the Company's MGP
sites. As a result, a second, more intensive investigation was
conducted in fiscal 1997 to determine the level of contamination
and to assess whether any remediation was required. The Company
had also been informed that certain materials had been discovered
on properties adjacent to a second site currently owned by the
Company. These adjacent properties have been classified by the
MDEP as a location to be investigated. Based on preliminary
investigation, the Company currently believes that it may not be
liable for cleanup costs associated at the adjacent properties
unless such liability is based on down-gradient status; however,
the Company may be liable for cleanup costs associated with the
parcel presently owned by the Company. The Company does not
currently possess sufficient information to determine the
probability or the cost of the potential remediation, however,
the MDPU provides for the recovery through the CGA of all
environmental response costs associated with this and any other
MGP sites over seven-year amortization periods without a return
on the unamortized balance. The 1990 MDPU agreement also
provides for no further investigation on 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 FERC Order 636, as supplemented by Order 636A,
pipeline companies have unbundled pipeline sales, storage and
transportation services. FERC Order 636 was implemented by the
Company's pipeline supplier, Tennessee Gas Pipeline Company
("TGPC"), on September 1, 1993. As a result, TGPC is providing
transportation service only. The Company now contracts for its
own gas supply through a consortium of gas companies and pays
monthly demand charges to TGPC for the availability of pipeline
capacity and transportation charges for gas transport. The
Company pays charges for the cost of gas delivered and for gas
inventory charges to reserve volumes of gas inventory in
connection with substantially all of its long-term firm gas
purchase agreements.
FERC Order 636 has also required pipelines to adopt a new
rate design that has shifted the recovery of the pipeline's fixed
costs to a monthly demand charge for firm transportation service
and away from recovery of costs of service on a volumetric basis.
FERC Order 636 also allows the pipeline companies to recover
transition costs incurred as they restructure their services.
TGPC began direct billing these costs to the Company on September
1, 1993 as a component of the demand charges. The Company's
current estimate of its obligation for transition costs is
approximately $401,000 and is based upon FERC approved filings.
This estimated liability has been included in the Company's
financial statements at August 31, 1997, together with the
related regulatory asset. The MDPU has approved the recovery of
Gas Supply Realignment costs from all firm customers.
The MDPU has received comments and proposals from interested
persons on how incentive regulation could improve upon the
existing framework of utility regulation. Although to date the
MDPU has not issued directives, it is expected that in the near
21
future, incentive ratemaking, in some form, will be instituted in
the Commonwealth of Massachusetts.
The accompanying consolidated financial statements conform
to generally accepted accounting principles applicable to rate
regulated enterprises and reflect the effects of the ratemaking
process in accordance with SFAS No. 71, Accounting for the
Effects of Certain Types of Regulation. Assuming a cost-of-
service based regulatory structure, regulators may permit
incurred costs, normally treated as expenses, to be deferred and
recovered through future revenues. Through their actions,
regulators may also reduce or eliminate the value of an asset, or
create a liability. If any portion of the Company's operations
were no longer subject to the provisions of SFAS No. 71, as a
result of a change in the cost-of-service based regulatory
structure or the effects of competition, the Company would be
required to write off regulated assets and liabilities. The
Company continues to believe that its use of regulatory
accounting remains appropriate.
The "Year 2000" Issue
The Company has assessed the impact of the year 2000 issue
and is currently modifying its computer system to process
transactions relating to the year 2000. Anticipated spending for
this modification will be expensed as incurred and is not
expected to have a significant impact on the Company's ongoing
results of operations.
New Accounting Standards
In March 1997, the Financial Accounting Standards Board
issued SFAS No. 128, Earnings Per Share. SFAS No. 128
establishes standards for computing and presenting earnings per
share and applies to entities with publicly held common stock or
potential common stock. This statement is effective for fiscal
years ending after December 15, 1997 and early adoption is not
permitted. When adopted, the statement will require restatement
of prior years' earnings per share. The Company will adopt this
statement for its fiscal year ended August 31, 1998. In
addition, the Company believes that the adoption of SFAS No. 128
will not have a material effect on its financial statements.
The American Institute of Certified Public Accountants
issued a Statement of Position ("SOP")96-1, Environmental
Remediation Liabilities. The SOP's objective is to make the
timing of the recognition of environmental obligations more
uniform by discussing the estimation process and providing
benchmarks to aid in determining when to recognize environmental
liabilities. The SOP is effective for the Company in fiscal
1998. The Company does not expect that the adoption of the SOP
will have a material impact on the Company's financial position
or results in operations.
Forward Looking Statements
The Private Securities Litigation Reform Act of 1995
encourages the use of cautionary statements accompanying forward-
looking statements. The preceding Management's Discussion and
Analysis of Financial Condition and Results of Operations
included forward-looking statements concerning the impact of
transportation customers on the Company's profitability; the
impact of changes in the cost of gas and of the CGA mechanism on
total margin; projected capital expenditures and sources of cash
to fund expenditures; and estimated costs of environmental
remediation and anticipated regulatory approval of recovery
mechanisms. The Company's future results, generally and with
21
respect to such forward-looking statements, may be affected by
many factors, among which are uncertainty as to the precise rates
for transportation of gas that will be allowed by the regulators
and transportation-only customers; uncertainty as to the
regulatory allowance of recovery of changes in the cost of gas;
uncertain demands for capital expenditures and the availability
of cash from various sources; and uncertainty as to the
regulatory approval of the full recovery of environmental costs,
transition costs, and other regulatory assets.
23
Item 8: Financial Statements and Supplementary Data
(a) Financial Statements Required by Regulation S-X
CONSOLIDATED STATEMENTS OF INCOME
Fiscal Years Ended August 31,
1997 1996 1995
OPERATING REVENUES $53,534,734 $49,929,389 $45,049,573
Less: Cost of gas 27,272,268 24,976,802 22,525,442
----------- ----------- -----------
Operating margin 26,262,466 24,952,587 22,524,131
----------- ----------- -----------
OPERATING EXPENSES:
Operations and maintenance expenses 12,291,661 11,976,067 11,078,029
Depreciation 3,372,714 2,697,241 2,500,585
Taxes, other than federal income 1,986,927 1,816,929 1,634,216
Federal income taxes 1,889,601 1,793,360 1,401,858
----------- ----------- -----------
TOTAL OPERATING EXPENSES 19,540,903 18,283,597 16,614,688
----------- ----------- -----------
OPERATING INCOME 6,721,563 6,668,990 5,909,443
OTHER INCOME, NET 337,707 1,997 6,202
----------- ----------- -----------
INCOME BEFORE INTEREST CHARGES 7,059,270 6,670,987 5,915,645
----------- ----------- -----------
INTEREST CHARGES:
Interest on long-term debt 2,338,112 1,967,073 2,048,959
Amortization of deferred debt expense 30,578 27,499 27,081
Other interest expense 750,895 873,198 732,941
Allowance for funds used
during construction (26,834) (46,143) (92,428)
----------- ----------- -----------
TOTAL INTEREST CHARGES 3,092,751 2,821,627 2,716,553
----------- ----------- -----------
NET INCOME 3,966,519 3,849,360 3,199,092
ANNUAL REDEEMABLE
PREFERRED DIVIDEND REQUIREMENTS - (13,860) (19,314)
----------- ----------- -----------
INCOME AVAILABLE FOR COMMON STOCK $ 3,966,519 $ 3,835,500 $ 3,179,778
=========== =========== ===========
SHARES OF COMMON STOCK OUTSTANDING
(WEIGHTED AVERAGE) 1,664,677 1,626,315 1,591,372
--------- --------- ---------
EARNINGS PER COMMON SHARE $ 2.38 $ 2.36 $ 2.00
------ ------ ------
CASH DIVIDENDS DECLARED PER COMMON SHARE $ 1.63 $ 1.59 $ 1.55
------ ------ ------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Fiscal Years Ended August 31,
1997 1996 1995
BALANCE AT BEGINNING OF YEAR $13,833,767 $12,576,695 $11,857,299
Net income 3,966,519 3,849,360 3,199,092
----------- ----------- -----------
TOTAL 17,800,286 16,426,055 15,056,391
----------- ----------- -----------
Cash dividends declared:
Redeemable preferred stock - 13,860 19,314
Common stock 2,706,278 2,578,428 2,460,382
----------- ----------- -----------
TOTAL 2,706,278 2,592,288 2,479,696
----------- ----------- -----------
BALANCE AT END OF YEAR $15,094,008 $13,833,767 $12,576,695
=========== =========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
24
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, August 31,
1997 1996
UTILITY PLANT, AT COST $104,540,111 $ 98,603,784
Less: Accumulated depreciation 25,021,795 22,290,175
------------ ------------
NET UTILITY PLANT 79,518,316 76,313,609
------------ ------------
Other property and investments 718,838 633,515
------------ ------------
CAPITALIZED LEASE (NET OF ACCUMULATED
AMORTIZATION OF $518,975 1N 1997 AND
$469,406 IN 1996) 604,822 654,391
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 434,930 303,526
Accounts receivable:
Customers (net of allowance for
uncollectible accounts of $772,000
in 1997 and $653,000 in 1996) 2,275,005 1,654,808
Other 389,526 229,189
Income tax refunds receivable - 874,000
Supplemental fuel inventory 4,131,520 4,047,421
Materials and supplies (at average cost) 560,493 512,330
Prepaid deferred income taxes 100,105 328,066
Prepayments and other 622,024 622,502
Recoverable gas costs 320,909 470,766
----------- ----------
TOTAL CURRENT ASSETS 8,834,512 9,042,608
----------- ----------
DERRED CHARGES:
Regulatory assets 1,790,966 2,464,691
Unamortized debt expense and other 1,278,367 663,119
----------- -----------
TOTAL DEFERRED CHARGES 3,069,333 3,127,810
----------- -----------
$ 92,745,821 $ 89,771,933
============ ============
The accompanying notes are an integral part of these consolidated
financial statements.
25
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
August 31, August 31,
1997 1996
COMMON STOCK EQUITY $35,408,645 $33,022,947
LONG-TERM DEBT, LESS CURRENT PORTION 28,799,000 19,765,535
----------- -----------
TOTAL CAPITALIZATION 64,207,645 52,788,482
----------- -----------
NONCURRENT OBLIGATIONS UNDER
CAPITAL LEASE 550,939 604,823
----------- -----------
CURRENT LIABILITIES:
Current portion of long-term debt 960,535 923,831
Current obligation under capital lease 53,883 49,568
Obligations under supplemental
fuel inventory 3,807,788 3,358,010
Notes payable, banks 3,313,000 11,940,000
Accounts payable 3,092,859 4,063,829
Accrued interest 803,237 937,988
Taxes payable 157,098 11,832
Accrued transition costs 401,465 890,432
Supplier refund due customers 1,567,364 275,644
Other 320,308 176,681
----------- -----------
TOTAL CURRENT LIABILITIES 14,477,537 22,627,815
----------- -----------
COMMITMENTS AND CONTINGENCIES
DEFERRED CREDITS:
Accumulated deferred income taxes 8,941,079 9,951,085
Unamortized investment tax credit 1,141,132 1,210,896
Deferred directors' fees 1,106,358 991,503
Other 2,321,131 1,597,329
----------- -----------
TOTAL DEFERRED CREDITS 13,509,700 13,750,813
----------- -----------
$92,745,821 $89,771,933
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
26
CONSOLIDATED STATEMENTS OF CASH FLOWS
Fiscal Years Ended August 31,
1997 1996 1995
OPERATING ACTIVITIES:
NET INCOME $ 3,966,519 $ 3,849,360 $ 3,199,092
Adjustments to reconcile net income ----------- ----------- -----------
to net cash:
Depreciation, including amounts
related to non-utility operations 3,789,528 3,130,712 2,920,476
Provisions for uncollectible accounts 119,441 57,792 (208,797)
Deferred income taxes (812,633) 1,950,962 40,876
Amortization (1,915) 7,943 8,390
Noncash compensation associated
with ESOP 75,000 150,000 225,000
Changes in current assets and liabilities:
Accounts receivable (899,975) (242,390) 546,304
Inventories including fuel (132,262) 2,512,221 294,854
Prepayments and other 478 (271,842) (33,922)
Accounts payable (970,970) 1,077,522 55,729
Supplier refund obligations 1,291,720 (2,179,095) 792,927
Taxes payable/receivable 1,019,266 (802,472) 488,000
Recoverable (refundable) gas costs 149,857 (2,960,944) 1,719,994
Other, net 469,023 (53,011) 658,391
----------- ----------- -----------
Total adjustments 4,096,558 2,377,398 7,508,222
----------- ----------- -----------
NET CASH PROVIDED BY
OPERATING ACTIVITIES 8,063,077 6,226,758 10,707,314
----------- ---------- ----------
INVESTING ACTIVITIES:
Utility capital expenditures (6,894,633) (8,027,623) (6,967,340)
Payments for retirements of property,
plant and equipment, net (99,602) (258,352) (66,497)
Purchase of investment (570,113) - -
Sale of investment 570,113 - -
---------- --------- ----------
NET CASH USED IN INVESTING
ACTIVITIES (6,994,235) (8,285,975) (7,033,837)
---------- ---------- ----------
FINANCING ACTIVITIES:
Dividends paid (2,706,278) (2,592,288) (2,479,696)
Issuance of common stock 1,048,703 856,007 814,126
Issuance of long-term debt 9,827,190 - -
Retirements of preferred stock - (336,000) (14,000)
Principal retired on long-term debt (854,831) (828,758) (855,304)
Changes in supplemental fuel inventory 449,778 (1,773,143) (1,297,617)
Changes in notes payable, banks (8,627,000) 7,050,000 390,000
Payment of ESOP debt (75,000) (150,000) (225,000)
NET CASH PROVIDED BY (USED IN) ---------- ---------- ----------
FINANCING ACTIVITIES (937,438) 2,225,818 (3,667,491)
---------- ---------- ----------
Net increase in cash and cash
equivalents 131,404 166,601 5,986
Cash and cash equivalents at
beginning of year 303,526 136,925 130,939
CASH AND CASH EQUIVALENTS AT ---------- ---------- ----------
END OF YEAR $ 434,930 $ 303,526 $ 136,925
========== ========== ==========
SUPPLEMENTAL DISCLOSURES:
Cash paid during the year for:
Interest (net of amount capitalized) $3,227,502 $2,708,961 $2,517,015
---------- ---------- ----------
Income taxes $2,682,465 $1,407,476 $1,743,197
---------- ---------- ----------
The accompanying notes are an integral part of these consolidated
financial statements.
27
CONSOLIDATED STATEMENTS OF CAPITALIZATION
August 31, August 31,
1997 1996
COMMON STOCK EQUITY:
Common stock, no par value, 5,000,000
authorized shares. Issued and
outstanding 1,685,318 shares at
August 31, 1997 and 1,642,490 issued
and outstanding at August 31, 1996. $20,320,890 $19,234,915
Unrealized gain (loss)on investments
available for sale, net (6,253) 29,265
Retained earnings 15,094,008 13,833,767
----------- -----------
35,408,645 33,097,947
----------- -----------
Less: Shares held by ESOP purchased
with debt - 75,000
----------- -----------
Total common stock equity 35,408,645 33,022,947
----------- -----------
LONG-TERM DEBT:
FIRST MORTGAGE BONDS:
10 1/4 percent, due serially
from 1994 to 2003 4,200,000 4,800,000
10.10 percent, due serially
from 2010 to 2020 8,000,000 8,000,000
7.28 percent due serially
from 2008 to 2017 10,000,000 -
----------- -----------
22,200,000 12,800,000
MORTGAGE NOTE: ----------- -----------
8 1/2 percent, due serially
from 1976 to 1997 360,535 609,366
----------- -----------
DEBENTURES:
8 5/8 percent, due 2006 2,245,000 2,245,000
8.15 percent, due 2017 4,954,000 4,960,000
---------- -----------
7,199,000 7,205,000
ESOP LOAN GUARANTEE: ---------- -----------
7.0 percent due serially
from 1987 to 1996 - 75,000
---------- -----------
TOTAL DEBT 29,759,535 20,689,366
Less: Current portion maturing
and payable 960,535 923,831
TOTAL LONG-TERM DEBT 28,799,000 19,765,535
----------- -----------
TOTAL CAPITALIZATION $64,207,645 $52,788,482
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
28
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. ("SFAS") 71, "Accounting for Certain Types of
Regulation". Under SFAS No. 71, a utility is allowed to defer
certain costs that otherwise would be expensed in recognition of
the ability to recover them in future rates.
The Company has established regulatory assets in cases where
the MDPU has permitted or is expected to permit the recovery of
specific costs over time. As of August 31, 1997, principal
regulatory assets include (1) approximately $401,000 for
transition costs associated with FERC Order 636, (2) $347,000
related to a settlement payment for a supplemental retirement
plan, and (3) $415,000 related to deferred income taxes.
Included in deferred credits is a regulatory liability of
$708,000 related to deferred income taxes. Assuming a cost-of-
service based regulatory structure, regulators may permit
incurred costs, normally treated as expenses, to be deferred and
recovered through future revenues. Through their actions,
regulators may also reduce or eliminate the value of an asset, or
create a liability. If any portion of the Company's operations
were no longer subject to the provisions of SFAS No. 71, as a
result of a change in the cost-of-service based regulatory
structure or the effects of competition, the Company would be
required to write off regulated assets and liabilities. The
Company continues to believe that its use of regulatory
accounting remains appropriate.
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
29
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 3.53 percent for fiscal 1997 and
3.03 percent for fiscal 1996 and 1995. As part of an MDPU
approved rate increase effective December 1, 1996, the Company
increased its annual depreciation rate to 3.70 percent from 3.03
percent. The 3.53 percent rate for 1997 represents pre December
1, 1996 depreciation at the former rate and post November 30,
1996 depreciation at the current rate. The cost of Utility Plant
retired or otherwise disposed of, in the ordinary course of
business, together with costs of removal less salvage, is charged
to accumulated depreciation.
Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Earnings Per Share
In March 1997, the Financial Accounting Standards Board
issued SFAS No. 128, Earnings Per Share. SFAS No. 128
establishes standards for computing and presenting earnings per
share and applies to entities with publicly held common stock or
potential common stock. This statement is effective for fiscal
years ending after December 15, 1997 and early adoption is not
permitted. When adopted, the statement will require restatement
of prior years' earnings per share. The company will adopt this
statement for its fiscal year ended August 31, 1998. In
addition, the Company believes that the adoption of SFAS No. 128
will not have a material effect on its financial statements.
Reclassifications
Certain prior year financial statement amounts have been
reclassified for consistent presentation with the current year.
B. Supplemental Fuel Inventory
The Company, with MDPU approval, finances its supplemental
gas inventory through a single purpose financing arrangement
extending through December 31, 2000. The credit agreement
provides for a total commitment of up to $10,000,000 and is
secured by storage gas. Financing resulted in an effective
interest cost to the Company of 6.1 percent for 1997 and 6.5
percent in 1996 based on average borrowing.
30
C. Common Stock
Common stock activity for the three-year period ended August
31, 1997, is as follows:
Additional
Number of Common Paid-in
Shares Stock Capital
BALANCE, AUGUST 31, 1994 1,572,062 $ 3,930,155 $13,532,990
Dividend reinvestment plan 19,276 48,190 389,246
Amortization of capital
stock expense - - 51,408
Employee stock plans 13,054 32,635 280,208
Sale of common stock 2,669 6,673 57,174
--------- --------- ----------
BALANCE, AUGUST 31, 1995 1,607,061 4,017,653 14,311,026
Dividend reinvestment plan 19,754 366,787 100,916
Amortization of capital
stock expense - 50,229 -
Employee stock plans 11,319 226,881 52,370
Sale of common stock 4,356 97,283 11,770
Conversion to no par value - 14,476,082 (14,476,082)
--------- ---------- ----------
BALANCE, AUGUST 31, 1996 1,642,490 19,234,915 -
Dividend reinvestment plan 19,733 475,380 -
Amortization of capital
stock expense - 37,272 -
Employee stock plans 17,794 438,252 -
Sale of common stock 5,301 135,071 -
--------- ---------- ----------
BALANCE, AUGUST 31, 1997 1,685,318 $20,320,890 $ -
========= ========== ==========
Conversion of Stock to No Par Value
The shareholders approved conversion of Common Stock from $2.50
par value to no par value effective September 15, 1995.
D. Restriction on Retained Earnings
Under the terms of the indenture securing the First Mortgage
Bonds, retained earnings in the amount of $5,260,241 as of August
31, 1997, were unrestricted as to the payment of cash dividends
on common stock and the purchase, redemption or retirement of
shares of common stock.
E. Interim Financing and Long-term Debt
The Company periodically borrows from banks on an unsecured,
short-term basis. At August 31, 1997, the Company had $3,313,000
of outstanding notes payable with a weighted average interest
rate of 6.2 percent under available lines of credit totaling
$19,000,000. The annual commitment fees related to these lines
of credit are between 1/4 percent and 3/8 percent on the total
amount of the line.
31
Substantially all plant assets are pledged as collateral
under the terms of the indenture of First Mortgage Bonds. The
8-1/2 percent Mortgage Note represents an obligation secured by
the liquefied gas storage facility in Haverhill, Massachusetts.
In accordance with the terms of the indenture of First Mortgage
Bonds, the Note Purchase Agreement of the sinking fund notes and
the Mortgage Note, the Company is required to make specified
sinking fund payments and other maturities of long-term debt of
$960,536 in 1998, $600,000 in 1999, $600,000 in 2000, $600,000 in
2001 and $17,005,000 thereafter.
F. Disclosure About Fair Values of Financial Instruments
The estimated fair values of the Company's long-term debt at
August 31, 1997 and 1996 are $35,202,321 and $22,901,111,
respectively, as compared to the carrying value of $28,799,000
and $19,765,535, respectively. The estimated fair value of the
Company's long-term debt is estimated based on the quoted market
prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturity.
The fair value shown above does not purport to represent the
amount at which these obligations could be settled.
The carrying value of cash approximates fair value because
of the short maturity of those instruments.
G. Income Taxes
The components of the provision for income taxes are as follows:
1997 1996 1995
FEDERAL
Current $2,258,000 $ 294,144 $1,469,957
Deferred (298,635) 1,569,000 2,000
Amortization of
investment tax
credit (69,764) (69,784) (70,099)
--------- --------- ---------
TOTAL FEDERAL 1,889,601 1,793,360 1,401,858
STATE --------- --------- ---------
Current 454,643 58,643 292,615
Deferred (64,000) 321,000 445
--------- --------- ---------
TOTAL STATE 390,643 379,643 293,060
--------- --------- ---------
TOTAL INCOME TAXES $2,280,244 $2,173,003 $1,694,918
========= ========= =========
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:
32
1997 1996 1995
Federal statutory rate 34.0% 34.0% 34.0%
==== ==== ====
Federal income tax
expense at statutory rates $2,117,753 $2,048,628 $1,663,963
Increase (decrease) in taxes
resulting from:
Amortization of investment
tax credit (69,764) (69,784) (70,099)
State taxes, net of
federal benefit 257,824 250,564 199,980
Other (25,569) (56,405) (98,926)
--------- --------- ---------
TOTAL INCOME TAX EXPENSE $2,280,244 $2,173,003 $1,694,918
========= ========= =========
EFFECTIVE INCOME TAX RATE 36.6% 36.1% 34.6%
==== ==== ====
The Company follows the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes"
("SFAS 109"). SFAS No. 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 $415,000 was
established for the deferred taxes not previously recovered as a
result of the flow through to customers for temporary differences
in prior years. This balance is being recovered over the
estimated lives of the property. A regulatory liability of
$708,000 was established for the tax benefit of unamortized
investment tax credits, which SFAS No. 109 requires to be treated as
a temporary difference. This benefit is being passed on to
customers over the lives of property giving rise to the
investment credits. Significant items making up deferred tax
assets and deferred tax liabilities at August 31, 1997 and 1996
are as follows:
1997 1996
Liabilities
Utility Plant-primarily depreciation $11,399,390 $10,779,608
Other 476,162 602,814
----------- -----------
TOTAL LIABILITIES 11,875,552 11,382,422
----------- -----------
Assets
Investment tax credits 708,053 751,340
Deferred directors fees 423,624 379,646
Unbilled revenue 317,513 208,870
Reserve for uncollectible receivables 295,688 249,954
Supplier refund 600,144 -
Capitalized cost - inventory 443,739 -
Other 245,817 169,593
---------- ----------
TOTAL ASSETS 3,034,578 1,759,403
---------- ----------
ACCUMULATED DEFERRED INCOME TAXES, NET $ 8,840,974 $ 9,623,019
========== ==========
33
The net year-end deferred income tax liabilities above are net of
current deferred tax assets of $100,105 and $328,066
respectively, which are included in prepaid income taxes in the
accompanying Consolidated Balance Sheets.
H. Leases
The Company is obligated under various lease agreements for
certain facilities and equipment used in operations. Total
expenditures under operating leases were $298,789 in 1997,
$315,152 in 1996 and $289,721 in 1995. A summary of property
classified as capital leases as of August 31, 1997 and 1996 is as
follows:
1997 1996
Buildings $1,123,796 $1,123,797
Less: Accumulated depreciation 518,974 469,406
---------- ----------
$ 604,822 $ 654,391
========== ==========
In accordance with the rate treatment allowed by the MDPU, the
depreciation expense of $49,568, $45,600, and $41,948, along with
interest of $52,931, $56,850 and $60,502 related to the capital
lease, is included in other operating expenses for the years
ended August 31, 1997, 1996 and 1995, respectively.
The Company also has various operating lease agreements for
equipment, vehicles and office space. The remaining minimum
annual rental commitment for these and all other non-cancelable
leases is as follows:
Capital Leases Operating Leases
1998 $102,500 $266,750
1999 102,500 101,500
2000 102,500 68,250
2001 102,500 16,750
2002 102,500 855
Thereafter 324,406 -
-------- --------
Total minimum lease payments 836,906 $454,105
========
Less: Amount representing
interest 232,084
--------
$604,822
========
I. Employee Benefits
Pension Plans
The Company has two pension plans covering substantially all
employees. The actuarial method for determining annual pension
cost is the Projected Unit Credit method.
34
Net pension cost for 1997, 1996 and 1995 consist of the following
components:
1997 1996 1995
Service cost - benefits
earned during the year $ 286,362 $ 268,542 $ 231,741
Interest cost on projected
benefit obligations 752,921 722,354 668,107
Actual return on plan assets (1,741,366) (1,125,838) (887,022)
Net amortization and deferral 1,134,587 609,010 412,504
---------- ---------- ---------
NET PENSION COST $ 432,504 $ 474,068 $ 425,330
========== ========== =========
The expected long-term rate of return on assets was 8.5 percent
in 1997, 1996 and 1995. The discount rate used in determining
the actuarial present value of the projected obligation was 7.5
percent in 1997 and 8.0 percent in 1996 and 1995. The expected
rate of pay increase was 5.0 percent in 1997 and 6.0 percent in
1996 and 1995.
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, 1997 and 1996:
1997 1996
Actuarial present value of benefit
obligations (in thousands):
Vested benefit obligation $ 9,257 $ 8,198
======= =======
Accumulated benefit obligation $ 9,817 $ 8,734
======= =======
Projected benefit obligation
for service rendered to date $10,689 $ 9,708
Plan assets, primarily listed stocks,
corporate bonds and U.S. bonds,
at fair value 10,212 9,083
------- -------
Projected benefit obligation in excess
of plan assets (477) (625)
Unrecognized net gain (1,586) (776)
Unrecognized prior service cost 1,635 1,399
Adjustment required to recognize
additional minimum liability (44) -
Unrecognized net obligation at transition (7) -
------- -------
Accrued pension liability $ (479) $ (2)
======= =======
Assets in the pension plan are currently held in mutual funds.
Employee Stock Ownership Plan
On September 1, 1986, the Company created an Employee Stock
Ownership Plan and Trust ("ESOP"). The Company contributes
annually to a trust an amount equal to principal plus interest
35
and any other fees net of interest income earned by the trust and
dividends on unallocated shares. The Trust was created primarily
to acquire shares of the Company's common stock for the exclusive
benefit of the participants (substantially all nonbargaining
employees). During fiscal 1987, the Trust borrowed $1,500,000
and acquired 82,800 shares, as adjusted for a two-for-one stock
split effective April 1, 1987, of the Company's previously
unissued common stock. The loan is guaranteed by the Company and
the final payment of $75,000 was due in October, 1996. The ESOP
was recorded as a liability and the offsetting debit was
accounted for as a reduction of common stock equity in the
accompanying consolidated balance sheets. Interest was payable
monthly at a floating rate which was 80 percent of the current
prime rate. The charge to income, which equals the Company's
contribution, for 1997 was $174,006 which includes 8,000
additional shares to be issued in early 1998, for 1996 was
$223,477, and for 1995 was $141,359. Interest on ESOP debt was
$839 for 1997, $8,055 for 1996 and $17,365 for 1995. Dividends
on unallocated ESOP shares used to pay debt service for all
periods presented was $5,699 for 1997, $12,738 for 1996 and
$27,193 for 1995.
Savings Plan
The Company has a thrift savings plan in which the Company
matches one-half of employee contributions with the match capped
at three percent. The Company contributed approximately $169,000
to the Plan in 1997, $132,000 to the Plan in 1996, and $119,000
to the plan in 1995.
Postretirement Benefits Other Than Pension
The Company follows 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. Prior to 1994, the cost of
postretirement benefits was recognized on a pay as you go basis.
The cumulative effect of the implementation of SFAS No. 106 as of
September 1, 1994 is being amortized over 20 years. The Company
is currently recovering the full SFAS No. 106 cost in rates.
The net periodic postretirement benefit cost for the year ended
August 31, 1997, 1996 and 1995 is as follows:
1997 1996 1995
Service cost $103,140 $104,469 $ 84,550
Interest cost 345,298 316,398 284,861
(Return) loss on plan assets (35,551) (22,610) 13,066
Net amortization and deferral 177,071 189,435 157,634
-------- -------- --------
TOTAL POSTRETIREMENT BENEFIT COST $589,958 $587,692 $540,111
======== ======== ========
36
The funded status of the Company's postretirement benefit plan
using a measurement date of July 1, 1997, 1996 and 1995 is as
follows:
1997 1996 1995
Accumulated postretirement benefit
obligation:
Retirees $(3,213,120) $(2,834,211) $(2,972,713)
Fully eligible active Plan
participants (162,946) (108,839) (118,200)
Other active Plan participants (1,481,702) (1,274,960) (1,264,135)
------------ ------------ ------------
(4,857,768) (4,218,010) (4,355,048)
Plan assets at fair value 1,386,073 886,580 557,939
Accumulated postretirement obligation ------------ ------------ ------------
greater than Plan assets (3,471,695) (3,331,430) (3,797,109)
Unrecognized transition obligation 3,261,880 3,465,748 3,669,616
Unrecognized (gain) loss 8,588 (310,951) (3,021)
------------ ------------ -----------
ACCRUED POSTRETIREMENT
BENEFIT COST $ (201,227) $ (176,633) $ (130,514)
============ ============ ===========
The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5 percent in
1997, 1996 and 1995. The annual increase in the cost of covered
health care benefits for 1997 was 8.75 percent and 7.0 percent
for participants under age 65 and over age 65, respectively, and
for 1996 and 1995 was 9.5 percent and 7.5 percent for
participants under 65 and over 65, respectively. This increase
gradually decreases to 5 percent in the year 2007 and thereafter.
A 1.0 percent increase in the assumed health care cost trend rate
would have increased the cost computed under SFAS 106 by $37,931
and increased the accumulated postretirement benefit by $443,713
as of August 31, 1997.
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 1997 and
1996 totaling $560,241 and $541,483, respectively. Assets in the
VEBA trusts are held in cash reserve accounts. Assets in the
subaccount to the pension plan are currently held in listed
stocks, corporate bonds and government bonds.
Stock Option Plans
In 1995 the Company adopted an Incentive Stock Option Plan and a
Non-Qualified Stock Option Plan (the Plans) under which options
may be granted to officers and key employees. Options for an
aggregate of 100,000 shares may be granted under the Plans with
not more than 25,000 shares granted during any one year to any
individual. During 1995, the Company granted a total of 20,000
shares under the Incentive Stock Option Plan and 4,000 shares
under the Non-Qualified Stock Option Plan at a price of $24.25
with exercise dates beginning February 9, 1996 and ending
February 9, 2000. No options were granted, exercised or expired
during either 1996 or 1997. At August 31, 1997, options covering
24,000 shares were outstanding and 9,600 were exercisable under
the Plans. In addition, 76,000 shares under the Plans are
available for future grants.
In October 1995, the Financial Accounting Standards Board issued
SFAS No. 123, Accounting for Stock-Based Compensation, which sets
forth a fair market value based method of recognizing stock-based
compensation expense. As permitted by SFAS No. 123, the Company
has elected to continue to apply APB No. 25 to account for its
stock option plans. Had compensation cost for awards in fiscal
1995, 1996 and 1997 under the Company's Incentive Stock Option
Plan and Non-Qualified Stock Option Plan been determined based on
the fair market value at the grant dates consistent with the
method set forth under SFAS No. 123, the effect would have been
as follows:
37
1997 1996 1995
Net income:
As reported $3,966,519 $3,835,500 $3,179,778
Pro forma $3,958,518 $3,821,855 $3,166,977
Earnings per share:
As reported $ 2.38 $ 2.36 $ 2.00
Pro forma $ 2.37 $ 2.35 $ 1.99
The fair value of each option granted is estimated on the grant
date using the Black-Scholes option pricing model. The weighted
average grant date fair value of options granted was $1.88. In
computing the above pro forma amounts the Company has assumed a
risk-free interest rate of 6.2 percent, an expected life of 4
years, an expected volatility of 11.5 percent and an expected
dividend yield of 6.2 percent.
J. Commitments and Contingencies
Construction Expenditures
The Company's construction expenditures in connection with its
continuing construction program are presently estimated at
$7,000,000 for 1998, $8,000,000 for 1999, and approximately
$7,000,000 in each of the following three years.
Gas Supply, Transportation and Storage
The Company has various long-term gas supply, transportation and
storage contracts with minimum cost provisions. Under these
contracts, the Company is obligated to make specified minimum
payments. Based on current rates and/or agreements, the minimum
annual payments under these contracts are as follows:
1997 to 2000
Pipeline Transportation Demand $ 3,859,635
Underground Storage Demand 458,945
Underground Storage Transportation 707,937
Pipeline Gas Inventory Charge 2,847,048
Gas Supply Realignment Charges 401,464
----------
$ 8,275,029
----------
FERC Order 636 allows the pipeline companies to recover transi
tion 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, 1997, the transition
costs are estimated at $401,000 and will be billed in fiscal 1998
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.
38
Litigation Matters
The Company is a defendant in various civil actions, which are
covered by insurance and reserves. Based on the advice of legal
counsel, management believes that the Company has adequate
defenses against these claims and, in view of the insurance
coverage, the potential liability would not materially effect
the financial condition or the results of operations of the Company.
Environmental Matters
The Company has received notification that the Massachusetts
Department of Environmental Protection ("MDEP"), has reason to
believe that the Company may be a potentially responsible party,
along with several other parties, with respect to alleged release
of hazardous materials at sites in Plympton, Massachusetts. The
Company does not currently have sufficient information to
reasonably estimate the amount of the final liability for cleanup
costs or other damages or expenses at such sites. The Company
believes it should be permitted to recover these costs through
rates.
The Company or its predecessors previously operated four
manufactured gas plants and one storage facility (collectively,
"MGPs") at sites in Massachusetts. It is possible that in the
manufacturing process some or all of the MGPs may have discharged
certain substances on the sites which may now be deemed to be
hazardous. The Company has not ascertained the extent of any
hazardous substance contamination on these sites from the MGP
operations. The Environmental Protection Agency ("EPA") and MDEP
have recently begun to focus on the potential environmental
hazards of MGPs. To the Company's knowledge, neither the EPA nor
the MDEP have issued any orders to clean up any of the Company's
MGP sites. In 1995 an investigation which reported the presence
of certain compounds was conducted at one of the Company's MGP
sites. As a result, a second, more intensive investigation was
conducted in fiscal 1997 to determine the level of contamination
and to assess whether any remediation was required. The Company
had also been informed that certain materials had been discovered
on properties adjacent to a second site currently owned by the
Company. These adjacent properties have been classified by the
MDEP as a location to be investigated. Based on preliminary
investigation, the Company currently believes that it may not be
liable for cleanup costs associated at the adjacent properties
unless such liability is based on down-gradient status; however,
the Company may be liable for cleanup costs associated with the
parcel presently owned by the Company. The Company does not
currently possess sufficient information to determine the
probability or the cost of the potential remediation, however,
the MDPU provides for the recovery through the CGA of all
environmental response costs associated with this and any other
MGP sites over seven-year amortization periods without a return
on the unamortized balance. The 1990 MDPU agreement also
provides for no further investigation on the prudency of any
Massachusetts gas utility's past MGP operations.
39
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To: The Board of Directors of Essex County Gas Company
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Essex County Gas Company (a
Massachusetts corporation) as of August 31, 1997 and 1996, and
the related consolidated statements of income, retained earnings
and cash flows for each of the three years in the period ended
August 31, 1997. 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, 1997 and
1996, and the results of its operations and its cash flows for
each of the three years in the period ended August 31, 1997, in
conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the
basic financial statements taken as a whole. The schedule listed
in the index to consolidated financial statements is presented
for purposes of complying with the Securities and Exchange
Commission's rules and is not a part of the basic financial
statements. The schedule has been subjected to the auditing
procedures applied in the audits of the basic financial
statements and, in our opinion, fairly state, in all material
respects, the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
October 24, 1997
40
Item 8: Financial Statements and Supplementary Data
(b) Selected Quarterly Financial Data
YEAR ENDED AUGUST 31, 1997
Three Months Ended
________________
November 30, February 28, May 31, August 31,
1996 1997 1997 1997 Total
Operating revenues $8,142,501 $23,220,840 $16,659,598 $5,511,795 $53,534,734
Operating income 471,157 3,814,227 1,971,507 464,672 6,721,563
Income (loss)
applicable to
common shares (260,669) 3,131,438 1,256,125 (160,375) 3,966,519
Earnings (loss) per
common share (.16) 1.89 .75 (.10) 2.38
Dividends declared per
common share .40 .41 .41 .41 1.63
Stock price range:
High 27.00 25.75 26.00 27.00
Low 24.00 24.25 24.25 25.25
YEAR ENDED AUGUST 31, 1996
Three Months Ended
November 30, February 29, May 31, August 31,
1995 1996 1996 1996 Total
Operating revenues $ 6,962,014 $22,632,458 $15,546,131 $ 4,788,786 $49,929,389
Operating income 536,242 3,701,969 1,733,463 697,316 6,668,990
Income (loss)
applicable to
common shares (208,087) 2,973,836 1,054,867 14,884 3,835,500
Earnings (loss) per
common share (.13) 1.83 .65 .01 2.36
Dividends declared
per common share .39 .40 .40 .40 1.59
Stock price range:
High 25.50 27.38 26.25 25.75
Low 24.25 25.00 23.50 23.00
41
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 1, 1997, for the Annual Meeting of
Stockholders to be held on January 20, 1998, under the caption
"Nominees for Director"; "Board of Directors and Committees"; and
"Section 16(a) Beneficial Ownership Reporting Compliance."
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 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Directors'
Compensation"; "Executive Compensation"; "Employee Plans and
Agreements - Pension Plan Table"; and "Compensation Committee
Report on Executive Compensation".
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 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Securites
Ownership of Certain Beneficial Owners and Management".
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 1, 1997, for the Annual Meeting of Stockholders to
be held on January 20, 1998, under the caption "Compensation
Committee Interlocks and Insider Participation" and "Certain
Transactions."
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 23
through 38, and the Report of Arthur Andersen LLP on page
39 therein.
2. Financial Statement Schedules.
The following supplementary financial statement
schedules required by Rule 5-04 of Regulation S-X, and report
42
thereon, are filed as part of this Form 10-K on the page
indicated below:
Schedule Page No. in
Number Description this Report
II Consolidated Valuation and Qualifying Accounts
for the three years ended August 31, 1997 42
Report ofIndependent Public Accountants 39
Schedules other than the one listed above are either not
required or not applicable, or the required information is
shown in the financial statements or notes thereto.
3. Exhibits required by Item 601 of Regulation S-K.
See Exhibit Index on pages 44 through 47.
B) Reports on Form 8-K.
No reports on Form 8-K have been filed during the quarter
ended August 31, 1997.
C) Exhibits required by Item 601 of Regulation S-K.
See Exhibit Index on pages 44 through 47.
D) Financial Statement Schedules.
CONSOLIDATION VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Reserves which are deducted in the balance sheets from
assets to that they supply
Charged Charged
Balance at to to Balance
Year ended beginning costs and other at end of
August 31 Description of period expenses accounts(1) Deductions period
1997 Allowance for
doubtful accounts $653 $614 $167 $662 $772
1996 Allowance for
doubtful accounts $595 $613 $164 $719 $653
1995 Allowance for
doubtful accounts $804 $422 $230 $861 $595
__________________________________________
(1)Represents recoveries on accounts previously written off
43
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, as amended, the registrant has
caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
ESSEX COUNTY GAS COMPANY
(Registrant)
Date: November 25, 1997 by /s/ James H. Hastings
Vice President and Treasurer
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, this report has been signed below by the
following persons in the capacities and on the dates indicated.
Signature Title Date
/s/ Charles E. Billups Chairman of the Board
/s/ Philip H. Reardon President and
Chief Executive Officer
/s/ James H. Hastings Vice President and Treasurer
(Principal Financial and
Accounting Officer)
/s/ Benjamin C. Bixby Director
/s/ Daniel A. Burkhardt Director
/ / Edward J. Curtis Director
/s/ Dorothy J. Dotson Director
/s/ Richard P. Hamel Director
/s/ Robert S. Jackson Director
/s/ Eric H. Jostrom Director
/ / Robert L. Meade Director
/s/ Kenneth L. Paul Director
/s/ Richard L. Wellman Director
44
Exhibit Index
The exhibits listed below are filed herewith or are incorporated
by reference to other filings.
Exhibit
Number Description
3.1 Restated Articles of Organization of Essex County
Gas Company.10
3.2 Bylaws of Essex County Gas Company.11
4.1 Indenture dated as of June 1, 1986 between the Company and
Centerre Trust Company of St. Louis, Trustee.2
4.2 Eleventh Supplemental Indenture dated as of September 15,
1988, providing for a 10 1/4 percent Series due 2003.1
4.3 Twelfth Supplemental Indenture dated as of December 1,
1990, providing for a 10.10 percent series due 2020.4
4.4 Revolving Credit Agreement dated November 14, 1995 between
Essex County Gas Company and the First National Bank of Boston.12
4.5 Fifteenth Supplemental Indenture dated as of December 1,
1996 providing for a 7.28 percent Series due 2017.13
10.1 LNG Storage, Inc., Lease Indenture of Mortgage and Deed of
Trust dated April 10, 1972.1
10.2 Haverhill Familee Investment Corporation - Lease of
Corporate Headquarters dated November 1, 1975.1
10.3 Arlington Trust Company - Purchase Contract, Credit
Agreement, Trust Agreement and Storage Agreement
dated October 1, 1980.1
10.4 Consolidated Gas Supply Corporation - Underground Storage
Contract dated February 18, 1980.1
10.5 Penn-York Energy Corporation - Storage Services Agreement
dated December 21, 1984.1
10.6 Canadian Gas Transportation Contract between Tennessee Gas
Pipeline Company and Essex County Gas Company dated
December 1, 1987.3
45
Exhibit
Number Description
10.7 Phase 2 Gas Sales Agreement between Boundary Gas and Essex
County Gas Company dated September 14, 1987.3
10.8 Amendment to the Agreement for the Sale of Gas between Bay
State Gas Company and Essex County Gas Company dated May 6, 1988.3
10.9 Agreement for the Liquefaction of Gas between Bay State Gas
Company and Essex County Gas Company dated March 14, 1988.3
10.10 Bond Purchase Agreement dated December 1, 1990,
between Allstate Life Insurance Company of New
York, and Essex County Gas Company.4
10.11 Iroquois Gas Transmission System, L.P. Gas
Transportation Contract for Firm Reserved Service
dated February 7, 1991.3
10.12 Alberta Northeast Gas Limited (ANE), Gas Sales
Contract Agreement No. 1 dated February 7, 1991.5
10.13 Aquila Energy Marketing Corporation Gas Sales
Agreement dated June 5, 1992.5
10.14 Natural Gas Clearinghouse Gas Sales Agreement dated
June 8, 1992.5
10.15 Tennessee Gas Pipeline Transportation Contract dated
February 7, 1991.6
10.16 Tennessee Gas Pipeline Company Gas Storage Contract
(SS-NE) TGP002099STO dated November 10, 1991.6
10.17 Tennessee Gas Pipeline Company Storage Service
Transportation Contract TF-4175 dated October 28, 1991.6
10.18 Form of employment agreement between the Company and
each of the following officers: Wayne I. Brooks,
Vice President; John W. Purdy, Jr., Vice President; James H.
Hastings, Vice President and Treasurer; Allen R. Neale,
Vice President; and Cathy E. Brown, Clerk. These contracts are
identical to those submitted with the Annual Report for
each with the exception of compensation amounts.2*
10.19 Employment Agreement between the Company and Philip H. Reardon,
President, dated November 19, 1992.7*
10.20 Gas Transportation Agreement between Essex County Gas Company and
Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule)
dated September 1, 1993.8
46
Exhibit
Number Description
10.21 Gas Transportation Agreement between Essex County Gas
Company and Tennessee Gas Pipeline Company (for use
under FT-A Rate Schedule) dated August 25, 1993.8
10.22 Gas Transportation Agreement between Essex County Gas
Company and Tennessee Gas Pipeline Company (for use
under Transportation Service "CGT-NE" Rate
Schedule) dated September 1, 1993.8
10.23 Gas Transportation Agreement between Essex County Gas
Company and Tennessee Gas Pipeline Company (for use
under FT-A Rate Schedule) dated September 1, 1993.8
10.24 Gas Transportation Agreement between Essex County Gas
Company and Tennessee Gas Pipeline Company (for use
under Rate Schedule FS) dated September 1, 1993.8
10.25 Amendment to Employment Agreement between the Company
and Philip H. Reardon, President, dated March 3, 1994.*
10.26 Amendment to Employment Agreement between the Company
and John W. Purdy, Jr., Vice President, dated March 3, 1994.*
10.27 Amendment to Employment Agreement between the Company
and Wayne I. Brooks, Vice President, dated March 3, 1994.*
10.28 Amendment to Employment Agreement between the Company
and Allen R. Neale, Vice President, dated March 3, 1994.*
10.29 Amendment to Employment Agreement between the Company
and James H. Hastings, Vice President and Treasurer,
dated March 3, 1994.*
10.30 Amendment to Employment Agreement between the Company
and Cathy E. Brown, Corporate Clerk, dated March 3, 1994.*
10.31 Essex County Gas Company Supplemental Retirement Plan
for Philip H. Reardon effective January 1, 1994.*
10.32 Employment Agreement between the Company and William
T. Beaton, Vice President, dated June 7, 1995.*
27 Financial Data Schedule.
B) Reports on Form 8-K.
No reports on Form 8-K have been filed during the quarter
ended August 31, 1997.
*Denotes Management Contract.
47
1Previously filed as an exhibit to Registrant's Registration
Statement on Form S-7, filed October 23, 1981, File No. 2-74531
and is incorporated herein by this reference.
2Previously filed as an exhibit to Registrant's Registration
Statement on Form S-2, filed June 19, 1986, File No. 33-6597
and is incorporated herein by this reference.
3Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter ended February 29, 1996, and is incorporated herein by
this reference.
4Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter ended February 28, 1991, and is incorporated herein by this
reference.
5Previously filed as an exhibit to Registrant's 10-Q filed for the
quarter ended May 31, 1992, and is incorporated herein by this reference.
6Previously filed as an exhibit to Registrant's 10-K filed for the
fiscal year ended August 31, 1992, and is incorporated herein by
this reference.
7Previously filed as an exhibit to Registrant's Form S-3, No.
33-69736, filed on September 30, 1993, and is incorporated herein
by this reference.
8Previously filed as an exhibit to Registrant's Form 10-K filed for
the fiscal year ended August 31, 1993, and is incorporated herein
by this reference.
9Previously filed as an exhibit to Registrant's Form 10-Q filed for
the quarter ended May 31, 1996 and is incorporated herein by this
reference.
10Previously filed as an exhibit to Registrant's Form 10-Q filed for
the quarter ended February 28, 1995 and is incorporated herein by
this reference.
11Previously filed as an exhibit to Registrant's Form 10-Q filed for
the quarter ended May 31, 1997 and is incorporated herein by this
reference.
12Previously filed as an exhibit to Registrant's Form 10-Q filed for
the quarter ended November 30, 1996 and is incorporated herein by
this reference.
13Previously filed as an exhibit to Registrant's Form 10-Q filed for
the quarter ended February 28, 1997 and is incorporated herein by
this reference.