Item 1: Business
General
The Company, a regulated public utility organized under the laws of the Commonwealth of Massachusetts in 1853, purchases, distributes and sells natural gas to residential, commercial and light industrial customers in northeastern Massachusetts. The Company operates in the cities of Haverhill, Newburyport, Amesbury and fourteen smaller municipalities covering an area of approximately 280 square miles. The year-round population of the Company's service area was approximately 165,000 in the 1990 Census.
The Company's service area is primarily comprised of residential communities with a number of small commercial and diversified light industrial businesses. The local economy, not unlike economic conditions in general, had been weak with a resultant slowdown in new construction, especially commercial construction during the early 1990s. However, during the last few years there has been a significant increase in new residential construction. New home construction activity significantly impacts the degree to which the Company is able to grow its customer base.
Sales and Customer Data
The Company sells natural gas to over approximately 42,000 customers in its service area. Residential users of natural gas generally experience their highest level of consumption for heating purposes during the winter months. Accordingly, the Company's sales and operating revenues are sensitive to the severity of the weather. The Company's rates are designed to recover added costs associated with peak operations during the winter months. In fiscal 1996, the Company's total operating revenues were $49,929,389 of which approximately 63.8% was derived from residential customers, 29.7% from commercial and industrial customers, 4.5% from interruptible customers and 2.0% from other sources. During this period, the Company sold 6,561,365 thousand cubic feet of gas (Mcf), of which approximately 55.5% was purchased by residential customers, 31.1% by commercial and industrial customers and 13.5% by interruptible customers. Losses and company use amounted to 87,501 Mcf for 1996.
Set forth in the following table is information by customer classification showing operating revenues, gas delivered and number of customers for the periods indicated.
Fiscal Year Ended August 31,
1996 1995 1994 1993 1992 (Dollars and Mcfs in Thousands)
Operating Revenues: Residential-general $ 2,208 $ 2,159 $ 2,291 $ 2,160 $ 2,070 Residential-heating 29,644 26,589 29,245 27,218 25,150 Commercial and Industrial 14,838 13,353 15,000 14,006 13,432 Interruptible 2,216 1,933 888 653 1,316 Other 1,023 1,016 1,112 979 945 ------- ------- ------- ------- ------- Total $49,929 $45,050 $48,536 $45,016 $42,913 ======= ======= ======= ======= ======= Gas Delivered (Mcf): Residential-general 151 148 159 158 158 Residential-heating 3,489 3,045 3,325 3,228 3,083 Commercial and Industrial 2,038 1,843 2,014 1,948 1,927 Interruptible 883 915 389 273 669 ------- ------- ------- ------- ------- Total Sales 6,561 5,951 5,887 5,607 5,837 Losses and Company Use 88 86 79 89 101 Total 6,649 6,037 5,966 5,696 5,938 ======= ======= ======= ======= ======= Number of Customers at Year-End: Residential-general 7,328 7,369 7,560 7,439 6,776 Residential-heating 30,025 29,028 28,093 27,434 27,522 Commercial and Industrial 4,173 4,125 3,961 3,884 3,863 Interruptible 2 2 2 2 2 ------- ------- ------- ------- ------- Total 41,528 40,524 39,616 38,759 38,163 ======= ======= ======= ======= ======= Effective Degree Days (20-Year Average: 6,813) 6,947 6,258 7,012 6,956 6,750
The Company's residential customers are classified as either general or heating customers. In fiscal 1996, residential-heating customers accounted for approximately 59.4% of total operating revenues, while residential-general customers accounted for approximately 4.4% of total operating revenues. Operating revenues from residential customers increased approximately 10.8% to $31,852,683 in fiscal 1996 from $28,747,790 in fiscal 1995. The sales increase was attributable to the relatively colder winter in fiscal 1996 compared to fiscal 1995 as residential volumes increased 14.0%. The average rate charged to residential customers per Mcf of gas was $8.75 and $9.00 in fiscal 1996 and 1995, respectively. The decrease in fiscal 1996 was primarily attributable to lower gas costs incurred by the Company due to the return to customers of pipeline supplier refund and previously overcollected gas costs.
The Company's commercial and industrial firm revenues increased approximately 11.1% to $14,837,612 in fiscal 1996 from $13,353,053 in fiscal 1995. The increase was attributable to a 10.6% volume increase and a 0.4% increase in the average price charged per Mcf of gas from $7.25 to $7.28. The sales increases were largely attributable to colder weather experienced during the winter in fiscal 1996 as compared to fiscal 1995.
The Company has two interruptible customers, only one of which purchased significant amounts of gas from the Company in fiscal 1996. Total interruptible revenues in fiscal 1996 were $2,215,677 compared to $1,932,751 in fiscal 1995. Sales of gas to interruptible customers do not materially affect the Company's operating income because the Company is required to return all gross profit on such sales to the Company's firm customers unless interruptible volumes exceed a certain threshold specified by the Massachusetts Department of Public Utilities ("MDPU"). Once that threshold is attained, the Company may retain 10% of gross profits. The threshold was attained in fiscal 1996 with approximately $5,000 retained by the Company. Any gross profit returned to the customers is returned through a Cost of Gas Adjustment ("CGA") under which the Company is permitted to recover its gas costs. The average price charged by the Company to interruptible customers was $2.51 per Mcf and $2.11 per Mcf in 1996 and 1995, respectively.
The Company's largest customer purchases gas on an interruptible basis and accounted for approximately 3.0% of operating revenues on average over the past three fiscal years ended August 31, 1996. Sales to that customer in 1996 totaled $2,201,142 or 4.4% of total Company operating revenues. Since most of the gross profit earned on interruptible sales is returned to firm customers, the Company believes that the loss of its largest on any single customer would not have a material effect on the Company's results of operations.
In addition to its principal business of gas sales, the Company rents water heaters and conversion burners and performs service work. Net revenues from rental operations and service work represented less than 2.2% of the total operating revenues of the Company over the past three years ended August 31, 1996.
During 1996, the Company added over 1,200 new customers. In fiscal 1995 and 1994, new customer additions (which approximated gross additions) were 1168 and 1013, respectively.
Gas Supply
The Company contracts for its gas supply on the basis of forecasted demand which is derived from historical weather patterns recorded since 1960. The maximum peak day demand during the last five fiscal years was 46,768 Mcf on February 6, 1995. Maximum peak day demand for 1996 was 46,017 Mcf and on February 4, 1996 peak day demand was 45,500 Mcf. The Company has the ability to meet a peak day demand of
approximately 65,000 Mcf. peak day demand for gas is affected by numerous factors, including the severity of the weather and the number of firm customers. Total gas sendout by the Company in fiscal 1996 was 6,648,866 Mcf compared to 6,037,442 Mcf in 1995 and 5,965,627 in fiscal 1994. The following table shows the sources of the Company's gas supply requirements for the periods indicated.
Fiscal Years Ended August 31, 1996 1995 1994 1993 1992
Gas Supply (Mcf): Natural gas delivered directly by pipeline 5,172,708 4,844,912 4,780,294 4,222,801 5,344,754 Underground storage withdrawn 1,035,011 820,493 820,102 1,271,670 459,594 Liquefied natural gas produced 441,147 372,037 365,231 201,439 133,171 --------- --------- --------- --------- --------- Total 6,648,866 6,037,442 5,965,627 5,695,910 5,937,519 ========= ========= ========= ========= =========
For the year ended August 31, 1996, approximately 77.8% of the Company's gas supply was delivered by Tennessee Gas Pipeline Company ("TGPC"), a division of Tenneco, with supplemental sources supplying the remainder.
The Company has a firm transportation contract with TGPC which provides for daily delivery of 15,728 dekatherms ("DTH") (each DTH is approximately 0.975 Mcf) through November 1, 2000. TGPC is currently delivering such quantities on a firm basis as authorized by the Federal Energy Regulatory Commission ("FERC"). In connection with the implementation of FERC Order 636, the Company has converted its natural gas purchase contract with TGPC into several firm gas supply contracts directly with other gas suppliers. These long-term contracts have been approved by the MDPU. All contracts are with major suppliers that have a demonstrated track record of performance and are at market sensitive prices. In addition to contracts with Aquila Energy and Natural Gas Clearinghouse for 2,500 DTH each per day for nine years, the Company, through the efforts of the Mansfield Consortium, negotiated contracts with Tenngasco for 4,410 DTH per day expiring October 31, 1999; Enron for 4,409 DTH per day expiring October 31, 1999; and Natural Gas Clearinghouse for an additional 1,909 DTH per day expiring September 1, 2002, to complete its transition under FERC Order 636. See "Item 1: Business--Regulatory Matters--FERC Matters".
The Company also purchases gas from Boundary Gas, Inc. ("Boundary"). Pursuant to a supply contract with Boundary expiring on January 15, 2003, the
Company may take up to a maximum of 1,610 Mcf per day from Boundary and may purchase up to 587,650 Mcf per year, the annual quantity limitation for the contract. The Company began in January 1988 taking up to a maximum of 1,610 Mcf per day. Pursuant to a supply contract with Boundary, the Company is required to purchase 75% of this maximum amount per year or its daily capacity will be reduced proportionately based on the level actually taken by the Company during such year. The Company purchased 569,346 Mcf in fiscal 1996 or 96.9% of the annual quantity limitation. The Company has a firm transportation contract with TGPC for the delivery of the Boundary supply.
The Company also purchases gas from Alberta Northeast Limited ("ANE"). In December 1991, the Company began to receive deliveries of 2,000 Mcf per day (approximately 2,051 DTH per day) of this Canadian gas from ANE after ANE received approvals from the National Energy Board of Canada and the Economic Regulatory Administration of the United States. Under its contract with ANE, the Company may purchase up to 717,193 Mcf per year (approximately 735,583 DTH per year), the annual quantity limitation for the contract. The contract requires the Company to purchase at least 60% of the annual quantity limitation per year or its daily capacity will be reduced proportionately based on the level actually taken by the Company during such year. The Company purchased approximately 710,085 Mcf in fiscal 1996 or 99.0% of the contracted amount in fiscal year 1996. The Company has firm transportation contracts with the Iroquois Pipeline and TGPC for the delivery of the above-mentioned volumes.
The Company has three contracts for underground storage with a total storage capacity of approximately 1,461,868 Mcf. The Company used a total of 1,035,011 Mcf, including 37,308 Mcf of fuel gas, of its total underground storage in fiscal 1996.
Under a contract expiring November 1, 2000, the Company assumed its pro rata share of TGPC underground storage. The Company received storage capacity of 780,928 DTH and 5,172 DTH per day of deliverability, as well as the ability to fill the storage with gas obtained from any supplier. This service augments the Company's ability to meet high delivery demand in the winter and to take advantage of lower off-season gas prices.
The Company also has a contract expiring April 1, 2000 for underground storage with Consolidated Supply Corporation for a total volume of 359,450 DTH. The contract is backed by a transportation contract with TGPC for the same period, which provides for the withdrawal from storage and delivery to the Company of up to 3,268 DTH per day (approximately 3,186 Mcf per day) on a firm basis.
The Company's third contract for underground storage is with National Fuel Gas Supply ("National Fuel") and extends through March 31, 1997. The total storage volume under this contract is 350,000 Mcf, and the maximum daily withdrawal is 3,182 Mcf. The contract is backed by a transportation contract with TGCP which has been authorized by FERC to deliver to the Company approximately 787 Mcf per day from this storage facility on a firm basis and the balance on a "best efforts" basis. The Company has notified National Fuel that it is terminating the contract as of March 31, 1997. In order to replace the capacity of the National Fuel contract, the Company has entered into an agreement with Distrigas of Massachusetts Corporation ("DOMAC"), which expires
October 31, 2006, that allows the Company to purchase up to 4,000 DTH/day for 151 days of Liquid Natural Gas as either a liquid or a vapor. The Company, at its discretion, may increase purchases under the contract by up to an additional 2,000 DTH/day after appropriate notice. The Company may also reduce quantities purchased if normal sales dip below the normal 1994-95 heating season sendout.
These underground storage arrangements allow the Company to maximize firm gas supply purchases while allowing the Company to take full advantage of the spot market gas prices during the summer and other periods when such gas is not required to meet customer demands. The stored gas is withdrawn during periods of high demand to assist the Company in meeting firm delivery requirements.
Through a wholly owned subsidiary, the Company owns a liquefied natural gas ("LNG") storage facility located in Haverhill, Massachusetts. The LNG storage facility has a storage capacity of 400,000 Mcf and has a daily sendout capacity of 30,000 Mcf. In fiscal 1996, sendout of LNG totaled 441,147 Mcf. At the same location, the Company owns and operates a propane plant that has a storage capacity equivalent of approximately 40,000 Mcf with a total daily sendout capacity of 7,000 Mcf. In fiscal 1996, there was no sendout of propane. Due to the comparible cost of LNG and propane compared to pipeline and underground storage, the Company uses these fuels primarily to satisfy peak winter demand.
Under an agreement with Bay State Gas Company which expired October 31, 1996, the Company was required to purchase 50,000 Mcf of LNG during each summer period and approximately 110,000 Mcf during each winter period with an option to purchase an additional 37,000 Mcf during each winter period. This contract was replaced by the contract with DOMAC discussed above.
Based on current information concerning pipeline and supplemental gas supplies, the Company expects to meet the gas requirements of its firm customers for the foreseeable future.
Competition
The Company has no direct competition with respect to the retail distribution of natural gas by pipeline in its service territory. Massachusetts law effectively protects gas companies from such competition. Where a gas company exists in active operation in Massachusetts, no other person may construct underground gas mains in the public ways without the approval, after notice and hearing, of the municipal authorities and, in certain circumstances, the MDPU. If a municipality desires to enter the gas business, it must take certain procedural steps, including obtaining a favorable vote by a majority of the voters at its town meeting. The municipality would then be required to purchase the utility plant of any gas company operating in the area at an agreed-upon price. If no agreement was reached, the MDPU would make the final determination. Management of the Company is not aware of any municipality in its service area which currently desires to enter the gas distribution business.
The Company faces a changing competitive market for natural gas. The Company's gas business competes principally with oil for industrial boiler uses and oil and electricity for residential and commercial space heating. Competition is primarily based on price. In addition, the MDPU required the Company to submit, for approval, rates dealing with transportation of third-party gas which will enable large volume customers to acquire natural gas from sources other than Essex County Gas. Although the Company has received approval for these rates, to date no customer has selected this option.
While the current retail price of natural gas is equal to or slightly higher than the retail price of oil for residential space heating customers, natural gas is the fuel of choice for most new residential construction. Natural gas has significant environmental, operational and maintenance advantages over oil. Additionally, most of the Company supply of natural gas is from North American sources. Since the mid-1970's, the retail cost of heating residential space by natural gas in the Company's service territory has been approximately the same, or slightly higher than, the comparable cost of heating by oil. There is no assurance what, if any, the relative price differential between natural gas and oil will be in the future. Natural gas has a significant price advantage over electricity supplied by investor-owned and municipal electric utilities in the Company's service territory.
In the Company's service territory, the cost of heating with natural gas for commercial and industrial customers is relatively competitive with the cost of heating with oil. Approximately 50 of the Company's commercial and industrial customers have dual heating facilities that enable them to switch freely between natural gas and oil. As of August 31, 1996, the majority of the Company's dual fuel customers were using oil.
Regulatory Matters
State
The Company is subject to the regulatory authority of the MDPU with respect to the issuance of securities, accounting practices, rates, service, contracts for the purchase of gas, territories served and related matters.
Since 1987, the Company has filed five requests for rate increases and has been granted a total of $8,030,791 in rate relief by the MDPU, which amounts to 61.7% of the total requested. The Company's most recent rate increase request was filed in fiscal 1996 and approved in fiscal 1997. The Company's fiscal 1996 rate increase request was for an annualized increase of approximately $3,400,000 and the MDPU approved an annualized rate increase of approximately $2,100,000. The rate increase will be effective December 1, 1996.
The MDPU permits Massachusetts gas companies to utilize a CGA that permits a gas company to pass on to firm customers (on a current basis) increases or decreases in the cost of gas supplies. Profits from interruptible sales and gas supplier refunds are also passed on to firm customers through the CGA and no portion of the interruptible profits are retained by the Company unless certain volumes are sold. Supplemental fuel
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.
The Company, or its predecessors, previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. Each of these facilities has been out of operation for more than 25 years. It is possible that, during the manufacturing process, some or all of the MGPs may have discharged certain substances on the sites which may now be deemed hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The Environmental Protection Agency ("EPA") and Massachusetts Department of Environmental Protection ("MDEP") are focusing on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. Investigations which reported the presence of certain compounds were conducted at two of the Company's MGP sites. As a result, a second, more intensive investigation will be conducted in 1996 to determine the level of contamination and to assess whether any remediation is required. The Company has also been informed that certain materials have been discovered on properties adjacent to a second site currently owned by the Company. These adjacent properties have been classified by the MDEP as a location to be investigated. Based on preliminary investigation, the Company currently believes that it may not be liable for cleanup costs associated at the adjacent properties unless such liability is based on down-gradient status; however, the Company may be liable for cleanup costs associated with the parcel presently owned by the Company. The Company does not currently possess sufficient information to determine the probability or the cost of the potential remediation, however, the MDPU provides for the recovery through the CGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. A 1990 MDPU agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations.
In 1990, the Company received notification from the MDEP that the MDEP has reason to believe that the Company may be a potentially responsible party, along with several others, with respect to certain metal salvaging sites. See the Footnotes to the Company's Financial Statements.
Pipeline Safety Matters
The DOT's Office of Pipeline Safety, from time to time, issues safety regulations pertaining to the installation, testing and repair of underground gas mains and related gas distribution facilities by pipeline and gas distribution companies. While the regulations may increase the Company's expenses, the Company does not believe such regulations will have a material adverse effect on its operating expenses or its construction plans for the foreseeable future.
Construction by a Massachusetts gas company of any manufacturing or storage facility or pipeline having a pressure in excess of 100 pounds per square inch and a length greater than one mile requires approval by the Energy Facilities Siting Board, a division of the MDPU created for the purpose of implementing energy policies designed to provide energy supply with a minimum impact on the environment and at the lowest possible cost. Compliance with the procedures of this Board and other environmental laws and regulations may result in construction delays or increased costs with respect to future expansion. The Company does not presently have any construction plans that would require the approval of the Board.
Personnel
On August 31, 1996, the Company had 127 permanent employees, including two part time, 74 of whom were represented by the United Steelworkers of America, AFL-CIO-CLC, Local 12086. The current three-year labor contract with the Steelworkers covering all hourly workers extends through February 4, 1999.
Item 2:
Item 2: Properties
The Company's property consists primarily of its distribution system and related facilities. As of August 31, 1996, the Company had approximately 750 miles of gas mains and 37,500 gas services as well as meters, measuring and regulator station equipment, and rental equipment on customers' premises. The Company also owns a propane plant with a storage capacity of 40,000 Mcf. In addition, the Company, through its wholly owned subsidiary, LNG Storage, Inc., owns an LNG storage facility with a storage capacity of 400,000 Mcf.
On August 31, 1996, the Company's gross utility plant amounted to $98,603,784 at historical cost.
Substantially all of the properties owned by the Company, other than expressly exempted property, are subject to a lien under the indenture securing the Company's First Mortgage Bonds. The Company's gas supply contracts have also been assigned as collateral security for the Company's First Mortgage Bonds. The indenture calls for a trustee or receiver to take possession of the property if there is a default under its terms. The property exempted from the lien includes cash, receivables, supplemental fuel inventories, materials and supplies, rental appliances, office furniture and equipment and an LNG storage facility. The LNG storage facility, while unencumbered with respect to the Company's First Mortgage Bonds, is encumbered by a separate mortgage note.
The Company leases its corporate headquarters building and distribution facilities. The lease agreement is scheduled to expire in October 2005. Annual rental payments amount to $102,500. The Company also has a division office that is rented under an agreement scheduled to expire on May 31, 1997.
Item 3:
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:
Item 4: Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5:
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters
The Company's Common Stock is traded on the Nasdaq/NMS under the symbol "ECGC." On October 1, 1996, the Common Stock was held by 1,336 stockholders of record. The following table sets forth, for the quarters indicated, the high and low sale prices as reported by Nasdaq/NMS, and the cash dividends per share declared in such quarters.
Cash Dividends Market Price Per Share High Low Fiscal Year Ended August 31, 1995 First Quarter $25.50 $24.25 $0.38 Second Quarter 25.25 23.50 0.39 Third Quarter 25.50 22.50 0.39 Fourth Quarter 25.50 22.50 0.39 Fiscal Year Ended August 31, 1996 First Quarter 25.50 24.25 0.39 Second Quarter 26.75 25.00 0.40 Third Quarter 26.25 23.50 0.40 Fourth Quarter 25.50 23.50 0.40 Fiscal Year Ending August 31, 1997 First Quarter 27.00 24.50 0.40* (through November 10, 1996)
*Paid on October 1, 1996 to shareholders of record on September 14, 1996.
The Company has paid regular dividends since 1914. Common Stock dividend payments in fiscal 1996 totaled $1.59 per share, as compared to $1.55 in fiscal 1995. Although the Company expects to continue to pay dividends at or near the current rate for the foreseeable future, the declaration of future dividends will be at the direction of the Company's Board of Directors and dependent on business conditions, earnings, contractual restrictions and cash requirements of the Company.
Item 6:
Item 6: Selected Financial Data
The following table sets forth certain selected consolidated financial data of the Company and its subsidiaries and the ratio of earnings to fixed charges for, or as of the end of, the five fiscal years ended August 31, 1996. Due to the seasonal nature of the Company's business, a substantial portion of the Company's operating revenues are derived from operations during the second and third quarters of each fiscal year. The selected consolidated financial data are qualified by reference to the consolidated financial statements and the notes thereto and other information and data set forth elsewhere in this Annual Report or incorporated by reference herein.
SELECTED CONSOLIDATED FINANCIAL DATA
Fiscal Years Ended August 31, 1996 1995 1994 1993 1992 (000s omitted, except for per share and ratio information)
Income Statement Data:
Operating revenues $49,929 $45,050 $48,536 $45,016 $42,913 Operating income 6,669 5,909 5,794 5,766 5,243 Income available for common stock 3,836 3,180 3,302 2,880 2,331 Shares of common stock outstanding, weighted average 1,626 1,591 1,559 1,475 1,306 Earnings per common share $ 2.36 $ 2.00 $ 2.12 $ 1.95 $ 1.79 Cash dividends declared per common share $ 1.59 $ 1.55 $ 1.51 $ 1.47 $ 1.43 Ratio of earnings to fixed charges (1) 2.83x 2.54x 2.83x 2.45x 2.11x
Balance Sheet Data:
Long-term debt (excluding current portion) $19,765 $20,689 $21,713 $22,148 $21,031 Redeemable preferred stock - 336 350 364 378 Common stock equity 33,023 30,709 28,870 26,985 20,982 ------- ------- ------- ------- ------- Total capitalization $52,788 $51,734 $50,933 $49,497 $42,391 ======= ======= ======= ======= ======= Capital lease (excluding current portion) $ 605 $ 654 $ 700 $ 742 $ 781 ======= ======= ====== ======= ======= Total assets $89,772 $86,582 $83,511 $76,535 $73,157 ======= ======= ======= ======= =======
(1)In computing the ratio of earnings to fixed charges, "earnings" are defined as income before income taxes and "fixed charges". Fixed charges consist of interest, including the amount capitalized, interest on the obligation under the supplemental fuel inventory, amortization of debt expense and the estimated interest portion (one third) of rental payments.
Item 7:
Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
Fiscal Years Ended August 31, 1996 and 1995
Revenues
The Company's sales are responsive to colder weather as the majority of its customers use natural gas for space heating purposes. The Company measures weather through the use of effective degree days. An effective degree day is calculated by subtracting the average temperature for the day, adjusted for wind and cloud cover, from 65 degrees Fahrenheit.
Using a twenty-year average, the Company's service territory incurs 6,813 effective degree days in one year. Fiscal 1996 had 6,947 effective degree days compared to 6,258 in fiscal 1995. As a result, the volume of sales to the Company's two major firm customer classes, residential and commercial and industrial, increased by 12.7% from 5,036,056 Mcf in 1995 to 5,678,115 Mcf in the current year. The colder weather, coupled with a 0.7% increase in price, resulted in revenues of $49,929,389 in 1996 compared to $45,049,573 in the prior year. Revenues consist of three components: firm gas revenues (whereby the Company must supply the customer on demand), interruptible revenues (whereby the Company may curtail gas supplies to large industrial customers during the peak winter season), and other revenues (primarily appliance rentals and service work). Firm revenues in fiscal 1996 were 10.9% higher than in fiscal 1995. The increase was attributable to the weather and price factors discussed previously and an increase of nearly 3.0 % in the Company's customer base. The average unit price of gas sold to all customers, including interruptible customers, increased 0.7% in 1996 to $7.45 from $7.40 in fiscal 1995. For firm customers, the average unit price decreased to $8.22 from $8.36 in the prior year. The Company's interruptible revenues increased 14.6% as the unit price increased by $0.40 to $2.51 over the same period. This price increase was offset by a volume decrease in interruptible sales by 31,749 Mcf to 883,250 Mcf. If interruptible volumes exceed a threshold based on sales during the last four years, the Company may retain 10% of the gross profit on interruptible sales and refund the remaining 90% to the Company's firm customers. In fiscal 1996, the required volumes of interruptible sales were obtained, and the Company retained approximately $5,000, returning the balance of all gross profit on interruptible sales to its firm customers. The decrease in interruptible volumes did not significantly impact the Company's earnings. Other revenues increased slightly to $1,023,417 in fiscal 1996 from $1,015,979 in fiscal 1995.
During fiscal 1996, the Company added over 1,200 new customers. The Company's ability to attract customers has been assisted by the improving economy and resultant new construction. Although there is a slight unfavorable price comparison with oil, which is the Company's primary competition in the area of space heating, the environmental advantages and convenience of natural gas allow the Company to compete favorably.
Operating Expenses
The Company's major operating expense is its cost of gas which increased 10.9% to $24,976,802 in fiscal 1996 from $22,525,442 in fiscal 1995. This increase was primarily due to an increase of 12.7% in firm volumes of gas sold. The unit price of gas increased 0.7% from 1995 to 1996. These gas costs are recovered from the Company's firm customers through a Cost of Gas Adjustment ("CGA") which is adjusted semi-annually to reflect any changes in gas costs.
Operations and maintenance expenses increased 8.1% to $11,976,067 in fiscal 1996 from $11,078,029 in fiscal 1995. This increase was mainly attributable to: an increase of $285,000 in employee benefits other than pensions, $267,000 in pension expense and an increase of approximately $190,000 in uncollectible accounts. The increase in employee benefits, other than pensions, is due to approximately $143,000 in additional medical expense due to higher utilization of the Company's self- insured medical plan. In addition, the Company increased its Employee Stock Ownership Plan contribution by $82,000 and a $25,000 increase in the Company's Thrift Savings Plan as more employees participated in the Company program and received matching funds. The increase in the pension expense is primarily due to an additional contribution to the Company's pension trust and the increase in uncollectible accounts is primarily due to the higher revenues recorded during the fiscal year. The Company also incurred a one-time additional regulatory expense of approximately $225,000 for conservation and load management programs and performance based ratemaking. These increases were offset by $80,000 of reduced rate case expense as the 1993 rate case expenditures were fully amortized in December 1995.
Utility Plant depreciation expense increased 7.9 % to $2,697,241 in fiscal 1996 from $2,500,585 in fiscal 1995, reflecting the ongoing investment in upgrading and expanding the Company's distribution system.
Taxes, other than federal income, increased 11.1% to $1,816,929 in fiscal 1996 from $1,634,216 in fiscal 1995. This increase was primarily related to an increase in real estate taxes due to assessments on the Company's additions to its utility plant and state income taxes resulting from higher pre-tax earnings.
Federal income taxes increased 28.0% to $1,793,360 in fiscal 1996 from $1,401,858 in fiscal 1995, also reflecting the increase in the Company's pre-tax earnings. The Company's combined effective tax rate for both federal and state income taxes was 36.1%.
Interest on long-term debt decreased 4.0% to $1,967,073 in fiscal 1996 from $2,048,959 in fiscal 1995. This decrease was related to the sinking fund payments of long-term debt. Other interest expense increased 19.1% to $873,198 in fiscal 1996 from $732,941 in fiscal 1995. This increase was primarily attributable to higher levels of short-term debt outstanding and higher interest rates in fiscal 1996 as compared to fiscal 1995.
Income available for common stock increased 20.6% to $3,835,500, or $2.36 per share, in fiscal 1996 from $3,179,778, or $2.00 per share, in fiscal 1995. Dividends per share declared and paid for fiscal 1996 and 1995 were $1.59 and $1.55, respectively.
Fiscal Years Ended August 31, 1995 and 1994
Revenues
The Company experienced only 6,258 effective degree days in fiscal 1995 compared to 7,012 in fiscal 1994. As a result, the volume of unit sales in the Company's two major customer classes, residential and commercial and industrial, decreased by 8.4% from 5,497,235 Mcf in 1994 to 5,036,056 Mcf in the current year. The warmer than normal weather resulted in decreased firm revenues from $46,536,115 to $42,100,843. Firm revenues decreased nearly 9.5% over fiscal 1994, primarily due to the weather as the Company's customer base increased by only 2.3%. The average unit price of all gas sold to customers, including interruptible customers, decreased 8.2% to $7.40 in fiscal 1995 from $8.06 in fiscal 1994. For firm customers only, the average unit price decreased to $8.36 from $8.47 in the prior year. The Company's interruptible revenues increased 117.6% as interruptible volumes increased 525,651 Mcf. The increase in interruptible volumes was primarily due to the availability of natural gas on a low cost, spot market basis. The increase in volumes did not impact the Company's earnings since the Company did not meet the interruptible threshold requirement discussed above. Other revenues decreased slightly to $1,015,929 from $1,111,654 in 1994.
Operating Expenses
The Company's major operating expense is its cost of gas, which decreased 9.9% to $22,525,442 in fiscal 1995 from $25,000,794 in fiscal 1994. This decrease was due to less volumes of gas sold.
Operations and maintenance expenses decreased 9.2% to $11,078,029 in fiscal 1995 from $12,206,720 in fiscal 1994. This decrease was mainly attributable to: decreases of approximately $600,000 in outside services, $220,000 in medical expenses, and a decrease of approximately $340,000 in uncollectible accounts. The reduction in outside service expense was primarily related to one-time items such as actuarial services relating to employee benefits, including medical costs for current and future retirees; legal and other consulting services relating primarily to regulatory affairs such as interruptible and firm transportation rates; general comments on utility mergers and acquisitions; and other regulatory items incurred in fiscal 1994. The decrease in employee benefits was primarily related to reduced medical costs for current and future retirees as medical utilization decreased.
Utility Plant depreciation increased 6.8% to $2,500,585 in fiscal 1995 from $2,341,381 in fiscal 1994, reflecting the investment in the Company's utility plant.
Taxes, other than federal income, decreased 2.4% to $1,634,216 in fiscal 1995 from $1,675,782 in fiscal 1994. This decrease was due to a decrease in state income taxes resulting from the lower pre-tax earnings.
Federal income taxes decreased 7.6% to $1,401,858 in fiscal 1995 from $1,517,130 in fiscal 1994, also reflecting the decrease in the Company's pre-tax earnings. The Company's combined effective tax rate for both federal and state income tax purposes was 34.6%.
Interest on long-term debt decreased 3.5% to $2,048,959 in fiscal 1995 from $2,124,058 in fiscal 1994. This decrease was related to the sinking fund payments on long-term debt. Other interest expense increased 108.8% to $732,941 in fiscal 1995 from $351,088 in fiscal 1994. This increase was primarily attributable to higher levels of short-term debt outstanding and higher interest rates in fiscal 1995 as compared to fiscal 1994.
Income available for common stock decreased 3.7% to $3,179,778 or $2.00 per share in 1995, from $3,301,711 or $2.12 per share in 1994. Dividends per share declared and paid for fiscal 1995 and 1994 were $1.55 and $1.51, respectively.
Liquidity and Capital Resources
Net cash provided by operating activities decreased $4,480,556 to $6,226,758 for the fiscal year ended August 31, 1996. The decrease was primarily due to a return in supplier refund obligations of $2,179,095 compared to an increase during the fiscal year ended August 31, 1995 of $792,927. Additionally, the Company decreased its recoverable gas cost position by $2,960,944 whereas in the prior year the Company increased its position by $1,719,994. These uses of cash were offset by an increase in deferred taxes of $1,950,962 and a decrease in inventories of $2,512,221.
Occasionally the Company receives refunds from its pipeline supplier as a result of regulatory action by the Federal Energy Regulatory Commission ("FERC".) The supplier refunds are returned by the Company to customers over a twelve month period.
The Company periodically borrows from banks on an unsecured, short-term basis. At August 31, 1996, the Company had $11,940,000 of outstanding notes payable under available lines of credit totaling $16,650,000 with six different banks. In addition, for the sole purpose of financing the Supplemental Fuel Inventory, the Company has a $10,000,000 line of credit. Due to the seasonal nature of the Company's business, the Company customarily draws upon its credit lines since both sales and construction activity are affected by seasonal weather conditions. Short-term financing is typically used to satisfy seasonal cash requirements while, on an annual basis, operating requirements are satisfied by cash flows from operations.
Funding for the Company's construction program has traditionally been generated by operations and, on a temporary basis, through short-term bank borrowings. These short-term borrowings are periodically repaid with proceeds from the issuance of long-term debt and equity. Management anticipates that these and other sources will remain available and continue to adequately serve the Company's needs.
During fiscal 1996, the Company's construction expenditures were approximately $8,000,000. This compares to approximately $7,000,000 in fiscal 1995. The Company has sought approval from the Massachusetts Department of Public Utilities ("MDPU") for a private placement of First Mortgage Bonds in the amount of approximately $10,000,000 during fiscal 1997. The Company's higher construction expenditures in fiscal 1996 were primarily attributable to additional construction requirements to bring on new customers, continued upgrading of the Company's existing
infrastructure and expenditures related to the Company's automated meter reading program. These capital expenditures were funded primarily from short-term debt and operations. Capital expenditures for fiscal 1997 are expected to be approximately $6,400,000.
Regulatory and Accounting Issues
The Company's revenues are based on rates regulated by the MDPU. These rates are designed to allow the Company to recover its operating costs and provide an opportunity to earn a reasonable rate of return on investor supplied funds. Once approved, the Company's rates are adjusted by a CGA which, subject to approval by the MDPU, permits the Company to change rates to recover its gas costs and certain other costs on a dollar-for-dollar basis. The CGA is also used as the mechanism to reduce charges to firm customers by the margin earned on sales to interruptible customers. In September 1996 the Company received approval for a rate increase of $2,100,000 which is scheduled to be effective December 1, 1996. As part of a settlement approved by the MDPU, the Company will increase its depreciation rate to an average rate of 3.7% effective December 1, 1996 based on a depreciation study. The effect of the change in the depreciation rate is to increase, on an annual basis, depreciation expense in 1997 by approximately $600,000.
The Company, or its predecessors, previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. Each of these facilities has been out of operation for more than 25 years. It is possible that, during the manufacturing process, some or all of the MGPs may have discharged certain substances on the sites which may now be deemed hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The Environmental Protection Agency ("EPA") and Massachusetts Department of Environmental Protection ("MDEP") are focusing on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. In 1995 an investigation which reported the presence of certain compounds was conducted at one of the Company's MGP sites. As a result, a second, more intensive investigation will be conducted in fiscal 1997 to determine the level of contamination and to assess whether any remediation is required. The Company has also been informed that certain materials have been discovered on properties adjacent to a second site currently owned by the Company. These adjacent properties have been classified by the MDEP as a location to be investigated. Based on preliminary investigation, the Company currently believes that it may not be liable for cleanup costs associated at the adjacent properties unless such liability is based on down-gradient status; however, the Company may be liable for cleanup costs associated with the parcel presently owned by the Company. The Company does not currently possess sufficient information to determine the probability on the cost of the potential remediation, however, the MDPU provides for the recovery through the CGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. The settlement agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past operations.
The natural gas industry is in the process of transitioning from a highly regulated environment to a competitive environment. Pursuant to FERC Order 636, as supplemented by Order 636A, pipeline companies have unbundled pipeline sales, storage and transportation services. FERC Order 636 was implemented by the Company's pipeline supplier, Tennessee Gas Pipeline Company ("TGPC"), on September 1, 1993. As a result, TGPC is providing transportation service only. The Company now contracts for its own gas supply through a consortium of gas companies and pays monthly demand charges to TGPC for the availability of pipeline capacity and transportation charges for gas transport. The Company pays charges for the cost of gas delivered and for gas inventory charges to reserve volumes of gas inventory in connection with substantially all of its long-term firm gas purchase agreements.
FERC Order 636 has also required pipelines to adopt a new rate design that has shifted the recovery of the pipeline's fixed costs to a monthly demand charge for firm transportation service and away from recovery of costs of service on a volumetric basis.
FERC Order 636 also allows the pipeline companies to recover transition costs incurred as they restructure their services. TGPC began direct billing these costs to the Company on September 1, 1993 as a component of the demand charges. The Company's current estimate of its obligation for transition costs is approximately $900,000 and is based upon FERC approved filings. This estimated liability has been included in the Company's financial statements at August 31, 1996, together with the related regulatory asset. The MDPU has approved the recovery of Gas Supply Realignment costs from all firm customers.
The MDPU has received comments and proposals from interested persons on how incentive regulation could improve upon the existing framework of utility regulation. Although to date the MDPU has not issued directives, it is expected that in the near future, incentive ratemaking, in some form, will be instituted in the Commonwealth of Massachusetts.
Item 8:
Item 8: Financial Statements and Supplementary Data
CONSOLIDATED STATEMENTS OF INCOME
Fiscal Years Ended August 31,
1996 1995 1994
OPERATING REVENUES $49,929,389 $45,049,573 $48,536,005 Less: Cost of gas 24,976,802 22,525,442 25,000,794 ----------- ----------- ----------- Operating margin 24,952,587 22,524,131 23,535,211 ----------- ----------- ----------- OPERATING EXPENSES: Operations and maintenance expenses 11,976,067 11,078,029 12,206,720 Depreciation 2,697,241 2,500,585 2,341,381 Taxes, other than federal income 1,816,929 1,634,216 1,675,782 Federal income taxes 1,793,360 1,401,858 1,517,130 ----------- ----------- ----------- TOTAL OPERATING EXPENSES 18,283,597 16,614,688 17,741,013 ----------- ----------- ----------- OPERATING INCOME 6,668,990 5,909,443 5,794,198 OTHER INCOME (EXPENSE), NET 1,997 6,202 (7,828) ----------- ----------- ----------- INCOME BEFORE INTEREST CHARGES 6,670,987 5,915,645 5,786,370 ----------- ----------- ----------- INTEREST CHARGES: Interest on long-term debt 1,967,073 2,048,959 2,124,058 Amortization of deferred debt expense 27,499 27,081 26,697 Other interest expense 873,198 732,941 351,088 Allowance for funds used during construction (46,143) (92,428) (37,268) ----------- ----------- ----------- TOTAL INTEREST CHARGES 2,821,627 2,716,553 2,464,575 ----------- ----------- ----------- NET INCOME 3,849,360 3,199,092 3,321,795 ANNUAL REDEEMABLE PREFERRED DIVIDEND REQUIREMENTS (13,860) (19,314) (20,084) ------------ ---------- ----------- INCOME AVAILABLE FOR COMMON STOCK $ 3,835,500 $ 3,179,778 $ 3,301,711 ============ =========== =========== SHARES OF COMMON STOCK OUTSTANDING (WEIGHTED AVERAGE) 1,626,315 1,591,372 1,558,574 ------------ ----------- ----------- EARNINGS PER COMMON SHARE $ 2.36 $ 2.00 $ 2.12 ------------ ----------- ----------- CASH DIVIDENDS DECLARED PER COMMON SHARE $ 1.59 $ 1.55 $ 1.51 ------------ ----------- -----------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Fiscal Years Ended August 31,
1996 1995 1994
BALANCE AT BEGINNING OF YEAR $12,576,695 $11,857,299 $10,903,703 Net income 3,849,360 3,199,092 3,321,795 ----------- ----------- ----------- TOTAL 16,426,055 15,056,391 14,225,498 ----------- ----------- ----------- Cash dividends declared: Redeemable preferred stock 13,860 19,314 20,084 Common stock 2,578,428 2,460,382 2,348,115 ----------- ----------- ----------- TOTAL 2,592,288 2,479,696 2,368,199 ----------- ----------- ----------- BALANCE AT END OF YEAR $13,833,767 $12,576,695 $11,857,299 =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, August 31, 1996 1995
UTILITY PLANT, AT COST $ 98,603,784 $ 91,462,732 Less: Accumulated depreciation 22,290,175 20,304,386 ------------ ------------ NET UTILITY PLANT 76,313,609 71,158,346 ------------ ------------ Other property and investments 633,515 570,620 ------------ ------------ CAPITALIZED LEASE (NET OF ACCUMULATED AMORTIZATION OF $469,406 1N 1996 AND $423,806 IN 1995) 654,391 699,991 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents 303,526 136,925 Accounts receivable: Customers (net of allowance for uncollectible accounts of $653,000 in 1996 and $595,000 in 1995) 1,654,808 1,418,510 Other 229,189 280,889 Income tax refunds receivable 874,000 200,000 Supplemental fuel inventory 4,047,421 6,477,155 Materials and supplies (at average cost) 512,330 594,817 Prepaid deferred income taxes 328,066 1,397,422 Prepayments and other 622,502 350,660 Recoverable gas costs 470,766 - ----------- ----------- TOTAL CURRENT ASSETS 9,042,608 10,856,378 ----------- ----------- DEFERRED CHARGES: Regulatory assets 2,464,691 2,267,954 Unamortized debt expense and other 663,119 1,028,319 ----------- ----------- TOTAL DEFERRED CHARGES 3,127,810 3,296,273 ----------- ----------- $ 89,771,933 $ 86,581,608 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
August 31, August 31, 1996 1995
COMMON STOCK EQUITY $33,022,947 $30,709,276 ----------- ----------- REDEEMABLE PREFERRED STOCK - 336,000 ----------- ----------- LONG-TERM DEBT, LESS CURRENT PORTION 19,765,535 20,689,366 ----------- ----------- TOTAL CAPITALIZATION 52,788,482 51,734,642 ----------- ----------- NONCURRENT OBLIGATIONS UNDER CAPITAL LEASE 604,823 654,390 ----------- ----------- CURRENT LIABILITIES: Current portion of long-term debt 923,831 978,758 Current obligation under capital lease 49,568 45,599 Obligations under supplemental fuel inventory 3,358,010 5,131,153 Notes payable, banks 11,940,000 4,890,000 Accounts payable 4,063,829 2,986,307 Accrued interest 937,988 825,322 Refundable gas costs - 2,490,178 Accrued transition costs 890,432 858,715 Supplier refund due customers 275,644 2,454,739 Other 188,513 850,404 ----------- ----------- TOTAL CURRENT LIABILITIES 22,627,815 21,511,175 COMMITMENTS AND CONTINGENCIES ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes 9,951,085 9,092,349 Unamortized investment tax credit 1,210,896 1,280,680 Deferred directors' fees 991,503 879,009 Other 1,597,329 1,429,363 ----------- ----------- TOTAL DEFERRED CREDITS 13,750,813 12,681,401 ----------- ----------- $89,771,933 $86,581,608 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Fiscal Years Ended August 31, 1996 1995 1994 OPERATING ACTIVITIES: NET INCOME $ 3,849,360 $ 3,199,092 $ 3,321,795 Adjustments to reconcile net ----------- ----------- ----------- income to net cash: Depreciation, including amounts related to non-utility operations 3,130,712 2,920,476 2,754,465 Provisions for uncollectible accounts 57,792 (208,797) 761,385 Deferred income taxes 1,950,962 40,876 1,006,618 Amortization 7,943 8,390 7,305 Noncash compensation associated with ESOP 150,000 225,000 150,000 Cash (used in) provided by working capital: (Increase) decrease in accounts receivable (242,390) 546,304 (912,662) Decrease (increase) in inventories including fuel 2,512,221 294,854 (462,827) (Increase) decrease in prepayments and other (271,842) (33,922) 185,674 Increase in accounts payable 1,077,522 55,729 104,406 (Decrease) increase in supplier refund obligations (2,179,095) 792,927 1,661,812 (Increase) decrease in taxes receivable (802,472) 488,000 (374,323) (Decrease) increase in recoverable (refundable) gas costs (2,960,944) 1,719,994 (154,584) Other, net (53,011) 658,391 (837,888) ----------- ----------- ----------- Total adjustments 2,377,398 7,508,222 3,889,381 NET CASH PROVIDED BY ----------- ----------- ----------- OPERATING ACTIVITIES 6,226,758 10,707,314 7,211,176 INVESTING ACTIVITIES: ----------- ----------- ----------- Utility capital expenditures (8,027,623) (6,967,340) (6,131,471) Payments for retirements of property, plant and equipment, net (258,352) (66,497) (183,999) NET CASH USED IN INVESTING ----------- ----------- ----------- ACTIVITIES (8,285,975) (7,033,837) (6,315,470) FINANCING ACTIVITIES: ----------- ----------- ----------- Dividends paid (2,592,288) (2,479,696) (2,368,199) Issuance of common stock 856,007 814,126 730,874 Retirements of preferred stock (336,000) (14,000) (14,000) Principal retired on long-term debt (828,758) (855,304) (193,340) (Decrease) increase in supplemental fuel inventory (1,773,143) (1,297,617) 862,068 Increase in notes payable, banks 7,050,000 390,000 300,000 Payment of ESOP debt (150,000) (225,000) (150,000) NET CASH PROVIDED BY (USED ----------- ----------- ---------- IN) FINANCING ACTIVITIES 2,225,818 (3,667,491) (832,597) Net increase in cash and cash ----------- ----------- ---------- equivalents 166,601 5,986 63,109 Cash and cash equivalents at beginning of year 136,925 130,939 67,830 CASH AND CASH EQUIVALENTS AT ----------- ----------- ----------- END OF YEAR $ 303,526 $ 136,925 $ 130,939 ============ ============ ============ SUPPLEMENTAL DISCLOSURES: Cash paid during the year for: Interest (net of amount capitalized) $ 2,708,961 $ 2,517,015 $ 2,449,138 ============ ============ =========== Income taxes $ 1,407,476 $ 1,743,197 $ 1,196,360 ============ ============ ===========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
August 31, August 31, 1996 1995 COMMON STOCK EQUITY: Common stock, no par value, 5,000,000 authorized shares, Issued and $19,234,915 outstanding 1,642,490 shares at August 31, 1996.
Common stock, $2.50 par value, 5,000,000 authorized shares, Issued and outstanding, 1,607,061 at August 31, 1995. $ 4,017,653 Additional paid-in capital 14,311,026 Unrealized gain on investments available for sale, net 29,265 28,902 Retained earnings 13,833,767 12,576,695 ----------- ----------- 33,097,947 30,934,276 Less: Shares held by ESOP purchased with debt 75,000 225,000 ----------- ----------- TOTAL COMMON STOCK EQUITY 33,022,947 30,709,276 ----------- ----------- REDEEMABLE PREFERRED STOCK: 5.50% series, $100 par value, 7,000 authorized shares Outstanding, 3,360 at August 31, 1995 - 336,000 ----------- ----------- LONG-TERM DEBT: FIRST MORTGAGE BONDS: 10 1/4%, due serially from 1994 to 2003 4,800,000 5,400,000 10.10%, due serially from 2010 to 2020 8,000,000 8,000,000 ----------- ----------- 12,800,000 13,400,000 MORTGAGE NOTE: ----------- ----------- 8 1/2%, due serially from 1976 to 1997 609,366 838,124 DEBENTURES: ----------- ----------- 8 5/8%, due 2006 2,245,000 2,245,000 8.15%, due 2017 4,960,000 4,960,000 ----------- ----------- 7,205,000 7,205,000 ESOP LOAN GUARANTEE: ----------- ----------- 7.0%, due serially from 1987 to 1996 75,000 225,000 ----------- ----------- TOTAL DEBT 20,689,366 21,668,124 Less: Current portion maturing and payable 923,831 978,758 ----------- ----------- TOTAL LONG-TERM DEBT 19,765,535 20,689,366 ----------- ----------- TOTAL CAPITALIZATION $52,788,482 $51,734,642 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
General
Essex County Gas Company is a public utility engaged in the distribution and sale of natural gas for residential, commercial and industrial uses. Its service area is located in northeastern Massachusetts.
Regulation
The Company is subject to regulation by the Massachusetts Department of Public Utilities ("MDPU") with respect to its rates and accounting practices. The accounting policies conform to generally accepted accounting principles as applied to regulated public utilities and reflects the effects of the ratemaking process in accordance with Statement of Financial Accounting, Standard No. 71, "Accounting for Certain Types of Regulation ("SFAS 71"). Under SFAS 71, a utility is allowed to defer costs that otherwise would be expensed in recognition of the ability to recover them in future rates.
The Company has established regulatory assets in cases where the MDPU has permitted or is expected to permit the recovery of specific costs over time. As of August 31, 1996, principal regulatory assets include (1) approximately $890,000 for transition costs associated with Federal Energy Regulatory Commission ("FERC") Order 636, (2) $435,000 related to a settlement payment for a supplemental retirement plan, and (3) $425,000 related to deferred income taxes. Included in deferred credits is a regulatory liability of $751,000 related to deferred income taxes.
Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" ("SFAS 121") was issued in March 1995 and is effective for the Company on September 1, 1996. SFAS 121 establishes accounting standards for the impairment of long lived assets. It requires that regulatory assets which are no longer probable of being recovered be written off. Based upon the current regulatory environment in the Company's service territory, it is not expected that the adoption of SFAS 121 will have a material impact on the Company's financial position or results of operations.
Principles of Consolidation and Presentation
The consolidated financial statements include the accounts of LNG Storage, Inc., a wholly owned subsidiary. All material intercompany balances and transactions have been eliminated.
Cash equivalents are defined as investments with an original maturity of three months or less.
Operating Revenues
Revenues from the sale of gas are based on rates authorized by the MDPU and are recorded in the period the bill is rendered. Meters are read and bills are rendered on a cycle basis throughout the month. As a result, the
volumes of gas delivered to customers in any period may be more or less than the usage for which customers are billed.
The Company's rates include a Cost of Gas Adjustment Factor which permits the Company to recover the difference between gas costs incurred by the Company and gas costs billed to customers. The amount of the difference is deferred for accounting purposes and expensed when reflected in billings in subsequent periods.
Utility Plant
Utility plant and other property are stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and material, allocable overhead, allowance for funds used during construction and indirect charges for engineering and supervision. Expenditures for ordinary maintenance and repairs are charged to expense as incurred.
Depreciation for financial reporting purposes is calculated on a straight-line basis. The annual provision for depreciation, based on the average depreciable property, was equivalent to a composite depreciation rate of 3.03% for fiscal 1996, 1995, and 1994. The cost of Utility Plant retired or otherwise disposed of, in the ordinary course of business, together with costs of removal less salvage, is charged to accumulated depreciation.
Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications
Certain prior year financial statement amounts have been reclassified for consistent presentation with the current year.
B. Supplemental Fuel Inventory
The Company, with MDPU approval, finances its supplemental gas inventory through a single purpose financing arrangement extending through December 31, 2000. The credit agreement provides for a total commitment of up to $10,000,000 and is secured by storage gas. Financing resulted in an effective interest cost to the Company of 6.5% for 1996 and 5.9% in 1995 based on average borrowing.
C. Common Stock
Common stock activity for the three-year period ended August 31, 1996, is as follows:
Additional Number of Common Paid-in Shares Stock Capital
BALANCE, AUGUST 31, 1993 1,544,045 $ 3,860,113 $12,820,750 Dividend reinvestment plan 15,452 38,631 359,647 Amortization of capital stock expense - - 51,408 Employee stock plans 10,397 25,991 247,775 Sale of common stock 2,168 5,420 53,410 --------- ----------- ----------- BALANCE, AUGUST 31, 1994 1,572,062 3,930,155 13,532,990 Dividend reinvestment plan 19,276 48,190 389,246 Amortization of capital stock expense - - 51,408 Employee stock plans 13,054 32,635 280,208 Sale of common stock 2,669 6,673 57,174 --------- ----------- ----------- BALANCE, AUGUST 31, 1995 1,607,061 4,017,653 14,311,026
Dividend reinvestment plan 19,754 366,787 100,916 Amortization of capital stock expense - 50,229 - Employee stock plans 11,319 226,881 52,370 Sale of common stock 4,356 97,283 11,770 Conversion to no par value - 14,476,082 (14,476,082) --------- ----------- ----------- BALANCE, AUGUST 31, 1996 1,642,490 $19,234,915 $ - ========= =========== ===========
Conversion of stock to no par value.
The shareholders approved conversion of Common Stock from $2.50 par value to no par value effective September 15, 1995.
D. Restriction on Retained Earnings
Under the terms of the indenture securing the First Mortgage Bonds, retained earnings in the amount of $6,447,424 as of August 31, 1996, were unrestricted as to the payment of cash dividends on common stock and the purchase, redemption or retirement of shares of common stock.
E. Interim Financing and Long-term Debt
The Company periodically borrows from banks on an unsecured, short-term basis. At August 31, 1996, the Company had $11,940,000 of outstanding notes payable with a weighted average interest rate of 5.9% under available lines of credit totaling $16,650,000. The annual commitment fees related to these lines of credit are between 1/4% and 3/8% on the total amount of the line.
Substantially all plant assets are pledged as collateral under the terms of the indenture of First Mortgage Bonds. The 8-1/2% Mortgage Note represents an obligation secured by the liquefied gas storage facility in Haverhill, Massachusetts. In accordance with the terms of the indenture of First Mortgage Bonds, the Note Purchase Agreement of the sinking fund notes and the Mortgage Note, the Company is required to make specified sinking fund payments and other maturities of long-term debt of $923,831 in 1997, $960,535 in 1998, $600,000 in 1999, $600,000 in 2000, $600,000 in 2001 and $17,005,000 thereafter.
F. Disclosure About Fair Values of Financial Instruments
The estimated fair values of the Company's financial instruments are as follows: Carrying Amount Fair Value
Cash $ 303,526 $ 303,526 Long-term debt $19,765,535 $22,901,111
The carrying value of cash approximates fair value because of the short maturity of those instruments.
The estimated fair value of the Company's long-term debt is based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturity. The fair value shown above does not purport to represent the amount at which these obligations would be settled.
G. Income Taxes
The components of the provision for income taxes are as follows:
1996 1995 1994 FEDERAL Current $ 294,144 $1,469,957 $ 796,930 Deferred 1,569,000 2,000 791,000 Amortization of investment tax credit (69,784) (70,099) (70,800) ---------- ---------- --------- TOTAL FEDERAL 1,793,360 1,401,858 1,517,130 ---------- ---------- --------- STATE Current 58,643 292,615 173,459 Deferred 321,000 445 162,000 ---------- ---------- --------- TOTAL STATE 379,643 293,060 335,459 ---------- ---------- --------- TOTAL INCOME TAXES $ 2,173,003 $1,694,918 $1,852,589 =========== ========== ========== A reconciliation of federal income taxes calculated at the statutory rate with income tax expense shown in the financial statements for each of the three years ended August 31, is as follows:
1996 1995 1994
FEDERAL STATUTORY RATE 34.0% 34.0% 34.0% ===== ===== ===== Federal income tax expense at statutory rates $2,048,628 $1,663,963 $1,759,260
Increase (decrease) in taxes resulting from: Amortization of investment tax credit (69,784) (70,099) (70,800)
State taxes, net of federal benefit 250,564 199,980 221,403 Other (56,405) (98,926) (57,274) ---------- ---------- ----------
TOTAL INCOME TAX EXPENSE $2,173,003 $1,694,918 $1,852,589 ========== ========== ========== EFFECTIVE INCOME TAX RATE 36.1% 34.6% 35.8% ===== ===== =====
Effective September 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). The adoption of SFAS 109 had no earnings impact on the Company. SFAS 109 requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse. A regulatory asset of $425,000 was established for the deferred taxes not previously recovered as a result of the flow through to customers for temporary differences in prior years. This balance is being recovered over the estimated lives of the property. A regulatory liability of $751,000 was established for the tax benefit of unamortized investment tax credits, which SFAS 109 requires to be treated as a temporary difference. This benefit is being passed on to customers over the lives of property giving rise to the investment credits. Significant items making up deferred tax assets and deferred tax liabilities at August 31, 1996 and 1995 are as follows:
1996 1995 LIABLILTIES Utility plant-primarily depreciation $10,779,608 $ 9,957,069 Other 602,814 332,912 ----------- ----------- TOTAL LIABILITIES 11,382,422 10,289,981 ASSETS ----------- ----------- Investment tax credits 751,340 794,403 Other 1,008,063 1,800,651 ----------- ----------- TOTAL ASSETS 1,759,403 2,595,054 ----------- ----------- ACCUMULATED DEFERRED INCOME TAXES, NET $ 9,623,019 $ 7,694,927 =========== ===========
The net year-end deferred income tax liabilities above are net of current deferred tax assets of $328,066 and $1,397,422 respectively, which are included in prepaid income taxes in the accompanying Consolidated Balance Sheets.
H. Leases
The Company is obligated under various lease agreements for certain facilities and equipment used in operations. Total expenditures under operating leases were $315,152 in 1996, $289,721 in 1995, and $309,992 in 1994. A summary of property classified as capital leases as of August 31, 1996 and 1995 is as follows:
1996 1995
Buildings $1,123,797 $1,123,797
Less: Accumulated depreciation 469,406 423,806 ---------- ---------- $ 654,391 $ 699,991 ========== ==========
In accordance with the rate treatment allowed by the MDPU, the depreciation expense of $45,600, $41,948, and $38,540 , along with interest of $56,850, $60,502, and $63,910 related to the capital lease, is included in other operating expenses for the years ended August 31, 1996, 1995 and 1994, respectively.
The Company also has various operating lease agreements for equipment, vehicles and office space. The remaining minimum annual rental commitment for these and all other non-cancelable leases is as follows:
Capital Leases Operating Leases
1997 $102,500 $237,989 1998 102,500 198,218 1999 102,500 47,373 2000 102,500 23,476 2001 102,500 - Thereafter 427,084 - ------- -------- Total minimum lease payments 939,584 $507,056 ======== Less: Amount representing interest 285,193 -------- $654,391 ========
I. Employee Benefits
Pension Plans
The Company has two pension plans covering substantially all employees. The actuarial method for determining annual pension cost is the Projected Unit Credit method.
Net pension cost for 1996, 1995 and 1994 consist of the following components:
1996 1995 1994
Service cost -- benefits earned during the year $ 268,542 $ 231,741 $ 212,190 Interest cost on projected benefit obligations 722,354 668,107 617,749 Actual return on plan assets (1,125,838) (887,022) (74,969) Net amortization and deferral 609,010 412,504 (444,131) ---------- --------- --------- NET PENSION COST $ 474,068 $ 425,330 $ 310,839 ========== ========= =========
The expected long-term rate of return on assets was 8.5% in 1996, 1995 and 1994. The discount rate used in determining the actuarial present value of the projected obligation was 8.0% in 1996, 1995 and 1994. The expected rate of pay increase was 6.0% in 1996, 1995 and 1994.
The following table sets forth the funding status of the pension plans and amounts recognized in the Company's balance sheet based on measurement dates of August 31, 1996 and 1995:
1996 1995
Actuarial present value of benefit obligations (in thousands): Vested benefit obligation $ 8,198 $ 7,960 ======= =======
Accumulated benefit obligation $ 8,734 $ 8,433 ======= ======= Projected benefit obligation for service rendered to date $ 9,708 $ 9,329 Plan assets 9,083 8,034 ------- ------- Projected benefit obligation in excess of plan assets (625) (1,295) Unrecognized net gain (776) (321) Unrecognized prior service cost 1,399 1,537 Adjustment required to recognize additional minimum liability - (330) Unrecognized net obligation at transition - 10 ------- ------- Accrued pension liability $ (2) $ (399) ======= ======= Assets in the pension plan are currently held in mutual funds.
Employee Stock Ownership Plan
On September 1, 1986, the Company created an Employee Stock Ownership Plan and Trust ("ESOP"). The Company contributes annually to a Trust an amount equal to principal plus interest and any other fees net of interest income earned by the Trust and dividends on unallocated shares. The Trust was created primarily to acquire shares of the Company's common stock for the exclusive benefit of the participants (substantially all nonbargaining employees). During fiscal 1987, the Trust borrowed $1,500,000 and acquired 82,800 shares, as adjusted for a two-for-one stock split effective April 1, 1987, of the Company's previously unissued common stock. The loan is guaranteed by the Company and the final payment of $75,000 is due in October, 1996. The ESOP is recorded as a liability and the offsetting debit is accounted for as a reduction of common stock equity in the accompanying consolidated balance sheets. Interest is payable monthly at a floating rate which is 80% of the current prime rate. The charge to income, which equals the Company's contribution, for 1996 was $223,477, which includes 6,000 additional shares to be issued in early 1997, for 1995 was $141,359, and for 1994 was $223,349. Interest on ESOP debt was $8,055 for 1996, $17,365 for 1995, and $37,023 for 1994. Dividends on unallocated ESOP shares used to pay debt service was $12,738 for 1996, $27,193 for 1995, $41,352 for 1994.
Savings Plan
The Company has a thrift savings plan in which the Company matches a portion of employee contributions up to six percent of a participant's wages. The Company contributed approximately $142,000 to the Plan in 1996, $119,000 to the plan in 1995, and $108,000 to the plan in 1994.
Postretirement Benefits Other Than Pension
On September 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions ("SFAS 106"). This standard requires the accrual of the expected cost of such benefits during the employee's years of service and the recognition of an actuarially determined postretirement benefit obligation earned by existing retirees. The assumptions and calculations involved in determining the accrual and the accumulated postretirement benefit obligation closely parallel pension accounting requirements. The cumulative effect of the implementation of SFAS 106 as of September 1, 1994 is being amortized over 20 years. Prior to 1994, the cost of postretirement benefits was recognized on a pay-as-you-go basis. The Company is currently recovering the full SFAS 106 cost in rates.
The net periodic postretirement benefit cost for the year ended August 31, 1996, 1995 and 1994 is as follows: 1996 1995 1994
Service cost $104,469 $ 84,550 $110,691 Interest cost 316,398 284,861 296,310 (Return) loss on plan assets (22,610) 13,066 - Net amortization and deferral 189,435 157,634 203,868 -------- -------- -------- TOTAL POSTRETIREMENT BENEFIT COST $587,692 $540,111 $610,869 ======== ======== ========
The funded status of the Company's postretirement benefit plan using a measurement date of July 1, 1996, 1995 and 1994 is as follows:
1996 1995 1994
Accumulated postretirement benefit obligation: Retirees $(2,834,211) $(2,972,713) $(2,714,112) Fully eligible active Plan participants (108,839) (118,200) (168,942) Other active Plan participants (1,274,960) (1,264,135) (1,183,982) ----------- ----------- ----------- (4,218,010) (4,355,048) (4,067,036) Plan assets at fair value 886,580 557,939 229,781 ----------- ----------- ----------- Accumulated postretirement obligation greater than Plan assets (3,331,430) (3,797,109) (3,837,255) Unrecognized transition obligation 3,465,748 3,669,616 3,873,484 Unrecognized (gain) loss (310,951) (3,021) (141,261) ---------- ---------- ---------- ACCRUED POSTRETIREMENT BENEFIT COST $ (176,633) $ (130,514) $ (105,032) ============ ============ ============
The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.5% in 1996, 1995 and 1994. The annual increase in the cost of covered health care benefits for 1996 and 1995 was 9.5% and 7.5% for participants under age 65 and over age 65, respectively, and for 1994 was 13% and 8% for participants under 65 and over 65, respectively. This increase gradually decreases to 5% in the year 2007 and thereafter. A 1% increase in the
assumed health care cost trend rate would have increased the cost computed under SFAS 106 by $32,648 and increased the accumulated postretirement benefit by $327,934 as of August 31, 1996.
The Company has established two Voluntary Employee Beneficiary Associations ("VEBA") trusts pursuant to section 501(c)9 of the Internal Revenue Code to fund these benefits. The Company also created a subaccount to its pension plan pursuant to section 401(h) of the Internal Revenue Code to satisfy a portion of its postretirement benefit obligation. The Company made contributions to the VEBA trusts and the subaccount during 1996 and 1995 totaling $541,483 and $514,629, respectively. Assets in the VEBA trusts are held in cash reserve accounts. Assets in the subaccount to the pension plan are currently held in mutual funds.
Incentive Stock Option Plan
In 1995 the Company adopted a Stock Option Plan ("Plan"). In accordance with the Plan, options may be granted from time to time but the total number of shares subject to the Plan shall not exceed 100,000 with not more than 25,000 shares granted during any one year to any individual. The Plan is considered an Incentive Stock Option Plan under Internal Revenue Code Section 422. No options were granted or exercised during fiscal 1996. During 1995, a total of 24,000 shares were granted at a price of $24.50 with exercise dates beginning February 9, 1996 and ending February 9, 2000. No options were exercised during 1995.
J. Commitments and Contingencies
Construction Expenditures
The Company's construction expenditures in connection with its continuing construction program are presently estimated at $6,400,000 for 1997 and approximately $6,200,000 in each of the four following years.
FERC Order 636 allows the pipeline companies to recover transition costs created as they buy out of long-term, fixed price contracts. Tennessee Gas Pipeline Company began direct billing these costs to the Company on September 1, 1993 as a component of the demand charges. At August 31, 1996, the transition costs are estimated at $890,000 and will be billed over a period of approximately three years subject to modification and/or refund based on final FERC approval of pipeline transition costs to be recovered. Negotiations are continuing with the pipeline of several other issues. As a result, the Company is unable to predict its final obligation at this time; however, based on these and subsequent settlement activities, the Company will adjust its regulatory assets and liability accounts accordingly. The MDPU has allowed recovery of these transition costs through the CGA.
Gas Supply, Transportation and Storage
The Company has various long-term gas supply, transportation and storage contracts with minimum cost provisions. Under these contracts, the Company is obligated to make specified minimum payments. Based on current rates and/or agreements, the minimum annual payments under these contracts are as follows:
1997 to 2001
Pipeline transportation demand $ 5,124,156
Underground storage demand 946,344
Underground storage transportation 1,011,780
Pipeline gas inventory charge 2,924,352
Gas supply realignment charges 890,424 ----------- $10,897,056 ===========
Litigation Matters
The Company is a defendant in various civil actions, which are covered by insurance and reserves. Based on the advice of legal counsel, management believes that the Company has adequate defenses against these claims and, in view of the insurance coverage, the potential liability would not materially effect the financial condition or the results of operations of the Company.
Environmental Matters
The Company has received notification that the Massachusetts Department of Environmental Protection ("MDEP"), has reason to believe that the Company may be a potentially responsible party, along with several other parties, with respect to alleged release of hazardous materials at sites in Plympton, Massachusetts. The Company does not currently have sufficient information to reasonably estimate the amount of the final liability for cleanup costs or other damages or expenses at such sites. The Company believes it should be permitted to recover these costs through rates. The Company or its predecessors previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. It is possible that in the manufacturing process some or all of the MGPs may have discharged certain substances on the sites which may now be deemed to be hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The Environmental Protection Agency ("EPA") and MDEP have recently begun to focus on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. In 1995 an investigation which reported the presence of certain compounds was conducted at one of the Company's MGP sites. As a result, a second, more intensive investigation is to be conducted to determine the level of contamination and to assess whether any
remediation is required. The Company has also been informed that certain materials have been discovered on properties adjacent to a second site currently owned by the Company. These adjacent properties have been classified by the MDEP as a location to be investigated. Based on preliminary investigation, the Company currently believes that it may not be liable for cleanup costs associated at the adjacent properties unless such liability is based on down-gradient status; however, the Company may be liable for cleanup costs associated with the parcel presently owned by the Company. The Company does not currently possess sufficient information to determine the probability or the cost of the potential remediation, however, the MDPU provides for the recovery through the CGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. The settlement agreement also provides for no further investigation on the prudency of any Massachusetts gas utility's past MGP operations.
K. Subsequent Events
In September 1996 the Company received approval for a rate increase of $2,100,000 which is scheduled to be effective December 1, 1996. As part of the settlement approved by the MDPU, the Company will increase its depreciation rate to an average rate of 3.70% effective December 1, 1996 based on a depreciation study. The effect of the change in the depreciation rate is to increase, on an annual basis, depreciation expense in 1997 by approximately $600,000.
The Company has sought MDPU approval of the private placement of First Mortgage Bonds in the amount of approximately $10,000,000.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Essex County Gas Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Essex County Gas Company (a Massachusetts corporation) as of August 31, 1996 and 1995, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended August 31, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Essex County Gas Company as of August 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended August 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP Boston, Massachusetts, October 21, 1996
PART III
Item 9:
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 10:
Item 10: Directors and Executive Officers of the Registrant
The information required by Item 401 and 405 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 21, 1997.
Item 11:
Item 11: Executive Compensation
The information required by Item 402 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 21, 1997.
Item 12:
Item 12: Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 2, 1996, for the Annual Meeting of Stockholders to be held on January 21, 1997.
Item 13:
Item 13: Certain Relationships and Related Transactions
The information required by Item 404 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 2, 1996, for the Annual Meeting of Stockholders to be held on January 21, 1997.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ESSEX COUNTY GAS COMPANY (Registrant)
Date: November 25, 1996 by /s/ James H. Hastings Vice President and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons in the capacities and on the dates indicated.
Signature Title Date
/s/ Charles E. Billups Chairman of the Board 11/25/96
/s/ Philip H. Reardon President and Chief 11/25/96 Executive Officer
/s/ James H. Hastings Vice President and 11/25/96 Treasurer (Principal Financial and Accounting Officer)
/s/ Benjamin C. Bixby Director 11/20/96
/s/ Daniel A. Burkhardt Director 11/25/96
/s/ Edward J. Curtis Director 11/21/96
/s/ Dorothy J. Dotson Director 11/20/96
/s/ Richard P. Hamel Director 11/20/96
/s/ Robert S. Jackson Director 11/25/96
/s/ Eric H. Jostrom Director 11/21/96
/ / Robert L. Meade Director
Signature Title Date
/ / Kenneth L. Paul Director
/s/ Richard L. Wellman Director 11/20/96
PART IV
ITEM 14:
ITEM 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K
A) Documents filed as part of this report:
1. The Financial Statements of the Company, on pages 22 through 38, and the Report of Arthur Andersen LLP on page 39 herein.
2. Schedules.
None.
3. Exhibits
Exhibit Number Description
3.1 Restated Articles of Organization of Essex County Gas Company.3
3.2 Bylaws of Essex County Gas Company.3
4.1 The rights of holders of Redeemable Preferred Stock, 5.50% Series and the rights of holders of Common Stock, are defined in the Bylaws and the Restated Articles of Organization of the Registrant. See Exhibit 3.1.
4.2 Indenture dated as of June 1, 1986 between the Company and Centerre Trust Company of St. Louis, Trustee.2
4.3 Eleventh Supplemental Indenture dated as of September 15, 1988, providing for a 10 1/4% Series due 2003.1
4.4 Twelfth Supplemental Indenture dated as of December 1, 1990, providing for a 10.10% series due 2020.4
4.5 Revolving credit agreement.9
10.1 LNG Storage, Inc., Lease Indenture of Mortgage and Deed of Trust dated April 10, 1972.1
10.2 Haverhill Familee Investment Corporation - Lease of Corporate Headquarters dated November 1, 1975.1
10.3 Arlington Trust Company - Purchase Contract, Credit Agreement, Trust Agreement and Storage Agreement dated October 1, 1980.1
Exhibit Number Description
10.4 Consolidated Gas Supply Corporation - Underground Storage Contract dated February 18, 1980.1
10.5 Penn-York Energy Corporation - Storage Services Agreement dated December 21, 1984.1
10.6 Canadian Gas Transportation Contract between Tennessee Gas Pipeline Company and Essex County Gas Company dated December 1, 1987.3
10.7 Phase 2 Gas Sales Agreement between Boundary Gas and Essex County Gas Company dated September 14, 1987.3
10.8 Amendment to the Agreement for the Sale of Gas between Bay State Gas Company and Essex County Gas Company dated May 6, 1988.3
10.9 Agreement for the Liquefaction of Gas between Bay State Gas Company and Essex County Gas Company dated March 14, 1988.3
10.10 Bond Purchase Agreement dated December 1, 1990, among Allstate Life Insurance Company of New York, and Essex County Gas Company.4
10.11 Iroquois Gas Transmission System, L.P. Gas Transpor- tation Contract for Firm Reserved Service dated February 7, 1991.3
10.12 Alberta Northeast Gas Limited (ANE), Gas Sales Contract Agreement No. 1 dated February 7, 1991.5
10.13 Aquila Energy Marketing Corporation Gas Sales Agreement dated June 5, 1992.5
10.14 Natural Gas Clearinghouse Gas Sales Agreement dated June 8, 1992.5
10.15 Tennessee Gas Pipeline Transportation Contract dated February 7, 1991.6
10.16 Tennessee Gas Pipeline Company Gas Storage Contract (SS-NE) TGP002099STO dated November 10, 1991.6
Exhibit Number Description
10.17 Tennessee Gas Pipeline Company Storage Service Transportation Contract TF-4175 dated October 28, 1991.6
10.18 The Company has entered into an amended employment contract with Charles E. Billups, Chairman of the Board.2*
10.19 Form of employment contract between the Company and each of the following officers: Wayne I. Brooks, Vice President; John W. Purdy, Jr., Vice President; James H. Hastings, Vice President and Treasurer; Allen R. Neale, Vice President; and Cathy E. Brown, Clerk. These contracts are identical to those submitted with the Annual Report for each with the exception of compensation amounts.2*
10.20 Employment Agreement between the Company and Philip H. Reardon, President, dated November 19, 1992.7*
10.22 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated September 1, 1993.8
10.23 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated August 25, 1993.8
10.24 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under Transportation Service "CGT-NE" Rate Schedule) dated September 1, 1993.8
10.25 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated September 1, 1993.8
10.26 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under Rate Schedule FS) dated September 1, 1993.8
10.27 Amendment to Employment Agreement between the Company and Philip H. Reardon, President, dated March 3, 1994.*
Exhibit Number Description
10.28 Amendment to Employment Agreement between the Company and John W. Purdy, Jr., Vice President, dated March 3, 1994.*
10.29 Amendment to Employment Agreement between the Company and Wayne I. Brooks, Vice President, dated March 3, 1994.*
10.30 Amendment to Employment Agreement between the Company and Allen R. Neale, Vice President, dated March 3, 1994.*
10.31 Amendment to Employment Agreement between the Company and James H. Hastings, Vice President and Treasurer, dated March 3, 1994.*
10.32 Amendment to Employment Agreement between the Company and Cathy E. Brown, Corporate Clerk, dated March 3, 1994.*
10.33 Essex County Gas Company Supplemental Retirement Plan for Philip H. Reardon effective January 1, 1994.*
10.34 Employment Agreement between the Company and William T. Beaton, Vice President, dated June 7, 1995.*
27 Financial Data Schedule.
B) Reports on Form 8-K.
No reports on Form 8-K have been filed during the quarter ended August 31, 1995.
*Denotes Management Contract.
1Previously filed as an exhibit to Registrant's Registration Statement on Form S-7, filed October 23, 1981, File No. 2-74531 and is incorporated herein by this reference.
2Previously filed as an exhibit to Registrant's Registration Statement on Form S-2 filed June 19, 1986, File No. 33-6597 and is incorporated herein by this reference.
3Previously filed as an exhibit to Registrant's 10-Q filed for the quarter year ended February 29, 1996, and is incorporated herein by this reference.
4Previously filed as an exhibit to Registrant's 10-Q filed for the quarter ended February 28, 1991, and is incorporated herein by this reference.
5Previously filed as an exhibit to Registrant's 10-Q filed for the quarter ended May 31, 1992, and is incorporated herein by this reference.
6Previously filed as an exhibit to Registrant's 10-K filed for the fiscal year ended August 31, 1992, and is incorporated herein by this reference.
7Previously filed as an exhibit to Registrant's Form S-3, No. 33-69736, filed on September 30, 1993, and is incorporated herein by this reference.
8Previously filed as an exhibit to Registrant's Form 10-K filed for the fiscal year ended August 31, 1993, and is incorporated herein by this reference.
9Previously filed as an exhibit to Registrant's Form 10-Q filed for the quarter ended May 31, 1996 and incorporated herein by this reference.