-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TAKcAmqeVUDArQJ5uPbVYJfdRLguS/3E+XpgoAFVOP+Db4hb39HNcsluj1rvMIbu r9vYJCdM7zgTAaRyi87IXg== 0000046189-95-000015.txt : 19951205 0000046189-95-000015.hdr.sgml : 19951205 ACCESSION NUMBER: 0000046189-95-000015 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19950831 FILED AS OF DATE: 19951129 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: ESSEX COUNTY GAS COMPANY CENTRAL INDEX KEY: 0000046189 STANDARD INDUSTRIAL CLASSIFICATION: 4924 IRS NUMBER: 041427020 STATE OF INCORPORATION: MA FISCAL YEAR END: 0831 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-01166 FILM NUMBER: 95597232 BUSINESS ADDRESS: STREET 1: 7 N HUNT RD CITY: AMESBURY STATE: MA ZIP: 01913 BUSINESS PHONE: 5083884000 MAIL ADDRESS: STREET 1: 7 NORTH HUNT ROAD CITY: AMESBURY STATE: MA ZIP: 01913 FORMER COMPANY: FORMER CONFORMED NAME: HAVERHILL GAS CO DATE OF NAME CHANGE: 19830420 10-K 1 [LIVE] 1 [NOTIFY] 74313,406 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ________________________ Form 10-K (Mark One) /X/ Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the fiscal year ended August 31, 1995. / / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the transition period from ________________ to __________________. Commission File Number 1-8154 ESSEX COUNTY GAS COMPANY (Exact name of Registrant as specified in its charter) Massachusetts 04-1427020 (State of organization) (IRS Employer Identification No.) 7 North Hunt Road, Amesbury, Massachusetts 01913 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (508) 388-4000 Securities registered pursuant to Section 12(b) of the Act: Title of Class Exchange Common Stock, $2.50 Par Value NASDAQ/NMS Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes / X / No / / Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/ The aggregate market value of the voting stock held by non-affiliates on October 31, 1995 based upon the last sales price on that date was approximately $40,367,000. DOCUMENTS INCORPORATED BY REFERENCE: Part III hereofincorporates by reference portions of the definitive Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held January 16, 1996. Part IV hereofincorporates by reference certain of the Exhibits to the following documents: Registration Statement No. 2-74531 on Form S-7, filed October 23, 1981, Registration Statement No. 33-6597 on Form S-2 filed on June 19, 1986, Registration Statement No. 33-69736 on Form S-3, filed on September 30, 1993, Registrant's Annual Report on Form 10-K for fiscal 1988, Registrant's Annual Report on Form 10-K for fiscal 1992, Registrant's Annual Report on Form 10-K for fiscal 1993, Registrant's Quarterly Report on Form 10-Q for the Quarter ended February 28, 1991, Registrant's Quarterly Report on Form 10-Q for the Quarter ended May 31,1992, Registrant's Quarterly Report on Form 10-Q for the Quarter ended February 28, 1995 and Registrant's Quarterly Report on Form 10-Q for the Quarter ended May 31, 1995. 2 ESSEX COUNTY GAS COMPANY FORM 10-K Annual Report Year Ended August 31, 1995 --------------------------- Table of Contents Item No. Topic Page PART I 1. Business 1 2. Properties 10 3. Legal Proceedings 10 4. Submission of Matters to a Vote of Security Holders 10 PART II 5. Market for the Registrant's Common Equity and Related Stockholder Matters 11 6. Selected Financial Data 11 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 8. Financial Statements and Supplementary Data 19 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 36 PART III 10. Directors and Executive Officers of the Registrant 37 11. Executive Compensation 37 12. Security Ownership of Certain Beneficial Owners and Management 37 13. Certain Relationships and Related Transactions 37 PART IV Signatures 38 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 47 PART I Item 1: Business General The Company, a regulated public utility organized under the laws of the Commonwealth of Massachusetts in 1853, purchases, distributes and sells natural gas to residential, commercial and light industrial customers in northeastern Massachusetts. The Company operates in the cities of Haverhill and Newburyport, the towns of Amesbury and Ipswich, and thirteen other smaller municipalities covering an area of approximately 280 square miles. The year-round population of the Company's service area was approximately 165,000 in the 1990 Census. The Company's service area is primarily comprised of residential communities with a number of small commercial and diversified light industrial businesses. The local economy, not unlike economic conditions in general, had been weak with a resultant slowdown in new construction, especially commercial construction during the early 1990s. However, during fiscal 1995 there was a slight increase in new residential construction. New home construction activity significantly impacts the degree to which the Company is able to grow itscustomer base. Sales and Customer Data The Company sells natural gas to over 40,000 customers in its service area. Residential users of natural gas generally experience their highest level of consumption for heating purposes during the winter months. Accordingly, the Company's sales and operating revenues are sensitive to the severity of the weather. The Company's rates are designed to recover added costs associated with peak operations during the winter months. In fiscal 1995, the Company's total operating revenues were $45,049,573 of which approximately 63.9% was derived from residential customers, 29.5% from commercial and industrial customers, 4.3% from interruptible customers and 2.3% from other sources. During this period, the Company sold 5,951,055 thousand cubic feet of gas (Mcf), of which approximately 53.7% was purchased byresidential customers, 31.0% by commercial and industrial customers and 15.3% by interruptible customers. Losses and company use amounted to 86,387 Mcf for 1995. Set forth in the following table is information by customer classification showing operating revenues, gas delivered and number of customers for the periods indicated.
Fiscal Years Ended August 31, 1995 1994 1993 1992 1991 (Dollars and Mcfs in Thousands) Operating Revenues: Residential-general $ 2,159 $ 2,291 $ 2,160 $ 2,070 $ 2,107 Residential-heating 26,589 29,245 27,218 25,150 21,666 Commercial and Industrial 13,353 15,000 14,006 13,432 12,001 Interruptible 1,933 888 653 1,316 1,724 Other 1,016 1,112 979 945 859 Total $45,050 $48,536 $45,016 $42,913 $38,357 ======= ======= ======= ======= ======= Gas Delivered (Mcf): Residential-general 148 159 158 158 171 Residential-heating 3,045 3,325 3,228 3,083 2,651 Commercial and Industrial 1,843 2,014 1,948 1,927 1,730 Interruptible 915 389 273 669 850 Total Sales 5,951 5,887 5,607 5,837 5,402 Losses and Company Use 86 79 89 101 78 Total 6,037 5,966 5,696 5,938 5,480 ====== ====== ====== ====== ====== Number of Customers at Year-End: Residential-general 7,369 7,560 7,439 6,776 6,965 3,884 3,863 3,941 Interruptible 2 2 2 2 2 Total 40,524 39,616 38,759 38,163 38,076 ====== ====== ====== ====== ====== Effective Degree Days (20-Year Average: 6,772) 6,258 7,012 6,956 6,750 5,843
The Company's residential customers are classified as either general or heating customers. In fiscal 1995, residential-heating customers accounted for approximately 59.0% of total operating revenues, while residential-general customers accounted for approximately 4.8% of total operating revenues. Operating revenues from residential customers decreased approximately 8.8% to $28,747,790 in fiscal 1995 from $31,535,901 in fiscal 1994. The sales decrease was attributable to the relatively warmer winter in fiscal 1995 compared to fiscal 1994 as residential volumes decreased 8.3%. The average rate charged to residential customers per Mcf of gas was $9.00 and $9.05 in fiscal 1995 and 1994, respectively. The decrease was primarily attributable to lower gas costs incurred by the Company. The Company's commercial and industrial firm revenues decreased approximately 10.9% to $13,353,053 in fiscal 1994 from $15,000,214 in fiscal 1994. The decrease was attributable to a 8.5% volume decrease and a 2.7% decrease in the average price charged per Mcf of gas from $7.45 to $7.25. The sales decreases were largely attributable to warmer weather experienced during the winter in fiscal 1995 as compared to fiscal 1994. The Company has two interruptible customers, only one of which purchased significant amounts of gas from the Company in fiscal 1995. Total interruptible revenues in fiscal 1995 were $1,932,751 compared to $888,236 in fiscal 1994. Sales of gas to interruptible customers do not materially affect the Company's operating income because the Company is required to return all gross profit on such sales directly to the Company's firm customers unless interruptible volumes exceed a certain threshold specified by the Massachusetts Department of Public Utilities ("MDPU"). Once that threshold is attained, the Company may retain 10% of gross profits. The threshold was not attained in fiscal 1995. Any gross profit returned to the customers are returned through a Standard Cost of Gas Adjustment ("SCGA") under which the Company is permitted to recover its gas costs. The average price charged by the Company to interruptible customers was $2.11 per Mcf and $2.28 per Mcf in 1995 and 1994, respectively. The Company's largest customer purchases gas on an interruptible basis and accounted for approximately 2.5% of operating revenues on average over the past three fiscal years ended August 31, 1995. Sales to that customer in 1995 totaled $1,890,561 or 4.2% of total Company operating revenues. Since most of the gross profit earned on interruptible sales is returned to firm customers, the Company believes that the loss of any single customer would not have a material effect on the Company's results of operations. In addition to its principal business of gas sales, the Company rents water heaters and conversion burners and performs service work. Net revenues from rental operations and service work represented less than 2% of the total operating revenues of the Company over the past three years ended August 31, 1995. During 1995, the Company added 955 new customers. In fiscal 1994 and 1993, net new customer additions (which approximated gross additions) were 857 and 596, respectively. Gas Supply The Company contracts for its gas supply on the basis of forecasted demand which is derived from historical weather patterns recorded since 1960. The maximum single-day demand during the last five fiscal years was 46,768 Mcf on February 6, 1995. Maximum single-day demand for 1994 and 1993 were 45,500 and 40,852 respectively. The Company has the ability to meet a single-day demand of approximately 65,000 Mcf. Single-day demand for gas is affected by numerous factors, including the severity of the weather and the number of firm customers. Total gas sendout by the Company in fiscal 1995 was 6,037,442 Mcf compared to 5,965,627 Mcf in 1994 and 5,695,910 in fiscal 1993. The following table shows the sources of the Company's gas supply requirements for the periods indicated.
Fiscal Years Ended August 31, 1995 1994 1993 1992 1991 Gas Supply (Mcf): Natural gas from pipeline 4,844,912 4,780,294 4,222,801 5,344,754 4,719,549 Underground storage withdrawn 820,493 820,103 1,271,670 459,594 569,458 Liquefied natural gas produced 372,037 361,440 201,439 132,965 190,508 Propane air produced - 3,791 - 206 288 Total 6,037,442 5,965,628 5,695,910 5,937,519 5,479,803 ========= ========= ========= ========= =========
For the year ended August 31, 1995, approximately 80.2% of the Company's gas supply was delivered by Tennessee Gas Pipeline Company ("TGPC"), a division of Tenneco, with supplemental sources supplying the remainder. The Company has a firm transportation contract with TGPC which provides for daily delivery of 15,728 dekatherms ("DTH") (each DTH is approximately 0.975 Mcf) through November 1, 2000. TGPC is currently delivering such quantities on a firm basis as authorized by the Federal Energy Regulatory Commission ("FERC"). In connection with the implementation of FERC Order 636, the Company has converted its natural gas purchase contract with TGPC into several firm gas supply contracts directly with other gas suppliers. These long-term contracts are subject to approval by the MDPU. All contracts are with major suppliers that have a demonstrated track record of performance and are at market sensitive prices. In addition to contracts with Aquila Energy and Natural Gas Clearinghouse for 2,500 DTH each per day for nine years, the Company, through the efforts of the Mansfield Consortium, negotiated contracts with Tenngasco for 4,410 DTH per day expiring October 31, 1999; Enron for 4,409 DTH per day expiring October 31, 1999; and Natural Gas Clearinghouse for an additional 1,909 DTH per day expiring September 1, 2002 to complete its transition under FERC Order 636. See "Item 1: Business--Regulatory Matters--FERC Matters". The Company also purchases gas from Boundary Gas, Inc. ("Boundary"). Pursuant to a supply contract with Boundary expiring on January 15, 2003, the Company may take up to a maximum of 1,610 Mcf per day from Boundary and may purchase up to 587,650 Mcf per year, the annual quantity limitation for the contract. The Company began in January 1988 taking up to a maximum of 1,610 Mcf per day. Pursuant to a supply contract with Boundary, the Company is required to purchase 75% of this maximum amount per year or its daily capacity will be reduced proportionately based on the level actually taken by the Company during such year. The Company purchased 569,828 Mcf in fiscal 1995 or 97.0% of the annual quantity limitation. The Company has a firm transportation contract with TGPC for the delivery of the Boundary supply. The Company also purchases gas from Alberta Northeast Limited ("ANE"). In December 1991, the Company began to receive deliveries of 2,000 Mcf per day (approximately 2,051 DTH per day) of this Canadian gas from ANE after ANE received approvals from the National Energy Board of Canada and the Economic Regulatory Administration of the United States. Under its contract with ANE, the Company may purchase up to 717,193 Mcf per year (approximately 735,583 DTH per year), the annual quantity limitation for the contract. The contract requires the Company to purchase at least 60% of the annual quantity limitation per year or its daily capacity will be reduced proportionately based on the level actually taken by the Company during such year. The Company purchased approximately 706,742 Mcf in fiscal 1995 or 98.5% of the contracted amount in fiscal year 1995. The Company has firm transportation contracts with the Iroquois Pipeline and TGPC for the delivery of the above-mentioned volumes. The Company has three contracts for underground storage with a total storage capacity of approximately 1,461,868 Mcf. The Company used a total of 842,205 Mcf, including 21,712 Mcf of fuel gas, of its total underground storage in fiscal 1995. Under a contract expiring November 1, 2000, the Company obtained its pro rata share of TGPC underground storage. The Company received storage capacity of 780,928 DTH and 5,172 DTH per day of deliverability, as well as the ability to fill the storage with gas obtained from any supplier. This service augments the Company's ability to meet high delivery demand in the winter and to take advantage of lower off-season gas prices. The Company also has a contract for underground storage with Consolidated Supply Corporation for a total volume of 359,450 DTH expiring April 1, 2000. The contract is backed by a transportation contract with TGPC for the same period, which provides for the withdrawal from storage and delivery to the Company of up to 3,268 DTH per day (approximately 3,186 Mcf per day) on a firm basis. The Company's third contract for underground storage is with Penn-York Energy Corporation and extends through March 31, 1996. It is expected that the contract will be renewed on an annual basis. The total storage volume under this contract is 350,000 Mcf, and the maximum daily withdrawal is 3,182 Mcf. The contract is backed by a transportation contract with TGCP which has been authorized by FERC to deliver to the Company approximately 787 Mcf per day from this storage facility on a firm basis and the balance on a "best efforts" basis. If the need develops, the Company will seek a firm transportation contract with TGPC for delivery of the full volume under the contract with Penn-York Energy Corporation. These underground storage arrangements allow the Company to maximize firm gas supply purchases while allowing the Company to take full advantage of the spot market gas prices during the summer and other periods when such gas is not required to meet customer demands. The stored gas is withdrawn during periods of high demand to assist the Company in meeting firm delivery requirements. Through a wholly owned subsidiary, the Company owns a liquefied natural gas ("LNG") storage facility located in Haverhill, Massachusetts. The LNG storage facility has a storage capacity of 400,000 Mcf and has a daily sendout capacity of 30,000 Mcf. In fiscal 1995, sendout of LNG totaled 372,037 Mcf. At the same location, the Company owns and operates a propane plant that has a storage capacity equivalent of approximately 40,000 Mcf with a total daily sendout capacity of 7,000 Mcf. In fiscal 1995, there was no sendout of propane. Due to the relatively high cost of LNG and propane, the Company uses these fuels primarily to satisfy peak winter demand. Under an agreement with Bay State Gas Company expiring October 31, 1996, the Company is required to purchase 50,000 Mcf of LNG during each summer period and approximately 110,000 Mcf during each winter period with an option to purchase an additional 37,000 Mcf during each winter period. Based on current information concerning pipeline and supplemental gas supplies, the Company expects to meet the gas requirements of its firm customers for the foreseeable future. Competition The Company has no direct competition with respect to the retail distri- bution of natural gas by pipeline in its service territory. Massachusetts law effectively protects gas companies from such competition. Where a gas company exists in active operation in Massachusetts, no other person may construct underground gas mains in the public ways without the approval, after notice and hearing, of the municipal authorities and, in certain circumstances, the MDPU. If a municipality desires to enter the gas business, it must take certain procedural steps, including obtaining a favorable vote by a majority of the voters at its town meeting. The municipality would then be required to purchase the utility plant of any gas company operating in the area at an agreed-upon price. If no agreement was reached, the MDPU would make the final determination. Management of the Company is not aware of any municipality in its service area which currently desires to enter the gas distribution business. The Company faces a changing competitive market for natural gas. Although it has no direct competition in its territory, the Company's gas business competes principally with oil for industrial boiler uses and oil and electricity for residential and commercial space heating. Competition is primarily based on price. In addition, the MDPU required the Company to submit, for approval, rates dealing with transportation of third-party gas which will enable large volume customers to acquire natural gas from sources other than Essex County Gas. Although the Company has received approval for these rates, to date no customer has selected this option. While the current retail price of natural gas is higher than the retail price of oil for residential space heating customers, natural gas is the fuel of choice for most new residential construction. Natural gas has significant environmental, operational and maintenance advantages over oil. Additionally, most of the Company supply of natural gas is from North American sources. Since the mid-1970's, the retail cost of heating residential space by natural gas in the Company's service territory has been approximately the same, or slightly higher than, the comparable cost of heating by oil. There is no assurance that the relative price differ- ential between natural gas and oil will diminish in the future. Natural gas has a significant price advantage over electricity supplied by investor-owned and municipal electric utilities in the Company's service territory. In the Company's service territory, the cost of heating with natural gas for commercial and industrial customers is relatively competitive with the cost of heating with oil. Approximately 50 of the Company's commercial and industrial customers have dual heating facilities that enable them to switch freely between natural gas and oil. As of August 31, 1995, the majority of the Company's dual fuel customers were using oil. Regulatory Matters State The Company is subject to the regulatory authority of the MDPU with respect to the issuance of securities, accounting practices, rates, service, contracts for the purchase of gas, territories served and related matters. Since 1987, the Company has filed four requests for rate increases and has been granted a total of $5,930,791 in rate relief by the MDPU, which amounts to 61.6% of the total requested. The Company's most recent rate increase request was filed in fiscal 1993 and approved in fiscal 1994. The Company's fiscal 1993 rate increase request was for an annualized increase of approximately $3,000,000 and the MDPU approved an annualized rate increase of approximately $1,730,000. The rate increase was effective December 1, 1993. The MDPU permits Massachusetts gas companies to utilize a SCGA that permits a gas company to pass on to firm customers (on a current basis) increases or decreases in the cost of gas supplies. Profits from interruptible sales and gas supplier refunds are also passed on to firm customers through the SCGA and no portion of the interruptible profits are retained by the Company unless certain volumes are sold. Supplemental fuel inventory and related administrative and carrying costs are also recovered through the SCGA. In addition, the MDPU allows recovery of the following through the SCGA: (1) working capital costs associated with purchased gas costs; (2) clean-up costs associated with waste materials from former gas manufacturing sites; and (3) interest on the over or under collected gas costs. The Company has the ability to release any of its unused capacity on the Tennessee Gas Pipeline with net proceeds being returned to firm customers through the SCGA. The Company has also incurred costs associated with MDPU Energy Conservation Load Management programs and the Company expects to recover these costs through the SCGA. Changes in rates charged to customers which are not incorporated in the SCGA must be approved by the MDPU. Some relief with respect to rate changes, such as adjustments in the allowed rates of return on common equity, granting of inflation adjustments, and the use of year-end rate base calculations in rate proceedings, have been granted in the past by the MDPU to remedy the financial burden resulting from the lag between the historic period upon which rate decisions are based and the date when the rates actually become effective. By law, the MDPU must act on a final rate proceeding within six months of filing and may grant relief during the interim period. FERC The Company is not subject to direct regulation by FERC, but is signifi- cantly affected by FERC orders that regulate interstate pipelines serving the Company. Pursuant to FERC Order No. 636, as supplemented by FERC Order No. 636A ("FERC Order 636"), TGPC is primarily a transportation pipeline and has discontinued nearly all of its activities as a FERC certificated merchant of gas. TGPC has previously received approval for the conversion of certain of its sales service to the Company. See "Item 1: Business--Gas Supply." The Company believes that the unbundling of these sales service arrangements will not result in material adverse changes in its business and that it will be able to recover, through rates, costs incurred in connection with the implementation of FERC Order 636. Certain issues are still pending before FERC, such as the manner in which TGPC may pass on a portion of its transition costs associated with Order 636. The MDPU allows the Company to recover any of the transition costs allowed by FERC through the SCGA. Certain other aspects of FERC Order 636 which affect or may affect the Company are pending before FERC or are subject to review by the courts. These include, among other things, (i) rules for "capacity brokering" or "capacity reassignment"; (ii) rules for the manner in which capacity is allocated on various pipelines for transportation purposes; and (iii) rules governing changes in ratemaking methodologies which create uncertainty as to future transportation costs. Until the regulatory treatment of these issues is clarified, the Company cannot predict the effect of such issues on its business. Environmental Matters The Company is subject to local, state and federal regulations through, among others, the Massachusetts Department of Environmental Protection ("MDEP"), the United States Environmental Protection Agency ("EPA"), the United States Department of Transportation ("DOT"), and the MDPU. The Company, or its predecessors, previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. Each of these facilities has been out of operation for more than 25 years. It is possible that, during the manufacturing process, some or all of the MGPs may have discharged certain substances on the sites which may now be deemed hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The Environmental Protection Agency ("EPA") and Massachusetts Department of Environmental Protection ("MDEP") are focusing on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. In 1995 an investigation which reported the presence of certain compounds was conducted at one of the Company's MGP sites. As a result, a second, more intensive investigation will be conducted in 1996 to determine the level of contamination and to assess whether any remediation is required. The Company does not currently possess sufficient information to determine the probability or the cost of the potential remediation, however, the MDPU provides for the recovery through the SCGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. A 1990 MDPU agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations. In 1990, the Company received notification from the MDEP that the MDEP has reason to believe that the Company may be a potentially responsible party, along with several others, with respect to certain metal salvaging sites. See Footnote I of the Company's Financial Statements. Pipeline Safety Matters The DOT's Office of Pipeline Safety, from time to time, issues safety regulations pertaining to the installation, testing and repair of underground gas mains and related gas distribution facilities by pipeline and gas distribution companies. While the regulations may increase the Company's expenses, the Company does not believe such regulations will have a material adverse effect on its operating expenses or its construction plans for the foreseeable future. Construction by a Massachusetts gas company of any manufacturing or storage facility or pipeline having a pressure in excess of 100 pounds per square inch (psi) and a length greater than one mile requires approval by the Energy Facilities Siting Board, a division of the MDPU created for the purpose of implementing energy policies designed to provide energy supply with a minimum impact on the environment and at the lowest possible cost. Compliance with the procedures of this Board and other environmental laws and regulations may result in construction delays or increased costs with respect to future expansion. The Company does not presently have any construction plans that would require the approval of the Board. Personnel On August 31, 1995, the Company had 128 permanent employees, 76 of whom were represented by the United Steelworkers of America, AFL-CIO-CLC, Local 12086. The current three-year labor contract with the Steelworkers covering all hourly workers extends through February 4, 1999. Item 2: Properties The Company's property consists primarily of its distribution system and related facilities. As of August 31, 1995, the Company had approximately 744 miles of gas mains and 37,124 gas services as well as meters, measuring and regulator station equipment, and rental equipment on customers' premises. The Company also owns a propane plant with a storage capacity of 40,000 Mcf. In addition, the Company, through its wholly owned subsidiary, LNG Storage, Inc., owns an LNG storage facility with a storage capacity of 400,000 Mcf. On August 31, 1995 the Company's gross utility plant amounted to $91,462,732 at historical cost. Substantially all of the properties owned by the Company, other than expressly exempted property, are subject to a lien under the indenture securing the Company's First Mortgage Bonds. The Company's gas supply contracts have also been assigned as collateral security for the Company's First Mortgage Bonds. The indenture calls for a trustee or receiver to take possession of the property if there is a default under its terms. The property exempted includes cash, receivables, supplemental fuel inventories, materials and supplies, rental appliances, office furniture and equipment and an LNG storage facility. The LNG storage facility, while unencumbered with respect to the Company's First Mortgage Bonds, is encumbered by a separate mortgage note. The Company leases its corporate headquarters building and distribution facilities. The lease agreement is scheduled to expire in October 2005. Annual rental payments amount to $102,500. The Company also has a division office that is rented under an agreement scheduled to expire on May 31, 1996. Item 3: Legal Proceedings There are certain non material routine claims incidental to its business pending against the Company, all of which are covered by insurance or reserves. Management believes that the Company has adequate defenses against these claims and it is the Company's intention to contest these claims. In view of the insurance coverages, the potential liabilities are not expected to materially affect the financial condition of the Company. Item 4: Submission of Matters to a Vote of Security Holders None. PART II Item 5: Market for Registrant's Common Equity and Related Stockholder Matters The Company's Common Stock is traded on the Nasdaq/NMS under the symbol "ECGC." On October 31, 1995, the Common Stock was held by 1,383 stockholders of record. The following table sets forth, for the quarters indicated, the high and low sale prices as reported by Nasdaq/NMS, and the cash dividends per share declared in such quarters.
Cash Dividends Market Price Per Share High Low Fiscal Year Ended August 31, 1994 First Quarter $30.50 $29.00 $0.37 Second Quarter 29.50 26.75 0.38 Third Quarter 28.00 24.75 0.38 Fourth Quarter 25.75 24.25 0.38 Fiscal Year Ended August 31, 1995 First Quarter 25.50 24.25 0.38 Second Quarter 25.25 23.50 0.39 Third Quarter 24.75 22.00 0.39 Fourth Quarter 25.50 22.50 0.39 Fiscal Year Ending August 31, 1996 First Quarter (through November 10, 1995) 25.25 24.25 0.39*
*Paid on October 1, 1995 to shareholders of record on September 18, 1995. The Company has paid regular dividends since 1914. Common Stock dividend payments in fiscal 1995 totaled $1.55 per share, as compared to $1.51 in fiscal 1994. Although the Company expects to continue to pay dividends at or near the current rate for the foreseeable future, the declaration of future dividends will be at the direction of the Company's Board of Directors and dependent on business conditions, earnings, contractual restrictions and cash requirements of the Company. Item 6: Selected Financial Data The following table sets forth certain selected consolidated financial data of the Company and its subsidiaries and the ratio of earnings to fixed charges for, or as of the end of, the five fiscal years ended August 31, 1995. Due to the seasonal nature of the Company's business, a substantial portion of the Company's operating revenues are derived from operations during the second and third quarters of each fiscal year. The selected consolidated financial data are qualified by reference to the consolidated financial statements and the notes thereto and other information and data set forth elsewhere in this Annual Report or incorporated by reference herein. SELECTED CONSOLIDATED FINANCIAL DATA Fiscal Years Ended August 31, 1995 1994 1993 1992 1991
(000s omitted, except for per share and ratio information) Income Statement Data: Operating revenues $45,050 $48,536 $45,016 $42,913 $38,357 Operating income 5,909 5,794 5,766 5,243 4,741 Income available for common stock 3,180 3,302 2,880 2,331 1,895 Shares of common stock outstanding, weighted average 1,591 1,559 1,475 1,306 1,281 Earnings per common share $2.00 $2.12 $1.95 $1.79 $1.48 Cash dividends declared per common share $1.55 $1.51 $1.47 $1.43 $1.40 Ratio of earnings to fixed charges (1) 2.54x 2.83x 2.45x 2.11x 1.86x Balance Sheet Data: Long-term debt (excluding current portion) $20,689 $21,713 $22,148 $21,031 $23,011 Redeemable preferred stock 336 350 364 378 392 Common stock equity 30,709 28,870 26,985 20,982 19,782 Total capitalization $51,734 $50,933 $49,497 $42,391 $43,185 ====== ====== ====== ====== ====== Capital lease (excluding current portion) $ 654 $ 700 $ 742 $ 781 $ 816 ====== ====== ====== ====== ====== Total assets $86,582 $83,511 $76,535 $73,157 $65,737 ====== ====== ====== ====== ======
_______________________ (1) In computing the ratio of earnings to fixed charges, "earnings" are defined as income before income taxes and fixed charges. "Fixed charges" consist of interest, including the amount capitalized, interest on the obligation under the supplemental fuel inventory trust, amortization of debt expense and the estimated interest portion (one-third) of rental payments. Item 7:Management's Discussion and Analysis of Financial Condition and Results of Operations Fiscal Years Ended August 31, 1995 and 1994 Revenues Using a twenty-year average, the Company's service territory incurs 6,772 effective degree days in one year. Fiscal 1995 had 6,258 effective degree days compared to 7,012 in fiscal 1994. As a result, the volume of sales to the Company's two major firm customer classes, residential heating and commercial and industrial, decreased by 8.4% from 5,497,235 Mcf in 1994 to 5,036,056 Mcf in the current year. The warmer weather, coupled with a 1.2% decrease in price, resulted in revenues of $45,049,573 compared to $48,536,005 in the prior year. Revenues consist of three components: firm gas revenues (whereby the Company must supply the customer on demand), interruptible revenues (whereby the Company may curtail gas supplies to large industrial customers during the peak winter season), and other revenues (primarily appliance rentals and service work). Firm revenues in fiscal 1995 were 9.5% lower than in fiscal 1994. The decrease was attributable to the weather and price factors discussed previously, as the Company's customer base increased by nearly 3.0%. The average unit price of gas sold to all customers, including interruptible customers, decreased 8.2% to $7.40 from $8.06 in fiscal 1994. For firm customers, the average unit price decreased to $8.36 from $8.47 in the prior year. The Company's interruptible revenues increased 117.6% as interruptible sales volumes increased 525,651 Mcf. The increase in interruptible sales volumes and revenues was primarily a result of the Company's ability to purchase natural gas on a low cost spot market basis. If interruptible volumes exceed a threshold based on sales during the last four years, the Company may retain 10% of the gross profit on interruptible sales and refund the remaining 90% to the Company's firm customers. In fiscal 1995, the required volumes of interruptible sales were not obtained, and the Company returned all gross profit on interruptible sales to its firm customers. Therefore, the increase in volumes did not significantly impact the Company's earnings. Other revenues decreased slightly to $1,105,979 from $1,111,654 in fiscal 1994. During fiscal 1995, the Company added 955 new customers. The Company's ability to attract customers has been assisted by the improving economy and resultant new construction. Although there was an unfavorable price comparison with oil, which is the Company's primary competition in the area of space heating, the environmental and convenience advantages of natural gas allow the Company to compete on a favorable footing. Operating Expenses The Company's major operating expense is its cost of gas which decreased 9.9% to $22,525,442 in fiscal 1995 from $25,000,794 in fiscal 1994. This decrease was primarily due to a decrease of 8.4% in firm volumes of gas sold. These gas costs are recovered from the Company's firm customers through a Standard Cost of Gas Adjustment ("SCGA") which is adjusted semi-annually to reflect any changes in gas costs. Operations and maintenance expenses decreased 9.2% to $11,078,029 in fiscal 1995 from $12,206,720 in fiscal 1994. This decrease was mainly attributable to: decreases of approximately $600,000 in outside services, $220,000 in medical expenses and $340,000 in uncollectible accounts. The reduction in outside services expense was primarily related to the cost of one-time items such as actuarial services relating to employee benefits, including medical costs for current and future retirees; legal and other consulting services relating primarily to regulatory affairs such as interruptible and firm transportation rates; general comments on utility mergers and acquisitions; and other regulatory items incurred in fiscal 1994. The decrease in employee benefits was primarily related to reduced medical costs for current and future retirees as medical utilization decreased. Utility Plant depreciation expense increased 6.8% to $2,500,585 in fiscal 1995 from $2,341,381 in fiscal 1994, reflecting the ongoing investment in upgrading and expanding the Company's distribution system. Taxes, other than federal income, decreased 2.4% to $1,634,216 in fiscal 1995 from $1,675,782 in fiscal 1994. This decrease was related to a decrease in state income taxes resulting from lower pre-tax earnings. Federal income taxes decreased 7.6% to $1,401,858 in fiscal 1995 from $1,517,130 in fiscal 1994, also reflecting the decrease in the Company's pre-tax earnings. The Company's combined effective tax rate for both federal and state income taxes was 34.6%. Interest on long-term debt decreased 3.5% to $2,048,959 in fiscal 1995 from $2,124,058 in fiscal 1994. This decrease was related to the sinking fund payments of long-term debt. Other interest expense increased 108.8% to $732,941 in fiscal 1995 from $351,088 in fiscal 1994. This increase was primarily attributable to higher levels of short-term debt outstanding and higher interest rates in fiscal 1995 as compared to fiscal 1994. Income available for common stock decreased 3.7% to $3,179,778, or $2.00 per share, in fiscal 1995 from $3,301,711, or $2.12 per share, in fiscal 1994. Dividends per share declared and paid for fiscal 1995 and 1994 were $1.55 and $1.51, respectively. Fiscal Years Ended August 31, 1994 and 1993 Revenues The Company experienced 7,012 effective degree days in fiscal 1994 compared to only 6,956 in fiscal 1993. As a result, the volume of unit sales in the Company's two major customer classes, residential heating and commercial and industrial, increased by 3.1% from 5,175,765 Mcf in 1993 to 5,338,422 Mcf in the current year. The colder than normal weather, plus a 4.2% increase in rates approved by the DPU effective December 1, 1991, resulted in increased revenues from $45,016,043 to $48,536,005. Firm revenues increased nearly 7.3% over fiscal 1993, primarily due to the weather and rate factors indicated above, as the Company's customer base increased by only 2.2%. The average unit price of all gas sold to customers, including interruptible customers, increased 2.7% to $8.06 from $7.85 in fiscal 1993. For firm customers only, the average unit price increased to $8.47 from $8.13 in the prior year. The Company's interruptible revenues increased 36.0% as interruptible volumes increased 116,679 Mcf. The increase in interruptible volumes was primarily due to the availability of natural gas at a more favorable price than oil. The increase in volumes did not significantly impact the Company's earnings due to the accounting treatment discussed above. Other revenues increased slightly to $1,111,654 from $978,764 in 1993. Operating Expenses The Company's major operating expense is its cost of gas, which increased 6.6% to $25,000,794 in fiscal 1994 from $23,456,542 in fiscal 1993. This increase was due to additional volumes of gas sold. Operations and maintenance expenses increased 10.0% to $12,206,720 in fiscal 1994 from $11,097,811 in fiscal 1993. This increase was mainly attributable to: increases of approximately $500,000 in outside services, $250,000 in medical expenses, $120,000 in regulatory expenses, $105,000 in legal and consulting costs related to Order 636, and an increase of approximately $60,000 related to additional volumes of LNG vaporized. The additional outside service expense was primarily related to items such as actuarial services relating to employee benefits, including medical costs for current and future retirees; legal and other consulting services relating primarily to regulatory affairs such as interruptible and firm transportation rates; general comments on utility mergers and acquisitions; and other regulatory items. The increase in employee benefits was primarily related to $600,000 for additional medical costs for current and future retirees as the Company has commenced recognizing these expenses over a twenty-year period. These costs were offset by a reduction of approximately $350,000 in medical expenses for current employees. Utility Plant depreciation increased 7.6% to $2,341,381 in fiscal 1994 from $2,175,693 in fiscal 1993, reflecting the increase in the Company's utility plant. Taxes, other than federal income, increased 38.7% to $1,675,782 in fiscal 1994 from $1,208,506 in fiscal 1993. This increase was due to an increase in real estate and property taxes associated with the Company's increased investment in utility plant and an increase in state income taxes resulting from the increase in the Company's pre-tax earnings. Federal income taxes increased 15.7% to $1,517,130 in fiscal 1994 from $1,311,456 in fiscal 1993, also reflecting the increase in the Company's pre-tax earnings. The Company's combined effective tax rate for both federal and state income tax purposes was 35.8%. Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994 from $2,442,345 in fiscal 1993. This decrease was related to the prepayment in 1993 of long-term debt. Other interest expense increased 74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993. Other interest expense increased 74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993. This increase was primarily attributable to higher levels of short-term debt outstanding and higher interest rates in fiscal 1994 as compared to fiscal 1993. Interest on long-term debt decreased 13.0% to $2,124,058 in fiscal 1994 from $2,442,345 in fiscal 1993. This decrease was related to the prepayment in 1993 of long-term debt. Other interest expense increased 74.5% to $351,088 in fiscal 1994 from $201,208 in fiscal 1993. This increase was primarily attributable to higher levels of short-term debt outstanding and higher interest rates in fiscal 1994 as compared to fiscal 1993. Income available for common stock increased 14.6% to $3,301,711 or $2.12 per share in 1994, from $2,880,490 or $1.95 per share in 1993. Dividends per share declared and paid for fiscal 1994 and 1993 were $1.51 and $1.47, respectively. Liquidity and Capital Resources The Company periodically borrows from banks on an unsecured, short-term basis. At August 31, 1995, the Company had $4,890,000 of outstanding notes payable under available lines of credit totaling $16,500,000 with five different banks. In addition, for the sole purpose of financing the Supplemental Fuel Inventory, the Company has a $7,000,000 line of credit. The Supplemental Fuel Inventory line of credit expired October 31, 1995 and the Company has a bridge loan in place until it receives Massachusetts Department of Public Utilities ("MDPU") approval for a new, long-term financing. MDPU approval is expected in late fall or early winter 1995. Due to the seasonal nature of the Company's business, the Company customarily draws upon its credit lines since both sales and construction activity are affected by seasonal weather conditions. Short-term financing is typically used to satisfy seasonal cash requirements while, on an annual basis, operating requirements are satisfied by cash-flows from operations. Funding for the Company's construction program has traditionally been generated by operations and, on a temporary basis, through short-term bank borrowings. These short-term borrowings are periodically repaid with proceeds from the issuance of long-term debt and equity. Management anticipates that these and other sources will remain available and continue to adequately serve the Company's needs. During fiscal 1995, the Company's construction expenditures were approximately $7,000,000. This compares to $6,100,000 in fiscal 1994. These capital expenditures were funded primarily from short-term debt and operations. The Company's higher construction expenditures in fiscal 1995 were primarily attributable to additional construction requirements to bring on new customers and major upgrading of the Company's existing infrastructure. Capital expenditures for fiscal 1996 are expected to be approximately $7,000,000. Regulatory and Accounting Issues The Company's revenues are based on rates regulated by the MDPU. These rates are designed to allow the Company to recover its operating costs and provide an opportunity to earn a reasonable rate of return on investor supplied funds. Once approved, the Company's rates are adjusted by a SCGA which, subject to approval by the MDPU, permits the Company to change rates to recover its gas costs and certain other costs on a dollar-for-dollar basis. The SCGA is also used as the mechanism to reduce charges to firm customers by the margin earned on sales to interruptible customers. The Company, or its predecessors, previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. Each of these facilities has been out of operation for more than 25 years. It is possible that, during the manufacturing process, some or all of the MGPs may have discharged certain substances on the sites which may now be deemed hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The Environmental Protection Agency ("EPA") and Massachusetts Department of Environmental Protection ("MDEP") are focusing on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. In 1995 an investi- gation which reported the presence of certain compounds was conducted at one of the Company's MGP sites. As a result, a second, more intensive investigation will be conducted in 1996 to determine the level of contamination and to assess whether any remediation is required. The Company does not currently possess sufficient information to determine the probability or the cost of the potential remediation, however, the MDPU provides for the recovery through the SCGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. The MDPU agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations. The natural gas industry is in the process of transitioning from a highly regulated environment to a competitive environment. Pursuant to Federal Energy Regulatory Commission ("FERC") Order 636, as supplemented by Order 636A, pipeline companies have unbundled pipeline sales, storage and transportation services. FERC Order 636 was implemented by the Company's pipeline supplier, Tennessee Gas Pipeline Company ("TGPC"), on September 1, 1993. As a result, Tennessee is providing transportation service only. The Company now contracts for its own gas supply through a consortium of gas companies and pays monthly demand charges to TGPC for the availability of pipeline capacity and transportation charges for gas transport. The Company pays charges for the cost of gas delivered and for gas inventory charges to reserve volumes of gas inventory in connection with substantially all of its long-term firm gas purchase agreements. FERC Order 636 has also required pipelines to adopt a new rate design that has shifted the recovery of the pipeline's fixed costs to a monthly demand charge for firm transportation service and away from recovery of costs of service on a volumetric basis. FERC Order 636 also allows the pipeline companies to recover transition costs incurred as they restructure their services. Tennessee began direct billing these costs to the Company on September 1, 1993 as a component of the demand charges. The Company's current estimate of its obligation for transition costs is approximately $900,000 and is based upon FERC approved filings. This estimated liability has been included in the Company's financial statements at August 31, 1995, together with the related regulatory asset. The MDPU has approved the recovery of GSR costs from all firm customers. The MDPU had previously sought comments from interested persons on how incentive regulation could improve upon the existing framework of utility regulation. As a result, as part of any general rate filing, companies must provide the MDPU with recommendations. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Essex County Gas Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of Essex County Gas Company (a Massachusetts corporation) as of August 31, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended August 31, 1995. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Essex County Gas Company as of August 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended August 31, 1995, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Boston, Massachusetts, October 30, 1995 Item 8: Financial Statements and Supplementary Data CONSOLIDATED STATEMENTS OF INCOME
Fiscal Years Ended August 31, 1995 1994 1993 Operating revenues $45,049,573 $48,536,005 $45,016,043 Less: Cost of gas 22,525,442 25,000,794 23,456,542 Operating margin 22,524,131 23,535,211 21,559,501 Operating expenses: Operations and maintenance expenses 11,078,029 12,206,720 11,097,811 Depreciation 2,500,585 2,341,381 2,175,693 Taxes, other than federal income 1,634,216 1,675,782 1,208,506 Federal income taxes 1,401,858 1,517,130 1,311,456 Total operating expenses 16,614,688 17,741,013 15,793,466 Operating income 5,909,443 5,794,198 5,766,035 Other income (expense), net 6,202 (7,828) (184,152) Income before interest charges 5,915,645 5,786,370 5,581,883 Interest charges: Interest on long-term debt 2,048,959 2,124,058 2,442,345 Amortization of deferred debt expense 27,081 26,697 84,323 Other interest expense 732,941 351,088 201,208 Allowance for funds used during construction (92,428) (37,268) (47,337) Total interest charges 2,716,553 2,464,575 2,680,539 Net income 3,199,092 3,321,795 901,344 Annual redeemable preferred dividend requirements (19,314) (20,084) (20,854) Income available for common stock $3,179,778 $ 3,301,711 $ 2,880,490 ========== =========== =========== Shares of common stock outstanding (weighted average) 1,591,372 1,558,574 1,475,313 Earnings per common share $ 2.00 $ 2.12 $ 1.95 Cash dividends declared per common share $ 1.55 $ 1.51 $ 1.47 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Fiscal Years Ended August 31, 1995 1994 1993 Balance at beginning of year $11,857,299 $10,903,703 $10,198,858 Net income 3,199,092 3,321,795 2,901,344 Total 15,056,391 14,225,498 13,100,202 Cash dividends declared: Redeemable preferred stock 19,314 20,084 20,854 Common stock 2,460,382 2,348,115 2,175,645 Total 2,479,696 2,368,199 2,196,499 Balance at end of year $12,576,695 $11,857,299 $10,903,703 =========== =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
ASSETS August 31, August 31, 1995 1994 Utility plant, at cost $ 91,462,732 $ 85,564,414 Less: Accumulated depreciation 20,304,386 18,519,429 Net utility plant 71,158,346 67,044,985 Other property and investments 570,620 499,439 Capitalized lease (net of accumulated amortization of$423,806 in 1995 and $381,858 in 1994) 699,991 741,939 Current assets: Cash and cash equivalents 136,925 130,939 Accounts receivable: Customers (net of allowance for uncollectible accounts of $595,000 in 1995 and $804,000 in 1994) 1,418,510 1,629,383 Other 280,889 407,523 Income tax refunds receivable 200,000 688,000 Supplemental fuel inventory 6,477,155 6,783,404 Materials and supplies (at average cost) 594,817 583,422 Prepaid deferred income taxes 1,397,422 816,445 Prepayments and other 350,660 316,738 Total current assets 10,856,378 11,355,854 Deferred charges: Unamortized debt expense and other 1,028,319 1,231,689 Regulatory assets 2,267,954 2,636,658 Total deferred charges 3,296,273 3,868,347 $ 86,581,608 $ 83,510,564 ============ ========== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES
August 31, August 31, 1995 1994 Common stock equity $30,709,276 $28,870,444 Redeemable preferred stock 336,000 350,000 Long-term debt, less current portion 20,689,366 21,713,124 Total capitalization 51,734,642 50,933,568 Noncurrent obligations under capital lease 654,390 699,991 Current liabilities: Current portion of long-term debt 978,758 1,035,304 Current obligation under capital lease 45,599 41,948 Obligations under supplemental fuel inventory trust 5,131,153 6,428,770 Notes payable, banks 4,890,000 4,500,000 Accounts payable 2,986,307 2,930,578 Accrued interest 825,322 625,784 Refundable gas costs 2,490,178 770,184 Accrued transition costs 858,715 1,018,531 Supplier refund due customers 2,454,739 1,661,812 Other 850,404 852,259 Total current liabilities 21,511,175 19,865,170 Commitments and contingencies Deferred credits: Accumulated deferred income taxes 9,092,349 8,452,562 Unamortized investment tax credit 1,280,680 1,350,779 Deferred directors' fees 879,009 777,871 Other 1,429,363 1,430,623 Total deferred credits 12,681,401 12,011,835 $86,581,608 $83,510,564 =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Fiscal Years Ended August 31, 1995 1994 1993 Operating activities: Net income $ 3,199,092 $ 3,321,795 $ 2,901,344 Adjustments to reconcile net income to net cash: Depreciation, including amounts related to non-utility operations 2,920,476 2,754,465 2,589,867 Provisions for uncollectible accounts (208,797) 761,385 741,431 Deferred income taxes 40,876 1,006,618 706,519 Amortization 8,390 7,305 96,032 Noncash compensation associated with ESOP 225,000 150,000 150,000 Cash (used in) provided by working capital: Decrease (increase) in accounts receivable 546,304 (912,662) (430,151) Decrease (increase) in inventories including fuel 294,854 (462,827) 777,064 Decrease (increase) in prepayments and other (33,922) 185,674 58,740 Increase in accounts payable 55,729 104,406 167,653 Increase in supplier refund obligations 792,927 1,661,812 - (Increase) decrease in taxes payable/receivable 488,000 (374,323) (313,677) (Decrease) increase in recoverable (refundable) gas costs 1,719,994 (154,584) (84,886) Other, net 658,391 (837,888) 273,654 Total adjustments 7,508,222 3,889,381 4,732,246 Net cash provided by operating activities 10,707,314 7,211,176 7,633,590 Investing activities: Utility capital expenditures (6,967,340) (6,131,471) (6,671,526) Payments for retirements of property, plant and equipment, net (66,497) (183,999) (78,401) Net cash used in investing activities (7,033,837) (6,315,470) (6,749,927) Financing activities: Dividends paid (2,479,696) (2,368,199) (2,196,499) Issuance of common stock 814,126 730,874 5,106,677 Issuance of long-term debt - - 4,661,445 Retirements of preferred stock (14,000) (14,000) (14,000) Principal retired on long-term debt (855,304) (193,340) (4,219,742) (Decrease) increase in supplemental fuel inventory trust (1,297,617) 862,068 (1,278,003) (Decrease) increase in notes payable, banks 390,000 300,000 (3,250,000) Payment of ESOP debt (225,000) (150,000) (150,000) Net cash used in financing activities (3,667,491) (832,597) (1,340,122) Net (decrease) increase in cash and cash equivalents 5,986 63,109 (456,459) Cash and cash equivalents at beginning of year 130,939 67,830 524,289 Cash and cash equivalents at end of year $ 136,925 $ 130,939 $ 67,830 =========== =========== ============= Supplemental disclosures: Cash paid during the year for: Interest (net of amount capitalized) $ 2,517,015 $ 2,449,138 $ 2,650,475 ============ =========== ============ Income taxes $ 1,743,197 $ 1,196,360 $ 1,305,394 ============ ============ ============ The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
August 31, August 31, 1995 1994 Common stock equity: Common stock, $2.50 par value, 5,000,000 authorized shares Issued and outstanding, 1,607,061 at August 31, 1995 and 1,572,062 at August 31, 1994 $ 4,017,653 $ 3,930,155 Additional paid-in capital 14,311,026 13,532,990 Unrealized gain on investments available for sale, net 28,902 - Retained earnings 12,576,695 11,857,299 30,934,276 29,320,444 Less: Shares held by ESOP purchased with debt 225,000 450,000 Total common stock equity 30,709,276 28,870,444 Redeemable preferred stock: 5.50% series, $100 par value, 7,000 authorized shares Outstanding, 3,360 at August 31, 1995 and 3,500 at August 31, 1994 336,000 350,000 Long-term debt: First Mortgage Bonds: 10 1/4%, due serially from 1994 to 2003 5,400,000 6,000,000 10.10%, due serially from 2010 to 2020 8,000,000 8,000,000 13,400,000 14,000,000 Mortgage Note: 8 1/2%, due serially from 1976 to 1997 838,124 1,048,428 Debentures: 8 5/8%, due 2006 2,245,000 2,250,000 8.15%, due 2017 4,960,000 5,000,000 7,205,000 7,250,000 ESOP Loan Guarantee: 7.0% due serially from 1987 to 1996 225,000 450,000 Total debt 21,668,124 22,748,428 Less: Current portion maturing and payable 978,758 1,035,304 Total long-term debt 20,689,366 21,713,124 Total capitalization $ 51,734,642 $ 50,933,568 ============= ============ The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A. Summary of Significant Accounting Policies General Essex County Gas Company is a public utility engaged in the distribution and sale of natural gas for residential, commercial and industrial uses. Its service area is located in northeastern Massachusetts. Regulation The Company is subject to regulation by the Massachusetts Department of Public Utilities ("MDPU") with respect to its rates and accounting practices. The accounting policies conform to generally accepted accounting principles as applied to regulated public utilities and reflects the effects of the ratemaking process in accordance with Statement of Financial Accounting, Standard No. 71, "Accounting for Certain Types of Regulation ("SFAS 71"). Under SFAS 71, a utility is allowed to defer costs that otherwise would be expensed in recognition of the ability to recover them in future rates. The Company has established regulatory assets in cases where the MDPU has permitted or is expected to permit the recovery of specific costs over time. As of August 31, 1995, principal regulatory assets include (1) approximately $860,000 for transition costs associated with FERC Order 636, (2) $520,000 related to a settlement payment for a supplemental retirement plan, and (3) $425,000 related to deferred income taxes. Included in deferred credits is a regulatory liability of $794,000 related to deferred income taxes. Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" ("SFAS 121") was issued in March 1995 and is effective for the Company on September 1, 1996. SFAS 121 established accounting standards for the impairment of long lived assets. It requires that regulatory assets which are no longer probable of being recovered be written off. Based upon the current regulatory environment in the Company's service territory, it is not expected that the adoption of SFAS 121 will have a material impact on the Company's financial position or results of operations. Principles of Consolidation and Presentation The consolidated financial statements include the accounts of LNG Storage, Inc., a wholly owned subsidiary. All material intercompany balances and transactions have been eliminated. Cash equivalents are defined as investments with an original maturity of three months or less. Operating Revenues Revenues from the sale of gas are based on rates authorized by the MDPU and are recorded in the period the bill is rendered. Meters are read and bills are rendered on a cycle basis throughout the month. As a result, the volumes of gas delivered to customers in any period may be more or less than the usage for which customers are billed. The Company's rates include a Cost of Gas Adjustment Factor which permits the Company to recover the difference between gas costs incurred by the Company and gas costs billed to customers. The amount of the difference is deferred for accounting purposes and expensed when reflected in billings in subsequent periods. Utility Plant Utility plant and other property are stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and material, allocable overhead, allowance for funds used during construction and indirect charges for engineering and supervision. Expenditures for ordinary maintenance and repairs are charged to expense as incurred. Depreciation for financial reporting purposes is calculated on a straight-line basis. The annual provision for depreciation, based on the average depreciable property, was equivalent to a composite depreciation rate of 3.03% for fiscal 1995, 1994, and 1993. The cost of Utility Plant retired or otherwise disposed of, in the ordinary course of business, together with costs of removal less salvage, is charged to accumulated depreciation. Reclassifications Certain prior year financial statement amounts have been reclassified for consistent presentation with the current year. B. Supplemental Fuel Inventory Trust The Company, with MDPU approval, finances its supplemental gas inventory through a single purpose trust which purchases gas with funds loaned to the trust by a bank. As required, the Company repurchases gas from the trust at prices based on original product cost, financing and trust fees. The credit agreement between the trust and the bank provides for a total commitment of up to $7,000,000. Financing and trust fees resulted in an effective interest cost to the Company of 5.9% for 1995 and 4.6% in 1994 based on average borrowing. Upon termination of the plan by either party, the Company is obligated to reimburse the trust in an amount equal to the investment in the trust not previously reimbursed plus any other obligations incurred by the trust. The Company has 240 days (60 days in the event of default) to reimburse the trust upon termination. C. Common Stock Common stock activity for the three-year period ended August 31, 1995, is as follows: Additional Number of Common Paid-in Shares Stock Capital Balance, August 31, 1992 1,317,805 $3,294,513 $ 8,238,964 Dividend reinvestment plan 15,042 37,605 321,702 Amortization of capital stock expense --- --- 40,709 Various employee stock plans 7,564 18,910 165,627 Sale of common stock 203,634 509,085 4,053,748 Balance, August 31, 1993 1,544,045 3,860,113 12,820,750 Dividend reinvestment plan 15,452 38,631 359,647 Amortization of capital stock expense - - 51,408 Various employee stock plans 10,397 25,991 247,775 Sale of common stock 2,168 5,420 53,410 Balance, August 31, 1994 1,572,062 3,930,155 13,532,990 Dividend reinvestment plan 19,276 48,190 389,246 Amortization of capital stock expense - - 51,408 Various employee stock plans 13,054 32,635 280,208 Sale of common stock 2,669 6,673 57,174 Balance August 31, 1995 1,607,061 $4,017,653 $14,311,026 ========== ========== =========== D. Redeemable Preferred Stock and Restriction on Retained Earnings The preferred stock is currently redeemable, in whole or in part, at the option of the Company, by a payment to the holder of $100 per share plus accrued dividends in the event of involuntary liquidation. This payment requirement increases fifty cents per share plus accrued dividends in the event of voluntary liquidation. A purchase agreement provides that the Company will annually offer to purchase and retire up to, but not in excess of, 140 shares of redeemable preferred stock at $100 per share plus accrued dividends. Payment of dividends on, or acquisition of, common stock is prohibited if the Company fails to cumulatively offer to purchase 280 shares of preferred stock. Required offers were made, and the Company redeemed, 140 shares during each of the three fiscal years ending August 31, 1995. Dividends on redeemable preferred stock are at a stated rate of 5.50% cumulative, payable quarterly January 1, April 1, July 1 and October 1. Under the terms of the indenture securing the First Mortgage Bonds, retained earnings in the amount of $5,192,475 as of August 31, 1995, were unrestricted as to the payment of cash dividends on common stock and the purchase, redemption or retirement of shares of capital stock. E. Interim Financing and Long-term Debt The Company periodically borrows from banks on an unsecured, short-term basis. At August 31, 1995, the Company had $4,890,000 of outstanding notes payable with a weighted average interest rate of 6.4% under available lines of credit totaling $16,500,000. The annual commitment fees related to these lines of credit are between 1/4% and 3/8% on the total amount of the line. Substantially all plant assets are pledged as collateral under the terms of the indenture of First Mortgage Bonds. The 8-1/2% Mortgage Note represents an obligation secured by the liquified gas storage facility in Haverhill, Massachusetts. In accordance with the terms of the indenture of First Mortgage Bonds, the Note Purchase Agreement of the sinking fund notes and the Mortgage Note, the Company is required to make specified sinking fund payments and other maturities of long-term debt of $978,758 in 1996, $923,830 in 1997, $960,536 in 1998, $600,000 in 1999, $600,000 in 2000 and $17,605,000 thereafter. F. Income Taxes The components of the provision for income taxes are as follows: 1995 1994 1993 Federal Current $1,469,957 $ 796,930 $1,054,220 Deferred 2,000 791,000 330,000 Amortization of investment tax credit (70,099) (70,800) (72,764) 1,401,858 1,517,130 1,311,456 State Current 292,615 173,459 213,603 Deferred 445 162,000 67,000 293,060 335,459 280,603 Total income taxes $1,694,918 $1,852,589 $1,592,059 ========== =========== =========== A reconciliation of federal income taxes calculated at the statutory rate with income tax expense shown in the financial statements for each of the three years ended August 31, is as follows: 1995 1994 1993 Federal statutory rate 34.0% 34.0% 34.0% ====== ====== ====== Federal income tax expense at statutory rates $1,663,963 $1,759,260 $1,527,756 Increase (decrease) in taxes resulting from: Amortization of investment tax credit (70,099) (70,800) (72,764) State taxes, net of federal benefit 199,980 221,403 185,596 Other (98,926) (57,274) (48,529) Total income tax expense $1,694,918 $1,852,589 $1,592,059 =========== =========== =========== Effective income tax rate 34.6% 35.8% 35.4% ====== ====== ====== Effective September 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). The adoption of SFAS 109 had no earnings impact on the Company. SFAS 109 requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse. A regulatory asset of $425,000 was established for the recovery of deficiencies in deferred taxes as a result of the net effect of establishing some deferred taxes for temporary differences using the flow-through method. Recovery of this amount will be addressed in the Company's next rate filing with the MDPU. A regulatory liability of $794,000 was established for the tax benefit of unamortized investment tax credits, which SFAS 109 requires to be treated as a temporary difference. This benefit will be passed on to customers over the lives of property giving rise to the investment credits. Significant items making up deferred tax assets and deferred tax liabilities at August 31, 1995 and 1994 are as follows: 1995 1994 Liabilities Utility Plant-primarily depreciation $ 9,957,069 $ 9,237,890 Other 332,912 425,099 10,289,981 9,662,989 Assets Investment tax credits 794,403 827,152 Other 1,800,651 1,199,720 2,595,054 2,026,872 Accumulated deferred income taxes, net $ 7,694,927 $ 7,636,117 =========== =========== The net year-end deferred income tax liabilities above are net of current deferred tax assets of $1,397,422 and $816,445, respectively, which is included in prepaid income taxes in the accompanying Consolidated Balance Sheets. Deferred federal income tax expense results from differences in the timing of recognition of certain items for tax and financial statement purposes. The components of the deferred income tax provision are as follows: 1995 1994 1993 Excess tax depreciation over book depreciation $ 593,030 $575,050 $459,099 Uncollectible accounts 70,990 (48,535) (52,768) Rate case expenses (40,939) (48,813) 56,145 Gas adjustment factor (584,798) 52,558 28,862 Other deferred charges and credits (63,865) 282,763 (52,817) Unbilled revenues 33,890 (25,033) 26,798 Deferred state taxes - (55,080) (22,780) Medical insurance reserves 4,925 - (62,458) Other (11,233) 58,090 (50,081) Deferred federal income taxes $ 2,000 $791,000 $330,000 ========== ========= ========= The tax effect of the cumulative amount of timing differences at August 31, 1995 for which deferred federal income taxes have not been provided is not significant. G. Leases The Company is obligated under various lease agreements for certain facilities and equipment used in operations. Total expenditures under operating leases for each period were $289,721 in 1995, $309,992 in 1994, and $287,736 in 1993. A summary of property classified as capital leases as of August 31, 1995 and 1994 is as follows: 1995 1994 Buildings $1,123,797 $1,123,797 Less: Accumulated depreciation 423,806 381,858 $ 699,991 $ 741,939 ========== ========== In accordance with the rate treatment allowed by the MDPU, the depreciation expense of $41,948, $38,540 and $35,500, along with interest of $60,502, $63,910 and $67,000 related to the capital lease, is included in other operating expenses for the years ended August 31, 1995 and 1994 and 1993, respectively. The Company also has various operating lease agreements for equipment, vehicles and office space. The remaining minimum annual rental commitment for these and all other non-cancellable leases is as follows: Capital Leases Operating Leases 1996 $102,500 $297,599 1997 102,500 254,357 1998 102,500 184,384 1999 102,500 26,644 2000 102,500 3,387 Thereafter 529,584 3,543 1,042,084 Total minimum lease payments $769,914 ======== Less: Amount representing interest 342,093 $699,991 ======== H. Employee Benefits Pension Plans The Company has two principal pension plans covering substantially all employees. The actuarial method for determining annual pension cost is the Projected Unit Credit method. Net pension cost for 1995, 1994 and 1993 consist of the following components: 1995 1994 1993 Service cost -- benefits earned during the year $231,741 $212,190 $ 175,000 Interest cost on projected benefit obligations 668,107 617,749 568,000 Actual return on plan assets (887,022) (74,969) (933,000) Net amortization and deferral 412,504 (444,131) 476,000 Net pension cost $425,330 $310,839 $286,000 ========= ========= ========= The expected long-term rate of return on assets was 8.5% in 1995 and 1994, the discount rate used in determining the actuarial present value of the projected obligation was 8.0% in 1995 and 1994 and the expected rate of pay increase was 6.0% in 1995 and 1994. The following table sets forth the funding status of the pension plans and amounts recognized in the Company's balance sheet based on measurement dates of August 31, 1995 and 1994: 1995 1994 Actuarial present value of benefit obligations (in thousands) Vested benefit obligation $ 7,960 $ 7,476 ======== ======== Accumulated benefit obligation $ 8,433 $ 7,884 ======== ======== Projected benefit obligation for service rendered to date $ 9,329 $ 8,634 Plan assets, primarily listed stocks, corporate bonds and U.S. bonds, at fair value 8,034 7,467 Projected benefit obligation in excess of plan assets (1,295) (1,167) Unrecognized net gain (321) (437) Unrecognized prior service cost 1,537 1,633 Adjustment required to recognize additional minimum liability (330) (465) Unrecognized net obligation at transition 10 20 Net pension liability $ 399 $ 416 ======== ======== Assets in the pension plan are currently held in listed stocks, corporate bonds and government bonds. Employee Stock Ownership Plan On September 1, 1986, the Company created an Employee Stock Ownership Plan and Trust ("ESOP"). The Company contributes annually to a trust an amount equal to principal plus interest and any other fees net of interest income earned by the trust and dividends on unallocated shares. The Trust was created primarily to acquire shares of the Company's common stock for the exclusive benefit of the participants (substantially all nonbargaining employees). During fiscal 1987, the Trust borrowed $1,500,000 and acquired 82,800 shares, as adjusted for a two-for-one stock split effective April 1, 1987, of the Company's previously unissued common stock. The loan is guaranteed by the Company and is payable in 10 equal annual installments of $150,000 through October, 1996. The ESOP is recorded as a liability and the offsetting debit is accounted for as a reduction of common stock equity in the accompanying consolidated balance sheets. Interest is payable monthly at a floating rate which is 80% of the current prime rate. The charge to income, which equals the Company's contribution, for 1995 was $141,359, for 1994 was $223,349, and for 1993 was $152,949. Interest on ESOP debt was $17,365 for 1995, $37,023 for 1994, and $51,758 for 1993. Dividends on unallocated ESOP shares used to pay debt service for all periods presented was $27,193 for 1995, $41,352 for 1994, and $52,439 for 1993. Savings Plan The Company has a thrift savings plan in which the Company matches a portion of employee contributions up to six percent of a participant's wages. The Company contributed approximately $118,939 to the plan in 1995, $108,000 to the plan in 1994, and $63,500 in 1993. Postretirement Benefits Other Than Pension On September 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions ("SFAS 106"). This standard requires the accrual of the expected cost of such benefits during the employee's years of service and the recognition of an actuarially determined postretirement benefit obligation earned by existing retirees. The assumptions and calculations involved in determining the accrual and the accumulated postretirement benefit obligation closely parallel pension accounting requirements. The cumulative effect of the implementation of SFAS 106 as of September 1, 1994 is being amortized over 20 years. Prior to 1994, the cost of postretirement benefits was recognized on a pay-as-you-go basis. The cost of retiree medical and life insurance benefits under the traditional pay-as-you-go basis was $223,000 for 1993. The Company is currently recovering the full SFAS 106 cost in rates. The net periodic postretirement benefit cost for the year ended August 31, 1995 and 1994 were as follows: 1995 1994 Service cost $ 84,550 $110,691 Interest cost 284,861 296,310 Loss on plan assets 13,066 - Net amortization and deferral 157,634 203,868 Total postretirement benefit cost $540,111 $610,869 ======== ========= The funded status of the Company's postretirement benefit plan using a measurement date of July 1, 1995 and 1994, is as follows: 1995 1994 Accumulated postretirement benefit obligation: Retirees $(2,972,713) $(2,714,112) Fully eligible active Plan participants (118,200) (168,942) Other active Plan participants (1,264,135) (1,183,982) (4,355,048) (4,067,036) Plan assets at fair value 557,939 229,781 Accumulated postretirement obligation greater than Plan assets (3,797,109) (3,837,255) Unrecognized transition obligation 3,669,616 3,873,484 Unrecognized (gain) loss (3,021) (141,261) Accrued postretirement benefit cost $ (130,514) $ (105,032) ============ =========== The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.5% in 1995 and 1994. The annual increase in the cost of covered health care benefits for 1995 was 9.5% and 7.5% for participants under age 65 and over age 65, respectively, and for 1994 was 13% and 8% for participants under 65 and over 65, respectively. This increase gradually decreases to 5% in the year 2007 and thereafter. A 1% increase in the assumed health care cost trend would have increased the cost computed under SFAS 106 by $27,444 and increased the accumulated postretirement benefit by $309,465 as of August 31, 1995. The Company has established two Voluntary Employee Beneficiary Associations ("VEBA") trusts pursuant to section 501(c)9 of the Internal Revenue Code to fund these benefits. The Company also created a subaccount to its pension plan pursuant to section 401(h) of the Internal Revenue Code to satisfy a portion of its postretirement benefit obligation. The Company made contributions to the trusts and the subaccount during 1995 and 1994 totaling $514,629 and $506,000, respectively. Assets in the VEBA trusts are held in cash reserve accounts. Assets in the subaccount to the pension plan are currently held in listed stocks, corporate bonds and government bonds. Incentive Stock Option Plan In 1995 the Company adopted a Stock Option Plan ("Plan"). In accordance with the Plan, options may be granted from time to time but the total number of shares subject to the Plan shall not exceed 100,000 with not more than 25,000 shares granted during any one year to any individual. The Plan is considered an Incentive Stock Option Plan under Internal Revenue Code Section 422. During 1995, a total of 24,000 shares were granted at a price of $24.50 with exercise dates beginning February 9, 1996 and ending February 9, 2000. No options were exercised during fiscal 1995. In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based Compensation" ("SFAS 123"). The Company will be required to adopt this standard effective September 1, 1996. SFAS 123 establishes a fair value based method of accounting for stock based compensation plans. SFAS 123 allows companies to either measure compensation using the fair value method or to continue to apply the provisions of APB Opinion No. 23, "Accounting for Stock Issued to Employees" and include footnote disclosure of pro forma net income and earnings per share calculated as if the fair value method had been applied. The Company expects to adopt the latter method and concludes that the adoption of this standard will not have a material impact on the results of operations or its financial condition. I. Commitments and Contingencies Construction Expenditures The Company's construction expenditures in connection with its continuing construction program are presently estimated at $7,000,000 for 1996 and approximately $6,000,000 in each of the four following years. Gas Supply, Transportation and Storage The Company has various long-term gas supply, transportation and storage contracts with minimum cost provisions. Under these contracts, the Company is obligated to make specified minimum payments. Based on current rates and/or agreements, the minimum annual payments under these contracts are as follows: 1996 to 2000 Pipeline Transportation Demand $5,182,643 Underground Storage Demand 979,608 Underground Storage Transportation 1,004,011 Pipeline Gas Inventory Charge 1,662,951 GSR Charges 858,715 $9,687,928 =========== FERC Order 636 also allows the pipeline companies to recover transition costs created as they buy out of long-term, fixed price contracts. Tennessee Gas Pipeline Company began direct billing these costs to the Company on September 1, 1993 as a component of the demand charges. At August 31, 1995, the transition costs are estimated at $860,000 and will be billed over a period of approximately three years subject to modification and/or refund based on final FERC approval of pipeline transition costs to be recovered. Negotiations are continuing with the pipeline of several other issues. As a result, the Company is unable to predict its final obligation at this time; however, based on these and subsequent settlement activities, the Company will adjust its regulatory assets and liability accounts accordingly. The MDPU has allowed recovery of these transition costs through the cost-of-gas adjustment clause. Litigation Matters The Company is a defendant in various civil actions, which are covered by insurance and reserves. Based on the advice of legal counsel, management believes that the Company has adequate defenses against these claims and, in view of the insurance coverage, the potential liability would not materially effect the financial condition or the results of operations of the Company. Environmental Matters The Company has received notification that the Massachusetts Department of Environmental Protection (MDEP) has reason to believe that the Company may be a potentially responsible party, along with several other parties, with respect to alleged release of hazardous materials at sites in Plympton, Massachusetts. The Company does not currently have sufficient information to reasonably estimate the amount of the final liability for cleanup costs or other damages or expenses at such sites. The Company believes it should be permitted to recover these costs through rates. The Company or its predecessors previously operated four manufactured gas plants and one storage facility (collectively, "MGPs") at sites in Massachusetts. Each of these facilities has been out of operation for more than 25 years. It is possible that in the manufacturing process some or all of the MGPs may have discharged certain substances on the sites which may now be deemed to be hazardous. The Company has not ascertained the extent of any hazardous substance contamination on these sites from the MGP operations. The EPA and MDEP have recently begun to focus on the potential environmental hazards of MGPs. To the Company's knowledge, neither the EPA nor the MDEP have issued any orders to clean up any of the Company's MGP sites. In 1995 an investigation which reported the presence of certain compounds was conducted at one of the Company's MGP sites. As a result, a second, more intensive investigation will be conducted in 1996 to determine the level of contamination and to assess whether any remediation is required. The Company does not currently possess sufficient information to determine the probability or the cost of the potential remediation, however, the MDPU provides for the recovery through the SCGA of all environmental response costs associated with this and any other MGP sites over seven-year amortization periods without a return on the unamortized balance. The MDPU agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations. Subsequent Events On September 15, 1995 the MDPU approved the Company's petition to change the par value of the Company's common stock from $2.50 par value to no par value. The change was effective October 5, 1995. The Company has petitioned the MDPU for a new supplemental fuel agreement replacing the one that expired October 31, 1995. Financing from the expiration of the original arrangement to approval from the MDPU has been accomplished by a $7,000,000 floating rate bridge loan which expires December 31, 1995. The Company expects MDPU approval for the supplemental fuel agreement in December 1995. Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. PART III Item 10: Directors and Executive Officers of the Registrant The information required by Item 401 and 405 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 16, 1996. Item 11: Executive Compensation The information required by Item 402 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 16, 1996. Item 12: Security Ownership of Certain Beneficial Owners and Management The information required by Item 403 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 16, 1996. Item 13: Certain Relationships and Related Transactions The information required by Item 404 of Regulation S-K is herein incorporated by reference to Registrant's Proxy Statement dated December 5, 1995, for the Annual Meeting of Stockholders to be held on January 16, 1996. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ESSEX COUNTY GAS COMPANY (Registrant) Date: November , 1995 by Vice President and Treasurer Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date /s/ Charles E. Billups Chairman of the Board 11/28/95 /s/ Philip H. Reardon President and Chief 11/28/95 Executive Officer /s/ James H. Hastings Vice President and 11/28/95 Treasurer (Principal Financial and Accounting Officer) /s/ Benjamin C. Bixby Director 11/28/95 /s/ Daniel A. Burkhard Director 11/28/95 /s/ Edward J. Curtis Director 11/28/95 /s/ Dorothy J. Dotson Director 11/28/95 /s/ Richard P. Hamel Director 11/28/95 /s/ Robert S. Jackson Director 11/28/95 /s/ Eric H. Jostrom Director 11/28/95 /s/ Robert L. Meade Director 11/28/95 /s/ Kenneth L. Paul Director 11/28/95 /s/ Richard L. Wellman Director 11/28/95 PART IV ITEM 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K A) Documents filed as part of this report: 1. The Financial Statements of the Company, on pages 20 through 36, and the Report of Arthur Andersen LLP on page 19 herein. 2. Schedules. None. 3. Exhibits Exhibit Number Description 3.1 Restated Articles of Organization of Essex County Gas Company.3 3.2 Bylaws of Essex County Gas Company.4 4.1 The rights of holders of Redeemable Preferred Stock, 5.50% Series and the rights of holders of Common Stock, are defined in the Bylaws and the Restated Articles of Organization of the Registrant. See Exhibit 3.1. 4.2 Indenture dated as of June 1, 1986 between the Com- pany and Centerre Trust Company of St. Louis, Trustee.2 Exhibit Number Description 4.3 Eleventh Supplemental Indenture dated as of Septem- ber 15, 1988, providing for a 10 1/4% Series due 2003.1 4.4 Twelfth Supplemental Indenture dated as of December 1, 1990, providing for a 10.10% Series due 2020.4 10.1 LNG Storage, Inc., Lease Indenture of Mortgage and Deed of Trust dated April 10, 1972.1 10.2 Haverhill Familee Investment Corporation - Lease of Corporate Headquarters dated November 1, 1975.1 10.3 Arlington Trust Company - Purchase Contract, Credit Agreement, Trust Agreement and Storage Agreement dated October 1, 1980.1 10.4 Consolidated Gas Supply Corporation - Underground Storage Contract dated February 18, 1980.1 10.5 Penn-York Energy Corporation - Storage Services Agreement dated December 21, 1984.1 10.6 Canadian Gas Transportation Contract between Tennessee Gas Pipeline Company and Essex County Gas Company dated December 1, 1987.3 10.7 Phase 2 Gas Sales Agreement between Boundary Gas and Essex County Gas Company dated September 14, 1987.3 10.8 Amendment to the Agreement for the Sale of Gas between Bay State Gas Company and Essex County Gas Company dated May 6, 1988.3 10.9 Agreement for the Liquefaction of Gas between Bay State Gas Company and Essex County Gas Company dated March 14, 1988.3 10.10 Bond Purchase Agreement dated December 1, 1990, among Allstate Life Insurance Company of New York, and Essex County Gas Company.4 10.11 Iroquois Gas Transmission System, L.P. Gas Transpor- tation Contract for Firm Reserved Service dated February 7, 1991.3 Exhibit Number Description 10.12 Alberta Northeast Gas Limited (ANE), Gas Sales Contract Agreement No. 1 dated February 7, 1991.5 10.13 Aquila Energy Marketing Corporation Gas Sales Agreement dated June 5, 1992.5 10.14 Natural Gas Clearinghouse Gas Sales Agreement dated June 8, 1992.5 10.15 Tennessee Gas Pipeline Transportation Contract dated February 7, 1991.6 10.16 Tennessee Gas Pipeline Company Gas Storage Con- tract (SS-NE) TGP002099STO dated November 10, 1991.6 10.17 Tennessee Gas Pipeline Company Storage Service Transportation Contract TF-4175 dated October 28, 1991.6 10.18 The Company has entered into an amended employment contract with Charles E. Billups, Chairman of the Board.2* 10.19 Form of employment contract between the Company and each of the following officers: Wayne I. Brooks, Vice President; John W. Purdy, Jr., Vice President; James H. Hastings, Vice President and Treasurer; Allen R. Neale, Vice President; and Cathy E. Brown, Clerk. These contracts are identical to those sub- mitted with the Annual Report for each with the exception of compensation amounts.2* 10.20 Employment Agreement between the Company and Philip H. Reardon, President, dated November 19, 1992.7* 10.22 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated September 1, 1993.8 10.23 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated August 25, 1993.8 10.24 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under Transportation Service "CGT-NE" Rate Schedule) dated September 1, 1993.8 Exhibit Number Description 10.25 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under FT-A Rate Schedule) dated September 1, 1993.8 10.26 Gas Transportation Agreement between Essex County Gas Company and Tennessee Gas Pipeline Company (for use under Rate Schedule FS) dated September 1, 1993.8 10.27 Amendment to Employment Agreement between the Company and Philip H. Reardon, President, dated March 3, 1994.* 10.28 Amendment to Employment Agreement between the Company and John W. Purdy, Jr., Vice President, dated March 3, 1994.* 10.29 Amendment to Employment Agreement between the Company and Wayne I. Brooks, Vice President, dated March 3, 1994.* 10.30 Amendment to Employment Agreement between the Company and Allen R. Neale, Vice President, dated March 3, 1994.* 10.31 Amendment to Employment Agreement between the Company and James H. Hastings, Vice President and Treasurer, dated March 3, 1994.* 10.32 Amendment to Employment Agreement between the Company and Cathy E. Brown, Corporate Clerk, dated March 3, 1994.* 10.33 Essex County Gas Company Supplemental Retirement Plan for Philip H. Reardon effective January 1, 1994.* 27 Financial Data Schedule B) Reports on Form 8-K No reports on Form 8-K have been filed during the quarter ended August 31, 1995. *Denotes Management Contract. 1 Previously filed as an exhibit to Registrant's Registration Statement on Form S-7, filed October 23, 1981, File No. 2-74531 and is incorporated herein by this reference. 2 Previously filed as an exhibit to Registrant's Registration Statement on Form S-2, filed June 19, 1986, File No. 33-6597 and is incorporated herein by this reference. 3 Previously filed as an exhibit to Registrant's 10-K filed for the fiscal year ended August 31, 1988, and is incorporated herein by this reference. 4 Previously filed as an exhibit to Registrant's 10-Q filed for the quarter ended February 28, 1991, and is incorporated herein by this reference. 5 Previously filed as an exhibit to Registrant's 10-Q filed for the quarter ended May 31, 1992, and is incorporated herein by this reference. 6 Previously filed as an exhibit to Registrant's 10-K filed for the fiscal year ended August 31, 1992, and is incorporated herein by this reference. 7 Previously filed as an exhibit to Registrant's Form S-3, No. 33-69736, filed on September 30, 1993, and is incorporated herein by this reference. 8 Previously filed as an exhibit to Registrant's Form 10-K filed for the fiscal year ended August 31, 1993, and is incorporated herein by this reference. [CIK] 0000046189 [NAME] ESSEX COUNTY GAS COMPANY [MULTIPLIER] 1,000 12-MOS AUG-31-1995 AUG-31-1995 PER-BOOK [TOTAL-NET-UTILITY-PLANT] 71,158 [OTHER-PROPERTY-AND-INVEST] 524 [TOTAL-CURRENT-ASSETS] 10,856 3,296 [OTHER-ASSETS] 700 [TOTAL-ASSETS] 86,535 [COMMON] 4,018 [CAPITAL-SURPLUS-PAID-IN] 14,086 [RETAINED-EARNINGS] 12,577 [TOTAL-COMMON-STOCKHOLDERS-EQ] 30,680 [PREFERRED-MANDATORY] 336 [PREFERRED] 0 [LONG-TERM-DEBT-NET] 20,689 [SHORT-TERM-NOTES] 4,890 [LONG-TERM-NOTES-PAYABLE] 0 [COMMERCIAL-PAPER-OBLIGATIONS] 0 979 [LEASES-CURRENT] 46 [OTHER-ITEMS-CAPITAL-AND-LIAB] 28,915 86,535 [GROSS-OPERATING-REVENUE] 45,050 [INCOME-TAX-EXPENSE] 1,402 [OTHER-OPERATING-EXPENSES] 37,738 [TOTAL-OPERATING-EXPENSES] 39,140 [OPERATING-INCOME-LOSS] 5,910 [OTHER-INCOME-NET] 6 [INCOME-BEFORE-INTEREST-EXPEN] 5,916 [TOTAL-INTEREST-EXPENSE] 2,717 [NET-INCOME] 3,199 19 [EARNINGS-AVAILABLE-FOR-COMM] 3,180 [COMMON-STOCK-DIVIDENDS] 2,460 [TOTAL-INTEREST-ON-BONDS] 2,049 [CASH-FLOW-OPERATIONS] 10,707 [EPS-PRIMARY] 2.00 [EPS-DILUTED] 2.00
-----END PRIVACY-ENHANCED MESSAGE-----