ITEM 1. BUSINESS
General
The business of EnergyNorth Natural Gas, Inc. (Company), incorporated in the state of New Hampshire in 1945, is the purchase, transportation and sale of natural gas for residential, commercial and industrial use in New Hampshire. The Company is a wholly owned subsidiary of EnergyNorth, Inc. (ENI), a public utility holding company, also incorporated in the state of New Hampshire. Both the Company and ENI are headquartered at 1260 Elm Street, Manchester, New Hampshire.
In general, the senior management of ENI serves as the senior management of the Company. ENI provides for administrative support and services and establishes policies, plans and goals.
The service territory of the Company has a population of approximately 470,000 in 27 communities situated in southern and central New Hampshire, which includes the communities of Nashua, Manchester, Concord and Laconia. The service area encompasses approximately 922 square miles. Located within 30 to 85 miles of Greater Boston, the Company's service territory offers a favorable business climate with no general sales or personal income taxes, a productive labor force and a comfortable, safe and clean environment for residents and tourists.
After three years of nonfarm employment growth rates greater than both the New England average and the national average, the state of New Hampshire nonfarm growth rate was 1.6% in 1998. This compares to a 2.4% average growth rate nationally and a 2.2% average rate for New England for the same period. However, New Hampshire employment growth in 1999 is forecasted to be 2.4%. New housing permits increased 15.4% in 1998 compared to 1997 and are expected to increase another 5.4% in 1999. While the New Hampshire unemployment rate for 1999 is forecasted at 2.4% compared to 2.6% in 1998, the labor force is forecasted to increase by 1.5% in 1999. Job growth and low unemployment in the Company's service area tend to result in an increase in volumes transported and sold and numbers of customers. (All employment and housing statistics are taken from The New England Economic Project's October 1998 Economic Outlook for New Hampshire.) In fiscal 1998, the Company experienced net growth of more than 2.4% in total customers compared to fiscal 1997.
The Company's marketing focus continues to stress low cost growth by concentrating on adding new customers along the Company's more than 1,000 miles of gas mains and adding load from the existing customer base, while also expanding its system of mains into areas in which there is a significant demand for natural gas service. The Company has more than a 28% share of the home heating market (based on households) within its service territory, creating a potential for increased sales where the natural gas pipeline is located and alternative fuels are used. In New Hampshire, fuel oil has a
penetration of over 55% of the home heating market. Currently, the price of natural gas for heating is higher than the full-service price of fuel oil. From a total energy perspective, natural gas is a stronger competitor with a complete line of gas appliances and uses, including ranges, water heaters, clothes dryers, fireplaces and gas logs, outdoor lights and natural gas heat pumps for heating and cooling. While these multiple uses provide opportunities to be the total energy provider to new customers, they also provide opportunities for expansion within the existing customer base. Due to continued customer conversions from other energy sources and expansion of its service territory, the Company has an opportunity for growth in the retail sales market. During the past five years, the Company has experienced an annual average customer growth rate of more than 2.3%. This compares to an approximate 1.3% national average for local distribution companies, according to the American Gas Association. Additional growth in distribution operations also occurs as industrial and commercial customers turn to natural gas for electric generation because of a price advantage and as a means to ensure compliance with the provisions of the Clean Air Act. As the electric industry continues to move toward deregulation, this option has become more attractive. The development of new gas-burning technologies for industry has provided opportunities for increased gas usage in market sectors that are not sensitive to the weather.
Gas Distribution Business
The Company distributes natural gas as a regulated utility pursuant to franchise authority granted by the State of New Hampshire Public Utilities Commission (Commission). No operations are outside New Hampshire. While the franchise area of the Company is primarily residential in character, 59% of sales volumes are commercial and industrial. As of September 30, 1998, the Company served nearly 69,600 customers, of which approximately 88% were residential and 12% were commercial and industrial. During fiscal 1998, no customer purchased more than 4.2% of the Company's total annual sales and transportation volume.
The Company offers firm and interruptible transportation service to its commercial and industrial customers. Transportation service allows a customer to purchase a natural gas supply directly from a third-party marketer. The marketer delivers the gas supply to one of the Company's interstate pipeline take stations. The customer contracts with the Company to transport the gas from the take station to its facility. To ensure a continual, uninterrupted supply, the Company also provides an optional, separate standby service as a backup to the gas supplies of transportation customers. As of September 30, 1998, the Company had 66 firm transportation customers.
The Company distributes gas to its utility customers through a system of underground pipelines connected with its three operations centers in Manchester, Nashua and Tilton, six take stations located in Manchester, Londonderry, Windham, Concord, Hooksett and Suncook and four production plant facilities in Manchester, Nashua, Concord and Tilton. The pipelines are generally located in public ways and are subject to licenses granted by municipalities. The Company serves over 75% of New Hampshire's natural gas customers.
On November 3, 1998, the Company filed a petition with the Commission for authority to operate in the city of Berlin, New Hampshire. Berlin is a community of approximately 12,000 inhabitants in the
northern tier of the state. The petition is supported by a request from the State of New Hampshire Department of Corrections to provide natural gas service to a new prison complex being constructed in Berlin. The prison will be located approximately one-half mile from the Portland Natural Gas Transmission System. The Company anticipates additional development in the vicinity of the prison complex, as well as interest from other energy users in the city of Berlin.
Summary of Revenues
Revenues, in thousands of dollars, attributable to various categories of gas distribution and related operations (unaudited) during the last three fiscal years are as follows:
September 30, ---------------------------------- 1998 1997 1996 ----------------------------------
Sales service $82,686 $91,670 $76,007 Transportation service 2,610 1,308 1,503 Service and appliance sales 1,910 1,949 1,781 Rentals 686 750 821 ---------------------------------- $87,892 $95,677 $80,112 ==================================
During the winter period, November 1 through March 31, the Company's gas revenues are substantially higher than during the summer months. The increase in gas revenues during the winter, and the concomitant increase in gas supply requirements, occurs because approximately 90% of the Company's customers use natural gas for heating.
Deregulation
The Company has been providing gas transportation rates and separate standby and balancing services for commercial and industrial customers since late 1993.
Gas transportation services have allowed customers to utilize the Company's distribution system for the transportation of gas purchased from third-party gas marketers, creating competition from gas marketers for the sale of gas to end users. At September 30, 1998, the Company had 66 firm transportation customers. These customers are, for the most part, large commercial and industrial customers. The volume transported for firm transportation customers in fiscal 1998 was 1.5 Bcf, approximately 13% of the Company's total gas delivered. The Company is participating in a proceeding at the Commission to examine further unbundling of the natural gas industry in New Hampshire. The purpose of the proceeding is to determine whether and to what extent unbundling provides benefits to customers and to make recommendations to the Commission as to the advisability of further unbundling to other classes of customers. Recommendations to the Commission are not expected until late summer of 1999. The Company cannot predict the outcome of the proceeding, or the impact on transportation volumes or customers. The Company expects the number of transportation customers and the volume of gas transported to increase.
The Company is the sole distributor and transporter of natural gas in its franchise area. The Tennessee Gas Pipeline Company ("Tennessee") is the only interstate pipeline to serve the Company's franchise area. For that reason, and because installation of private transmission mains would typically be impractical, customers have not attempted to bypass the Company's distribution system.
Competition
Natural gas competes mainly with electricity and fuel oil. The principal competitive factors between natural gas and alternative fuels are the price of the fuel and the conversion costs from one fuel to another. Competition is greatest among the Company's commercial and industrial customers who have the capability to use alternative fuels. The Company provides flexible rates for users with dual-fuel capabilities in order to better compete with the alternative fuels.
Under current market conditions, natural gas has a significant price advantage over electricity in New Hampshire. Natural gas heating costs are currently less than one-third of electric heating costs. At the present time, the price of natural gas for heating is higher than the full-service price of fuel oil. The Company continues to add customers who might otherwise elect to use oil, because energy decisions are also based on factors other than cost, such as service, cleanliness and environmental impact. Demand for natural gas is expected to continue to increase as national attention remains focused on its environmental advantages, efficiency and security of supply. Commercial and industrial customers continue to find gas technologies and equipment attractive as they deal with the requirements of the Clean Air Act Amendments of 1990 and other federal environmental legislation.
Gas Supply
General. The Company's gas supply goal is to maintain a balanced portfolio of supply that will continue to minimize the overall cost of gas while providing the necessary security to meet demand requirements.
Supply Contracts and Storage. The Company's gas supply is principally natural gas transported by the interstate pipeline system. The Company has contracted with Tennessee to deliver 56,833 Dekatherms ("Dths," a unit of heating value equivalent to one million British Thermal Units) per day on a firm transportation basis with an additional 8,000 Dths per day on an interruptible basis. The Company also contracted with a New England supplier for city gate delivery of 8,000 Dths per day (151 day service). Natural gas supplies are purchased with both long-term and short-term firm contracts. During fiscal year 1998, the Company purchased approximately 1.8% of its annual natural gas requirements with short-term contracts. The Company did not purchase supply on the spot market in fiscal year 1998. The Company's long-term contracts, under which it has firm supply for approximately 40,529 Dths per day, have remaining terms of one to eight years.
In fiscal 1998, approximately 56% of the gas delivered by the Company came from domestic pipeline sources, 19% from Canadian pipeline supplies and approximately 11% from supplemental pipeline supplies. LP and liquefied natural gas (LNG) purchases from both domestic and foreign sources made up approximately 1% of the gas delivered by the Company. Supplemental supplies of gas are
produced from plants owned and operated by the Company. Third-party marketer supply to end users on the Company's system accounted for 13%.
All pipeline volumes are transported by Tennessee under FERC tariffed rate schedules. The supply from Canada is transported to Tennessee's system using the TransCanada and the Iroquois Gas transmission systems.
In addition to long-term supply sources, the Company stores gas during the summer months under long-term contracts with the owners of storage facilities located in Pennsylvania and New York. Gas from these storage facilities, up to 24,304 Dths per day on a firm basis, is delivered to the Company during the winter months through the Tennessee system. The Company owns other on-site storage facilities capable of holding 115,660 Dths of LP and 13,057 Dths of LNG.
The Company has contracted for 300,000 Dths of supplemental gas vapor, 100,000 Dths of LNG and an additional one million gallons of LP for the winter of 1998 - 1999.
The Company expects to be able to secure the gas supply required to meet existing customer and forecasted new customer demands through long-term commitments and purchases in the spot market.
Cost of Purchased and Produced Gas. The average unit cost of gas purchased and produced during the twelve months ended September 30, 1998 was approximately $4.09 per Mcf compared to $4.28 per Mcf for the same period last year. The 1998 average unit cost reflects the lower cost of gas supply in the marketplace. The cost of gas adjustment (CGA) clause authorized by the Commission permits recovery by the Company from its customers (or requires refunds to its customers) of gas costs (including pipeline, LP, LNG and storage) that are higher (or lower) than the cost of gas included in base rates. The Company may adjust the approved CGA rate upward or downward on a monthly basis. The monthly accumulative adjustments may not exceed 10% of the approved unit cost of gas sold. Amounts recovered through CGA rates are reconciled twice annually against actual costs, for summer and winter periods, and future CGA rates are adjusted accordingly.
The Company has a Natural Gas Price Risk Management Program designed to protect customers from sharp increases in the commodity cost of gas. Under the program, the Company has purchased call and sold put options for the 1998 - 1999 winter period. The call options provide the right, but not the obligation, to purchase gas at a predetermined price by a certain date. By selling a put option, the Company agrees to purchase gas at a predetermined price by a certain date. The purchase of call options and the sale of put options creates a collar mechanism. The collar establishes a maximum and minimum price at which the Company will buy gas contracts on the commodities market. All program costs and benefits will be passed on to customers through the CGA.
Margins earned on interruptible, 280-day sales and capacity release are passed on to firm customers through the CGA. In addition, costs associated with a fuel inventory trust, including administration fees and carrying costs, are recovered through the CGA.
Supervision and Regulation
The Company is subject to regulation by the Commission, which has authority over accounting, rates and charges, the issuance of securities and certain operating matters. Changes in utility rates and charges cannot be made without a 30-day notice to the Commission, which has the power to suspend, investigate and change any proposed increase in rates and charges.
The gas distribution business of the Company is subject to extensive safety regulations and reporting requirements promulgated by the United States Department of Transportation, but is not otherwise subject to direct regulation by federal agencies except as to environmental matters. The Company is also subject to zoning and other regulations by local authorities. Its capital expenditures, earnings and operations have not been materially affected by environmental and local regulation.
Employees
At September 30, 1998, the Company had 105 full-time employees, represented by two contracts with Local 12012 of the United Steelworkers of America. The contracts expire in 2001. Substantially all of the cost of ENI's 116 full-time employees is allocated to the Company. None of ENI's employees are represented by labor unions.
ITEM 2.
ITEM 2. PROPERTIES
The Company's gas distribution facilities constitute the majority of its physical assets. As of September 30, 1998, the Company had approximately 1,086 miles of mains and 690 miles of service connections. The mains and service connections are adequate to meet service requirements and are maintained through a regular program of inspection and repair. Offices and operations centers located in Nashua, Manchester, Concord and Tilton are adequate for the needs of the Company and are regularly maintained and in good condition. Substantially all of the Company's properties are fully utilized. Substantially all of the Company's utility properties are subject to the liens of the indentures securing the Company's First Mortgage Bonds. In some cases, motor vehicles and nonutility assets are subject to purchase money security interests held by banks.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In addition to the matters described below, the Company is a party in several proceedings of the sort that arise in the ordinary course of its business. Such actions, for the most part, are covered by insurance and, to the extent that they are not fully covered, the damages sought are not material in amount. The Company is a party to various routine Commission proceedings relating to operations, none of which is expected to have a material impact on the Company's earnings or assets.
The Company and certain of its predecessors owned or operated several facilities for the manufacture of gas from coal, a process used through the mid-1900s that produced by-products that may be considered contaminated or hazardous under current law, and some of which may still be present at such facilities. The Company accrues environmental investigation and cleanup costs with respect to
former manufacturing sites and other environmental matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
The New Hampshire Department of Environmental Services (NHDES) has required remedial action for a portion of the Concord site at which wastes were disposed from approximately 1852 through 1952. The estimated cost to complete this remedial action ranges from $1.9 million to $4.0 million, and the Company has recorded $1.9 million at September 30, 1998 in deferred charges. The Company has received an order from the Commission approving recovery from customers, over a seven-year period, of substantially all costs, excluding carrying costs, of past and future investigation, remediation and recovery efforts for the Concord site. Recovery of costs incurred through April 30, 1998 began on June 1, 1998. The total unamortized balance for the Concord site, including the gasholder site, of $5.5 million at September 30, 1998 is excluded from rate base. The Company may not earn a return or charge rates to customers based on amounts not included in rate base.
The Company has instituted several lawsuits to recover the costs of investigation and remediation of the Concord site. On December 8, 1995, the Company filed suit in the United States District Court for the District of New Hampshire against Associated Electric and Gas Insurance Services, Ltd., American Home Assurance Company, CIGNA Specialty Insurance Company, International Insurance Company, Lloyd's, Underwriters at London, Lexington Insurance Company and National Union Fire Insurance Company, later adding Columbia Casualty Company as a defendant, seeking declaratory judgment that they owe the Company a defense and/or indemnification for environmental claims associated with the Concord facility. The Company filed suit in the New Hampshire (Hillsborough County) Superior Court on December 8, 1995 against the Continental Insurance Company and Netherlands Insurance Company seeking a declaratory judgment that they owe the Company a defense and/or indemnification for environmental claims associated with the Concord facility.
At the direction of NHDES, the Company and Public Service Company of New Hampshire (PSNH), an electric utility company, conducted an environmental site characterization of a former manufactured gas plant in Laconia, New Hampshire. The Laconia manufactured gas plant operated between approximately 1887 and 1952, and the Company owned and operated the facility for approximately the last seven years of its active life. Without admitting liability, the Company and PSNH entered into an agreement under which the costs of the site characterization were shared. The Company's share of the costs of the site characterization and a report to the NHDES totaled $409,000 and has been recorded in deferred charges as of September 30, 1998. The report describes conditions at the site, including the presence of by-products of the manufactured gas process in site soils, groundwater and sediments in an adjacent water body. Based upon its review of the report, the NHDES has directed PSNH and the Company to prepare and submit a remedial action plan. The Company has recorded an additional $150,000 in deferred charges at September 30, 1998, for risk characterization studies at the Laconia site and a remedial action plan. The Company expects to incur further costs but is currently unable to predict the magnitude of any liability that may be imposed on it for the cost of additional studies or the performance of a remedial action in connection with the Laconia site. The Company commenced proceedings in New Hampshire Superior Court and Federal District Court on February 2, 1997 against eighteen of its present and former insurers seeking recovery of expenses that have been and will be
incurred in connection with the investigation and remediation of contamination from the Laconia plant.
Through November 1998, the Company reached settlements with defendants in gasholder related envionmental lawsuits in an aggregate amount of $3.5 million and further payment to the Company of a portion of future Concord site remediation costs. The Company expects that such settlement amounts will reduce the amount that it will be permitted by the Commission to recover from its ratepayers.
During 1998, the Company received a notice of potential responsibility from the Environmental Protection Agency related to a site in the area of its former gas manufacturing plant in Nashua, New Hampshire. The Company's share of costs for the disposal of contaminants at the site are estimated to range from $300,000 to $350,000 and the Company recorded $300,000 in deferred charges at September 30, 1998. The Company subsequently received a request from the NHDES to investigate the former gas manufacturing site in Nashua, New Hampshire. The Company expects to incur cost but is currently unable to predict the magnitude of any liability that may be imposed on it for cost of studies or the performance of remedial action in connection with the Nashua site.
The Company is pursuing and intends to pursue recovery from insurance carriers and claims against any other responsible parties seeking to ensure that they contribute appropriately to reimburse the Company for any costs incurred with respect to environmental matters. The Company intends to seek and expects to receive approval of rate recovery methods with respect to environmental matters after it has determined the extent of contamination, received recommendations with regard to remediation and commenced remediation efforts.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
OMITTED
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) No equity securities of the Company were sold by it during the period covered by this report. All 120,000 shares of the Company's outstanding common stock are held by EnergyNorth, Inc.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
OMITTED
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings
Warmer weather in the Company's service territory significantly impacted net income, which declined to $4.9 million in 1998 from $6 million in 1997. Temperatures were 12.9% warmer than normal and 11.4% warmer than the prior year. The effect of weather, when compared to normal, reduced 1998 utility margin by $1.7 million after taxes; whereas, warmer temperatures in 1997 decreased utility margin by $454,000 after taxes. In addition, 1997 earnings were $649,000 higher than 1998 as a result of a favorable net property tax settlement that was recorded in 1997. Partially offsetting the 1998 decrease in net income was continued customer growth and successful efforts to contain operating costs.
Sales and Revenues
The rates charged to customers are regulated by the Commission. The Commission is required by New Hampshire law to allow the Company to charge rates that are just and reasonable, such that the Company is compensated for the cost of providing service and allowed a reasonable rate of return on its investment. The Company regularly assesses whether it is earning a reasonable return and files for rate increases when it determines that it is not being permitted to earn a reasonable return.
The Company generates revenues primarily through the sale and transportation of natural gas. The Company's gas sales are divided into two categories: firm, whereby the Company must supply gas to customers on demand; and interruptible, whereby the Company may, generally during colder months, temporarily discontinue service to high-volume commercial and industrial customers. Sales of gas to interruptible customers do not materially affect the Company's operating income because all margin on such sales is returned to the Company's firm customers.
The Company's tariff includes CGA rates that provide for increases and decreases in the rates charged for gas to reflect estimated changes in the cost of gas. Although changes in CGA rates affect revenues, they do not affect total margin because the CGA is a tariff mechanism designed to provide dollar-for- dollar recovery of gas costs. Amounts recovered through CGA rates are reconciled at least semiannually against actual costs, and future CGA rates are adjusted accordingly.
The Company's sales are responsive to colder weather because the majority of firm customers use natural gas for space heating purposes. The Company measures weather through the use of degree days. A degree day is calculated by subtracting the average temperature for the day from 65 degrees Fahrenheit. The "normal" number of degree days during any period is calculated based upon a rolling approximate 30-year average number of degree days during such period. The table below discloses degree day data as recorded at the U.S. weather station in Concord, New Hampshire, comparing actual degree days to the previous period and to normal. Because of the
size and topographical variations of the Company's service territory, weather conditions within such territory often vary. The Company considers Concord, New Hampshire weather data to be representative of weather conditions within its service territory.
Operating revenues were $85.3 million in 1998 compared to $93 million in 1997, an 8.3% decrease. Firm sales gas revenues in 1998 were $78.8 million compared to $85.7 million in 1997. Firm transportation revenues of $2.4 million were twice the level achieved in 1997. The weather in 1998 was 12.9% warmer than normal and 11.4% warmer than the previous year. Growth in the average number of customers of 2.4% in 1998 helped mitigate the effects of the warmer temperatures. Firm sendout, including transportation, was 11.6 Bcf compared to 11.5 Bcf in 1997. Volumes transported increased more than 121%. This increase included a shift of 207,000 Mcf from firm commercial and industrial sales to transportation, representing a decrease of $900,000 in operating revenues attributable to the commodity cost of gas.
Shifts between transportation and sales gas will cause variations in natural gas revenues since the transportation rate does not include the commodity cost of gas, which is billed directly to customers by their marketers. The Company's rate structure provides for transportation service margin that is approximately 2.4% less than sales service margin. At September 30, 1998, the Company had 66 firm transportation customers compared to 45 customers the previous year.
The Company is currently involved in a proceeding at the Commission to examine further unbundling of the natural gas industry in New Hampshire. The Company cannot predict the outcome of this proceeding or potential impact on operating income.
Cost of Gas Sold
The cost of gas sold was $46.7 million in 1998 compared to $54.6 million in 1997. The decrease was primarily due to lower volumes of gas sold ($6.1 million) and a decline in the unit cost ($2.4 million). The average unit cost of gas sold in 1998 was $4.09 per Mcf compared to $4.28 per Mcf in 1997. Decreases or increases in purchased gas costs from suppliers have no significant impact on margin, as they are passed on to customers through the CGA.
Operating Expenses
Operations and maintenance expense for fiscal year 1998 was essentially unchanged from the prior year. The warmer winter season resulted in lower maintenance and bad debt expenses. Other operating and administrative costs decreased as a result of effective cost containment
efforts, which offset increases in labor costs and health insurance and other employee benefit costs.
Depreciation and amortization expense increased 8.3% in 1998 and reflects continued expansion, including the full impact of the Company's major main extension to serve Milford, New Hampshire, which was completed in late fiscal year 1997. Depreciation and amortization expense also includes normal upgrades to the distribution system and related facilities and amortization of environmental remediation costs. Net additions to property, plant and equipment were $13.2 million and $12 million in 1998 and 1997, respectively.
Taxes other than income taxes increased more than $1.1 million to $3.7 million in 1998. The 1997 results include a favorable property tax settlement, net of adjustments, of more than $1 million.
The lower level of pretax income is the main reason for the $666,000 decrease in federal and state income taxes in 1998.
Capital Resources and Liquidity
Because of the seasonal nature of the Company's operations, a substantial portion of cash receipts is generated during the November - March heating season, which results in the highest cash inflow during late winter and early spring. Cash requirements for capital expenditures, dividends, long-term debt retirement, environmental remediation and working capital do not track this pattern of cash receipts. The greatest demand for cash is in the fall and early winter to support the completion of the annual construction program and to fund gas inventories and other working capital requirements.
The Company's major uses of cash in 1998 were capital expenditures of $13.2 million, dividend payments of $3.8 million, environmental remediation of $661,000 and retirement of $515,000 of long-term debt. These expenditures were funded primarily through cash generated from current operations and short-term borrowings. Borrowings against lines of credit during 1998 ranged from zero to a high of $3.6 million. In addition, at September 30, 1998, deferred gas cost was in an overcollected position resulting from winter and summer activity. The overcollected amounts will be returned to customers through the CGA mechanism.
Capital expenditures for 1999 are currently projected at approximately $11.6 million. Additional cash requirements will be necessary for the payment of dividends, environmental remediation, annual sinking fund requirements and maturities of long-term debt and working capital. Cash to fund these requirements is expected to be provided principally by internally generated funds and short-term bank borrowings under the Company's lines of credit. At September 30, 1998, the Company had available lines of credit aggregating $15 million, $1.9 million of which was outstanding. In addition, a credit line of $10.5 million was available at September 30, 1998, under the Company's fuel inventory trust financing plan. At September 30, 1998, the Company's fuel
inventory in trust in the balance sheet was $8.7 million with an outstanding purchase obligation of $8.7 million.
On September 30, 1998, the Company's capitalization ratio consisted of 50% common equity and 50% debt, including short-term debt.
Environmental Matters
The Company continues to work with federal and state environmental agencies to assess the extent and environmental impact of contaminants that may exist at or near former gas manufacturing sites. The costs of such assessments and any related remediation determined to be necessary is expected to be funded from traditional sources of capital, recoveries from insurance carriers and responsible third parties and customers. For further information, see Note 9 to the financial statements.
Results of Operations 1997 Compared to 1996
Net income increased to $6 million in 1997 from 1996 net income of $5.4 million. The 1997 increase in earnings was due primarily to successful efforts to contain operating costs.
Operating revenues were $93 million in 1997, an increase of 20% from 1996. The increase resulted primarily from higher CGA rates. The average unit cost of gas sold in 1997 was $4.28 per Mcf compared to $3.96 per Mcf in 1996. Weather in the Company's service territory was 1.5% warmer than 1996, although the November - - March winter heating season was 7.3% warmer. The total volume of gas delivered to customers increased more than 2%. Partially offsetting the impact of the warmer temperatures was the 2.2% growth in the average number of customers.
Operations and maintenance expense was approximately the same as the prior year. Reductions in the work force, other cost saving initiatives and workers' compensation and health insurance refunds helped offset most of the increases from liability insurance, uncollectible accounts and other administrative expenses.
Taxes other than income taxes decreased almost $1.1 million to $2.6 million, due primarily to a favorable property tax settlement, net of adjustments, of more than $1 million, which offset property tax rate increases and additions to taxable property.
New Accounting Standards and Pronouncements
During fiscal year 1998, the Company implemented Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share," which establishes standards for computing and presenting earnings per share, and SFAS No. 129, "Disclosure of Information about Capital Structure," which establishes standards for disclosure requirements regarding capital structure. Both SFAS No. 128 and No. 129 have no material impact on the Company's financial reporting.
The Financial Accounting Standards Board issued new accounting standards which the Company will adopt in future periods. SFAS No. 130, "Reporting Comprehensive Income," establishes standards for reporting and the disclosure of comprehensive income and its components. This standard is effective in fiscal year 1999 and is not expected to have a material impact on the Company's financial reporting. SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," requires disclosure of operating segments, including disclosures about products and services, geographic areas and major customers. It is effective in fiscal year 1999 and is not expected to have a material impact on the Company's financial reporting. SFAS No. 132, "Employer's Disclosures About Pensions and Other Postretirement Benefits," revises employer's disclosures about pension and other postretirement benefit plans. It does not change the measurement of recognition of those plans. Effective in fiscal year 1999, the standard is not expected to have a significant impact on the Company's financial reporting. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," establishes standards for recording all derivative instruments as assets and liabilities measured at fair value. The standard is effective in the fourth quarter of fiscal year 1999 and is not expected to have a material impact on the Company's financial position.
The American Institute of Certified Public Accountants issued Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed and Obtained for Internal Use," and SOP 98-5, "Reporting on the Costs of Start- up Activities." Both are effective in fiscal year 2000 and adoption is not expected to have a material impact on the Company's financial position.
Year 2000 Readiness
The Company has evaluated its principal computer systems and noninformation technology systems including, but not limited to, telecommunication systems, automated meter reading systems, SCADA, regulator stations, plant remote control systems and security systems to determine readiness for the year 2000. These systems are currently capable of processing the year 2000, or are in the process of being upgraded or replaced by systems that are similarly capable. All necessary program modifications and system upgrades and testing are expected to be completed by the year 2000. Costs incurred to date and costs expected to be incurred to complete the year 2000 readiness are not significant and will not have a material impact on the Company's financial position or results of operations. The Company is currently assessing year 2000 issues with third parties with whom it has a material relationship. Except for the Company's major pipeline supplier, who has provided assurance of compliance, the Company has not determined the level of third-party risk. Preparation of a contingency plan to address failure of various systems is in process and is expected to be finalized prior to September 30, 1999.
Factors That May Affect Future Results
The Private Securities Litigation Reform Act of 1995 encourages the use of cautionary statements accompanying forward-looking statements. The preceding Management's Discussion and Analysis of Financial Condition and Results of Operations includes forward-looking statements concerning the impact of changes in the cost of gas and of the CGA mechanism on total margin;
projected capital expenditures and sources of cash to fund expenditures; impact of unbundling regulatory proceedings; year 2000 readiness and estimated costs of environmental remediation and anticipated regulatory approval of recovery mechanisms. The Company's future results, generally and with respect to such forward-looking statements, may be affected by many factors, among which are uncertainty as to the regulatory allowance of recovery of changes in the cost of gas; uncertain demands for capital expenditures and the availability of cash from various sources; uncertainty as to whether transportation rates will be reduced in future regulatory proceedings with resulting decreases in transportation margins; uncertainty as to environmental costs and as to regulatory approval of the full recovery of environmental costs, transition costs and other regulatory assets; weather; results of regulatory proceedings on unbundling; impact of new pipeline supplies and success of the Company's year 2000 readiness efforts and those of its vendors and customers.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company does not enter into material market risk sensitive transactions.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements required by Regulation S-X
Statements of Income EnergyNorth Natural Gas, Inc.
(In thousands) For the years ended September 30, 1998 1997 1996 - ----------------------------------------------------------------------------- Operating revenues: Utility gas service $84,274 $91,965 $76,620 Other 1,022 1,013 890 ------------------------------------ Total operating revenues 85,296 92,978 77,510 ------------------------------------
Operating expenses: Cost of gas sold 46,693 54,633 39,115 Operations and maintenance 18,445 18,397 18,624 Depreciation and amortization 5,381 4,969 4,693 Taxes other than income taxes 3,738 2,590 3,654 Federal and state income taxes 2,812 3,478 3,224 ------------------------------------ Total operating expenses 77,069 84,067 69,310 ------------------------------------
Operating income 8,227 8,911 8,200
Other income 1,111 792 735
Interest expense: Interest on long-term debt 3,628 2,657 2,747 Other interest 797 1,061 761 ------------------------------------ Total interest expense 4,425 3,718 3,508 ------------------------------------
Net income $ 4,913 $ 5,985 $ 5,427 ====================================
The accompanying notes are an integral part of these financial statements.
Statements of Capitalization EnergyNorth Natural Gas, Inc.
(In thousands, except share information) September 30, 1998 1997 - -------------------------------------------------------------------------------- Capitalization: Common stockholder's equity: Common stock - par value of $25 per share; 120,000 shares authorized, issued and outstanding $ 3,000 $ 3,000 Amount in excess of par 22,538 22,538 Retained earnings 19,265 18,155 --------------------- Total common stockholder's equity 44,803 43,693 ---------------------
Long-term debt: First Mortgage Bonds Due 2009 8.44% 3,667 4,000 Due 2019 9.70% 7,000 7,000 Due 2020 9.75% 10,000 10,000 Due 2027 7.40% 21,975 22,000
Notes payable Due through 2001 prime plus .50% 240 397 --------------------- 42,882 43,397 Less current portion 450 484 --------------------- Total long-term debt 42,432 42,913 ---------------------
Total capitalization $87,235 $86,606 =====================
The accompanying notes are an integral part of these financial statements.
Statements of Retained Earnings EnergyNorth Natural Gas, Inc.
(In thousands) For the years ended September 30, 1998 1997 1996 - ------------------------------------------------------------------------------ Balance at beginning of year $18,155 $15,819 $14,027 Add - net income 4,913 5,985 5,427 ----------------------------------- 23,068 21,804 19,454 Deduct - cash dividends on common stock 3,803 3,649 3,635 ----------------------------------- Balance at end of year $19,265 $18,155 $15,819 ===================================
The accompanying notes are an integral part of these financial statements.
ENERGYNORTH NATURAL GAS, INC. Notes to Financial Statements
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth Natural Gas, Inc. (Company) are set forth below.
Business Organization
The Company is a wholly owned subsidiary of EnergyNorth, Inc. Transactions between the Company and other affiliated companies include payments for management, accounting, data processing and other services. The Company is a regulated gas distribution utility located in southern and central New Hampshire and also provides service and sells appliances. The rates and accounting practices followed by the gas distribution subsidiary are regulated by the State of New Hampshire Public Utilities Commission (Commission). The Company's accounting policies conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the rate- making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for Certain Types of Regulation."
Revenue Recognition
Revenues derived from the sale and transportation of natural gas are based on rates authorized by the Commission. Customers' meters are read and bills are rendered on a cycle basis throughout the month. The Company records unbilled revenues related to gas delivered but not billed at the end of the ac counting period.
Cost of Gas Adjustment Clause
The Company's tariff includes a cost of gas adjustment (CGA) clause that permits billings to customers for changes in its cost of gas over a base period cost. The tariff provides for a CGA calculation for a summer period and a winter period. The Company may adjust the approved CGA rate upward or downward on a monthly basis. The monthly cumulative adjustments may not exceed 10% of the approved unit cost of gas sold. Any difference remaining between the cost of gas incurred and amounts billed to customers at the end of each summer or winter period is deferred for rate- making and accounting purposes to the next corresponding summer or winter period. Interest accrues on these amounts at the prime rate, adjusted quarterly.
Inventories
Inventories are valued on the basis of the lower of average cost or market.
Depreciation
The Company provides for depreciation on the straight-line basis. The rates applied are approved by the Commission. Such rates were equivalent to a composite rate of 3.4% for each of the years ended September 30, 1998, 1997 and 1996. Under depreciation practices required by the Commission, when gas utility assets under the composite method are retired from service, the cost of the retired assets is
removed from the property accounts and charged, together with any cost of removal, to the accumulated depreciation accounts. For all other assets, when assets are sold or retired, the cost of the assets and their related accumulated depreciation are removed from the respective accounts, net removal costs are recorded and any gain or loss is included in income.
Deferred Charges
Total deferred charges consist primarily of regulatory assets and the cost of issuing debt. The Company has established various regulatory assets in cases where the Commission has permitted, or is expected to permit, recovery of specific costs over a period of time. At September 30, 1998, regulatory assets included $6.1 million for environmental investigation and remediation costs and $2.4 million of unrecovered deferred state income taxes (see Note 6).
The unamortized cost of issuing debt at September 30, 1998 is $2 million. Deferred financing costs are amortized over the life of the related security. Other deferred charges are amortized over the recovery period specified by the Commission.
Investment Tax Credits
Investment tax credits are amortized over the estimated useful life of the property that gave rise to the credit.
Fair Value of Financial Instruments
Because of the short maturity of certain assets, which include cash, temporary cash investments and accounts receivable, and certain liabilities, which include accounts payable and notes payable to banks, these instruments are stated at amounts that approximate fair value.
If long-term debt outstanding at September 30, 1998 had been refinanced using new issue debt rates of interest that on average are lower than the outstanding rates, the present value of those obligations would have increased from the amounts outstanding in the September 30, 1998 accompanying balance sheet by 20.6%. In the event of refinancing, there would be no gain or loss as, under established regulatory procedure, any such difference would be reflected in rates and have no effect on income.
Derivative Instruments and Hedging Activities
The Company utilizes call and put options to manage market risk associated with a portion of anticipated gas supply requirements. The Company's policy prohibits utilization of derivatives for trading purposes.
Gains or losses on derivatives associated with forecasted transactions are recognized when such forecasted transactions affect earnings. If a derivative instrument is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If such derivative is terminated early for other economic reasons,
any gain or loss as of the termination date is deferred and recorded when the associated transaction or forecasted transaction affects earnings.
Although options traded on the NYMEX are included in the table below, they are not financial instruments since physical delivery of natural gas may be made pursuant to these contracts. They are a major part of the commodity risk management program.
The following table summarizes the types of hedges used and the related financial information as of September 30, 1998:
Notional Volumes Hedges of NYMEX Contracts - ---------------------------------------------------------------------- Calls - MMBtu Purchases 302 Puts - MMBtu Sales 302
$ Amount (In thousands) - ---------------------------------------------------------------------- Deferred gains, net $131
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect assets and liabilities, the disclosure of contingent assets and liabilities, and revenues and expenses. Actual amounts could differ from those estimates.
Reclassifications
Reclassifications are made periodically to previously issued financial statements to conform to the current year's presentation.
Note 2. Cash Flows
Supplemental disclosures of cash flow information were as follows (in thousands):
1998 1997 1996 - -------------------------------------------------------------------- Cash paid during the year for: Interest (net of amount capitalized) $3,957 $3,821 $3,369 Income taxes 2,761 3,557 508
In preparing the accompanying statements of cash flows, all highly liquid investments having maturities of three months or less when acquired were considered to be cash equivalents and classified as cash and temporary cash investments.
Note 3. Inventory Financing
The Company finances gas inventory purchases through the use of a single purpose trust, which purchases gas with funds loaned to it by a bank. As the Company requires gas to service customers, gas is repurchased from the trust at original product cost plus financing costs and trust fees. The cost of gas and related financing are recoverable through the CGA.
The bank credit agreement provides for a .375% commitment fee on the credit line and interest at prime (8.25% at September 30, 1998) with a fixed-rate interest option at less than prime on the outstanding balance. The trust agreement provides for a management fee of $8,000 annually. The credit agreement between the trust and the bank provides for a total commitment of up to $10.5 million through February 1999.
As of September 30, 1998 and 1997, the gas inventories under the trust agreement and controlled by the Company totaled $8.7 million and $7.8 million, respectively, and are included in inventories in the accompanying balance sheets. Inventory purchase obligations under this financing agreement are reflected as a current liability in the accompanying balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 1998, the Company had $15 million available under various unsecured bank lines of credit that are renewed annually, $1.9 million of which was outstanding. The weighted average interest rate on borrowings outstanding on September 30, 1998 was 8.2%. The lines bear interest at prime, or less than prime on certain of the lines for fixed periods of time, and are due on demand. For some lines, the terms of the credit agreements require annual commitment fees of .25% of the lines.
Note 5. Long-Term Debt
Interest payments for the First Mortgage Bonds are due semiannually. The First Mortgage Bonds are collateralized by first mortgage liens on substantially all real property and operating plant facilities.
The aggregate amounts of principal due for all long-term debt for each of the five years subsequent to September 30, 1998 are as follows (in thousands):
Fiscal year Amount - ----------------------------------------------------------------- 1999 $450 2000 429 2001 362 2002 333 2003 333
Note 6. Income Taxes
The Company files a consolidated federal income tax return with its parent company. For financial reporting and rate purposes, the Company provides taxes on a separate return basis.
At September 30, 1998 and 1997, a SFAS No. 109 related regulatory liability amounted to $892,000 and $960,000, respectively, for the tax benefit of unamortized investment tax credits, and $249,000 and $294,000, respectively, for the excess reserves for deferred taxes as a result of pre-July 1, 1987 deferred income taxes that were recorded in excess of the current federal statutory income tax rate.
A deferred state income tax liability and a corresponding regulatory asset of approximately $2.4 million, representing revenues the Company expects to recover from gas service customers, were established at September 30, 1994 as a result of recording deferred state income taxes on the cumulative temporary differences due to a change in New Hampshire tax law. Effective June 2, 1994, the 1% franchise tax assessed on sales of natural gas was repealed. Prior to the change in tax law, the franchise tax was permitted as a credit against the New Hampshire Business Profits Tax (NHBPT). Because franchise tax payments exceeded the NHBPT, the Company never incurred a NHBPT liability; therefore, no deferred state income taxes related to temporary differences were recorded.
The tax effects of cumulative differences that gave rise to the deferred tax liabilities and deferred tax assets for the years ended September 30, 1998 and 1997 were as follows (in thousands):
1998 1997 - --------------------------------------------------------------------- Deferred tax assets: Deferred gas costs $ 1,450 $ 240 Contributions in aid of construction 759 726 Unamortized investment tax credits 545 590 Allowance for doubtful accounts 419 506 Other 1,126 942 ---------------------- Total deferred tax assets 4,299 3,004 ----------------------
Deferred tax liabilities: Property-related 17,073 15,957 Environmental costs 1,455 1,936 Other 1,972 1,787 ---------------------- Total deferred tax liabilities 20,500 19,680 ---------------------- Net deferred tax liability $16,201 $16,676 ======================
Deferred income taxes were classified in the accompanying balance sheets at September 30, 1998 and 1997 as follows (in thousands):
1998 1997 - ---------------------------------------------------------------------------- Current $(1,729) $ (725) Long-term 17,930 17,401 ------------------------- Total $16,201 $16,676 =========================
The components of federal and state income taxes reflected in the accompanying statements of income for the years ended September 30, 1998, 1997 and 1996 were as follows (in thousands):
1998 1997 1996 - ------------------------------------------------------------------------- Federal: Current $2,702 $3,369 $ (323) Deferred (268) (378) 3,119 Investment tax credits (124) (136) (140) ---------------------------------- Total federal 2,310 2,855 2,656 ----------------------------------
State: Current 555 701 (129) Deferred (53) (78) 697 ---------------------------------- Total state 502 623 568 ---------------------------------- Total provision for income taxes $2,812 $3,478 $3,224 ==================================
The total federal and state income tax provision, as a percentage of income before federal and state income taxes, was 36.4%, 36.7% and 37.3% for the years ended September 30, 1998, 1997 and 1996, respectively. The following table reconciles the income tax provision calculated using the federal statutory tax rate of 34% to the book provision for federal and state income taxes (in thousands):
1998 1997 1996 - ------------------------------------------------------------------------------- Tax calculated at statutory rate $2,627 $3,217 $2,941 Increase (reduction) in effective tax resulting from: Amortization of investment tax credit (124) (136) (140) Adjustment due to change in tax rates (28) (28) (28) State taxes, net of federal tax benefit 331 411 375 Other, net 6 14 76 ------------------------ Total provision for income taxes $2,812 $3,478 $3,224 ========================
Note 7. Employee Benefit Plans
Pension Plans
The Company has noncontributory defined benefit plans covering substantially all employees. Benefits are based on years of credited service and average earnings during the five highest consecutive years of
earnings prior to the normal retirement date. The Company is also charged for pension expense for the management pension plan of the parent company.
The Company's funding policy is to annually contribute to the plans an amount that is not less than the minimum amount required by the Employee Retirement Income Security Act of 1974 and not more than the maximum amount deductible for income tax purposes.
Net periodic pension cost included the following components (in thousands):
1998 1997 1996 - --------------------------------------------------------------------------- Service cost for benefits earned $ 245 $ 229 $ 249 Interest cost on projected benefit obligations 537 509 472 Actual return on plan assets (201) (1,975) (542) Net amortization and deferral (531) 1,311 (90) Parent company allocation 402 427 344 ------------------------- Net periodic pension cost $ 452 $ 501 $ 433 =========================
The following table sets forth the funded status of the plans at September 30, 1998, 1997 and 1996 (in thousands): 1998 1997 1996 - --------------------------------------------------------------------------- Vested benefit obligation $7,248 $6,286 $5,983 ==========================
Accumulated benefit obligation $7,513 $6,553 $6,228 ==========================
Projected benefit obligation $8,425 $7,336 $6,971 Plan assets at fair value 9,166 9,135 7,300 -------------------------- Funded status 741 1,799 329 Unrecognized transition asset (265) (325) (384) Unrecognized prior service cost 239 295 351 Unrecognized net loss (gain) 372 (851) 447 -------------------------- Prepaid pension $1,087 $ 918 $ 743 ==========================
Assumptions used to determine the projected benefit obligation were as follows:
1998 1997 1996 - --------------------------------------------------------------------------- Discount rate 7.0% 7.5% 7.5% Rate of increase in future compensation levels 4.0 4.0 4.0 Expected long-term rate of return on assets 9.0 9.0 9.0
Plan assets are invested in common stocks and bonds.
The Company has an employee 401(k) savings and investment plan covering substantially all employees. The Company made contributions of $87,000, $85,000 and $61,000 for the years ended September 30, 1998, 1997 and 1996, respectively.
Other Postemployment Benefits
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to qualified retired employees.
The expense recorded in fiscal 1998, 1997 and 1996 for providing postretirement benefits, including amortization of the accumulated projected benefit obligation over a 20-year period, was $230,000, $216,000 and $222,000, respectively.
The Company has funded these benefit costs by making cash contributions, at the same level of expense recorded, to a voluntary employee benefit association (VEBA) trust.
The following table sets forth the funded status of the plan at September 30, 1998 and 1997 (in thousands):
1998 1997 - ------------------------------------------------------------------------------- Accumulated postretirement benefit obligation as of July 31: Retirees $ 1,106 $ 1,299 Fully eligible active plan participants 549 480 Other active participants 784 743 ----------------- 2,439 2,522 Plan assets at fair market value (1,248) (1,064) Unrecognized transition obligation (2,101) (2,241) Unrecognized net gain 966 836 ----------------- Accrued postretirement benefit cost at July 31 56 53 Contributions for the two-month period ended September 30 57 54 ----------------- Accrued postretirement benefit cost at September 30 $ (1) $ (1) =================
The components of net periodic postretirement benefit cost at September 30, 1998 and 1997 were as follows (in thousands):
1998 1997 - ------------------------------------------------------------------------------- Service cost - benefits attributed to services during the year $ 50 $ 48 Interest cost on accumulated postretirement benefit obligation 186 167 Actual asset return (76) (190) Net amortization and deferral 70 191 -------------- Net periodic postretirement benefit cost $230 $ 216 ==============
A 9% average annual rate of increase in the per capita costs of covered health care benefits was assumed for fiscal 1998, reduced in steps of 1% to a level of 5% at 2002 and thereafter. This decrease results from changes in estimates of future health care inflation, assumed changes in health care utilization and related effects. Increasing the assumed health care cost trend rates by one percentage point in each year would have resulted in a $98,000 increase in the accumulated postretirement benefit obligation as of July 31, 1998 and an increase in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost of $10,000 for fiscal 1998. A discount rate of 7% was used to determine the accumulated postretirement
benefit obligation. The expected long-term rate of return on plan assets is 9%. Plan assets are invested in common stocks and bonds.
Note 8. Operating Leases
The Company leases certain facilities and equipment under long- term, noncancelable operating lease agreements having terms greater than one year. Future minimum rental commitments for these leases, at September 30, 1998, are approximated as follows (in thousands):
Fiscal year Amount - ----------------------------------------------------------------- 1999 $93 2000 89 2001 51 2002 28 2003 9
The total rental expense charged to operations for the years ended September 30, 1998, 1997 and 1996 was approximately $807,000, $947,000 and $973,000, respectively.
Note 9. Commitments and Contingencies
Contracts
The Company has various contractual agreements covering the transportation of natural gas, underground storage facilities and the purchase of natural gas, which are recoverable under the Company's CGA. These contracts expire at various times from 1999 to 2011.
Litigation
The Company has been named in certain lawsuits arising from normal operations. In the opinion of management, the outcome of these lawsuits will not have a material adverse effect on the financial position or results of operations of the Company.
Environmental Issues
The Company and certain of its predecessors owned or operated several facilities for the manufacture of gas from coal, a process used through the mid-1900s that produced by-products that may be considered contaminated or hazardous under current law, and some of which may still be present at such facilities. Like other companies in the natural gas industry, the Company is a party to governmental actions associated with former gas manufacturing sites.
The Company is engaged in remedial action at a former gas manufacturing site in Concord, New Hampshire, and is participating with Public Service Company of New Hampshire in ongoing site assessment and evaluation of remedial options at a site located in Laconia, New Hampshire. The Company received a notice of potential responsibility from the Environmental Protection Agency
related to a site in the area of its former gas manufacturing plant in Nashua, New Hampshire, and also received a request from the New Hampshire Department of Environmental Services to investigate this former gas manufacturing site. Costs to complete remedial action at the Concord site and the Company's share of investigation and evaluation costs at the other sites are estimated to range from $2.3 million to $5 million. Along with costs incurred to date, the Company has recorded $2.3 million in accrued liability at September 30, 1998, with a corresponding charge to recoverable environmental costs. Actual environmental remediation costs to be incurred depend on a number of factors, and therefore future costs may differ from the amount currently recorded as a liability. Factors that may bear on cost include changes in remediation techniques or practices, changes in regulatory standards and the nature and extent of contamination at the sites. The Company accrues environmental investigation and cleanup costs with respect to former gas manufacturing sites and other environmental matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
The Company has received orders from the Commission that provide for recovery from customers, over a seven-year period, of substantially all costs, excluding carrying costs, of past and future investigation, remediation and recovery efforts for the Concord site. The unamortized balance of unrecovered costs ($5.5 million at September 30, 1998) is excluded from rate base. The Company may not earn a return or charge rates to customers based on amounts not included in rate base.
The Company has instituted several lawsuits to recover the costs of investigation and remediation of the Concord site and investigation of the Laconia site. Through November 1998, the Company reached settlements with certain of the defendants in those suits in an aggregate amount of $3.5 million. The settlements also include further payment to the Company of a portion of future Concord site remediation costs. The proceeds are being reflected as reductions in deferred charges, as shown in the accompanying balance sheets. The Company expects that such settlement amounts will reduce the amount that it will be permitted by the Commission to recover from its customers.
The Company is pursuing and intends to pursue recovery from insurance carriers and claims against any other responsible parties seeking to ensure that they contribute appropriately to reimburse the Company for any costs incurred with respect to environmental matters. The Company will continue to seek and expects to receive approval of rate recovery methods with respect to environmental matters after it has determined the extent of contamination, received recommendations with regard to remediation and commenced remediation efforts.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of EnergyNorth Natural Gas, Inc.:
We have audited the accompanying balance sheets and statements of capitalization of EnergyNorth Natural Gas, Inc. (a New Hampshire corporation and a wholly-owned subsidiary of EnergyNorth, Inc.) as of September 30, 1998 and 1997, and the related statements of income, retained earnings, common stockholder's equity and cash flows for each of the three years in the period ended September 30, 1998. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule 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 financial statements referred to above present fairly, in all material respects, the financial position of EnergyNorth Natural Gas, Inc. as of September 30, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 1998, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule under part IV, Item 14, is presented for purposes of additional analysis and is not a required part of the basic financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, is fairly stated, in all material respects, in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP Boston, Massachusetts November 4, 1998
(b) Supplementary Financial Information
Selected Quarterly Financial Data (Unaudited) EnergyNorth Natural Gas, Inc.
Operating Operating Net income (In thousands) revenues income (loss) (loss) Cash dividends - ---------------------------------------------------------------------------- First Quarter 1998 $27,135 $4,512 $3,826 $935 1997 25,360 4,190 3,408 890 - ---------------------------------------------------------------------------- Second Quarter 1998 37,479 6,113 5,264 935 1997 43,402 6,572 5,892 891 - ---------------------------------------------------------------------------- Third Quarter 1998 13,106 (816) (1,672) 1,000 1997 16,023 (804) (1,513) 934 - ---------------------------------------------------------------------------- Fourth Quarter 1998 7,576 (1,582) (2,505) 933 1997 8,193 (1,047) (1,802) 934 - ---------------------------------------------------------------------------- Note: In the opinion of the Company, the quarterly financial data include all adjustments, consisting of normal recurring adjustments and reclassifications, necessary for a fair presentation of such information. Quarterly amounts vary significantly due to seasonal weather conditions.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no such matters during the fiscal year ended September 30, 1998.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
OMITTED
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
OMITTED
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
OMITTED
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
OMITTED PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) List of documents filed as part of this Report
(1) Financial Statements
The following financial statements are included herein under Part II, Item 8: Page No(s). in this Report Statements of Income for the years ended September 30, 1998, 1997 and 1996 17 Balance Sheets at September 30, 1998 and 1997 18 Statements of Capitalization at September 30, 1998 and 1997 19 Statements of Retained Earnings for the years ended September 30, 1998, 1997 and 1996 20 Statements of Cash Flows for the years ended September 30, 1998, 1997 and 1996 21 Notes to Financial Statements 22-31 Report of Independent Public Accountants 32 Supplementary Financial Information 33
(2) Financial Statement Schedules
The following supplementary financial statement schedules required by Rule 5-04 of Regulation S-X, and report thereon, are filed as part of this Form 10-K on the page indicated below:
Schedule Page No. in Number Description this Report
II Valuation and Qualifying Accounts for the three years ended September 30, 1998 36
Report of Independent Public Accountants 32
Schedules other than the one listed above are either not required or not applicable, or the required information is shown in the financial statements or notes thereto.
(3) Exhibits Required by Item 601 of Regulation S-K
See Exhibit Index on pages 38 and 39.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended September 30, 1998.
(c) Exhibits - See Exhibit Index on pages 38 and 39.
(d) Financial Statement Schedules
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGYNORTH NATURAL GAS, INC.
Date: December 22, 1998 by: /s/ Robert R. Giordano Robert R. Giordano Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on December 22, 1998.
/s/ Robert R. Giordano Director and Chief Executive Officer Robert R. Giordano (principal executive officer)
/s/ Michelle L. Chicoine Director and President Michelle L. Chicoine
/s/ Kenneth M. Margossian Director and Executive Vice President Kenneth M. Margossian
/s/ Frank L. Childs Director and Senior Vice President, Frank L. Childs Treasurer and Chief Financial Officer (principal financial officer)
/s/ David A. Skrzysowski Vice President & Controller David A. Skrzysowski (principal accounting officer)
/s/ Edward T. Borer Director Edward T. Borer
/s/ N. George Mattaini Director N. George Mattaini
EXHIBIT INDEX
The exhibits listed below are filed herewith, or are incorporated herein by reference to other filings.
Exhibit Number Description
3.1 Articles of Incorporation of EnergyNorth Natural Gas, Inc. are incorporated by reference to Exhibit 3.1 to EnergyNorth Natural Gas, Inc.'s Registration Statement on Form S-1, No. 333-32949, dated August 6, 1997.
3.2 By-Laws of EnergyNorth Natural Gas, Inc., as amended, are incorporated by reference to Exhibit 3.2 to EnergyNorth Natural Gas, Inc.'s Amendment No. 2 to Registration Statement on Form S-1, No. 333-32949, dated September 17, 1997.
4.1 Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, as amended and supplemented by a First Supplemental Indenture, dated as of October 1, 1988, and by a Second Supplemental Indenture, dated as of August 31, 1989, is incorporated by reference to Exhibit 4.1 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1989.
4.2 Third Supplemental Indenture, dated as of September 1, 1990, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
4.3 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.3 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1992.
4.4 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the fiscal year ended September 30, 1996.
4.5 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s Amendment No. 1 to Registration Statement on Form S-1, No. 333-32949, dated September 10, 1997.
10.1 Gas transportation agreement (FT-A), dated as of September 1, 1993, between Tennessee Gas Pipeline Company and EnergyNorth Natural Gas, Inc. is incorporated by
reference to Exhibit 10.1 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1993.
10.2 Gas transportation agreement (Contract No. 632), dated as of September 1, 1993, between Tennessee Gas Pipeline Company and EnergyNorth Natural Gas, Inc. is incorporated by reference to Exhibit 10.2 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.3 Tax Sharing Agreement, dated as of October 1, 1988, is incorporated by reference to Exhibit 10.21 to EnergyNorth Natural Gas, Inc.'s Registration Statement on Form S-1, No. 333-32949, dated August 6, 1997.
10.4 Cost Allocation Agreement, dated as of October 1, 1996, is incorporated by reference to 10.22 to EnergyNorth Natural Gas, Inc.'s Amendment No. 2 to Registration Statement on Form S-1, No. 333-32949, dated September 17, 1997.
27 Financial Data Schedule of the Registrant.