ITEM 1. BUSINESS
General
The business of EnergyNorth, Inc., incorporated in the State of New Hampshire in 1982, is the ownership of 100% of the outstanding common stock of EnergyNorth Natural Gas, Inc. ("ENGI"), EnergyNorth Propane, Inc. ("ENPI"), and EnergyNorth Realty, Inc. EnergyNorth, Inc. ("ENI" or the "Registrant"), and its subsidiaries, collectively referred to as the "Company", are headquartered at 1260 Elm Street, Manchester, New Hampshire, except for ENPI, which is headquartered at 75 Regional Drive, Concord, New Hampshire. All subsidiaries are incorporated in the State of New Hampshire.
The business of ENGI, the Registrant's principal subsidiary, is the purchase, transportation and sale of natural gas for residential, commercial and industrial use in New Hampshire. ENPI is a retailer of liquefied petroleum gas ("propane" or "LP") and serves customers in central and southern New Hampshire. During 1996, ENPI entered into a joint venture with Northern New England Gas Corporation, creating a limited liability company to provide LP gas sales and service in the State of Vermont.
In general, the senior management of ENI serves as the senior management of all subsidiaries. The Company provides for the subsidiaries' administrative support and services and establishes policies, plans and goals.
The service territory of ENGI has a population of approximately 463,000 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 911 square miles. Located within 30 to 85 miles of Greater Boston, ENGI'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.
The State of New Hampshire's job growth continues to be robust, ranking first among New England states with a 1.9% growth rate. This compares to a 1.9% average growth rate nationally and a 1.4% average rate for New England. According to The New England Economic Project's October 1996 Economic Outlook for New Hampshire, new housing permits are expected to increase 3.2% in 1997 over 1996. While the New Hampshire unemployment rate for 1997 is forecasted at 4% compared to 3.8% in 1996, the labor force is forecasted to increase by 1.2% in 1997. In fiscal 1996, the Company experienced net growth of over 2.4% in natural gas customers and almost 9.4% in propane customers over 1995. ENGI'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. ENGI has a 30% - 35% share of the home heating market 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 57% of the home heating market. Currently, the comparative full service price of natural gas for heating is less than fuel oil. From a total energy perspective, natural gas is a strong competitor with a complete range 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, it also provides opportunities for expansion within the existing customer base. Due to continued customer conversions from other energy sources and expansion of its service territory, ENI has an opportunity for growth in the retail sales market. During the past five years, ENGI has experienced an annual average customer growth rate of about 2.0% compared to the 1.5% national average for local distribution companies. Additional growth in distribution operations may also occur 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 becomes more attractive. The development of new gas-burning technologies for industry and the wider acceptance of natural gas as a fuel for motor vehicles have provided opportunities for increased gas usage in market sectors that are not sensitive to the weather.
The Utility Gas Distribution Business
ENGI distributes natural gas as a regulated utility pursuant to franchise authority granted by the New Hampshire Public Utilities Commission (the "Commission"). No operations are outside New Hampshire. While the franchise area of ENGI is primarily residential in character, sales volumes are almost evenly split between residential and commercial/industrial customers. As of September 30, 1996, the Company's utility business served over 66,000 customers, of which approximately 88% were residential and 12% were commercial and industrial. During fiscal 1996, no ENGI customer purchased more than 4% of the total ENGI annual sales volume.
In fiscal 1994, ENGI unbundled its services by providing a new transportation-only service for both firm and interruptible, large commercial and industrial customers. Transportation service allows customers to purchase a natural gas supply directly from gas marketers who deliver that gas supply to an ENGI gate station and contract with ENGI for local transportation to their facilities. To ensure a continual, uninterrupted supply, ENGI also provides an optional, separate standby service as a backup to the gas supplies of transportation customers. During 1996, ENGI provided transportation service to 29 customers. Under the present regulatory environment, a switch to transportation service will reduce sales volumes and resulting utility gross revenues, but will not have an impact on gross margin. Current rates established for firm transportation by the Commission provide the same margin as firm sales service. ENGI is currently involved in a proceeding at the Commission to determine the costs of providing transportation service. A decision in this proceeding may result in a reduction in current transportation rates and a corresponding decrease in transportation margin. ENGI cannot predict the impact, if any, that the results of this proceeding may have on future operations. ENGI distributes gas to substantially all of 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. ENGI serves over 75% of New Hampshire's natural gas customers.
The Retail Propane Business
ENPI sells propane to residential, commercial and industrial customers in more than 100 communities primarily located within a 50-mile radius of Concord. Propane distribution does not require a regulatory franchise. Propane is delivered to customers by trucks from ENPI's liquid propane storage facilities located in communities within ENPI's service territory. ENPI purchases the majority of its liquid propane requirements on a firm contractual basis. The remaining liquid propane requirement is purchased in the spot market. During 1996, ENPI entered into a joint venture with Northern New England Gas Corporation to provide LP gas sales and service in Vermont. ENPI holds a 49% interest and will provide planning and management expertise to the joint venture.
Summary of Revenues
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 89% of ENGI's customers use natural gas for heating.
Deregulation
The implementation of Federal Energy Regulatory Commission ("FERC") Order 636 provided for the unbundling and deregulation of the interstate pipeline system and led to the beginning of unbundling of the intrastate pipeline system in New Hampshire. In late 1993, the Commission approved gas transportation rates and separate standby and balancing services for commercial and industrial customers. Gas transportation services have allowed customers to utilize ENGI'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, 1996, 29 customers had entered into transportation agreements with ENGI. These customers are, for the most part, large commercial and industrial customers. The volume transported for transportation customers in fiscal 1996 was 514,000 Mcf, approximately 4% of ENGI's total gas sales.
ENGI 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 ENGI's franchise area. For that reason, and because installation of private transmission mains would typically be impractical, customers have not attempted to bypass ENGI'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 ENGI's commercial and industrial customers who have the capability to use alternative fuels. ENGI provides flexible rates for users with dual-fuel capabilities in order to better compete with the alternative fuels.
Natural gas has a significant price advantage over electricity. Natural gas heating costs are typically less than one-half of electric heating costs. At the present time, the price of natural gas is less than the price of oil for heating. ENGI continues to add customers because energy decisions are also based on factors other than cost. Demand is expected to continue to increase as national attention remains focused on natural gas because of its environmental advantages, efficiency and security of supply. Additionally, 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.
The retail propane market is very competitive, and several other retail propane operations exist within the communities served by ENPI. The principal competitive factors in the industry are price, dependability of delivery and service.
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. ENGI's gas supply is principally natural gas transported by the interstate pipeline system. ENGI has contracted with Tennessee to deliver 56,833 Dths per day on a firm transportation basis and up to 8,000 Dths per day on an interruptible basis. Natural gas supplies are purchased both on a long-term contract and short-term spot market basis. During 1996, ENGI purchased approximately 6.2% of its annual natural gas requirements in the spot market. At times during the year, typically during the summer, ENGI will purchase lower cost spot market natural gas supply. ENGI's long-term contracts, under which it has firm supply for approximately 32,529 Dths per day, have remaining terms of three to ten years.
In fiscal 1996, approximately 68% of ENGI's gas requirements came from domestic pipeline sources, 21% from Canadian pipeline supplies and approximately 10% from supplemental pipeline supplies. LP and liquefied natural gas ("LNG") purchases from both domestic and foreign sources made up approximately 1% of ENGI's total supply requirements. Supplemental supplies of gas are produced from plants owned and operated by ENGI.
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, ENGI 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 ENGI during the winter months through the Tennessee system. ENGI owns other on-site storage facilities capable of holding 125,438 Dths of LP and 13,057 Dths of LNG.
ENGI has contracted for 1,760,000 Dths of supplemental gas vapor, 75,000 Dths of LNG and an additional 1,000,000 gallons of LP for the winter of 1996-1997.
The Company expects to be able to secure the gas supply required to meet new customer demands through long-term commitments and purchases in the spot market.
Controlled Attachment Policy. The controlled attachment policy is a tariff provision that restricts sales to large commercial and industrial firm customers. The controlled attachment policy for year-round natural gas customers provides for a reasonable balance between gas supply and the requirements of current and future customers in the ENGI franchise area. Sales to new customers and additional sales to existing customers are limited to 250 Mcf per day per customer. The daily Mcf limits do not apply for interruptible and 280-day customers who have available standby fuel and equipment and who agree to limit their consumption if requested by ENGI.
Cost of Purchased and Produced Gas. The average unit cost of gas purchased and produced during the twelve months ended September 30, 1996 was approximately $3.96 per Mcf compared to $3.44 per Mcf for the same period last year. The 1996 average unit cost reflects higher pipeline costs due to supplier rate case settlements and higher cost of gas supply in the marketplace. The Cost of Gas Adjustment ("CGA") clause authorized by the Commission permits recovery by ENGI, from 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 CGA is determined twice annually, for summer and winter periods.
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 gas inventory trust, including administration fees and carrying costs, are recovered through the CGA.
ENGI is subject to payment of transition costs associated with FERC Order 636 restructuring. Tennessee began billing these costs late in fiscal 1993 and ENGI has incurred $5.9 million in transition costs through September 30, 1996 and is recovering these costs through the CGA. Based on current information, additional transition costs are expected to range from $1.7 million to $5.1 million. Meanwhile, ENGI customers are benefiting from the restructuring, realizing long-term savings in gas costs.
Supervision and Regulation
ENI is generally exempt from regulation under the Public Utility Holding Company Act of 1935, because its utility operations are predominantly intrastate in character.
ENGI 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 30 days notice to the Commission, which has the power to suspend, investigate and change any proposed increase in rates and charges. Neither New Hampshire statutes nor regulations of the Commission, by their terms, subject ENGI to direct supervision or regulation by the Commission except with respect to the acquisition of other New Hampshire public utility holding companies or public utilities.
The gas distribution businesses of ENGI and ENPI are subject to extensive safety regulations and reporting requirements promulgated by the United States Department of Transportation, but are not otherwise subject to direct regulation by Federal agencies except as to environmental matters. These subsidiaries are also subject to zoning and other regulations by local authorities, and their capital expenditures, earnings and operations have not been materially affected by environmental and local regulation.
Employees
At September 30, 1996, the Company had 250 full-time employees of whom 136 were represented by four contracts with Local 12012 of the United Steelworkers of America. Two union contracts covering 27 employees expire in 1997 and two covering 109 employees expire in 2001. Executive Officers of the Registrant
ITEM 2.
ITEM 2. PROPERTIES
The Company's utility gas distribution facilities constitute the majority of its physical assets. As of September 30, 1996, ENGI had approximately 1,020 miles of mains and 640 miles of service connections. The utility's 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 ENGI General and Refunding Bonds. In some cases, motor vehicles and nonutility assets are subject to purchase money security interests held by banks. The Manchester office building and substantially all of ENPI's assets are subject to first mortgages. The Company also has long-term leases for motor vehicles, office equipment and computer equipment.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is a party in several routine proceedings. 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. ENGI is currently participating in a proceeding at the Commission to determine the costs of providing transportation service. ENGI cannot predict the impact, if any, a decision in this proceeding may have on future operations. ENGI is a party to various other Commission proceedings relating to operations, none of which is expected to have a material impact on the Company's earnings or assets.
In 1995, ENGI completed the disposal of the contents of the gasholder situated on a former gas manufacturing site in Concord, New Hampshire. Total remediation costs amounted to approximately $3.5 million. Recovery of these costs from customers began on July 1, 1995 and will extend over a seven-year period. The unamortized balance of $3.0 million at September 30, 1996 is excluded from rate base.
The New Hampshire Department of Environmental Services ("NHDES") has selected a remedial action for a portion of the Concord site at which wastes were disposed of between the late 1800's and the mid-1900's. The estimated cost of the remedial action ranges from $2.9 million to $4.8 million, and the Company has recorded $2.9 million at September 30, 1996 in deferred charges.
The Company and another utility company have been directed by the NHDES to conduct 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 the other utility have entered into an agreement under which the costs of the site characterization are shared. The Company's share of the costs of the site characterization and a report to the NHDES, which is underway, is expected to total $88,000 and has been recorded in deferred charges as of September 30, 1996. The Company 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 will 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. On September 12, 1995 the Company filed a Complaint in the United States District Court for the District of New Hampshire against UGI Utilities, Inc., as the successor to United Gas Improvement Company. The Company seeks contribution for expenses incurred at the Concord site based upon the operation of the manufactured gas plant by the United Gas Improvement Company, a predecessor of UGI Utilities, Inc., during a period of time the manufactured gas plant was in operation.
On December 8, 1995 ENGI 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, National Union Fire Insurance Company, later adding Columbia Casualty Company as a defendant, seeking a declaratory judgment that they owe ENGI a defense and/or indemnification for environmental claims associated with the Concord facility. ENGI 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 ENGI a defense and/or indemnification for environmental claims associated with the Concord facility.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders in the fourth quarter of fiscal 1996.
PART II ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
________________________ See notes 8 and 9 to the consolidated financial statements for information related to accounting changes.
Reclassifications are made periodically to previously issued financial data to conform to the current presentation.
* Results include a credit to earnings for previously disallowed gas costs, net of tax, of $959. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share for 1996 were $1.89 on record net income of $6.1 million, which represents a 45% increase from the $1.30 per share earned in 1995. Return on average common equity for 1996 was 13.9%, bettering the previous year's 9.9% return. The 1996 increase in earnings was primarily due to greater margins resulting mostly from growth in volumes delivered. Volumes of firm gas delivered to utility customers increased 13.1% to 11.4 million Mcf, and propane gallons sold increased almost 21% in 1996. Weather in the Company's service area was near normal in 1996 but 9.5% colder than the prior year. In 1995, earnings were reduced by approximately $.50 per share, after taxes, as a result of warmer temperatures. In addition, 1995 earnings included a $215,000 after-tax gain ($.07 per share) on the sale of railcars.
The Company's Board of Directors increased the quarterly dividend 8.9% during the fiscal year. The current quarterly dividend of 30.5 cents per share is equal to an annual dividend of $1.22 per share. Cash dividends paid to common shareholders in 1996 were $3,826,000, representing a payout ratio of 63% of 1996 earnings.
Utility Sales and Revenues
Utility gas service operating revenues were $77.5 million in 1996, compared to $69.8 million in 1995. The increase resulted primarily from increased volumes delivered to firm residential and commercial heating customers. The weather in 1996 was 9.5% colder than in 1995. In addition, customer growth in 1996 was approximately 1.7%. Revenues from gas transported for customers under firm transportation service rates increased more than 40% to $979,000, due to a 45% increase in volumes transported. This increase included a shift of 162,000 Mcf from firm commercial and industrial sales customers, representing a decrease of $516,000 in operating revenue attributable to the commodity cost of gas. The Company generates revenues through the sale and transportation of natural 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 the customer by its marketer. The Company's rate structure allows for similar margins on transported and sales gas. The Company is currently involved in a proceeding at the New Hampshire Public Utilities Commission (the "Commission") to determine the costs of providing transportation service. A decision in this proceeding may result in a reduction in current transportation rates and a corresponding decrease in transportation margin. The Company cannot predict the impact, if any, that the results of the proceeding may have on future operations. At September 30, 1996, the Company had 29 transportation customers compared to 21 customers the previous year. Interruptible revenue and interruptible transportation revenue increased $895,000 in 1996 to $4.6 million. Interruptible margins are used to lower charges to firm customers through the cost of gas adjustment ("CGA") and do not impact the Company's profitability. The Company's tariff includes CGA rates which 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 under CGA rates are reconciled biannually against actual costs, and future CGA rates are adjusted accordingly.
Utility Cost of Gas Sold
Cost of gas was $39.5 million in 1996 and $36.1 million in 1995. The increase was primarily due to higher prices from suppliers ($5.9 million) and the increase in delivered volumes ($4.7 million), partially offset by timing differences related to the recovery of gas costs through the CGA ($7.2 million). The average unit cost of gas sold in 1996 was $3.96 per Mcf, compared to $3.44 per Mcf in 1995. Increases or decreases in purchased gas costs from suppliers have no significant impact on margin, as they are passed on to customers through the CGA.
Retail Propane Operations
Retail propane operations contributed $646,000 to net earnings of the Company, an increase of $276,000 over 1995 results. 1996 operating revenues increased $2.4 million to $11.4 million, as propane gallons sold increased almost 21%. Substantial customer growth and the colder weather accounted for the increase in gallons sold. The average number of propane customers increased more than 10% in 1996. Despite an increase in the unit cost of gas of 10.5% and competitive pressure to maintain price, gross margin increased $982,000 or 21%. Operations and maintenance expense increased more than $425,000, primarily as a result of increases in labor, transportation and other delivery related expenses necessary to support an expanding customer base.
Operating Expenses
Operations and maintenance expense increased $614,000, or less than 3%, to $21.7 million in 1996. 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.
Depreciation and amortization expense increased from $5.1 million to $5.8 million in 1996, consistent with the Company's continued investment in the expansion and upgrading of its distribution system and facilities. Net additions to property, plant and equipment were $8.8 million and $7.9 million in 1996 and 1995, respectively.
Taxes other than income taxes increased $193,000 to $3.9 million primarily due to increases in property taxes, resulting from property tax rate increases and additions to taxable property. A higher level of pretax income was the main reason for the $1.7 million increase in total Federal and state income taxes in 1996. In addition, as a result of the resolution of certain tax issues, the Company reduced Federal income taxes by $200,000 in 1995.
Total other income for 1995 includes a gain of $350,000 from the sale of railcars formerly used to transport liquid propane.
Fiscal 1996 interest expense decreased 12.9% from 1995 due mainly to the repayment of $3.8 million of long-term debt and a decrease in average short-term borrowings and average short-term interest rates.
Capital Resources and Liquidity
Because of the seasonal nature of the Company's operations, a substantial portion of cash receipts are generated during the November-March heating season, which results in the highest cash inflow during late winter and early spring. However, cash requirements for capital expenditures, dividends, long-term debt retirement 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.
Cash provided by operations and financing activities was sufficient to fund investing activities in 1996. Higher earnings due to increased margins from greater sales volumes had a favorable impact on funds provided by operating activities. Additionally, during 1996, the Company raised almost $802,000 of common equity through the Dividend Reinvestment and Stock Purchase Plan. Borrowings against lines of credit during 1996 ranged from zero to a high of $9.5 million. In addition, the Company refinanced a $1.5 million mortgage note. The Company's major uses of cash were capital expenditures of $8.8 million, environmental remediation of $672,000 and retirement of $3.8 million of long-term debt. Deferred gas costs increased $9.4 million, due to the timing of the recovery of increased gas costs through the CGA. In addition, dividend payments to shareholders totaled $3.8 million in 1996.
Capital expenditures for 1997 are currently projected at approximately $10.3 million, and annual sinking fund requirements and maturities of long-term debt are scheduled to be $2.3 million in 1997. Additional cash requirements will be necessary for the payment of dividends, environmental remediation 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, 1996, the Company had available lines of credit aggregating $13.0 million with $9.5 million outstanding. In addition, a credit line of $9.5 million was available at September 30, 1996 under the Company's inventory trust financing plan. At September 30, 1996, the Company's inventory in trust on the consolidated balance sheet was $7.8 million with an outstanding purchase obligation of $7.9 million. On September 30, 1996, the Company's capitalization ratio consisted of 52% common equity and 48% debt, including short-term debt. Return on average common equity was 13.9%. In order to contribute to both stability and the ability to market new securities when appropriate, the Company attempts to maintain a balanced capital structure. The Company will seek future debt and equity financing based upon the amount and timing of internally generated funds, rate relief, regulatory actions and market conditions.
Environmental Matters
The Company and certain of its predecessors owned or operated facilities for the manufacture of gas from coal, a process used through the mid-1900's 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 clean-up 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 is reasonably certain.
A former manufactured gas facility in Concord, New Hampshire has been investigated and partially remediated. Disposal of the contents of the gasholder situated at this former gas manufacturing facility has been completed. Total remediation costs amounted to approximately $3.5 million and were recorded in deferred charges. Recovery of costs from customers began on July 1, 1995 and will extend over a seven-year period. The unamortized balance of $3.0 million at September 30, 1996 is excluded from rate base.
The New Hampshire Department of Environmental Services ("NHDES") has selected a remedial action for a portion of the Concord site at which wastes were disposed of between the late 1800's and mid-1900's. The estimated cost of the remedial action ranges from $2.9 million to $4.8 million, and the Company has recorded $2.9 million at September 30, 1996 in deferred charges.
The Company is pursuing recovery from its insurance carriers as well as from insurance carriers of its predecessors with respect to the Concord site. In addition, the Company is pursuing recovery against an entity that the Company alleges owned or operated the manufactured gas plant during the late 1800's and early 1900's.
The Company and another utility company have been directed by the NHDES to conduct 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 the other utility have entered into an agreement under which costs of the site characterization are shared. The Company's share of the costs of the site characterization and a report to the NHDES, which is underway, is expected to total $88,000 and has been recorded in deferred charges as of September 30, 1996. The Company 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 will 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.
Results of Operations 1995 Compared to 1994
Net income declined to $4.1 million in 1995 from record 1994 net income of $5.4 million. Earnings per share in 1995 were $1.30 compared to $1.74 in 1994. A key reason for the decrease in net income was the impact on operations of significantly warmer weather during the 1995 heating season. The effect of weather, when compared to normal, reduced 1995 net income by approximately $.50 per share, after taxes. In 1994, net income increased $.30 per share, after taxes, as a result of the record colder than normal temperatures.
Operating revenues were approximately $78.8 million in 1995, a decrease of 18.8% from 1994. The total volume of gas sendout declined 7.5% as temperatures in 1995 were 13.3% warmer than in 1994 and 9.2% warmer than normal. The average number of utility customers increased 2.1% to more than 65,000 in 1995. Utility gas service revenues, which represented 88.6% of total operating revenues, decreased by $18.4 million or 20.9%.
Propane operations recorded $9.0 million in total operating revenues in 1995, a slight increase over 1994. The increase was primarily due to a 12% increase in the average number of propane customers to 10,800 in 1995. Propane gallons sold decreased almost 2% in 1995 due to the effect of warmer weather.
The average unit cost of gas purchased and produced decreased to $3.44 per Mcf in 1995 from $4.03 per Mcf in 1994.
Operations and maintenance expense decreased 3.5% in 1995, primarily because of reductions in the work force combined with reductions in workers' compensation insurance and bad debt expense.
Capital expenditures for the Company's continuing expansion and system improvement programs were the reason for the 4.5% increase in depreciation and amortization in 1995.
A gain of $350,000 from the sale of railcars formerly used to transport liquid propane is included in total other income for 1995.
Total interest expense was $4.3 million in 1995, or 9.3% greater than 1994. The Company's total average short-term borrowings and the weighted average short-term interest rate were greater than in 1994. Total Federal and state income taxes decreased $644,000 in 1995. The lower level of pretax income and the resolution of certain tax issues are the principal reasons for the decrease. Partially offsetting the decrease was the impact of the repeal of the franchise tax. The Company's gas distribution subsidiary recorded state income taxes of $359,000 in 1995. No state income taxes were recorded in 1994 for this subsidiary.
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 transportation customers on the Company's profitability; the impact of changes in the cost of gas and of the CGA mechanism on total margin; projected capital expenditures and sources of cash to fund expenditures; and estimated costs of environmental remediation and anticipated regulatory approval of recovery mechanisms. The Company's future results, generally and with respect to such forward-looking statements, may be affected by many factors, among which are uncertainty as to the precise rates for transportation of gas that will be allowed by the regulators and as to the number and size of sales gas customers who become transportation-only customers; uncertainty as to the regulatory allowance of recovery of changes in the cost of gas; uncertain demands for capital expenditures and the availability of cash from various sources; and uncertainty as to the regulatory approval of the full recovery of environmental costs, transition costs, and other regulatory assets. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements required by Regulation S-X
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements
The accompanying notes are an integral part of these consolidated financial statements. ENERGYNORTH, INC. Notes to Consolidated Financial Statements
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth, Inc. and subsidiaries (the "Company") are set forth below.
Principles of Consolidation
The accompanying financial statements of the Company include the accounts of all subsidiaries. All significant intercompany accounts and transactions have been eliminated in the accompanying consolidated financial statements.
Business Organization
The Company's principal business activity is the management and operation of a regulated gas distribution subsidiary located in southern and central New Hampshire. The rates and accounting practices followed by the gas distribution subsidiary are regulated by the New Hampshire Public Utilities Commission (the "Commission"). The Company's accounting policies conform to generally accepted accounting principles applicable to rate- regulated enterprises and reflect the effects of the ratemaking process in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for Certain Types of Regulation."
The Company also operates a nonregulated propane distribution subsidiary and provides service and sells appliances through its utility subsidiary.
Revenue Recognition
Utility 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 accounting 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. Any difference between the cost of gas incurred and amounts billed to customers is deferred for ratemaking and accounting purposes to the next corresponding 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 depreciation on the straight-line basis. The rates applied by the regulated subsidiary are approved by the Commission. Such rates were equivalent to a composite rate of 3.4% for each of the years ended September 30, 1996, 1995 and 1994. The depreciation rates for nonregulated property, plant and equipment were 8.2%, 7.8% and 8.0% for the years ended September 30, 1996, 1995 and 1994, respectively. 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 are 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, 1996, regulatory assets include $6.8 million for environmental investigation and disposal costs and $2.4 million of unrecovered deferred state income taxes (see Note 7).
The unamortized cost of issuing debt at September 30, 1996 is $675,000. 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.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," issued in March 1995 and effective October 1, 1996, establishes accounting standards for the impairment of long-lived assets. SFAS No. 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. While circumstances may change, based on the current regulatory environment in the Company's service area, it is not expected that the adoption of SFAS No. 121 will have a material impact on the Company's financial position or results of operations.
Investment Tax Credits
Investment tax credits are being 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, 1996 was refinanced using new issue debt rates of interest that on average are lower than the outstanding rates, the present value of those obligations would increase from the amounts outstanding on the September 30, 1996 balance sheet by 10.8%.
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
In preparing the accompanying consolidated statements of cash flows, all highly liquid investments having maturities of three months or less when acquired were considered to be cash equivalents.
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 under 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, 1996) 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 $9.5 million through February 1997.
As of September 30, 1996 and 1995, the gas inventories under the trust agreement and controlled by the Company totaled $7.8 million and $7.1 million, respectively, and are included in inventories in the accompanying consolidated balance sheets. Inventory purchase obligations under this financing agreement are reflected as a current liability on the accompanying consolidated balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 1996, the Company had available $13.0 million under various unsecured bank lines of credit that are renewed annually, $9.5 million of which was outstanding. The weighted average interest rate on borrowings outstanding on September 30, 1996 was 6.6%. 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% to .35% of the lines.
Note 5. Long-Term Debt
Interest payments for the General and Refunding Bonds are due semi-annually. The General and Refunding Bonds are collateralized by first mortgage liens on substantially all real property and operating plant facilities of the Company's gas utility operations.
Note 6. Common Stock
On June 6, 1990, the Board of Directors declared a dividend distribution of one Right for each outstanding share of common stock of the Company. The Rights will not be exercisable until a person ("Acquiring Person") or group of affiliated or associated persons acquires 10% or more of the Company's outstanding common stock or announces an intention to make a tender offer that would result in ownership by such person or persons of 20% or more of the Company's outstanding common stock. Following such an event and unless earlier redeemed or expired, each Right entitles its holder to purchase from the Company one share of common stock for $48.00.
In the event the Company is acquired in a merger or other business combination, 50% or more of its consolidated assets or earning power is sold or transferred, any person acquires 15% or more of the Company's outstanding common stock, or an Acquiring Person engages in one or more self-dealing transactions with the Company, each Right will entitle its holder to purchase, at the Rights' exercise price, a number of shares of common stock of the Company or of the acquiring company having a value of twice such exercise price. Any Rights held by an Acquiring Person or its affiliate or associate become null and void upon the occurrence of any such events.
Prior to expiration of the Rights and except in certain instances following acquisitions of 10% or more of the Company's common stock, the Company may redeem all of the Rights for one cent per Right. The Rights do not carry voting or dividend rights and have no dilutive effect or effect on the earnings of the Company.
The distribution of the Rights was made on June 18, 1990 to shareholders of record on that date and attach to all common shares issued at and after that date. The Rights will expire on June 18, 2000 unless such date is extended or unless the Rights are earlier redeemed by the Company.
Note 7. Income Taxes
On October 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires adjustments of deferred tax assets and liabilities to reflect the future tax consequences, consistent with currently enacted tax laws and rates, of items already reflected in the financial statements. The implementation of SFAS No. 109 on October 1, 1993 had no material impact on the earnings or cash flows of the Company. A regulatory liability of approximately $440,000 was established 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. Also, a regulatory liability of approximately $1,183,000 was established for the tax benefit of unamortized investment tax credits, which SFAS No. 109 requires to be treated as a temporary difference. This benefit will be passed on to customers over the lives of the property giving rise to the investment tax credits. The Company does not believe that SFAS No. 109 will significantly impact future results of operations or cash flows based on current ratemaking policy.
At September 30, 1996 and 1995, the SFAS No. 109 regulatory liability amounted to $1.0 million and $1.1 million, respectively, for the tax benefit of unamortized investment tax credits, and $339,000 and $384,000, 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 utility 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's gas distribution subsidiary never incurred a NHBPT liability; therefore, no deferred state income taxes related to temporary differences were recorded.
Note 8. 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'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.
The Company also has a Supplemental Executive Retirement Plan ("SERP") for certain management employees. Benefits are based on the employee's service and earnings as defined in the SERP. The SERP is a non-qualified plan under the Internal Revenue Code and has no advance funding. Benefit payments are made directly by the Company to retired employees or their beneficiaries.
Plan assets are invested in common stocks and bonds.
The Company has employee 401(k) savings and investment plans covering substantially all employees. The Company made contributions of $216,000, $210,000 and $178,000 for the years ended September 30, 1996, 1995 and 1994, respectively.
Other Postemployment Benefits
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to qualified retired employees.
In accordance with SFAS No. 106, the Company began recording the cost of postretirement benefits on an accrual basis in 1994. The expense recorded in fiscal 1996, 1995 and 1994 for providing postretirement benefits, including amortization of the accumulated projected benefit obligation over a 20-year period, was $588,000, $646,000 and $878,000, respectively.
The Company has funded these benefit costs by making cash contributions, at the same level of expense recorded, to voluntary employee benefit association ("VEBA") trusts established separately for salaried and hourly paid employees.
An 11% average annual rate of increase in the per capita costs of covered health care benefits was assumed for fiscal year 1996, 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 $434,000 increase in the accumulated postretirement benefit obligation as of July 31, 1996 and an increase in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for fiscal year 1996 of $37,000. A discount rate of 7.5% 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 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 1996 to 2011.
Litigation
The Company and its subsidiaries have 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 facilities for the manufacture of gas from coal, a process used through the mid-1900's 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 clean-up 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 is reasonably certain.
A former manufactured gas facility in Concord, New Hampshire has been investigated and partially remediated. Disposal of the contents of the gasholder situated at this former gas manufacturing facility has been completed. Total remediation costs amounted to approximately $3.5 million and were recorded in deferred charges. Recovery of costs from customers began on July 1, 1995 and will extend over a seven-year period. The unamortized balance of $3.0 million at September 30, 1996 is excluded from rate base.
The New Hampshire Department of Environmental Services ("NHDES") has selected a remedial action for a portion of the Concord site at which wastes were disposed of between the late 1800's and mid-1900's. The estimated cost of the remedial action ranges from $2.9 million to $4.8 million, and the Company has recorded $2.9 million at September 30, 1996 in deferred charges.
The Company is pursuing recovery from its insurance carriers as well as from insurance carriers of its predecessors with respect to the Concord site. In addition, the Company is pursuing recovery against an entity that the Company alleges owned or operated the manufactured gas plant during the late 1800's and early 1900's.
The Company and another utility company have been directed by the NHDES to conduct 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 the other utility have entered into an agreement under which costs of the site characterization are shared. The Company's share of the costs of the site characterization and a report to the NHDES, which is underway, is expected to total $88,000 and has been recorded in deferred charges as of September 30, 1996. The Company 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 will 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.
Transition Costs
Federal Energy Regulatory Commission Order 636 allows interstate pipeline companies to recover transition costs created, for the most part, as they buy out of long-term, fixed-price gas contracts. The Company's pipeline supplier, Tennessee Gas Pipeline Company, began direct billing these costs to the Company on September 1, 1993 as a component of demand charges. Through September 30, 1996, the Company has been billed $5.9 million for transition costs and has charged these costs to deferred gas costs. The Company is recovering transition costs through the CGA. Based on current information, additional transition costs are expected to range from $1.7 million to $5.1 million and will continue to be billed over a period of approximately one to three years. At September 30, 1996, the Company has recorded an estimated liability of $1.7 million for transition costs and a corresponding regulatory asset. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and the Shareholders of EnergyNorth, Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of EnergyNorth, Inc. (a New Hampshire corporation) and subsidiaries as of September 30, 1996 and 1995, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended September 30, 1996. These consolidated 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, Inc. and subsidiaries as of September 30, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1996, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic consolidated 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 consolidated financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic consolidated financial statements and, in our opinion, is fairly stated, in all material respects, in relation to the basic consolidated financial statements taken as a whole.
/s/ Arthur Andersen LLP
Boston, Massachusetts November 1, 1996
Note: Earnings (loss) per share are based on the weighted average shares outstanding at the end of the quarter. 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no such matters during the fiscal year ended September 30, 1996.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item is incorporated by reference to pages 3 and 4 of the Registrants' Proxy Statement for its Annual Meeting to be held February 5, 1997, except for information relating to identification of Executive Officers of the Registrant which is contained in Part I of the Report.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item is incorporated by reference to "Compensation of Directors," "Executive Compensation" and "Non-Contributory Retirement Plan" on pages 5 through 7 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item is incorporated by reference to pages 2 and 3 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item is incorporated by reference to "Compensation Committee Interlocks and Insider Participation" on page 5 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997.
PART IV
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 Consolidated Statements of Income for the years ended September 30, 1996, 1995 and 1994 21 Consolidated Balance Sheets at September 30, 1996 and 1995 22 Consolidated Statements of Capitalization at September 30, 1996 and 1995 23 Consolidated Statements of Common Stockholders' Equity for the years ended September 30, 1996, 1995 and 1994 24 Consolidated Statements of Cash Flows for the years ended September 30, 1996, 1995 and 1994 25 Notes to Consolidated Financial Statements 26-36 Report of Independent Public Accountants 37
(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 Consolidated Valuation and Qualifying Accounts for the three years ended September 30, 1996 41 Report of Independent Public Accountants 37
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 43 through 45.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended September 30, 1996.
(c) Exhibits - See Exhibit Index on pages 43 through 45.
(d) Financial Statement Schedules SCHEDULE II
ENERGYNORTH, INC. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (In thousands)
________________________________________ (1) Represents recoveries on accounts previously written off 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, INC.
Date: December 20, 1996 by: /s/ Robert R. Giordano Robert R. Giordano President & 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 20, 1996.
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, Inc. are incorporated by reference to Exhibit 4.1 of EnergyNorth, Inc.'s Registration Statement on Form S-3, No. 33-41579, dated July 2, 1991.
3.2 By-Laws of EnergyNorth, Inc., dated as of February 1, 1995, are incorporated by reference to Exhibit 4 to EnergyNorth, Inc.'s Post-Effective Amendment No. 2 to Registration Statement on Form S-3, No. 33-58127, dated November 21, 1996.
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 of 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 of 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.
4.5 Copies of Bond Indentures and a note and credit agreement defining the rights of holders of long-term debt of certain subsidiaries of EnergyNorth, Inc., under which the amounts of bonds or the note issued do not exceed 10% of the consolidated assets of EnergyNorth, Inc. will be furnished to the Securities and Exchange Commission upon request.
4.6 Rights Agreement, dated as of June 18, 1990, between the Registrant and State Street Bank & Trust Company as Rights Agent is incorporated by reference to Exhibit I-2 to EnergyNorth, Inc.'s Registration Statement on Form 8-A, dated June 18, 1990.
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 Supplemental Executive Retirement Plan of EnergyNorth, Inc., as amended.
10.4 Deferred Compensation Agreement, dated as of November 30, 1993, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.3 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1993.
10.5 Deferred Compensation Agreement, dated as of November 30, 1993, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.5 to EnergyNorth Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1993.
10.6 Amendment to Deferred Compensation Agreement, dated as of October 1, 1996, between Robert R. Giordano and the Registrant.
10.7 Amendment to Deferred Compensation Agreement, dated as of October 1, 1996, between Albert J. Hanlon and the Registrant.
10.8 Deferred Compensation Agreement, dated as of November 30, 1993, between Richard P. Demers and the Registrant, as amended.
10.9 Deferred Compensation Agreement, dated as of November 30, 1995, between Frank L. Childs and the Registrant, as amended.
10.10 Deferred Compensation Agreement, dated as of November 30, 1993, between Michelle L. Chicoine and the Registrant, as amended.
10.11 EnergyNorth, Inc. 1992 Directors' Deferred Compensation Plan, as amended.
10.12 Consulting Agreement, dated as of October 12, 1990, between N. George Mattaini and the Registrant is incorporated by reference to Exhibit 10.17 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
10.13 Amendment No. 1 to Consulting Agreement dated as of February 7, 1996 between N. George Mattaini and the Registrant. 10.14 Employment Agreement, dated as of December 1, 1995, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.9 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.15 Employment Agreement, dated as of December 1, 1995, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.11 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.16 Management Continuity Agreement, dated as of December 7, 1995, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.12 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.17 Management Continuity Agreement, dated as of December 7, 1995, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.14 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.18 Management Continuity Agreement, dated as of December 2, 1996, between Michelle L. Chicoine and the Registrant.
10.19 Management Continuity Agreement, dated as of December 2, 1996, between Frank L. Childs and the Registrant.
10.20 Management Continuity Agreement, dated as of December 7, 1995, between Richard P. Demers and the Registrant.
10.21 EnergyNorth, Inc. Key Employee Performance and Equity Incentive Plan, as amended, is incorporated by reference to Exhibit 10.15 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
21 Subsidiaries of the Registrant is incorporated by reference to Exhibit 22 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule of the Registrant.
99 EnergyNorth, Inc.'s Dividend Reinvestment and Stock Purchase Plan, as amended is incorporated by reference to Exhibit 99 of EnergyNorth Inc.'s Post- Effective Amendment No. 2 to Registration Statement on Form S-3, No. 33-58127, dated November 21, 1996.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share for 1996 were $1.89 on record net income of $6.1 million, which represents a 45% increase from the $1.30 per share earned in 1995. Return on average common equity for 1996 was 13.9%, bettering the previous year's 9.9% return. The 1996 increase in earnings was primarily due to greater margins resulting mostly from growth in volumes delivered. Volumes of firm gas delivered to utility customers increased 13.1% to 11.4 million Mcf, and propane gallons sold increased almost 21% in 1996. Weather in the Company's service area was near normal in 1996 but 9.5% colder than the prior year. In 1995, earnings were reduced by approximately $.50 per share, after taxes, as a result of warmer temperatures. In addition, 1995 earnings included a $215,000 after-tax gain ($.07 per share) on the sale of railcars.
The Company's Board of Directors increased the quarterly dividend 8.9% during the fiscal year. The current quarterly dividend of 30.5 cents per share is equal to an annual dividend of $1.22 per share. Cash dividends paid to common shareholders in 1996 were $3,826,000, representing a payout ratio of 63% of 1996 earnings.
Utility Sales and Revenues
Utility gas service operating revenues were $77.5 million in 1996, compared to $69.8 million in 1995. The increase resulted primarily from increased volumes delivered to firm residential and commercial heating customers. The weather in 1996 was 9.5% colder than in 1995. In addition, customer growth in 1996 was approximately 1.7%. Revenues from gas transported for customers under firm transportation service rates increased more than 40% to $979,000, due to a 45% increase in volumes transported. This increase included a shift of 162,000 Mcf from firm commercial and industrial sales customers, representing a decrease of $516,000 in operating revenue attributable to the commodity cost of gas. The Company generates revenues through the sale and transportation of natural 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 the customer by its marketer. The Company's rate structure allows for similar margins on transported and sales gas. The Company is currently involved in a proceeding at the New Hampshire Public Utilities Commission (the "Commission") to determine the costs of providing transportation service. A decision in this proceeding may result in a reduction in current transportation rates and a corresponding decrease in transportation margin. The Company cannot predict the impact, if any, that the results of the proceeding may have on future operations. At September 30, 1996, the Company had 29 transportation customers compared to 21 customers the previous year. Interruptible revenue and interruptible transportation revenue increased $895,000 in 1996 to $4.6 million. Interruptible margins are used to lower charges to firm customers through the cost of gas adjustment ("CGA") and do not impact the Company's profitability. The Company's tariff includes CGA rates which 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 under CGA rates are reconciled biannually against actual costs, and future CGA rates are adjusted accordingly.
Utility Cost of Gas Sold
Cost of gas was $39.5 million in 1996 and $36.1 million in 1995. The increase was primarily due to higher prices from suppliers ($5.9 million) and the increase in delivered volumes ($4.7 million), partially offset by timing differences related to the recovery of gas costs through the CGA ($7.2 million). The average unit cost of gas sold in 1996 was $3.96 per Mcf, compared to $3.44 per Mcf in 1995. Increases or decreases in purchased gas costs from suppliers have no significant impact on margin, as they are passed on to customers through the CGA.
Retail Propane Operations
Retail propane operations contributed $646,000 to net earnings of the Company, an increase of $276,000 over 1995 results. 1996 operating revenues increased $2.4 million to $11.4 million, as propane gallons sold increased almost 21%. Substantial customer growth and the colder weather accounted for the increase in gallons sold. The average number of propane customers increased more than 10% in 1996. Despite an increase in the unit cost of gas of 10.5% and competitive pressure to maintain price, gross margin increased $982,000 or 21%. Operations and maintenance expense increased more than $425,000, primarily as a result of increases in labor, transportation and other delivery related expenses necessary to support an expanding customer base.
Operating Expenses
Operations and maintenance expense increased $614,000, or less than 3%, to $21.7 million in 1996. 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.
Depreciation and amortization expense increased from $5.1 million to $5.8 million in 1996, consistent with the Company's continued investment in the expansion and upgrading of its distribution system and facilities. Net additions to property, plant and equipment were $8.8 million and $7.9 million in 1996 and 1995, respectively.
Taxes other than income taxes increased $193,000 to $3.9 million primarily due to increases in property taxes, resulting from property tax rate increases and additions to taxable property. A higher level of pretax income was the main reason for the $1.7 million increase in total Federal and state income taxes in 1996. In addition, as a result of the resolution of certain tax issues, the Company reduced Federal income taxes by $200,000 in 1995.
Total other income for 1995 includes a gain of $350,000 from the sale of railcars formerly used to transport liquid propane.
Fiscal 1996 interest expense decreased 12.9% from 1995 due mainly to the repayment of $3.8 million of long-term debt and a decrease in average short-term borrowings and average short-term interest rates.
Capital Resources and Liquidity
Because of the seasonal nature of the Company's operations, a substantial portion of cash receipts are generated during the November-March heating season, which results in the highest cash inflow during late winter and early spring. However, cash requirements for capital expenditures, dividends, long-term debt retirement 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.
Cash provided by operations and financing activities was sufficient to fund investing activities in 1996. Higher earnings due to increased margins from greater sales volumes had a favorable impact on funds provided by operating activities. Additionally, during 1996, the Company raised almost $802,000 of common equity through the Dividend Reinvestment and Stock Purchase Plan. Borrowings against lines of credit during 1996 ranged from zero to a high of $9.5 million. In addition, the Company refinanced a $1.5 million mortgage note. The Company's major uses of cash were capital expenditures of $8.8 million, environmental remediation of $672,000 and retirement of $3.8 million of long-term debt. Deferred gas costs increased $9.4 million, due to the timing of the recovery of increased gas costs through the CGA. In addition, dividend payments to shareholders totaled $3.8 million in 1996.
Capital expenditures for 1997 are currently projected at approximately $10.3 million, and annual sinking fund requirements and maturities of long-term debt are scheduled to be $2.3 million in 1997. Additional cash requirements will be necessary for the payment of dividends, environmental remediation 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, 1996, the Company had available lines of credit aggregating $13.0 million with $9.5 million outstanding. In addition, a credit line of $9.5 million was available at September 30, 1996 under the Company's inventory trust financing plan. At September 30, 1996, the Company's inventory in trust on the consolidated balance sheet was $7.8 million with an outstanding purchase obligation of $7.9 million. On September 30, 1996, the Company's capitalization ratio consisted of 52% common equity and 48% debt, including short-term debt. Return on average common equity was 13.9%. In order to contribute to both stability and the ability to market new securities when appropriate, the Company attempts to maintain a balanced capital structure. The Company will seek future debt and equity financing based upon the amount and timing of internally generated funds, rate relief, regulatory actions and market conditions.
Environmental Matters
The Company and certain of its predecessors owned or operated facilities for the manufacture of gas from coal, a process used through the mid-1900's 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 clean-up 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 is reasonably certain.
A former manufactured gas facility in Concord, New Hampshire has been investigated and partially remediated. Disposal of the contents of the gasholder situated at this former gas manufacturing facility has been completed. Total remediation costs amounted to approximately $3.5 million and were recorded in deferred charges. Recovery of costs from customers began on July 1, 1995 and will extend over a seven-year period. The unamortized balance of $3.0 million at September 30, 1996 is excluded from rate base.
The New Hampshire Department of Environmental Services ("NHDES") has selected a remedial action for a portion of the Concord site at which wastes were disposed of between the late 1800's and mid-1900's. The estimated cost of the remedial action ranges from $2.9 million to $4.8 million, and the Company has recorded $2.9 million at September 30, 1996 in deferred charges.
The Company is pursuing recovery from its insurance carriers as well as from insurance carriers of its predecessors with respect to the Concord site. In addition, the Company is pursuing recovery against an entity that the Company alleges owned or operated the manufactured gas plant during the late 1800's and early 1900's.
The Company and another utility company have been directed by the NHDES to conduct 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 the other utility have entered into an agreement under which costs of the site characterization are shared. The Company's share of the costs of the site characterization and a report to the NHDES, which is underway, is expected to total $88,000 and has been recorded in deferred charges as of September 30, 1996. The Company 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 will 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.
Results of Operations 1995 Compared to 1994
Net income declined to $4.1 million in 1995 from record 1994 net income of $5.4 million. Earnings per share in 1995 were $1.30 compared to $1.74 in 1994. A key reason for the decrease in net income was the impact on operations of significantly warmer weather during the 1995 heating season. The effect of weather, when compared to normal, reduced 1995 net income by approximately $.50 per share, after taxes. In 1994, net income increased $.30 per share, after taxes, as a result of the record colder than normal temperatures.
Operating revenues were approximately $78.8 million in 1995, a decrease of 18.8% from 1994. The total volume of gas sendout declined 7.5% as temperatures in 1995 were 13.3% warmer than in 1994 and 9.2% warmer than normal. The average number of utility customers increased 2.1% to more than 65,000 in 1995. Utility gas service revenues, which represented 88.6% of total operating revenues, decreased by $18.4 million or 20.9%.
Propane operations recorded $9.0 million in total operating revenues in 1995, a slight increase over 1994. The increase was primarily due to a 12% increase in the average number of propane customers to 10,800 in 1995. Propane gallons sold decreased almost 2% in 1995 due to the effect of warmer weather.
The average unit cost of gas purchased and produced decreased to $3.44 per Mcf in 1995 from $4.03 per Mcf in 1994.
Operations and maintenance expense decreased 3.5% in 1995, primarily because of reductions in the work force combined with reductions in workers' compensation insurance and bad debt expense.
Capital expenditures for the Company's continuing expansion and system improvement programs were the reason for the 4.5% increase in depreciation and amortization in 1995.
A gain of $350,000 from the sale of railcars formerly used to transport liquid propane is included in total other income for 1995.
Total interest expense was $4.3 million in 1995, or 9.3% greater than 1994. The Company's total average short-term borrowings and the weighted average short-term interest rate were greater than in 1994. Total Federal and state income taxes decreased $644,000 in 1995. The lower level of pretax income and the resolution of certain tax issues are the principal reasons for the decrease. Partially offsetting the decrease was the impact of the repeal of the franchise tax. The Company's gas distribution subsidiary recorded state income taxes of $359,000 in 1995. No state income taxes were recorded in 1994 for this subsidiary.
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 transportation customers on the Company's profitability; the impact of changes in the cost of gas and of the CGA mechanism on total margin; projected capital expenditures and sources of cash to fund expenditures; and estimated costs of environmental remediation and anticipated regulatory approval of recovery mechanisms. The Company's future results, generally and with respect to such forward-looking statements, may be affected by many factors, among which are uncertainty as to the precise rates for transportation of gas that will be allowed by the regulators and as to the number and size of sales gas customers who become transportation-only customers; uncertainty as to the regulatory allowance of recovery of changes in the cost of gas; uncertain demands for capital expenditures and the availability of cash from various sources; and uncertainty as to the regulatory approval of the full recovery of environmental costs, transition costs, and other regulatory assets. ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements required by Regulation S-X
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements
The accompanying notes are an integral part of these consolidated financial statements. ENERGYNORTH, INC. Notes to Consolidated Financial Statements
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth, Inc. and subsidiaries (the "Company") are set forth below.
Principles of Consolidation
The accompanying financial statements of the Company include the accounts of all subsidiaries. All significant intercompany accounts and transactions have been eliminated in the accompanying consolidated financial statements.
Business Organization
The Company's principal business activity is the management and operation of a regulated gas distribution subsidiary located in southern and central New Hampshire. The rates and accounting practices followed by the gas distribution subsidiary are regulated by the New Hampshire Public Utilities Commission (the "Commission"). The Company's accounting policies conform to generally accepted accounting principles applicable to rate- regulated enterprises and reflect the effects of the ratemaking process in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for Certain Types of Regulation."
The Company also operates a nonregulated propane distribution subsidiary and provides service and sells appliances through its utility subsidiary.
Revenue Recognition
Utility 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 accounting 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. Any difference between the cost of gas incurred and amounts billed to customers is deferred for ratemaking and accounting purposes to the next corresponding 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 depreciation on the straight-line basis. The rates applied by the regulated subsidiary are approved by the Commission. Such rates were equivalent to a composite rate of 3.4% for each of the years ended September 30, 1996, 1995 and 1994. The depreciation rates for nonregulated property, plant and equipment were 8.2%, 7.8% and 8.0% for the years ended September 30, 1996, 1995 and 1994, respectively. 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 are 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, 1996, regulatory assets include $6.8 million for environmental investigation and disposal costs and $2.4 million of unrecovered deferred state income taxes (see Note 7).
The unamortized cost of issuing debt at September 30, 1996 is $675,000. 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.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," issued in March 1995 and effective October 1, 1996, establishes accounting standards for the impairment of long-lived assets. SFAS No. 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. While circumstances may change, based on the current regulatory environment in the Company's service area, it is not expected that the adoption of SFAS No. 121 will have a material impact on the Company's financial position or results of operations.
Investment Tax Credits
Investment tax credits are being 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, 1996 was refinanced using new issue debt rates of interest that on average are lower than the outstanding rates, the present value of those obligations would increase from the amounts outstanding on the September 30, 1996 balance sheet by 10.8%.
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
In preparing the accompanying consolidated statements of cash flows, all highly liquid investments having maturities of three months or less when acquired were considered to be cash equivalents.
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 under 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, 1996) 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 $9.5 million through February 1997.
As of September 30, 1996 and 1995, the gas inventories under the trust agreement and controlled by the Company totaled $7.8 million and $7.1 million, respectively, and are included in inventories in the accompanying consolidated balance sheets. Inventory purchase obligations under this financing agreement are reflected as a current liability on the accompanying consolidated balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 1996, the Company had available $13.0 million under various unsecured bank lines of credit that are renewed annually, $9.5 million of which was outstanding. The weighted average interest rate on borrowings outstanding on September 30, 1996 was 6.6%. 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% to .35% of the lines.
Note 5. Long-Term Debt
Interest payments for the General and Refunding Bonds are due semi-annually. The General and Refunding Bonds are collateralized by first mortgage liens on substantially all real property and operating plant facilities of the Company's gas utility operations.
Note 6. Common Stock
On June 6, 1990, the Board of Directors declared a dividend distribution of one Right for each outstanding share of common stock of the Company. The Rights will not be exercisable until a person ("Acquiring Person") or group of affiliated or associated persons acquires 10% or more of the Company's outstanding common stock or announces an intention to make a tender offer that would result in ownership by such person or persons of 20% or more of the Company's outstanding common stock. Following such an event and unless earlier redeemed or expired, each Right entitles its holder to purchase from the Company one share of common stock for $48.00.
In the event the Company is acquired in a merger or other business combination, 50% or more of its consolidated assets or earning power is sold or transferred, any person acquires 15% or more of the Company's outstanding common stock, or an Acquiring Person engages in one or more self-dealing transactions with the Company, each Right will entitle its holder to purchase, at the Rights' exercise price, a number of shares of common stock of the Company or of the acquiring company having a value of twice such exercise price. Any Rights held by an Acquiring Person or its affiliate or associate become null and void upon the occurrence of any such events.
Prior to expiration of the Rights and except in certain instances following acquisitions of 10% or more of the Company's common stock, the Company may redeem all of the Rights for one cent per Right. The Rights do not carry voting or dividend rights and have no dilutive effect or effect on the earnings of the Company.
The distribution of the Rights was made on June 18, 1990 to shareholders of record on that date and attach to all common shares issued at and after that date. The Rights will expire on June 18, 2000 unless such date is extended or unless the Rights are earlier redeemed by the Company.
Note 7. Income Taxes
On October 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires adjustments of deferred tax assets and liabilities to reflect the future tax consequences, consistent with currently enacted tax laws and rates, of items already reflected in the financial statements. The implementation of SFAS No. 109 on October 1, 1993 had no material impact on the earnings or cash flows of the Company. A regulatory liability of approximately $440,000 was established 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. Also, a regulatory liability of approximately $1,183,000 was established for the tax benefit of unamortized investment tax credits, which SFAS No. 109 requires to be treated as a temporary difference. This benefit will be passed on to customers over the lives of the property giving rise to the investment tax credits. The Company does not believe that SFAS No. 109 will significantly impact future results of operations or cash flows based on current ratemaking policy.
At September 30, 1996 and 1995, the SFAS No. 109 regulatory liability amounted to $1.0 million and $1.1 million, respectively, for the tax benefit of unamortized investment tax credits, and $339,000 and $384,000, 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 utility 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's gas distribution subsidiary never incurred a NHBPT liability; therefore, no deferred state income taxes related to temporary differences were recorded.
Note 8. 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'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.
The Company also has a Supplemental Executive Retirement Plan ("SERP") for certain management employees. Benefits are based on the employee's service and earnings as defined in the SERP. The SERP is a non-qualified plan under the Internal Revenue Code and has no advance funding. Benefit payments are made directly by the Company to retired employees or their beneficiaries.
Plan assets are invested in common stocks and bonds.
The Company has employee 401(k) savings and investment plans covering substantially all employees. The Company made contributions of $216,000, $210,000 and $178,000 for the years ended September 30, 1996, 1995 and 1994, respectively.
Other Postemployment Benefits
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to qualified retired employees.
In accordance with SFAS No. 106, the Company began recording the cost of postretirement benefits on an accrual basis in 1994. The expense recorded in fiscal 1996, 1995 and 1994 for providing postretirement benefits, including amortization of the accumulated projected benefit obligation over a 20-year period, was $588,000, $646,000 and $878,000, respectively.
The Company has funded these benefit costs by making cash contributions, at the same level of expense recorded, to voluntary employee benefit association ("VEBA") trusts established separately for salaried and hourly paid employees.
An 11% average annual rate of increase in the per capita costs of covered health care benefits was assumed for fiscal year 1996, 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 $434,000 increase in the accumulated postretirement benefit obligation as of July 31, 1996 and an increase in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for fiscal year 1996 of $37,000. A discount rate of 7.5% 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 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 1996 to 2011.
Litigation
The Company and its subsidiaries have 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 facilities for the manufacture of gas from coal, a process used through the mid-1900's 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 clean-up 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 is reasonably certain.
A former manufactured gas facility in Concord, New Hampshire has been investigated and partially remediated. Disposal of the contents of the gasholder situated at this former gas manufacturing facility has been completed. Total remediation costs amounted to approximately $3.5 million and were recorded in deferred charges. Recovery of costs from customers began on July 1, 1995 and will extend over a seven-year period. The unamortized balance of $3.0 million at September 30, 1996 is excluded from rate base.
The New Hampshire Department of Environmental Services ("NHDES") has selected a remedial action for a portion of the Concord site at which wastes were disposed of between the late 1800's and mid-1900's. The estimated cost of the remedial action ranges from $2.9 million to $4.8 million, and the Company has recorded $2.9 million at September 30, 1996 in deferred charges.
The Company is pursuing recovery from its insurance carriers as well as from insurance carriers of its predecessors with respect to the Concord site. In addition, the Company is pursuing recovery against an entity that the Company alleges owned or operated the manufactured gas plant during the late 1800's and early 1900's.
The Company and another utility company have been directed by the NHDES to conduct 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 the other utility have entered into an agreement under which costs of the site characterization are shared. The Company's share of the costs of the site characterization and a report to the NHDES, which is underway, is expected to total $88,000 and has been recorded in deferred charges as of September 30, 1996. The Company 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 will 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.
Transition Costs
Federal Energy Regulatory Commission Order 636 allows interstate pipeline companies to recover transition costs created, for the most part, as they buy out of long-term, fixed-price gas contracts. The Company's pipeline supplier, Tennessee Gas Pipeline Company, began direct billing these costs to the Company on September 1, 1993 as a component of demand charges. Through September 30, 1996, the Company has been billed $5.9 million for transition costs and has charged these costs to deferred gas costs. The Company is recovering transition costs through the CGA. Based on current information, additional transition costs are expected to range from $1.7 million to $5.1 million and will continue to be billed over a period of approximately one to three years. At September 30, 1996, the Company has recorded an estimated liability of $1.7 million for transition costs and a corresponding regulatory asset. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and the Shareholders of EnergyNorth, Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of EnergyNorth, Inc. (a New Hampshire corporation) and subsidiaries as of September 30, 1996 and 1995, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended September 30, 1996. These consolidated 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, Inc. and subsidiaries as of September 30, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1996, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic consolidated 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 consolidated financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic consolidated financial statements and, in our opinion, is fairly stated, in all material respects, in relation to the basic consolidated financial statements taken as a whole.
/s/ Arthur Andersen LLP
Boston, Massachusetts November 1, 1996
Note: Earnings (loss) per share are based on the weighted average shares outstanding at the end of the quarter. 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, 1996.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item is incorporated by reference to pages 3 and 4 of the Registrants' Proxy Statement for its Annual Meeting to be held February 5, 1997, except for information relating to identification of Executive Officers of the Registrant which is contained in Part I of the Report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item is incorporated by reference to "Compensation of Directors," "Executive Compensation" and "Non-Contributory Retirement Plan" on pages 5 through 7 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997. ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item is incorporated by reference to pages 2 and 3 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item is incorporated by reference to "Compensation Committee Interlocks and Insider Participation" on page 5 of the Registrant's Proxy Statement for its Annual Meeting to be held February 5, 1997.
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 Consolidated Statements of Income for the years ended September 30, 1996, 1995 and 1994 21 Consolidated Balance Sheets at September 30, 1996 and 1995 22 Consolidated Statements of Capitalization at September 30, 1996 and 1995 23 Consolidated Statements of Common Stockholders' Equity for the years ended September 30, 1996, 1995 and 1994 24 Consolidated Statements of Cash Flows for the years ended September 30, 1996, 1995 and 1994 25 Notes to Consolidated Financial Statements 26-36 Report of Independent Public Accountants 37
(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 Consolidated Valuation and Qualifying Accounts for the three years ended September 30, 1996 41 Report of Independent Public Accountants 37
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 43 through 45.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended September 30, 1996.
(c) Exhibits - See Exhibit Index on pages 43 through 45.
(d) Financial Statement Schedules SCHEDULE II
ENERGYNORTH, INC. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (In thousands)
________________________________________ (1) Represents recoveries on accounts previously written off 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, INC.
Date: December 20, 1996 by: /s/ Robert R. Giordano Robert R. Giordano President & 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 20, 1996.
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, Inc. are incorporated by reference to Exhibit 4.1 of EnergyNorth, Inc.'s Registration Statement on Form S-3, No. 33-41579, dated July 2, 1991.
3.2 By-Laws of EnergyNorth, Inc., dated as of February 1, 1995, are incorporated by reference to Exhibit 4 to EnergyNorth, Inc.'s Post-Effective Amendment No. 2 to Registration Statement on Form S-3, No. 33-58127, dated November 21, 1996.
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 of 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 of 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.
4.5 Copies of Bond Indentures and a note and credit agreement defining the rights of holders of long-term debt of certain subsidiaries of EnergyNorth, Inc., under which the amounts of bonds or the note issued do not exceed 10% of the consolidated assets of EnergyNorth, Inc. will be furnished to the Securities and Exchange Commission upon request.
4.6 Rights Agreement, dated as of June 18, 1990, between the Registrant and State Street Bank & Trust Company as Rights Agent is incorporated by reference to Exhibit I-2 to EnergyNorth, Inc.'s Registration Statement on Form 8-A, dated June 18, 1990.
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 Supplemental Executive Retirement Plan of EnergyNorth, Inc., as amended.
10.4 Deferred Compensation Agreement, dated as of November 30, 1993, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.3 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1993.
10.5 Deferred Compensation Agreement, dated as of November 30, 1993, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.5 to EnergyNorth Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1993.
10.6 Amendment to Deferred Compensation Agreement, dated as of October 1, 1996, between Robert R. Giordano and the Registrant.
10.7 Amendment to Deferred Compensation Agreement, dated as of October 1, 1996, between Albert J. Hanlon and the Registrant.
10.8 Deferred Compensation Agreement, dated as of November 30, 1993, between Richard P. Demers and the Registrant, as amended.
10.9 Deferred Compensation Agreement, dated as of November 30, 1995, between Frank L. Childs and the Registrant, as amended.
10.10 Deferred Compensation Agreement, dated as of November 30, 1993, between Michelle L. Chicoine and the Registrant, as amended.
10.11 EnergyNorth, Inc. 1992 Directors' Deferred Compensation Plan, as amended.
10.12 Consulting Agreement, dated as of October 12, 1990, between N. George Mattaini and the Registrant is incorporated by reference to Exhibit 10.17 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
10.13 Amendment No. 1 to Consulting Agreement dated as of February 7, 1996 between N. George Mattaini and the Registrant. 10.14 Employment Agreement, dated as of December 1, 1995, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.9 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.15 Employment Agreement, dated as of December 1, 1995, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.11 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.16 Management Continuity Agreement, dated as of December 7, 1995, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.12 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.17 Management Continuity Agreement, dated as of December 7, 1995, between Albert J. Hanlon and the Registrant is incorporated by reference to Exhibit 10.14 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.18 Management Continuity Agreement, dated as of December 2, 1996, between Michelle L. Chicoine and the Registrant.
10.19 Management Continuity Agreement, dated as of December 2, 1996, between Frank L. Childs and the Registrant.
10.20 Management Continuity Agreement, dated as of December 7, 1995, between Richard P. Demers and the Registrant.
10.21 EnergyNorth, Inc. Key Employee Performance and Equity Incentive Plan, as amended, is incorporated by reference to Exhibit 10.15 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
21 Subsidiaries of the Registrant is incorporated by reference to Exhibit 22 of EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
23 Consent of Arthur Andersen LLP.
27 Financial Data Schedule of the Registrant.
99 EnergyNorth, Inc.'s Dividend Reinvestment and Stock Purchase Plan, as amended is incorporated by reference to Exhibit 99 of EnergyNorth Inc.'s Post- Effective Amendment No. 2 to Registration Statement on Form S-3, No. 33-58127, dated November 21, 1996.