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), ENI Mechanicals, Inc. (ENMI) 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. ENPI is headquartered at 75 Regional Drive, Concord, New Hampshire. ENMI's wholly owned subsidiaries, Northern Peabody, Inc. (NPI) and Granite State Plumbing and Heating, Inc. (GSPH), are headquartered at 25 Depot Street, Manchester New Hampshire and 546 Mast Road, Goffstown, New Hampshire, respectively. All subsidiaries are incorporated in the state of New Hampshire.
On July 14, 1999, the Company and Eastern Enterprises (Eastern), a Massachusetts business trust, entered into an Agreement and Plan of Reorganization (Agreement) which provides for the merger of the Company with a subsidiary of Eastern, as a result of which the Company's subsidiaries would become wholly owned subsidiaries of Eastern. On November 4, 1999, Eastern entered into an agreement to merge with KeySpan Corporation and, as a result, the Company and Eastern amended the Agreement. Under the amended Agreement, holders of outstanding shares of the Company's common stock will be paid entirely in cash and the closing will take place simultaneously with the Eastern merger with KeySpan Corporation. If the Eastern/KeySpan Corporation merger is not completed, the Company and Eastern would nonetheless merge, and holders of outstanding shares of the Company's common stock can elect to receive cash, Eastern common stock or a combination of cash and stock as set forth in the Agreement. Completion of the merger is subject to approval by the Company's stockholders and receipt of satisfactory regulatory approvals, including approval by the State of New Hampshire Public Utilities Commission (Commission) and the Securities and Exchange Commission.
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 LPG) and serves customers in central and southern New Hampshire. ENPI is a member of VGS Propane, LLC (VGSP), a joint venture with Northern New England Gas Corporation. VGSP is a Vermont limited liability company which provides LPG sales and service in the state of Vermont.
In May 1998, ENI acquired NPI and GSPH. Both are mechanical contractors engaged in the design, construction and service of plumbing, heating, ventilation, air conditioning and process piping systems. They serve commercial, industrial and institutional customers in northern New England. NPI has an operating location in Portland, Maine.
In general, the senior management of ENI serves as the senior management of all subsidiaries, other than NPI and GSPH. ENI provides for the subsidiaries' administrative support and services and establishes policies, plans and goals.
The service territory of ENGI has a population of approximately 482,000 in 28 communities situated mostly in southern and central New Hampshire, which includes the communities of Nashua, Manchester, Concord and Laconia. In 1999, ENGI was awarded the franchise for the city of Berlin, New Hampshire. Berlin is situated in the northern part of New Hampshire approximately 100 miles from the rest of the service area. The remaining service area encompasses approximately 922 square miles and is 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 New Hampshire nonfarm employment growth rate was 2.1% in 1999. This compares to a 2.0% average growth rate nationally and a 1.6% average rate for New England for the same period. New Hampshire employment growth in 2000 is forecasted to be 1.7%. New housing permits increased 16.6% in 1999 compared to 1998, and are expected to decrease by 5.2% in 2000. The New Hampshire unemployment rate for 2000 is forecasted at 2.7% compared to 2.5% in 1999, and the labor force is forecasted to increase by 1.7% in 2000. Job growth and low unemployment in the Company's service area tend to result in an increase in gas volumes transported and sold and numbers of customers. (All employment and housing statistics are taken from The New England Economic Project's October 1999 Economic Outlook for New Hampshire.) In fiscal 1999, the Company experienced net growth of 2.9% in natural gas and transportation customers and 8.3% in propane customers over 1998.
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, while also expanding its system of mains into areas in which there is a significant demand for natural gas service. In 1999, ENGI expanded into Berlin, New Hampshire and began providing natural gas service in early fiscal year 2000. ENGI has more than a 28% share of the home heating market (based on households) within its service territory, creating a potential for increased sales where the natural gas pipeline is located and alternative fuels are used. In New Hampshire, fuel oil has a penetration of over 55% of the home heating market. Currently, the price of natural gas for heating is higher than the full- service price of fuel oil. From a total energy perspective, natural gas is a stronger competitor with a complete line of gas appliances and uses, including ranges, water heaters, clothes dryers, fireplaces and gas logs, outdoor lights and natural gas heat pumps for heating and cooling. While these multiple uses provide opportunities to be the total energy provider to new customers, they also provide opportunities for expansion within the existing customer base. Due to continued customer conversions from other energy sources and expansion of its service territory, ENGI has an opportunity for growth in the retail sales market. During the past four years, ENGI has experienced an annual average customer growth rate of 2.7%. This compares to an approximate 1.1% national average for local distribution companies, according to the American Gas Association. Additional growth in distribution operations also occurs as industrial and commercial customers turn to natural gas for electric generation because of a price advantage and as a means to ensure compliance with the provisions of the Clean Air Act. As the
electric industry continues to move toward deregulation, this option has become more attractive. The development of new gas-burning technologies for industry has provided opportunities for increased gas usage in market sectors that are not sensitive to the weather.
Utility Gas Distribution Business
ENGI distributes natural gas as a regulated utility pursuant to franchise authority granted by the Commission. No operations are outside New Hampshire. While ENGI's franchise area is primarily residential in character, 51% of sales volumes are commercial and industrial. As of September 30, 1999, the Company's utility business served nearly 72,000 customers, of which approximately 88% were residential and 12% were commercial and industrial. During fiscal 1999, no ENGI customer purchased more than 2.5% of the total ENGI annual sales and transportation volume.
ENGI offers firm and interruptible transportation service to its commercial and industrial customers. Transportation service allows a customer to purchase a natural gas supply directly from a third-party marketer. The marketer delivers the gas supply to one of ENGI's interstate pipeline take stations. The customer contracts with ENGI to transport the gas from the take station to its facility. To ensure a continual, uninterrupted supply, ENGI also provides an optional, separate standby service as a backup to the gas supplies of transportation customers. As of September 30, 1999, ENGI had 89 firm transportation customers.
ENGI distributes gas to its utility customers through a system of underground pipelines connected with its three operations centers in Manchester, Nashua and Tilton, seven take stations located in Manchester, Londonderry, Windham, Concord, Hooksett, Suncook and Berlin 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 more than 75% of New Hampshire's natural gas customers.
On September 7, 1999, the Commission approved a petition filed by ENGI for authority to operate in the city of Berlin, New Hampshire. Berlin is a community of approximately 12,000 inhabitants in the northern tier of the state. At the request of the State of New Hampshire Department of Corrections, ENGI is providing natural gas service to a new prison complex being constructed in Berlin. The prison is located approximately one- half mile from the Portland Natural Gas Transmission System. ENGI anticipates additional development in the vicinity of the prison complex, as well as interest from other energy users in the city of Berlin.
Retail Propane Business
ENPI sells propane to more than 15,300 customers, of which approximately 90% are residential and 10% are commercial and industrial. ENPI's service territory includes more than 150 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. ENPI utilizes fixed price contracts with certain suppliers to cover its retail fixed price program, as well as to reduce price volatility during the winter months. ENPI holds a 49% interest in VGSP, a joint venture, and provides planning and management expertise through its representation on the VGSP Board of Managers. VGSP is the largest Vermont-based propane company and services more than 10,000 customers throughout the state of Vermont.
On August 26, 1999, ENPI exercised its option under the VGSP Operating Agreement to offer to sell its share of VGSP to Northern New England Gas Corporation, the 51% member of VGSP. In accordance with the terms of the Operating Agreement, an appraisal is underway to determine the fair value of each member's ownership interest. ENPI anticipates its withdrawal as a member of VGSP will be completed in early 2000.
Mechanical Contracting Business
NPI and GSPH are mechanical contractors engaged in the design, construction and service of plumbing, heating, ventilation, air conditioning and process piping systems. Both companies serve commercial, industrial and institutional customers in northern New England and Massachusetts from operating locations in Manchester and Goffstown, New Hampshire and Portland, Maine. Most mechanical systems are constructed on the site of each project. NPI performs some fabrication work, mostly for industrial customers, at its fabrication shop in Manchester, New Hampshire. The total backlog of orders for NPI and GSPH at September 30, 1999 was $18.5 million compared to $16.2 million last year, and approximately $13 million of the 1999 backlog is expected to be completed in fiscal year 2000.
Summary of Revenues
Revenues attributable to various categories of gas distribution and related operations during the last three fiscal years and mechanical contracting operations for the fiscal year ended September 30, 1999 and for the five-month period ended September 30, 1998 are as follows (in thousands, unaudited):
September 30, -------------------------------- 1999 1998 1997 -------------------------------- Utility (natural gas) sales service $ 72,891 $ 82,686 $ 91,670 Utility transportation service 3,726 2,610 1,308 Propane gas sales 11,164 11,204 12,893 Service and appliance sales 2,275 2,128 2,185 Rentals 854 899 937 Mechanical contract sales 31,391 13,426 - -------------------------------- $122,301 $112,953 $108,993 ================================
During the winter period, November 1 through March 31, the Company's natural gas and propane revenues are substantially higher than during the summer months. The increase in natural gas and propane revenues during the winter, and the concomitant increase in gas supply requirements, occurs because approximately 83% of ENGI's and ENPI's customers use natural gas and propane for heating.
Deregulation
ENGI has been providing gas transportation service, including standby and balancing services for commercial and industrial customers since late 1993. Gas transportation service allows customers to utilize ENGI's distribution system for the transportation of gas purchased from third-party suppliers, creating competition from gas marketers for the sale of gas to end users. At September 30, 1999, ENGI had 89 firm transportation customers. These customers are, for the most part, large commercial and industrial customers. The volume transported for firm transportation customers in fiscal 1999 was 2.0 Bcf, 26% of the Company's total commercial and industrial load and 15.8% of ENGI's total gas delivered. ENGI is participating in a proceeding at the Commission to examine further unbundling of the natural gas industry in New Hampshire. The purpose of the proceeding is to determine whether and to what extent unbundling provides benefits to customers and to make recommendations to the Commission as to the advisability of further unbundling to other classes of customers. A full report of recommendations by the participants, along with model terms and conditions, is expected to be filed with the Commission in late 1999. ENGI cannot predict the outcome of the proceeding, or the impact on transportation volumes or customers.
ENGI is the sole distributor and transporter of natural gas in its franchise area. The Tennessee Gas Pipeline Company (Tennessee) serves all of ENGI's franchise area, except the city of Berlin, which is served by the Portland Natural Gas Transmission System. 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, some of whom 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.
Under current market conditions, natural gas has a significant price advantage over electricity in New Hampshire. Natural gas heating costs are currently less than one-third of electric heating costs. At the present time, the price of natural gas for heating is higher than the full-service price of fuel oil. ENGI continues to add customers who might otherwise elect to use oil, because energy decisions are also based on factors other than cost, such as service, cleanliness and environmental impact. Demand for natural gas is expected to continue to increase as national attention remains focused on its environmental advantages, efficiency and security of supply. Commercial and industrial customers continue to find gas technologies and equipment attractive as they deal with
the requirements of the Clean Air Act Amendments of 1990 and other federal environmental legislation. The retail propane market is very competitive, and numerous 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.
The mechanical contracting market is very competitive. Most contracts are awarded through a bid process in which there are, usually, at least three bidders. The principal competitive factors are price and the quality and reliability of the construction work.
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, Pipeline Transportation and Underground Storage Contracts. ENGI's gas supply is principally natural gas, transported on interstate pipelines. The primary pipeline ENGI uses to bring natural gas to its distribution territory is the Tennessee Gas Pipeline (TGP). ENGI contracts for 56,833 Dekatherms (Dth) of primary firm and 8,000 Dth of interruptible capacity on TGP. ENGI also has a long-term contract with a New England supplier for additional firm city gate delivery of 8,000 Dth per day (151 day service).
ENGI's natural gas supply contracts are a mix of long and short- term agreements. ENGI's firm supply contracts for fiscal year 1999, with terms of one to seven years, totaled 40,529 Dth per day. During fiscal year 1999, approximately 4.7% of ENGI's natural gas supply portfolio was firm delivered winter supplemental supply. One percent of ENGI's annual supply in fiscal year 1999 was purchased in the spot market.
In fiscal year 1999, approximately 61% of the gas delivered by ENGI came from domestic pipeline sources, 24% from Canadian pipeline sources, and 14% from supplemental pipeline sources. LPG and liquefied natural gas (LNG) purchases from both domestic and foreign sources made up approximately 1% of the gas delivered by ENGI. LPG and LNG are vaporized at ENGI's peakshaving (production) plants as needed to supplement pipeline natural gas supplies. Unbundled end-user customers that are supplied by third-party marketers accounted for nearly 15.8% of total load on ENGI's system during fiscal year 1999.
All pipeline volumes to ENGI's city gates are transported via the TGP, except for volumes which are transported to the city gate at Berlin, New Hampshire by the Portland Natural Gas Transmission System. Canadian supplies are also transported by the suppliers on the TransCanada Pipeline to the U.S. border, where ENGI takes possession in this country and transports these supplies on the Iroquois Gas Transmission System, the Portland Natural Gas Transmission System and the TGP. All domestic pipelines operate under FERC approved tariffs.
ENGI has underground storage agreements with four storage field operators in the Pennsylvania-New York area. ENGI fills these storage fields each summer for use during the following winter. Total combined storage controlled by ENGI equals 2,579,431 Dth with daily withdrawal rights of 30,833 Dth. All underground storage fields operate under FERC approved tariffs. ENGI also owns on-site storage facilities capable of holding 115,660 Dth of LPG and 13,057 Dth of LNG. ENGI has contracted for 450,000 Dth of supplemental pipeline supply, 100,000 Dth of LNG and 1,000,000 gallons of LPG for the upcoming winter (1999/2000).
The Company expects to be able to secure the gas supply required to meet existing customer and forecasted new customer demands through long and short-term commitments and through spot purchases when needed.
Cost of Purchased and Produced Gas. The average unit cost of gas purchased and produced during the twelve months ended September 30, 1999 was approximately $3.78 per Mcf compared to $4.09 per Mcf for the same period last year. The 1999 average unit cost reflects the lower cost of gas supply in the marketplace. The cost of gas rate authorized by the Commission permits recovery by ENGI from its customers (or requires refunds to its customers) of gas costs (including pipeline, storage, LPG and LNG) that are higher (or lower) than the cost of gas included in base rates. ENGI may adjust the approved cost of gas rate upward or downward on a monthly basis. The monthly accumulative adjustments may not exceed 10% of the approved unit cost of gas sold. Amounts recovered through cost of gas charges are reconciled twice annually against actual costs, for summer and winter periods, and future cost of gas rates are adjusted accordingly.
ENGI has a Natural Gas Price Risk Management Program designed to protect customers from sharp increases in the commodity cost of gas. Under the program, ENGI has purchased call and sold put options for the 1999/2000 winter period. The call options provide the right, but not the obligation, to purchase gas at a predetermined price by a certain date. The purchase of call options and the sale of put options create a collar mechanism. The collar establishes a maximum and minimum price at which the Company will buy gas contracts on the commodities market. All program costs and benefits are passed on to customers through the cost of gas charge.
Margins earned on interruptible service, 280 day service and capacity releases are passed on to firm customers through the cost of gas charge. In addition, costs associated with the fuel inventory trust, including administrative fees and carrying costs, are recovered through the cost of gas charge.
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 a 30-day notice to the Commission, which has the power to suspend, investigate and change any proposed increase in rates and charges.
The natural gas and propane 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. Their capital expenditures, earnings and operations have not been materially affected by environmental and local regulation.
The mechanical contracting businesses of NPI and GSPH are subject to OSHA regulations and local, state and federal building codes but are not otherwise subject to direct regulation by federal, state and local agencies.
Employees
At September 30, 1999, the Company had 459 full-time employees, of whom 135 were represented by four contracts with Local 12012 of the United Steelworkers of America. The contracts expire in 2001 and 2002. Various locals of the United Association of Plumbers and Pipefitters represent 134 employees under a contract that expires in 2000.
ITEM 2.
ITEM 2. PROPERTIES
The Company's utility gas distribution facilities constitute the majority of its physical assets. As of September 30, 1999, ENGI had approximately 1,113 miles of mains and 702 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 First Mortgage 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 computer equipment and vehicles.
Office/operating locations for NPI and GSPH in Manchester and Goffstown, New Hampshire and Portland, Maine are leased until 2002-2003 with options to renew. The locations are adequate and are regularly maintained and in good condition. Substantially all vehicles and other equipment are leased or are subject to purchase money security interests held by banks.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In addition to the matters described below, the Company is a party in several proceedings of the sort that arise in the ordinary course of its business. Such actions, for the most part, are covered by insurance and, to the extent that they are not fully covered, the damages sought are not material in
amount. The Company is a party to various routine Commission proceedings relating to operations, none of which is expected to have a material impact on the Company's earnings or assets.
The Company, and certain of its predecessors, own or owned several facilities at which manufactured gas plants (MGP) operated. MGPs were used to manufacture gas prior to the introduction of natural gas to the Company's service area. Generally, MGPs operated from the late 1800s to the early 1950s. The MGPs produced wastes and by-products that may be considered contaminated or hazardous under current law, and some of which may still be present at such facilities. Relevant environmental laws can be used by the state and federal government to hold the Company strictly liable for the costs of studying and remedying discarded by-products from MGPs owned and operated by its predecessors. The Company accrues environmental investigation and cleanup costs with respect to former MGPs and other environmental matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
The New Hampshire Department of Environmental Services (NHDES) has required the Company to undertake remedial investigation and/or remedial action at MGPs located in Concord, Laconia, Nashua, and Dover, New Hampshire. At each MGP, the Company is responding to the NHDES's requirements as described below.
In September 1992, the NHDES required the Company to undertake a remedial investigation of the former MGP in Concord, New Hampshire. Study and remediation associated with the Concord MGP is ongoing. The estimated cost to complete this remedial action ranges from $690,000 to $1.6 million, and the Company has recorded $690,000 at September 30, 1999 in deferred charges. The Company received an order from the Commission approving recovery from customers, over a seven-year period, of substantially all costs, excluding carrying costs, incurred for the Concord MGP. The total unamortized balance for the Concord site, including the gas holder site, was $4.4 million as of September 30, 1999.
At the direction of the NHDES, the Company and Public Service Company of New Hampshire (PSNH), an electric utility company, conducted a remedial investigation of a former MGP in Laconia, New Hampshire, and in January 1999 prepared a Remedial Action Plan for that site. Without admitting any liability, on September 3, 1999, the Company entered into a Site Responsibilities and Indemnity Agreement (SRIA) with PSNH. Pursuant to the SRIA, the Company will pay $4.2 million to PSNH over a twenty-four (24) month period. In exchange, PSNH will assume responsibility for all future site study and remediation, and PSNH will indemnify the Company against such costs. The Company's legal liability under state and federal laws is unaffected by the SRIA. Through September 30, 1999, the Company has paid $1 million under the SRIA. The estimated costs associated with work undertaken prior to the SRIA ranges from $117,000 to $517,000, and the Company has recorded $3.3 million in deferred charges at September 30, 1999.
During 1998, the Company and PSNH received Notice of Potential Responsibility from the Environmental Protection Agency (EPA) for the so-called Nashua River Asbestos Site. The EPA contends that wastes released from the former MGP in Nashua, New Hampshire are commingled with asbestos wastes from a former Johns Manville facility located adjacent to the former MGP.
The Company's share of costs to complete the disposal of contaminants that are the subject of EPA claims are estimated to range from $375,000 to $450,000. The Company and PSNH subsequently received a notice from the NHDES requiring the investigation of the former MGP site in Nashua. The Company estimates the cost of site investigation and characterization at the Nashua MGP to range from $250,000 to $325,000. The Company recorded $625,000 in deferred charges at September 30, 1999.
In April 1999, the Company received notice from the NHDES to investigate the former MGP site in Dover, New Hampshire. PSNH and another utility company, Northern Utilities, received similar notices concerning the Dover MGP from the NHDES. The Company estimates its cost of that investigation and characterization to range from $200,000 to $400,000. The Company has recorded $200,000 in deferred charges at September 30, 1999.
The Commission has approved a generic recovery mechanism for costs incurred at all MGP sites, except recovery for the Concord site noted above, which provides for a seven-year recovery period of substantially all costs, excluding carrying costs. The recovery mechanism provides that the environmental surcharge to customers will not exceed 5% of total gross gas revenues in any given year but that amounts in excess of 5% will be deferred to future periods with recovery of applicable carrying costs.
The Company intends to pursue insurance recovery as well as recovery from other responsible parties to ensure that such third parties contribute appropriately to reimburse the Company for any costs incurred with respect to environmental matters. All recoveries serve to reduce the seven-year environmental surcharge period to customers. The Company has instituted suits in the United States Federal District Court for New Hampshire and in New Hampshire superior courts against one third party, as well as the Company's insurers and insurers of its predecessors to recover the costs of investigation and remediation of the Concord, Nashua, Dover and Laconia MGP sites. In each litigation, the Company is seeking declaratory judgment that its insurers owe the Company a defense and/or indemnification for environmental claims associated with each respective MGP. Through September 30, 1999, the Company has recovered a total of $4.3 million in settlement of third-party MGP litigation.
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 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Outstanding shares of the Company's common stock are listed and traded on the New York Stock Exchange with the symbol "EI." High and low sales prices during 1999 and 1998 were as follows:
Fiscal 1999 Fiscal 1998 High Low High Low - ------------------------------------------------------------------- First Quarter $29 5/8 $26 3/16 $28 13/16 $22 3/4 Second Quarter 30 1/8 27 1/2 29 1/16 27 5/8 Third Quarter 29 1/4 26 5/8 29 3/4 26 3/8 Fourth Quarter 43 3/4 28 7/8 27 5/8 25 1/4
As of December 2, 1999, there were 1,839 holders of record of common stock.
Quarterly cash dividends paid were as follows:
Fiscal 1999 Fiscal 1998 - ----------------------------------------------------------------- First Quarter $.335 $.32 Second Quarter .335 .32 Third Quarter .35 .335 Fourth Quarter .35 .335
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share for 1999 were $1.37 on net income of $4.5 million, which represents a 16.5% decrease from the $1.64 per share earned in 1998. Impacting 1999 financial results were reorganization costs of $1.2 million, or $.35 per share, incurred as a result of the pending merger with Eastern. Although the weather was colder in 1999, it was warmer than normal and also had a significant impact on financial results, reducing 1999 utility margin by approximately $.36 per share, after taxes. In 1998, utility margin was reduced approximately $.51 per share, after taxes, as a result of warmer than normal temperatures. The 1999 earnings were favorably impacted by continued customer growth and successful efforts to contain operating costs. The earnings achieved represent a return on average common equity of 11.2% before the impact of reorganization costs. Cash dividends paid on common stock were $1.37 representing a payout ratio of 100% of 1999 earnings. The current quarterly dividend of $.35 per share is equal to an annual dividend of $1.40 per share. The quarterly dividend increased 4.5% in 1999, from $.335 to $.35 per share.
Utility Sales and Revenues
The rates charged to utility customers are regulated by the Commission. The Commission is required by New Hampshire law to allow ENGI to charge rates that are just and reasonable, such that ENGI is compensated for the cost of providing service and allowed a reasonable rate of return on its investment. ENGI regularly assesses whether it is earning a reasonable return and files for rate increases when it determines that it is not being permitted to earn a reasonable return.
ENGI generates revenues primarily through the sale and transportation of natural gas. ENGI's gas sales are divided into two categories: firm, whereby ENGI must supply gas to customers on demand; and interruptible, whereby ENGI may, generally during colder months, temporarily discontinue service to high-volume commercial and industrial customers. Sales of gas to interruptible customers do not materially affect ENGI's operating income because all margin on such sales is returned to the Company's firm customers.
ENGI's tariff includes cost of gas rates that provide for increases and decreases in the rates charged for gas to reflect estimated changes in the cost of gas. Although changes in cost of gas rates affect revenues, they do not affect total margin because the cost of gas charge is a tariff mechanism designed to provide dollar-for-dollar recovery of gas costs. Amounts recovered through cost of gas charges are reconciled at least semiannually against actual costs, and future cost of gas rates are adjusted accordingly.
ENGI's sales are responsive to colder weather because the majority of firm customers use natural gas for space heating purposes. ENGI measures weather through the use of degree days. A degree day is calculated by subtracting the average temperature for the day from 65 degrees Fahrenheit. The "normal" number of degree days during any period is calculated based upon a rolling approximate 30-year average number of degree days during such period. The table below discloses
degree day data as recorded at the U.S. weather station in Concord, New Hampshire, comparing actual degree days to the previous period and to normal. Because of the size and topographical variations of ENGI's service territory, weather conditions within such territory often vary. ENGI considers Concord, New Hampshire weather data to be representative of weather conditions within its service territory.
Operating revenues for ENGI were $76.6 million in 1999 compared to $85.3 million in 1998. The decrease resulted primarily from lower cost of gas rates due to reductions in the cost of gas. Partially offsetting the impact of lower cost of gas charges was the 2.4% growth in the average number of customers in 1999. Customer growth combined with temperatures that were 2.5% colder than the prior year resulted in a 4.6% increase in firm sendout. The weather in 1999 was 10.1% warmer than normal. Revenues from gas transported for customers under firm transportation service rates increased 45% to $3.4 million, due to a more than 46% increase in volumes transported. This increase included a shift of 174,000 Mcf from firm commercial and industrial sales customers, representing a decrease of $615,000 in operating revenues attributable to the commodity cost of gas.
Utility Cost of Gas
The cost of gas sold was $36.6 million in 1999 compared to $46.7 million in 1998 The decrease was primarily due to timing differences related to the recovery of gas costs through cost of gas charges ($5.4 million), lower volumes of gas sold ($1.3 million) and a decline in the unit cost ($3.4 million). The average unit cost of gas sold in 1999 was $3.78 per Mcf compared to $4.09 per Mcf in 1998. Decreases or increases in purchased gas costs from suppliers have no significant impact on margin, because they are passed on to customers through the cost of gas charge.
Retail Propane Operations
ENPI contributed $203,000 to net earnings of the Company, a slight increase over 1998 results. Significantly impacting net earnings were reorganization costs of $95,000. In addition, ENPI's share of VGSP's loss was $266,000 after taxes compared to a loss of $244,000 last year. The average number of propane customers increased more than 8% and propane gallons sold increased 6.5% in 1999. The substantial customer growth and weather that was colder than the prior year accounted for the increase in gallons sold. While 1999 operating revenues of $11.1 million were slightly less than 1998, gross margin increased 6.5%. The cost of gas sold was favorably impacted by market prices and was 7.5% less than 1998. The Company was able to maintain a competitive price while the unit cost of gas sold decreased 13.2%. Operations and maintenance expense increased approximately 5.7%. Increases in labor, transportation and other delivery related
expenses necessary to support an expanding customer base were partially offset by cost control measures in other areas.
Mechanical Contracting Operations
Contract revenues and net income for 1999 were $31.4 million and $422,000 compared to $13.4 million and $194,000 in 1998, respectively. The Company's mechanical contracting operations were acquired under the purchase method of accounting in May 1998. Consequently, only five months of ENMI are included in 1998 results.
Operating Expenses
Operation and maintenance expenses of the mechanical contracting business and increases in wages were the primary reasons for the 9.3% increase in operations and maintenance in 1999. The 1999 results include the first full year of ENMI operational expenses.
Higher depreciation and amortization charges were a direct result of plant additions and amortization of environmental remediation costs. Net additions to property, plant and equipment were $13.8 million and $14.7 million in 1999 and 1998, respectively.
Total interest expense increased $210,000 in 1999 due primarily to the increased level of short-term debt outstanding during the fiscal year.
Reorganization costs are not currently tax deductible. The higher level of income before reorganization costs was the reason for the $120,000 increase in federal and state income taxes in 1999.
Capital Resources and Liquidity
Because of the seasonal nature of the Company's gas operations, a substantial portion of cash receipts is generated during the November - March heating season, which results in the highest cash inflow during late winter and early spring. Cash requirements for capital expenditures, dividends, long-term debt retirement, environmental remediation and working capital do not track this pattern of cash receipts. The greatest demand for cash is in the fall and early winter to support the completion of the annual construction program and to fund gas inventories and other working capital requirements.
The Company's major uses of cash in 1999 were capital expenditures of $13.8 million, environmental remediation of $4.9 million, and retirement of $2.3 million of long-term debt. In addition, dividend payments to shareholders totaled $4.5 million in 1999. These expenditures were funded primarily through cash generated from current operations and short-term borrowings. Borrowings against lines of credit during 1999 ranged from $181,000 to a high of $15.3 million. In addition, at September 30, 1999, deferred gas cost was in an undercollected position resulting from winter and summer activity. The undercollected amounts will be recovered from customers through cost of gas charges.
Capital expenditures for fiscal year 2000 are currently projected at approximately $14.3 million. Additional cash requirements will be necessary for the payment of dividends, environmental remediation, annual sinking fund requirements, maturities of long- term debt, working capital and costs related to the proposed merger with Eastern. 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, 1999, the Company had available lines of credit aggregating $27.7 million, $15.3 million of which was outstanding. In addition, a credit line of $10.5 million was available at September 30, 1999, under the Company's fuel inventory trust financing plan. At September 30, 1999, the Company's fuel inventory in trust was $8.3 million with an outstanding purchase obligation of $8.3 million.
On September 30, 1999, the Company's capitalization ratio consisted of 45% common equity and 55% debt, including short-term debt.
Environmental Matters
The Company continues to work with federal and state environmental agencies to assess the extent and environmental impact of contaminants that may exist at or near former gas manufacturing sites. The costs of such assessments and any related remediation determined to be necessary is expected to be funded from traditional sources of capital, recoveries from insurance carriers and responsible third parties and customers. For further information, see Note 12 to the consolidated financial statements.
Results of Operations 1998 Compared to 1997
Net income decreased to $5.4 million in 1998 from 1997 net income of $6.5 million. Earnings per share in 1998 were $1.64 compared to $2.01 in 1997. Warmer weather in the Company's service territory significantly impacted net income. Temperatures were 12.9% warmer than normal and 11.4% warmer than the prior year. The effect of weather, when compared to normal, reduced 1998 utility margin by $.51 per share after taxes; whereas, warmer temperatures in 1997 decreased utility margin by $.14 per share after taxes. In addition, 1997 earnings were $.20 per share higher than 1998 as a result of a favorable net property tax settlement that was recorded in 1997.
Operating revenues were $109.9 million in 1998, an increase of 3.9% from 1997. Mechanical contracting operations acquired in 1998 added $13.4 million to operating revenues. Utility gas service revenues, which represented more than 77% of total operating revenues, decreased by $7.7 million, or 8.3%. The unit cost of gas sold in 1998 was $4.09 per Mcf compared to $4.28 per Mcf in 1997. Although the weather in the Company's service territory was 12.9% warmer than normal and 11.4% warmer than 1997, the total volume of gas delivered to utility customers increased slightly. Partially offsetting the impact of the warmer temperatures was the 2.4% growth in the average number of utility customers.
Propane operations recorded $11.2 million in total operating revenues in 1998, a decrease over 1997 of $1.7 million. Propane gallons sold were slightly less than 1997 due to the warmer weather, and the unit cost of propane gallons sold decreased 22%.
Operations and maintenance expense for 1998 included the expenses of the mechanical contracting operations that were acquired in May. The increase from 1997 was due mostly to this acquisition. Taxes other than income taxes increased $1.2 million to $4.1 million in 1998. The 1997 results include a favorable property tax settlement, net of adjustments, of more than $1 million.
New Accounting Standards and Pronouncements
During fiscal year 1999, the Company implemented a number of Statements of Financial Accounting Standards (SFAS). SFAS No. 130, "Reporting Comprehensive Income," establishes standards for reporting and the disclosure of comprehensive income and its components. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," requires disclosure of operating segments, including disclosures about products and services, geographic areas and major customers. SFAS No. 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," revises employer's disclosures about pension and other postretirement benefit plans. It does not change the measurement or recognition of those plans. None of the above standards had a material impact on the Company's financial reporting.
The Financial Accounting Standards Board issued new accounting standards which the Company will adopt in future periods. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," establishes standards for recording all derivative instruments as assets and liabilities measured at fair value. The standard was to be effective in the first quarter of fiscal year 2000, but was amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" - an amendment of FASB Statement 133. As such, SFAS No. 133 will be effective in the first quarter of fiscal year 2001. The Company has not yet quantified the impacts of adopting SFAS No. 133 in the financial statements and has not determined the timing of or method of adoption of SFAS No. 133. However, the statement could increase volatility in earnings and other comprehensive income.
The American Institute of Certified Public Accountants issued Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed and Obtained for Internal Use," and SOP 98-5, "Reporting on the Costs of Start-up Activities." Both are effective in fiscal year 2000 and adoption is not expected to have a material impact on the Company's financial position.
Year 2000 Readiness
The Company has evaluated its principal computer systems and noninformation technology systems including, but not limited to, telecommunication systems, automated meter reading systems, SCADA, regulator stations, plant remote control systems and security systems to determine readiness for the year 2000. At September 30, 1999, all Company systems critical to the delivery of gas to customers are year 2000 compliant. All necessary program modifications and system upgrades and testing have been completed. Costs incurred to date and costs expected to be incurred to complete the year 2000 readiness are not material and will not have a material impact on the Company's financial position or results of operations.
The Company is currently assessing year 2000 issues with third parties with whom it has a material relationship. Although this assessment is ongoing, critical vendors contacted to date have indicated that interruption to service due to year 2000 problems is unlikely. Due to the complexity of the problem and the reliance on certain important vendors and suppliers, there can be no guarantee that year 2000 compliance for all computer systems and other systems will be achieved or that critical and important vendors and suppliers will achieve compliance. The successful upgrade of the Company's systems on a timely basis is critical to enable the Company to avoid business disruption and the loss of essential information or data in the year 2000. In addition, a disruption of the transmission of gas due to year 2000 problems experienced by the Company's gas supplier or other significant vendors and service providers could prevent the delivery of a sufficient amount of gas to enable the Company to serve certain customer segments.
Because of the difficulty of accessing year 2000 readiness of others outside the control of the Company, the Company considers potential disruptions by these third parties to present the "reasonably likely worst case scenario." The Company's inability to serve its customers could result in increased costs, loss of business and other similar risks. In an effort to reduce the risks of non-compliance, the Company has updated its Emergency Plan to consider any foreseeable year 2000 contingencies.
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 discussion of the Company's business and Management's Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning the impact of changes in the cost of gas and cost of gas rates on total margin; projected capital expenditures and sources of cash to fund expenditures; the impact of regulatory proceedings on unbundling; year 2000 readiness; estimated costs of environmental remediation and regulatory approval of recovery; competition with other forms of energy; expansion of service in Berlin; the merger with Eastern; and customer bypass. The Company's future results, generally and with respect to such forward-looking statements, may be affected by many factors, among which are uncertainty as to the regulatory allowance of recovery of changes in the cost of gas; uncertain demands for capital expenditures and the availability of cash from various sources; uncertainty as to whether transportation rates will be reduced in future regulatory proceedings with resulting decreases in transportation margins; uncertainty as to environmental costs and as to regulatory approval of the full recovery of environmental costs and other regulatory assets; weather; results of regulatory proceedings on unbundling; impact of new pipeline supplies; costs of other sources of energy; expansion of service in Berlin; consummation of the merger with Eastern; customer bypass; and success of the Company's year 2000 readiness efforts and those of its vendors and customers.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company does not enter into material market risk sensitive transactions.
ENERGYNORTH, INC. Notes to Consolidated Financial Statements
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth, Inc. and subsidiaries (Company) are set forth below.
Principles of Consolidation - ---------------------------
The accompanying consolidated 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, EnergyNorth Natural Gas, Inc., primarily located in southern and central New Hampshire. The rates and accounting practices followed by the gas distribution subsidiary are regulated by the State of New Hampshire Public Utilities Commission (Commission). The Company's accounting policies conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for Certain Types of Regulation."
The Company also operates a nonregulated propane distribution subsidiary, EnergyNorth Propane, Inc., and provides service and sells appliances through its utility subsidiary.
During fiscal year 1998, the Company acquired two mechanical contracting operations and, through a nonregulated subsidiary, ENI Mechanicals, Inc., provides design, construction and service of plumbing, heating, ventilation, air conditioning and process piping systems to commercial, industrial and institutional customers (see Note 10).
Business Segments - -----------------
Effective October 1, 1998, the Company adopted SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information." Pursuant to SFAS No. 131, the Company's three reportable segments are natural gas distribution, propane gas distribution and mechanical contracting. The adoption of this statement by the Company did not have a material effect on the Company's financial statements. In accordance with this statement, the Company is presenting the required information for the three segments. Because this is the initial year of application of this statement, comparative information for prior years was restated.
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 each month. The Company records unbilled revenues related to gas delivered but not billed at the end of the accounting period.
Mechanical contracting work is performed under cost-plus-fee contracts, fixed-price contracts and time and material contracts. The Company follows the percentage-of-completion method of accounting for contracts that extend for periods in excess of one year. Revenues and related costs for time and material contracts are recognized as the work is performed.
Cost of Gas Rates - -----------------
The Company's tariff includes a cost of gas rate that permits billings to customers to recover its cost of gas. The tariff provides for a cost of gas rate calculation for a summer period and a winter period. The Company may adjust the approved cost of gas rate upward or downward on a monthly basis. The monthly cumulative adjustments may not exceed 10% of the approved unit cost of gas sold. Any difference remaining between the cost of gas incurred and amounts billed to customers at the end of each summer or winter period is deferred for rate-making and accounting purposes to the next corresponding summer or winter period. Interest accrues on these amounts at the prime rate, adjusted quarterly.
Inventories - -----------
Inventories are valued on the basis of the lower of average cost or market.
Depreciation - ------------
The Company provides for depreciation on the straight-line basis. The rates applied by the regulated subsidiary are approved by the Commission. Such rates were equivalent to a composite rate of 3.5% for the year ended September 30, 1999, and 3.4% for each of the years ended September 30, 1998 and 1997. The depreciation rates for nonregulated property, plant and equipment were 7.4%, 7.5% and 8% for the years ended September 30, 1999, 1998 and 1997, 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 is removed from the property accounts and charged, together with any cost of removal, to the accumulated depreciation accounts. For all other assets, when assets are sold or retired, the cost of the assets and their related accumulated depreciation are removed from the respective accounts, net removal costs are recorded and any gain or loss is included in income.
Deferred Charges - ----------------
Total deferred charges consist primarily of regulatory assets and the cost of issuing debt. The Company has established various regulatory assets in cases where the Commission has permitted, or is expected to permit, recovery of specific costs over a period of time. At September 30, 1999, regulatory assets included $11.6 million for environmental investigation and remediation costs and $2.5 million of unrecovered deferred state income taxes (see Note 7).
The unamortized cost of issuing debt at September 30, 1999 is $1.9 million. Deferred financing costs are amortized over the life of the related security. Other deferred charges are amortized over the recovery period specified by the Commission.
Investment Tax Credits - ----------------------
Investment tax credits are amortized over the estimated useful life of the property that gave rise to the credit.
Fair Value of Financial Instruments - -----------------------------------
Because of the short maturity of certain assets, which include cash, temporary cash investments and accounts receivable, and certain liabilities, which include accounts payable and notes payable to banks, these instruments are stated at amounts that approximate fair value.
If long-term debt outstanding at September 30, 1999 had been refinanced using new issue debt rates of interest that on average are lower than the outstanding rates, the present value of those obligations would have increased from the amounts outstanding in the September 30, 1999 accompanying consolidated balance sheet by 2%.
Stock-Based Compensation - ------------------------
The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related interpretations in accounting for its employee stock options. Under APB 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. The Company has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (see Note 9).
Comprehensive Income - --------------------
Effective October 1, 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive Income." This statement establishes standards for reporting and the disclosure of comprehensive income and its components. It did not have a material impact on the Company's financial reporting.
Earnings per Share - ------------------
SFAS No. 128, "Earnings per Share," requires the computation of basic and diluted earnings per share. Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share is determined by giving effect to the exercise of stock options using the treasury stock method (see Note 9).
(In thousands, except per share amounts) For the years ended September 30, 1999 1998 1997 - ------------------------------------------------------------------------- Net income $4,537 $5,378 $6,518 ============================
Weighted average shares 3,319 3,273 3,243 Dilutive effect of options 14 - - ---------------------------- Adjusted weighted average shares 3,333 3,273 3,243 ============================
Basic earnings per share $ 1.37 $ 1.64 $ 2.01 Diluted earnings per share $ 1.36 $ 1.64 $ 2.01
Derivative Instruments and Hedging Activities - ---------------------------------------------
The Company utilizes call and put option contracts to manage market risk associated with a portion of anticipated gas supply requirements. The Company's policy prohibits utilization of derivatives for trading purposes.
Gains or losses on derivatives associated with forecasted transactions are recognized when such forecasted transactions affect earnings. If a derivative instrument is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If such derivative is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and recorded when the associated transaction or forecasted transaction affects earnings.
Although options traded on the NYMEX are included in the table below, they are not financial instruments since physical delivery of natural gas may be made pursuant to these contracts. They are a major part of the commodity risk management program.
The following table summarizes the types of hedges used and the related financial information as of September 30, 1999:
Notional volumes Hedges of NYMEX contracts - ----------------------------------------------------------------- Calls - MMBtu Purchases 105 Puts - MMBtu Sales 105
$ Amount (In thousands) - ----------------------------------------------------------------- Deferred losses, net $(16)
Use of Estimates - ----------------
The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect assets and liabilities, the disclosure of contingent assets and liabilities, and revenues and expenses. Actual amounts could differ from those estimates.
Reclassifications - -----------------
Reclassifications are made periodically to previously issued financial statements to conform to the current year's presentation.
Note 2. Cash Flows
Supplemental disclosures of cash flow information were as follows (in thousands):
1999 1998 1997 - ----------------------------------------------------------------------- Cash paid during the year for: Interest (net of amount capitalized) $4,683 $4,269 $4,080 Income taxes 981 3,246 3,972
Noncash investing and financing activities: Acquisition investment (see Note 10) - 1,991 -
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 equivalents and classified as cash and temporary cash investments.
Note 3. Inventory Financing
The Company finances gas inventory purchases through the use of a single purpose trust, which purchases gas with funds loaned to it by a bank. As the Company requires gas to service customers, gas is repurchased from the trust at original product cost plus financing costs and trust fees. The cost of gas and related financing are recoverable through the cost of gas charge.
The bank credit agreement provides for a .375% commitment fee on the credit line and interest at prime (8.25% at September 30, 1999) with a fixed-rate interest option at less than prime on the outstanding balance. The trust agreement provides for a management fee of $8,000 annually. The credit agreement between the trust and the bank provides for a total commitment of up to $10.5 million through March 31, 2001.
As of September 30, 1999 and 1998, the gas inventories under the trust agreement and controlled by the Company totaled $8.3 million and $8.7 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 in the accompanying consolidated balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 1999, the Company had $27.7 million available under various unsecured bank lines of credit that are renewed annually, $15.3 million of which was outstanding. The weighted average interest rate on borrowings outstanding on September 30, 1999 was 6.1%. The lines bear interest at prime or less than prime on certain of the lines for fixed periods of time, and are due on demand. For some lines, the terms of the credit agreements require annual commitment fees of .25% of the lines.
Note 5. Long-Term Debt
Interest payments for the First Mortgage Bonds are due semiannually. The First Mortgage Bonds are collateralized by first mortgage liens on substantially all real property and operating plant facilities of the Company's gas utility operations.
The aggregate amounts of principal due for all long-term debt for each of the five years subsequent to September 30, 1999 are as follows (in thousands):
Fiscal year Amount - ----------------------------------------------------------------- 2000 $791 2001 666 2002 563 2003 505 2004 459
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
At September 30, 1999 and 1998, a SFAS No. 109 related regulatory liability amounted to $824,000 and $892,000, respectively, for the tax benefit of unamortized investment tax credits, and $203,000 and $249,000, 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 $2.5 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.
The tax effects of cumulative differences that gave rise to the deferred tax liabilities and deferred tax assets for the years ended September 30, 1999 and 1998 were as follows (in thousands):
1999 1998 - ------------------------------------------------------------- Deferred tax assets: Deferred gas costs $ - $ 1,450 Contributions in aid of construction 794 759 Unamortized investment tax credits 506 545 Allowance for doubtful accounts 429 434 Deferred compensation 367 280 VEBA 175 119 Other 365 886 -------------------- Total deferred tax assets 2,636 4,473 ====================
Deferred tax liabilities: Property-related 19,110 18,035 Environmental costs 2,645 1,455 Other 2,067 2,073 --------------------- Total deferred tax liabilities 23,822 21,563 --------------------- Net deferred tax liability $21,186 $17,090 =====================
Deferred income taxes were classified in the accompanying consolidated balance sheets at September 30, 1999 and 1998 as follows (in thousands):
1999 1998 - ----------------------------------------------------------------------- Current $ (68) $(1,738) Long-term 21,254 18,828 -------------------- Total $21,186 $17,090 ====================
The components of federal and state income taxes reflected in the accompanying consolidated statements of income for the years ended September 30, 1999, 1998 and 1997 were as follows (in thousands):
1999 1998 1997 - ----------------------------------------------------------------------- Federal: Current $ (213) $2,939 $3,649 Deferred 2,983 (265) (383) Investment tax credits (123) (124) (136) ------------------------------ Total federal 2,647 2,550 3,130 ------------------------------
State: Current (196) 601 756 Deferred 771 (49) (78) ------------------------------ Total state 575 552 678 ------------------------------ Total provision for income taxes $3,222 $3,102 $3,808 ==============================
The total federal and state income tax provision, as a percentage of income before federal and state income taxes, was 41.5%, 36.6% and 36.9% for the years ended September 30, 1999, 1998 and 1997, respectively. The significant increase in the effective federal and state income tax rate is due to reorganization costs that are not tax deductible. The following table reconciles the income tax provision calculated using the federal statutory tax rate of 34% to the book provision for federal and state income taxes (in thousands):
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 nonqualified 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.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits to qualified retired employees.
The expense recorded in fiscal 1999, 1998 and 1997 for providing postretirement benefits, including amortization of the accumulated projected benefit obligation over a 20-year period, was $413,000, $486,000 and $542,000, 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.
The prior service cost is amortized on a straight-line basis over the average remaining service period for active participants. The gain or loss in excess of the greater of 10% of the benefit obligation or the market value of assets is amortized on a straight-line basis over the average remaining service period for active participants.
Assumed Health Care Cost Trend
For measurement purposes, an 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 1999. The rate is assumed to decrease gradually to 5% for 2002 and remain at that level thereafter. For 1999, the annual rate of increase for age post 65 was changed to 10% , decreasing gradually to 5% for 2004 and thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one-percentage- point change in assumed health care costs trend rates would have the following effects for 1999:
One percentage One percentage point increase point decrease ------------------------------- Total of service and interest cost components $ 18,913 $ (17,309) Postretirement benefit obligation 188,473 (174,449)
The Company has employee 401(k) savings and investment plans covering substantially all employees. The Company made contributions of $263,000, $254,000 and $242,000 for the years ended September 30, 1999, 1998 and 1997, respectively.
The Company is a participating employer in a defined contribution profit sharing plan and trust covering certain employees who meet specific age and service requirements. No profit sharing contributions were made to the plan in 1999. The plan includes a salary reduction provision with a matching discretionary employer contribution. The company contributed $34,000 in 1999.
The Company is also a contributing employer to various area-wide, union-negotiated, multi-employer defined pension plans covering certain employees by craft. Contributions totaled $551,000 in 1999.
Note 9. Stock Option Plan
During fiscal year 1999, the EnergyNorth, Inc. 1998 Stock Option Plan (Plan) was adopted. The Plan provides for grants of either incentive stock options or nonqualified stock options to purchase shares of the Company's common stock. Stock options may be granted to officers, directors and key employees responsible for the direction and management of the Company. At September 30, 1999, 200,000 shares of common stock were reserved for issuance under the Plan. Information related to stock options during 1999 is as follows:
Number Option exercise of shares price per share Total price - ----------------------------------------------------------------------------- Shares under option at 9/30/98 - $ - $ - Granted 44,000 28.00 1,232,000 Exercised - - - Forfeited - - - ----------------------------------------- Shares under option at 9/30/99 44,000 $28.00 $1,232,000 =========================================
Outstanding options were incentive options and non-qualified options. No compensation expense related to stock option grants was recorded in 1999 as the option exercise prices were equal to fair market value on the date of grant.
Pro forma information regarding net income and earnings per share is required by SFAS No. 123, "Accounting for Stock-Based Compensation," and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted average assumptions for 1999:
- ---------------------------------------------------------------- Risk-free interest rate 4.45% Dividend yield 3.30% Volatility factor .2353 Weighted average expected life 4 years
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting periods. The Company's pro forma net earnings (in thousands) and earnings per share were as follows:
- ---------------------------------------------------------------- Net earnings - as reported $4,537 Net earnings - pro forma 4,504 Earnings per share - as reported 1.37 Earnings per share - pro forma 1.36 Weighted average fair value of options 5.04 granted during the year
Because the statement provides for pro forma amounts for options granted beginning in 1999, the pro forma expense will likely increase in future years as new option grants become subject to the pricing model.
Note 10. Acquisition
In May 1998, the Company acquired Northern Peabody, Inc. (NPI) and Granite State Plumbing and Heating, Inc. (GSPH). Both NPI and GSPH are mechanical contractors engaged in the design, construction and service of plumbing, heating, ventilation, air conditioning and process piping systems in northern New England. They became wholly owned subsidiaries of ENI Mechanicals, Inc., a subsidiary of the Company. For financial statement purposes, the acquisition was recorded
as a purchase. Accordingly, the results of operations of NPI and GSPH are included in the accompanying consolidated financial statements since May 1, 1998.
Note 11. Operating Leases
The Company leases certain facilities and equipment under long- term, noncancelable operating lease agreements having terms greater than one year. Future minimum rental commitments for these leases, at September 30, 1999, are approximated as follows (in thousands):
Fiscal year Amount - ----------------------------------------------------------------- 2000 $322 2001 257 2002 223 2003 95 2004 9
The total rental expense charged to operations for the years ended September 30, 1999, 1998 and 1997 was approximately $611,000, $557,000 and $574,000, respectively.
Note 12. 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 cost of gas rates. These contracts expire at various times from 1999 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, own or owned several facilities at which manufactured gas plants (MGP) operated. MGPs were used to manufacture gas prior to the introduction of natural gas to the Company's service area. Generally, MGPs operated from the late 1800s to the early 1950s. The MGPs produced wastes and by-products that may be considered contaminated or hazardous under current law, and some of which may still be present at such facilities. Relevant environmental laws can be used by the state and federal government to hold the Company strictly liable for the costs of studying and remedying discarded by-products from MGPs owned and operated by its predecessors. The Company accrues environmental investigation and cleanup costs with respect to former MGPs and other environmental matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
The New Hampshire Department of Environmental Services (NHDES) has required the Company to undertake remedial investigation and/or remedial action at MGPs located in Concord, Laconia, Nashua, and Dover, New Hampshire. At each MGP, the Company is responding to the NHDES's requirements as described below.
In September 1992, the NHDES required the Company to undertake a remedial investigation of the former MGP in Concord, New Hampshire. Study and remediation associated with the Concord MGP is ongoing. The estimated cost to complete this remedial action ranges from $690,000 to $1.6 million, and the Company has recorded $690,000 at September 30, 1999 in deferred charges. The Company received an order from the Commission approving recovery from customers, over a seven-year period, of substantially all costs, excluding carrying costs, incurred for the Concord MGP. The total unamortized balance for the Concord site, including the gas holder site, was $4.4 million as of September 30, 1999.
At the direction of the NHDES, the Company and Public Service Company of New Hampshire (PSNH), an electric utility company, conducted a remedial investigation of a former MGP in Laconia, New Hampshire, and in January 1999 prepared a Remedial Action Plan for that site. Without admitting any liability, on September 3, 1999, the Company entered into a Site Responsibilities and Indemnity Agreement (SRIA) with PSNH. Pursuant to the SRIA, the Company will pay $4.2 million to PSNH over a twenty-four (24) month period. In exchange, PSNH will assume responsibility for all future site study and remediation, and PSNH will indemnify the Company against such costs. The Company's legal liability under state and federal laws is unaffected by the SRIA. Through September 30, 1999, the Company has paid $1 million under the SRIA. The estimated costs associated with work undertaken prior to the SRIA ranges from $117,000 to $517,000, and the Company has recorded $3.3 million in deferred charges at September 30, 1999.
During 1998, the Company and PSNH received Notice of Potential Responsibility from the Environmental Protection Agency (EPA) for the so-called Nashua River Asbestos Site. The EPA contends that wastes released from the former MGP in Nashua, New Hampshire are commingled with asbestos wastes from a former Johns Manville facility located adjacent to the former MGP. The Company's share of costs to complete the disposal of contaminants that are the subject of EPA claims are estimated to range from $375,000 to $450,000. The Company and PSNH subsequently received a notice from the NHDES requiring the investigation of the former MGP site in Nashua. The Company estimates the cost of site investigation and characterization at the Nashua MGP to range from $250,000 to $325,000. The Company recorded $625,000 in deferred charges at September 30, 1999.
In April 1999, the Company received notice from the NHDES to investigate the former MGP site in Dover, New Hampshire. PSNH and another utility company, Northern Utilities, received similar notices concerning the Dover MGP from the NHDES. The Company estimates its cost of that investigation and characterization to range from $200,000 to $400,000. The Company has recorded $200,000 in deferred charges at September 30, 1999.
The Commission has approved a generic recovery mechanism for costs incurred at all MGP sites, except recovery for the Concord site noted above, which provides for a seven-year recovery period of substantially all costs, excluding carrying costs. The recovery mechanism provides that the environmental surcharge to customers will not exceed 5% of total gross gas revenues in any given year but that amounts in excess of 5% will be deferred to future periods with recovery of applicable carrying costs.
The Company intends to pursue insurance recovery as well as recovery from other responsible parties to ensure that such third parties contribute appropriately to reimburse the Company for any costs incurred with respect to environmental matters. All recoveries serve to reduce the seven-year environmental surcharge period to customers. The Company has instituted suits in the United States Federal District Court for New Hampshire and in New Hampshire superior courts against one third party, as well as the Company's insurers and insurers of its predecessors to recover the costs of investigation and remediation of the Concord, Nashua, Dover and Laconia MGP sites. In each litigation, the Company is seeking declaratory judgment that its insurers owe the Company a defense and/or indemnification for environmental claims associated with each respective MGP. Through September 30, 1999 the Company has recovered a total of $4.3 million in settlement of third-party MGP litigation.
Note 13. Merger
On July 14, 1999, the Company and Eastern Enterprises (Eastern), a Massachusetts business trust, entered into an Agreement and Plan of Reorganization (Agreement) which provides for the merger of the Company with a subsidiary of Eastern, as a result of which the Company's subsidiaries would become wholly owned subsidiaries of Eastern. On November 4, 1999, Eastern entered into an agreement to merge with KeySpan Corporation and, as a result, the Company and Eastern amended the Agreement. Under the amended Agreement, holders of outstanding shares of the Company's common stock will be paid entirely in cash and the closing will take place simultaneously with the Eastern merger with KeySpan Corporation. If the Eastern/KeySpan Corporation merger is not completed, the Company and Eastern would nonetheless merge, and holders of outstanding shares of the Company's common stock can elect to receive cash, Eastern common stock or a combination of cash and stock as set forth in the Agreement. Completion of the merger is subject to approval by the Company's stockholders and receipt of satisfactory regulatory approvals, including approval by the Commission and the Securities and Exchange Commission. Reorganization costs incurred as a result of the impending merger were $1.2 million in 1999.
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, 1999 and 1998, 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, 1999. 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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1999, 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.
ARTHUR ANDERSEN LLP Boston, Massachusetts November 5, 1999
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, 1999.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors of the Registrant
The directors and executive officers who are directors of the Registrant are listed below, together with position, age at December 31, 1999, business experience, and other information as to each.
(1) Mr. Borer is a director of Philadelphia Corporation for Investment Services and Chester Valley Bancorp Inc., a NASDAQ traded company. Chester Valley Bancorp, Inc. is a 100% owner of Philedelphia Corporation for Investment Services. (2) Mr. Leitz is a director of the Wyman-Gordon Company.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires that each director and certain officers of the Company file reports of initial beneficial ownership and changes in beneficial ownership of the Company's common stock with the Securities and Exchange Commission. To the Company's knowledge, during 1999, all directors and officers filed all such required notices except that Mr. Margossian, a former Senior Vice President, filed a Form 5 with respect to the acquisition of 200 shares four days late.
ITEM 11. EXECUTIVE COMPENSATION
Compensation of the Directors
The Chairman of the Board of Directors receives an annual retainer of $40,000 and the Vice Chairman receives an annual retainer of $20,000. All other directors receive annual retainers of $10,500. Committee chairmen receive additional annual retainers of $2,500. Incentive compensation in the amount of 100 shares of the Company's $1.00 par value Common Stock is awarded to each director annually, provided that the Company has achieved certain fiscal year earnings and shareholder return objectives. The Chairman and directors receive fees of $750 for each board meeting attended and $650 for each committee meeting attended. The Vice Chairman and committee chairmen receive fees of $750 for each board and committee meeting attended. Multiple meetings of the board of directors held on the day of the annual meeting of the board of directors are considered one meeting. Directors who are employees receive no annual retainers, director incentive compensation, or meeting fees.
Directors may elect to have portions of their retainers and fees credited each year to a deferred compensation account pursuant to a plan that provides for accrual of interest and distribution of the deferral accounts in lump sum amounts or in equal installments over ten years, at the option of each director, beginning on a date designated by the director.
In fiscal 1999, each non-employee director was granted an option to purchase 1,000 shares of the Company's Common Stock in accordance with the 1998 Stock Option Plan.
Executive Compensation
The following Summary Compensation Table shows compensation paid by the Company for services rendered in all capacities during the fiscal years ended September 30, 1999, 1998 and 1997 to the Chief Executive Officer and the four other executive officers of the Company whose salary and cash incentive and bonus award for the 1999 fiscal year exceeded $100,000.
(1) Includes amounts earned and deferred without election by the officer and amounts deferred pursuant to Deferred Compensation Agreements and the Company's 401(k) plan. (2) There are no shares of restricted stock holdings of the above- named officers as of September 30, 1999. (3) All other compensation paid in 1999 includes: Employer contributions to the Company's 401(k) plan for Mr. Giordano ($5,063), Ms. Chicoine ($5,287), Mr. Childs ($6,213), Mr. Margossian ($5,187), and Mr. Skrzysowski ($4,438); value of term life insurance premiums paid for Mr. Giordano ($2,400), Ms. Chicoine ($2,400), Mr. Childs ($2,356), Mr. Margossian ($2,185), and Mr. Skrzysowski ($1,625); portion of interest earned in a deferred compensation account by Mr. Giordano in excess of 120% of federal long-term rate ($10,791). (4) Includes cash and stock incentive awards. (5) Includes an award of 1,350 shares of restricted stock that are subject to forfeiture and nontransferability until July 16, 2000 for Mr. Giordano ($36,197) and cash bonus award for Ms. Chicoine ($10,000), Mr. Childs ($20,000) and Mr. Margossian ($5,000) for 1998 acquisition activities. (6) Mr. Margossian joined the Company on September 29, 1997 and resigned on November 19, 1999.
Other Compensation Arrangements
Stock Options
In November 1998, the Company adopted the EnergyNorth, Inc. 1998 Stock Option Plan (Plan) to provide for grants of options to officers, directors and key employees to purchase common stock of the Company. The maximum exercise period for any option is ten years.
Options granted under the Plan have been entirely incentive stock options with the exception of options granted to directors. The option price per share for options granted under the Plan was determined at 100% of the fair market value of the average closing price for the common stock, as reported on the New York Stock Exchange, during the ten trading days immediately preceding the date of grant. All options that have been granted under the Plan become exercisable over a four-year period beginning in 1999, except for options granted to Mr. Giordano, which become exercisable over five years.
The following table sets forth certain information regarding stock options granted under the Plan during the fiscal year ended September 30, 1999.
The following table provides information with respect to options to purchase shares of the Company's common stock exercised in fiscal 1999 and the value of unexercised options granted during the fiscal year under the Plan to the named executive officers in the Summary Compensation Table and all directors as a group and held by them as of September 30, 1999. The Company has no compensation plan under which SARs are granted.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
(1) Represents the difference between the exercise price of the options and the closing price of $41.50 for the Company's common stock as quoted by the New York Stock Exchange on September 30, 1999 times the number of options held.
Noncontributory Retirement Plan
The following Pension Plan table sets forth estimated combined annual benefits payable under the Company's Retirement Plan and Supplemental Executive Retirement Plan (SERP) at age 65 to persons in specified compensation and years of service classifications. The combined annual benefits shown in the table do not reflect offsets for benefits of Social Security and for retirement benefits received from other employers.
PENSION PLAN TABLE
- ---------------------------------------------------------------------- Average annual earnings 15 years of 25 years of 35 years of during highest five years service service service - ---------------------------------------------------------------------- $125,000 $ 93,750 $ 93,750 $ 93,750 150,000 112,500 112,500 112,500 175,000 131,250 131,250 131,250 200,000 150,000 150,000 150,000 250,000 187,500 187,500 187,500 300,000 225,000 225,000 225,000 350,000 262,500 262,500 262,500 400,000 300,000 300,000 300,000
All full-time salaried employees, including officers and certain part- time employees, are eligible to participate in the Company's Retirement Plan, provided an employee has reached the age of 21 and has completed one year of service. The SERP is a noncontributory plan intended to supplement benefits of the Retirement Plan for certain named executive officers, effective January 1, 1985. Under both plans normal retirement is at age 65 with a provision for early retirement. Benefits under the Retirement Plan vest after five years of service and under the SERP vest after ten years of service. Earnings under the plans for the executive officers named in the Summary Compensation Table consist of regular annual compensation, excluding bonuses or severance pay, and are the same, except for bonuses and "Other", as the Annual Compensation and Long-Term Compensation shown in the
Summary Compensation Table. Mr. Giordano has 34 credited years of service under the plans, Ms. Chicoine 9 years, Mr. Childs 4 years, Mr. Margossian 2 years and Mr. Skrzysowski 22 years.
Funding of the Retirement Plan is based on actuarial computations and results in a pool of assets held in trust that is unallocated with respect to any particular individual. Benefits payable under the Retirement Plan are calculated on the basis of straight life annuity amounts, accrued over a 25-year period and are not subject to any deduction for Social Security Benefits or other offset.
Benefits under the SERP are unfunded, accrue over a 15-year period and once they are fully vested do not vary with years of service, except that SERP participants who are included in the plan after September 30, 1995 will have benefits reduced if they retire prior to the normal retirement date under the Retirement Plan. For an individual retiring at age 65, benefits are calculated on the basis of 75% of the average of the five highest consecutive years' earnings, less any amounts receivable for benefits of Social Security, the Retirement Plan, and other qualified plans of the Company and other employers.
Employment Agreements
The Company has employment agreements with Mr. Giordano and Ms. Chicoine under which the Company has agreed to employ Mr. Giordano through March 31, 2003 and Ms. Chicoine for a two-year period, which may be extended annually for an additional year. If the Company terminates the employment of either of these individuals other than for breach of the agreement or misconduct, it is required to continue salary payments including average or target incentive compensation, deferred compensation and amounts the employee has elected to defer, through the term of the agreement. Such termination payments will not be made following any termination of employment that gives rise to payments under the management continuity agreements described below.
Management Continuity Agreements
The Company has Management Continuity Agreements (Continuity Agreements) with Mr. Giordano, Ms. Chicoine, Messrs. Childs, Margossian, and Skrzysowski. Mr. Margossian terminated his employment, and his rights under his continuity agreement terminated on November 19, 1999. The Continuity Agreements provide that in the event of termination of employment or a reduction in compensation, position or other conditions of employment within a specified period following a Change in Control of the Company, as defined in the Continuity Agreements, or termination by the employee for Good Reason, as defined in the Continuity Agreements, following a Change in Control, the Company shall pay to the employee a lump-sum severance benefit and certain other benefits. The severance benefit payable to Mr. Giordano and Ms. Chicoine is three times his or her annual salary and incentive and deferred compensation, a prorated incentive payment for the year in which termination occurs, continuation of benefits or a payment equal to the present value of those benefits and, for Mr. Giordano, the present value of the additional amount he would have received under the Retirement Plan and the SERP if he had continued to be employed for three years from termination. In addition, the Company is required to make additional payments to Mr. Giordano and Ms. Chicoine sufficient on an after-tax basis to satisfy any tax liability incurred under the "parachute" tax rules of the Internal Revenue Code. The severance benefit payable to Mr. Childs is 2.95 times his annual salary
and incentive and deferred compensation. The severance benefit payable to Mr. Skrzysowski is the greater of two times his annual salary or 2.75 times his five-year average taxable compensation. In each continuity agreement, except for Mr. Giordano's and Ms. Chicoine's, no severance benefits are paid to the extent that such benefits, aggregated with other benefits paid to the employee, constitute "excess parachute payments" within the meaning of Section 280G of the Internal Revenue Code.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information regarding beneficial ownership of the Company's $1.00 par value Common Stock, its only class of securities, by each director and certain executive officers (Messrs. Childs, Margossian and Skrzysowski), and all directors and executive officers as a group, as of October 8, 1999. No person is known to the Company to own more than 5% of the Company's stock.
PRINCIPAL STOCKHOLDERS
- -------------------------------------------------------------------------------- Number of shares Percentage of Name of individual beneficially owned (6) common stock - -------------------------------------------------------------------------------- Roger C. Avery (1) 34,727 1.046 Edward T. Borer (2) 15,539 * Michelle L. Chicoine 5,371 * Frank L. Childs 2,592 * Richard B. Couser 656 * Joan P. Cudhea (3) 14,302 * Sylvio L. Dupuis 1,295 * Robert R. Giordano (4) 21,267 * Constance B. Girard-diCarlo 597 * Andrew E. Lietz 1,352 * Kenneth M. Margossian 1,551 * N. George Mattaini (5) 11,812 * David A. Skrzysowski 1,720 * John E. Tulley II 800 * All directors and executive officers as a group (14 in number at October 8, 1999) 113,581 3.421 _______________ * Less than 1%.
(1) Includes 12,879 shares held by Mr. Avery solely in a fiduciary capacity and in which he disclaims beneficial ownership. (2) Includes 963 shares held by Mr. Borer's spouse, in which he disclaims beneficial ownership. (3) Includes 1,690 shares held by Ms. Cudhea's daughter-in-law, in which she disclaims beneficial ownership and over which she shares investment power only. (4) Includes 430 shares held by Mr. Giordano's spouse, in which he disclaims beneficial ownership. (5) Includes 7,404 shares held by Mr. Mattaini's spouse, in which he disclaims beneficial ownership. (6) Beneficial ownership includes shares that the following persons have a right to acquire upon exercise of options: Mr. Giordano, 3,571; Ms. Chicoine, 2,500; Mr. Childs, 1,250; Mr. Margossian, 1,250; and each director who is not also an employee, 250.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
There are no relationships or related transactions that require disclosure.
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:
Item 8: Page No(s). in this Report -------------- Consolidated Statements of Income for the years ended September 30, 1999, 1998 and 1997 21 Consolidated Balance Sheets at September 30, 1999 and 1998 22 Consolidated Statements of Capitalization at September 30, 1999 and 1998 23 Consolidated Statements of Common Stockholders' Equity for the years ended September 30, 1999, 1998 and 1997 24 Consolidated Statements of Cash Flows for the years ended September 30, 1999, 1998 and 1997 25 Notes to Consolidated Financial Statements 26-41 Report of Independent Public Accountants 42
(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. Number Description in this Report -------- ----------- --------------
II Consolidated Valuation and Qualifying Accounts for the three years ended September 30, 1999 54
Report of Independent Public Accountants 42
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 56 through 59.
(b) Reports on Form 8-K
A current report on Form 8-K reporting the occurrence of an event covered by Item 5 was filed on July 20, 1999 by the Company regarding the Company's plan to merge with Eastern Enterprises.
(c) Exhibits - See Exhibit Index on pages 56 through 59.
(d) Financial Statement Schedules
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGYNORTH, INC.
Date: December 17, 1999 by: /s/ Robert R. Giordano ---------------------- Robert R. Giordano President and 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 17, 1999.
/s/ Robert R. Giordano Director, President and - ------------------------ Chief Executive Officer Robert R. Giordano (principal executive officer)
/s/ Frank L. Childs Senior Vice President and - ------------------------ Chief Financial Officer Frank L. Childs (principal financial officer)
/s/ David A. Skrzysowski Vice President and Controller - ------------------------ (principal accounting officer) David A. Skrzysowski
/s/ Edward T. Borer Director - ------------------------ Edward T. Borer
/s/ N. George Mattaini Director - ------------------------ N. George Mattaini
/s/ Michelle L. Chicoine Director - ------------------------ Michelle L. Chicoine
/s/ Richard B. Couser Director - ------------------------ Richard B. Couser
/s/ Sylvio L. Dupuis Director - ------------------------ Sylvio L. Dupuis
EXHIBIT INDEX
The exhibits listed below are filed herewith, or are incorporated herein by reference to other filings.
Exhibit Number Description - ------- -----------
2.0 Agreement and Plan of Reorganization dated July 14, 1999 among Eastern Enterprises, EE Acquisition Company, and EnergyNorth, Inc. Schedules described in the Agreement will be furnished supplementally to the SEC upon request.
2.1 Amendment No. 1 to Agreement and Plan of Reorganization, dated November 4, 1999.
3.1 Articles of Incorporation of EnergyNorth, Inc. are incorporated by reference to Exhibit 3.1 to EnergyNorth, Inc.'s Quarterly Report on Form 10-Q (File No. 1-11441) for the quarter ended March 31, 1996.
3.2 By-Laws of EnergyNorth, Inc., as amended, 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 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1989.
4.2 Third Supplemental Indenture, dated as of September 1, 1990, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1990.
4.3 Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.3 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1992.
4.4 Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the fiscal year ended September 30, 1996.
4.5 Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987, is incorporated by reference to Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s Amendment No. 1 to Registration Statement on Form S-1, No. 333-32949, dated September 10, 1997.
4.6 Copies of credit agreements defining the rights of holders of long-term debt of certain subsidiaries of EnergyNorth, Inc., under which the amounts of the debt issued do not exceed 10% of the consolidated assets of EnergyNorth, Inc., will be furnished to the Securities and Exchange Commission upon request.
4.7 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.
4.8 Amendment to Rights Agreement (undated - 1999).
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 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.3 Contract Restructuring Letter Agreement between Tennessee Gas Pipeline Company and EnergyNorth Natural Gas, Inc. effective November 1, 1999.
10.4 Supplemental Executive Retirement Plan of EnergyNorth, Inc., as amended, is incorporated by reference to Exhibit 10.3 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the fiscal year ended September 30, 1996.
10.5 Deferred Compensation Agreement, dated as of October 1, 1997, between Robert R. Giordano and the Registrant is incorporated by reference to Exhibit 10.4 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for fiscal year ended September 30, 1997.
10.6 Deferred Compensation Agreement, dated as of October 1, 1997, between Richard P. Demers and the Registrant is incorporated by reference to Exhibit 10.7 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for fiscal year ended September 30, 1997.
10.7 Deferred Compensation Agreement, dated as of October 1, 1997, between Frank L. Childs and the Registrant is incorporated by reference to Exhibit 10.8 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for fiscal year ended September 30, 1997.
10.8 Deferred Compensation Agreement, dated as of October 1, 1997, between Michelle L. Chicoine and the Registrant is incorporated by reference to Exhibit 10.9 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for fiscal year ended September 30, 1997.
10.9 EnergyNorth, Inc. 1992 Directors' Deferred Compensation Plan, as amended is incorporated by reference to Exhibit 10.10 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for fiscal year ended September 30, 1997.
10.10 Amended and Restated Employment Agreement, dated as of July 14, 1999, between Robert R. Giordano and the Registrant.
10.11 Amended and Restated Employment Agreement, dated as of July 14, 1999, between Michelle L. Chicoine and the Registrant.
10.12 Amended and Restated Management Continuity Agreement, dated as of July 14, 1999, between Robert R. Giordano and the Registrant.
10.13 Amended and Restated Management Continuity Agreement, dated as of July 14, 1999, between Michelle L. Chicoine and the Registrant.
10.14 Management Continuity Agreement, dated as of December 2, 1996, between Frank L. Childs and the Registrant is incorporated by reference to Exhibit 10.19 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the fiscal year ended September 30, 1996.
10.15 Management Continuity Agreement, dated as of December 12, 1995, between David A. Skrzysowski and the Registrant.
10.16 Consulting Agreement, dated as of July 1999, among EnergyNorth, Inc., Eastern Enterprises, and Robert R. Giordano.
10.17 Employment and Related Matters Agreement, dated July 14, 1999, between Eastern Enterprises and Robert R. Giordano.
10.18 EnergyNorth, Inc. Key Employee Performance and Equity Incentive Plan, as amended, is incorporated by reference to Exhibit 10.15 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended September 30, 1995.
10.19 EnergyNorth, Inc. Directors' Incentive Compensation Plan is incorporated by reference to Exhibit 10 to EnergyNorth Inc.'s Quarterly Report on Form 10-Q (File No. 1-11441) for the quarter ended March 31, 1997.
10.20 EnergyNorth, Inc. 1998 Stock Option Plan is incorporated by reference to Exhibit 10.18 to EnergyNorth, Inc.'s Annual Report on Form 10-K (File No. 1-11441) for the year ended September 30, 1998.
21 Subsidiaries of the Registrant is incorporated by reference to Exhibit 21 to EnergyNorth, Inc.'s Annual Report on Form 10-K (File No. 1-11441) for the year ended September 30, 1998.
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.