ITEM 1. BUSINESS
THE COMPANY
Bay State Gas Company ("Bay State" or the "Company") was incorporated in 1974 as a Massachusetts corporation. However, Bay State's predecessor companies' operations began in 1847, and consecutive quarterly dividends have been paid by these entities or Bay State since 1853. The Company is primarily a gas distribution utility that provides local transportation service in the Brockton, Lawrence, and Springfield, Massachusetts areas. Additionally, the Company also offers additional energy products and services to its customers, including commodity sales of natural gas, and invests in energy ventures. Approximately 95% of all revenues are generated from providing local transportation and natural gas sales with 84% of these annual revenues coming from the Company's Massachusetts service area. Bay State has five subsidiaries within its corporate organization. Northern Utilities, Inc. ("Northern") is a gas distribution utility operating in the Portland and Lewiston areas in Maine and the Portsmouth area in New Hampshire. Granite State Gas Transmission, Inc. ("Granite") is an interstate gas transmission and supply company operating in the states of Maine, New Hampshire, Massachusetts, and Vermont. Granite has four wholly owned subsidiaries, Bay State Energy Development, Inc., which owns an equity interest in the MASSPOWER cogeneration partnership, Natural Gas Development Corp., a corporation established to invest in the Portland Natural Gas Transmission System ("PNGTS"), a proposed natural gas transmission pipeline in northern New England, Bay State Energy Enterprises, Inc., which owns a equity interest in KBC Energy Services, a partnership which markets natural gas supplies and energy-related services on a nonregulated basis to commercial and industrial end-users and Energy Asset Funding Inc., a corporation established to provide financing for energy-related equipment.
Natural gas sales in New England are seasonal, and the Company's results of operations reflect this seasonality. Accordingly, results of operations are typically most favorable in the second quarter of the Company's fiscal year (three months ended March 31), with results of operations being next most favorable in the first quarter, while losses are commonly incurred in the third and fourth quarters. The quarterly operating results for 1995 and 1994 are described further in Note 9 of "Notes to Consolidated Financial Statements," Part II, Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Company's customers generally are billed monthly on a cycle basis in therms. One therm equals 100,000 British thermal units (1 Btu), the heat content of approximately 100 cubic feet of gas. 1,000,000 Btu (1 MMBtu), or ten therms are the energy equivalent of approximately 1,000 cubic feet of natural gas or 7.14 gallons of home heating oil.
LOCAL TRANSPORTATION MARKETS AND COMPETITION
In 1995, 97% of Bay State's customers purchased bundled local transportation and natural gas and the remaining 3% elected to purchase unbundled local transportation. The tables below show the net change in transportation customers and throughput volumes for the past three years.
The Company's principal competitors are unregulated fuel-oil retailers and regulated electric utilities. Increases in demand for natural gas are primarily driven by the rate of economic growth and new construction within the Company's service territories, and by the marketing and pricing of competing fuels.
In the residential market, the Company should continue to benefit from the New England region's market and growth potential. There are approximately 150,000 households along the Company's mains and additional homes located short distances from existing gas mains that use no gas at all. In addition, the Company anticipates additional growth from the estimated 44,000 existing residential nonheating customers. These are attractive markets for the Company and represent an opportunity to increase gas sales with little or no capital investment.
For commercial and industrial customers, environmental issues are an important issue in choosing an energy source. Since natural gas is the cleanest burning fossil fuel, using natural gas can assist companies in complying with the Clean Air Act and underground oil storage tank legislation.
Finally, the Company markets gas to large users on a seasonal or interruptible basis. Approximately 59% of these interruptible volumes in 1995 were sold to five electric utilities for electric power generation. The remainder were sold to approximately 110 industrial customers equipped to burn either natural gas or fuel oil. Price is the key competitive factor in this market, and the Company pursues interruptible sales through a flexible pricing structure designed to remain competitive with other fuels. Substantially all net margins from interruptible sales are passed back to firm customers through cost of gas adjustment clauses (see "Rates and Regulations").
NATURAL GAS SALES
The natural gas sales portion of the Company's bundled service does not currently provide a profit margin. However, as all but 85 of the Company's 287,000 local transportation customers purchase bundled transportation and natural gas, minimizing gas costs is an important part of the Company's business.
The Company's strategy of balancing gas purchase costs and security of supply is achieved by optimizing the mix and terms of natural gas contracts with the use of supplemental liquefied natural gas and propane to meet peak winter demand. The Company maintains a diversified gas supply portfolio of domestic and Canadian gas supply contracts with producers.
CAPACITY REQUIREMENTS
Bay State has capacity contracts for the transmission of natural gas to its distribution system from the producing areas of North America. The Company currently transports natural gas from Canada through a converted oil pipeline leased from the Portland Pipe Line Corporation ("PPLC"). The PPLC lease currently extends to March 31, 1997. An agreement with PPLC to extend the lease through the 1997-1998 heating season is being sought. Short-term contingency plans have been developed for supplying customers in Maine and New Hampshire through the 1997-1998 heating season in the event that the lease is not extended. Long-term, two projects to replace the pipeline capacity provided by the PPLC lease are being pursued, a 2.0 million MMBtu liquefied natural gas storage facility in Wells, Maine, and PNGTS. For further discussion of these
projects see Note 8 of "Notes to Consolidated Financial Statements," Part II, Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REGULATION AND RATES
The Company and its subsidiaries, are subject, where applicable, to regulation by the Massachusetts Department of Public Utilities ("MADPU"), the New Hampshire Public Utilities Commission ("NHPUC"), the Maine Public Utilities Commission ("MPUC") and the Federal Energy Regulatory Commission ("FERC") with respect to rates, adequacy of service, issuance of securities, accounting, and other matters.
The tariff schedules of the local distribution companies provide for declining block rates which result in reductions in the unit price as usage increases, and for seasonal rates that charge customers more per unit for gas purchased during the high-demand winter heating season and less per unit during summer months. These schedules also contain cost of gas adjustment ("CGA") clauses that permit the distribution companies to pass on to firm customers increases or decreases in recovered natural gas costs. Substantially all gas supplier refunds and profits from interruptible sales are returned to firm customers through the CGA clauses.
As a result of a third party fuel inventory financing program instituted by the Company in 1982, fuel inventory and the related administrative and carrying costs are also recovered through the CGA clauses. In addition, the MADPU allows recovery of the following through the CGA: 1) the working capital costs associated with purchased gas costs; 2) clean-up costs associated with waste materials from former gas manufacturing sites; and 3) costs associated with MDPU-approved energy conservation and load management programs.
The Company offers special contracts to large volume industrial customers in its Massachusetts service area and natural gas transportation service to industrial end-user customers in both its Massachusetts and New Hampshire jurisdictions. Contracts for such service are individually filed with and approved by the MADPU and NHPUC and are in effect for specified periods of time.
The following table provides the most recent rate activity of the Company by state and federal jurisdictions:
FRANCHISES
The utility franchise rights of the Company are non-exclusive. Competition from other companies in the distribution of gas, however, is restricted without prior approval of the applicable local and state governmental agencies.
The laws of the Commonwealth of Massachusetts permit a municipality, by appropriate vote of its residents, to enter the gas business and purchase the facilities of the utility serving such municipality. If the utility is not willing to sell, the municipality may construct a plant or acquire one from another source. The Company is not aware of any municipality which intends to seek approval of such action.
OTHER ENERGY PRODUCTS AND SERVICES
For a discussion of Other Energy Products and Services see "Other Energy Products and Services" in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
ENERGY VENTURES
For a discussion of Income (Loss) from Investments in Energy Ventures, see "Income (Loss) from Investments in Energy Ventures" in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
EMPLOYEES
The Company employed 1,062 persons at September 30, 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of the principal executive officers of the Registrant as of November 15, 1995 are listed below along with their business experience during the past five years. All principal executive officers are elected annually by the Board of Directors at the Directors' first meeting following the annual meeting of shareholders. There are no family relationships among these officers, except as noted below, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was selected.
ITEM 2.
ITEM 2. PROPERTIES
The Company holds franchise rights to lay gas mains in the streets and public places of various service territories in Massachusetts, Maine, and New Hampshire.
As of September 30, 1995, the Company's system consisted of approximately 5,306 miles of distribution mains; 132 miles of transmission lines, with requisite accessory pumping and regulating stations; LNG liquefaction, vaporization and storage facilities; propane storage tanks; 259,185 services (small pipe connecting mains with piping on the customers' premises) and 287,213 meters installed on customers' premises.
The Company also leases a transmission line which is 166 miles in length running from the Canadian border through Vermont and New Hampshire and terminating in South Portland, Maine (see Item 1. Business, "Capacity Requirements").
The transmission and distribution system is for the most part located on or under public streets, alleys, avenues, and other public places or on private property not owned by the Company, with the permission or consent of the respective owners.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is working with federal and state environmental agencies to assess the extent and environmental impact of and appropriate remedial action for waste materials from former gas manufacturing sites (see Note 8 of "Notes to the Consolidated Financial Statements," Part II, Item 8, Financial Statements and Supplementary Data).
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders through solicitation of proxies or otherwise.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Company is listed on both the New York Stock Exchange and the Boston Stock Exchange. The ticker symbol is "BGC" and common listings in the financial press include "BayStGas" and "BaySGs." As of November 15, 1995, the Company had approximately 11,336 shareholders of record. The number of shareholders indicated does not reflect the number of persons or entities who hold their common stock in nominee name through various brokerage firms or other entities. Information regarding cash dividends declared on common stock is included in Note 9 of "Notes to the Consolidated Financial Statements," Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Listed below is the required selected financial data for the Company's last five fiscal years.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Year In Review
During 1995, Bay State Gas Company ("Bay State" or the "Company") continued to respond to the changing energy industry while experiencing warmer than normal weather. During 1995, the weather was 11% warmer than the prior year and 6% warmer than normal within the Company's service territories. The following table displays the degree days for the past three years:
Bay State responded to the warmer weather by implementing several cost saving and service-related program improvements that not only minimized the impact of the weather on net income for 1995, but will also positively impact earnings in future years.
Net income was $23.1 million in 1995 compared to $24.5 million in 1994, and earnings per share were $1.71. This compares to $1.85 one year ago. The common stock dividends declared in 1995 were $1.48 per share, 2.8% higher than the prior year. This was the twelfth consecutive year of increased common stock dividends, and it completes the 142nd year of consecutive quarterly dividends. The current annualized dividend is equivalent to $1.50 per share.
Local Transportation
The majority of Bay State's customers purchase bundled local transportation and natural gas. Some larger commercial and industrial customers have elected to purchase unbundled local transportation, requiring them to now manage their own gas purchasing, balancing, and storage functions.
Local transportation revenues decreased 3.6% from 1994 to 1995. This decrease in revenues was primarily attributable to the warmer weather experienced in the Company's service territories during 1995, which reduced transportation, or throughput, to firm customers. The 11% change in weather from year to year would have resulted in a $7.1 million decrease in transportation revenues. However, the Company added almost 6,500 customers in 1995, up from 4,800 and 5,800 in 1994 and 1993, respectively. This 2.3% growth in the customer base somewhat offset the negative impact of the weather on revenues.
Additionally, total system throughput increased from 77.8 million MMBtu in 1994 to 84.0 million MMBtu in 1995 as the Company utilized its capacity during the warmer weather by supplying additional volumes to interruptible customers. The profit margins from these customers are passed back to the Company's firm customers through reduced gas costs.
Natural Gas Sales
The natural gas sales portion of the Company's bundled service does not currently provide a profit margin. However, as all but 85 of the Company's 287,000 local transportation customers purchase bundled local transportation and natural gas, minimizing gas costs is an important part of the Company's business.
The Company's strategy of balancing gas costs and security of supply is achieved by optimizing the mix and terms of natural gas contracts with the use of supplemental liquefied natural gas and propane to meet peak winter demand. The Company maintains a diversified gas supply portfolio of domestic and Canadian gas supply contracts with producers.
The Company's rates include cost of gas adjustment clauses ("CGA") pursuant to which natural gas purchase costs and other costs are recovered from customers. The following table details these costs:
Recovered natural gas costs decreased by 15%, or $41.6 million, in 1995. This decrease was the result of a decline in purchase costs combined with decreases in supplemental fuel costs, demand-side management program ("DSM") costs, and transition costs. The decrease in purchase costs reflect a combination of the effect of the new competitive gas supply environment and the impact of the warm weather on demand. The decrease in supplemental fuel costs also reflect the warmer weather, as well as renegotiated contracts with supplemental fuel suppliers. DSM programs are aimed at motivating customers to use natural gas responsibly and, at the same time, cost the Company less than the incremental gas supply these customers would have used otherwise. As these programs have become fully implemented, their costs to customers have been reduced.
The Federal Energy Regulatory Commission ("FERC") is permitting gas pipeline companies, including those from which the Company purchases a significant portion of its natural gas supplies and storage services, to bill their customers for prudently incurred costs of transitioning into the deregulated environment. These costs significantly declined in 1995 and should continue to decline in the future. The Company has regulatory approval to recover these costs through the CGA.
Other Energy Products and Services
As is the case with revenues generated from local transportation, propane revenues are also significantly impacted by the weather. However, in 1995, the Company was able to expand its propane business to compensate for the weather-related decrease in demand. Sales volumes for propane increased from 6.8 million gallons in 1994 to 7.4 million gallons in 1995.
Revenues from equipment rentals and service increased by over 21% or $2.2 million in 1995 after increasing by 7% and 4% in 1994 and 1993, respectively. This significant increase in 1995 is primarily the result of moderate price increases and new service offerings combined with an increase in the number of units rented and serviced.
Operating Expenses
Operations expenses decreased by $3.9 million in 1995 after decreasing by $1.5 million in 1994 and increasing by $7.5 million in 1993. As the result of lower accounts receivable balances and improved collections from customers through special payment arrangements, bad debt expense was reduced by $2.5 million in 1995. The remaining decrease reflects other cost control measures.
Higher plant balances, an outcome of customer growth, have resulted in continuing increases in depreciation expense. Taxes, other than income taxes, increased primarily due to higher property taxes. Annual increases in property tax rates and assessments, combined with the growth in plant, increased property taxes by $601,000, $808,000, and $821,000 in 1995, 1994, and 1993, respectively.
Income (Loss) from Investments in Energy Ventures
Bay State has operating results from two investments in energy ventures: MASSPOWER, a cogeneration facility, and KBC Energy Services ("KBC"), a partnership with Connecticut Natural Gas Corporation and Koch Gas Services Company, which markets natural gas supplies and energy-related services on a nonregulated basis to commercial and industrial end-users.
Interest Expense and Dividend Requirements on Preferred Stock
In 1995, the Company incurred additional interest expense due to overcollections of recovered natural gas costs, a result of lower than forecasted wellhead costs, and higher than anticipated pipeline supplier refunds. Dividend requirements on preferred stock were relatively flat for the comparative periods.
Results of Operations, 1994 and 1993
Net income increased $1.7 million and $4.4 million in 1994 and 1993, respectively. In both years the Company experienced colder than normal weather and had a growing customer base. The 1993 net income increase also reflected the result of a rate increase in the Company's Massachusetts service area.
Operating revenues for 1994 and 1993 increased by $50.9 million and $39.6 million, respectively. In both years, this growth was primarily due to customer additions, combined with an increase in the cost of gas and the colder weather. The increase in 1993 operating revenues also reflected the Massachusetts rate increase, which was effective in November 1992. Recovered natural gas costs increased 17.6% and 9.3% in 1994 and 1993, respectively. The 1994 increase was the result of higher combined purchase and transmission costs, and additional increases in supplemental fuel costs, DSM program costs, and transition costs while the 1993 increase was primarily the result of higher natural gas commodity prices both under long-term contracts and from the spot market. These costs represent a bundled product and transmission cost for most of 1993.
Operations expenses decreased by $1.5 million in 1994, after increasing by $7.5 million in 1993. The decrease was the net result of the absence of costs related to the union work stoppages, which occurred in 1993, and higher bad debt expense related to the colder winter weather experienced in 1994. Also contributing to the decrease in 1994 operations expenses was the effect of an internal review of operations and corporate structure performed early in 1994. This review resulted in a flatter, more efficient organization requiring almost 5% fewer employees. The largest increases in operating expenses in 1993 were in employee benefits and outside services. The higher employee benefit expenses in 1993 included an increase in postretirement benefit costs, resulting from the implementation of Statement of Financial Accounting Standards No. 106, and the establishment of an accrual for an employee severance plan. Outside services included an abnormal level of costs related to the union work stoppages and regulatory restructuring costs.
Interest expense increased $2.2 million in 1994 due to higher levels of long-term debt outstanding during the year, higher short-term debt rates, and a decrease in the debt portion of AFUDC. Total interest expense for 1993 was comparable to the prior year.
Liquidity and Capital Resources
Natural gas sales in New England are seasonal, and the Company's cash flows reflect this seasonality. Approximately 74% of annual revenues are generated during the heating season, which results in a high level of cash flow from operations from late winter through early summer. Short-term borrowings are typically highest in the fall and early winter as a result of completion of the annual construction program and seasonal
working capital requirements. The Company has been able to access the financial markets to meet its capital requirements and does not anticipate a change in its access to, or the availability of, capital in the coming year.
Cash flows from operations improved by $7.6 million in 1995 despite a decrease in net income primarily as the result of decreasing accounts receivable balances, increases in refunds due customers, and lower cash contributions to benefit plans. Refunds from upstream pipelines totaled approximately $15.8 million in 1995 as compared to $9.4 million in 1994. This amount will be refunded to customers in the near future, contributing to reduced gas prices. The Company made cash contributions to its benefit plans of $3.2 million, $15.3 million, and $15.0 million in 1995, 1994, and 1993, respectively.
The Company invests in property, plant, and equipment to improve and protect its distribution system, and to expand its system to meet customer demand. As a result of planned spending, capital expenditures for property, plant, and equipment increased $2.1 million in 1995. Capital expenditures for 1996 are estimated to be approximately $53.0 million.
The remaining increase in investing activities for 1995 relates to expenditures on energy ventures. These expenditures were $4.6 million, $1.0 million, and $4.8 million in 1995, 1994, and 1993, respectively. In 1993, a one-time equity investment was made in MASSPOWER of $4.2 million. Capital expenditures for energy ventures for 1996 are estimated to be approximately $6.3 million (see note 8).
As was the case in 1994, the 1995 decline in cash flows from financing activities reflects a reduction in debt issuances as a result of strong cash flows from operations. The Company has a shelf registration statement covering up to $125.0 million of senior unsecured debt securities, under which $65.0 million in notes has been issued as of September 30, 1995. The Company has access to $77.0 million in bank lines of credit. In early 1995, the Dividend Reinvestment Plan was converted to a market purchase plan, eliminating new equity issuances under this plan.
The Company is in the final stages of completing a sale and lease-back arrangement for equipment rental assets with a financing company, through which approximately $20.7 of additional capital will be made available. This, along with continuing strong operating cash flows, will enable the Company to fund its operating and investing activities without extensive long-term debt or equity issuances in 1996.
Impact of Inflation
The rates charged to transportation customers may not be increased without formal proceedings before regulatory authorities. Accordingly, in the absence of authorized rate increases and except for changes in recovered gas costs, which are reflected in customer rates, the Company must look to performance improvements and higher sales volumes, particularly from highly profitable market segments, to offset inflationary increases in its costs of operations. Current rates only permit the Company to recover its historical cost of utility plant and give no recognition to the current cost of replacing facilities. Although no new material
rate proceedings are currently planned, under the current regulatory process, management believes the cost of utility plant additions will be recognized in setting future rate levels.
Environmental Issues
The Company continues to work with federal and state environmental agencies to assess the extent and environmental impact of waste materials that exist at or near former gas manufacturing sites located primarily in Massachusetts. The costs of such assessments and any related remediation determined to be necessary will be funded from traditional sources of capital and recovered from customers (see note 8).
New Accounting Standard
In March 1995, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of." This statement, which is effective for years beginning after December 15, 1995, requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company does not expect that the adoption of this standard will have a material impact on the results of operations, financial condition, or cash flows of the Company.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
BAY STATE GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1995, 1994, AND 1993
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the accounts of Bay State Gas Company and its wholly owned subsidiaries (the "Company"). All significant intercompany transactions and accounts have been eliminated. Certain information in the prior period financial statements has been reclassified to conform with the current period's presentation.
REGULATION AND OPERATIONS. The Company is subject to regulation with respect to rates, accounting and other matters, where applicable, by the Massachusetts Department of Public Utilities ("MADPU"), the New Hampshire Public Utilities Commission, the Maine Public Utilities Commission, and the FERC. The Company's accounting policies conform to generally accepted accounting principles and reflect the effects of the ratemaking process in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
PLANT. Plant is stated at original cost and consists of utility plant and non-utility plant assets. The original cost of depreciable units of plant retired, together with the cost of removal, net of salvage, is charged to accumulated depreciation. The costs of maintenance, repairs, and replacements of minor items are charged to expense as incurred.
Depreciation is provided for all classes of plant on a group straight-line basis in amounts equivalent to overall composite rates of 3.88% for 1995 and 1994 and 3.74% for 1993.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC). AFUDC is the estimated cost of funds used for construction purposes. Such allowances are charged to plant and reported as other income (cost of equity funds) or a reduction of interest expense (cost of borrowed funds). AFUDC was $748,000, $457,000, and $2,028,000 for 1995, 1994, and 1993, respectively.
INVESTMENTS. The Company accounts for its partnership investments by the equity method.
CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
LOCAL TRANSPORTATION, NATURAL GAS SALES, AND DEFERRED GAS COSTS. Local transportation revenue and natural gas sales are based on the volume of gas transported or sold at billing rates authorized by regulatory authorities and include unbilled revenues for gas delivered, but not billed. The Company's rates include cost of gas adjustment clauses pursuant to which gas and certain other costs are recovered from customers. Any differences between gas costs incurred and amounts billed are deferred for recovery from or refund to customers in future periods. Also included in natural gas sales are sales to interruptible customers. Substantially all net margins from interruptible sales are used to reduce gas costs to customers through the cost of gas adjustment clauses.
ENVIRONMENTAL COSTS. In accordance with orders of regulatory authorities, the Company defers costs incurred to remediate environmental damage. Such costs are amortized to expense over periods of seven to 10 years as they are recovered from customers (see note 8).
INCOME TAXES. On October 1, 1993, the Company adopted the asset and liability method of accounting for income taxes as required by Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." Pursuant to SFAS 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the tax bases and the financial statement carrying amounts of existing assets and liabilities. Prior year financial statements reflect deferred income taxes for the tax effects of the timing differences between the recognition of revenue and expense for income tax purposes and financial reporting purposes (see note 2).
Investment tax credits related to plant additions prior to 1987 were deferred and are being amortized as reductions of income tax expense over the lives of the related assets.
PENSION AND OTHER EMPLOYEE BENEFIT PLANS. The Company has noncontributory defined benefit pension plans covering substantially all employees. Benefits under the plans are generally based on years of service and the level of compensation during the final years of employment. Pension costs are recognized on the accrual method of accounting over the expected periods of employee service based on actuarial assumptions.
Statements of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefit Plans Other than Pensions" and No. 112, "Employers' Accounting for Postemployment Benefits," were adopted on October 1, 1993, requiring the accrual method of accounting for the costs of postretirement and postemployment benefits. Other postretirement benefits consist of certain health and life insurance benefits for retired and active employees hired before September 30, 1990. Postemployment benefits consist of workers compensation claims, long-term disability payments, and medical coverage continuation payments. These costs were previously recognized when paid. They are now accrued over the expected periods of employee service based on actuarial assumptions (see note 7).
EARNINGS PER SHARE. Earnings per common share have been computed by dividing earnings applicable to common stock by the weighted average number of shares of common stock outstanding during each year.
NEW ACCOUNTING STANDARDS. Effective for fiscal years beginning after December 15, 1995, SFAS 121 will require a review of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. It is expected that the adoption of this standard will not have a material impact on cash flows, financial condition, or the results of operations.
NOTE 2. INCOME TAXES
At September 30, 1995 and 1994, unamortized deferred investment tax credits included in long-term deferred taxes amounted to $5.8 million and $6.2 million, respectively.
As discussed in note 1, a new method of accounting for income taxes was adopted as of October 1, 1993. The cumulative effect on the years prior to October 1, 1993 of adopting the new method of accounting for income taxes had no effect on net income because a regulatory asset of $9.6 million was recorded, reflecting future amounts due from customers for the effects of the temporary differences. The effect of the change on income tax expense for 1994 was not significant because amounts of income tax expense which differ from amounts calculated in accordance with currently effective rate orders for settlement with customers in future periods have been deferred.
NOTE 3. CAPITALIZATION
COMMON STOCK. A Key Employee Stock Option Plan provided for the granting of options to key employees to purchase an aggregate of 1,050,000 shares of common stock. While it is anticipated that no further options will be granted under this plan, previously granted options may continue to be exercised through 2002.
A Shareholder Rights Plan provides one right ("Right") to buy one share of common stock at a purchase price of $70 for each share of common stock issued and to be issued. The Rights expire on November 30, 1999 and only become exercisable, or separately transferable, 10 days after a person or group acquires, or announces an intention to acquire, beneficial ownership of 20% or more of the Company's common stock. The Rights are redeemable by the Board at a price of $.01 per Right, at any time prior to the acquisition by a person or a group of beneficial ownership of 20% or more of the Company's common stock. Once a person or group acquires more than 20% of the Company's common stock, however, the Rights may not be redeemed.
At September 30, 1995, there were 385,000 authorized but unissued shares of common stock reserved for the Dividend Reinvestment Plan ("DRP"). On December 1, 1994, the DRP was converted to a market based plan. It is anticipated that no further shares will be issued under this plan.
CUMULATIVE PREFERRED STOCK AND LONG-TERM DEBT. The cumulative preferred stocks rank equally and are preferred over common stock in voluntary liquidation at the redemption price in effect at the time of such voluntary liquidation and in involuntary liquidation at the par value per share, in each case plus accrued dividends, except for the $3.80 Series, $50 par value, which has a voluntary liquidation value of $83 per share and a set involuntary liquidation value of $81.50 per share, plus accrued dividends.
As of September 30, 1995, long-term debt agreements contain no provisions restricting the payment of dividends on common stock. All debt is unsecured.
As of September 30, 1995 and 1994, $6.0 million and $18.0 million of long-term debt were outstanding under revolving credit agreements at weighted average interest rates of 6.23% and 5.36%, respectively.
The fair values of capital lease obligations are estimated using the present value of the minimum lease payments discounted at market rates. The fair values of long-term debt are estimated based on current rates offered to the Company for debt of the same remaining maturities. The carrying amounts for cash and temporary cash investments, accounts receivable, accounts payable, accrued liabilities, and short-term debt approximate their fair values due to the short-term nature of these instruments.
NOTE 4. LEASES
Noncancelable operating and capital leases have been entered into for the use of certain facilities and equipment. The operating lease agreements generally contain renewal options. The capital leases relate to liquefied natural gas storage facilities. Certain leases contain renewal and purchase options and escalation clauses.
Interest included in capital lease payments was $253,000, $328,000, and $397,000 in 1995, 1994, and 1993, respectively.
At September 30, 1995, the Company had unsecured bank lines of credit aggregating $77.0 million for which it pays commitment fees, and access to an additional $30.0 million under the Fuel Purchase Agreements as described in note 6.
NOTE 6. FUEL PURCHASE AGREEMENTS
Up to $30.0 million can be raised through credit agreements (the "Agreements") underlying the Fuel Purchase Agreements with a corporation established to provide financing, through borrowing on a demand basis or selling supplemental gas inventories. Any inventories sold must be repurchased and any associated carrying costs paid when the gas is withdrawn from storage. All gas costs, carrying costs, and administrative charges are fully recoverable through the CGA approved in each state regulatory jurisdiction. The Agreements contain an expiration date of September 1998.
NOTE 7. PENSION AND EMPLOYEE BENEFIT PLANS
Plan assets are primarily invested in marketable pooled funds holding equity and corporate debt securities and in cash equivalents. Certain changes in items shown above are not recognized as they occur, but are systematically amortized over subsequent periods. Unrecognized amounts as of September 30, 1995 and 1994, are as follows:
The discount rate, rate of increase in future compensation levels, and expected long-term rate of return on plan assets used in determining the actuarial present value of the projected benefit obligation were 8.0%, 5.0%, and 9.0% for both 1995 and 1994. Net pension cost for 1995, 1994, and 1993 included the following components:
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS. As described in note 1, the Company adopted the accrual method of accounting for postretirement benefit plans other than pensions in 1994. The change in the method of accounting had no significant impact in 1994 as regulatory authorities permit the Company to defer costs in excess of amounts recovered through rates for collection in future periods. The present value of the accumulated benefit obligation was $24.7 million and $28.2 million, at September 30, 1995 and 1994, respectively. The expense recognized was $2.7 million, $2.8 million, and $2.5 million for 1995, 1994, and 1993, respectively. The components of other postretirement benefit expense for 1995 and 1994 are as follows:
Plan assets are held in voluntary employee benefit association ("VEBA") trusts and medical funds in the pension plans. VEBA assets are invested in common stocks, bonds, and cash equivalents.
The accumulated other postretirement benefit obligation was determined using an assumed discount rate of 8.0% and an expected long-term pre-tax rate of return on plan assets of 9.0% for both 1995 and 1994, and a health care cost trend rate of 9.0% and 11.0% in 1995 and 1994, respectively, decreasing to 6.0% by 1998. An annual 1% increase in the health care cost trend rate would increase the accumulated postretirement benefit obligation by $2.2 million and the cost for 1995 by $300,000.
RETURN ON PREPAYMENTS OF OTHER POSTRETIREMENT BENEFITS. As permitted by regulatory authorities, noncash returns of $1,650,000, $857,000, and $286,000 for 1995, 1994, and 1993, respectively, have been recorded on amounts of prepayments associated with employee postretirement benefit plans other than pensions. Regulators permit the accrual of returns on these prepayments because the plan funding will significantly reduce future costs of the plans.
POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS. As described in note 1, the accrual method of accounting for postemployment benefit plans was adopted in 1994. The change in the method of accounting had no significant impact in 1994 as the Company deferred costs in excess of amounts recovered through rates for collection in future periods. The present value of the accumulated benefit obligation was $4.9 million and $4.1 million, at September 30, 1995 and 1994, respectively.
EMPLOYEE SAVINGS PLAN. Employee Savings Plans (the "ESP's") provides eligible employees with an incentive to save and invest regularly. The ESP's are defined contribution plans, which allow eligible employees to defer a portion of their salaries to employee-funded pretax retirement savings accounts. Matching contributions to certain employee deferrals were $813,000, $784,000, and $601,000 in 1995, 1994, and 1993, respectively.
NOTE 8. COMMITMENTS AND CONTINGENCIES
CAPACITY REQUIREMENTS. The Company currently transports natural gas from Canada through a converted oil pipeline leased from the Portland Pipe Line Corporation ("PPLC"). The PPLC lease currently extends to March 31, 1997. An agreement with PPLC to extend the lease through the 1997-1998 heating season is being sought. Short-term contingency plans have been developed for supplying customers in Maine and New Hampshire through the 1997-1998 heating season in the event that the lease is not extended. Long-term, two projects to replace the pipeline capacity provided by the PPLC lease are being pursued, a 2.0 million MMBtu liquefied natural gas storage facility in Wells, Maine ("Wells LNG"), and the Portland Natural Gas Transmission System ("PNGTS").
PNGTS is an interstate pipeline that will extend 250 miles from the US-Canadian border to the New Hampshire-Massachusetts border. By March 1, 1996, PNGTS plans to file an application with the FERC for approval to construct and operate the pipeline. The Company has entered into long-term agreements with PNGTS for service on the pipeline. Such agreements are subject to state regulatory review and approval in Massachusetts, Maine, and New Hampshire. In November 1994, the Company filed an application with the FERC for approval to construct and operate Wells LNG. The Company will file for approval from the public utility commissions of Maine and New Hampshire of its agreement for service from the LNG facility.
Recovery of investments in PNGTS and Wells LNG is dependent upon, among other things, successful completion of the projects and the terms of required regulatory approvals. While their completion is subject to a number of factors beyond the Company's control, the Company believes that these projects will be successful. Both of these projects are scheduled to be completed and available for service by November 1998.
During 1995, the Company made an initial investment of $50,000 in KBC and is committed to invest up to a total of $1.7 million. KBC began operations in 1995.
LONG-TERM OBLIGATIONS. The Company has long-term contracts for the purchase, storage, and delivery of gas supplies. Certain of these contracts contain minimum purchase provisions which, in the opinion of management, are not in excess of the Company's requirements.
ENVIRONMENTAL ISSUES. Like other companies in the natural gas industry, the Company is party to governmental actions associated with former gas manufacturing sites. Management estimates that, exclusive of insurance recoveries, if any, expenditures to remediate and monitor known environmental sites will range from $3.9 million to $10.0 million. Accordingly, a $3.9 million liability, with an offsetting charge to a regulatory asset (see note 1), has been accrued. Environmental expenditures for 1995, 1994, and 1993 were $387,000, $129,000, and $620,000, respectively. Exclusive of amounts accrued for future expenditures, at September 30, 1995 and 1994, approximately $3.0 million of environmental expenditures had been deferred for future recovery from customers.
REGULATORY MATTERS. On April 13, 1995, approval was received from the FERC for a $1.1 million increase in annual pipeline revenues effective November 1, 1994.
An overall revenue-neutral rate redesign has been filed with the MADPU. The goal of the rate redesign is to implement rates that more closely reflect the actual costs associated with serving different customers. New rates are expected to be effective early in calendar 1996.
Significant regulatory assets arising from the rate-making process associated with income taxes, employee benefits, and environmental response costs have been recorded. Based on its assessments of decisions by regulatory authorities, management believes that all regulatory assets will be settled at recorded amounts through specific provisions of current and future rate orders.
LITIGATION. The Company is involved in various legal actions and claims arising in the normal course of business. Based on its current assessment of the facts of law, and consultations with outside counsel, management does not believe that the outcome of any action or claim will have a material effect upon the consolidated financial position, results of operations, or liquidity of the Company.
NOTE 9. UNAUDITED QUARTERLY FINANCIAL DATA
In thousands except per share amounts.
In the opinion of management, quarterly financial data includes all adjustments, consisting only of normal recurring accruals, necessary for a fair representation of such information. Revenue and income amounts vary significantly due to seasonal weather conditions.
REPORT OF MANAGEMENT
The management of Bay State Gas Company and its subsidiaries has the responsibility for preparing the accompanying financial statements. We believe the financial statements were prepared in conformity with generally accepted accounting principles. Management also prepared the other information in the annual report and is responsible for its accuracy and consistency with the financial statements.
To fulfill its responsibility, management maintains a system of internal control that has been designed to provide reasonable assurance as to the integrity and reliability of the financial statements and the safeguarding of Company assets.
The Company has established statements of corporate policy relating to conflict of interest and conduct of business and annually receives from appropriate employees confirmation of compliance with these policies.
The Company's financial statements have been audited by KPMG Peat Marwick LLP, independent certified public accountants. The independent accountants are elected by the Company's Directors and report any recommendations concerning the Company's system of internal control to the Audit Committee of the Board of Directors, which consists of three outside Directors. The Audit Committee meets periodically with management, internal auditors and KPMG Peat Marwick LLP, to review and monitor the Company's financial reporting, accounting practices, and business conduct.
Although there are inherent limitations in any system of internal control, management believes that as of September 30, 1995, the Company's system of internal control was adequate to accomplish the objectives discussed herein.
ROGER A. YOUNG THOMAS W. SHERMAN Chief Executive Officer Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders of BAY STATE GAS COMPANY
We have audited the accompanying consolidated balance sheets and statements of capitalization of Bay State Gas Company and subsidiaries as of September 30, 1995 and 1994, and the related consolidated statements of earnings, shareholders' equity and cash flows for each of the years in the three-year period ended September 30, 1995. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits 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 Bay State Gas Company and subsidiaries at September 30, 1995 and 1994, and the results of their operations and their cash flows for each of the years in the three-year period ended September 30, 1995 in conformity with generally accepted accounting principles.
As discussed in Notes 1, 2, and 7 to the consolidated financial statements, the Company changed its methods of accounting for income taxes, postemployment benefits and postretirement health and welfare benefits in 1994.
KPMG PEAT MARWICK LLP
Boston, Massachusetts October 24, 1995
PART III
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the Directors of the Registrant as set forth on pages 3 and 4 of the 1996 annual meeting proxy statement, dated December 7, 1995, is incorporated herein by reference. Information relating to the Executive Officers of the Registrant is contained in Part I, Item 1, Business.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding compensation of the Registrant's executive officers as set forth on pages 7 through 15 of the 1996 annual meeting proxy statement, dated December 7, 1995, is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the security ownership of certain beneficial owners and management as set forth on pages 5 and 6 of the 1996 annual meeting proxy statement, dated December 7, 1995, is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions as set forth on pages 4, 6, 7 and 15 of the 1996 annual meeting proxy statement, dated December 7, 1995, is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THE REPORT:
(1) The following financial statements are included herein under Part II, Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Consolidated Statements of Earnings for the Years ended September 30, 1995, 1994, and 1993 Consolidated Balance Sheets as of September 30, 1995 and 1994 Consolidated Statements of Capitalization as of September 30, 1995 and Consolidated Statements of Shareholders' Equity for the Years ended September 30, 1995, 1994, and 1993 Consolidated Statements of Cash Flows for the Years ended September 30, 1995, 1994, and 1993 Independent Auditors' Report
(2) The following additional data should be read in conjunction with the financial statements included in Part II, Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Schedules not included herein have been omitted because they are not required or are not applicable, or the required information is shown in such financial statements or notes thereto.
(3) Exhibits -- See Exhibit index on page 34.
(B) REPORTS ON FORM 8-K:
The Company did not file a report on Form 8-K during the fourth quarter of fiscal 1995.
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.
BAY STATE GAS COMPANY
/S/ THOMAS W. SHERMAN By --------------------------------- THOMAS W. SHERMAN EXECUTIVE VICE PRESIDENT
Date: December 1, 1995 ------------------------------
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 and on the dates indicated.
EXHIBIT INDEX
(3) Articles of incorporation and by-laws:
(4) Instruments defining the rights of security holders, including indentures:
The following is a listing of debt instruments defining the rights of security holders, including indentures and/or note agreements for Bay State, Northern, and Granite. None of these instruments represent any securities in an amount authorized or outstanding which exceeds 10% of the total assets of the Company as of September 30, 1995. The Company will furnish the Securities and Exchange Commission with copies of any of the instruments listed below upon request.
Revolving Credit Agreement between Northern and The First National Bank of Boston, to borrow up to $20,000,000, dated as of March 17, 1993, due March 17, 1997.
Indenture between Bay State and The First National Bank of Boston, Trustee, dated as of April 1, 1991, for Senior Unsecured Debt Securities under which the following Notes have been issued under a Prospectus dated April 18, 1991:
- $10,000,000 Principal Amount of 9.20% Notes due June 6, 2011 - $5,000,000 Principal Amount of 9.28% Notes due August 12, 2021 - $25,000,000 Principal Amount of 9.45% Notes due September 5, 2031 - $12,000,000 Principal Amount of 8.15% Notes due August 26, 2022 - $4,000,000 Principal Amount of 7.55% Notes due November 1, 2002 - $1,000,000 Principal Amount of 7.55% Notes due October 2, 2002 - $5,000,000 Principal Amount of 7.45% Notes due December 16, 2002 - $5,000,000 Principal Amount of 7.38% Notes due December 31, 2002 - $7,000,000 Principal Amount of 7.375% Notes due November 1, 2002 - $1,000,000 Principal Amount of 7.375% Notes due December 31, 2002 - $5,000,000 Principal Amount of 7.37% Notes due December 31, 2002 - $20,000,000 Principal Amount of 7.25% Notes due August 5, 2002
Indenture between Bay State and The First National Bank of Boston, Trustee, dated as of April 1, 1991, for Senior Unsecured Debt Securities under which the following Notes have been issued under a Prospectus dated April 7, 1993:
- $10,000,000 Principal Amount of 7.42% Notes due September 10, 2001 - $10,000,000 Principal Amount of 7.625% Notes due June 19, 2023 - $10,000,000 Principal Amount of 6.0% Notes due July 6, 2000 - $15,000,000 Principal Amount of 6.0% Notes due September 29, 2003 - $10,000,000 Principal Amount of 6.58% Notes due June 21, 2005 - $5,000,000 Principal Amount of 6.0% Notes due January 30, 2001 - $5,000,000 Principal Amount of 6.625% Notes due June 28, 2002
Note Purchase Agreement between Northern and First Colony Life Insurance for the purchase and sale of $13,000,000 principal amount of 9.70% Notes dated as of January 1, 1992, due September 1, 2031.
Note Purchase Agreement between Northern and the Mutual Life Insurance Company of New York for the purchase and sale of $10,000,000 principal amount of 6.93% Notes dated as of September 29, 1995, due September 27, 2010.
Note Purchase Agreement between Northern and the Mutual Life Insurance Company of New York for the purchase and sale of $5,000,000 principal amount of 6.30% Notes dated as of September 29, 1995, due September 30, 1998.