ITEM 1. BUSINESS.
GENERAL DEVELOPMENT OF BUSINESS
Boston Gas Company (the "Company") is engaged in the transportation, distribution and sale of natural gas to residential, commercial, and industrial customers which includes the City of Boston, Massachusetts, and 73 other Massachusetts communities. The Company has one subsidiary, Massachusetts LNG Incorporated ("Mass LNG"), which holds a long-term lease on two liquefied natural gas facilities. The Company has been in business for 171 years and is the second oldest gas company in the United States. Since 1929, all of the common stock of the Company has been owned by Eastern Enterprises ("Eastern"), which is headquartered in Weston, Massachusetts.
GAS SALES
Firm gas sales are made under rate schedules or contracts with customers who do not contemplate service interruption. Firm sales of natural gas sold for purposes of space heating are directly related to weather conditions. Consequently, variations in weather patterns can have a significant impact upon the Company's revenues and earnings. The Company also provides seasonal firm sales and transportation services to customers for terms of less than 365 days.
Non-firm sales include interruptible sales made pursuant to contracts with customers who typically can use oil and gas interchangeably and special sales for resale to other gas companies for distribution to their
customers. Non-firm sales are dependent upon gas supply availability, weather conditions and the price of gas in relation to the price of alternate fuels. The price the Company charges is generally tied to the price of the customer's alternate fuel. Availability of gas supply and price competition from residual oil are important factors in retaining non-firm sales. Beginning November 1, 1993, gross margins from non-firm sales and transportation services ($8,434,000 in 1993 and $10,248,000 in 1992) are passed back to firm customers through the cost of gas adjustment clause up to a threshold based upon the prior season's experience. Non-firm margins realized in excess of the threshold are shared between shareholders and core customers 25% and 75%, respectively.
One customer accounted for 4.0% of the Company's operating revenues in 1993, 2.3% in 1992 and 3.5% in 1991.
GAS SUPPLY
The Company purchases approximately 70% of its pipeline gas supplies directly from producers and marketers pursuant to long-term contracts which are subject to review and approval by the Massachusetts Department of Public Utilities ("Department"). Seven of the Company's direct purchase agreements have been approved by the Department including two long-term Canadian agreements. Five other long-term agreements are pending before the Department, with orders expected by April, 1994. The Company purchases its remaining pipeline supplies pursuant to short-term, firm winter service agreements and on a spot basis. Pipeline supplies are transported on interstate pipeline systems to the Company's service territory pursuant to transportation agreements approved by the Federal Energy Regulatory Commission ("FERC"). The Company has also contracted with pipeline companies and others for the storage of natural gas and related transportation from underground storage fields located in New York and Pennsylvania. Supplemental supplies of liquefied natural gas ("LNG") and propane are purchased and produced from foreign and domestic sources.
All interstate pipelines serving the Company have implemented service restructuring plans on terms and conditions approved by FERC pursuant to Order No. 636. Order No. 636, issued April 8, 1992, required interstate pipeline companies to unbundle existing gas service contracts into separate gas sales, transportation and storage services. Accordingly, the Company's firm bundled service with Algonquin Gas Transmission Company ("Algonquin"), a wholly-owned subsidiary of Algonquin Energy, Inc., a wholly-owned subsidiary of Texas Eastern Transmission Corporation ("Texas Eastern"), itself a wholly-owned subsidiary of Panhandle Eastern Corporation, was converted to an annual firm transportation entitlement of 65,600 MMCF. Similarly, the Company's firm bundled sales service with Texas Eastern has been converted to an annual firm transportation entitlement of 100,100 MMCF; and its firm bundled sales service with Tennessee Gas Pipeline Company, a division of Tenneco, Inc. ("Tennessee"), has been converted to an annual firm transportation entitlement of 77,800 MMCF. In addition, as a result of industry restructuring, the Company has firm entitlements on interstate pipelines upstream of Tennessee, Texas Eastern, and Algonquin, with direct access to supply areas. Together, these transportation entitlements are used to transport natural gas purchased by the Company from producing regions and underground storage facilities to our service territory. After restructuring, the Company now holds direct entitlements to 16,500 MMCF of storage capacity with Tennessee, Texas Eastern and others. These new transportation and storage agreements with Algonquin, Texas Eastern, and Tennessee have terms generally expiring no earlier than November 1996, April 2012, and April 2000, respectively. The Company is provided rights of first refusal under Order No. 636 to extend the terms of such service. The Company considers the service reliability of its natural gas portfolio after industry restructuring to be comparable to that existing prior to Order No. 636.
In addition to its domestic supply arrangements, the Company has three contracts for the purchase of Canadian gas supplies. The Company's contract with Boundary, Inc. provides for the purchase of 3,845 MMCF of gas annually and expires on January, 2003. The Company also has contracts with Alberta Northeast Gas, Ltd. ("ANE") to purchase up to 6,242 MMCF of gas annually, and with Imperial Oil of Canada, Ltd. ("Imperial"), formerly Esso Resources Canada, Ltd., for the purchase of 12,775 MMCF of gas annually. These contracts expire on November, 2003 and April, 2007, respectively. The Company has contracted with Iroquois Gas Transmission System ("IGTS"), Tennessee and Algonquin to transport these
gas supplies from the Canadian border to delivery points in the Company's service territory. All necessary Canadian government approvals for the purchase, import, and transportation of these volumes have been issued.
The Company has contracts, expiring in 1998, with Distrigas of Massachusetts Corporation ("DOMAC") for the purchase of an annual quantity of up to 2,000 MMCF of LNG and for 1,000 MMCF of LNG storage capacity and related vaporization services. The Company also purchases LNG from DOMAC on a spot basis when prices are competitive with alternative supplies. DOMAC's affiliate, Distrigas Corporation, imports the LNG from Algeria pursuant to agreements with Sonatrach, the Algerian National Energy Company, through its wholly-owned subsidiary Sonatrading Amsterdam B.V. The United States Department of Energy ("DOE") and FERC have granted the necessary approvals for the import, sale and storage of LNG.
The Company relies on supplemental supplies to meet firm sendout requirements which are greater than its firm pipeline capacity entitlements. The number of days that peak sendout can be maintained is limited by the capacity of the Company's storage facilities for supplemental gas supplies and the rate at which these supplies can be sent out, and subsequently replenished. Increased deliveries of pipeline supplies have reduced the Company's dependence on more costly supplemental supplies. The Company considers its peak day sendout capability, based on its total supply resources, adequate to meet the requirements of its customers.
The Company owns or leases facilities which enable it to store the equivalent of 4,000 MMCF of natural gas in liquid form as LNG and vaporize it for use during periods of high demand. The inventory for these facilities is provided by liquefaction of pipeline gas and from LNG purchased. The maximum storage capacity of these facilities may be limited by various factors, including maintenance and other operating considerations.
In addition to LNG, the Company has the ability to use propane to meet its demand requirements during periods of extreme cold weather. Propane can be mixed with air and introduced, along with natural gas, into the gas distribution system at a number of propane-air facilities owned by the Company.
REGULATION AND RATES
The Company's operations are subject to Massachusetts statutes applicable to gas utilities. Rates, the territorial limit of the Company's service area, issuance of securities, affiliated party transactions, purchase of gas and pipeline safety regulations are regulated by the Department.
The rates for gas service rendered by the Company are subject to approval by, and are on file with, the Department. Gas operating revenues are recognized when billed. No revenue is recorded for the amount of gas distributed to customers which is unbilled at the end of a period. The Company has a cost of gas adjustment clause which allows for the adjustment of billing rates for firm gas sales to recover the cost of gas delivered to firm customers. For financial reporting purposes, the Company defers the cost of any firm gas that has been distributed, but is unbilled at the end of a period, to a period in which the gas is billed to customers.
On October 30, 1993, the Department allowed the Company an annual revenue increase of $37,700,000, effective November 1, 1993, and also approved several rate design changes that reduce the volatility of the Company's margins attributable to weather. This was accomplished by increasing customer charges and moving the recovery of certain local production and storage costs from base rates to the cost of gas adjustment clause.
Facility expansion is regulated by the Department. Municipal, state and federal authorities have jurisdiction over the use of public ways, land and waters for gas mains and other distribution facilities.
LICENSES AND FRANCHISES
The Company and Eastern were granted an intrastate exemption from the provisions of the Public Utility Holding Company Act of 1935 ("the Act") under Section 3(a)(1) thereof, pursuant to an order of the Securities and Exchange Commission (the "SEC") dated February 28, 1955, as amended by orders dated November 3, 1967 and August 28, 1975. On February 7, 1989, the SEC issued a proposed rule under the Act which would provide limits for non-utility related diversification by intrastate public utility holding companies, such as Eastern, that are exempt under the Act. Since its proposal in 1989, the SEC has taken no action with respect to this proposed rule. Eastern and the Company cannot predict whether this proposed rule will be adopted or whether it will affect their exemption under the Act.
Except as set forth above, there are no patents, trademarks, licenses or concessions that are important to the business of the Company.
COMPETITION AND MARKETING
The Company competes with fuel oil and electricity and other supplies of gas for residential, commercial and industrial uses. The Company's marketing efforts continue to benefit from growing customer awareness of natural gas as a safe, reliable, economical and environmentally sound fuel. Customer recognition that the use of gas improves overall air quality, reduces pollutants and eliminates on-site fuel storage problems has become increasingly significant.
The Company added annual firm sales of approximately 2,443 MMCF in 1993. In the commercial and industrial markets, where the Company has a 22% market share in its service territory, a degree of penetration which is approximately half that of the United States commercial and industrial market share, considerable growth opportunities exist. In 1993, the Company added new firm annual load of 1,812 MMCF in these markets. Increasing environmental regulation of emissions should provide additional opportunities in the commercial and industrial markets. The Company has identified several industrial facilities that must file compliance plans under these regulations by April 1, 1994.
Approximately 4,391 residential customers converted to gas for central heating last year. Despite lower oil prices, the Company expects continued strong activity in the residential conversion market. Approximately 46% of the Company's existing customers do not use gas for central heating. The Company plans on targeting this group as well as electrically-heated residential complexes with special programs to encourage the conversion to natural gas.
FERC Order No. 636 and other regulatory changes have increased the potential for competition among existing and new suppliers of natural gas in the Company's service area, particularly in large commercial and industrial markets (see "Gas Supply"). The Company believes it is well positioned to respond to such sales competition. The Company received approval from the Department to file contracts designed to compete with non-captive commercial and industrial customers with alternative energy options. This provides for an expedited approval process and enhances the Company's ability to negotiate sales agreements that reflect competitive market conditions. In June 1992, FERC granted the Company authority to make sales for resale in interstate commerce under the terms of a blanket marketing certificate. This additional sales authority allows the Company to maximize the use of its supply entitlements, thereby minimizing the cost of gas to firm customers and making its sales rates more competitive. The Company is also well positioned to provide transportation service to customers who may engage in direct purchases of natural gas from other suppliers under firm and interruptible transportation tariffs approved by the Department. The rate design changes
approved by the Department in the October 30, 1993 rate order provide for margin neutrality regardless of the customer's decision to purchase gas directly from the Company or purchase third-party gas for transportation on the Company's distribution system.
The Company continues to pursue market opportunities in natural gas-powered vehicles. The recent passage of The National Energy Policy Act, as well as the Clean Air Act Amendments of 1990, both of which mandate the use of alternative fuel vehicles by the mid-1990's by certain commercial fleets, have enhanced opportunities in this market. The Company has initiated a number of programs demonstrating the environmental and operating advantages of natural gas vehicles. The Company's marketing activities include the installation of two Company-owned fueling stations, conversion of 92 Company vehicles, and establishment of pilot programs with a number of large fleet operators to demonstrate the advantages of choosing natural gas to meet alternative fuel vehicle requirements.
Other new markets, such as air conditioning, cogeneration and desiccant dehumidification continue to develop as new technologies emerge.
ENVIRONMENTAL REGULATION
The Company is subject to local, state and federal environmental regulation of its operations and properties. The Company is working with the Massachusetts Department of Environmental Protection ("DEP") to determine the environmental impact, if any, of by-products associated with 13 former manufactured gas plant ("MGP") properties which the Company currently owns and for which the Company may be potentially responsible. The Company is currently assessing seven of these properties pursuant to applicable DEP procedures. The Company expects to spend approximately $1 million in assessing these properties in 1994 and expects similar expenditures for site assessment for the next several years as other properties are investigated. Since the DEP has not yet approved a remediation plan for any Company site, the Company cannot reliably predict the potential liability associated with final remediation of any of these properties. Company experience to date indicates that assessment and remediation costs of at least $18 million could be incurred over the next several years at these thirteen properties, subject to possible contribution or the assumption of responsibility by New England Electric System ("NEES") or one of its subsidiaries as discussed below.
Massachusetts Electric Company, a wholly-owned subsidiary of NEES, has assumed responsibility for remediating a fourteenth property currently owned by the Company (part of the site of gas manufacturing operations in Lynn, Massachusetts) pursuant to the decision of the Court of Appeals for the First Circuit in The John S. Boyd, Inc., et al. v. Boston Gas Company, et al, Civil Action No. 89-575-T (May 26, 1993). The First Circuit found that NEES and its subsidiaries, as the prior owners and operators of the Lynn MGP site, were responsible for remediating the site and that the Company did not assume any liability for environmental remediation when it acquired the property from NEES in 1973. Of the thirteen other sites currently owned by the Company, ten were acquired from NEES. Given substantial similarities between these acquisitions and that involved in Boyd, it is not probable that the Company will have any material exposure for environmental remediation at these ten sites.
There are 23 other former MGP sites within the Company's service territory which the Company does not currently own. The DEP has not issued a Notice of Responsibility to the Company for any of these 23 sites. At this time, there is substantial uncertainty as to whether the Company is responsible for remediating any of these sites either because the Company never owned the site, the Company does not have successor liability for contamination of the site by earlier operators, or site conditions do not require remediation by the Company.
By an order issued on May 25, 1990, the Department approved a settlement agreement which provides for the recovery through the cost of gas adjustment clause of all environmental response costs associated with former MGP sites over separate, seven-year amortization periods without a return on the unamortized balance. The settlement agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations.
EMPLOYEE RELATIONS
As of December 31, 1993, the Company had 1,720 employees, 71% of whom were organized in six local unions with which the Company has collective bargaining agreements. In 1993, after a seventeen-week work stoppage, the Company entered into a new six-year labor contract with the bargaining units which, among other things, provides for annual general wage increases of approximately 4%, updates work rules and changes health care coverage to a managed care program with cost sharing.
ITEM 2.
ITEM 2. PROPERTIES.
The Company and Mass LNG own or lease facilities which enable them to liquefy natural gas in periods of low demand, store the resulting LNG and vaporize it for use in periods of high demand. The Company owns and operates such a facility in Dorchester, Massachusetts, and Mass LNG leases and operates one such facility in Lynn, Massachusetts, and a storage facility in Salem, Massachusetts. In addition, the Company owns propane-air facilities at several locations throughout its service territory.
In addition to the properties described above, the Company owns or leases several small buildings and miscellaneous parcels of land located throughout its service area which are used for such purposes as storage, subsidiary operations centers, district business offices and natural gas receiving stations.
The Company's gas distribution system on December 31, 1993 included approximately 5,700 miles of gas mains, 396,000 services and 519,000 active customer meters.
The Company's gas mains and services, as well as related equipment, are, in general not on land owned in fee, being in part, in, under or over public ways, land or water and, in part, upon or under private ways or other property not owned by the Company, such occupation of public and private property being, in general, pursuant to easements, licenses, permits or grants of location. Except as stated above, the principal items of property of the Company are owned in fee. A portion of the utility properties and franchises of the Company are pledged as security for the Company's First Mortgage Bonds.
In 1993, the Company's expenditures on capital expansion and improvement were $47.1 million. Capital expenditures were principally made for improvements to the distribution system, for system expansion to meet customer demand and for productivity enhancement.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
With the resolution of the John Boyd case discussed in Item 1 above, and other than normal routine litigation incidental to the Company's business, there are no material pending legal proceedings involving the Company.
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 1993.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Eastern was the holder of record of all of the outstanding common equity securities of the Company throughout the year ended December 31, 1993. Dividends on such common equity amounted to $8,998,219 and $7,712,760 for 1993 and 1992, respectively. At December 31, 1993, under the most restrictive provision limiting dividend payments in the Company's financing indentures, there were no restrictions on retained earnings.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Not required.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
1993 COMPARED TO 1992
Earnings available to common shareholders in 1993 of $18.0 million were $9.3 million lower than the prior year. Earnings in 1992 reflect a one-time increase of $7.2 million, as a result of a modification to the Company's gas cost recovery mechanism approved by the Department in May 1992. The modification shifted the recovery of a portion of pipeline gas costs from the non-heating season to the heating season to more closely match revenues with costs incurred. Excluding such modification, earnings year to year decreased $2.1 million. This decline in earnings was primarily due to the seventeen week labor dispute and increased depreciation and amortization expense. In addition, weather was 1.3% warmer than normal and 4.5% warmer than 1992.
Partially offsetting the above was a $5.0 million increase in net earnings related to the rate increase granted the Company by the Department effective November 1, 1993. The Department awarded the Company an annual revenue increase of $37.7 million, or 6.3%. During 1993, the Company added annual firm sales of approximately 2.4 BCF from the conversion of approximately 4,391 existing non-heating residences to natural gas and the addition of new customers.
Operating earnings of $49.0 million , excluding the 1992 operating earnings impact of the change in the gas cost recovery mechanism of $11.6 million, were $2.4 million lower than 1992. The increase in operating expenses was mainly due to the work stoppage and its resultant impact on expenditure capitalization. Depreciation and amortization expense increases in 1993 are principally the result of continued investments in system replacement and expansion and productivity programs. Year to year increases in property taxes also contributed to the decline in operating earnings.
1992 COMPARED TO 1991
Earnings available to common shareholders in 1992 of $27.3 million were 76% higher than 1991 earnings of $15.5 million primarily due to more seasonable weather and the modification to the Company's gas cost recovery mechanism approved by the Department effective May 1, 1992. Since the change took effect May 1, 1992, the Company recognized a one-time increase in earnings of $7.2 million; however, the modification has no impact on earnings over a 12 month period. Excluding the modification to the gas cost recovery mechanism, earnings year to year increased $4.6 million.
More seasonal weather, following unusually warm weather conditions in 1990 and 1991, produced the most favorable impact on 1992 earnings, representing a $9.1 million increase over 1991 results. 1992, which was 19% colder as compared to 1991, resulted in an increase in firm gas sales of 7.3 BCF. Growth in the firm customer base also contributed to the increase in earnings. During 1992, the Company added annual firm sales of approximately 3.1 BCF from the conversion of 4,690 existing non-heating residences to natural gas and the additional new customers.
Operating earnings, excluding the pre-tax impact of the change in the gas cost recovery mechanism of $11.6 million, were $12.2 million higher than 1991 operating earnings of $39.3 million. Operating expense
increases were primarily the result of higher labor and system maintenance costs. Depreciation and amortization expense increased in 1992 due to continued investments related primarily to customer growth, system replacement and productivity improvements. Interest expense increased in 1992 as compared to 1991 due to higher levels of average debt outstanding and reduced capitalized interest.
LIQUIDITY AND CAPITAL RESOURCES
The Company maintains four committed lines of credit totaling $40.0 million. The Company also maintains various uncommitted lines of credit and markets its own commercial paper. In addition, the Company may borrow up to $45.0 million under Eastern's credit facilities.
In accordance with the rate order issued by the Department effective October 1, 1988, the Company funds all of its gas inventory through external financing. The costs of such financing are recovered from customers through the Company's cost of gas adjustment clause. Effective December 31, 1993, the Company increased its credit capacity for fuel financing through the negotiation of a credit agreement with a group of banks which provides for borrowing of up to $90.0 million for the purpose of financing its inventory of gas supplies. The Company's' capacity under the prior agreement was $60.0 million. (See Note 4 of the Notes to Consolidated Financial Statements.)
On May 12, 1993, the Company received from its shareholder, Eastern Enterprises, a $20.0 million equity contribution, which was used to redeem $20.0 million of the Company's outstanding 9% Debentures, due 2001.
On July 13, 1993, the Registrant selected a Final Term which is a Mandatory Redemption Term with respect to its Variable Term Cumulative Preferred Stock, Series A. The dividend rate during the Final Term is 6.421% per annum and dividends are paid quarterly. The Final Term calls for 5% annual sinking fund payments beginning on September 1, 1999, is non-callable for 10 years, and shall end on September 1, 2018.
The Company expects capital expenditures for 1994 to be approximately $53.0 million. Capital expenditures will be largely for improvements to the distribution system, for system expansion to meet customer demand and for productivity enhancement. The Company also expects to incur assessment and remediation costs of approximately $1.0 million in 1994 associated with MGP sites. Such costs are recoverable in rates as discussed more fully in Note 12 of Notes to Consolidated Financial Statements.
On October 30, 1993, the Department granted the Company an annual revenue increase of $37.7 million effective November 1, 1993.
In January 1994, the Company issued $36.0 million of Medium-term Notes Series B, with a weighted average maturity of 24 years and coupon of 6.94% pursuant to a $50.0 million shelf registration statement dated October 28, 1992 on file with the SEC.
The Company believes that projected cash flow from operations, in combination with currently available resources, is sufficient to meet 1994 capital expenditures and working capital requirements, normal debt repayments and dividends to shareholders.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information with respect to this item appears commencing on Page of this Report. Such information is incorporated herein by reference.
ITEM 9.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY.
Not required.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Not required.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Not required.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not required.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES.
Information with respect to these items appears on Page of this Report. Such information is incorporated herein by reference.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES AND EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. BOSTON GAS COMPANY Registrant
By: J. F. BODANZA _________________________________ J. F.BODANZA SENIOR VICE PRESIDENT AND TREASURER (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
Dated:
Schedules other than those listed above have been omitted as the information has been included in the consolidated financial statements and related notes or is not applicable nor required.
Separate financial statements of the Company are omitted because the Company is primarily an operating company and its subsidiary is wholly-owned and is not indebted to any person in an amount that is in excess of 5% of total consolidated assets.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ACCOUNTING POLICIES
The significant accounting policies followed by the Company and its subsidiary are described below and in the following footnotes:
Note 2--Cost of Gas Adjustment Clause and Deferred Gas Costs Note 3--Income Taxes Note 6--Pension Benefits Note 7--Post-Retirement Benefits Other Than Pensions Note 8--Leases
Principles of Consolidation
The Company is a wholly-owned subsidiary of Eastern Enterprises ("Eastern"). The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Massachusetts LNG Incorporated ("Mass LNG"). All material intercompany balances and transactions between the Company and its subsidiary have been eliminated in consolidation.
Depreciation
Depreciation is provided at rates designed to amortize the cost of depreciable property, plant and equipment over their estimated remaining useful lives. The composite depreciation rate, expressed as a percentage of the average depreciable property in service, was 3.98% in 1993, 3.80% in 1992 and 3.79% in 1991.
Accumulated depreciation is charged with the original cost and cost of removal, less salvage value, of units retired. Expenditures for repairs, upkeep of units of property and renewal of minor items of property replaced independently of the unit of which they are a part are charged to maintenance expense as incurred.
Gas Operating Revenues
Gas operating revenues are recorded when billed. Revenue is not recorded for the amount of gas distributed to customers which is unbilled at the end of the period; however, the cost of this gas is deferred as discussed in Note 2.
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause requires the Company to adjust its rates semiannually for firm gas sales in order to track changes in the cost of gas distributed with an annual adjustment of subsequent rates for any collection over or under actual costs incurred. As a result, the Company defers the cost of any firm gas that has been distributed, but is unbilled at the end of a period, to a period in which the gas is billed to customers. The cost of gas adjustment clause also recovers the amortization of all environmental response costs associated with former manufactured gas plant ("MGP") sites and costs related to the Company's various conservation and load management programs.
In May of 1992, the Company modified the cost of gas adjustment clause shifting a portion of pipeline gas costs from the non-heating to the heating season in order to more closely match revenues with the related costs.
(3) INCOME TAXES
The Company is a member of an affiliated group of companies which files a consolidated federal income tax return. The Company follows the policy, established for the group, of providing for income taxes which would be payable on a separate company basis. The Company's effective income tax rate was 38.4% in 1993,
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) INCOME TAXES (CONTINUED) 39.4% in 1992 and 36.2% in 1991. State taxes represent the majority, or 4.3%, 4.6% and 4.8% of the difference between the effective rate and the Federal income tax rate for 1993, 1992 and 1991, respectively.
Effective January 1, 1992, the Company adopted Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS 109 requires adjustment of deferred tax assets and liabilities to reflect the future tax consequences, at currently enacted rates, of items already reflected in the financial statements. A regulatory asset of $1,880,000 was established for the recovery of prepaid taxes established at the higher federal tax rates in effect prior to 1988. In its most recent rate request proceeding, the Company received permission to recover this amount over three years. A regulatory liability of $6,144,000 was established for the tax benefit of unamortized investment tax credits, which SFAS 109 requires to be treated as a temporary difference. This benefit will be passed on to customers over the lives of property giving rise to the investment credits, consistent with the 1986 Tax Reform Act. About 38% of each of these items reflect a "gross-up" for taxes as SFAS 109 eliminated net-of tax accounting for regulatory assets and liabilities. The regulatory liability for excess deferred taxes being returned to customers over a 30 year period pursuant to a 1988 rate order was similarly increased by $4,445,000 upon the adoption of SFAS 109.
The Revenue Reconciliation Act of 1993, enacted on August 10, 1993, increased the statutory Federal income tax rate from 34% to 35%, retroactive to January 1, 1993. The provision for income taxes in 1993 includes approximately $300,000 for the impact of the rate change on current earnings. The effect of the rate change on deferred tax requirements at January 1, 1993 is reflected in the regulatory asset and liability established at the adoption of SFAS 109.
During 1991, deferred income taxes were provided for significant timing differences in the recognition of revenue and expenses for tax and financial statement purposes. The principal component of the 1991 deferred provision was $2,308,000 for accelerated depreciation, partially offset by a credit of $1,021,000 for deferred gas costs.
Investment tax credits are deferred and credited to income over the lives of the property giving rise to such credits. The credit to income was approximately $689,000 in 1993, $673,000 in 1992 and $692,000 in 1991.
(4) COMMITMENTS
Long-term Obligations
The First Mortgage Bonds are secured by a first mortgage lien on a portion of the Company's utility properties and franchises. The annual sinking fund requirement for the 8.375% First Mortgage Bonds is $480,000.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED) The 7.95% Sinking Fund Debentures have an annual sinking fund requirement of $425,000. The 9.0% and 8.75% Sinking Fund Debentures require annual sinking fund payments of $5,000,000 and $3,000,000, respectively, beginning in 1997.
On October 28, 1992, the Company filed a Shelf registration covering the issuance of up to $50,000,000 of additional Medium-Term Notes through December 31, 1994 for the financing of capital expenditures and the payment of related obligations. In January 1994 the Company issued $36,000,000 of Medium-Term Notes with maturities of 20 - 30 years and an average weighted interest rate of 6.94%.
The terms of the various indentures referred to above, as supplemented, provide that dividends may not be paid on common stock of the Company under certain conditions. At December 31, 1993 there were no restrictions on retained earnings available for payment of dividends.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department of Public Utilities (the Department) effective October 1, 1988, the Company funds all of its inventory of gas supplies through external sources. All costs related to this funding are recoverable from its customers. The Company maintains a credit agreement with a group of banks which provides for the borrowing of up to $90,000,000 for the exclusive purpose of funding its inventory of gas supplies or for backing commercial paper issued for the same purpose. The Company had $59,297,000 and $48,631,000 of commercial paper outstanding at December 31, 1993 and 1992, respectively, for this purpose. Since the commercial paper is supported by the credit agreement, these borrowings have been classified as non-current in the accompanying consolidated balance sheets. The credit agreement includes a 364 day revolving credit which may be converted to a two-year term loan at the Company's option if the 364 day revolving credit is not renewed by the banks. The Company may select interest rate alternatives based on prime or Eurodollar rates. No borrowings were outstanding under this agreement at December 31, 1993 and no borrowings were outstanding under the prior $60,000,000 credit agreement at December 31, 1992.
Notes Payable
The Company maintains four committed lines of credit totaling $40,000,000 which provide for interest at either prime rate or money market rates. The Company pays facility fees related to these lines of credit. In addition, the Company has various uncommitted lines of credit which provide for interest at the federal funds, money market or prime rates. These lines of credit are used for short-term borrowings. The Company had outstanding borrowings of $106,300,000 and $53,332,000 in commercial paper and bank loans not related to gas inventory financing at December 31, 1993 and 1992, respectively.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED) Eastern Borrowing Arrangement
Eastern has a credit agreement with a group of banks which provides for the borrowing by Eastern and its subsidiaries of up to $60,000,000 (of which the Company may borrow up to $35,000,000) at any time through December 31, 1994, with borrowings thereunder maturing not later than December 31, 1995. The interest rate for such borrowings is the agent bank's prime rate, or at Eastern's option, 1/4 of 1% over the agent bank's Eurodollar rate or 3/8 of 1% over the agent bank's certificate of deposit rate. Eastern has the option until December 31, 1994 to convert up to $25,000,000 of the total commitment to a five-year term loan arrangement with the same interest rate provisions through 1994 and thereafter with interest of 1/8 of 1% over the agent bank's prime rate or 5/8 of 1% over the agent bank's Eurodollar rate or 7/8 of 1% over the agent bank's certificate of deposit rate. The credit agreement provides, among other things, for a commitment fee of 1/4 of 1% on the first $50,000,000 unused portion of the commitment and 3/16 of 1% on the unborrowed portion of the commitment greater than $50,000,000.
Eastern also has a $10,000,000 line of credit under which the Company is entitled to borrow which provides for interest at the prime rate, or at Eastern's option, rates tied to Eurodollar, certificate of deposit or money market quotes.
(5) VARIABLE TERM CUMULATIVE PREFERRED STOCK
On July 13, 1993, the Company selected a Final Term which is a Mandatory Redemption Term with respect to its Variable Term Cumulative Preferred Stock, Series A. The dividend rate during the Final Term is 6.421% per annum and dividends are paid quarterly. The Final Term calls for 5% annual sinking fund payments beginning on September 1, 1999, is non-callable for 10 years, and shall end on September 1, 2018.
(6) PENSION BENEFITS
The Company, through retirement plans under collective bargaining agreements and participation in Eastern's pension plans, provides retirement benefits for substantially all of its employees. The benefits under these plans are based on stated amounts for years of service or employee's average compensation during the five years prior to retirement. The Company follows a policy of funding retirement and employee benefit plans in accordance with the requirements of the plans and agreements in sufficient amounts to satisfy the "Minimum Funding Standards" of the Employee Retirement Income Security Act of 1974 ("ERISA").
The expected long-term rate of return on assets was 8.5% in 1993 and 1992 and 7.5% in 1991. The discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% for 1993 as well as for prior years. The rate of increase in future compensation levels was 5.0%.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(6) PENSION BENEFITS (CONTINUED)
(7) POST-RETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company, through participation in Eastern administered plans and welfare plans under collective bargaining agreements, provides certain health care and life insurance benefits for retired employees.
Effective January 1, 1991, the Company adopted Statement of Financial Accounting Standards No. 106 ("SFAS 106"), "Employers' Accounting for Post-Retirement Benefits Other Than Pensions," by immediately recognizing the cumulative effect of the accounting change. SFAS 106 requires that the expected cost of post-retirement benefits other than pensions be charged to expense during the period that the employee renders service. As of the date of adoption, the cumulative effect of the accounting change ("transition obligation") was, $89,120,000. With approval by the Department, the Company has deferred the cost of the transition obligation and the amount by which expense under SFAS 106 exceeds amounts currently included in rates. The 1993 rate order allows the Company to phase in incremental costs associated with SFAS 106 over a four-year period. Each year during the phase-in, the Company will file for an increase in rates to reflect an additional increment of SFAS 106 costs. The difference between the incremental annual amount allowed in rates during the phase-in period and the SFAS 106 costs will be deferred as a regulatory asset with carrying costs.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) POST-RETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED) Prior to the 1993 rate order, the Company recognized as expense and recovered through rates billed to customers the cost of post-retirement benefits on a claims paid basis. Such costs totalled $4,437,000 in 1993, $4,110,000 in 1992 and $3,431,000 in 1991.
The Company established a 501(c)(9) Voluntary Employee Beneficiary Association ("VEBA") Trust in 1991 to begin funding its post-retirement benefit obligation for collectively bargained employees. The Company contributed $5,000,000 in 1992 to the VEBA.
The weighted average discount rate used in determining the accumulated post-retirement benefit obligation was 7.5% in 1993 and 1992. A 12% and 15% annual increase in the cost of covered health care benefits was assumed for 1993 and 1992, respectively. This rate of increase is assumed to drop gradually to 5% after 7 years. A 1% increase in the assumed health care cost trend would have increased the post-retirement benefit cost by $489,000 and $1,056,000 and the accumulated post-retirement benefit obligation by $5,691,000 in 1993 and $9,164,000 in 1992.
In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112 ("SFAS 112"), "Employer's Accounting for Postemployment Benefits", which establishes standards of financial accounting and reporting for certain postemployment benefit obligations. The adoption of SFAS 112 is not expected to have a material effect on the Company's financial condition or results of operations. SFAS 112 is effective for fiscal years beginning after December 15, 1993.
(8) LEASES
The Company and its subsidiary lease certain facilities and equipment under long-term leases which expire on various dates through the year 2000. Total rentals charged to income under all lease agreements were approximately $7,663,000 in 1993, $6,939,000 in 1992 and $6,417,000 in 1991.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(8) LEASES (CONTINUED)
Under the terms of SFAS 71, the timing of expense recognition on capitalized leases should conform with regulatory rate treatment. The Company has included the rental payments on its financing leases in its cost of service for rate purposes. Therefore, the total depreciation and interest expense that was recorded on the leases was equal to the rental payments included in other operating and maintenance expense in the accompanying consolidated statements of income.
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value disclosures for financial instruments:
Cash and Short-term Investments
The carrying amounts approximate fair value because of the short maturity of those instruments.
Short-term Debt
The carrying amounts of the Company's short-term debt, including notes payable and gas inventory financing, approximate their fair value.
Long-term Debt
The fair value of long-term debt is estimated based on currently quoted market prices for similar types of borrowing arrangements.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS (CONTINUED) Preferred Stock
The fair value of the preferred stock for 1993 is based on currently quoted market prices. For 1992 the carrying amount approximates fair value because of the frequency with which dividend rates were reset.
(10) SUPPLEMENTARY INFORMATION
The Company paid Eastern $3,096,000 in 1993, $2,707,000 in 1992 and $2,520,000 in 1991 for various legal, tax and corporate services rendered.
(11) SIGNIFICANT CUSTOMER
Firm and non-firm sales to a single customer produced revenues totaling $24,800,000 in 1993, $13,900,000 in 1992 and $18,500,000 in 1991, or 4.0%, 2.3% and 3.5% of total revenues in 1993, 1992 and 1991, respectively.
(12) ENVIRONMENTAL ISSUES
The Company is subject to local, state and federal environmental regulation of its operations and properties. The Company is working with the Massachusetts Department of Environmental Protection ("DEP") to determine the environmental impact, if any, of by-products associated with 13 former manufactured gas plant ("MGP") properties which the Company currently owns and for which the Company may be potentially responsible. The Company is currently assessing seven of these properties pursuant to applicable DEP procedures. The Company expects to spend approximately $1 million in assessing these properties in 1994 and expects similar expenditures for site assessment for the next several years as other properties are investigated. Since the DEP has not yet approved a remediation plan for any Company site, the Company cannot reliably predict the potential liability associated with final remediation of any of these properties. Company experience to date indicates that assessment and remediation costs of at least $18 million could be incurred over the next several years at these thirteen properties, subject to possible contribution or the assumption of responsibility by New England Electric System ("NEES") or one of its subsidiaries as discussed below.
Massachusetts Electric Company, a wholly-owned subsidiary of NEES, has assumed responsibility for remediating a fourteenth property currently owned by the Company (part of the site of gas manufacturing operations in Lynn, Massachusetts) pursuant to the decision of the Court of Appeals for the First Circuit in The John S. Boyd, Inc., et al. v. Boston Gas Company, et al, Civil Action No. 89-575-T (May 26, 1993). The First Circuit found that NEES and its subsidiaries, as the prior owners and operators of the Lynn MGP site, were responsible for remediating the site and that the Company did not assume any liability for environmental remediation when it acquired the property from NEES in 1973. Of the 13 other sites currently owned by the Company, 10 were acquired from NEES. Given substantial similarities between these acquisitions and that involved in Boyd, it is not probable that the Company will have any material exposure for environmental remediation at these 10 sites.
BOSTON GAS COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) ENVIRONMENTAL ISSUES (CONTINUED) There are 23 other former MGP sites within the Company's service territory which the Company does not currently own. The DEP has not issued a Notice of Responsibility to the Company for any of these 23 sites. At this time, there is substantial uncertainty as to whether the Company is responsible for remediating any of these sites either because the Company never owned the site, the Company does not have successor liability for contamination of the site by earlier operators, or site conditions do not require remediation by the Company.
By an order issued on May 25, 1990, the Department approved a settlement agreement which provides for the recovery through the cost of gas adjustment clause of all environmental response costs associated with former MGP sites over separate, seven-year amortization periods without a return on the unamoritized balance. The settlement agreement also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations.
(13) PIPELINE TRANSITION COSTS
Pursuant to Federal Energy Regulatory Commission ("FERC") Order No. 636, pipelines will be allowed to recover prudently incurred transition costs, including (1) gas supply realignment costs or the costs of renegotiating existing gas supply contracts with producers; (2) unrecovered purchased gas adjustment costs or unrecovered gas costs at the time the pipelines ceased the merchant function; (3) stranded costs or the unrecovered costs of assets that cannot be assigned to customers of unbundled services; and (4) new facilities costs or the costs of new facilities required to physically implement the order.
The Company's obligation for transition costs is $30.6 million and it has recorded this amount less actual billings at December 31, 1993 of $6.3 million as a liability in the accompanying consolidated balance sheet. As pipelines continue to incur and file for recovery of transition costs, the Company's obligation may increase.
The Company's obligation to Tennessee for transition costs is $12.0 million, based on filings by Tennessee at FERC. Payments to Tennessee for such costs commenced in October 1993. The Company's obligations to Texas Eastern and Algonquin for transition costs is $18.6 million, based on filings by Texas Eastern and Algonquin at FERC. Payments to Texas Eastern and Algonquin began in July 1993.
The Department has allowed recovery of the Company's transition costs liability over a five-year period commencing in May 1994. Accordingly, the Company has recorded a regulatory asset equivalent to the liability established at December 31, 1993.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Boston Gas Company:
We have audited the accompanying consolidated balance sheets of Boston Gas Company (a Massachusetts Corporation and wholly-owned subsidiary of Eastern Enterprises) and subsidiary as of December 31, 1993 and 1992, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Boston Gas Company and subsidiary as of December 31, 1993 and 1992 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to consolidated financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO. Boston, Massachusetts February 4, 1994
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION FOR THE TWO YEARS ENDED DECEMBER 31, 1993 (UNAUDITED)
The following table summarizes the Company's reported quarterly information for the years ended December 31, 1993 and 1992:
The above amounts vary significantly due to the seasonality of the Company's business.
SCHEDULE V
BOSTON GAS COMPANY AND SUBSIDIARY
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS)
SCHEDULE VI
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS)
SCHEDULE V
BOSTON GAS COMPANY AND SUBSIDIARY
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS)
SCHEDULE VI
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS)
SCHEDULE V
BOSTON GAS COMPANY AND SUBSIDIARY
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1991 (IN THOUSANDS)
SCHEDULE VI
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1991 (IN THOUSANDS)
SCHEDULE VIII
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS)
SCHEDULE VIII
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS)
SCHEDULE VIII
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1991 (IN THOUSANDS)
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(1) Reclassified from other accounts
SCHEDULE IX
BOSTON GAS COMPANY AND SUBSIDIARY
SHORT-TERM BORROWINGS FOR THE YEARS ENDED DECEMBER 31, 1991, 1992 AND 1993 (IN THOUSANDS)
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(A) Average daily balances. (B) Actual interest incurred divided by average amount outstanding during the year.
SCHEDULE X
BOSTON GAS COMPANY AND SUBSIDIARY
SUPPLEMENTARY EARNINGS STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)