ITEM 1. BUSINESS.
General
Boston Gas Company (the "Company") is engaged in the transportation, distribution and sale of natural gas to residential, commercial, and industrial customers in Boston, Massachusetts, and 73 other communities in eastern and central Massachusetts. The Company also sells gas for resale in Massachusetts and other states (see "Competition" section). The Company has one subsidiary, Massachusetts LNG Incorporated ("Mass LNG") which holds a long-term lease on two liquefied natural gas ("LNG") facilities. Boston Gas is the largest natural gas distribution company in New England, has been in business for 172 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 AND TRANSPORTATION
Gas is sold and transported for "firm" and "non-firm" customers. Principal uses of natural gas include central, space and water heating, cooking, drying, steam generation and a variety of industrial applications.
"Firm" sales and transportation services are generally provided without interruption throughout the year, although uninterrupted seasonal services are available to firm customers for periods of less than 365 days. Firm services are provided under either filed rate schedules or through individually negotiated contracts. Firm sales and transportation of natural gas used for central or space heating are directly related to weather conditions. Consequently, temperature variations can have a significant impact, both favorable and unfavorable, upon the Company's revenues and earnings. Compared to normal, actual billing temperatures were 1% colder, 1% warmer and 4% colder in 1994, 1993 and 1992, respectively.
"Non-firm" sales and transportation services are generally provided to large commercial and industrial customers who can use gas and oil interchangeably or to other gas distribution utilities for resale. Non-firm services are dependent upon a number of factors, including the price of gas compared to competing fuels, gas supply availability, weather conditions and system capacity, both local and interstate. Non-firm services are provided through individually negotiated contracts and, in most cases, the price charged takes into account the price of the customer's alternative fuel, which is generally residual fuel oil. Beginning November 1, 1993, gross margin from non-firm sales and transportation services ($10.9 million in 1994 and $8.2 million in 1993) in excess of a threshold based upon the prior season's experience are shared between firm customers and shareholders, 75% and 25%, respectively.
The following table provides information with respect to the volumes of gas sold and transported by the Company during the three years 1992-1994. The table is in billions of cubic feet ("BCF") of natural gas at 1,000 B.T.U. per cubic foot.
Residential heating sales include all gas sold to customers having central or space heating. Commercial sales include all gas sold to retail establishments and commercial properties including central-metered apartment houses and condominiums with five or more units. Growth in the Company's firm transportation services reflects changes in the gas industry (see "Gas Supply" and "Competition" sections).
The Company's operations are subject to Massachusetts statues applicable to gas utilities as described in the "Regulation" section. Facility expansion is regulated by the Massachusetts Department of Public Utilities (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.
GAS SUPPLY
The following table provides statistical information with respect to the Company's sources of supply during 1992-1994. The table is in BCF of natural gas at 1,000 B.T.U. per cubic foot.
The Company purchases approximately 70% of its pipeline gas supplies directly from domestic and Canadian producers and marketers pursuant to long-term contracts which have been reviewed and approved by the Department. The Company purchases its remaining pipeline supplies from domestic sources pursuant
to short-term, firm winter service agreements and on a spot basis. The Company has diversified its pipeline gas supplies across major North American producing regions, including on and off-shore Gulf of Mexico and mid-continent areas in the United States, as well as from western Canada.
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 services from underground storage fields located in West Virginia, New York and Pennsylvania. Supplemental supplies of 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 its Order No. 636. Order No. 636, issued April 8, 1992, required interstate pipeline companies to unbundle gas sales 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 Texas Eastern Transmission Corporation ("Texas Eastern"), was converted to an annual firm transportation entitlement of 87.4 BCF. Similarly, the Company's firm bundled sales service with Texas Eastern has been converted into an annual firm transportation entitlement of 102.3 BCF; and its firm bundled sales service with Tennessee Gas Pipeline Company, ("Tennessee") has been converted to an annual transportation and storage entitlement of 79.4 BCF. In addition, 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 described above and from underground storage facilities to its service territory. The Company holds direct entitlements to 17.2 BCF of storage capacity with Tennessee, Texas Eastern and others. The underlying transportation and storage agreements with Algonquin, Texas Eastern, and Tennessee have terms generally expiring no earlier than November 1996, April 2012, and November 2000, respectively. The Company is provided rights of first refusal under Order No. 636 to extend the terms of the majority of these transportation and storage contracts. The Company considers the service reliability of its natural gas portfolio 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 3.8 BCF of gas annually and expires on January 2003. The Company also has contracts with Alberta Northeast Gas, Ltd. to purchase up to 4.8 BCF of gas annually, and with Imperial Oil of Canada, Ltd. for the purchase of 12.8 BCF of gas annually. These contracts expire on November 2003 and April 2007, respectively. The Company has contracted with Iroquois Gas Transmission System, Tennessee and Algonquin to transport these gas supplies from the Canadian border to delivery points in the Company's service territory.
The Company has contracts, expiring in 1998, with Distrigas of Massachusetts Corporation ("DOMAC") for the purchase of an annual quantity of up to 2.0 BCF of LNG and for 1.0 BCF 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.
The Company relies on supplemental supplies of storage gas, LNG and propane 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. The Company owns or leases facilities which enable it to store the equivalent of 4.6 BCF 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 purchased LNG. Over the past five years, increased pipeline capacity has reduced the Company's dependence on these 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 firm customers.
REGULATION
The Company's operations are subject to Massachusetts statutes applicable to gas utilities. Rates, the territorial limit of the Company's service area, purchase of gas, pipeline safety regulations, issuance of securities and affiliated party transactions are regulated by the Department. Rates for firm sales and transportation provided by the Company are subject to approval by, and are on file with, the Department. In addition, the Company has a cost of gas adjustment clause which allows for the adjustment of billing rates for firm gas sales to enable it to recover the actual cost of gas delivered to firm customers.
On October 30, 1993, the Department allowed the Company an annual revenue increase of $37.7 million, effective November 1, 1993, and also approved several rate design changes that reduce the volatility of its margins attributable to weather. The Department also ordered a four-year phase in of postretirement benefits other than pensions. The Company began billing the second year phase-in on November 1, 1994.
Changes stemming from FERC Order 636 are being considered at state levels. The Department has initiated a proceeding to review alternative regulatory approaches, including regulation that is incentive or performance based.
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.
SEASONALITY AND WORKING CAPITAL
The Company's revenues, earnings and cash flow are highly seasonal as most of its firm sales and transportation are directly related to temperature conditions. The majority of the Company's earnings are generated in the first quarter with a seasonal loss occurring in the third quarter. Since the bulk of its revenues are billed in the November through April heating season, significant cash flows are generated from late winter to early summer. In addition, through the cost of gas adjustment clause, the Company bills its customers over the heating season for pipeline demand charges paid by the Company over the entire year. This difference, along with other costs of gas distributed but unbilled, is reflected as deferred gas costs and results in short-term borrowings. Short-term borrowings are also required from time to time to finance normal business operations. As a result of all factors, short- term borrowings are generally highest during the late fall and early winter.
COMPETITION
The Company competes with suppliers of fuel oil and electricity for residential, commercial and industrial customers. In addition, the Company faces competition from other suppliers of natural gas for large commercial and industrial applications. The Company's marketing efforts emphasize the continuing environmental benefits of natural gas, together with its reliability and long-term economic value as compared to oil and electricity. The clean burning nature of natural gas combustion and the absence of on-site fuel storage problems are major environmental advantages for natural gas.
The Company increased annualized firm throughput by an estimated 3.8 BCF during 1994 through volume additions of 2.3 BCF in the firm residential and commercial/industrial markets and additions of 1.5 BCF through special contracts and transportation arrangements.
Increased activity in new residential construction, together with the accelerated marketing efforts to encourage conversion to natural gas, resulted in the addition of 5,300 residential heating customers. Approximately 45% of the Company's existing residential customers do not use gas for central heating, representing a prime marketing opportunity. The Company targets this group through special programs with an objective of increasing the rate of conversion to natural gas.
No customer, or group of customers under common control, accounted for 3% or more of the total firm revenues in 1994.
Considerable growth opportunities exists in the commercial and industrial markets, where the Company's market penetration is only two-thirds the national average due to historical capacity limitations and the relatively late introduction of natural gas into New England. Despite low oil prices in 1994, the environmental advantages of natural gas and customers' desire for long-term value and price stability generated the highest level of new sales in this market segment in the past five years.
In June 1992, FERC granted the Company the 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.
FERC Order No. 636 and other regulatory changes have increased competition among existing and new suppliers of natural gas in the Company's service area, particularly in the large commercial and industrial sectors (see "Gas Supply"). The Company provides firm and interruptible transportation-only service to customers who may engage in direct purchases of natural gas from other suppliers. Firm transportation tariffs provide equal gross margin opportunities for the Company regardless of whether the customer purchases gas directly from the Company or purchases gas from a third party and arranges for transportation-only service on the Company's distribution system. These services allow flexibility for customers and encourage conversions to natural gas, while providing increased opportunities for the Company to increase throughput on its system and generate increased margins. The Company has also received approval from the Department to enter into contracts designed to compete for commercial and industrial customers with alternative energy options. As a result of these factors, the Company believes it is well positioned to respond to such competition.
The Company continues to pursue market opportunities in natural gas-powered vehicles as the passage of federal legislation has enhanced opportunities in this market. The City of Boston Fire Department recently removed restrictions which barred natural gas vehicles from city tunnels and major bridges, thus making the use of these vehicles more practical. The Company achieved significant progress in 1994 through cooperative efforts with state and federal government agencies to obtain access to federal funding grants for fueling station infrastructure development. This funding will help provide additional commercial and municipal fleet fueling sites in the near future. The Company's program in this market includes the installation of two Company-owned fueling stations, conversion of 103 Company vehicles and the establishment of pilot programs with a number of large fleet operations for on-site fueling to demonstrate the advantage of choosing natural gas to meet alternative fuel vehicle requirements.
ENVIRONMENTAL MATTERS
The Company may have to share responsibility for environmental remediation of certain former manufactured gas plant sites, as described in Note 11 appearing on page. A subsidiary of New England Electric System has assumed responsibility for remediating 11 of the 15 such sites owned by the Company, subject to a limited contribution by the latter. A 1990 regulatory settlement with the Department provides for recovery by the Company of environmental costs associated with such sites over separate, seven-year amortization periods without a return on the unamortized balance. Although the Company does not possess at this time sufficient information to reasonably determine the ultimate cost to it of such remediation, it believes that it is not probable that such costs will materially affect its financial condition or results of operations.
EMPLOYEES
As of December 31, 1994, the Company had 1,700 employees, 71% of whom are 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 six-year labor contracts with the bargaining units, which provided for, among other things, annual wage increases of approximately 4%, updated work rules and changed 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 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.
On December 31, 1994, the Company's distribution system included approximately 5,700 miles of gas mains, 397,000 services and 522,000 active customer meters.
The Company's gas mains and services are generally located on public ways or private property not owned by it. The Company's occupation of such property is generally 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 1994, the Company's capital expenditures were $53.5 million. Capital expenditures were principally made for improvements to the distribution system, for system expansion to meet customer demand and for productivity enhancement initiatives. The Company plans to spend approximately $58 million for similar purposes in 1995.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
With the resolution of the John Boyd case discussed in Note 11 appearing on page, 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 1994.
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, 1994. Dividends on such common equity amounted to $12,803,182 and $8,998,219 for 1994 and 1993, respectively. At December 31, 1994, 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.
1994 COMPARED TO 1993
Net earnings applicable to common stock for 1994 were $25.2 million, an increase of $7.2 million or 40% from 1993. An annual rate increase of $37.7 million, effective November 1, 1993, increased 1994 net earnings by $18.2 million. Net earnings also benefitted from increased sales to new and existing customers of
2.3 BCF. Despite record cold temperatures in early 1994, the year averaged only slightly colder than normal due to 18% warmer than normal fourth quarter weather. Weather for 1993 was essentially normal. In total, the weather decreased net earnings approximately $1.8 million after considering the higher workload related labor and operating costs associated with the unusually cold first quarter weather and the reduced sales margin attributable to the 18% warmer fourth quarter.
In addition, the above were partially offset by higher charges for property taxes, bad debts and employee benefits. Increased depreciation and amortization reflects higher allowed depreciation rates and continued investments in system replacement and expansion. Interest expense increased in 1994 primarily due to the issuance of long-term debt as well as higher rates on short-term borrowings.
1993 COMPARED TO 1992
Net earnings available to common shareholders in 1993 of $18.0 million were $9.3 million lower than the prior year. Net 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, net earnings year to year decreased $2.1 million. This decline in net 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.
LIQUIDITY AND CAPITAL RESOURCES
The Company maintains 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 $75.0 million under Eastern's credit agreement.
During 1994 the Company issued $50.0 million of Medium-term Notes Series B, with a weighted average maturity of 21 years and a coupon of 7.20% pursuant to a $50.0 million shelf registration statement dated October 28, 1992 on file with the SEC.
Short-term borrowings at December 31, 1994 were $62.5 million, a decrease of $43.8 million from December 31, 1993 primarily reflecting the use of proceeds from the Medium-term note issuance mentioned above. Cash from operations for 1994 was sufficient to cover dividends to shareholders, capital expenditures and normal debt repayments.
The Company expects capital expenditures for 1995 to be approximately $58.0 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 believes that projected cash flow from operations, in combination with currently available resources, is sufficient to meet 1995 capital expenditure 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.
(3) LIST OF EXHIBITS.
There were no reports on Form 8-K filed in the Fourth Quarter of 1994. - -------- * Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules and Regulations under the Securities Exchange Act of 1934, reference is made to the document previously filed with the Commission.
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
J.F. Bodanza By: _________________________________ J.F. BODANZA SENIOR VICE PRESIDENT AND TREASURER (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
Dated: March 16, 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 INDICATED ON THE 16TH DAY OF MARCH 1995.
SIGNATURE TITLE
C. R. Messer Director and - ------------------------------------- President C. R. MESSER
A. J. DiGiovanni Director and Senior Vice - ------------------------------------- President A. J. DIGIOVANNI
J. F. Bodanza Director and Senior Vice President - ------------------------------------- andTreasurer (Principal Financial J. F. BODANZA andAccounting Officer)
J. A. Ives Director - ------------------------------------- J. A. IVES
R. R. Clayton Director - ------------------------------------- R. R. CLAYTON
W. J. Flaherty Director - ------------------------------------- W. J. FLAHERTY
BOSTON GAS COMPANY AND SUBSIDIARY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES (INFORMATION REQUIRED BY ITEMS 8 AND 14 (A) OF FORM 10-K)
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.
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDER'S INVESTMENT
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF EARNINGS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
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 Boston Gas Company (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--Postretirement 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.
Regulatory Assets
The Company is subject to provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent certain costs that will be recovered from customers through current and future rates. The following regulatory assets were reflected in the Consolidated Balance Sheets as of December 31:
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 5.16% in 1994, 3.98% in 1993 and 3.80% in 1992.
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.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 1992, the Company modified the cost of gas adjustment clause by 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 that 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 39.5% in 1994, 38.4% in 1993 and 39.4% in 1992. State taxes represent the majority, or 4.3%, 4.3% and 4.6% of the difference between the effective rate and the Federal income tax rate for 1994, 1993 and 1992, respectively.
A summary of the provision for income taxes for the three years ended December 31 is as follows:
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. At December 31, 1994 the balance of the regulatory asset was $1,097,000. 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. The balance at December 31, 1994 was $5,045,000. 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. At December 31, 1994 the balance to be returned to customers was $8,296,000.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (3) INCOME TAXES (CONTINUED)
The Revenue Reconciliation Act of 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.
For income tax purposes, the Company uses accelerated depreciation and shorter depreciation lives permitted by the Internal Revenue Service. Deferred federal and state taxes are provided for the tax effects of all temporary differences between financial reporting and taxable income. Significant items making up deferred tax liabilities and deferred tax assets at December 31, 1994 and 1993, are as follows:
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 $724,000 in 1994, $689,000 in 1993 and $673,000 in 1992.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations, less the current portion, as of December 31, 1994 and 1993, respectively.
The First Mortgage Bonds are secured by a first mortgage lien on a portion of the Company's utility properties and franchises.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
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. During 1994 the Company issued all $50,000,000 of Medium-Term Notes with a weighted average maturity of 21 years and a coupon rate of 7.20%. The Series B Notes include $12,000,000 maturing in 2006 with a put option at par in 1999 and an interest rate step up from 8.09% to 8.59% in 1999.
The aggregate consolidated annual sinking fund requirements, less amounts acquired in advance, and current maturities of long-term debt for the next five years are as follows:
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, 1994, under the most restrictive of these provisions, 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 $53,578,000 and $59,297,000 of commercial paper outstanding at December 31, 1994 and 1993, 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 and requires a facility fee of 1/10 of 1% on the commitment. No borrowings were outstanding under this agreement at December 31, 1994 and 1993.
Notes Payable
The Company maintains committed lines of credit totaling $40,000,000 which provide for interest based on prime or money market rates.
These lines of credit are used to back commercial paper and for short-term borrowings. The Company pays facility fees of seven basis points 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 uncommitted lines of credit are used for short-term borrowings. The Company had outstanding borrowings of $62,530,000 and $106,300,000 in commercial paper and bank loans not related to gas inventory financing at December 31, 1994 and 1993, respectively. The weighted average interest rate on these borrowings at December 31, was 5.9% in 1994 and 3.5% in 1993.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (4) COMMITMENTS (CONTINUED)
Eastern Borrowing Arrangement
During 1994, Eastern negotiated a credit agreement with a group of banks which provides for the borrowing by Eastern of up to $100,000,000 (of which the Company may borrow up to $75,000,000) at any time through December 31, 1999. The interest rate for such borrowings is the agent bank's prime rate, or at Eastern's option, various alternatives.
(5) PREFERRED STOCK
In 1992, the Company sold 1,200,000 shares of variable-term cumulative preferred stock, which is non-voting and has a liquidation value of $25 per share. In 1993 the Company selected a Final Term of September 1, 2018 and fixed the dividend rate at 6.421%, payable quarterly. The Final Term requires 5% annual sinking fund payments beginning on September 1, 1999. The preferred stock can not be called prior to 2003.
(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").
Net pension cost included the following components:
For the periods 1994, 1993 and 1992, the expected long-term rate of return on assets was 8.5%, the discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% and 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)
The following table sets forth the funded status of pension plans and amounts recognized in the Company's consolidated balance sheets based on a measurement date as of October 1, 1994 and 1993.
(7) POSTRETIREMENT 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 Postretirement Benefits Other Than Pensions," by immediately recognizing the cumulative effect of the accounting change. SFAS 106 requires that the expected cost of postretirement 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 requested in rates during the phase-in period and the full SFAS 106 costs will be deferred as a regulatory asset with carrying costs.
Net postretirement benefit cost included the following components:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED)
The following table sets forth the funded status of the plans and amounts recognized in the Company's consolidated balance sheets based on a measurement date as of October 1, 1994 and October 1, 1993.
The Company established a 501(c) (9) Voluntary Employee Beneficiary Association ("VEBA") Trust in 1991 to begin funding its postretirement benefit obligation for collectively bargained employees. There were no contributions to the VEBA in 1994 or 1993. Plan assets are invested in equity securities, fixed- income investments and money market instruments.
The weighted average discount rate used in determining the accumulated post- retirement benefit obligation was 7.5% in 1994 and 1993. An 11% and 12% annual increase in the cost of covered health care benefits was assumed for 1994 and 1993, 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 postretirement benefit cost by $529,000 in 1994 and $489,000 in 1993, and the accumulated postretirement benefit obligation by $6,302,000 in 1994 and $5,691,000 in 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 2001. Total rentals charged to income under all lease agreements were approximately $6,040,000 in 1994, $7,663,000 in 1993 and $6,939,000 in 1992.
The Company capitalizes its financing leases which include liquefied natural gas facilities and an operations center. A summary of property held under capital leases as of December 31, 1994 and 1993 is as follows:
Under the terms of SFAS No. 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
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (8) LEASES (CONTINUED)
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 earnings.
The Company also has various operating lease agreements for office facilities and other equipment. The remaining minimum rental commitment for these and all other noncancellable leases, including the financing leases, at December 31, 1994 is as follows:
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value disclosures for financial instruments:
Cash
The carrying amounts approximate fair value.
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.
Preferred Stock
The fair value of the preferred stock for 1994 and 1993 is based on currently quoted market prices.
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1994 and 1993 are as follows:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(10) SUPPLEMENTARY INFORMATION
The Company paid Eastern $3,669,000 in 1994, $3,096,000 in 1993 and $2,707,000 in 1992 for various legal, tax and corporate services rendered.
(11) ENVIRONMENTAL ISSUES
The Company is party to governmental actions requiring investigation and possible remediation of former manufactured gas plant ("MGP") sites. The Company currently owns fifteen former MGP sites. Massachusetts Electric Company (MEC), a wholly-owned subsidiary of New England Electric System ("NEES"), has assumed full responsibility for remediating one such MGP site in Lynn, Massachusetts, pursuant to the decision of the First Circuit Court of Appeals in The John S. Boyd, Inc., et al. v. Boston Gas Company, et al, which affirmed that NEES and its subsidiaries are responsible for remediating the site as prior owners and operators. Pursuant to a recent settlement agreement between MEC and the Company (the "Settlement Agreement"), MEC also assumed responsibility for remediating another ten of the sites owned by the Company, subject to limited contribution by the Company. The Company will work with the Massachusetts Department of Environmental Protection (the "DEP") to determine the extent of remediation which may be required at the four remaining owned sites not covered by the Settlement Agreement or Boyd. The Company expects to spend approximately $1 million in 1995 for assessment and contribution costs associated with the Company's and MEC's site investigations. Since the DEP has not yet approved a remediation plan for any of these sites, the Company does not possess at this time sufficient information to reasonably determine the ultimate cost of remediation, but believes that it is not probable that such costs will materially affect the Company's financial condition or results of operations, particularly given the Company's limited potential responsibility as a result of the Settlement Agreement. Company experience to date indicates that assessment and remediation costs of approximately $15 million could be paid by the Company with respect to these ten sites covered by the Settlement Agreement and the four other currently owned sites.
The Company is aware of 25 other former MGP sites within the Company's service territory which the Company does not currently own. MEC has provided full indemnification of Boston Gas with respect to eight of these sites in the Settlement Agreement. At this time, there is substantial uncertainty as to whether the Company is responsible for remediating any of the other sites either because the Company does not have successor liability for contamination of these sites by earlier operators or site conditions do not require remediation by the Company. The DEP has not issued a Notice of Responsibility to the Company for any of these sites.
By a rate order issued on May 25, 1990, the Department approved 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 rate order also provides for no further investigation of the prudency of any Massachusetts gas utility's past MGP operations.
(12) PIPELINE TRANSITION COSTS
Pursuant to Federal Energy Regulatory Commission (FERC) Order No. 636, pipelines are currently recovering 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 uncovered 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 estimate of its obligation for transition costs is $41.6 million at December 31, 1994 and it has recorded this amount less actual billings of $30.0 million as a liability in the accompanying consolidated
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (12) PIPELINE TRANSITION COSTS (CONTINUED)
balance sheet. As pipelines continue to file for recovery of transition costs, the Company's obligation may increase.
The Company's obligations to Texas Eastern and Algonquin for transition costs is $14.6 million, based on a Texas Eastern settlement agreement and filings made by Texas Eastern and Algonquin at FERC. Payments to Texas Eastern and Algonquin began in July 1993. The Company's obligation to Tennessee for transition costs is $26.2 million, based on filings by Tennessee at FERC. Payments to Tennessee for such costs commenced in October, 1993. Obligations to other pipeline companies are approximately $.8 million.
The Department allowed recovery of the Company's transition costs liability over a five-year period commencing in May 1994. In June 1994, the Department opened a generic investigation to set standards for recovery of Order 636 costs. The parties involved have proposed to recover costs from both sales and transportation customers on a current basis, with the ability to amortize costs depending upon customer bill impact. An order is expected in 1995. Accordingly, at December 31, 1994 the Company has recorded a regulatory asset of $34.4 million and deferred gas costs of $6.5 million which, taken together plus recoveries to date, is equivalent to the Company's total estimated obligation for transition costs.
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, 1994 and 1993, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These consolidated 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 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 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, 1994 and 1993 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, 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 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 LLP
Boston, Massachusetts January 27, 1995
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION FOR THE TWO YEARS ENDED DECEMBER 31, 1994 (UNAUDITED)
The following table summarizes the Company's reported quarterly information for the years ended December 31, 1994 and 1993:
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1994 (IN THOUSANDS)
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS)
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS)