ITEM 1. BUSINESS.
GENERAL
Boston Gas Company (the "Company"), is engaged in the transportation and sale of natural gas to approximately 530,000 residential, commercial and industrial customers in Boston, Massachusetts and 73 other communities in eastern and central Massachusetts. The Company also sells gas for resale. The Company has one subsidiary, Massachusetts LNG Incorporated ("Mass LNG"), which held a long-term lease on two liquefied natural gas ("LNG") facilities and now operates the facilities pursuant to an agreement (see Item 2, Properties). The Company is the largest natural gas distribution company in New England, has been in business for 175 years and is the second oldest gas company in the United States. All of the common stock of the Company is held by Eastern Enterprises ("Eastern"), which is headquartered in Weston, Massachusetts. Eastern has owned Boston Gas Company since 1929.
For definition of certain industry specific terms, see the Glossary at the end of Part I and appearing on page 6.
The Company provides both local transportation services and gas supply for all customer classes. All residential customers currently purchase combined or "bundled" supply and transportation services from the Company. In 1993, the Massachusetts Department of Telecommunications and Energy, formerly the Department of Public Utilities ("the Department") approved the Company's proposal to unbundle local transportation service and gas sales service for its 450 largest commercial and industrial customers. In November 1996, the Department approved the Company's proposal to offer unbundled transportation service to all of its commercial and industrial customers, numbering over 41,000. As of December 31, 1997, 2,174 customers have chosen to purchase gas from 22 qualified third party suppliers. The Company views these third party suppliers as trade allies in marketing gas and increasing its throughput and expects to work closely with them to facilitate the unbundling process and ensure a smooth transition, especially in the tracking and processing of transactions. While the migration of customers from firm sales to transportation-only service will lower the Company's revenues, it has no impact on the Company's operating earnings. The Company earns all of its margins on the local distribution of gas and none on the resale of the commodity itself. The Company has implemented a program to educate commercial and industrial customers about the opportunity to purchase gas from third- party suppliers, while still relying on the Company for delivery.
The Company offers both firm and non-firm services. Firm local transportation services and sales are provided under rate tariffs or contracts filed with the Department that typically obligate the Company to provide service without interruption throughout the year. Non-firm transportation services and sales are generally provided to large commercial and industrial customers who can use gas and oil interchangeably. Non-firm services, including sales to other gas companies for resale, are provided through individually negotiated contracts and, in most cases, the price charged takes into account the price of the customer's alternative fuel.
In the fourth quarter of 1997, the Company recorded $8.7 million of restructuring charges in connection with its decision to exit the gas appliance repair and service business. This will allow the Company to focus on its core business of local transportation and expanding throughput on its system.
MARKETS AND COMPETITION
The Company competes with other fuel distributors, primarily oil dealers, throughout its service territory. Over the last six years, the Company has increased its share in the total stationary energy market from 31% to 37%. This market share compares to the national level of approximately 44%, and may represent a growth opportunity for the Company. However, actual experience cannot be predicted with certainty, and will depend on such factors as the price of competitive energy sources, the level of investment by the Company and customer perceptions of relative value.
GAS THROUGHPUT
The following table, in billions of cubic feet of natural gas at 1,000 Btu per cubic foot ("BCF") provides information with respect to the volumes of gas delivered by the Company during the three years 1995-1997.
Residential customers comprise 92% of its customer base, while commercial and industrial establishments account for the remaining 8%. Volumetrically, residential customers account for 26% of total throughput and 35% of total firm throughput, while commercial and industrial customers account for 74% of total throughput and 65% of total firm throughput. In 1997, approximately 70% of commercial and industrial customers' total throughput was local transportation-only services; Boston Edison Company, an electric utility on the Company's system, accounted for approximately 44% of the commercial and industrial local transportation throughput.
No customer, or group of customers under common control, accounted for 2% or more of total firm revenues in 1997.
GAS SUPPLY
The following table in BCF provides statistical information with respect to the Company's sources of supply during 1995-1997.
Year to year variations in storage gas and unbilled gas reflect variations in end-of-year customer requirements, due principally to weather. Given the ready availability of supply, the Company purchased approximately two-thirds of its peak pipeline supplies under firm short-term and spot contracts. The balance of peak day pipeline requirements is purchased directly from domestic and Canadian producers and marketers pursuant to long-term contracts which have been reviewed and approved by the Department or by the Federal Energy Regulatory Commission ("FERC").
Pipeline supplies are transported on interstate pipeline systems to the Company's service territory pursuant to long-term contracts. FERC-approved tariffs provide for fixed demand charges for the firm capacity rights
under these contracts. The interstate pipeline companies that provide firm transportation service to the Company's service territory, the peak daily and annual capacity and the contract expiration dates are as follows:
In addition, the Company has firm capacity contracts on interstate pipelines upstream of Algonquin and Tennessee pipelines to transport natural gas purchased by the Company from producing regions to the Algonquin and Tennessee pipelines. In total, contracts comprising 59% of the Company's peak day pipeline capacity entitlements expire before 2001.
The Company has contracted with pipeline companies and others for the storage of natural gas in underground storage fields located in Pennsylvania, New York, Maryland and West Virginia. These contracts provide storage capacity of 17.3 BCF and peak day deliverability of 0.16 BCF. The Company utilizes its existing transportation contracts to transport gas from the storage fields to its service territory. Supplemental supplies of LNG and propane are purchased and produced from foreign and domestic sources.
Peak day throughput in BCF was 0.66 in 1997 and 0.69 in 1996 and 1995. The Company provides for peak period demand through a least cost portfolio of pipeline, storage and supplemental supplies. The Company considers its peak day send out capacity, based on its total supply resources, to be adequate to meet the requirements of its firm customers.
REGULATION
The Company's operations are subject to Massachusetts statutes applicable to gas utilities. Rates, gas purchases, pipeline safety regulations, issuance of securities, and affiliate transactions are regulated by the Department. Rates for firm transportation and sales 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 that 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, including the demand charges for capacity on the interstate pipeline system.
On May 16, 1997 the Company received a response from the Department concerning its request for reconsideration, clarification and recalculation of the Department's November 1996 rate order. The Department granted an additional $1.9 million in revenues (a $6.3 million increase was granted in the November 1996 Order) and reduced the productivity offset portion of the Performance-Based Rate ("PBR") formula established in its November 1996 Order by 50 basis points, from 2.00% to 1.50%. Compared to the Department's original decision these changes will add approximately $3.5 million to projected revenue in 1998, increasing to about $8.0 million by 2002, the last year of the plan. The Department also made modifications to the service quality measures requested by the Company, but left unchanged the Company's maximum annual exposure of $5.0 million for failing to achieve them. On June 5, 1997, the Company filed a notice of appeal of the Department's orders to the Massachusetts Supreme Judicial Court. The Company expects that the appeal will take approximately one year, and that any relief granted by the court will be prospective.
On July 18, 1997, the Department directed all ten investor-owned gas distribution companies in Massachusetts to undertake a collaborative process with other stakeholders to develop common principles under which comprehensive gas service unbundling might proceed. The Department deferred the second phase of the Company's unbundling proceeding, which is to address residential unbundling and a permanent capacity assignment method, subject to its assessment of the progress of the collaborative discussions.
On November 7, 1997, the Department approved rate schedules designed to implement the Company's $1.8 million rate increase approved by the Department in the Company's first annual performance-based regulatory plan compliance proceeding.
In its November 1996 order, the Department also approved the Company's proposal to facilitate competition in the natural gas marketplace. Under the approved service unbundling program, on an interim basis, eligible commercial and industrial customers migrating from firm sales to firm transportation will be assigned, at cost, a pro-rata share of the upstream pipeline capacity purchased by the Company to serve them. At the Department's direction, permanent assignment of upstream pipeline capacity is currently being addressed as part of the collaborative process discussed above. The capacity assignment method ultimately approved by the Department could permit capacity to be acquired by marketers at less than cost. If that proves to be the case, there can be no assurance that the Company will be permitted to recover such costs until the Department has addressed their recoverability. The collaborative is also examining how to extend unbundled transportation service to residential customers.
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.
SEASONALITY AND WORKING CAPITAL
The Company's revenues, earnings and cash flow are highly seasonal as most of its transportation services and sales 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 majority 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 the majority of the 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 is financed through short-term borrowings. Short-term borrowings are also required from time to time to finance normal business operations. As a result of these factors, short-term borrowings are generally highest during the late fall and early winter.
ENVIRONMENTAL MATTERS
The Company may have or share responsibility under applicable environmental law for the remediation of former manufactured gas plant ("MGP") sites. Information with respect to the remediation of MGP sites may be found in Note 12 of Notes to Consolidated Financial Statements. Such information is incorporated herein by reference.
EMPLOYEES
As of December 31, 1997, the Company had approximately 1,440 employees, 74% of whom are organized in local unions with which the Company has collective bargaining agreements that expire in 1999.
ITEM 2.
ITEM 2. PROPERTIES.
The Company and Mass LNG operate 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. Mass LNG leased one such facility located in Lynn, Massachusetts and a storage facility in Salem, Massachusetts under a lease that expired on June 30, 1997. Negotiations for the purchase of the facilities stalled and the matter is now in litigation (see Item 3, Legal Proceedings). Mass LNG continues to operate the facilities pursuant to a stipulation and agreement between the
parties that provides for $2.3 million to be held in escrow and suspends Mass LNG's rent payment obligation while the stipulation and agreement is in effect. The stipulation and agreement terminates on the earlier of the resolution by judgment or October 1, 1998.
The Company owns propane-air facilities at several locations throughout its service territory.
On December 31, 1997, the Company's distribution system included approximately 5,800 miles of gas mains, 401,000 services and 534,000 active customer meters. A majority of the gas mains consist of cast iron and bare steel, which require ongoing maintenance and replacement.
The Company's gas mains and services are usually located on public ways or private property not owned by it. In general, the Company's occupation of such property is 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.
In 1997, the Company's capital expenditures were $55.4 million. Capital expenditures were principally made for improvements to the distribution system, for system expansion to meet customer demand and for productivity improvements. The Company plans to spend approximately $59 million for similar purposes in 1998.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
On May 6, 1997, Mass LNG filed suit against the Industrial National Leasing Corp. ("INLC") in Suffolk Superior Court, Massachusetts. This action results from the parties' being unable to reach agreement relative to Mass LNG's purchase rights set forth in the lease agreement under which Mass LNG leased two LNG facilities from INLC (see Item 2, Properties). The complaint seeks a judicial determination of the parties' rights under the lease.
Other than the Mass LNG litigation and 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 1997.
GLOSSARY
BUNDLED SERVICE--Two or more services tied together as a single product. Services include gas sales at the city gate, interstate transportation, local transportation, balancing daily swings in customer loads, storage, and peak- shaving services.
CAPACITY--The capability of pipelines and supplemental facilities to deliver and/or store gas.
CITY GATE--Physical interconnection between an interstate pipeline and the local distribution company.
CORE CUSTOMER--Generally, customers with no readily available energy services alternative.
FIRM SERVICE--Sales and/or transportation service provided without interruption throughout the year. Uninterrupted seasonal services are also available for less than 365 days. Firm services are provided under either filed rate tariffs or through individually negotiated contracts.
GAS MARKETER (BROKER)--A non-regulated buyer and seller of gas.
INTERSTATE TRANSPORTATION--Transportation of gas by an interstate pipeline to the city gate.
LOCAL DISTRIBUTION COMPANY (LDC)--A utility that owns and operates a gas distribution system for the delivery of gas supplies from the city gate to end-user facilities.
LOCAL TRANSPORTATION SERVICE--Transportation of gas by the LDC from the city gate to the customer's burner tip.
NON-CORE CUSTOMERS--Generally, those customers with readily available, economically viable alternatives to gas.
NON-FIRM SERVICE--Sales and transportation service offered at a lower level of reliability and cost. Under this service, the LDC can interrupt customers on short notice, typically during the winter season. 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 energy alternative.
PERFORMANCE-BASED REGULATORY PLAN--Incentive ratemaking mechanism, typically a price cap plan, where rates are adjusted annually pursuant to a pre- determined formula tied to a measure of inflation, less a productivity offset, subject to the achievement of service quality measures and the incurrence of exogenous costs.
THROUGHPUT--Gas volume delivered to customers through the LDC's gas distribution system.
UNBUNDLED SERVICE--Service that is offered and priced separately, such as separating the cost of gas commodity delivered to the LDC's city gate from the cost of transporting the gas from the city gate to the end user. Unbundled services can also include daily or monthly balancing, back-up or stand-by services and pooling. With unbundled services, customers have the opportunity to select only the services they desire.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'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, 1997. Dividends on such common equity amounted to $18.3 million and $14.7 million for 1997 and 1996, respectively.
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.
1997 COMPARED TO 1996
Net earnings applicable to common stock for 1997 were $36.6 million, an increase of $7.5 million or 26% as compared to 1996. This increase primarily reflects growth in throughput, lower operating expenses, the full year impact of the 1996 rate order and a $2.0 million gain on the settlement of pension obligations, partially offset by the margin impact of lower average customer usage and warmer weather and a higher charge for depreciation reflecting continued investment in system replacement and expansion. Weather for 1997 was 3% colder than normal but 2% warmer than 1996. Although weather for 1997 was 2% warmer than 1996, weather for the first quarter of 1997, when the Company generates most of its revenues and earnings, was 9% warmer than the prior year. The Company recorded a restructuring charge of approximately $8.7 million in the fourth quarter of 1997, reflecting management's decision to exit the gas appliance repair and service business (See Note 10 of Notes to Consolidated Financial Statements). The earnings impact of this non-recurring charge was offset by a non-recurring increase in revenues as described below.
Revenues in 1997 decreased by 0.6% primarily because of lower average customer usage, the migration of customers from firm sales to transportation- only service, and the impact of comparatively warmer weather, partially offset by sales to new customers and the full year impact of the 1996 rate order. The migration of customers from firm sales to transportation-only service has no impact on the Company's earnings. The Company earns all of its margins on the local distribution of gas and none on the sale of the commodity itself.
During the fourth quarter of 1997, the Company recorded a non-recurring increase in revenues of approximately $8.9 million related to a change as a result of the 1996 rate ruling in the recovery mechanism for the portion of bad debt expense associated with gas costs.
1996 COMPARED TO 1995
Net earnings applicable to common stock for 1996 were $29.1 million, an increase of $5.8 million or 25% from 1995. This increase primarily reflects colder billing temperatures, increased customer demand, and the absence of reengineering related charges. Weather for 1996 was 4% colder than normal and 5% colder than 1995. These factors were somewhat offset by higher operating expenses, principally wages, benefits and marketing related costs. Increased depreciation and property tax expense reflect continued investment in system expansion and replacement.
The reduction in interest expense reflects the refinancing during the fourth quarter of 1995 and lower borrowing requirements.
LIQUIDITY AND CAPITAL RESOURCES
To meet cash requirements and support its commercial paper program, the Company has available up to $75.0 million of Eastern's committed credit agreement and a $40.0 million uncommitted line of credit. The Company also maintains a bank credit agreement which provides for the borrowing of up to $70.0 million for
the exclusive purpose of funding its inventory of gas supplies or to back commercial paper issued for the same purpose.
The Company expects capital expenditures for 1998 to be approximately $59 million. Capital expenditures will be largely for improvements to the distribution system, for system expansion to meet customer demand and for productivity improvements.
The Company believes that projected cash flow from operations, in combination with currently available resources, is more than sufficient to meet 1998 capital expenditures and working capital requirements, dividends to shareholders and normal debt repayments. The foregoing forward-looking statement involves risks and uncertainties. The Company's actual experience may differ materially from its current expectation for various reasons, including unexpected capital expenditures or working capital requirements. Moreover, there can be no assurance that the external capital resources currently available will continue to be available or will be available on terms and conditions advantageous to the Company.
OTHER MATTERS
On May 16, 1997 the Company received a response from the Department concerning its request for reconsideration, clarification and recalculation of the Department's November 1996 rate order. The Department granted an additional $1.9 million in revenues (a $6.3 million increase was granted in the November 1996 Order) and reduced the productivity offset portion of the Performance-Based Rate ("PBR") formula established in its November 1996 Order by 50 basis points, from 2.00% to 1.50%. Compared to the Department's original decision, these changes will add approximately $3.5 million to projected revenue in 1998, increasing to about $8.0 million by 2002, the last year of the plan. The Department also made modifications to the service quality measures requested by the Company, but left unchanged the Company's maximum annual exposure of $5.0 million for failing to achieve them. On June 5, 1997, the Company filed a notice of appeal of the Department's orders to the Massachusetts Supreme Judicial Court. The Company expects that the appeal will take approximately one year, and that any relief granted by the court will be prospective.
On July 18, 1997, the Department directed all ten investor-owned gas distribution companies in Massachusetts to undertake a collaborative process with other stakeholders to develop common principles under which comprehensive gas service unbundling might proceed. The Department deferred the second phase of the Company's unbundling proceeding, which is to address residential unbundling and a permanent capacity assignment method, subject to its assessment of the progress of the collaborative discussions.
On November 7, 1997, the Department approved rate schedules designed to implement the Company's $1.8 million rate increase approved by the Department in the Company's first annual performance-based regulatory plan compliance proceeding.
In its November 1996 order, the Department also approved the Company's proposal to facilitate competition in the natural gas marketplace. Under the approved service unbundling program, on an interim basis, eligible commercial and industrial customers migrating from firm sales to firm transportation will be assigned, at cost, a pro-rata share of the upstream pipeline capacity purchased by the Company to serve them. At the Department's direction, permanent assignment of upstream pipeline capacity is currently being addressed as part of the collaborative process discussed above. The capacity assignment method ultimately approved by the Department could permit capacity to be acquired by marketers at less than cost. If this proves to be the case, there can be no assurance that the Company will be permitted to recover such costs until the Department has addressed their recoverability. The restructuring collaborative is also examining how to extend unbundled transportation service to residential customers.
The Company may have or share responsibility under applicable environmental law for the remediation of 17 former manufactured gas plant ("MGP") sites, as described in Note 12 of Notes to Consolidated Financial Statements. A subsidiary of New England Electric System ("NEES") has assumed responsibility for remediating
10 of these sites, subject to a limited contribution from the Company. The Company has recorded a liability of $19.5 million, which represents its best estimate at this time of remediation costs, which may reasonably be estimated to range from $17 million to $31 million. However, there can be no assurance that such costs will not vary considerably from these estimates.
By a rate order issued on May 25, 1990, the Department approved the recovery of all prudently incurred environmental response costs associated with former MGP sites over separate, seven-year amortization periods, without a return on the unamortized balance. The Company has recognized an insurance receivable of $3.4 million, reflecting a negotiated settlement with an insurance carrier for environmental expense indemnity, and a regulatory asset of $16.1 million, representing the expected rate recovery of environmental remediation costs, net of the insurance settlement. The Company currently believes, in light of the indemnity agreement with the NEES subsidiary and the Department rate order on environmental cost recovery, that it is not probable that such costs will materially affect its financial condition or results of operations.
The Company has assessed the impact of the year 2000 with respect to its information systems and is currently modifying those systems as part of a plan which the Company believes will provide year 2000 compliance. Anticipated spending for these modifications is being expensed as incurred and is not expected to have a material impact on operating results or financial condition.
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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
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 1997. - -------- * 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
By: /s/ J.F. Bodanza ----------------------------------- J.F. BODANZA SENIOR VICE PRESIDENT AND TREASURER (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
Dated:
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 2ND DAY OF MARCH 1998.
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 accounting policies of Boston Gas Company (the "Company") conform to generally accepted accounting principles and reflect the effects of the ratemaking process in accordance with Statement of Financial Accounting Standards No. 71 ("SFAS 71"), "Accounting for the Effects of Certain Types of Regulation".
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--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.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation and Operations
The Company is a gas distribution company engaged in the transportation and sale of natural gas to residential, commercial and industrial customers. The Company's service territory includes Boston and 73 other communities in eastern and central Massachusetts.
The Company's operations are subject to Massachusetts statutes applicable to gas utilities. Its revenues, earnings and cash flows are highly seasonal, as most of its throughput is directly related to temperature levels.
Regulatory Assets and Liabilities
The Company is regulated as to rates, accounting and other matters by the Massachusetts Department of Telecommunications and Energy ("the Department"). Therefore, the Company accounts for the economic effects of regulation in accordance with the provisions of SFAS 71. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs or (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another regulation. The Company has reviewed these criteria and believes that the continuing application of SFAS 71 is appropriate.
Regulatory assets have been established that represent probable future revenue to the Company associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with the amounts that are to be credited to customers through the ratemaking process.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(1) ACCOUNTING POLICIES (CONTINUED)
The following regulatory assets were reflected in the Consolidated Balance Sheets as of December 31:
Regulatory liabilities total approximately $10,371,000 and $11,446,000 at December 31, 1997 and 1996 and relate primarily to income taxes.
As of December 31, 1997 all of the Company's regulatory assets and regulatory liabilities are being reflected in rates charged to customers over periods ranging from 1 to 22 years. For additional information regarding deferred income taxes, postretirement benefit costs, environmental costs and Order 636 transition costs, see footnotes 3, 7, 12 and 13, respectively.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 121 ("SFAS 121") "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" which became effective for 1996, establishes accounting standards for the impairment of long-lived assets. SFAS 121 also requires that regulatory assets that are no longer probable of recovery through future revenues be charged to earnings. SFAS 121 did not have an impact on the Company's financial position or results of operations in 1997 and 1996.
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 5.19% in 1997, 5.15% in 1996 and 5.13% in 1995.
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 ("CGAC") requires the Company to adjust its rates semi-annually 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. In its order of November 29, 1996 ("the 1996 Rate Order"), the Department modified the CGAC to
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS (CONTINUED)
recover the gas cost portion of the Company's bad debt write-offs effective December 1, 1996. The order also granted a local distribution adjustment clause ("LDAC") to recover the amortization of all environmental response costs associated with former manufactured gas plant ("MGP") sites, FERC Order 636 transition costs and costs related to the Company's various conservation and load management programs from the Company's firm sales and transportation customers. These costs were previously recovered through the CGAC.
(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 that would be payable on a separate company basis. The Company's effective income tax rate was 36.9% in 1997, which includes the effect of 1.8% related to prior years tax benefits, 39.2% in 1996 and 39.1% in 1995. State taxes represent the majority of the difference between the effective rate and the Federal income tax rate for 1997, 1996 and 1995.
A summary of the provision for income taxes for the three years ended December 31 is as follows:
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
At December 31, 1997 the Company has a regulatory liability of $3,255,000 which represents the tax benefit of unamortized investment tax credits. This benefit is being passed on to customers over the lives of property giving rise to the investment credit. The Company also has a regulatory liability for excess deferred taxes being returned to customers over a 30 year period pursuant to a 1988 rate order with a balance to be refunded to customers of $7,116,000 as of December 31, 1997.
For income tax purposes, the Company uses accelerated depreciation and shorter depreciation lives, as permitted by the Internal Revenue Code. 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 assets and deferred tax liabilities at December 31, 1997 and 1996 are as follows:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(3) INCOME TAXES (CONTINUED)
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 $906,000 in 1997, $931,000 in 1996, and $937,000 in 1995.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations as of December 31:
The Company currently has a shelf registration covering the issuance of up to $100,000,000 of Medium-Term Notes, of which $60,000,000 of Medium-Term Notes, Series C have been issued.
There are no sinking fund requirements for the next five years related to the $210,000,000 of Medium-Term Notes outstanding at December 31, 1997 and none are callable prior to maturity.
Annual maturities of capital lease obligations are $507,000, $561,000, $620,000 and $55,000 for 1998 through 2001, respectively.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department effective October 1, 1988, the Company funds its inventory of gas supplies through external sources. All costs related to this funding are recoverable
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(4) COMMITMENTS (CONTINUED)
from its customers. The Company maintains a long-term credit agreement with a group of banks which provides for the borrowing of up to $70,000,000 for the exclusive purpose of funding its inventory of gas supplies or for backing commercial paper issued for the same purpose. The Company had $55,502,000 and $55,594,000 of commercial paper outstanding to fund its inventory of gas supplies at December 31, 1997 and 1996, respectively. 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 one-year revolving credit facility which may be converted to a two-year term loan at the Company's option if the one-year revolving credit facility is not renewed by the banks. The Company may select the agent bank's prime rate or, at the Company's option, various pricing alternatives. The agreement requires a facility fee of 1/12 of 1% on the commitment. No borrowings were outstanding under this agreement during 1997 and 1996.
Short-Term Debt and Lines of Credit
Eastern maintains a credit agreement with a group of banks which provides for the borrowing by Eastern of up to $100,000,000 (of which up to $75,000,000 may be borrowed or used to back commercial paper issued by the Company) at any time through December 31, 2001. The interest rate for borrowings is the agent bank's prime rate, or at the borrower's option, various pricing alternatives. The Company had outstanding borrowings of $39,700,000 and $57,000,000 in commercial paper not related to gas inventory financing at December 31, 1997 and 1996, respectively. The weighted average interest rate on these borrowings was 6.19% at December 31, 1997 and 5.99% at December 31, 1996.
In addition to the $75,000,000 available under the Eastern credit agreement, the Company has an uncommitted line of credit of $40,000,000 under which it may borrow through December 31, 1998. The interest rate for such borrowings is a function of federal funds, money market or prime rates. There were no borrowings outstanding under this uncommitted line at December 31, 1997 and 1996.
(5) PREFERRED STOCK
The Company has outstanding 1,200,000 shares of 6.421% Cumulative Preferred Stock, which is non-voting and has a liquidation value of $25 per share. The preferred stock requires 5% annual sinking fund payments beginning on September 1, 1999 with a final redemption on September 1, 2018. The preferred stock is not callable 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:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(6) PENSION BENEFITS (CONTINUED)
For the periods 1997 and 1996, the expected long-term rate of return on assets was 8.5% and the discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5%. The rate of increase in future compensation levels was 4.75%-5.0% for 1997 and 1996.
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 of October 1.
(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. The expected cost of postretirement benefits other than pensions is charged to expense during the period of the employee's service. As of the date of adoption of Statement of Financial Accounting Standards No. 106 ("SFAS 106"), "Employers Accounting for Postretirement Benefits Other Than Pensions", the cumulative effect of the accounting change ("transition obligation") was $89,120,000. The 1996 Rate Order allowed recovery of SFAS 106 costs, which includes current SFAS 106 expense and the amortization of the regulatory asset related to the transition obligation.
Net postretirement benefit costs 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 of October 1.
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. Plan assets are invested in equity securities, fixed-income investments and money market instruments.
The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.5% in 1997 and 1996. A 7% annual increase in the cost of covered health care benefits was assumed for 1997 and 1996. This rate of increase is assumed to remain at 7% through 1999 and decrease to 6% in 2000 and 5% thereafter. A 1% increase in the assumed health care cost trend would have increased the postretirement benefit cost by $382,000 in 1997 and $536,000 in 1996, and the accumulated postretirement benefit obligation by $4,258,000 in 1997 and $6,253,000 in 1996.
(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 $10,112,000 in 1997, $8,418,000 in 1996 and $8,826,000 in 1995.
The Company capitalizes its financing leases, which include liquefied natural gas facilities and an operations center. The lease for the liquefied natural gas facilities in Lynn and Salem expired June 30, 1997. On May 6, 1997 the Company filed a civil suit to determine its purchase rights under the lease. Pending the court's decision or a negotiated outcome, the parties have agreed that the Company will continue to operate and maintain the facilities. A summary of property held under capital leases as of December 31 is as follows:
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 earnings.
The Company also has various operating lease agreements for office facilities and other equipment. The remaining minimum rental commitments for these and all other noncancelable leases, including the financing leases, at December 31, 1997 is as follows:
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair values of 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.
Preferred Stock
The fair value of the preferred stock for 1997 and 1996 is based on currently quoted market prices.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(9) FAIR VALUES OF FINANCIAL INSTRUMENTS (CONTINUED)
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1997 and 1996 are as follows:
(10) RESTRUCTURING CHARGE
During the fourth quarter of 1997, the Company recorded a restructuring charge of $8.7 million related to its decision to exit the gas appliance repair and service business. The charge includes $5.4 million for employee severance and termination benefits associated with the elimination of approximately 130 bargaining unit and management positions. The remaining $3.3 million relates to the disposition of assets, the cancellation of lease obligations, communications, legal and other related costs. The Company expects the restructuring plan to be complete by the end of 1998. The restructuring charge is reported as a component of operating expenses in the consolidated statement of earnings.
(11) RELATED PARTY TRANSACTIONS
The Company paid Eastern $4,300,000 in 1997, $4,048,000 in 1996, and $4,117,000 in 1995 for legal, tax and corporate services rendered.
In December 1996, Eastern Rivermoor Company, Inc., a wholly owned subsidiary of Eastern, purchased the Company's primary operations center from a third party and assumed the current lease agreement with the Company. During 1997 the Company paid $752,000 to Eastern Rivermoor Company, Inc.
During 1996, Eastern entered into a joint venture with New England Electric System ("NEES") to form AllEnergy Marketing Company, L.L.P., a new unregulated energy marketing company. In the fourth quarter of 1997, Eastern sold its interest to NEES. During 1997 and 1996, AllEnergy purchased gas from the Company at prices and terms equivalent to those used in transacting business with unrelated parties and totalled approximately $163,000 and $2,764,000, respectively.
(12) ENVIRONMENTAL ISSUES
The Company, like many other companies in the natural gas industry, is party to governmental proceedings requiring investigation and possible remediation of former manufactured gas plant ("MGP") sites. The Company may have or share responsibility under applicable environmental laws for the remediation of 17 such sites. A subsidiary of New England Electric System ("NEES") has assumed responsibility for remediating 10 of these sites, subject to a limited contribution from the Company. The Company has estimated its potential share of the costs of investigating and remediating former MGP sites in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," and the American Institute of Certified Public Accountants Statement of Position 96-1, "Environmental Remediation Liabilities." The Company has recorded a liability of $19.5 million, which represents its best estimate at this time of remediation costs, which may reasonably be estimated to range from $17 million to $31 million. However, there can be no assurance that such
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(12) ENVIRONMENTAL ISSUES (CONTINUED)
costs will not vary considerably from these estimates. Factors that may bear on costs differing from estimates include, without limit, changes in regulatory standards, changes in remediation technologies and practices and the type and extent of contaminants discovered at the sites.
The Company is aware of 21 other former MGP sites within its service territory. The NEES subsidiary has provided full indemnification to the Company with respect to eight of these sites. At this time, there is substantial uncertainty as to whether the Company has or shares responsibility for remediating any of these other sites. No notice of responsibility has been issued to the Company for any of these sites from any governmental environmental authority.
By a rate order issued on May 25, 1990, the Department approved the recovery of all prudently incurred environmental response costs associated with former MGP sites over separate, seven-year amortization periods, without a return on the unamortized balance. The Company has recognized an insurance receivable of $3.4 million, reflecting a negotiated settlement with an insurance carrier for environmental expense indemnity, and a regulatory asset of $16.1 million, representing the expected rate recovery of environmental remediation costs, net of the insurance settlement. The Company currently believes, in light of the indemnity agreement with the NEES subsidiary and the Department rate order on environmental cost recovery, that it is not probable that such costs will materially affect its financial condition or results of operations.
(13) PIPELINE TRANSITION COSTS
Pursuant to FERC Order 636, pipelines were permitted 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.
On March 8, 1995 the Department issued an order allowing for the recovery of the Company's transition cost liability from customers. During 1997, the Company's remaining obligation for transition cost liability was settled by applying pipeline rate case refunds against such obligation.
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, 1997 and 1996, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1997. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Boston Gas Company and subsidiary as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, 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 22, 1998
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION FOR THE TWO YEARS ENDED DECEMBER 31, 1997 (UNAUDITED)
The following table summarizes the Company's reported quarterly information for the years ended December 31, 1997 and 1996:
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1997 (IN THOUSANDS)
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1996 (IN THOUSANDS)
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1995 (IN THOUSANDS)