ITEM 1. BUSINESS.
GENERAL
Boston Gas Company (the "Company"), is engaged in the transportation and sale of natural gas to over 515,000 residential, commercial and industrial customers in Boston, Massachusetts and 73 other communities in eastern and central Massachusetts. The Company also sells gas for resale in Massachusetts and other states. The Company has one subsidiary, Massachusetts LNG Incorporated ("Mass LNG"), which holds a long-term lease on two liquefied natural gas ("LNG") facilities. The Company is the largest natural gas distribution company in New England, has been in business for 173 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.
For definition of certain industry specific terms, see the Glossary at the end of Part I and appearing on page 5.
The Company provides both local transportation services and gas supply for all customer classes. All residential customers and most commercial/industrial customers currently purchase combined or "bundled" supply and transportation services from the Company. Local transportation service is offered on an unbundled basis to large commercial/industrial customers, who may purchase gas supply from the Company or other sources.
The Company's services are available on a firm and non-firm basis. Firm transportation services and sales are provided under rate tariffs filed with the Massachusetts Department of Public Utilities (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/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. Beginning in November, 1993, margin on non-firm throughput and city gate sales in excess of a threshold based upon the prior year's non- firm margin is shared between firm customers and the Company, 75% and 25%, respectively. Under this sharing mechanism, the Company retained $353,000 and $1,040,000 in 1995 and 1994, respectively.
MARKETS AND COMPETITION
The Company competes with other fuel distributors, primarily oil dealers, throughout its service territory. Over the last five years, the Company has increased its market share of the total stationary energy market from 28% to 35%. This market share compares to the national average of approximately 43% 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 and customer perceptions of relative value.
Residential customers comprise 92% of its customer base, while commercial/industrial establishments account for the remaining 8%. Volumetrically, residential customers account for 29% of total throughput and 42% of firm throughput, while commercial/industrial customers account for 71% of total throughput and 58% of firm throughput. Approximately half of the commercial/industrial customers' total throughput is local transportation.
In 1993, the Department approved the Company's proposal to unbundle local transportation service and gas sales service for its largest commercial/industrial customers. Unbundling allows customers to purchase local transportation from the Company on a basis separate from the purchase of gas supply, which the customer may buy from the Company or third parties. This unbundling initiative extended to eligible customers direct access to gas supplies and interstate pipeline capacity, as authorized by the Federal Energy Regulatory Commission ("FERC") in Order 636. As a result of Order 636, the Company has seen increasing competition from other gas suppliers into its service territory. In 1995, 103 of the approximately 450 eligible customers purchased gas supplies from third parties. In response to such perceived trends, in 1994, the Company initiated a large-scale reengineering effort to reduce costs, increase productivity, and improve customer service.
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 gas throughput of the Company for the three years 1993-1995.
No customer, or group of customers under common control, accounted for 3% or more of total firm revenues in 1995.
GAS SUPPLY
The following table in BCF provides statistical information with respect to the Company's sources of supply for 1993-1995.
The Company purchases approximately 60% 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 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. The expiration dates for these contracts are similar to those included in the above table.
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 for storage capacity of 17.3 BCF and peak day capacity of 0.16 BCF. The Company utilizes its existing capacity 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 0.69, 0.65 and 0.64 in 1995, 1994 and 1993, respectively. The Company provides for peak period demand through a least cost portfolio of pipeline, storage and supplemental supplies. The Company considers its peak day sendout 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, 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 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 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, including the demand charges for capacity on the interstate pipeline system.
In February of 1995 the Department ordered all large gas and electric utilities to file incentive rate proposals as soon as possible. The order signaled a significant departure from established Department practice of setting rates to reflect all allowed costs of service. In the second quarter of 1996 the Company intends to file an incentive rate proposal consistent with the Department's directives. As part of its rate restructuring proposal, the Company will offer unbundled transportation and sales service to a broader range of customers.
As more customers elect to purchase gas from third parties, a greater amount of upstream pipeline capacity under contract may be idle, unless it can be remarketed or assigned. The recoverability of cost for any such idle capacity will be an issue for the Department to address for all utilities subject to its jurisdiction. While there can be no assurance, it is the Company's position that it should be afforded the opportunity to recover prudently incurred, non-mitigable stranded capacity cost.
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 flows are highly seasonal as the demand for most of its transportation services and sales is 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 is financed through short-term borrowings. Short-term borrowings are also required from time to time to finance normal business operations. As a result, short-term borrowings are generally highest during the late fall and early winter.
ENVIRONMENTAL MATTERS
The Company may have to share responsibility under applicable environmental law for the remediation of certain former manufactured gas plant ("MGP") sites, as described in Note 11 of Notes to Financial Statements. 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. The Company does not possess at this time sufficient information to reasonably determine the ultimate cost to it of such remediation and no assurance can be given with respect to the future recoverability of such costs. However, in light of the factors discussed above, the Company believes that it is not probable that such costs will materially affect its financial condition or results of operations.
EMPLOYEES
As of December 31, 1995, the Company had approximately 1,550 employees, 73% of whom are organized in local unions with which the Company has collective bargaining agreements that expire in 1999. The approximate 10% reduction in staffing from the prior year was accomplished through attrition and early retirement and severance programs for both management and union employees associated with the Company's ongoing reengineering program.
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 numerous locations throughout its service territory.
On December 31, 1995, the Company's distribution system included approximately 5,800 miles of gas mains, 397,000 services and 525,000 active customer meters.
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 1995, the Company's capital expenditures were $57.3 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 $60.0 million for similar purposes in 1996.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS.
Other than 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 1995.
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 from the city gate to the customer's burner tip, balancing daily swings in customer loads, storage, and peak-shaving services.
BURNER TIP--Ultimate point of consumption of natural gas at the customer's end-use equipment.
CAPACITY--The maximum capability of pipelines and supplemental facilities to deliver and/or store gas at a given time.
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 natural gas.
LOCAL DISTRIBUTION COMPANY (LDC)--A utility that owns and operates a natural 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.
MERCHANT BUSINESS--Business of purchasing and selling natural gas.
NON-CORE CUSTOMERS--Generally, those customers with readily available, economically viable alternatives to natural gas, and/or are of sufficient size to arrange for their own energy supplies.
NON-FIRM SERVICE--Sales and transportation service that offers service at a lower cost and level of reliability. 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 alternative fuel.
TRANSITION COSTS--Pursuant to FERC Order 636, these are costs incurred by interstate pipelines as they unbundled their services and exited the merchant business. Transition costs include uncovered gas costs at the time the pipelines ceased the merchant function, stranded costs or unrecovered costs of assets that cannot be assigned to customers of unbundled services, and gas supply realignment costs or the costs of renegotiating existing gas supply contracts with producers.
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 use. 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 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, 1995. Dividends on such common equity amounted to $11.9 million and $12.8 million for 1995 and 1994, respectively. At December 31, 1995, 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.
1995 COMPARED TO 1994
Net earnings applicable to common stock for 1995 were $23.4 million, a decrease of $1.8 million or 7% from 1994. Increased throughput to new and existing customers, the recognition of lost margins associated with conservation programs and the reimbursement of previously incurred environmental expenses were offset primarily by lower customer consumption in the heating markets and to a lesser extent weather. While weather in both 1995 and 1994 was essentially normal for the year as a whole, temperatures within the year varied widely relative to normal and from year to year.
Higher operating costs, primarily non-recurring charges associated with early retirement and severance programs for both management and union employees, were partially offset by related labor savings and reduced weather- related workload during the first half of the year. Work force reductions resulted from the Company's reengineering project which focused on improving customer service and lowering operating costs.
Also contributing to lower earnings were increased depreciation and property tax expenses related to continued investments in system replacement and expansion partially offset by a reduced provision for uncollectible accounts.
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 benefited 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.
LIQUIDITY AND CAPITAL RESOURCES
In 1995, the Company maintained committed lines of credit totaling $40.0 million, which were not renewed when they expired on December 31, 1995. To meet cash requirements and support it's commercial paper program, the Company has available up to $75.0 million of Eastern's committed credit agreement and various uncommitted lines of credit. The Company also maintains a bank credit agreement which supports the issuance of up to $90.0 million of commercial paper to fund its inventory of gas supplies.
During the fourth quarter of 1995, the Company issued $60.0 million of Medium-Term Notes, Series C pursuant to a shelf registration filed on June 13, 1995. These notes have an average maturity of 26 years and a weighted average interest rate of 7.08%. Proceeds from this issuance were used to complete an in-substance defeasance of all outstanding 8 3/4% and 9% Debentures due 2001 with an aggregate principal amount of $60.0 million.
In connection with the defeasance, the Company has irrevocably requested that the 9% Debentures be called on May 15, 1996 and the 8 3/4% Debentures be called on December 15, 1996. Under the terms of the applicable debt instruments, the Company has deposited U.S. Government Securities in an irrevocable trust to cover principal, call premiums and interest to the call dates.
The Company expects capital expenditures for 1996 to be approximately $60.0 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 expects that projected cash flow from operations, in combination with currently available resources, is sufficient to meet 1996 capital expenditure and working capital requirements, normal debt repayments and dividends to its shareholders. 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 which the Company believes are currently available to it will continue to be available or will be available on terms and conditions advantageous to the Company.
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 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 1995. - - -------- * 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: J.F. Bodanza --------------------------------- J.F. BODANZA SENIOR VICE PRESIDENT AND TREASURER (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
Dated: March 18, 1996
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 18TH DAY OF MARCH 1996.
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 - - ------------------------------------- and Treasurer (Principal Financial J. F. BODANZA and Accounting 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 Statements of Financial Accounting Standards No. 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 the demand for most of its transportation services and sales is directly related to temperature conditions. The Company purchases pipeline gas supplies from a variety of domestic and Canadian producers and marketers. Gas supplies are purchased using a combination of long-term commitments, firm winter service agreements and spot purchases. The Company has diversified its pipeline gas supplies across major North American producing regions, including western Canada.
Regulatory Assets
The Company is subject to the provisions of Statement of Financial Accounting Standards 71, ("SFAS 71") "Accounting for the Effects of Certain Types of Regulation". Regulatory assets represent probable future revenue to the Company associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The following regulatory assets were reflected in the Consolidated Balance Sheets as of December 31:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) ACCOUNTING POLICIES (CONTINUED)
Regulatory liabilities total $12,391,000 and $13,341,000 at December 31, 1995 and 1994 and relate primarily to income taxes.
As of December 31, 1995 all of the Company's regulatory assets and regulatory liabilities are being reflected in rates charged to customers over periods ranging from 1 to 24 years. For additional information regarding deferred income taxes, Order 636 transition costs, environmental costs and postretirement benefit costs, see footnotes 3, 12, 11, and 7 respectively.
If a portion of the Company's operations is no longer subject to the provisions of SFAS 71, a write off of related regulatory assets and liabilities would be required, unless some form of transition cost recovery (refund) continues through rates established and collected for the Company's remaining regulated operations.
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 5.13% in 1995, 5.16% in 1994 and 3.98% in 1993.
Accumulated depreciation is charged with the original cost and cost of removal, less salvage value, of units retired. Expenditures for repairs, upkeep of units of property and renewal of minor items of property replaced independently of the unit of which they are a part are charged to maintenance expense as incurred.
Gas Operating Revenues
Gas operating revenues are recorded when billed. Revenue is not recorded for the amount of gas distributed to customers, which is unbilled at the end of the period; however, the cost of this gas is deferred as discussed in Note 2.
(2) COST OF GAS ADJUSTMENT CLAUSE AND DEFERRED GAS COSTS
The cost of gas adjustment clause requires the Company to adjust its rates 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. The cost of gas adjustment clause also recovers 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.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 39.1% in 1995, 39.5% in 1994, and 38.4% in 1993. State taxes represent the majority of the difference between the effective rate and the Federal income tax rate for 1995, 1994 and 1993.
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, 1995 the balance of the regulatory asset was $498,000. 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, 1995 was $4,440,000. 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, 1995 the balance to be returned to customers was $7,951,000.
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 assets and deferred tax liabilities at December 31, 1995 and 1994, 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 $937,000 in 1995, $723,000 in 1994 and $689,000 in 1993.
(4) COMMITMENTS
Long-term Obligations
The following table provides information on long-term obligations as of December 31:
In 1995, the Company filed a shelf registration covering the issuance through 1997 of up to $100,000,000 of Medium-Term Notes. In October and November 1995, the Company issued $60,000,000 of Medium-Term Notes, Series C, with a weighted average maturity of 26 years and a coupon of 7.08%. The proceeds from this issuance were used to complete an in-substance defeasance of $60,000,000 principal amount of 8.75%--9.00% Debentures due 2001. In connection with the defeasance the Company has irrevocably requested that the Debenture Trustee call the Debentures on the first date that they can be redeemed with lower cost debt. In December 1995, the Company deposited $65,136,000 of U.S. government securities into an irrevocable trust to cover the principal amount called, the call premiums of $1,161,000 and interest to the date of call of $3,975,000. As a result of the in-substance defeasance, the debt has been considered extinguished; accordingly, the government securities and
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS (CONTINUED)
$60,000,000 principal amount of Debentures due 2001 were removed from the balance sheet at December 31, 1995. Pursuant to regulatory accounting, the in- substance defeasance transaction resulted in the deferral of $2,250,000 as debt issuance costs to be amortized over the lives of the newly issued Medium- Term Notes.
On September 1, 1995 the Company redeemed all of the outstanding principal amount of 8.375% First Mortgage Bonds due 1996 at a redemption price of 100%.
In 1994 the Company issued $50,000,000 of Medium-Term Notes, Series B, with a weighted average maturity of 21 years and a coupon 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. Proceeds from the issuance reduced current debt.
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, 1995 and none are callable prior to maturity.
Annual maturities of capital lease obligations are $1,508,000, $1,029,000, $507,000, $561,000 and $620,000 for 1996 through 2000, respectively.
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, 1995 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 Massachusetts 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 long-term 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 $45,600,000 and $53,578,000 of commercial paper outstanding to fund its inventory of gas supplies at December 31, 1995 and 1994, 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 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 the agent bank's prime rate or, at the Company's option various alternatives. The agreement requires a facility fee of 1/12 of 1% on the commitment. No borrowings were outstanding under this agreement during 1995 and 1994.
Eastern Borrowing Arrangement
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 29, 2000. The interest rate for such borrowings is the agent bank's prime rate, or at Eastern's option, various alternatives.
Notes Payable
In addition to the Eastern borrowing arrangement, the Company maintained committed lines of credit totaling $40,000,000 during 1995 and 1994 which were not renewed.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) COMMITMENTS--(CONTINUED)
The Company has various uncommitted lines of credit which provide for interest as a function of federal funds, money market or prime rates. These uncommitted lines of credit are used, in conjunction with commercial paper, for working capital needs. The Company had outstanding borrowings of $52,000,000 and $62,530,000 in commercial paper not related to gas inventory financing at December 31, 1995 and 1994, respectively. The weighted average interest rate on these borrowings at December 31, was 5.93% in both 1995 and 1994.
(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:
For the periods 1995 and 1994, 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 1995 and 5% in 1994.
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.
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 that the employee renders service. As of the date of adoption of Statement of Financial Accounting Standards No. 106 ("SFAS106"), "Employees Accounting for Postretirement Benefits Other Than Pensions" 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 costs included the following components:
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. The Company contributed $2,600,000 to the VEBA in 1995. 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 1995 and 1994. A 10% and 11% annual increase in the cost of covered health care benefits was
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (CONTINUED)
assumed for 1995 and 1994, respectively. This rate of increase is assumed to drop gradually to 5% after 5 years. A 1% increase in the assumed health care cost trend would have increased the postretirement benefit cost by $541,000 in 1995 and $529,000 in 1994, and the accumulated postretirement benefit obligation by $6,300,000 in 1995 and $6,302,000 in 1994.
(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 $8,826,000 in 1995, $8,323,000 in 1994 and $7,663,000 in 1993.
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 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 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 noncancelable leases, including the financing leases, at December 31, 1995 is as follows:
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 1995 and 1994 is based on currently quoted market prices.
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1995 and 1994 are as follows:
(10) SUPPLEMENTARY INFORMATION
The Company paid Eastern $4,117,000 in 1995, $3,669,000 in 1994, and $3,096,000 in 1993 for various legal, tax and corporate services rendered.
(11) ENVIRONMENTAL ISSUES
The Company, like many other companies in the natural gas industry, is party to governmental actions requiring investigation and possible remediation of former manufactured gas plant ("MGP") sites. The Company currently owns 15 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 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 ten other sites owned by the Company, subject to limited contribution by the Company. The Company is working with the Massachusetts Department of Environmental Protection (the "DEP") to determine the extent of remediation which may be required at the four former MGP sites currently owned by the Company and not covered by the
BOSTON GAS COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(11) ENVIRONMENTAL ISSUES (CONTINUED)
Settlement Agreement or the Boyd decision. The Company expects to spend approximately $1 million in 1996 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, and no assurance can be given with respect to the future recoverability of such costs. However, management 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 and the rate order discussed below. 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 $44,520,000 at December 31, 1995 and it has recorded this amount less actual billings of $35,010,000 as a liability in the accompanying consolidated balance sheet. As pipelines continue to file for recovery of transition costs, the Company's obligation may increase.
On March 8, 1995 the Department issued an order allowing for the recovery of the Company's transition costs liability over one year. Accordingly, at December 31, 1995 the Company has recorded a regulatory asset of $9,510,000 and deferred gas costs of $19,363,000 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, 1995 and 1994, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, 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 23, 1996
BOSTON GAS COMPANY AND SUBSIDIARY
INTERIM FINANCIAL INFORMATION FOR THE TWO YEARS ENDED DECEMBER 31, 1995 (UNAUDITED)
The following table summarizes the Company's reported quarterly information for the years ended December 31, 1995 and 1994:
SCHEDULE II
BOSTON GAS COMPANY AND SUBSIDIARY
VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1995 (IN THOUSANDS)
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)