-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KjA3PFCOL4IfRl/EyR3AMG87YguqOOXYOM+FOe3ADfMg//PhNEVowj7FiHc1ldy/ rxMAzi0+z0xFGIeuJi72Bw== 0001062379-03-000350.txt : 20030813 0001062379-03-000350.hdr.sgml : 20030813 20030813162309 ACCESSION NUMBER: 0001062379-03-000350 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030813 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BOSTON GAS CO CENTRAL INDEX KEY: 0000013390 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 041103580 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 002-23416 FILM NUMBER: 03841565 BUSINESS ADDRESS: STREET 1: ONE BEACON ST CITY: BOSTON STATE: MA ZIP: 02108 BUSINESS PHONE: 6177428400 MAIL ADDRESS: STREET 1: ONE BEACON STREET CITY: BOSTON STATE: MA ZIP: 02108 10-K/A 1 bogas-10kamend2002.txt FORM 10-K/AMENDMENT (2002) UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A Amendment No. 1 (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 or Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____ to____ Commission File Number 2-23416 BOSTON GAS COMPANY D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND (Exact Name of Registrant As Specified In Its Charter) Massachusetts 04-1103580 (State or other jurisdiction of (I.R.S. Employer Identification No.) Incorporation or Organization) 52 Second Avenue (781) 466-5000 Waltham, Massachusetts 02453 (Registrant's Telephone Number) (Address of Principal Executive Offices) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Exchange ------------------- -------- None None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X Indicate the number of shares outstanding of the registrant's class of common stock as of March 1, 2002. All common stock, 514,184 shares, are held by KeySpan New England LLC . The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format. EXPLANATORY NOTE Boston Gas Company hereby amends its Form 10-K for the period from January 1, 2002 to December 31, 2002 (the "Form 10-K") as set forth in this Form 10-K/A (the "Form 10-K/A"). This Form 10-K/A is being amended solely to include the Section 906 Certifications of the Chief Operating Officer and Chief Financial Officer dated March 28, 2003, inadvertently omitted from our previously filed Form 10-K, as well as the certifications, dated the date hereof, required as a result of the filing of this amendment. BOSTON GAS COMPANY FORM 10-K Fiscal Year Ended December 31, 2002 TABLE OF CONTENTS
Item No Topic Page -- ----- ---- PART I 1. Business General............................................................................................................ 1 Forward-Looking Information........................................................................................ 1 Markets and Competition............................................................................................ 2 Gas Throughput..................................................................................................... 2 Gas Supply......................................................................................................... 3 Regulation......................................................................................................... 4 Seasonality and Working Capital.................................................................................... 4 Environmental Matters.............................................................................................. 4 Employees.......................................................................................................... 4 2. Properties......................................................................................................... 5 3. Legal Proceedings.................................................................................................. 5 4. Submission of Matters to a Vote of Security Holders................................................................ 5 Glossary........................................................................................................... 6 PART II 5. Market for the Registrant's Common Equity and Related Stockholder Matters.......................................... 7 6. Selected Financial Data............................................................................................ 7 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 7 7A. Quantitative and Qualitative Disclosures About Market Risk......................................................... 10 8. Financial Statements and Supplementary Data........................................................................ 11 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................... 11 PART III 10. Directors and Executive Officers of the Registrant................................................................. 12 11. Executive Compensation............................................................................................. 12 12. Security Ownership of Certain Beneficial Owners and Management..................................................... 12 13. Certain Relationships and Related Transactions..................................................................... 12 14. Controls and Procedures............................................................................................ 12 PART IV 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................................... 13
PART I Item 1. Business. General Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein as the "Company", "we", "us" and "our"), is a gas distribution company engaged in the transportation and sale of natural gas to approximately 563,000 residential, commercial and industrial customers in Boston, Massachusetts and 73 other communities in eastern and central Massachusetts. We are the largest natural gas distribution company in New England and have been in business for 180 years. We are a wholly-owned subsidiary of KeySpan New England, LLC ("KNE LLC") (formerly known as Eastern Enterprises). On November 8, 2000, KeySpan Corporation ("KeySpan") acquired all of the common stock of KNE LLC. The transaction was accounted for as a purchase, with KeySpan being the acquiring company. KNE LLC has owned Boston Gas Company since 1929. KeySpan is a registered holding company under the Public Utility Holding Company Act ("PUHCA") of 1935, as amended. As a result, its activities, as well as certain activities of its subsidiaries, including the Company, are regulated by the Securities and Exchange Commission (the "SEC") under PUHCA. For definition of certain industry-specific terms, see the Glossary at the end of Part I and appearing on page 6. The Company provides local transportation services and gas supply to all customer classes. Our services are available on a firm and non-firm basis. Firm transportation service and sales are provided under rate tariffs and/or contracts filed with the Massachusetts Department of Telecommunications and Energy ("Department") that typically obligate us to provide service without interruption throughout the year. Non-firm transportation service and sales are generally provided to large commercial/industrial customers who can use gas or another energy source interchangeably. 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. The Company offers unbundled services to all of its customers who are allowed to purchase local transportation from us separately from the purchase of gas supply, which the customer may buy from third-party suppliers. We view these third-party suppliers as partners in marketing gas and increasing throughput and expect to work closely with them to facilitate the unbundling process and ensure a smooth transition, especially in the tracking and processing of transactions. We implemented programs to educate customers about the opportunity to purchase gas from third-party suppliers, while still relying on us for delivery. As of December 31, 2002, we had approximately 5,800 firm commercial and industrial transportation customers. Unbundled service to residential customers became available on November 1, 2000. While the migration of customers to transportation-only service will lower our revenues, it has no impact on our operating earnings. We earn all of our margins on the local distribution of gas and none on the resale of the commodity itself. Forward-Looking Information Certain statements contained in this Annual Report on Form 10-K concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are other than statements of historical facts, are " forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Without limiting the foregoing, all statements under the captions "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosure about Market Risk," relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, pursuit of potential future acquisition opportunities and sources of funding, are forward-looking statements. Such forward-looking statements reflect numerous assumptions and involve a number of risks and uncertainties and actual results may differ materially from those discussed in such statements. 1 Among the factors that could cause actual results to differ materially are: general economic conditions, especially in Massachusetts; fluctuations in weather; volatility of energy prices, including natural gas; available sources and cost of fuel; federal and state regulatory initiatives that increase competition, threaten cost and investment recovery, and impact rate structures; the ability of the Company to successfully reduce its cost structure; inflationary trends and interests rates; implementation of new accounting standards; retention of key personnel; creditworthiness of counter-parties to derivative instruments and commodity contracts; and other risks detailed from time to time in other reports and other documents filed by the Company with the SEC. For any of these statements, the Company claims the protection of the safe harbor for forward-looking information contained in the Private Securities Litigation Reform Act of 1995, as amended. For additional discussion on these risks, uncertainties and assumptions, see Item 1. "Business", Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." and Item 7A. "Quantitative and Qualitative Disclosure about Market Risk," contained herein. Markets and Competition The Company competes with other fuel distributors, primarily oil dealers, throughout its service territory. We believe that there are significant opportunities to increase the number of natural gas customers by converting residential, industrial and commercial customers from oil-to-gas for space heating purposes. However, increasing the number of natural gas customers cannot be predicted with certainty and will depend on such factors as the price of competitive energy sources, the level of investment required and customer perception of relative value. Gas Throughput The following table in BCF provides information with respect to the volumes of gas sold and transported by the Company during the three years 2000-2002.
- ------------------------------------------------------------------------------------------------ Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------ Residential 41.7 41.9 43.2 Commercial and industrial 20.9 21.9 25.4 Off-system sales 0.1 0.2 2.6 - ------------------------------------------------------------------------------------------------ Total sales 62.7 64.0 71.2 Transportation of customer-owned gas 65.6 61.9 55.8 Less: Off-system sales (0.1) (0.2) (2.6) - ------------------------------------------------------------------------------------------------ Total throughput 128.2 125.7 124.4 - ------------------------------------------------------------------------------------------------ Total firm throughput 127.3 124.9 122.4 - ------------------------------------------------------------------------------------------------
The above table excludes the effect of the accrual method of revenue recognition as discussed in Note 1 of the Notes to Financial Statements. In 2002, residential customers comprised 91% of our customer base, while commercial and industrial customers accounted for the remaining 9%. Volumetrically, residential customers accounted for 33% of total firm throughput, while commercial and industrial customers accounted for 67% of total firm throughput. Approximately 76% of commercial and industrial customers' total throughput was transportation-only service. Sithe Energy, an independent power generator on our system, was responsible for approximately 25% of this transportation throughput under a contract which was renewed through March, 2004. Sithe, however, has an option to cancel the contract with 60 days notification. They have also notified us that they do not intend to extend the contract beyond March 2004. The anticipated loss in annual transportation revenues is expected to be $3.4 million, or $2.2 million, net of taxes. No customer, or group of customers under common control, accounted for 2% or more of total firm revenues in 2002. 2 Gas Supply The following table in BCF provides information with respect to our sources of supply during the three years 2000-2002.
- --------------------------------------------------------------------------------------------------- Years Ended December 31, 2002 2001 2000 - --------------------------------------------------------------------------------------------------- Natural gas purchases 58.3 52.3 59.6 Underground storage withdrawal 8.5 6.0 12.5 Liquefied natural gas ("LNG") purchases 1.3 1.9 5.3 - --------------------------------------------------------------------------------------------------- Total source of supply 68.1 60.2 77.4 Company use, unbilled and other (5.4) 3.8 (6.2) - --------------------------------------------------------------------------------------------------- Total sales 62.7 64.0 71.2 - ---------------------------------------------------------------------------------------------------
Year-to-year variations in storage gas and unbilled gas reflect variations in end-of-year customer requirements, due principally to weather. The vast majority of our gas supplies are transported on interstate pipeline systems to our service territory pursuant to long-term contracts. Federal Energy Regulatory Commission ("FERC") approved tariffs provide for fixed demand charges for the firm capacity rights under these contracts for the interstate pipeline companies that provide firm transportation service to our service territory. The peak daily, annual capacity and contract expiration dates are as follows:
Capacity in BCF - ------------------------------------------------------------------------------------------------------------------ Expiration Pipeline Daily Annual Dates - ------------------------------------------------------------------------------------------------------------------ Algonquin Gas Transmission Company ("Algonquin") 0.29 85.9 10/05-04/13 Tennessee Gas Pipeline Company ("Tennessee") 0.24 88.1 10/08-11/12 - ------------------------------------------------------------------------------------------------------------------ 0.53 174.0 - ------------------------------------------------------------------------------------------------------------------
In addition to capacity on the Algonquin and Tennessee systems, we have firm capacity contracts upstream of both pipelines in order to transport natural gas purchased by us from various areas of gas production. We have also 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 16.3 BCF and peak day deliverability of 0.18 BCF. We utilize existing transportation contracts to transport gas from the storage fields to our service territory. Supplemental supplies of LNG and propane are produced by and purchased from foreign and domestic sources. The Company operated under a portfolio management contract with El Paso Merchant Energy Gas, L.P. ("El Paso"), from November 1, 1999 through October 31, 2002. El Paso was responsible for providing the majority of the city gate supply requirements to the Company, in addition to managing certain of the Company's and certain affiliates upstream capacity, underground storage and term supply contracts. We negotiated an interim agreement with Entergy-Koch that replaced the expired El Paso agreement. The interim agreement commenced on November 1, 2002 and extends through March 31, 2003. On April 1, 2003, a new portfolio management agreement will become effective with Entergy-Koch with a term of three years. 3 Peak day firm throughput in BCF was 0.86 in 2002, 0.63 in 2001, and 0.80 in 2000. We provide for peak period demand through a least-cost portfolio of pipeline, storage and supplemental supplies. Supplemental supplies include LNG and propane air, which are vaporized mainly at points on our distribution system. We own propane air facilities and one LNG facility in Dorchester, Massachusetts. We also lease two LNG facilities sited on land owned by us in Salem and Lynn, Massachusetts and also lease space in facilities located in Providence, Rhode Island and Everett, Massachusetts. We consider our peak day sendout capacity, based on our total supply resources, to be adequate to meet the requirements of our firm customers. Fluctuations in utility gas costs have little impact on our operating results because the current gas rate structure includes a gas adjustment clause whereby variations between actual gas costs incurred and gas costs billed are deferred and subsequently refunded to or collected from customers. Regulation Our operations are subject to Massachusetts statutes applicable to gas utilities. Rates for gas sales and transportation service, distribution safety practices, issuance of securities and affiliate transactions are regulated by the Department. Rates for transportation service and gas sales are subject to approval by and are on file with the Department. Our cost of gas adjustment clause, allows for a semiannual adjustment, and based on certain criteria, a monthly adjustment of billing rates for firm gas sales to reflect the actual cost of gas delivered to customers, including demand charges for capacity on the interstate pipeline system. Similarly, through our local distribution adjustment clause, we collect the actual cost of approved energy efficiency programs and the cost of remediating former manufactured gas plant sites from all firm customers, including those purchasing gas supply from third parties. For more detailed information regarding regulation, see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operation-Other Matters - -Regulation." Seasonality and Working Capital Our revenues, earnings and cash flows are highly seasonal because most transportation services and sales are directly related to temperature conditions. Since the majority of 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, we bill our customers over the November - April heating season for the majority of the pipeline demand charges incurred and paid by us over the entire year. This timing difference, along with other costs of gas distributed but unbilled, is reflected as deferred gas costs on the Balance Sheet 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 We have or share responsibility under applicable environmental law for the remediation of former manufactured gas plant operations, including former operating plants, gas holder locations and satellite disposal sites. Information with respect to the remediation of these sites may be found in Note 9 of the Notes to Financial Statements. Such information is incorporated herein by reference. Employees As of December 31, 2002, Boston Gas had approximately 775 employees, 87% of whom are organized in local unions with which we have collective bargaining agreements. In March 2002, we entered into a four-year collective bargaining agreement with the largest bargaining units representing union employees; these agreements expire in 2006. 4 Item 2. Properties. We operate three LNG facilities in Dorchester, Salem, and Lynn, Massachusetts. These facilities provide us with local storage of gas, because the stored LNG can be vaporized into our distribution system to supplement pipeline gas in periods of high demand. We own the Dorchester facility. We also own the real property at the Salem and Lynn facilities and rent the storage facilities under a long-term lease arrangement. In addition, we own propane-air facilities at various locations throughout our service territory. On December 31, 2002, our distribution system included approximately 6,200 miles of gas mains, 450,000 services and 563,000 active customer meters. A majority of the gas mains consist of cast iron and bare steel, which require ongoing maintenance and replacement. Our gas mains and services are usually located on public ways or private property not owned by us. In general, our occupation of such property is pursuant to easements, licenses, permits or grants of location. Except as stated above, the principal items of property are owned. In 2002 our capital expenditures were approximately $110 million. Capital expenditures were principally made for improvements to the distribution system and for system expansion to meet customer growth. We plan to spend approximately $100 million, including costs of removal, for similar purposes in 2003. Information with respect to the Company's material properties used in the conduct of its business is set forth in, or incorporated by reference in, Item 1 hereof. Except where otherwise specified, all such properties are owned or, in the case of certain rights of way used in the conduct of its gas distribution business, held pursuant to municipal consents, easements or long-term leases. In addition, we lease other office and building space, office equipment, and vehicles. Our properties are adequate and suitable to meet our current and expected business requirements. Moreover, their productive capacity and utilization meet our needs for the foreseeable future. We continually examine our real property and other property for its contribution and relevance to our businesses and when such properties are no longer productive or suitable, they are disposed of as promptly as possible. In the case of leased office space, we anticipate no significant difficulty in leasing alternative space at reasonable rates in the event of the expiration, cancellation or termination of a lease. Item 3. Legal Proceedings. Other than routine litigation incidental to the business, there are no material pending legal proceedings involving the Company. Item 4. Submission of Matters to a Vote of Security Holders. No matters were submitted to a vote of Security Holders in the fourth quarter of 2002. 5 Glossary BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot. 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. Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot. Firm Service--Sales and/or transportation service provided without interruption. This could be for the year, or for an agreed upon period 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 energy 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, whereby 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 factors. 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 typically have the opportunity to select only the services they desire. Utility Money Pool--KeySpan has established a money pool for its utility subsidiaries for purposes of reducing outside borrowings and for a more efficient use of funds. Utility subsidiaries can borrow from/or lend to the money pool depending upon its financing needs. The money pool is funded by commercial paper and operating funds of net lenders to the pool. It is administered by a wholly-owned KeySpan subsidiary, KeySpan Corporate Services LLC ("KCS") and its operation is subject to PUHCA regulation. 6 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. KNE LLC, a wholly-owned subsidiary of KeySpan Corporation, is the holder of record of all of the outstanding common equity securities of the Company. Item 6. Selected Financial Data. Not required. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. RESULTS OF OPERATIONS The net loss applicable for common stock for the year ended December 31, 2002 was $3.4 million compared to a net loss of $31.3 million in the prior year. The improvement of $27.8 million, or 89%, over the prior year is due primarily to an increase in operating margin and the discontinuance of goodwill amortization offset, in part, by higher interest expense and income taxes. Operating revenues for the year ended December 31, 2002 declined $190 million, or 23%, from 2001. The decrease was due to a decline of $213 million, or 38%, in the cost of gas sold to customers, which are fully recovered through revenues. The decrease in gas costs reflects a 40% decline in the average commodity price of gas combined with a 4.3% decrease in throughput. The decline in throughput was primarily due to significantly warmer weather in the first quarter of 2002 versus the prior year's first quarter. Our gas rate structure includes a gas adjustment clause, pursuant to which gas costs are fully recovered. Further, variations between actual gas costs incurred and gas costs billed are deferred and refunded to or collected from customers in a subsequent period. As a result, fluctuations in the cost of gas sold have little or no impact on operating margin. Operating margin (revenues less the cost of gas sold) for the year ended December 31, 2002 increased $23.0 million, or 8.5%, from the year ended December 31, 2001. Primarily contributing to the improvement was an increase of $13.8 million due to customer growth, a base rate increase of $3.6 million associated with our performance-based rate plan ("PBR") (see "Other Matters-Regulation") and an additional benefit of $6.3 million attributable to the favorable court decision which resulted in the elimination of an "accumulated inefficiencies factor" included in the PBR (see "Other Matters-Regulation"). Other gas margins, which include sales to non-core customers and regulatory rate incentives, increased $3.9 million. The improvement in operating margin was partially offset by a reduction of $1.6 million as a result of lower gas throughput due to the warmer first quarter weather and a net reduction of $3.3 million in revenues associated with weather derivatives that hedged approximately 7.4% colder than normal weather during the fourth quarter. (See Item 7A. "Quantitative and Qualitative Disclosures About Market Risk -Weather Derivatives" for further information). Total operating expenses, excluding goodwill amortization, declined $5.1 million or 2% over the prior year. Operations and maintenance expense decreased $2.9 million, or 1.8% over the prior year, primarily due to cost saving synergies realized during the year as well as lower bad debt expense due to the lower average levels of customer receivables in 2002. These decreases were offset, in part, by allocated payroll taxes associated with general and administrative services provided by KCS, which were included in 2002 operations and maintenance expense, whereas in 2001, these general and administrative services were provided by our employees and the related taxes were charged to operating taxes. 7 Depreciation expense increased as a result of continued investments in the distribution infrastructure. Operating taxes decreased primarily due to the lower payroll taxes (as discussed above) and lower property taxes. In accordance with SFAS 142, as of January 1, 2002, we are no longer amortizing goodwill. For the year ended December 31, 2001, amortization of goodwill was $19.4 million. For the year ended December 31, 2002, interest expense on long term debt was comparable to the prior year. For the year ended December 31, 2002, other interest expense increased $6.8 million, or 15.5%, versus 2001. This increase resulted from a full year of interest expense in 2002 versus six months of interest expense in 2001 on a $50 million advance from KeySpan made on June 30, 2001. For the year ended December 31, 2002, interest capitalized for construction increased $1.8 million over the prior year principally due to the investment in software in 2002. Income tax expense for the year ended December 31, 2002 increased $12.4 million from 2001. The increase in expense is primarily attributable to higher taxable income. LIQUIDITY AND CAPITAL RESOURCES In 2002, we received capital contributions of $200 million from KNE LLC. The proceeds were used to pay down borrowings from the utility money pool. On September 1, 2002, we made the required $1.5 million annual sinking fund payment on our 6.42% Cumulative Preferred Stock. For details on the Preferred Stock, see Note 4 in the Notes to Financial Statements. On November 8, 2000, KCS, a subsidiary of KeySpan, became an affiliate of the Company, as a result of KeySpan's acquisition of KNE LLC. KCS provides financing requirements to the Company for working capital and gas inventory through the Company's participation in a utility money pool. Interest charged equals interest incurred by KeySpan to borrow funds to meet the needs of the Company plus a proportional share of the administrative costs incurred in obtaining the required funds. As part of the transaction with KeySpan, the Company recorded in November 2000, a $600 million advance payable to KeySpan. During 2001, an additional $50 million advance was received from KeySpan and a $50 million dividend was paid to KeySpan. Interest charges are equal to the interest incurred by KeySpan on debt borrowings issued by KeySpan and recorded on the books of the Company. Issuance expense is charged to the Company from KeySpan equal to the amortization of actual issuance costs incurred by KeySpan on its debt borrowings. KeySpan amortizes these costs over the life of the related KeySpan borrowings. We have $210 million of Medium-Term Notes outstanding at December 31, 2002. For details on debt, see Note 3 in the Notes to Financial Statements. The ratings on the long-term debt have remained on stable outlook. At December 31, 2002, Moody's Investor Services and Standard & Poor's rated the debt A2. As discussed, revenues, earnings and cash flows are highly seasonal. Since the majority of revenues are billed during the heating season, significant cash flows are generated from late winter to early summer. Alternatively, in preparation for the heating season (i.e. purchasing and storing of natural gas), short-term borrowings are highest during the late fall and early winter. The Company expects capital expenditures for 2003 to be approximately $100 million, including costs of removal. Capital expenditures will be largely for system expansion to meet customer growth and improvements to the distribution system. The Company believes that projected cash flow from operations, in combination with currently available resources (i.e. utility money pool), is sufficient to meet 2003 capital expenditures, working capital requirements, preferred dividend payments and normal debt repayments. 8 OTHER MATTERS Regulation Our operations are subject to Massachusetts statutes applicable to gas utilities. Rates for gas sales and transportation service, distribution safety practices, issuance of securities and affiliate transactions are regulated by the Department. Rates for transportation service and gas sales are subject to approval by and are on file with the Department. Our cost of gas adjustment clause, billed to firm sales customers, allows for the semiannual adjustment, and based on certain criteria, a monthly adjustment of billing rates for firm gas sales to reflect the actual cost of gas delivered to customers, including demand charges for capacity on the interstate pipeline system. Similarly, through its local distribution adjustment clause, we collect the actual costs of approved energy efficiency programs and the cost of remediating former manufactured gas plant sites from all firm customers, including those purchasing gas supply from third parties. The Company's rates for local transportation service had been governed by a five-year performance-based rate plan (the "Plan") approved in D.P.U. 96-50. Under the Plan, our local transportation rates had been adjusted annually to reflect inflation for the previous 12 months and reduced by a productivity factor. The Plan also provided for penalties if we failed to meet specified service quality measures, with a maximum potential exposure of $1 million. There was a margin sharing mechanism whereby 25% of earnings in excess of a 15% return on year-ending equity were to be passed back to ratepayers. Similarly, ratepayers were to absorb 25% of any shortfall below a 7% return on year-ending equity. Although the Plan expired October 31, 2002, distribution rates established under the Plan continue to be effective. We expect to propose a new rate plan with the Department during the spring of 2003. In D.P.U. 96-50, the productivity factor was set at 1.50% and the service quality penalty was expanded beyond the $1 million proposed in our Plan. We appealed D.P.U. 96-50 and on January 16, 2001, the Department limited the maximum service quality adjustment to $1 million and adjusted the productivity factor to 1.0%. On January 30, 2001, we appealed the imposition of the 0.5% accumulated inefficiencies adjustment and on March 7, 2002, the Supreme Judicial Court of Massachusetts ruled in favor of the Company and eliminated the accumulated inefficiencies factor of 0.5%, thereby reducing the productivity factor to 0.5%. On November 1, 2001, the Department issued an order requiring all Massachusetts electric and gas utilities to develop service quality plans effective January 1, 2002. On April 17, 2002, the Department issued an order approving our service quality plan that was filed with the Department on March 1, 2002. Service quality will be tracked and measured against historical benchmarks. Our failure to meet the Department's service quality standards is subject to a maximum penalty equivalent to 2% of its distribution service revenues. Each measurement period will be a calendar year. The first measurement period began on January 1, 2002. For the year ended 2002, we met the Department's service quality standards and were not subject to any penalties. All of our customers are eligible to purchase unbundled local transportation service from the Company and to purchase their gas supply from third parties. In 2000, the Department approved Model Terms and Conditions for residential customer tariffs effective November 1, 2000. The Model Terms and Conditions are consistent with the Department's order of February 1, 1999 which provided that, for a five-year transition period, local distribution company ("LDC") contractual commitments to upstream capacity will be assigned on a mandatory, pro rata basis to marketers selling gas supply to the LDC's customers. The approved mandatory assignment method eliminates the possibility that because of the migration of customers to the gas supply service of third parties, the costs of upstream interstate gas pipeline capacity purchased by the Company to serve firm customers would be absorbed by the LDC or other customers through the transition period. The Department also found that, through the transition period, LDCs will retain primary responsibility for upstream capacity planning and procurement to assure that adequate capacity is available at Massachusetts city gates to support customer requirements and growth. In year three of the five-year transition period, the Department intends to evaluate the extent to which the upstream capacity market for Massachusetts is workably competitive based on a number of factors and accelerate or decelerate the transition period accordingly. 9 Securities and Exchange Commission Regulation The Company, as a wholly owned subsidiary of KeySpan, is subject to the jurisdiction of the SEC under PUHCA. The rules and regulations under PUHCA generally limit the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. In addition, the principal regulatory provisions of PUHCA: (i) regulate certain transactions among affiliates within a holding company system including the payment of dividends by such subsidiaries to a holding company; (ii) govern the issuance, acquisition and disposition of securities and assets by a holding company and its subsidiaries; (iii) limit the entry by registered holding companies and their subsidiaries into businesses other than electric and/or gas utility businesses; and (iv) require SEC approval for certain utility mergers and acquisitions. As a result of an order issued by the SEC on November 8, 2000, in connection with KeySpan's acquisition of KNE LLC and EnergyNorth, Inc., and as amended on December 6, 2002 and February 14, 2003, we are committed through December 31, 2003 to have common equity of at least 30% of total capitalization, including affiliated debt. At December 31, 2002, our common equity was 35.8% of total capitalization, including affiliated debt. Environmental Matters The Company has or shares responsibility under applicable environmental law for the remediation of former manufactured gas plant operations, including former operating plants, gas holder locations and satellite disposal sites. Information with respect to the remediation of these sites may be found in Note 9 of the Notes to Financial Statements. Such information is incorporated herein by reference. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. We are subject to various risk exposures and uncertainties associated with our operations. The most significant contingency involves the evolution of the gas distribution industry towards a more competitive and deregulated environment. In addition, we are exposed to commodity price risk. Set forth below is a description of these exposures and an explanation as to how we have managed and, to the extent possible, sought to reduce these risks. Regulatory Issues and the Competitive Environment In July 1997, the Department directed Massachusetts gas distribution companies to undertake a collaborative process with other stakeholders to develop common principles under which comprehensive gas service unbundling might proceed. A settlement agreement by the LDC's and the marketer group regarding model terms and conditions for unbundled transportation service was approved by the Department in November 1998. In February 1999, the Department issued its order on how unbundling of natural gas service will proceed. For a five-year transition period, the Department determined that LDC's contractual commitments to upstream capacity will be assigned on a mandatory, pro rata basis to marketers selling gas supply to the LDC's customers. The approved mandatory assignment method eliminates the possibility that the costs of upstream capacity purchased by the LDC's to serve firm customers will be absorbed by other customers through the transition period. The Department also found that, through the transition period, LDCs will retain primary responsibility for upstream capacity planning and procurement to assure that adequate capacity is available to support customer requirements and growth. The Department approved the LDC's Terms and Conditions of Distribution Service that conform to the settled upon model terms and conditions. Since November 1, 2000, all Massachusetts gas customers have the option to purchase their gas supplies from third party sources other than the LDC's. We believe that the actions described above strike a balance among competing stakeholder interests in order to most effectively make available the benefits of the unbundled gas supply market to all customers. 10 Commodity Price and Credit Risk Weather Derivatives The utility tariffs associated with our operations do not contain a weather normalization clause. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of operations. To mitigate the effect of fluctuations from normal weather on our financial position and cash flows, we sold heating degree-day call options and purchased heating-degree day put options for the November 2002 - April 2003 winter season. With respect to sold call options, we are required to make a payment of $40,000 per heating degree day to our counter-parties when actual weather experienced during the November 2002 - April 2003 time frame is above 4,470 heating degree days, which equates to approximately 1% colder than normal weather. With respect to purchased put options, we will receive a $20,000 per heating degree day payment from our counter-parties when actual weather is below 4,150 heating degree days, or is approximately 7% warmer than normal. Based on the terms of such contracts, as discussed in Note 11 of the Notes to Financial Statements, we account for such instruments pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives." In this regard, we account for such instruments using the "intrinsic value method" as set forth in such guidance. During the fourth quarter of 2002, weather was approximately 7.4% colder than normal and we recorded a $3.3 million reduction to revenues with a corresponding liability due to our counter-parties. Our derivative contracts are primarily used to manage exposure to market risk arising from changes in demand as a result of weather colder or warmer than normal. In the event of nonperformance by a counter-party to a derivative contract, the desired impact may not be achieved. The risk of a counter-party nonperformance is generally considered credit risk and is actively managed by assessing each counter-party credit profile and negotiating appropriate levels of collateral and credit support. Physically-Settled Commodity Derivative Instruments: On April 1, 2002 we implemented Derivative Implementation Group ("DIG") C16 of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted, incorporating SFAS 137 and 138 and certain implementation issues (collectively "SFAS 133"). Issue C16 relates to the exemption (as normal purchases and normal sales) of contracts that combine a forward contract and a purchased option contract. Based upon a review of our physical commodity contracts, we determined that certain contracts for the physical purchase of natural gas can no longer be exempted as normal purchases from the requirements of SFAS 133. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts is subject to SFAS 71. Therefore, changes in the market value of these contracts are recorded as a deferred asset or deferred liability on the Balance Sheet. Item 8. Financial Statements and Supplementary Data. Information with respect to this item appears commencing on Page F-1 of this Report. Such information is incorporated herein by reference. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Arthur Andersen LLP ("Arthur Andersen") served as the Company's independent public accountants since May 1998. On March 29, 2002, our Board of Directors, determined not to renew the engagement of Arthur Andersen and appointed Deloitte & Touche LLP ("Deloitte & Touche") as independent public accountants. During the past two fiscal years through March 29, 2002, there was no report on the financial statements of the Company by Arthur Andersen that contained an adverse opinion or a disclaimer of opinion, or was qualified or modified as to uncertainty, audit scope, or accounting principles. During the past two fiscal years through March 29, 2002, there were no disagreements with Arthur Andersen on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of Arthur Andersen, would have caused the firm to make reference to the subject matter of such disagreements in connection with their respective reports. 11 PART III Item 10. Directors and Executive Officers of the Registrant. Not required. Item 11. Executive Compensation. Not required. Item 12. Security Ownership of Certain Beneficial Owners and Management. Not required. Item 13. Certain Relationships and Related Transactions. Not required. Item 14. Controls and Procedures Evaluation of Disclosure Controls and Procedures Within 90 days prior to the date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including its Chief Operating Officer and Principal Financial and Accounting Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures. The Company's disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in its periodic SEC filings is recorded, processed and reported within the time periods specific in the SEC's rules and forms. Based upon that evaluation, the Chief Operating Officer and Principal Financial and Accounting Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in its periodic SEC filings. Changes In Internal Controls There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. 12 PART IV Item 15. 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 F-1 of this Report. Such information is incorporated herein by reference. (3) List of Exhibits. 3.1 Restated Articles of Organization, as amended (Filed as Exhibit 3.1 to the registration statement of the Company on Form S-3 (File No. 33-48525)).* 3.2 By-Laws of the Company as amended (Filed as Exhibit 1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1976 (File No. 2-23416)).* (Note: Certain instruments with respect to long-term debt of the Company or its subsidiary are not filed herewith since no such instrument authorizes securities in an amount greater than 10% of the total assets of the Company and its subsidiary on a consolidated basis. The Company agrees to furnish to the Securities and Exchange Commission upon request a copy of any such omitted instrument of the Company or its subsidiary.) 4.1 Indenture dated as of December 1, 1989 between the Company and The Bank of New York, Trustee (Filed as Exhibit 4.2 to the registration statement of the Company on Form S-3 (File No. 33-31869)).* 4.2 Agreement of Registration, Appointment and Acceptance dated as of November 18, 1992 among the Company, The Bank of New York as Resigning Trustee, and The First National Bank of Boston as Successor Trustee. (Filed as an exhibit to registration statement of the Company on Form S-3 (File No. 33-31869)).* 4.3 Utility Money Pool Agreement. (filed as an exhibit 4.3 to the Annual Report of the company on Form 10-K for the year ended December 31, 2000).* 10.1 Gas Transportation Contract between the Company and Tennessee Gas Pipeline Company dated as of September 1, 1993 providing for transportation of approximately 94,000 dekatherms of natural gas per day (Filed as Exhibit 10.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1993).* 10.2 Gas Transportation Contract between the Company and Texas Eastern dated October 29, 1999 providing for transportation of approximately 48,133 dekatherms of natural gas per day. (Filed as Exhibit 10.2 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.3 Gas Transportation Contract between the Company and Texas Eastern dated December 30, 1993 providing for transportation of approximately 32,000 dekatherms of natural gas per day. (Filed as Exhibit 10.3 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1993).* 10.4 Gas Transportation Contract between the Company and Algonquin dated October 29, 1999 providing for transportation of approximately 45,000 dekatherms of natural gas per day. (Filed as Exhibit 10.4 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.5 Agreement between the Company and Maritimes Northeast Pipeline L.L.C. dated January 4, 1999 providing for transportation of approximately 43,200 dekatherms of natural gas per day. (Filed as Exhibit 10.5 to the Annual Report of the Company on Form 10-K for the year ended December 31, 2001).* 10.6 Gas Storage Agreement between the Company and Honeoye Storage Corporation dated October 11, 1985 providing for storage demand of 6,150 dekatherms of natural gas per day. (Filed as Exhibit 10.17 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1985).* 13 10.7 Firm Gas Transportation agreement between the Company and Algonquin Gas Transmission Company dated July 27, 2000 providing for transportation of approximately 15,000 dekatherms of natural gas per day. Filed as Exhibit 10.7 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1985).* 10.8 Gas Sales Contract between the Company and Esso Resources Canada, Limited, (now Imperial Oil of Canada, Ltd.) dated as of May 1, 1989. (Filed as Exhibit 10.12 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1989).* 10.8.1 Amendment to the Gas Sales Contract between the Company and Esso Resources (now Imperial Oil of Canada), dated as of November 12, 1997 and Bridge Agreement dated as of October 23, 1997, executed pursuant to Master Agreement dated as of November 1, 1997. (Filed as Exhibit 10.9.2 to the Annual Report of the Company on Form 10K for the year ended December 31, 1998).* 10.9 Gas Sales Agreement between the Company and Boundary Gas, Inc., dated as of September 14, 1987; and First Amendment hereto dated as of January 1, 1990; Second Amendment thereto dated as of July 1, 1990; Third Amendment thereto dated as of 1991; Fourth Amendment thereto dated as of June 5, 1991; Fifth Amendment thereto dated as of May 4, 1993; Sixth Amendment thereto dated as of September 9, 1993; Amendment thereto dated as of March 8, 1996; and Amendment thereto dated as of August 20, 1997. (Filed as Exhibit 10.10 to the Annual Report of the Company on Form 10K for the year ended December 31, 1994.)* 10.10Gas Sales Agreement between the Company and Alberta Northeast Gas, Ltd. dated as of February 7, 1991. (Filed as Exhibit 10.16 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1990).* 10.10.1 Amendments to the Gas Sales Agreement between the Company and Alberta Northeast Gas, Ltd., dated as of October 1, 1992; May 5, 1993; November 27, 1995; and March 14, 1996. (Filed as Exhibit 10.12.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1998).* 10.11Firm Gas Transportation Agreement between the Company and Iroquois Gas Transmission System, L.P. dated as of February 7, 1991. (Filed as Exhibit 10.17 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1990).* 10.11.1 Amendment dated as of November 3, 1998 to the Firm Gas Transportation Agreement between the Company and Iroquois Gas Transmission System, L.P. dated as of February 7, 1991. (Filed as Exhibit 10.13.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.12Firm Gas Transportation Agreement between the Company and Tennessee Gas Pipeline Company dated as of February 7, 1991. (Filed as Exhibit 10.18 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1990).* 10.13Gas Transportation Contract between the Company and Algonquin dated October 29, 1999 providing for transportation of approximately 29,000 dekatherms of natural gas per day. (Filed as Exhibit 10.15 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.14Gas Transportation Contract between the Company and Algonquin dated October 29, 1999 providing for transportation of approximately 96,000 dekatherms of natural gas per day. (Filed as Exhibit 10.16 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 14 10.15Gas Transportation Contract between the Company and Algonquin dated October 29, 1999 providing for transportation of approximately 20,000 dekatherms of natural gas per day. (Filed as Exhibit 10.17 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.16Gas Transportation Contract between the Company and Algonquin dated December 1, 1994 providing for transportation of approximately 20,000 dekatherms of natural gas per day. (Filed as Exhibit 10.19 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.17Gas Transportation Contract between the Company and Algonquin dated January 1, 1998 providing for transportation of approximately 27,000 dekatherms of natural gas per day. (Filed as Exhibit 10.20 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.18Gas Transportation Contract between the Company and CNG Transmission dated October 1, 1993 providing for transportation of approximately 21,000 dekatherms of natural gas per day. (Filed as Exhibit 10.23 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.18.1 Amendment dated as of August 1, 2002 to the Gas Transportation Contract between the Company and CNG Transmission dated October 1, 1993 providing for a MDQ reduction to 12,978 dekatherms, and extending the term to October 31, 2005. (Filed as Exhibit 10.18.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.19Gas Storage Contract between the Company and CNG Transmission dated November 1993 providing for storage demand of 42,000 dekatherms of natural gas per day. (Filed as Exhibit 10.24 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.20Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 10,000 dekatherms of natural gas per day. (Filed as Exhibit 10.25 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.20.1 Amendment dated October 31, 2002 to the Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 10,533 dekatherms of natural gas per day and extending term of the agreement to October 31, 2008. (Filed as Exhibit 10.20.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.21Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 8,600 dekatherms of natural gas per day. (Filed as Exhibit 10.28 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.22Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 41,000 dekatherms of natural gas per day. (Filed as Exhibit 10.29 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.22.1 Amendment dated October 31, 2002 to the Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 41,687 dekatherms of natural gas per day and extending term of the agreement to October 31, 2008. (Filed as Exhibit 10.22.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.23Gas Storage Contract between the Company and Tennessee Gas Pipeline dated December 1, 1994 providing for storage demand of approximately 71,000 dekatherms of natural gas per day. (Filed as Exhibit 10.31 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 15 10.23.1 Amendment dated as of October 31, 2002 to the Gas Storage Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for storage demand of approximately 41,687 dekatherms of natural gas per day and extending term of the agreement to October 31, 2008. (Filed as Exhibit 10.23.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.24Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1996 providing for transportation of approximately 13,000 dekatherms of natural gas per day. (Filed as Exhibit 10.32 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.24.1 Amendment dated as of October 31, 2002 to the Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1996 providing for transportation of approximately 13,027 dekatherms of natural gas per day and extending term of the agreement to October 31, 2008. (Filed as Exhibit 10.24.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.25Gas Transportation Contract between the Company and Texas Eastern Transmission dated December 30, 1993 providing for transportation of approximately 39,000 dekatherms of natural gas per day. (Filed as Exhibit 10.33 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.25.1 Amendment dated as of October 29, 1998 to the Gas Transportation Contract between the Company and Texas Eastern Transmission dated December 30, 1993 providing for transportation of approximately 39,000 dekatherms of natural gas per day (Filed as Exhibit 10.27.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.26Gas Transportation Contract between the Company and Texas Eastern Transmission dated December 30, 1993 providing for transportation of approximately 21,000 dekatherms of natural gas per day. (Filed as Exhibit 10.34 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.27Gas Transportation Contract between the Company and Texas Eastern Transmission dated December 30, 1993 providing for transportation of approximately 5,000 dekatherms of natural gas per day (terminated on October 31, 2002). (Filed as Exhibit 10.35 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.28Gas Transportation Contract between the Company and Texas Eastern Transmission dated October 29, 1999 providing for transportation of approximately 29,000 dekatherms of natural gas per day. (Filed as Exhibit 10.30 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.29Gas Transportation Contract between the Company and Transcontinental Gas Pipeline dated June 1, 1993 providing for transportation of approximately 6,000 dekatherms of natural gas per day. (Filed as Exhibit 10.40 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.30Gas Transportation Contract between the Company and Texas Gas Transmission dated November 1, 1993 providing for transportation of approximately 13,000 dekatherms of natural gas per day. (Filed as Exhibit 10.41 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 16 10.31Gas Transportation Contract between the Company and Texas Gas Transmission dated November 1, 1993 providing for transportation of approximately 13,000 dekatherms of natural gas per day. (Filed as Exhibit 10.41 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).* 10.31.1 Amendment dated as of October 31, 2002 to the Gas Transportation Contract between the Company and Tennessee Gas Pipeline dated September 1, 1993 providing for transportation of approximately 94,312 dekatherms of natural gas per day and extending term of the agreement to October 31, 2008. (Filed as Exhibit 10.31.1 to the Company's Form 10-K for the year ended December 31, 2002).* 10.32Agreement between the Company and Texas Eastern Transmission dated as of October 29, 1999 providing for storage demand of approximately 68,700 dekatherms of natural gas per day. (Filed as Exhibit 10.35 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.33Agreement between the Company and Algonquin LNG, Corp. dated as of October 29, 1999 providing for storage demand of approximately 35,000 dekatherms of natural gas per day. (Filed as Exhibit 10.36 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.34Contract Restructuring Agreement between the Company and Tennessee Gas Pipeline dated as of August 2, 1999. (Filed as Exhibit 10.37 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.35Redacted Gas Resource Portfolio Management and Gas Sales Agreement between the Company, Colonial Gas Company, Essex Gas Company and El Paso Energy Marketing Company dated as of September 14, 1999, as amended (terminated on October 31, 2002). (Filed as Exhibit 10.1 to the Form 10-K of Eastern Enterprises for the year ended December 31, 1999.).* 10.36Amended and Restated Lease Agreement between Industrial National Leasing Corporation, Lessor, and Boston Gas Company, Lessee, dated as of April 30, 1999. (Filed as Exhibit 10.39 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).* 10.37Precedent Agreement between the Company and Algonquin Gas Transmission Company dated as of June 13, 2001 providing for transportation of approximately 20,000 dekatherms of natural gas per day. (Filed as Exhibit 10.40 to the Company's Form 10-K for the year ended December 31, 2001).* 10.38Agreement between the Company and Maritimes Northeast Gas Pipeline Limited Partnership dated June 16, 1999 providing for transportation of approximately 43,200 dekatherms of natural gas per day. (Filed as Exhibit 10.41 to the Company's Form 10-K for the year ended December 31, 2001).* 10.39Redacted Gas Resource Portfolio Management and Gas Sales Agreement between the Company, Colonial Gas Company and Essex Gas Company and Entergy-Koch Trading, LP, dated as of October 29, 2002. (Filed as Exhibit 10.39 to the Company's Form 10-K for the year ended December 31,2002).* 17 31.1 Certification of the President and Chief Operating Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated August 13, 2003.(Filed herewith) 31.2 Certification of the Senior Vice President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated August 13, 2003. (Filed herewith) 32.1 Certification of the President and Chief Operating Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 dated March 28, 2003. (Filed herewith) 32.2 Certification of the Senior Vice President and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 dated March 28, 2003. (Filed herewith) 32.3 Certification of the President and Chief Operating Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 dated August 13, 2003. (Filed herewith) 32.4 Certification of the Senior Vice President and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 dated August 13, 2003. (Filed herewith) Reports on Form 8-K There were no reports on Form 8-K filed in the Fourth Quarter of 2002. * 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. 18 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 D/B/A KeySpan Energy Delivery New England Registrant By: /s/NICKOLAS STAVROPOULOS ------------------------ Nickolas Stavropoulos Chief Operating Officer and President By: /s/JOSEPH F. BODANZA --------------------- Joseph F. Bodanza Senior Vice President and Chief Accounting Officer Dated: August 13, 2003 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 13th day of August, 2003. Signature Title --------- ----- Nickolas Stavropoulos --------------------- Nickolas Stavropoulos Director 19 BOSTON GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES (Information required by Items 8 and 14 (a) of Form 10-K) Independent Auditors' Report.................................................................................... F-25 Report of Independent Public Accountants - 2001 and prior....................................................... F-26 Statements of Operations for the Years Ended December 31, 2002 and 2001, and the Periods from November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000..................... F-2 Balance Sheets as of December 31, 2002 and 2001................................................................. F-3 and F-4 Statements of Retained Earnings (Deficit) and Statements of Comprehensive Income (Loss)for the Years Ended December 31, 2002 and 2001, and the Periods from November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000 ..................................... F-5 Statements of Cash Flows for the Years Ended December 31, 2002 and 2001, and the Periods from November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000.......................................................................................... F-6 Notes to Financial Statements.................................................................................... F-7 to F-24 Interim Financial Information for the Two years Ended December 31, 2002 (unaudited).............................. F-27 Schedule for the Years Ended December 31, 2002 and 2001, and the Periods from November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000: Schedule II--Valuation and Qualifying Accounts......................................................... F-28 Schedules other than that listed above have been omitted as the information has been included in the financial statements and related notes or is not applicable or required.
F-1
BOSTON GAS COMPANY STATEMENTS OF OPERATIONS - ----------------------------------------------------------------------------------------------------------------------------------- Period from Period from November 8, January 1, Year Ended December 31, 2000 through 2000 through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - -------------------------------------------------------------------------------------------------------------------------------- Predecessor Operating Revenues $ 639,111 $ 828,938 $ 202,842 $ 453,783 Cost of gas sold 345,823 558,683 131,516 247,548 --------------------- -------------------- ------------------- ----------------- Operating Margin 293,288 270,255 71,326 206,235 Operating Expenses: Operations and maintenance 154,095 156,956 25,259 123,667 Depreciation and amortization 56,203 52,261 10,745 39,515 Amortization of goodwill - 19,439 3,226 - Operating taxes 17,401 23,570 4,557 18,918 Merger related expenses - - 101 23,347 --------------------- -------------------- ------------------- ----------------- Total Operating Expenses 227,699 252,226 43,888 205,447 --------------------- -------------------- ------------------- ----------------- Operating Income 65,589 18,029 27,438 788 --------------------- -------------------- ------------------- ----------------- Other Income 258 2,775 451 719 Interest Expense: Long-term debt 16,855 16,835 2,806 13,984 Other, including amortization of debt expense 50,658 43,867 3,501 (4,017) Less-Interest during construction (2,501) (686) (202) (704) --------------------- -------------------- ------------------- ----------------- Total Interest Expense 65,012 60,016 6,105 9,263 --------------------- -------------------- ------------------- ----------------- Income Before Income Taxes 835 (39,212) 21,784 (7,756) Income Taxes Current (63,870) 26,839 2,707 (21,186) Deferred 67,179 (35,895) 7,011 17,718 --------------------- -------------------- ------------------- ----------------- Total Income Tax Expense (Benefit) 3,309 (9,056) 9,718 (3,468) --------------------- -------------------- ------------------- ----------------- Net (Loss)Income (2,474) (30,156) 12,066 (4,288) Preferred stock dividends 975 1,096 183 1,174 --------------------- -------------------- ------------------- ----------------- Net Income (Loss) applicable for Common Stock $ (3,449) $ (31,252) $ 11,883 $ (5,462) ===================== ==================== =================== ================= The accompanying notes are an integral part of these financial statements.
F-2 BOSTON GAS COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, (In Thousands of Dollars) 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------------ ASSETS Property: Gas plant, at cost $ 1,194,842 $ 1,070,610 Construction in progress 10,415 27,875 Less-Accumulated depreciation (470,556) (425,163) ---------------------------- ----------------------------- 734,701 673,322 ---------------------------- ----------------------------- Current assets: Cash and temporary cash investments 2,168 3,104 Accounts receivable 123,681 95,393 Allowance for uncollectible accounts (14,666) (14,730) Accounts receivable-affiliates 4,195 8,851 Accrued utility revenue 66,619 50,693 Deferred gas costs 68,647 15,670 Natural Gas and other inventories, at average cost 74,549 79,544 Material and supplies, at average cost 4,754 3,996 Prepaid expenses and other 371 377 ---------------------------- ----------------------------- 330,318 242,898 ---------------------------- ----------------------------- Other Assets: Goodwill 790,285 790,285 Deferred postretirement cost 44,360 42,585 Deferred charges and other assets 96,378 56,261 ---------------------------- ----------------------------- 931,023 889,131 ---------------------------- ----------------------------- Total Assets $ 1,996,042 $ 1,805,351 - ------------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these financial statements.
F-3 BOSTON GAS COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, (In Thousands of Dollars) 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------ LIABILITIES AND CAPITALIZATION Capitalization Common stock, $100 par value-authorized and outstanding-514,184 shares $ 51,418 $ 51,418 Amounts in excess in par value 560,575 360,575 Accumulated deficit (22,817) (19,368) Accumulated other comprehensive income (9,823) (692) -------------------------- --------------------------- Total common stockholder's investment 579,353 391,933 Cumulative Preferred stock, $1 par value, liquidation preference $25 per share-562,700 and 622,700 shares at December 31, 2002 and 2001, respectively 13,840 15,289 Long-term obligations, less current portion 222,563 223,403 -------------------------- --------------------------- Total Capitalization 815,756 630,625 -------------------------- --------------------------- Advance from KeySpan 650,000 650,000 -------------------------- --------------------------- Total Capitalization and Advance from KeySpan 1,465,756 1,280,625 -------------------------- --------------------------- Commitments and Contingencies(See Note 6) Current Liabilities Current portion of long-term obligations 840 586 Notes payable utility pool 67,174 147,350 Notes payable utility pool - gas inventory financing 83,907 85,401 Accounts payable and affiliates 131,380 99,608 Accrued taxes 4,495 5,740 Accrued income taxes (6,747) (2,432) Accrued interest 4,334 11,377 Customer deposits 1,563 1,884 Other current liabilities - 157 -------------------------- --------------------------- 286,946 349,671 -------------------------- --------------------------- Deferred Credits and Other Liabilities Deferred income tax 141,408 73,609 Unamortized investment tax credits 1,714 2,556 Postretirement benefits obligation 53,747 50,901 Environmental liability 28,831 31,878 Other 17,640 16,111 -------------------------- --------------------------- 243,340 175,055 -------------------------- --------------------------- Total Capitalization and Liabilities $ 1,996,042 $ 1,805,351 - ------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these financial statements.
F-4
BOSTON GAS COMPANY STATEMENTS OF RETAINED EARNINGS (DEFICIT) - ---------------------------------------------------------------------------------------------------------------------------------- Period from Period from November 8, January 1, 2000 Year Ended December 31, 2000 through through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ---------------------------------------------------------------------------------------------------------------------------------- Predecessor Balance at beginning of period $ (19,368) $ 11,883 $ - $ 189,517 Net (loss) income (2,474) (30,155) 12,066 (4,288) Preferred stock dividend (975) (1,096) (183) (1,174) Common stock dividend - - - (22,496) - ---------------------------------------------------------------------------------------------------------------------------------- Balance at end of period $ (22,817) $ (19,368) $ 11,883 $ 161,559 - ----------------------------------------------------------------------------------------------------------------------------------
BOSTON GAS COMPANY STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - ------------------------------------------------------------------------------------------------------------------------------------ Period from Period from November 8, January 1, 2000 Year Ended December 31, 2000 through through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ------------------------------------------------------------------------------------------------------------------------------------ Predecessor Net (loss) income $ (2,474) $ (30,155) $ 12,066 $(4,288) - ------------------------------------------------------------------------------------------------------------------------------------ Other Comprehensive income (loss) net of tax Accrued unfunded pension obligation (9,374) (692) - - - ------------------------------------------------------------------------------------------------------------------------------------ Other Comprehensive income (loss) net of tax $ (9,374) $ (692) $ - $ - - ------------------------------------------------------------------------------------------------------------------------------------ Comprehensive (loss) income $ (11,848) $ (30,847) $ 12,066 $(4,288) - ------------------------------------------------------------------------------------------------------------------------------------ Related tax (benefit) expense Accrued unfunded pension obligation (5,047) (373) - - - ------------------------------------------------------------------------------------------------------------------------------------ Total tax (benefit) $ (5,047) $ (373) $ - $ - - ------------------------------------------------------------------------------------------------------------------------------------ The accompanying notes are an integral part of these financial statements.
F-5
STATEMENTS OF CASH FLOWS - ----------------------------------------------------------------------------------------------------------------------------------- Period from Period from November 8, January 1, Year Ended Year Ended 2000 through 2000 through (In Thousands of Dollars) December 31, 2002 December 31, 2001 December 31, 2000 November 7, 2000 - ----------------------------------------------------------------------------------------------------------------------------------- Predecessor Operating Activities Net (loss) income $ (2,474) $ (30,155) $ 12,066 $ (4,288) Adjustments to reconcile net income to net cash provided by (used in) operating activities Depreciation and amortization 56,203 71,700 13,971 39,515 Deferred income tax 67,179 (35,895) 7,011 17,718 Changes in assets and liabilities Accounts receivable and affiliates (23,637) 10,812 (61,736) 46,483 Accrued utility revenue (15,926) 21,130 (16,287) 14,029 Natural Gas and other inventories 4,237 (22,396) 18,987 (31,560) Deferred gas costs (52,977) 61,995 (51,225) (28,066) Accounts payable and affiliates (31,772) (5,735) 25,060 32,314 Accrued income taxes (5,560) 16,178 5,249 (20,495) Other 6,200 (2,929) 3,237 4,056 ---------------- ---------------- ---------------- ---------------- Net Cash Provided by (Used in) Operating Activities 1,473 84,705 (43,667) 69,706 ---------------- ---------------- ---------------- ---------------- Investing Activities Capital expenditures (110,360) (111,735) (21,802) (52,958) Net cost of removal (7,904) (6,834) (1,272) (4,628) ---------------- ---------------- ---------------- ---------------- Net Cash Used in Investing Activities (118,264) (118,569) (23,074) (57,586) ---------------- ---------------- ---------------- ---------------- Financing Activities Changes in advance from KeySpan 50,000 Capital Contribution from KNE LLC 200,000 Changes in notes payable - utility money pool (80,176) 32,507 54,843 8,800 Changes in gas inventory financing - utility money pool (1,494) 3,094 13,719 14,568 Redemption of preferred stock (1,500) (1,500) (9,933) Dividends paid on common and preferred stock (975) (51,096) (183) (23,670) Other 47 4 217 ---------------- ---------------- ---------------- ---------------- Net Cash Provided by (Used in) Financing Activities 115,855 33,052 68,383 (10,018) ---------------- ---------------- ---------------- ---------------- Net (Decrease) or Increase in Cash and Cash Equivalents $ (936) $ (812) $ 1,642 $ 2,102 ================ ================ ================ ================ Cash and Cash Equivalents at Beginning of Period 3,104 3,916 2,274 172 ---------------- ---------------- ---------------- ---------------- Cash and Cash Equivalents at End of Period $ 2,168 $ 3,104 $ 3,916 $ 2,274 ================ ================ ================ ================ Interest Paid $ 79,813 $ 75,438 $ 18,255 $ - Income Tax Paid $ 1,310 $ 2,489 $ (1,718) $ 115 - ------------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements.
F-6 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (1) Accounting Policies General Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein as the "Company", "we" "us and "our") 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 is a wholly-owned subsidiary of KeySpan New England LLC ("KNE LLC") (Formerly known as Eastern Enterprises) and an indirect wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), a registered holding company under the Public Utility Holding Company Act ("PUHCA") of 1935, as amended. Basis of Presentation The accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Massachusetts Department of Telecommunications and Energy (the "Department"). The accounting policies of the Company conform to generally accepted accounting principles and reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement recognizes the ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, we record these future economic benefits and obligations as Regulatory Assets and Regulatory Liabilities on the Balance Sheet, respectively. The financial statements include the accounts of the Company and its wholly-owned subsidiary, Massachusetts LNG Incorporated, which became inactive in 1999. 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. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation. Merger and Goodwill On November 8, 2000, KeySpan acquired all of the common stock of KNE LLC for $64.56 per share in cash. The transaction was accounted for using the purchase method of accounting for business combinations. The purchase price was allocated to the net assets acquired of KNE LLC and its subsidiaries based upon their fair value. The historical cost basis of the Company's assets and liabilities, with minor exceptions, was determined to represent the fair value due to the existence of regulatory-approved rate plans based upon the recovery of historical costs and a fair return thereon. Under "push-down" accounting, the excess of the purchase price over the fair value of the Company's net assets acquired, or goodwill, of approximately $774 million was recorded as an asset and was being amortized over a period of 40 years (see below). The push-down accounting resulted in an increase in equity of $170 million and the recording of a $600 million advance from KeySpan. An additional $38.7 million was recorded as goodwill in finalizing the purchase price allocation, of which $36.2 million was an addition to equity. F-7 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (1) Accounting Policies (Continued) On January 1, 2002, the Company adopted SFAS 142 "Goodwill and Other Intangible Assets". Under SFAS 142, among other things, goodwill is no longer required to be amortized and is to be tested for impairment at least annually. The initial impairment test was to be performed within six months of adopting SFAS 142 using a discounted cash flow method, compared to an undiscounted cash flow method allowed under a previous standard. Any amounts impaired using data as of January 1, 2002, was to be recorded as a "Cumulative Effect of an Accounting Change". Any amounts impaired using data after the initial adoption date will be recorded as an operating expense. During the second quarter of 2002, we completed our initial impairment analysis for the Company and determined that no impairment existed. Also, in the fourth quarter of 2002, we updated our review of the carrying value of goodwill compared to the fair value of the assets by reporting unit and determined that no impairment existed. As required by SFAS 142, below is a reconciliation of reported net income (loss) applicable for common stockholders for the years ended December 31, 2002 and 2001 and the periods from November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000 and pro-forma net income (loss), for the same periods, adjusted for the discontinuance of goodwill amortization.
- ------------------------------------------------------------------------------------------------------------------------------------ Period from Period from November 8, January 1, Year Ended December 31, 2000 through 2000 through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ------------------------------------------------------------------------------------------------------------------------------------ Predecessor Net income (loss) applicable for common stock $ (3,449) $ (31,251) $ 11,883 $ (5,462) Add back: goodwill amortization - 19,439 3,226 - - ------------------------------------------------------------------------------------------------------------------------------------ Adjusted net income (loss) applicable for common stock $ (3,449) $ (11,812) $ 15,109 $ (5,462) - ------------------------------------------------------------------------------------------------------------------------------------
Recent Accounting Pronouncements On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142 "Goodwill and Other Intangible Assets". The key concepts from the two interrelated Statements include mandatory use of the purchase method when accounting for business combinations, discontinuance of goodwill amortization, a revised framework for testing goodwill impairment at a "reporting unit" level and new criteria for the identification and potential amortization of other intangible assets. Other changes to existing accounting standards involve the amount of goodwill to be used in determining the gain or loss on the disposal of assets and a requirement to test goodwill for impairment at least annually. In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS 143 is effective for fiscal years beginning after June 2002. F-8 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (1) Accounting Policies (Continued) We have completed our assessment of SFAS 143. Our asset base is primarily composed of storage, and distribution assets which we believe operate in perpetuity and, therefore, have indeterminate cash flow estimates. A legal obligation may be construed to exist due to certain safety requirements at final abandonment. In addition, a legal obligation may be construed to exist with respect to our LNG storage tanks due to clean up responsibilities upon cessation of use. Since that exposure is in perpetuity and cannot be measured, no liability will be recorded. Our asset retirement obligation will be re-evaluated annually. SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", was effective January 1, 2002, and addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business". SFAS 144 retains the fundamental provisions of SFAS 121 and expands the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. For 2002, implementation of this Statement did not have any effect on our results of operations and financial position. In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities". This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability recognition for Certain Employee Termination benefits and Other Costs to Exit an Activity". This Statement is effective for exit or disposal activities initiated after December 31, 2002, with early application encouraged. In November 2002, the FASB issued FASB Interpretation No. 45("FIN 45"), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires the guarantor to recognize a liability for the non-contingent component of a guarantee; that is, the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even if it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. FIN 45 also requires additional disclosures related to guarantees. The disclosure requirements are effective for interim and annual financial statements for periods ending after December 15, 2002. The recognition and measurement provisions of FIN 45 are effective for all guarantees entered into or modified after December 31, 2002. We currently do not anticipate that implementation of this Statement will have any effect on our results of operations and financial condition. In January 2003, the FASB issued FASB Interpretation No. 46 ("FIN 46"), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51." FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. At the present time, we do not have any arrangements with variable interest entities. F-9 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (1) Accounting Policies (Continued) Regulation The Company is regulated as to rates, accounting and other matters by the Department. Therefore, we account for the economic effects of regulation in accordance with the provisions of SFAS 71. In the event that we determine that the Company 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. Management believes that this amount would approximate $49.0 million, net of taxes, as of December 31, 2002. Criteria that gives rise to the discontinuance of SFAS 71 include (1) increasing competition that restricts our ability to establish prices to recover specific costs or (2) a significant change in the manner in which rates are set by regulators. We have reviewed these criteria and believe that the continued 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 rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. The following regulatory assets were reflected on the balance sheet as of December 31: - ---------------------------------------------------------------------------- In Thousands of Dollars 2002 2001 - ---------------------------------------------------------------------------- Post-retirement benefit costs $ 44,360 $ 42,585 Environmental costs 36,939 35,917 - ---------------------------------------------------------------------------- $ 81,299 $ 78,502 - ---------------------------------------------------------------------------- Environmental costs are included in Deferred Charges and Other Assets on the Balance Sheet. Regulatory liabilities, primarily relating to income taxes, total approximately $5.9 million and $6.8 million at December 31, 2002 and 2001, respectively. These amounts are included in Other Deferred Credits and Other Liabilities on the Balance Sheet. As of December 31, 2002, all of our regulatory assets and liabilities for which cash expenditures have been made or cash has been received are reflected in rates charged or credited to customers. We estimate that full recovery of our regulatory assets will not exceed 20 years. For additional information regarding deferred income taxes, post-retirement benefit costs and environmental costs, see Notes 2, 5 and 9, respectively. Gas Operating Revenues Customers are billed monthly on a cycle basis. Revenues include unbilled amounts related to the estimated gas usage that occurred from the most recent meter reading to the end of each month. F-10 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (1) Accounting Policies (Continued) Cost of Gas Adjustment Clause and Deferred Gas Costs The cost of gas adjustment clause ("CGAC") requires us to semiannually, or based on certain criteria monthly, adjust rates for firm gas sales in order to track changes in the cost of gas distributed, with an annual adjustment of subsequent rates made for any over or under recovery of actual costs incurred. As a result, the cost of firm gas that has been distributed to customers but is unbilled at the end of a period is deferred to the period in which the gas is billed to customers. We recover the gas cost portion of bad debt write-offs through the CGAC. In addition, through a local distribution adjustment clause ("LDAC"), we are allowed to recover the amortization of environmental response costs associated with former manufactured gas plant ("MGP") sites, costs related to the our various conservation and load management programs, and other specified costs from our firm sales and transportation customers. Property and Depreciation Utility gas property is stated at original cost of construction, which includes allocations of overheads, including taxes, and an allowance for funds used during construction. 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, is approximately 5.0% for all periods presented. Amortization is provided on intangible assets, principally software, over the estimated useful life of these assets. Accumulated depreciation is charged with original cost and the 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. (2) Income Taxes For 2002, the Company will file a consolidated income tax return with KeySpan. We also filed a consolidated return with KeySpan for the year ended 2001 and the period from November 8, 2000 through December 31, 2000. Under the KeySpan tax sharing agreement, the allocation of the realized tax liability or benefit on the federal consolidated income tax return will be based upon separate return contributions of each company in the consolidated group to the consolidated taxable income or loss. For the period January 1, 2000 through November 7, 2000, we filed a consolidated federal income tax return with KNE LLC. For this period, we followed a policy, established for the group, of providing for income taxes payable on a separate company basis. Our effective income tax rate was 396% in 2002, 23.1% for 2001, and 44.6% for the period from November 8 through December 31, 2000, and 44.7% for the period from January 1 through November 7, 2000. The majority of the differences between the effective rate and the federal income tax rate of 35% are primarily due to state income taxes for each of the periods as well as the non-deductibility of goodwill amortization for the periods from November 8, 2000 through December 31, 2001. In 2002, the effective income tax rate of 396% is primarily a function of $4.4 million in state taxes, net of a federal tax benefit, on only $895,000 of pre-tax book income. The state tax expense is high in relation to the book income due to deductions primarily related to pension contributions and deferred gas costs, which resulted in the Company generating a current state tax benefit and a deferred state tax expense. Massachusetts does not allow regulated utilities to utilize state net operating losses. Therefore, the Company is unable to offset its deferred tax expense with its current state tax benefit, resulting in the disproportionate expense for the current year. F-11 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (2) Income Taxes (Continued) A summary of the provision (benefit) for income taxes is as follows:
- ---------------------------------------------------------------------------------------------------------------------------------- Period from Period from November 8, January 1, Year Ended December 31, 2000 through 2000 through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ---------------------------------------------------------------------------------------------------------------------------------- Predecessor Current- Federal $ (60,391) $ 22,378 $ 2,258 $ (17,695) State (3,479) 4,461 449 (3,491) ----------------- ------------------ ------------------------ ----------------------- Total current provision(benefit) (63,870) 26,839 2,707 (21,186) Deferred- Federal 56,972 (30,198) 5,835 14,713 State 10,207 (5,697) 1,176 3,005 ----------------- ------------------ ------------------------ ----------------------- Total deferred provision(benefit) 67,179 (35,895) 7,011 17,718 Total provision(benefit) for income taxes $ 3,309 $ (9,056) $ 9,718 $ (3,468) - ----------------------------------------------------------------------------------------------------------------------------------
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. At December 31, 2002, the Company had a regulatory tax liability of $879,000 which represents the tax benefit of unamortized investment tax credits. This benefit is being passed back to customers over the lives of property giving rise to the investment credit. We also had a regulatory liability of $5.0 million at December 31, 2002, for excess deferred taxes being returned to customers over a 30-year period pursuant to a 1988 rate order. For income tax purposes, we use 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 liabilities at December 31, 2002 and 2001 are as follows: F-12 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (2) Income Taxes (Continued)
Year Ended Year Ended In Thousands of Dollars December 31, 2002 December 31, 2001 - ------------------------------------------------------------------------------------------------------------------- Assets: Regulatory liabilities $ 2,381 $ 2,718 Other 35,965 31,784 --------------------------- -------------------------- Total deferred tax assets 38,346 34,502 --------------------------- -------------------------- Liabilities: Accelerated depreciation (97,737) (85,333) Deferred gas costs (46,884) 2,604 Other (38,916) (19,752) --------------------------- -------------------------- Total deferred tax liabilities (183,537) (102,481) --------------------------- -------------------------- - ------------------------------------------------------------------------------------------------------------------- Total net deferred taxes $ (145,191) $ (67,979) - ------------------------------------------------------------------------------------------------------------------- Deferred income taxes are reflected in the balance sheet as follows: Accrued income taxes (current deferred) $ (3,783) $ 5,630 Deferred income taxes (long-term) (141,408) (73,609) --------------------------- -------------------------- $ (145,191) $ (67,979) =========================== ==========================
Investment tax credits are deferred and credited to income over the lives of the property giving rise to such credits. The credits to income for both 2002 and 2001 were $842,000, $140,000 for the period from November 8 through December 31, 2000 and $702,000 for the period from January 1 through November 7, 2000. (3) Debt Long-term Obligations The following table provides information on long-term obligations as of December 31:
(In Thousands of Dollars) 2002 2001 - ----------------------------------------------------------------------------------------------------------------------- 8.33%--9.75%, Medium-Term Notes Series A, due 2005--2022 $ 100,000 $ 100,000 6.93%--8.50%, Medium-Term Notes, Series B, due 2006--2024 50,000 50,000 6.80%--7.25%, Medium-Term Notes, Series C, due 2012--2025 60,000 60,000 Capital lease obligations (Note 6) 13,403 13,989 Less current portion (840) (586) - ----------------------------------------------------------------------------------------------------------------------- $ 222,563 $ 223,403 - -----------------------------------------------------------------------------------------------------------------------
F-13 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (3) Debt (Continued) There are no sinking fund requirements for the next two years related to the $210 million of Medium-Term Notes and none are callable prior to maturity. In 2005, $15 million of 8.875% Medium-Term Notes Series A, mature. In 2006, $12 million of 8.09% Medium-Term Notes Series B, mature. Annual maturities of capital lease obligations for 2003 through 2007 are $840,000, $891,000, $945,000, $1.0 million and $1.06 million, respectively. Utility Money Pool Borrowings Financing for the Company for working capital and gas inventory needs is obtained through the Company's participation in a utility money pool. The utility money pool is administered by KeySpan Corporate Services ("KCS"). At December 31, 2002, the Company had outstanding borrowings of $67.2 million and $83.9 million for working capital and gas inventory, respectively. Interest charged on outstanding borrowings is generally equal to KeySpan's short term borrowing rate, plus a proportional share of the administrative costs incurred in obtaining the required funds. All costs related to gas inventory borrowings are recoverable from customers through the CGAC. The average annual interest rate on these borrowings for 2002 was 2.9%. Advance from KeySpan As part of the acquisition by KeySpan in November 2000, the Company recorded a $600 million advance payable to KeySpan. During 2001, an additional $50 million was advanced from Keyspan. Interest charges equal interest incurred by KeySpan on debt borrowings issued by KeySpan. The weighted-average interest rate on these borrowings for 2002 is 7.78 %. Issuance expense is charged to the Company from KeySpan equal to the amortization of actual issuance costs incurred by KeySpan on its debt borrowings. KeySpan amortizes these costs over the life of the related KeySpan borrowings. (4) Preferred Stock The Company has outstanding 562,700 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. At the Company's option, the annual sinking fund payment may be increased to 10%. The preferred stock is callable at par in September 2003. The Company redeemed 60,000 shares, or 5% at $25 per share, on both September 1, 2002 and September 3, 2001. (5) Retiree Benefits The Company provides post-retirement benefits, including pension ("pension"), medical and life insurance (collectively "health care") benefits for substantially all of its employees. The plan is contributory for retirees, with respect to medical benefits and noncontributory with respect to life insurance benefits. F-14 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (5) Retiree Benefits (Continued) The Company is subject to deferral accounting requirements, as previously ordered by the Department, for other postretirement benefit costs. In addition, per department approval dated January 28, 2003, we will defer, and record as either a regulatory asset or regulatory liability, the difference between the level of pension expense that is included in rates charged to gas customers and the actuarial determined amounts. Pension benefits for salaried employees are based on salary and years of service, while pension benefits for union employees are based on negotiated benefits and years of service. Employees hired before 1993 who are participants in the pension benefit plans become eligible for post-retirement health care benefits if they reach retirement age while working for the Company. The funding of these pension benefit plans is in accordance with the requirements of the plans and, where applicable, in sufficient amounts to satisfy the "Minimum Funding Standards" of the Employee Retirement Income Security Act ("ERISA"). Effective December 31, 2002, KeySpan merged our qualified pension plans, with other KeySpan pension plans, into a consolidated Pension Plan (thus forming The KeySpan Retirement Plan). Thus, for 2002, the pension disclosures presented below represent the portion of The KeySpan Retirement Plan as it relates to direct employees of the Company, with the exception of management employees of an affiliate, Essex Gas Company, who are included in this plan and for which the benefit obligation attributed to them approximates 3.8% of the total benefit obligation at December 31, 2002. Prior to 2002, plan information was for the Company's separate pension plans. The health care plans have not been merged with our KeySpan plans and therefore, continue to remain separate plans of the Company. F-15 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (5) Retiree Benefits (Continued) The net cost for these plans were charged to expense as follows:
- ------------------------------------------------------------------------------------------------------------------------------ Period from Period from November 8, January 1, Pensions Year Ended December 31, 2000 through 2000 through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ------------------------------------------------------------------------------------------------------------------------------ Predecessor Service cost - benefits earned during the period $ 3,536 $ 2,964 $ 410 $ 2,272 Interest cost on benefit obligation 11,941 10,690 1,835 8,170 Expected return on plan assets (12,330) (12,701) (2,176) (10,698) Amortization of prior service cost 945 - - 1,090 Amortization of transitional obligation - - - 186 Amortization of net actuarial (gain)/loss 1,918 60 - (821) - ------------------------------------------------------------------------------------------------------------------------------ Total pension cost $ 6,010 $ 1,013 $ 69 $ 199 - ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------- Period from Period from November 8, January 1, Health Care Year Ended December 31, 2000 through 2000 through (In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000 - ------------------------------------------------------------------------------------------------------------------------------- Predecessor Service cost-benefits earned during the period $ 1,386 $ 1,358 $ 131 $ 624 Interest cost on benefit obligation 6,683 6,687 1,110 4,736 Expected return on plan assets (2,193) (2,349) (405) (1,787) Amortization of prior service cost 12 - - (882) Amortization of net actuarial (gain)/loss 895 636 - (726) Regulatory deferral - - 486 4,646 - ------------------------------------------------------------------------------------------------------------------------------- Total health care cost $ 6,783 $ 6,332 $ 1,322 $ 6,611 - -------------------------------------------------------------------------------------------------------------------------------
F-16 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (5) Retiree Benefits (Continued) The following table sets forth the change in benefit obligation and plan assets and reconciliation of funded status of our pension plans and amounts recorded on the balance sheet as of December 31, 2002, and December 31, 2001: - -------------------------------------------------------------------------------- Pensions December 31, (In Thousands of Dollars) 2002 2001 - -------------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of period $ 162,953 $ 157,285 Service cost 3,536 2,964 Interest cost 11,941 10,690 Amendments 7,452 4,419 Actuarial gain (loss) 9,883 (8,403) Benefits paid (8,859) (4,002) - -------------------------------------------------------------------------------- Benefit obligation at end of period 186,906 162,953 - -------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of period 150,240 153,328 Actual return on plan assets (30,322) (8,968) Employer contributions 44,460 19,000 Adjustment - (4,717) Benefits paid (8,858) (8,403) - -------------------------------------------------------------------------------- Fair value of plan assets at end of period 155,520 150,240 - -------------------------------------------------------------------------------- Reconciliation of funded Status: Funded status (31,386) (12,713) Unrecognized actuarial loss 75,938 33,085 Unrecognized prior service cost 10,030 4,419 - -------------------------------------------------------------------------------- Net prepaid pension cost reflected on balance sheet $ 54,582 $ 24,791 - -------------------------------------------------------------------------------- Prepaid pension costs are reflected in Deferred Charges and Other Assets on the Balance Sheet. F-17 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (5) Retiree Benefits (Continued) The following table sets forth the change in benefit obligation and plan assets and reconciliation of funded status of our health care plans and amounts recorded on the balance sheet as of December 31, 2002 and December 31, 2001:
- ---------------------------------------------------------------------------------------------------------------- Health Care December 31, (In Thousands of Dollars) 2002 2001 - ---------------------------------------------------------------------------------------------------------------- Change in benefit obligation: Benefit obligation at beginning of period $ 100,877 $ 87,440 Service cost 1,386 1,358 Interest cost 6,683 6,686 Amendments 87 21 Plan participants contributions 27 - Actuarial gain (loss) 5,106 11,860 Benefits paid (5,421) (6,488) - ---------------------------------------------------------------------------------------------------------------- Benefit obligation at end of period 108,745 100,877 - ---------------------------------------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at beginning of period 27,695 27,432 Actual return on plan assets (4,723) 783 Employer contributions 3,910 5,947 Plan participants contributions 27 21 Benefits paid (5,421) (6,488) - ---------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of period 21,488 27,695 - ---------------------------------------------------------------------------------------------------------------- Reconciliation of funded Status: Funded status (87,257) (73,182) Unrecognized actuarial loss 34,827 22,577 Unrecognized prior service cost 75 - - ---------------------------------------------------------------------------------------------------------------- Net (accrued) health care cost reflected on balance sheet $ (52,355) $ (50,605) - ----------------------------------------------------------------------------------------------------------------
Accrued health care costs are primarily reflected in Postretirement Benefit Obligation on the Balance Sheet. To fund health care benefits under its collective bargaining agreements, the Company maintains a Voluntary Employee Beneficiary Association ("VEBA") Trust to which it makes contributions from time to time. Pension and health care plan assets are invested principally in common stock and fixed income assets. F-18 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (5) Retiree Benefits (Continued) Following are the weighted-average assumptions used in developing the projected and accumulated benefit obligations: - -------------------------------------------------------------------------------- Year Ended December 31, (In Thousands of Dollars) 2002 2001 2000 - -------------------------------------------------------------------------------- Assumptions: Obligation discount 6.75% 7.00% 7.00% Asset return 8.50% 8.50% 8.50% Average annual increase in compensation 4.00% 4.00% 5.00% Health care inflation trend 5.0-9.0% 5.0-10.0% 8.00% - -------------------------------------------------------------------------------- The health care inflation rate for 2003 is assumed to be 9%. The rate is assumed to decrease gradually to 5% in 2009 and remain at that level thereafter. A one-percentage-point increase or decrease in the assumed health care trend rate for 2002 would have the following effects: One- One- Percentage Percentage Point Point (In Thousands of Dollars) Increase Decrease - ------------------------------------------------------------------------------- Net periodic healthcare expense $ 606 $ (554) Postretirement benefit obligation $ 7,474 $ (6,979) - ------------------------------------------------------------------------------- Unfunded Pension Obligations At December 31, 2002, accumulated benefit obligations were in excess of pension assets. Pursuant to SFAS 87 "Employers' Accounting for Pensions", an additional minimum liability would normally be recorded for this unfunded pension obligation. As allowed for under current accounting guidelines, this accrual can be offset by a corresponding debit to an intangible asset up to the amount of accumulated unrecognized prior service costs with the remaining amount recorded as a direct charge to other comprehensive income. However, as the pension plans were merged into The KeySpan Retirement Plan, an additional minimum liability is not determined based upon the subsidiary plan information, but rather based upon the minimum liability associated with The KeySpan Retirement Plan. Therefore, a minimum liability is not recorded based upon the above plan information. F-19 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (6) Contractual Obligations and Contingencies (Continued) Leases Since the beginning of 2002, substantially all operating leases are the obligation of KCS, a wholly owned subsidiary of KeySpan. The Company records, as an inter-company expense, costs incurred for the use of leased equipment such as buildings, office equipment and vehicles. These inter-company expenses, were approximately $5.2 million in 2002 and are reflected in Operations and Maintenance expense in the Statement of Operations. Prior to 2002, rental expense was a direct charge to the Company and was $7.4 million in 2001, $2.3 million for the period November 8, 2000 through December 31, 2000 and $8.7 million for the period January 1 through November 7, 2000. In April 1999, the Company entered into a 15 year capital lease for the LNG facilities located in Salem and Lynn, Massachusetts. A summary of property held under capital leases as of December 31 is as follows: - ------------------------------------------------------------------------------ In Thousands of Dollars 2002 2001 - ------------------------------------------------------------------------------ LNG Facilities $ 14,834 $ 14,834 Less: Accumulated Depreciation 1,431 845 - ------------------------------------------------------------------------------ Total Capital Lease $ 13,403 $ 13,989 - ------------------------------------------------------------------------------ Under the terms of SFAS 71, the timing of expense recognition on capitalized leases conforms with regulatory rate treatment. The Company has included the rental payments on its capital leases in its cost of service for rate purposes. The remaining minimum rental commitment for the capital leases at December 31, 2002 is approximately $1.6 million a year through 2007, and $10.3 million thereafter. Included in these future obligations are interest and executory costs of approximately $4.8 million. As discussed above, minimum rental lease payments for operating leases are paid by KCS. Fixed Charges Under Firm Contracts We have entered into various contracts for gas delivery, storage and supply services. The contracts have remaining terms that cover from one to ten years. Certain of these contracts require payment of annual demand charges in the aggregate amount of approximately $127.0 million. We are liable for these payments regardless of the level of service we require from third parties. Such charges are currently recovered from utility customers through the gas adjustment clause. F-20 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS (6) Contractual Obligations and Contingencies (Continued) Legal From time to time we are subject to various legal proceedings arising out of the ordinary course of our business. We do not consider any of such proceedings to be material to our business or likely to result in a material adverse effect on our results of operations, financial condition and cash flows. (7) 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 is based on currently quoted market prices. The carrying amounts and estimated fair values of the Company's long-term debt and preferred stock at December 31, 2002 and 2001 are as follows:
- ------------------------------------------------------------------------------------------------------------- 2002 2001 - ------------------------------------------------------------------------------------------------------------- In Thousands of Dollars Carrying Amount Fair Value Carrying Amount Fair Value - ------------------------------------------------------------------------------------------------------------- Long-term debt $ 223,403 $ 260,477 $ 223,989 $ 229,499 Preferred stock 13,840 14,067 15,289 15,209 - ------------------------------------------------------------------------------------------------------------- $ 237,243 $ 274,544 $ 239,278 $ 244,708 - -------------------------------------------------------------------------------------------------------------
F-21 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS--(Continued) (8) Related Party Transactions On November 8, 2000, KCS became an affiliate of the Company, through KNE LLC's merger with KeySpan. KCS provides financing to the Company for working capital and gas inventory through a utility money pool. At December 31, 2002 and 2001, we had outstanding borrowings of $67.2 million and $147.4 million for working capital, respectively, and $83.9 and $85.4 million for fuel inventory, respectively. KCS also provides the Company with services, including executive and administrative, corporate affairs, customer services, environmental services, financial services (including accounting, auditing, risk management, tax, treasury/finance), human resources, information technology, legal, materials management and purchasing, and strategic planning. In 2002 and 2001, we were charged $86.8 million and $37.3 million, respectively, for these services. The increase in amounts charged by KCS is primarily due to the labor costs associated with a large number of employees who were previously employees of the Company, but are now employees of KCS. KCS also purchases and/or develops and implements software and purchases hardware used by the Company. The amount charged to us by KCS for these technology assets totaled $18.0 and $21.8 million during 2002 and 2001, respectively. These charges have been recorded as property assets on our Balance Sheet. In 2002 and 2001, we were charged by KCS $8.8 million and $7.3 million, respectively, for interest on working capital and gas inventory borrowings. In 2000, the Company expensed $1.7 million for interest on these borrowings. Interest charged is equal to actual interest incurred by KeySpan to issue commercial paper, plus a proportional share of the administrative costs incurred in obtaining the funds to meet the combined short-term borrowing requirements of the members of the Utility Pool Agreement. As of December 31, 2002, $650 million in advances were recorded on the books of the Company from KeySpan Corporation. In 2002 and 2001, we were charged by KeySpan Corporation $51.8 and $49.9 million for interest and debt issuance costs, respectively. In 2000, we expensed $5.5 million for interest and debt issuance costs on the advance outstanding in 2000. Interest charges equal interest incurred by KeySpan on debt borrowings issued by KeySpan. Issuance expense is charged to the Company from KeySpan equal to the amortization of actual issuance costs incurred by KeySpan on its debt borrowings. KeySpan amortizes these costs over the life of the related KeySpan borrowings. F-22 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS--(Continued) (9) Environmental Matters 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") operations, including former operating plants, gas holder locations and satellite disposal sites. We may have or share responsibility under applicable environmental laws for the remediation of 19 such sites. A subsidiary of National Grid USA (formerly New England Electric System) has assumed responsibility for remediating 11 of these sites, subject to a limited contribution from the Company. In addition, we are aware of 31 other former MGP related sites within our service territory. The National Grid USA subsidiary has provided full indemnification to the Company with respect to eight of the 31 sites. At this time, there is substantial uncertainty as to whether we have or share responsibility for remediating any of these sites. However, no notice of responsibility has been issued to us for these sites from any governmental environmental authority. The Company has estimated its potential share of the costs of investigating and remediating the former MGP related sites and the non-MGP site in accordance with SFAS No. 5, "Accounting for Contingencies," and the American Institute of Certified Public Accountants Statement of Position 96-1, "Environmental Remediation Liabilities." We estimate the remaining cost of its MGP-related environmental cleanup activities will be $28.9 million, which amount has been accrued by us as a reasonable estimate of probable cost for known sites. However, there can be no assurance that actual costs will not vary considerably from these estimates. Factors that may bear on actual 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. Expenditures incurred to date with respect to these MGP-related activities total $17.7 million. 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 related sites over separate, seven-year amortization periods, without a return on the unamortized balance. The Company has recognized a regulatory asset of $36.9 million, representing the expected rate recovery of environmental remediation costs. This amount is included in Deferred Charges and Other Assets on the Balance Sheet. F-23 BOSTON GAS COMPANY NOTES TO FINANCIAL STATEMENTS--(Continued) (10) Workforce Reduction Program In November, 2000, as a result of the KeySpan merger, we recorded a liability for $6.0 million for a severance program implemented to reduce the workforce. This severance program was to continue through 2002. During the year ended December 31, 2001, we paid $1.3 million for this program and reduced our liability by $3.3 million as a result of lower than anticipated costs per employee and recorded a corresponding reduction to Goodwill. The remaining liability at December 31, 2001 was $1.4 million. In 2002, approximately $0.4 million was paid with the remaining liability of approximately $0.2 million reversed and recorded to earnings. There is a remaining liability of approximately $0.8 million which is schedule to be paid out in 2003. (11) Derivatives The utility tariffs associated with our operations do not contain a weather normalization clause. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of operations. To mitigate the effect of fluctuations from normal weather on our financial position and cash flows, we sold heating degree-day call options and purchased heating-degree day put options for the November 2002 - April 2003 winter season. With respect to sold call options, we are required to make a payment of $40,000 per heating degree day to our counter-parties when actual weather experienced during the November 2002 - April 2003 time frame is above 4,470 heating degree days, which equates to approximately 1% colder than normal weather. With respect to purchased put options, we will receive a $20,000 per heating degree day payment from our counter-parties when actual weather is below 4,150 heating degree days, or is approximately 7% warmer than normal. Based on the terms of such contracts, we account for such instruments pursuant to the requirements of EITF 99-2, "Accounting for Weather Derivatives." In this regard, we account for such instruments using the "intrinsic value method" as set forth in such guidance. During the fourth quarter of 2002, weather was approximately 7.4% colder than normal and we recorded a $3.3 million reduction to revenues with a corresponding liability due to our counter-parties. On April 1, 2002, we adopted Implementation Issue C16 of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended and interpreted incorporating SFAS 137 and 138 and certain implementation issues (collectively "SFAS 133"). Issue C16 establishes new criteria that must be satisfied in order for contracts that combine a forward contract and a purchased option contract to be exempted as normal purchases and sales. Based upon a review of its physical gas purchase commodity contracts, we determined that certain contracts could no longer be exempted as normal purchases from the requirements of SFAS 133. At December 31, 2002, the fair value of these contracts was a liability of $0.6 million. Since these contracts are for the purchase of natural gas sold to firm gas sales customers, the accounting for these contracts is subject to SFAS 71. Therefore, changes in the market value of these contracts are recorded as a deferred asset or deferred liability on the Balance Sheet. F-24 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Boston Gas Company: We have audited the accompanying Balance Sheet of Boston Gas Company (the Company) (an indirectly wholly-owned subsidiary of KeySpan Corporation,) as of December 31, 2002, and the related Statements of Operations, Retained Earnings (Deficit), Comprehensive Income (Loss), and Cash Flows for the year then ended. Our audit also included the financial statement schedule, for the year ended December 31, 2002, listed in the Index to Financial Statements and Schedules. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial schedule based on our audit. The financial statements of Boston Gas Company as of December 31, 2001, and for the year then ended, the period from November 8, 2000 through December 31, 2000 and the period from January 1, 2000 through November 7, 2000 were audited by other auditors who have ceased operations. Their report, dated February 4, 2002, expressed an unqualified opinion on those statements. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Boston Gas Company as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects, the information set forth therein. As discussed in Note 1 to the Financial Statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets," (SFAS No. 142) to change its method of accounting for goodwill and other intangible assets. As discussed above, the financial statements of the Company as of December 31, 2001, and for the year then ended, the period from November 8, 2000 through December 31, 2000 and the period from January 1, 2000 through November 7, 2000 were audited by other auditors who have ceased operations. Note 1 to these financial statements has been revised to include the transitional disclosures required by SFAS No. 142. Our audit procedures with respect to the disclosures in Note 1 for the 2001 and 2000 periods included (i) agreeing the previously reported net income (loss) applicable for common stock to the previously issued financial statements and the adjustments to net income (loss) applicable for common stock representing amortization expense recognized in those periods related to goodwill to the Company's underlying records obtained from management, and (ii) testing the mathematical accuracy of the reconciliation of adjusted net income (loss) to reported net income (loss) available for common stock. In our opinion, the disclosures in Note 1 are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 financial statements of the Company other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole. DELOITTE & TOUCHE LLP New York, New York February 10, 2003 F-25 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 an indirect wholly-owned subsidiary of KeySpan Corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of earnings, retained earnings, comprehensive income and cash flows for the year ended December 31, 2001, the period from November 8, 2000 through December 31, 2000, the period from January 1, 2000 through November 7, 2000, and the year ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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, 2001 and 2000 and the results of their operations and their cash flows for the year ended December 31, 2001, the period from November 8, 2000 through December 31, 2000, the period from January 1, 2000 through November 7, 2000, and the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index to consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states, 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 New York, New York February 4, 2002 Readers of these financial statements should be aware that this report is a copy of a previously issued Arthur Andersen LLP report and that this report has not been reissued by Arthur Andersen LLP. Furthermore, this report has not been updated since February 4, 2002 and Arthur Andersen LLP completed its last post audit review of the December 31, 2001 financial statements on April 29, 2002. F-26
BOSTON GAS COMPANY INTERIM FINANCIAL INFORMATION For the two years ended December 31, 2002 and 2001 (Unaudited) Quarters Ended 2002 - ------------------------------------------------------------------------------------------------------------------------------- (In Thousands) March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 244,291 $ 101,771 $ 64,424 $ 228,625 Operating margin $ 110,804 $ 54,886 $ 40,592 $ 87,006 Operating earnings (loss) including income taxes $ 41,539 $ 3,683 $ (6,153) $ 23,211 Net earnings (loss) applicable to common stock $ 25,262 $ (11,814) $ (23,692) $ 6,795 - ------------------------------------------------------------------------------------------------------------------------------- Quarters Ended 2001 - ------------------------------------------------------------------------------------------------------------------------------- (In Thousands) March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 401,020 $ 148,042 $ 84,462 $195,414 Operating margin $ 109,273 $ 49,897 $ 36,626 $ 74,459 Operating earnings (loss) including income taxes $ 32,652 $ (4,555) $ (11,193) $ 10,181 Net earnings (loss) applicable to common stock $ 19,626 $ (20,446) $ (26,949) $ (3,482) - -------------------------------------------------------------------------------------------------------------------------------
In the opinion of management, the annual financial data includes all adjustments, unless otherwise noted in the accompanying footnotes, consisting only of normal recurring accruals, necessary for a fair presentation of such information. F-27
SCHEDULE II BOSTON GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS ---------------------------------------------------------------------------------- Charged Net Balance at Charged (Credited)to Deductions Beginning of (Credited) other from Balance at (In Thousands) Period to Income Accounts Reserves End of Period For the Year Ended December 31, 2002 Reserves for doubtful accounts $ 14,730 $ 15,503 $ - $ 15,567 $ 14,666 ======== ======== ======== ======== ======== Reserve for self-insurance $ 843 $ 1,250 $ - $ 1,425 $ 668 ======== ======== ======== ======== ======== Reserve for environmental expenses $ 31,878 $ - $ 3,047 $ - $ 28,831 ======== ======== ======== ======== ======== For the Year Ended December 31, 2001 Reserves for doubtful accounts $ 13,681 $ 11,192 $ - $ 10,143 $ 14,730 ======== ======== ======== ======== ======== Reserve for self-insurance $ 2,891 $ 675 $ - $ 2,723 $ 843 ======== ======== ======== ======== ======== Reserve for environmental expenses $ 18,000 $ - $ 13,878 $ - $ 31,878 ======== ======== ======== ======== ======== For the Period From November 8, 2000 Through December 31, 2000 Reserves for doubtful accounts $ 12,329 $ 2,687 $ - $ 1,335 $ 13,681 ======== ======== ======== ======== ======== Reserve for self-insurance $ 2,901 $ 250 $ - $ 260 $ 2,891 ======== ======== ======== ======== ======== Reserve for environmental expenses $ 18,000 $ - $ - $ - $ 18,000 ======== ======== ======== ======== ======== For the Period From January 1, 2000 Through November 7, 2000(Predecessor) Reserves for doubtful accounts $ 14,816 $ 7,761 $ - $ 10,248 $ 12,329 ======== ======== ======== ======== ======== Reserve for self-insurance $ 3,913 $ 1,616 $ - $ 2,628 $ 2,901 ======== ======== ======== ======== ======== Reserve for environmental expenses $ 18,000 $ - $ - $ - $ 18,000 ======== ======== ======== ======== ========
F-28 EX-31 3 ex311-bogas10kamend02.txt EXHIBIT 31.1 Exhibit 31.1 CERTIFICATION OF THE PRESIDENT AND CHIEF OPERATING OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Nickolas Stavropoulos, certify that: 1. I have reviewed this amendment to the annual report on Form 10-K of Boston Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 13, 2003 /s/ Nickolas Stavropoulos ------------------------- Name: Nickolas Stavropoulos Title: President and Chief Operating Officer Note: A signed original of this written statement required by Section 302 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. 2 EX-31 4 ex312-bogas10kamend02.txt EXHIBIT 31.2 Exhibit 31.2 CERTIFICATION OF THE SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Joseph F. Bodanza, certify that: 1. I have reviewed this amendment to the annual report on Form 10-K of Boston Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 13, 2003 /s/ Joseph F. Bodanza --------------------- Name: Joseph F. Bodanza Title: Senior Vice President and Chief Accounting Officer Note: A signed original of this written statement required by Section 302 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. 2 EX-32 5 ex321-bogas10kamend02.txt EXHIBIT 32.1 Exhibit 32.1 CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Boston Gas Company (the "Corporation") on Form 10-K for the period ended December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Nickolas Stavropoulos, President and Chief Operating Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, amended; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation. /s/ Nickolas Stavropoulos ------------------------- Name: Nickolas Stavropoulos Title: President and Chief Operating Officer Date: March 28, 2003 Note: A signed original of this written statement required by Section 906 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-32 6 ex322-bogas10kamend02.txt EXHIBIT 32.2 Exhibit 32.2 CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Boston Gas Company (the "Corporation") on Form 10-K for the period ended December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Joseph F. Bodanza, Senior Vice President and Principal Financial and Accounting Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, amended; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation. /s/ Joseph F. Bodanza --------------------- Name: Joseph F. Bodanza Title: Senior Vice President and Principal Financial and Accounting Officer Date: March 28, 2003 Note: A signed original of this written statement required by Section 906 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-32 7 ex323-bogas10kamend02.txt EXHIBIT 32.3 Exhibit 32.3 CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the amendment to the Annual Report of Boston Gas Company (the "Corporation") on Form 10-K for the period ended December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Nickolas Stavropoulos, President and Chief Operating Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, amended; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation. /s/ Nickolas Stavropoulos ------------------------- Name: Nickolas Stavropoulos Title: President and Chief Operating Officer Date: August 13, 2003 Note: A signed original of this written statement required by Section 906 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. EX-32 8 ex324-bogas10kamend02.txt EXHIBIT 32.4 Exhibit 32.4 CERTIFICATION PURSUANT TO U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the amendment to the Annual Report of Boston Gas Company (the "Corporation") on Form 10-K for the period ended December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Joseph F. Bodanza, Senior Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, amended; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation. /s/ Joseph F. Bodanza --------------------- Name: Joseph F. Bodanza Title: Senior Vice President and Chief Financial Officer Date: August 13, 2003 Note: A signed original of this written statement required by Section 906 has been provided to Boston Gas Company and will be retained by Boston Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----