Item 1. Business.
General
Boston Gas Company D/B/A KeySpan Energy Delivery New England (the "Company"), is engaged in the transportation and sale of natural gas to approximately 555,000 residential, commercial and industrial customers in Boston, Massachusetts and 73 other communities in eastern and central Massachusetts. The Company is the largest natural gas distribution company in New England and has been in business for 179 years.
The Company is a wholly-owned subsidiary of Eastern Enterprises ("Eastern"). On November 8, 2000, KeySpan Corporation ("KeySpan") acquired all of the common stock of Eastern. The transaction was accounted for as a purchase, with KeySpan being the acquiring company. Prior to this transaction, Eastern had owned Boston Gas Company since 1929. KeySpan is a registered holding company under the Public Utility Holding Company Act ("PUCHA") 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 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. The Company's 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 the Company 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 the Company separately from the purchase of gas supply, which the customer may buy from third-party suppliers. The Company views these third-party suppliers as partners in marketing gas and increasing throughput and expects to work closely with them to facilitate the unbundling process and ensure a smooth transition, especially in the tracking and processing of transactions. The Company has also implemented programs to educate customers about the opportunity to purchase gas from third-party suppliers, while still relying on the utility for delivery. As of December 31, 2001, the Company had approximately 4,500 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 the Company's revenues, it has no impact on its operating earnings. The Company earns all of its margins on the local distribution of gas and none on the resale of the commodity itself.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers, throughout its service territory. Over the last nine years, the Company has increased its share in the total stationary energy market from 31% to 38%. This market share compares to the national level of approximately 44%, and represents a growth opportunity for the Company. However, future market share 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 1999-2001.
Years Ended December 31, ------------------------ 2001 2000 1999 ------ ------ ------ Residential ............................. 41.9 43.2 39.3 Commercial and industrial ............... 21.9 25.4 27.3 Off-system sales ........................ 0.2 2.6 5.6 ------ ------ ------ Total sales ....................... 64.0 71.2 72.2 Transportation of customer-owned gas .... 61.9 55.8 56.4 Less: Off-system sales .................. (0.2) (2.6) (5.6) ------ ------ ------ Total throughput .................. 125.7 124.4 123.0 ====== ====== ====== Total firm throughput ............. 124.9 122.4 109.1 ====== ====== ======
The above table excludes the effect of the accrual method of revenue recognition as discussed in Note 1 of Notes to Consolidated Financial Statements.
In 2001, residential customers comprised 91% of the Company's customer base, while commercial and industrial establishments accounted for the remaining 9%. Volumetrically, residential customers accounted for 34% of total firm throughput, while commercial and industrial customers accounted for 66% of total firm throughput. Approximately 69% of commercial and industrial customers' total throughput was transportation-only service. Sithe Energy, an independent power generator on the Company's system, was responsible for approximately 28% of this transportation throughput under a contract which was renewed through February, 2003.
No customer, or group of customers under common control, accounted for 2% or more of total firm revenues in 2001.
Gas Supply
The following table in BCF provides information with respect to the Company's sources of supply during the three years 1999-2001.
Years Ended December 31, ------------------------ 2001 2000 1999 ------ ------ ------ Natural gas purchases .................... 52.3 59.6 65.9 Underground storage withdrawal ........... 6.0 12.5 9.9 Liquefied natural gas ("LNG") purchases .. 1.9 5.3 1.9 ------ ------ ------ Total source of supply ............. 60.2 77.4 77.7 Company use, unbilled and other .......... 3.8 (6.2) (5.5) ------ ------ ------ Total sales ........................ 64.0 71.2 72.2 ====== ====== ======
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 the Company's gas supplies are transported on interstate pipeline systems to the Company's 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 the Company's service territory, the peak daily and annual capacity and the contract expiration dates are as follows:
In 1999, the Company restructured its long-term capacity contracts with Tennessee Gas Pipeline. The majority of these Tennessee contracts are up for renewal in 2003. Less than 1% of the Company's capacity on Algonquin expired in 2002. In addition, the Company has firm capacity contracts on interstate pipelines upstream of the Algonquin and Tennessee pipelines to transport natural gas purchased by the Company from various areas of gas production.
The Company has contracted with pipeline companies and others for the storage of natural gas in underground storage fields located in Pennsylvania, New York, Maryland and West Virginia. These contracts provide storage capacity of 16.3 BCF and peak day deliverability of 0.18 BCF. The Company utilizes its existing transportation contracts to transport gas from the storage fields to its service territory. Supplemental supplies of LNG and propane are produced by and purchased from foreign and domestic sources.
The Company and its Massachusetts affiliates, Colonial Gas Company and Essex Gas Company, continue to operate under the portfolio management contract with El Paso Merchant Energy - Gas, L.P. This arrangement has a three-year primary term that commenced on November 1, 1999. El Paso is responsible for providing the majority of the city gate supply requirements to the three companies and managing certain of the companies' upstream capacity, underground storage and term supply contracts. The Department approved the contract in October 1999.
Peak day firm throughput in BCF was 0.63 in 2001, 0.80 in 2000, and 0.64 in 1999. The Company provides 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 at points on the Company's distribution system. The Company owns propane air facilities and an LNG facility in Dorchester, Massachusetts. The Company also leases two LNG facilities sited on land owned by the Company in Salem and Lynn, Massachusetts and leases space in facilities located in Providence, Rhode Island and Everett, Massachusetts. The Company considers its peak day sendout capacity, based on its total supply resources, to be adequate to meet the requirements of its firm customers.
Regulation
The Company's operations are subject to Massachusetts statutes applicable to gas utilities. Rates 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. The Company's cost of gas adjustment clause, billed to firm sales customers, allows for the semiannually, and based on certain criteria, 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, the Company collects 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 are governed by the five-year performance-based rate plan approved by the Department's 1996 order in D.P.U. 96-50. Under the plan, the Company's local transportation rates are recalculated annually to reflect inflation for the previous 12 months and reduced by a productivity factor. The plan also provides for penalties if the Company fails to meet specified service quality measures, with a maximum potential exposure of $1 million. There is a margin sharing mechanism whereby 25% of earnings in excess of a 15% return on year-ending equity are to be passed back to ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7% return on year-ending equity. Because rates under the Plan expire on October 31, 2002, Boston Gas has represented to the DTE that by April, 2002 it will address what rate plan it will propose to succeed the Plan.
In the Department's Order of D.P.U. 96-50, it set the productivity factor at 1.50% and expanded the service quality penalty beyond the $1 million proposed by the Company. The Company appealed the Department's order in D.P.U. 96-50 and the Supreme Judicial Court issued an order vacating: 1) the "accumulated inefficiencies" component of the productivity factor, thereby reducing the productivity factor from 1.5% to 0.5%; and 2) the expansion of the service quality penalty beyond $1 million, and remanded these matters to the Department for further proceedings. On January 16, 2001, the Department issued its order in the remand proceeding. The order limited the maximum service quality adjustment to $1 million but imposed a 0.5 percent accumulated inefficiencies component to the productivity factor to be implemented retroactively as of November 1, 1999 thereby increasing the productivity factor from 0.5% to 1.0%. On January 30, 2001, the Company appealed the imposition of the 0.5% accumulated inefficiencies adjustment to the Supreme Judicial Court and was granted a stay of the Department's order pending a final decision by the Court on the merits of the appeal. On March 7, 2002, the Supreme Judicial Court ruled in favor of Boston Gas Company and eliminated the accumulated inefficiencies factor of 0.5%. During the first quarter of 2002,the Company will reverse a previously recorded loss provision of approximately $4.0 million because of this favorable ruling.
On November 1, 2001, the DTE issued an order requiring all Massachusetts electric and gas utilities to develop service quality plans effective January 1, 2002 and providing potential penalties up to two percent of distribution service revenues. These plans, and their potential penalties, will differ from the service quality plan and potential penalties incorporated in the Company's current Plan.
All of the Company's 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 the Company's tariffs for all its residential customers 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 marketers, 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.
Seasonality and Working Capital
The Company's revenues, earnings and cash flow are highly seasonal because most of its transportation services and sales are directly related to temperature conditions. Since the majority of its revenues are billed in the November through April heating season, significant cash flows are generated from late winter to early summer. In addition, through the cost of gas adjustment clause, the Company bills its customers over the heating season for the majority of the pipeline demand charges paid by the Company over the entire year. This difference, along with other costs of gas distributed but unbilled, is reflected as deferred gas costs and is financed through short-term borrowings. Short-term borrowings are also required from time to time to finance normal business operations. As a result of these factors, short-term borrowings are generally highest during the late fall and early winter.
Environmental Matters
The Company 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 Notes to Consolidated Financial Statements. Such information is incorporated herein by reference.
Employees
As of December 31, 2001, the Company had approximately 1,300 employees, 73% of whom are organized in local unions with which the Company has collective bargaining agreements. In March 2002, the Company entered into a new four-year collective bargaining agreement with the largest bargaining units representing union employees; these agreements expire in 2006.
Item 2.
Item 2. Properties.
The Company operates three LNG facilities in Dorchester, Salem, and Lynn, Massachusetts. These facilities provide the Company with local storage of gas, because the stored LNG can be vaporized into the Company's distribution system to supplement pipeline gas in periods of high demand. The Company owns the Dorchester facility. The Company owns the real property at the Salem and Lynn facilities and rents the storage facilities under a long-term lease arrangement.
The Company owns propane-air facilities at various locations throughout its service territory.
On December 31, 2001, the Company's distribution system included approximately 6,100 miles of gas mains, 440,000 services and 561,000 active customer meters. A majority of the gas mains consist of cast iron and bare steel, which require ongoing maintenance and replacement.
The Company's gas mains and services are usually located on public ways or private property not owned by it. In general, the Company's occupation of such property is pursuant to easements, licenses, permits or grants of location. Except as stated above, the principal items of property of the Company are owned.
In 2001, the Company's capital expenditures were approximately $112 million. Capital expenditures were principally made for improvements to the distribution system, for system expansion to meet customer growth and for productivity improvements. The Company plans to spend approximately $94 million for similar purposes in 2002.
Item 3.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the Company's business, there are no material pending legal proceedings involving the Company.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of Security Holders in the fourth quarter of 2001.
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, typically a price cap plan, 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 have the opportunity to select only the services they desire.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
Eastern Enterprises, 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.
Item 6. Selected Financial Data.
Not required.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
RESULTS OF OPERATIONS
As discussed under Note 1 of Notes to Consolidated Financial Statements, the Company became an indirect wholly-owned subsidiary of KeySpan Corporation when its parent company, Eastern Enterprises, merged with KeySpan on November 8, 2000.
Year ended December 31, 2001
Net loss applicable to common stock for 2001 was $ 31.3 million. Weather for this period was 4.5% warmer than normal. As a result of the merger, this period included a full year of amortization of goodwill of $19.4 million and interest and debt issuance costs of $49.8 million related to the $650 million advance from KeySpan.
Period from November 8, 2000 through December 31, 2000
Weather for this period was 11% colder than normal. As a result of the merger, this period includes amortization of goodwill of $3.2 million and interest and debt issuance costs of $5.5 million related to the $600 million advance from KeySpan Corporation.
Period from January 1, 2000 through November 7, 2000
Weather for the period was normal. This period includes merger-related expenses of approximately $23.3 million consisting primarily of separation payments to officers, payment of vested stock options and other compensation related matters associated with the KeySpan merger.
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.
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 more competitive and deregulated environments. In addition, we are exposed to commodity price risk and interest 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 DTE 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 Local Distribution Company's ("LDC's") and the
marketer group regarding model terms and conditions for unbundled transportation service was approved by the DTE in November 1998. In February 1999, the DTE issued its order on how unbundling of natural gas service will proceed. For a five year transition period, the DTE determined that 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 the costs of upstream capacity purchased by the LDCs to serve firm customers will be absorbed by the LDC or other customers through the transition period. The DTE 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 DTE approved the LDCs 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 LDCs.
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.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page of this Report. Such information is incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11.
Item 11. Executive Compensation.
Not required.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13.
Item 13. Certain Relationships and Related Transactions.
Not required.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page of this Report. Such information is incorporated herein by reference.
(3) List of Exhibits.
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 Herewith).
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).
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 Registrant's Annual Report 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).*
10.9 --Amendment to Exhibit 10.9, 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).*
10.10 --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).*
10.11 --Gas 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).*
10.12 --Amendments to Exhibit 10.12, Gas Sales Agreement between the Company and Alberta Northeast Gas, Ltd., dated as of October 1, 1992; May 5, 1993; November 27, 1995; March 14, 1996; and November 27, 1995. (Filed as Exhibit 10.12.1 to the Annual Report of the Company on Form 10-K For the year ended December 31, 1998).*
10.13 --Firm 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).*
10.13.1 --Agreement between the Company and Iroquois Gas Transmission System L.P. amending Exhibit 10.13 as of November 3, 1998. (Filed as Exhibit 10.13.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.14 --Firm 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).*
10.15 --Gas 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).*
10.16 --Gas 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).*
10.17 --Gas 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).*
10.18 --Gas 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).*
10.19 --Gas 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).*
10.20 --Gas 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).*
10.21 --Gas 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).*
10.22 --Gas 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).*
10.23 --Gas 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).*
10.24 --Gas 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).*
10.25 --Gas 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).*
10.26 --Gas 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).*
10.27 --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 10.33 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).*
10.27.1 --Agreement between the Company and Texas Eastern Transmission amending Exhibits 10.27, 10.15, 10.16, 10.17, 10.29, and 10.30 dated as of October 29, 1998. (Filed as Exhibit 10.27.1 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.28 --Gas 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).*
10.29 --Gas 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. (Filed as Exhibit 10.35 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1997).*
10.30 --Gas 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).*
10.31 --Gas Transportation Contract between the Company and Texas Eastern Transmission dated October 29, 1999 providing for transportation of approximately 3,000 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, 1999).*
10.32 --Gas 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). *
10.33 --Gas 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).*
10.34 --Agreement between the Company and Tennessee Gas Pipeline dated as of September 1, 1993 providing for transportation of approximately 10,500 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, 1999).*
10.35 --Agreement 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).*
10.36 --Agreement 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).*
10.37 --Contract Restructuring Agreement between the Company and Tennessee Gas Pipeline dated as of August 2, 1999 amending Exhibits 10.1, 10.31 and 10.32. (Filed as Exhibit 10.37 to the Annual Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.38 --Redacted 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. (Filed as Exhibit 10.1 to the Form 10-K of Eastern Enterprises for the year ended December 31, 1999.).*
10.39 --Amended 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).*
10.40 --Precedent 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 Herewith).
10.41 --Agreement between the Company and Maritimes Northeast Gas Pipeline Limited Partnership dated June 18, 1999 providing for transportation of approximately 43,200 Dekatherms of natural gas per day. (Filed Herewith).
99.1 A Letter by the Company to the Securities and Exchange Commission regarding representations from Arthur Andersen LLP. (Filed herewith)
There were no reports on Form 8-K filed in the Fourth Quarter of 2001.
* Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules and Regulations under the Securities Exchange Act of 1934, reference is made to the document previously filed with the Commission.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BOSTON GAS COMPANY D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND Registrant
/s/ JOSEPH F. BODANZA
By: _____________________________________________ Joseph F. Bodanza Senior Vice President Finance, Accounting and Regulatory Affairs (Principal Financial and Accounting Officer)
Dated: March 29, 2002
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 29th day of March, 2002.
Signature Title --------- -----
/s/ CHESTER R. MESSER Director and President ___________________________ Chester R. Messer
BOSTON GAS COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES (Information required by Items 8 and 14 (a) of Form 10-K)
Schedules other than that listed above have been omitted as the information has been included in the consolidated financial statements and related notes or is not applicable nor required.
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
General
Boston Gas Company (the "Company") is a gas distribution company engaged in the transportation and sale of natural gas to residential, commercial and industrial customers. The Company's service territory includes Boston and 73 other communities in eastern and central Massachusetts. The Company is a wholly-owned subsidiary of Eastern Enterprises ("Eastern") and an indirect wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), a registered holding company under the Public Utility Holding Company Act of 1935, as amended.
Basis of Presentation
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 No. 71 ("SFAS 71"), "Accounting for the Effects of Certain Types of Regulation."
The Consolidated 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.
Merger and Goodwill
On November 8, 2000, KeySpan acquired all of the common stock of Eastern for $64.56 per share in cash. The transaction has been accounted for using the purchase method of accounting for business combinations. The purchase price was allocated to the net assets acquired of Eastern 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 is 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.
As prescribed by SFAS 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", the carrying value of goodwill is reviewed if the facts and circumstances, such as significant declines in sales, earnings or cash flows, or material adverse changes in the business climate suggest it might be impaired. If this review indicates that goodwill is not recoverable, as determined based upon the estimated undiscounted cash flows of the equity acquired, impairment would be measured by comparing the carrying value of the investment in such entity to its fair value. Fair value would be determined based on quoted market values, appraisals, or discounted cash flows. For the year ended December 31, 2001, no write-down of goodwill was determined to be necessary.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
On January 1, 2002, the Company 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. The annual impairment test is to be performed within six months of adopting SFAS 142 with any resulting impairment reflected as either a change in accounting principle, or a charge to operations in the financial statements. The result of this analysis is not complete at this time, and the Company is unable to determine the impact this analysis may have on its results of operations or financial condition. However, a change in the measurement of the realization of goodwill could result in a significant change in its carrying value.
Regulation
The Company is regulated as to rates, accounting and other matters by the Massachusetts Department of Telecommunications and Energy ("the Department"). Therefore, the Company accounts for the economic effects of regulation in accordance with the provisions of SFAS 71. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Management believes that this amount would approximate $79 million as of December 31, 2001. Criteria that give rise to the discontinuance of SFAS 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs or (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company has reviewed these criteria and believes that the continuing application of SFAS 71 is appropriate.
Regulatory assets have been established that represent probable future revenue to the Company associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with the amounts that are to be credited to customers through the rate-making process.
The following regulatory assets were reflected in the consolidated balance sheets as of December 31:
2001 2000 ------- ------- (In Thousands)
Post-retirement benefit costs ............ $42,585 $44,085 Environmental costs ...................... 35,917 18,060 ------- ------- $78,502 $62,145 ======= =======
Regulatory liabilities total approximately $6,801,000 and $7,694,000 at December 31, 2001 and 2000 respectively, and relate to income taxes.
As of December 31, 2001, all of the Company's regulatory assets and liabilities are reflected in rates charged or credited to customers over periods ranging from 1 to 20 years. For additional information regarding deferred income taxes, post-retirement benefit costs and environmental costs, see Notes 2, 5 and 9, respectively.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
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.
Cost of Gas Adjustment Clause and Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires the Company to semiannually, and based on certain criteria, monthly adjust its rates for firm gas sales in order to track changes in the cost of gas distributed, with an annual adjustment of subsequent rates for any over or under recovery of actual costs incurred. As a result, the cost of any firm gas that has been distributed but is unbilled at the end of a period is deferred by the Company to the period in which the gas is billed to customers. The Company recovers the gas cost portion of its bad debt write-offs through the CGAC. In addition, through a local distribution adjustment clause ("LDAC"), the Company is allowed to recover the amortization of environmental response costs associated with former manufactured gas plant ("MGP") sites, costs related to the Company's various conservation and load management programs, and other specified costs from the Company's firm sales and transportation customers.
Depreciation
Depreciation is provided at rates designed to amortize the cost of depreciable property, plant and equipment over their estimated remaining useful lives. The composite depreciation rate, expressed as a percentage of the average depreciable property in service, is 5.0% for all periods presented. Amortization is provided on intangible assets, principally software, over the estimated useful life of the asset.
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.
Recent Accounting Pronouncements
In June of 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The Standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity will capitalize a cost increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the impact, if any, that the Statement may have on its results of operations and financial condition.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
SFAS 144, " Accounting for the Impairment of Disposal of Long-Lived Assets," is effective January 1, 2002, and addresses accounting and reporting for the impairment of 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. We currently do not anticipate that implementation of this Statement will have a significant effect on our results of operations and financial condition.
Reclassifications
Certain prior year financial statement amounts have been reclassified for consistent presentation with the current year.
(2) Income Taxes
For 2001, the Company will file a consolidated income tax return with KeySpan Corporation. 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 1999, the period January 1 through November 7, 2000, and the period form November 8 through December 31, 2000, the Company filed a consolidated federal income tax return with Eastern Enterprises. For these periods the Company followed the policy, established for the group, of providing for income taxes payable on a separate company basis. The Company's effective income tax rate was (23.1)% in 2001, 44.6% for the period from November 8 through December 31, 2000, (44.7)% for the period from January 1 through November 7, 2000, and 38.2% in 1999. State income taxes and the nondeductibility of goodwill amortization represent the majority of the difference between the effective rate and the federal income tax rate of 35% for 2001 and for the period from November 8 through December 31, 2000 and state income taxes represent the majority of the difference for the period from January 1 through November 7, 2000 and 1999.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
A summary of the provision for income taxes is as follows:
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
At December 31, 2001 the Company had a regulatory liability of $1,336,000 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. The Company also has a regulatory liability for excess deferred taxes being returned to customers over a 30-year period pursuant to a 1988 rate order with a balance to be refunded to customers of $5,466,000 as of December 31, 2001.
For income tax purposes, the Company uses accelerated depreciation and shorter depreciation lives, as permitted by the Internal Revenue Code. Deferred federal and state taxes are provided for the tax effects of all temporary differences between financial reporting and taxable income. Significant items making up deferred tax assets and liabilities at December 31, 2001 and 2000 are as follows:
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
Investment tax credits are deferred and credited to income over the lives of the property giving rise to such credits. The credit to income for 2001 was $842,000, $140,000 for the period from November 8 through December 31, 2000, $702,000 for the period from January 1 through November 7, 2000, and $842,000 in 1999.
(3) Debt
Long-term Obligations
The following table provides information on long-term obligations as of December 31:
There are no sinking fund requirements for the next three years related to the $210,000,000 of Medium-Term Notes outstanding at December 31, 2001 and none are callable prior to maturity. In 2005, $15,000,000 of 8.875% Medium-Term Notes Series A, mature. In 2006, $12,000,000 of 8.09% Medium-Term Notes Series B, mature.
Annual maturities of capital lease obligations for 2002 through 2006 are $586,000, $840,000, $891,000, $945,000 and $ 1,003,000, respectively.
Utility Money Pool Borrowings
KeySpan Corporate Services provides financing to the Company for working capital and gas inventory through the Company's participation in a Utility Money Pool. At December 31, 2001, the Company had outstanding borrowings of $ 147,350,000 and $ 85,401,000 for working capital and gas inventory, respectively. Interest charged equals interest incurred by KeySpan Corporate Services to borrow funds to meet the needs of the Company, plus a proportional share of the administrative costs incurred in obtaining the required funds. All costs related to the gas inventory borrowings are recoverable from customers through the CGAC. The average yearly rate on these borrowings was 4.16 %.
Advance from KeySpan Corporation
As part of the merger, the Company recorded in November 2000, a $600 million advance payable to KeySpan. Interest charges equal interest incurred by KeySpan on debt borrowings issued by KeySpan and recorded on the books of the Company. During 2001, an additional $50 million was advanced from Keyspan. The weighted-average interest rate on these borrowings is 7.78 %. Issuance expense is charged to the Company from KeySpan equal to the actual issuance costs incurred by KeySpan on its debt borrowings. These costs are amortized over the life of the borrowings.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Preferred Stock
The Company has outstanding 622,700 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 not callable prior to 2003. On September 3, 2001, the Company redeemed 60,000 shares, or 5% at $25 per share. On September 1, 2000, the Company redeemed 120,000 shares, or 10% of the outstanding shares, at $25 per share. In addition to the 120,000 shares redeemed in 2000, the Company purchased 277,300 shares on the open market which were subsequently retired.
(5) Retiree Benefits
The Company provides retirement benefits for substantially all of its employees. These plans include pensions, health and life insurance benefits.
Pension benefits for salaried plans are based on salary and years of service, while union retirement and welfare plans are based on negotiated benefits and years of service. Employees hired before 1993 who are participants in the pension plans become eligible for post-retirement health care benefits if they reach retirement age while working for the Company. The funding of retirement and employee 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").
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The net cost for these plans and agreements charged to expense was as follows:
Pensions
Health Care
The previous tables do not reflect retirement pension enhancements of $2,066,000 for 1999.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The following tables set forth the change in benefit obligation and plan assets and reconciliation of funded status of Company plans and amounts recorded in the Company's balance sheet as of December 31, 2001, December 31, 2000, and November 7, 2000, using actuarial measurement dates of December 31, 2001, December 31, 2000, and November 7, 2000, respectively:
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The following tables set forth the change in benefit obligation and plan assets and reconciliation of funded status of Company plans and amounts recorded in the Company's balance sheet as of December 31, 2001, December 31, 2000 and November 7, 2000, using actuarial measurement dates of December 31, 2001, December 31, 2000, and November 7, 2000, respectively:
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. Plan assets are invested in debt and equity marketable securities.
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the projected benefit obligation:
The health care inflation rate for 2002 is assumed to be 10%. 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 2001 would have the following effects:
Unfunded Pension Obligations
At December 31, 2001, accumulated benefit obligations were in excess of pension assets. Pursuant to FAS 87 "Employers' Accounting for Pensions", the Company was required to record an additional $5.1 million minimum liability for this unfunded pension obligation. As allowed for under current accounting guidelines, this accrual can be offset by a corresponding debit to a long-term asset up to the amount of accumulated unrecognized prior service costs. Any remaining amount is to be recorded as a direct charge to equity. Therefore, at year-end, the Company recorded a $4.4 million debit in Deferred Charges Other and a $0.7 million debit in Accumulated Other Comprehensive Income. In December 2002, we will re-measure the accumulated benefit obligations and pension assets, and adjust the accrual and deferrals as appropriate.
(6) Leases
The Company leases certain facilities and equipment under long-term leases which expire on various dates through the year 2016. Total rentals charged to income under all lease agreements were $7,425,000 in 2001, $2,247,000 for the period November 8 through December 31, 2000, $8,685,000 for the period January 1 through November 7, 2000, and $9,846,000 in 1999. The Company has capitalized leases for two LNG facilities. A summary of property held under capital leases as of December 31 is as follows:
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Leases (Continued)
In April 1999, the Company entered into a 15 year lease agreement for the LNG facilities located in Salem and Lynn, Massachusetts. The facilities had previously been leased by the Company's subsidiary, Mass LNG, which became inactive in 1999.
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 financing leases in its cost of service for rate purposes.
The Company also has various operating lease agreements for office facilities and other equipment. The remaining minimum rental commitment for these and all other noncancellable leases, including the financing leases, at December 31, 2001 is as follows:
(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, 2001 and 2000 are as follows:
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(8) Related Party Transactions
In 2001, the Company was charged $37,333,000 by KeySpan Corporate Services for services, which included costs associated with: 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.
KeySpan Corporate Services also purchases and/or develops and implements software and purchases hardware which are or will be used by the Company. Capital costs charged to the Company for these technology assets totaled $21,762,000 during 2001.
The Company paid Eastern $833,000 for the period November 8 through December 31, 2000, $4,167,000 for the period January 1 through November 7, 2000, and $4,500,000 in 1999 for legal, tax and corporate services rendered.
The Company paid $775,000 in 2001, $129,000 for the period November 8 through December 31, 2000, $646,000 for the period January 1 through November 7, 2000, and $775,000 annually in 1999 to lease an operations center from an affiliated company.
On November 8, 2000, KeySpan Corporate Services became an affiliate of the Company, through Eastern's merger with KeySpan. KeySpan Corporate Services provides financing to the Company for working capital and gas inventory through the Company's participation in a Utility Money Pool. At December 31, 2001, the Company had outstanding borrowings of $147,350,000 and $85,401,000 for working capital and fuel inventory, respectively. In 2001, the Company was charged by KeySpan Corporate Services $4,830,000 and $2,466,000 for interest on working capital and fuel inventory borrowings, respectively. At December 31, 2000, the Company had outstanding borrowings of $114,843,000 and $82,307,000 for working capital and fuel inventory, respectively. In 2000, the Company expensed $868,000 and $811,000 for interest on these working capital and gas inventory borrowings, respectively. Interest charged is equal to actual interest incurred by KeySpan Corporate Services to borrow funds to meet the needs of the Company, 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, 2001, $650 million in advances were recorded on the books of the Company from KeySpan Corporation. During 2001, an additional $50 million had been advanced from KeySpan. A $50 million dividend was than paid to KeySpan and charged against "Amounts in excess of par value." In 2001, the Company was charged by KeySpan Corporation $48,609,000 and $1,225,000 for interest and debt issuance costs, respectively. In 2000, the Company expensed $5,504,000 for interest and debt issuance costs on this advance. Interest charged is equal to actual interest incurred by KeySpan Corporation on such advances by KeySpan Corporation. Issuance expense is charged to the Company from KeySpan Corporation equal to the actual issuance costs incurred by KeySpan Corporation on such advances. These costs are amortized over the life of the borrowings.
(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. The Company may have or
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Environmental Matters (Continued)
share responsibility under applicable environmental laws for the remediation of 19 such sites. A subsidiary of New England Electric System ("NEES") has assumed responsibility for remediating 11 of these sites, subject to a limited contribution from the Company. The Company also may have or share responsibility for the remediation of one non-MGP site. 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." The Company estimates the remaining cost of its MGP-related environmental cleanup activities will be $31.9 million, which amount has been accrued by the Company 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.
The Company is aware of 31 other former MGP related sites within its service territory. The NEES 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 the Company has or shares responsibility for remediating any of these sites. No notice of responsibility has been issued to the Company for these sites from any governmental environmental authority.
By a rate order issued on May 25, 1990, the Department approved the recovery of all prudently incurred environmental response costs associated with former MGP related sites over separate, seven-year amortization periods, without a return on the unamortized balance. The Company has recognized an insurance receivable of $3.0 million, reflecting a negotiated settlement with an insurance carrier for MGP-related environmental expense indemnity, and a regulatory asset of $28.9 million, representing the expected rate recovery of environmental remediation costs, net of the insurance settlement. In light of the indemnity agreement with the NEES subsidiary, the Department rate order on MGP-related cost recovery, and the expected cost of remediating the non-MGP site, the Company believes that it is not probable that actual costs will materially affect its financial condition or results of operations.
(10) Workforce Reduction Program
As a result of the KeySpan merger, the Company implemented a severance program in an effort to reduce the workforce. In 2000, The Company recorded a liability of $6 million associated with this severance program. During the year ended December 31, 2001, the Company reduced this liability by $3.3 million as a result of lower than anticipated costs per employee and recorded a corresponding reduction to Goodwill. This severance program is targeted to reduce the workforce by 80 employees and will continue through 2002. At December 31, 2001, the Company paid $1.3 million for these programs and had a remaining liability of $1.4 million.
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 subsidiary 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
BOSTON GAS COMPANY
INTERIM FINANCIAL INFORMATION For the Two Years Ended December 31, 2001 (Unaudited)
In the opinion of management, the quarterly 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.
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)