10-K405 1 d10k405.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (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, 2001 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 0-10007 COLONIAL GAS COMPANY D/B/A/ KEYSPAN ENERGY DELIVERY NEW ENGLAND (Exact Name of Registrant As Specified In Its Charter) Massachusetts 04-3480443 (State or other jurisdiction of (I.R.S. Employer Identification No.) Incorporation or Organization) One Beacon Street (617) 742-8400 Boston, Massachusetts 02108 (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, 100 shares, are held by Eastern Enterprises. 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. COLONIAL GAS COMPANY FORM 10-K Fiscal Year Ended December 31, 2001 TABLE OF CONTENTS
Item No. Page -------- ---- PART I 1.Business................................................................................... 1 General.................................................................................... 1 Markets and Competition.................................................................... 1 Gas Throughput............................................................................. 2 Gas Supply................................................................................. 2 Regulation................................................................................. 3 Seasonality and Working Capital............................................................ 4 Environmental Matters...................................................................... 4 Employees.................................................................................. 4 2.Properties................................................................................. 4 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 Disclosure about Market Risk.................................. 9 8.Financial Statements and Supplementary Data................................................ 10 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 10 PART III 10.Directors and Executive Officers of the Registrant......................................... 11 11.Executive Compensation..................................................................... 11 12.Security Ownership of Certain Beneficial Owners and Management............................. 11 13.Certain Relationships and Related Transactions............................................. 11 PART IV 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K............................ 12
PART I Item 1. Business. General Colonial Gas Company D/B/A KeySpan Energy Delivery New England (the "Company"), a Massachusetts corporation formed in 1849, is engaged in the transportation and sale of natural gas to approximately 168,000 residential, commercial and industrial customers in 24 municipalities located northwest of Boston ("Merrimack Valley" area) and on Cape Cod. 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. Previous to this transaction, Eastern had owned Colonial Gas since August 31, 1999. KeySpan is a registered holding company under the Public Utilities 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. On August 31, 1999, the Company completed a merger with Eastern in a transaction with an enterprise value of approximately $474 million. In effecting the transaction, Eastern paid $150 million in cash, net of cash acquired and including transaction costs, issued approximately 4.2 million shares of common stock valued at $186 million and assumed $138 million of debt. 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 549 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 and electricity suppliers, throughout its service territory. Over the last four years, the Company has increased its market share in the total stationary energy market from 42% to 48%. This market share compares to the national level of approximately 44% and represents a growth opportunity for the Company. However, the 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. 1 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 ......................................... 12.7 13.0 12.0 Commercial and industrial ........................... 6.5 7.4 6.8 ---- ---- ---- Total sales ................................... 19.2 20.4 18.8 Transportation of customer-owned gas ................ 2.7 3.8 6.4 ---- ---- ---- Total throughput .............................. 21.9 24.2 25.2 ==== ==== ==== Total firm throughput ......................... 21.8 22.4 22.1 ==== ==== ==== In 2001, residential customers comprised 89% of the Company's customer base, while commercial and industrial establishments accounted for the remaining 11%. Volumetrically, residential customers accounted for 58% of total firm throughput, while commercial and industrial customers accounted for 42% of total firm throughput. Approximately 29% of commercial and industrial customers' total throughput was transportation-only services. 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 ......................... 17.1 18.1 15.8 Underground storage withdrawal ................ 3.1 4.7 3.1 Liquefied natural gas ("LNG") purchases ....... 0.9 1.4 1.2 ---- ---- ---- Total source of supply .................. 21.1 24.2 20.1 Company use, unbilled and other ............... (1.9) (3.8) (1.3) ---- ---- ---- Total sales ............................. 19.2 20.4 18.8 ==== ==== ==== 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:
Capacity in BCF --------------- Expiration Pipeline Daily Annual Dates -------- ----- ------ ----- Algonquin Gas Transmission Company ("Algonquin") .. .056 18.7 2005-2013 Tennessee Gas Pipeline Company ("Tennessee") ...... .072 26.3 2003-2013 ---- ---- ---- ---- .128 45.0 ==== ====
In 1999, the Company restructured its long-term capacity contracts on Tennessee Gas Pipeline. As a result, the majority of these Tennessee contracts are up for renewal in 2003. In addition, the Company has firm capacity 2 contracts on interstate pipelines upstream of 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 3.6 BCF and peak day deliverability of .041 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, Boston 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. The Company has two agreements with Distrigas of Massachusetts Corporation that expire on October 31, 2002, which allow the Company to purchase up to 10,000 Dekatherms ("Dth") per day for 151 days and 5,000 Dth per day for 365 days of liquefied natural gas ("LNG") in either liquid or vapor form. Peak day firm throughput in BCF was 0.102 in 2001, 0.126 in 2000 and 0.106 in 1999 for the Company's Merrimack Valley service area and 0.071 in 2001, 0.087 in 2000 and 0.069 in 1999 for the Company's Cape Cod service area. 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's Merrimack Valley service area has on-system LNG and propane air facilities which have an aggregate sendout capacity of approximately .087 BCF per day. The Company also operates on-system facilities in the Cape Cod service area capable of providing approximately .029 BCF per day. 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 ("CGAC") billed to firm sales customers, allows for the semiannual, 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 for ratemaking purposes, the Company recovers 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. In connection with the acquisition by Eastern Enterprises in 1999, on July 15, 1999, the Department approved the merger and rate plan, resulting in a 2.2% reduction in the total burner-tip price paid by the Company's firm sales customers in the first full year following the merger and a ten-year freeze of base rates. The base rate freeze is subject only to certain exogenous factors, such as changes in tax laws, accounting changes, or regulatory, judicial, or legislative changes. The Office of the Attorney General appealed the Department's order to the Supreme Judicial Court, which appeal is still pending. As a result of the rate plan, the Company discontinued its application of Statement of Financial Accounting Standards ("SFAS") No. 71, as described in Note 1 of Notes to Consolidated Financial Statements. 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. 3 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. After conducting an industry-wide proceeding regarding the calculation of lost margins that gas companies are allowed to recover as a result of their conservation or demand-side management ("DSM") programs, the Department ruled in November 1999 that, effective for filings for the twelve-month period beginning May 1, 1999, the Company may recover lost margins for only four years past the installation of DSM measures. This ruling changed the Department's previous approved calculation method. However, based on the Department's order approving the merger and rate plan, the Company has petitioned the Department for recovery of the resulting reduction in lost margins as an exogenous adjustment. The Department has approved the recovery of these costs as an exogenous adjustment subject to the condition that Company earnings are reasonable. 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 unbilled gas costs receivable 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 one former manufactured gas plant ("MGP") site, related satellite disposal sites, one non-MGP site and one federal superfund site. Information with respect to the remediation of MGP related 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 227 employees, 59% of whom are organized in local unions with which the Company has collective bargaining agreements that expire in 2002 and 2003. Item 2. Properties. The Company has two principal operations centers and two principal LNG storage facilities. One of the storage facilities is located in Tewksbury, Massachusetts and has a capacity of approximately 1.0 BCF and the other is located in South Yarmouth, Massachusetts and has a capacity of approximately .18 BCF. In addition, the Company owns a 36,000 square foot facility located in Lowell, Massachusetts used for administrative purposes. 4 On December 31, 2001, the Company's distribution system included approximately 3,300 miles of gas mains, 148,000 services and 168,000 active customer meters. The Company's gas mains and services are usually located on public ways or private property not owned by it. In general, the Company's occupation of such property is pursuant to easements, licenses, permits or grants of location. Except as stated above, the principal items of property of the Company are owned. In 2001, the Company's capital expenditures were approximately $26 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 $32 million for similar purposes in 2002. 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. 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. 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. 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. 6 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. Eastern Enterprises ("Eastern"), a wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), 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 As discussed under Note 1 of the Notes to the Consolidated Financial Statements, the Company became an indirect wholly-owned subsidiary of KeySpan Corporation when its parent company, Eastern, merged with KeySpan on November 8, 2000. Year ended December 31, 2001 Net loss for 2001 was $1.6 million. Weather for this period was 5.0% warmer that normal. As a result of the merger, this period included a full year of amortization of goodwill of $9.4 million and interest and debt issuance costs of $17.8 million related to the $200 million advance from KeySpan. Period from November 8, 2000 through December 31, 2000 Weather for this period was 13% warmer than normal. Based on the merger with KeySpan, this period includes amortization of goodwill of $1.6 million and $2.3 million of interest and debt issuance costs on the $250 million advance from KeySpan. Period from January 1, 2000 through November 7, 2000 Weather for the period was 2% colder than normal. Based on the merger with KeySpan, the Company recorded merger-related expenses of approximately $8.8 million consisting primarily of separation payments to officers, payment of vested stock options and other compensation related matters. This period includes a restructuring charge of $7.0 million related to the Company's exit of the gas appliance rental and service business. The charge includes $5.1 million to write down to fair value the equipment used in the rental business and $1.2 million for employee severance and termination benefits associated with the service business. The remaining $0.7 million is associated with the disposal of inventory and other related costs. 7 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 Disclosures 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. Among the factors that could cause actual results to differ materially are: general economic conditions, especially in Massachusetts; 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 interest rates; and other risks detailed from time to time in other reports and other documents filed by the Company with 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" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" contained herein. LIQUIDITY AND CAPITAL RESOURCES On November 8, 2000, KeySpan Corporate Services LLC, a KeySpan subsidiary, became an affiliate of the Company, through the Company's transaction with KeySpan. KeySpan Corporate Services 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 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. As part of the KeySpan merger, the Company recorded in November, 2000 a $250 million advance payable to KeySpan, of which $100 million was previously owed to Eastern. During 2001, $50 million was repaid to KeySpan after an additional investment in equity by KeySpan of $50 million. 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 actual issuance costs incurred by KeySpan on its debt borrowings. These costs are amortized over the life of the borrowings. The Company expects capital expenditures for 2002 to be approximately $32 million. 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, is sufficient to meet 2002 capital expenditures, working capital requirements, dividend payments and normal debt repayments. OTHER MATTERS 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 ("CGAC") billed to firm sales customers, allows for the semiannual, 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 for ratemaking purposes, the Company recovers the actual 8 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. In connection with the acquisition by Eastern Enterprises in 1999, on July 15, 1999, the Department approved the merger and rate plan, resulting in a 2.2% reduction in the total burner-tip price paid by the Company's firm sales customers in the first full year following the merger and a ten-year freeze of base rates. The base rate freeze is subject only to certain exogenous factors, such as changes in tax laws, accounting changes, or regulatory, judicial, or legislative changes. The Office of the Attorney General appealed the Department's order to the Supreme Judicial Court, which appeal is still pending. As a result of the rate plan, the Company discontinued its application of Statement of Financial Accounting Standards ("SFAS") No. 71, as described in Note 1 of Notes to Consolidated Financial Statements. 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. 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. After conducting an industry-wide proceeding regarding the calculation of lost margins that gas companies are allowed to recover as a result of their conservation or demand-side management ("DSM") programs, the Department ruled in November 1999 that, effective for filings for the twelve-month period beginning May 1, 1999, the Company may recover lost margins for only four years past the installation of DSM measures. This ruling changed the Department's previous approved calculation method. However, based on the Department's order approving the merger and rate plan, the Company has petitioned the Department for recovery of the resulting reduction in lost margins as an exogenous adjustment. The department has approved the recovery of these costs as an exogenous adjustment subject to the condition that company earnings are reasonable. Environmental Matters The Company has or shares responsibility under applicable environmental law for the remediation of one former manufactured gas plant ("MGP") site, related satellite disposal sites, one non-MGP site and one federal superfund site. Information with respect to the remediation of MGP related sites may be found in Note 9 of Notes to Consolidated 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 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. 9 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. 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. None. 10 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. 11 PART IV 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 F-1 of this Report. Such information is incorporated herein by reference. (3) List of Exhibits. 2 Agreement and Plan of Reorganization by and between Eastern Enterprises and Colonial Gas Company dated as of October 17, 1998, filed as Exhibit 2.1 to the Registrant's Form 8-K Report dated October 21, 1998.* 3.1 Restated Articles of Organization for Colonial Gas Company dated August 5, 1999, filed as Exhibit 3.1 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 3.2 By-Laws of Colonial Gas Company dated August 5, 1999, filed as Exhibit 3.2 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 4.1 Second Amended and Restated First Mortgage Indenture dated as of June 1, 1992, filed as Exhibit 4(b) to Form 10-Q of the Registrant for the quarter ended June 30, 1992.* 4.2 First Supplemental Indenture dated as of June 15, 1992, filed as Exhibit 4(c) to Form 10-Q of the Registrant for the quarter ended June 30, 1992.* 4.3 Second Supplemental Indenture dated as of September 27, 1995, filed as Exhibit 4(c) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 4.4 Amendment to Second Supplemental Indenture dated as of October 12, 1995, filed as Exhibit 4(d) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 4.5 Third Supplemental Indenture dated as of December 15, 1995, filed as Exhibit 4(f) to the Registrant's Form S-3 Registration Statement dated January 5, 1998.* 4.6 Fourth Supplemental Indenture dated as of March 1, 1998, filed as Exhibit 4(l) to the Registrant's Form 10-Q for the quarter ended March 31, 1998.* 4.7 Utility Money Pool Agreement, filed as Exhibit 4.7 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 2000.* 10.2 Gas Transportation Contract for Firm Reserved Service with Iroquois, dated February 7, 1991, filed as Exhibit 10 (v) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1990.* 10.3 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-E), dated June 1, 1993, filed as Exhibit 10 (p) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.4 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as Exhibit 10 (q) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 12 10.5 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as Exhibit 10 (r) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.6 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as Exhibit 10 (s) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.7 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-E), dated June 1, 1993, filed as Exhibit 10 (t) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.8 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as Exhibit 10 (u) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.9 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993, filed as Exhibit 10 (v) to the Registrant's Annual Report on From 10-K for the fiscal year ended December 31, 1993.* 10.10 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule CDS), dated June 1, 1993, filed as Exhibit 10 (w) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.11 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company for 1996 dth per day (under Rate Schedule FT-1), dated June 1, 1993, filed as Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.12 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FTS-8), dated June 1, 1993, filed as Exhibit 10 (y) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993. * 10.13 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FTS-7), dated June 1, 1993, filed as Exhibit 10 (z) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993. * 10.14 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company for 7,918 dth per day (under Rate Schedule FT-1), dated June 1, 1993, filed as Exhibit 10.14 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.15 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company for 2,222 dth per day (under Rate Schedule FT-1), dated June 1, 1993, filed as Exhibit 10.15 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.16 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company for 104 dth per day (under Rate Schedule FT-1), dated June 1, 1993, filed as Exhibit 10.16 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.17 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated August 1, 1993, filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.18 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated September 1, 1993, filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 13 10.19 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated September 1, 1993, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.20 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated September 1, 1993, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.21 Service Agreement between CNG Transmission Corporation and Colonial Gas Company (under Rate Schedule FTNN), dated October 1, 1993, filed as Exhibit 10 (rr) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.22 Service Agreement between CNG Transmission Corporation and Colonial Gas Company (under Rate Schedule GSS), dated October 1, 1993, filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.23 Service Agreement between CNG Transmission Corporation and Colonial Gas Company (under Rate Schedule GSS-II), contract no. 400009, dated November 1, 1998, filed as Exhibit 10.23 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.24 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FT-1), dated October 1, 1993, filed as Exhibit 10 (uu) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.25 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated September 1, 1993, filed as Exhibit 10 (vv) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.26 Service Agreement between National Fuel Gas Supply Corporation and Colonial Gas Company (under Rate Schedule EFT), dated October 28, 1993, filed as Exhibit 10 (ww) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.27 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated September 1, 1993, filed as Exhibit 10 (xx) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.28 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AIT-1), dated September 15, 1993, filed as Exhibit 10 (yy) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.29 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated October 1, 1993, filed as Exhibit 10 (zz) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.* 10.30 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FT-1), dated August 18, 1994, filed as Exhibit 10 (kk) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.31 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FSS-1), dated August 29, 1994, filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.32 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994, filed as Exhibit 10 (mm) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 14 10.33 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994, filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.34 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule SS-1), dated November 30, 1994, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.35 Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedule FSS-1), dated November 30, 1994, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.36 Letter Agreement between Algonquin Gas Transmission Company and Colonial Gas Company, Regarding transfer of transportation entitlements, dated March 28, 1994, filed as Exhibit 10 (qq) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.37 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated November 1, 1994, filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.38 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated November 1, 1994, filed as Exhibit 10 (tt) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994.* 10.39 Firm Natural Gas Transportation agreement between Tennessee Gas Pipeline and Colonial Gas Company (under Rate Schedule NET-Northeast), dated August 1, 1995, filed as Exhibit 10 (qq) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 10.40 Gas Transportation Agreement between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FT-A), dated June 1, 1995, filed as Exhibit 10 (rr) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 10.41 Amendment No. 1 (dated July 1, 1995 to Gas Storage Contract between Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate Schedule FS), dated December 1, 1994 (which superseded contract dated September 1, 1993), filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 10.42 Amendment to Gas Transportation Contract for Firm Reserved Service with Iroquois Gas Transmission System, L.P., dated September 1, 1995, filed as Exhibit 10 (tt) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995.* 10.43 Service Agreement between Algonquin Transmission Company and Colonial Gas Company (Under Rate Schedule AFT-1), dated December 1, 1995, filed as Exhibit 10 (uu) to the Registrant's Annual Report on Form 10-K. 10.44 Service Agreement between Algonquin Gas Transmission Company and Colonial Gas Company (under Rate Schedule AFT-1), dated June 23, 2000, filed as Exhibit 10.44 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1995. 10.45 Service Agreement between CNG Transmission Corporation and Colonial Gas Company (under Rate Schedule GSS-II), contract No. 300114, dated November 1, 1998, filed as Exhibit 10.45 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.46 Service Agreement between CNG Transmission Corporation and Colonial Gas Company (under Rate Schedule GSS-II), contract No. 300115, dated November 1, 1998, filed as Exhibit 10.46 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 15 10.47 Amended Service Agreement between Texas Eastern Transmission Corporation and Colonial Gas Company (under Rate Schedules CDS & FT-1) dated January 6, 1999, filed as Exhibit 10.47 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.48 Redacted Gas Resources Portfolio Management and Gas Sales Agreement between Colonial Gas Company and El Paso Energy Marketing Company dated September 14, 1999, as amended, filed herewith as Exhibit 10.1 to Form 10-K of Eastern Enterprises for the year ended December 31, 1999.* 10.49 Contract Restructuring Agreement between Colonial Gas Company and Tennessee Gas Pipeline dated August 2, 1999, filed as Exhibit 10.49 to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.* 10.50 Precedent Agreement between the Company and Algonquin Gas Transmission Company dated as of June 13, 2001, filed herewith. 99.1 Letter by the Company to the Securities and Exchange Commission regarding representations of 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. 16 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. COLONIAL GAS COMPANY D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND (Registrant) By: /s/ JOSEPH F. BODANZA -------------------------------------------- Joseph F. Bodanza Senior Vice President Finance, Accounting and Regulatory Affairs (Principal Financial and Accounting Officer) Date: 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 -------------------------------- Chester R. Messer Director and President 17 COLONIAL GAS COMPANY INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES (Information required by Items 8 and 14 (a) of Form 10-K) Report of Independent Public Accountants................................................................ F-20 Consolidated Statements of Earnings for the Year Ended December 31, 2001, Period from November 8, 2000 through December 31, 2000, Period from January 1, 2000 through November 7, 2000, Four Months Ended December 31, 1999, and Eight Months Ended August 31, 1999...................................................................... F-2 Consolidated Balance Sheets as of December 31, 2001 and 2000............................................ F-3 and F-4 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Year Ended December 31, 2001, Period from November 8, 2000 through December 31, 2000, Period from January 1, 2000 through November 7, 2000, Four Months Ended December 31, 1999, and Eight Months Ended August 31, 1999......................................... F-5 Consolidated Statements of Cash Flows for the Year Ended December 31, 2001, Period from November 8, 2000 through December 31, 2000, Period from January 1, 2000 through November 7, 2000, Four Months Ended December 31, 1999, and Eight Months Ended August 31, 1999...................................................................... F-6 Notes to Consolidated Financial Statements.............................................................. F-7 to F-19 Interim Financial Information for the Two Years Ended December 31, 2001 (Unaudited)..................... F-21 Schedule for the Year Ended December 31, 2001, Period from November 8, 2000 through December 31, 2000, Period from January 1, 2000 through November 7, 2000, and Year Ended December 31, 1999................................................................................. Schedule II--Valuation and Qualifying Accounts.................................................... F-21
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. F-1 COLONIAL GAS COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
Period from Period from November 8, January 1, 2000 Four Months Eight Months Year Ended 2000 through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Operating revenues .......................... $ 246,122 $ 61,414 $ 138,142 $ 54,098 $ 122,626 Cost of gas sold ............................ 159,064 32,384 72,658 26,087 65,320 --------- -------- --------- -------- --------- Operating margin ............................ 87,058 29,030 65,484 28,011 57,306 --------- -------- --------- -------- --------- Operating expenses: Operations ........................... 26,615 7,220 19,797 9,101 19,818 Maintenance .......................... 3,503 576 2,950 1,151 4,835 Depreciation and amortization ........ 14,465 2,875 11,359 2,857 10,086 Amortization of goodwill ............. 9,366 1,556 5,020 2,008 -- Income taxes ......................... 5,584 5,429 1,601 3,406 3,639 Taxes, other than income ............. 4,400 830 3,748 1,626 3,861 Restructuring charge ................. -- -- 7,000 -- -- Merger related expenses .............. -- -- 8,795 -- 3,788 --------- -------- --------- -------- --------- Total operating expenses .......... 63,933 18,486 60,270 20,149 46,027 --------- -------- --------- -------- --------- Operating earnings .......................... 23,125 10,544 5,214 7,862 11,279 Other earnings (loss), net .................. 17 19 315 237 (20) --------- -------- --------- -------- --------- Earnings before interest expense ............ 23,142 10,563 5,529 8,099 11,259 --------- -------- --------- -------- --------- Interest expense: Long-term debt ....................... 8,515 1,422 7,111 2,844 5,689 Other, including amortization of debt expense ........................... 16,339 2,316 5,842 2,569 1,244 Less--Interest during construction ... (128) (31) (64) (27) (194) --------- -------- --------- -------- --------- Total interest expense ............... 24,726 3,707 12,889 5,386 6,739 --------- -------- --------- -------- --------- Net (loss) earnings ......................... $ (1,584) $ 6,856 $ (7,360) $ 2,713 $ 4,520 ========= ======== ========= ======== =========
The accompanying notes are an integral part of these consolidated financial statements. F-2 COLONIAL GAS COMPANY CONSOLIDATED BALANCE SHEETS ASSETS
December 31, ------------------------ 2001 2000 --------- --------- (In Thousands) Gas plant, at cost .................................................................. $ 418,099 $ 394,509 Construction work-in-progress ....................................................... 9,763 7,751 Less-Accumulated depreciation ................................................. (133,127) (119,564) --------- --------- Net plant ............................................................... 294,735 282,696 --------- --------- Current assets: Cash .......................................................................... 121 124 Accounts receivable, less reserves of $3,709 at December 31, 2001 and $2,964 at December 31, 2000 ....................................................... 19,531 24,285 Accounts receivable - affiliates .............................................. 25,713 5,235 Accrued utility revenue ....................................................... 19,064 22,414 Deferred gas costs ............................................................ 15,579 33,550 Natural gas and other inventories, at average cost ............................ 16,832 13,246 Materials and supplies, at average cost ....................................... 695 1,709 Prepaid expenses .............................................................. 72 262 --------- --------- Total current assets .................................................... 97,607 100,825 --------- --------- Other assets: Goodwill ...................................................................... 377,652 371,850 Deferred charges and other assets ............................................. 6,998 4,077 --------- --------- Total other assets ...................................................... 384,650 375,927 --------- --------- Total assets ............................................................ $ 776,992 $ 759,448 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. F-3 COLONIAL GAS COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES
December 31, ----------------------- 2001 2000 --------- -------- (In Thousands) Capitalization: Common stockholder's investment-- Common stock, $1 par value-- Authorized and outstanding--100 shares ............... $ -- $ -- Amounts in excess of par value .......................... 269,430 203,558 Retained earnings ....................................... 5,272 6,856 Accumulated comprehensive income ........................ (5,281) -- --------- -------- Total common stockholder's investment ............. 269,421 210,414 Long-term obligations, less current portion ................... 120,205 120,621 --------- -------- Total capitalization .............................. 389,626 331,035 Advance from KeySpan .......................................... 200,000 250,000 --------- -------- Total capitalization and advance from KeySpan ................. 589,626 581,035 --------- -------- Current liabilities: Current portion of long-term obligations ................ 296 572 Notes payable - utility pool ............................ 68,517 47,209 Notes payable - utility pool gas inventory financing .... 21,958 19,216 Accounts payable ........................................ 12,538 38,765 Accounts payable--affiliates ............................ -- 6,486 Accrued taxes ........................................... 896 533 Accrued income taxes .................................... (75) 291 Accrued interest ........................................ 8,726 4,263 Customer deposits ....................................... 538 738 Other current liabilities ............................... 656 2,929 --------- -------- Total current liabilities ......................... 114,050 121,002 --------- -------- Reserves and deferred credits: Deferred income taxes ................................... 38,322 36,641 Unamortized investment tax credits ...................... 2,402 2,605 Postretirement benefits obligation ...................... 6,770 5,972 Other ................................................... 25,822 12,193 --------- -------- Total reserves and deferred credits ............... 73,316 57,411 --------- -------- Total capitalization and liabilities .............. $ 776,992 $759,448 ========= ========
The accompanying notes are an integral part of these consolidated financial statements. F-4 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Period from Period from November 8, 2000 January 1, 2000 Four Months Eight Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Balance at beginning of period ......... $ 6,856 $ -- $ 229 $ -- $ 36,173 Net (loss) earnings .............. (1,584) 6,856 (7,360) 2,713 4,520 Cash dividends on common stock ... -- -- (6,039) (2,484) (6,255) ------- ------ -------- ------- -------- Balance at end of period ............... $ 5,272 $6,856 $(13,170) $ 229 $ 34,438 ======= ====== ======== ======= ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Period from Period from November 8, 2000 January 1, 2000 Four Months Eight Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Net (loss) earnings .................... $(1,584) $6,856 $ (7,360) $ 2,713 $ 4,520 Accrued unfunded pension obligation .... (8,125) -- -- -- -- Income tax effect ...................... 2,844 -- -- -- -- ------- ------ -------- ------- -------- Comprehensive (loss) income ............ $(6,865) $6,856 $ (7,360) $ 2,713 $ 4,520 ======= ====== ======== ======= ========
The accompanying notes are an integral part of these consolidated financial statements. F-5 COLONIAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Period from Period from November 8, 2000 January 1, 2000 Four Months Eight Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Cash flows from operating activities: Net (loss) earnings ......................... $ (1,584) $ 6,856 $ (7,360) $ 2,713 $ 4,520 Adjustments to reconcile net (loss) earnings to provided by operating activities: Depreciation and amortization ............ 23,831 4,431 16,379 4,865 10,086 Deferred taxes ........................... 1,681 4,724 4,194 2,198 (2,751) Other changes in assets and liabilities: Accounts receivable ................... (15,724) (7,986) (6,122) (4,548) 1,802 Accrued utility margin ................ 3,350 (7,955) 7,350 (7,420) 7,222 Accounts payable--affiliates .......... (6,486) 4,859 (15,714) 15,084 2,832 Inventories ........................... (2,572) 8,752 (9,850) 1,120 640 Deferred gas costs .................... 17,971 (21,475) (12,006) (13,888) 18,280 Accounts payable ...................... (26,227) 10,548 11,639 5,666 (1,274) Accrued income taxes .................. (366) 1,333 3,853 (5,200) (10,708) Other ................................. 8,521 2,014 3,929 (7,481) 22,884 -------- -------- -------- -------- -------- Cash (used for) provided by operating activities .................................. 2,395 6,101 (3,708) (6,891) 53,533 -------- -------- -------- -------- -------- Cash flows from investing activities: Capital expenditures ........................ (26,448) (6,943) (12,092) (7,105) (12,715) -------- -------- -------- -------- -------- Cash used for investing activities ............. (26,448) (6,943) (12,092) (7,105) (12,715) -------- -------- -------- -------- -------- Cash flows from financing activities: Changes in notes payable, net ............... 21,308 (191) 18,400 10,000 (33,000) Changes in inventory financing .............. 2,742 1,031 3,176 4,139 (3,255) Advance from KeySpan ........................ (50,000) -- -- -- (102) Addition to equity .......................... 50,000 -- -- -- 1,399 Cash dividends paid on common stock ......... -- -- (6,039) (2,484) (6,255) -------- -------- -------- -------- -------- Cash provided by (used for) financing activities .................................. 24,050 840 15,537 11,655 (41,213) -------- -------- -------- -------- -------- Decrease in cash ............................... (3) (2) (263) (2,341) (395) Cash at beginning of period .................... 124 126 389 2,730 3,125 -------- -------- -------- -------- -------- Cash at end of period .......................... $ 121 $ 124 $ 126 $ 389 $ 2,730 ======== ======== ======== ======== ======== Supplemental disclosure of cash flow information: Cash paid (refunded) during the year for: Interest, net of amounts capitalized ...................... $ 22,134 $ 623 $ 14,206 $ 1,657 $ 8,434 ======== ======== ======== ======== ======== Income taxes ....................... $ 3,440 $ -- $ (6,921) $ 4,376 $ 3,595 ======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-6 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Accounting Policies General Colonial 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 24 municipalities located northwest of Boston and on Cape Cod. 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 consolidated financial statements include the accounts of the Company and its affiliate, Massachusetts Fuel Inventory Trust (through December 31, 2000) and its wholly-owned subsidiary, Transgas Inc.(through August 31, 1999). Transgas ceased to be a subsidiary of Colonial Gas Company and became a subsidiary of Eastern upon closing of the Eastern merger discussed below. All material intercompany balances and transactions between the Company and its subsidiary have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. KeySpan 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. Consistent with the Eastern merger, 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 $139 million was recorded as an asset and is being amortized over a period of 40 years. The push-down accounting resulted in a decrease to equity of $8.9 million and the recording of a $250 million advance from KeySpan, $100 million of which was previously owed to Eastern. An additional $15.2 million was recorded as goodwill in finalizing the purchase price allocation of which $15.9 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. 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 F-7 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (1) Accounting Policies (Continued) 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. Eastern Merger On August 31, 1999, the Company completed a merger with Eastern in a transaction with an enterprise value of approximately $474 million. In effecting the transaction, Eastern paid $150 million in cash, net of cash acquired and including transaction costs, issued approximately 4.2 million shares of common stock valued at $186 million and assumed $138 million of debt. The merger was accounted for using the purchase method of accounting for business combinations. The purchase price was allocated to the net assets acquired based on their fair value. The historical cost basis of the Company's assets and liabilities, with the exception of the adjustments described below, was determined to represent the fair value due to the existence of a regulatory-approved rate plan based upon the recovery of historical costs and a fair return thereof. The administrative functions of the Company have been integrated into the functions of its affiliate, KeySpan Corporate Services LLC, an indirect wholly-owned subsidiary of KeySpan. In connection with the merger, the Department of Telecommunications and Energy (the "Department") approved a rate plan resulting in a ten-year freeze of base rates at current levels. Due to the length of the base rate freeze, the Company was required to discontinue its application of Statement of Financial Accounting Standards ("SFAS") No. 71 "Accounting for the Effects of Certain Types of Regulation". Accordingly, as of the merger, the Company assigned no value to regulatory assets of approximately $18 million, consisting principally of deferred demand side management program costs, deferred environmental costs and unrecovered deferred income taxes. The excess of consideration over the fair value of the assets acquired of $241 million was recorded as goodwill, which was being amortized on a straight-line basis over a 40-year period. Of the $241 million, $141 million was recorded as an increase to common equity and $100 million as an advance from Eastern. Regulation The Company is regulated as to rates, accounting and other matters by the Department. For the periods prior to the merger with Eastern and the approved rate plan, the accounting policies conformed to generally accepted accounting principles as applied to regulated public utilities and reflected the effects of the ratemaking process in accordance with SFAS No. 71. Under SFAS No. 71, the Company was allowed to defer certain costs that otherwise would be expensed in recognition of the ability to recover them in future rates. As F-8 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (1) Accounting Policies (Continued) described above, the Company discontinued application of SFAS No. 71 as a result of the rate plan approved by the Department in connection with its approval of the merger of the Company with Eastern. 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 Unbilled Gas Costs Receivable 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 cost 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. Upon the discontinuance of the application of SFAS No. 71, the Company records amounts recoverable under the LDAC as revenue when billed to 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, was 3.6% in 2001, and 3.7% in 2000 and 1999. 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. We currently do not anticipate that implementation of this Statement will have a significant effect on its results of operation and financial condition. F-9 COLONIAL 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 operation 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 the four months ended December 31, 1999, the period January 1 through November 7, 2000, and the period from 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 140% for 2001, 44% for the period from November 8, 2000 through December 31, 2000, 56% for the four months ended December 31, 1999 and 45% for the eight months ended August 31, 1999. State taxes and the nondeductibility of goodwill amortization associated with the Eastern and KeySpan mergers, represent the majority of the difference between the effective rate and the federal income tax rate of 35% for 2001, 2000 and 1999. For the period from January 1 through November 7, 2000, the effective tax rate was incalculable as there was income tax expense even though the Company had a loss. This was due to the non-deductibility of goodwill amortization and certain merger costs. A summary of the provision for income taxes is as follows:
Period from Period from Eight November 8, January 1, Four Months Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Current-- Federal ......................... $ 11,788 $ 588 $(2,166) $1,028 $ 5,344 State ........................... 2,378 117 (427) 180 1,046 -------- ------ ------- ------ ------- Total Current Provision ... 14,166 705 (2,593) 1,208 6,390 -------- ------ ------- ------ ------- Deferred-- Federal ......................... (7,072) 3,942 3,476 1,800 (2,328) State ........................... (1,510) 782 718 398 (423) -------- ------ ------- ------ ------- Total Deferred Provision .. (8,582) 4,724 4,194 2,198 (2,751) -------- ------ ------- ------ ------- Provision for income taxes ............ $ 5,584 $5,429 $ 1,601 $3,406 $ 3,639 ======== ====== ======= ====== =======
F-10 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (2) Income Taxes (Continued) 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. Income tax credits are deferred and credited to income over the lives of the property giving rise to such credits. 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:
December 31, ------------------------- 2001 2000 -------- -------- (In Thousands) Assets: Total deferred tax assets .......................... $ 15,494 $ 13,437 -------- -------- Liabilities: Accelerated Depreciation ................................. (36,682) (35,296) Deferred Gas Costs ....................................... (4,673) (12,389) Other .................................................... (11,899) (7,960) -------- -------- Total deferred tax liabilities ..................... (53,254) (55,645) -------- -------- Total net deferred taxes ........................... $(37,760) $(42,208) ======== ======== Deferred taxes are reflected in the balance sheet as follows: Accrued income taxes (current deferred) .................. $ 562 $ (5,567) Deferred income taxes (long-term) ........................ (38,322) (36,641) -------- -------- Total .............................................. $(37,760) $(42,208) ======== ========
F-11 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (3) Debt Long-term Obligations The following table provides information on long-term obligations as of:
December 31, ------------------------- 2001 2000 --------- --------- (In Thousands) First Mortgage Bonds: 8.80%, Series CH, due 2022 ................................. $ 25,000 $ 25,000 6.38%--6.94%, Medium-Term Notes, Series A, due 2008--2027 .. 65,000 65,000 5.50%--6.86%, Medium-Term Notes, Series B, due 2003--2028 .. 30,000 30,000 Capital lease obligations (Note 5) ............................... 501 1,193 Less current portion ............................................. (296) (572) --------- --------- $ 120,205 $ 120,621 ========= =========
Bonds of $10,000,000 are due in 2003. Bonds of $15,000,000 due in 2027 can be redeemed by the holder in 2002. Bonds of $20,000,000 due in 2025 can be redeemed by the holder in 2005. Bonds of $20,000,000 due in 2028 can be redeemed by the holder in 2008. The first mortgage bonds are collateralized by utility property. The Company's first mortgage bond indenture includes, among other provisions, limitations on the issuance of long-term debt, leases and the payment of dividends from retained earnings. Annual maturities of capital lease obligations are $296,000, $167,000, $35,000, $3,000 and $0 for 2002 through 2006, 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 $68,517,000 and $21,958,000 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 by KeySpan 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 $250 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, $50 million was repaid to KeySpan. The interest rate on these borrowings is 7.625%. 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. F-12 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (4) Retiree Benefits Pension Plans The Company has defined benefit pension plans covering substantially all employees. These include two qualified union plans, one qualified plan for non-union employees, and various unqualified individual retirement agreements covering certain key employees and retirees. 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"). Cost for these plans and agreements charged to expense was as follows:
Period from Period from November 8 January 1 Four Months Eight Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Service cost .................................. $ 753 $ 184 $ 643 $ 243 $ 850 Interest cost on projected benefits obligation ................................... 4,315 679 3,092 1,239 2,447 Expected return on plan assets ................ (4,161) (700) (3,197) (1,302) (2,977) Amortization of prior service cost ............ -- -- -- -- 97 Amortization of transitional obligation ....... -- -- -- -- 238 Recognized actuarial loss ..................... 263 -- -- -- 96 Curtailment ................................... -- -- -- -- 295 ------- ----- ------- ------- ------- Total net pension cost ........................ $ 1,170 $ 163 $ 538 $ 180 $ 1,046 ======= ===== ======= ======= =======
Post-retirement Life and Health Care The Company has a post-retirement benefit plan that covers substantially all employees. The plan provides medical, dental and life insurance benefits. The plan is contributory for retirees, with respect to post-retirement medical and dental benefits; the plan is noncontributory with respect to life insurance benefits. Beginning in 1990, the Company has funded a portion of these costs through the combination of trusts under Section 501(c)(9) and Section 401(h) of the Internal Revenue Code. Net periodic expense for post-retirement benefits other than pensions was as follows:
Period from Period from November 8 January 1 Four Months Eight Months Year Ended through through Ended Ended December 31, December 31, November 7, December 31, August 31, 2001 2000 2000 1999 1999 ---- ---- ---- ---- ---- (In Thousands) (Predecessor II) (Predecessor II) (Predecessor I) Service cost .................................... $ 236 $ 81 $ 107 $ 39 $ 94 Interest cost on accumulated benefits obligations ................................... 887 161 649 247 400 Expected return on plan assets .................. (397) (76) (304) (127) (292) Amortization of transition obligation ........... -- -- -- -- 166 Recognized actual loss .......................... 10 -- -- -- -- Curtailment ..................................... -- -- -- -- 308 ------- ----- ------- ------- ------- Total net retiree health care cost .............. $ 736 $ 166 $ 452 $ 159 $ 676 ======= ===== ======= ======= =======
F-13 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (4) Retiree Benefits (Continued) The tables above do not reflect retirement enhancements for pension and health care of $2,667,000 and $33,000, respectively for the eight months ended August 31, 1999. The following tables set forth the change in benefit obligation and plan assets and reconciliation of funded status of the Company's pension 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:
Period from Period from November 8 January 1 Year Ended through through December 31, December 31, November 7, 2001 2000 2000 ---- ---- ---- (In Thousands) (Predecessor II) Pensions Change in benefit obligation Balance at beginning of period ............... $ 60,311 $ 55,503 $ 52,986 Adjustment ................................... 2,949 -- -- Service cost ................................. 753 183 643 Interest cost ................................ 4,315 691 3,079 Plan amendments .............................. 3,444 -- -- Benefits paid ................................ (4,933) (475) (3,370) Actuarial (gain) loss ........................ (1,990) 4,409 2,165 -------- -------- -------- Balance at end of period ..................... $ 64,849 $ 60,311 $ 55,503 ======== ======== ======== Change in plan assets Fair value, beginning of period .............. $ 48,999 $ 49,971 $ 48,484 Adjustment ................................... 1,831 -- -- Actual return on plan assets ................. (4,909) (520) 4,318 Employer contributions ....................... 1,985 23 539 Benefits paid ................................ (4,933) (475) (3,370) -------- -------- -------- Fair value at end of period .................. $ 42,973 $ 48,999 $ 49,971 ======== ======== ======== Reconciliation of funded status Funded status ................................ $(21,876) $(11,312) $ (5,532) Contributions for fourth quarter ............. -- -- -- Unrecognized actuarial loss .................. 7,795 5,641 3,000 Unrecognized prior service ................... 3,444 -- -- -------- -------- -------- Net amount recognized at end of period ....... $(10,637) $ (5,671) $ (2,532) ======== ======== ======== Amounts recognized in balance sheet Prepaid benefit cost ......................... $ -- $ 59 $ 73 Accrued benefit liability .................... (19,362) (5,730) (2,605) Intangible asset ............................. 3,444 -- -- Accumulated other comprehensive income ....... 5,281 -- -- -------- -------- -------- Net amount ................................... $(10,637) $ (5,671) $ (2,532) ======== ======== ========
F-14 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (4) Retiree Benefits (Continued) Assets of the employee benefit plans are invested in domestic and international equities, domestic and international fixed income securities, real estate and other short-term debt instruments. The following tables set forth the change in benefit obligation and plan assets and reconciliation of funded status of the Company's post-retirement life and health benefit 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:
Period from Period from November 8 January 1 Year Ended through through December 31, December 31, November 7, 2001 2000 2000 ---- ---- ---- (In Thousands) (Predecessor II) Healthcare Change in benefit obligation Balance at beginning of period .......... $ 12,819 $ 11,396 $ 10,761 Adjustment .............................. 771 -- -- Service cost ............................ 236 81 108 Interest cost ........................... 887 161 649 Plan participant's contribution ......... 473 -- -- Curtailment loss ........................ -- -- -- Special termination benefits ............ -- -- -- Benefits paid ........................... (1,517) (49) (545) Subsidiary spun-off ..................... -- -- -- Actuarial (gain) loss ................... (534) 1,230 423 -------- -------- -------- Balance at end of period ................ $ 13,135 $ 12,819 $ 11,396 ======== ======== ======== Change in plan assets Fair value, beginning of period ......... $ 4,937 $ 5,184 $ 5,172 Adjustment .............................. 294 -- -- Actual return on plan assets ............ (1,132) (198) 557 Employer contributions .................. 356 -- -- Benefits paid ........................... (1,517) (49) (545) Subsidiary spun-off ..................... -- -- -- Plan participant's contribution ......... 473 -- -- -------- -------- -------- Fair value at end of period ............. $ 3,411 $ 4,937 $ 5,184 ======== ======== ======== Reconciliation of funded status Funded status ........................... $ (9,724) $ (7,882) $ (6,212) Unrecognized actuarial loss ............. 2,577 1,504 400 -------- -------- -------- Net amount recognized at end of period .. $ (7,147) $ (6,378) $ (5,812) ======== ======== ======== Amounts recognized in balance sheet Prepaid benefit cost .................... $ 153 $ 113 $ -- Accrued benefit liability ............... (7,300) (6,491) (5,812) -------- -------- -------- Net amount .............................. $ (7,147) $ (6,378) $ (5,812) ======== ======== ========
F-15 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (4) Retiree Benefits (Continued) Following are the weighted-average assumptions used in developing the projected benefit obligation:
Period from Period from November 8 January 1 Year Ended through through December 31, December 31, November 7, 2001 2000 2000 ---- ---- ---- (Predecessor II) Discount rate............................. 7.0% 7.0% 7.5% Return on plan assets..................... 8.5% 8.5% 8.5% Increase in future compensation........... 4.0% 5.0% 5.0% Health care inflation rate................ 5.0-10.0% 8.0% 8.0%
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:
One-Percentage One-Percentage Point Increase Point Decrease -------------- -------------- (In Thousands) Service cost and interest cost components ... $ 162 $ (142) Post-retirement benefit obligation .......... $1,578 $(1,433)
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 $3.4 million debit in Deferred Charges Other and a $5.3 million debit in Accumulated Other Comprehensive Income. In December 2002, the Company will re-measure the accumulated benefit obligations and pension assets, and adjust the accrual and deferrals as appropriate. (5) Leases The Company leases certain equipment used in its operations. The Company has capitalized certain of these leases and reflects lease payments as rental expense in the periods to which they relate. Total rent expense for the year ended December 31, 2001 was $592,000. Total rental expense for the period from November 8 through December 31, 2000 and the period from January 1 through November 7, 2000 approximated $128,000 and $688,000, respectively. Total rental expense for the four months ended December 31, 1999 and eight months ended August 31, 1999 approximated $265,000 and $545,000, respectively. F-16 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (5) Leases (Continued) The remaining minimum rental commitment for capital leases at December 31, 2001 is as follows: Year (In Thousands) ---- 2002 ........................................................ $296 2003 ........................................................ 167 2004 ........................................................ 35 2005 ........................................................ 3 2006 ........................................................ -- Later years ................................................. -- ---- Total minimum lease payments ................................ $501 ==== (6) 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. The carrying amounts and estimated fair values of the Company's long-term debt at December 31, 2001 and 2000 are as follows: 2001 2000 ------------------------ ----------------------- Carrying Carrying Amount Fair Value Amount Fair Value ------ ---------- ------ ---------- (In Thousands) Long-term debt ...... $120,868 $120,653 $121,193 $121,606 (7) Related Party Transactions In 2001, the Company was charged $9,080,000 by KeySpan Corporate Services for services, which included: 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 $5,616,000 during 2001. The Company paid Eastern $145,000 for the period November 8, 2000 through December 31, 2000, $725,000 for the period January 1, 2000 through November 7, 2000 and $240,000 in 1999 for legal, tax and corporate services rendered. On November 8, 2000, KeySpan Corporate Services became an affiliate of the Company, through the Company's merger with KeySpan. KeySpan Corporate Services provides financing to the Company for working F-17 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (7) Related Party Transactions (Continued) capital and gas inventory through the Company's participation in a Utility Money Pool. At December 31, 2001, the Company had outstanding borrowings of $68,517,000 and $21,958,000 for working capital and fuel inventory, respectively. In 2001, the Company was charged by KeySpan Corporate Services $1,347,000 and $547,000 for interest on working capital and fuel inventory borrowings, respectively. At December 31, 2000, the Company had outstanding borrowings of $47,209,000 and $19,216,000 for working capital and gas inventory, respectively. In 2000, the Company paid KeySpan Corporate Services $170,000 and $42,000 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, $200 million in advances were recorded on the books of the Company from KeySpan Corporation. A $100 million of this advance was previously owed to Eastern and is reflected in the Balance Sheet at December 31, 1999. In 2001, the Company was charged by KeySpan Corporation $17,141,000 and $650,000 for interest and debt issuance costs, respectively. 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. (8) Restructuring Charge During the third quarter of 2000, the Company recorded a restructuring charge of $7.0 million related to its decision to exit the gas appliance repair and service and appliance rental business. The charge includes $5.1 million to write down to fair value the equipment used in the rental business and $1.2 million for employee severance and termination benefits associated with the service business. The remaining $0.7 million is associated with the disposal of inventory and related costs. (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") and related sites. The Company may have or share responsibility under applicable environmental laws for the remediation of one former MGP site and related satellite disposal sites, as well as one non-MGP site and a federal superfund site. The Company has estimated its potential share of the costs of investigating and remediating these sites 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 presently estimates the remaining cost of its MGP-related environmental cleanup activities will be $2.4 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 this estimate. 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. By a rate order issued on May 25, 1990, the Department approved, for ratemaking purposes, 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 currently believes, in light of the Department rate order, that it is not probable that actual costs will materially affect its financial condition or results of operations. F-18 COLONIAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (9) Environmental Matters (Continued) The Company has received and responded to Requests for Information from the U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), regarding one federal superfund site that the EPA is currently investigating. Although the Company cannot determine the amount of its liability at this time, it does not believe that any such liability will have a material adverse effect on the Company's financial condition. (10) Workforce Reduction Program As a result of the KeySpan merger, the Company implemented a severance program in an effort to reduce the workforce. The Company recorded a liability of $1.7 million associated with this severance program. During the year ended December 31, 2001 the Company reduced this liability by $1.1 million as a result of lower than anticipated costs per employee and recorded a corresponding reduction to Goodwill. This severance program was targeted to reduce the Company's workforce by an additional 20 employees. At December 31, 2001 the Company paid $0.6 million for this program, which was completed in 2001. F-19 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Colonial Gas Company: We have audited the accompanying consolidated balance sheet of Colonial 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, the four months ended December 31, 1999 and the eight months ended August 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 Colonial 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, the four months ended December 31, 1999 and the eight months ended August 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 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 state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP New York, New York February 4, 2002 F-20 COLONIAL GAS COMPANY INTERIM FINANCIAL INFORMATION For the Two Years Ended December 31, 2001 (Unaudited)
Three Months Ended ------------------ March 31 June 30 Sept. 30 Dec. 31 -------- ------- -------- ------- (In Thousands) 2001 Operating revenues ................. $122,048 $ 42,185 $ 19,482 $62,407 Operating margin ................... $ 42,681 $ 13,754 $ 6,564 $24,059 Utility operating earnings (loss) .. $ 18,867 $ 579 $ (3,062) $ 6,741 Net earnings (loss) ................ $ 12,474 $ (5,777) $ (9,227) $ 946
Period from Period from Three Months Ended October 1 November 8 ---------------------------- through through March 31 June 30 Sept. 30 Nov. 7 Dec. 31 -------- ------- -------- ------ ------- (Predecessor II) (Predecessor II) (Predecessor II) (Predecessor II) (In Thousands) 2000 Operating revenues ................. $86,335 $ 26,718 $ 16,222 $ 8,867 $61,414 Operating margin ................... $41,494 $ 13,953 $ 6,654 $ 3,383 $29,030 Utility operating earnings (loss) .. $17,243 $ 2,379 $ (5,922) $(8,486) $10,544 Net earnings (loss) ................ $13,695 $ (1,565) $(10,229) $(9,261) $ 6,856
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. F-21 SCHEDULE II COLONIAL GAS COMPANY VALUATION AND QUALIFYING ACCOUNTS (In Thousands)
Additions --------- Net Balance at Charged Charged Deductions Balance at Beginning (Credited) to Other from End Description Of Period to Income Accounts Reserves Of Period ----------- --------- --------- -------- -------- --------- For the Year Ended December 31, 2001 ------------------------------------ Reserves for doubtful accounts $2,964 $2,820 $ -- $2,075 $3,709 ====== ====== ====== ====== ====== Reserve self-insurance $1,886 $ 275 $ -- $ 566 $1,595 ====== ====== ====== ====== ====== Reserve for environmental expenses $ 850 $ -- $1,664 $ 96 $2,418 ====== ====== ====== ====== ====== For the Period from November 8 through December 31, 2000 -------------------------------------------------------- Reserves for doubtful accounts $2,897 $ 286 $ -- $ 219 $2,964 ====== ====== ====== ====== ====== Reserve self-insurance $1,427 $ 459 $ -- $ -- $1,886 ====== ====== ====== ====== ====== Reserve for environmental expenses $ 850 $ -- $ -- $ -- $ 850 ====== ====== ====== ====== ====== For the Period from January 1 through November 7, 2000 ------------------------------------------------------ (Predecessor II) ---------------- Reserves for doubtful accounts $2,677 $1,695 $ -- $1,475 $2,897 ====== ====== ====== ====== ====== Reserve self-insurance $1,108 $ 793 $ -- $ 474 $1,427 ====== ====== ====== ====== ====== Reserve for environmental expenses $ 850 $ -- $ -- $ -- $ 850 ====== ====== ====== ====== ====== For the Four Months Ended December 31, 1999 ------------------------------------------- (Predecessor II) ---------------- Reserves for doubtful accounts $3,168 $ 344 $ -- $ 835 $2,677 ====== ====== ====== ====== ====== Reserve self-insurance $1,008 $ 100 $ -- $ -- $1,108 ====== ====== ====== ====== ====== Reserve for environmental expenses $ 200 $ -- $ 650 $ -- $ 850 ====== ====== ====== ====== ====== For the Eight Months Ended August 31, 1999 ------------------------------------------ (Predecessor I) --------------- Reserves for doubtful accounts $2,551 $1,234 $ -- $ 617 $3,168 ====== ====== ====== ====== ====== $ (760)* Reserve self-insurance $1,408 $ 559 $ -- $ 199 $1,008 ====== ====== ====== ====== ====== Reserve for environmental expenses $ 200 $ -- $ -- $ -- $ 200 ====== ====== ====== ====== ======
* Reserve Balance spun off from Transgas at acquisition F-22