-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HeX/FpyjkJy2GWzTH4zuhRFQwdn1tpxGAjJDytiiekyFVCn1PuK4ngzmJpl89Dbs yObR/2+Lb8i127n5pI70vA== 0000060653-98-000013.txt : 19980317 0000060653-98-000013.hdr.sgml : 19980317 ACCESSION NUMBER: 0000060653-98-000013 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980313 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: COLONIAL GAS CO CENTRAL INDEX KEY: 0000060653 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 041558100 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-13351 FILM NUMBER: 98564729 BUSINESS ADDRESS: STREET 1: 40 MARKET ST CITY: LOWELL STATE: MA ZIP: 01852 BUSINESS PHONE: 5084583171 FORMER COMPANY: FORMER CONFORMED NAME: LOWELL GAS CO DATE OF NAME CHANGE: 19811124 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K _x_ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 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 (Exact name of registrant as specified in its charter) Massachusetts 04-1558100 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 40 Market Street, Lowell, Massachusetts 01852 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (978) 322-3000 Securities registered pursuant to Section 12(b) of the Act: Common Stock, $3.33 par value (Title of Class) 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. _x_ Yes ___ 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 ____ The aggregate market value of the voting stock held by non- affiliates of the registrant as of February 27, 1998 was $248,707,883. The number of shares of the registrant's common stock outstanding as of February 27, 1998 was 8,707,497. DOCUMENTS INCORPORATED BY REFERENCE Portions of the annual report to stockholders for the year ended December 31, 1997 are incorporated by reference into Part II and Part IV. Portions of the proxy statement for the 1998 annual meeting of stockholders are incorporated by reference into Part III. COLONIAL GAS COMPANY FORM 10-K ANNUAL REPORT FOR THE YEAR ENDING DECEMBER 31, 1997 TABLE OF CONTENTS PART I Item 1. Business Item 2. Properties Item 3. Legal Proceedings Item 4. Submission of Matters to a Vote of Security Holders PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters Item 6. Selected Financial Data Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 8. Financial Statements and Supplementary Data Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure PART III Item 10. Directors and Executive Officers of the Registrant Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management Item 13. Certain Relationships and Related Transactions PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K PART I Item 1. Business THE COMPANY Colonial Gas Company ("Colonial" or the "Company"), a Massachusetts corporation formed in 1849, is primarily a regulated natural gas distribution utility. The Company serves over 151,000 utility customers in 24 municipalities located northwest of Boston and on Cape Cod. Through its subsidiary, Transgas Inc. ("Transgas"), the Company also provides over-the- road transportation of liquefied natural gas ("LNG"), propane and other commodities. The Company's corporate office is located at 40 Market Street, Lowell, Massachusetts 01852. The telephone number is (978) 322-3000. The Company's combined natural gas distribution service areas in the Merrimack Valley region northwest of Boston and on Cape Cod cover approximately 622 square miles with a year-round population of approximately 500,000, which increases by approximately 350,000 during the summer tourist season on Cape Cod. The Company is serving approximately 50% of potential customers in its service areas. Of its 151,600 customers, approximately 90% are residential accounts. The Company added 6,112 firm sales customers in 1997. The Company's growth has been based on new residential construction in its service areas and conversions to gas from other energy sources for existing homes and businesses. Of the total number of new customers in 1997, 54% converted from other fuels and 46% were new construction. The Company's 1997 consolidated operating revenues were derived 65% from firm gas sales to residential customers, 31% from firm gas sales to commercial and industrial customers, 2% from non-firm customers, 1% from firm transportation customers and 1% from other revenues. For the year 1997, the Company sold 19,997 MMcf of gas, of which 12,074 MMcf was sold in the Merrimack Valley area and 7,923 MMcf in the Cape Cod area. At December 31, 1997, 91% of the Company's residential customers used gas as their source of heating fuel. The demand for the products and services furnished by the Company is to a great extent seasonal, being heaviest in the colder months. At December 31, 1997, the Company had 490 full-time- equivalent employees. Of those employees, 96 are covered by a collective bargaining agreement with the United Steelworkers of America which expires in April 2001 and 73 are covered by a separate collective bargaining agreement with the United Steelworkers of America which expires in February 2000. In addition, Transgas employs 62 full-time employees of which 46 are covered by collective bargaining agreements with the International Brotherhood of Teamsters . The drivers agreement expires in June 1999 while the mechanics agreement expires in July 1999. GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES As discussed below in "Regulatory Matters", in 1997 the Massachusetts Department of Telecommunications and Energy, formerly known as the Department of Public Utilities (the "DTE"), directed all investor-owned gas utilities to unbundle their rates and services in order to make supplier choice available to all gas utility customers beginning November 1, 1998. Unbundled service involves the customers themselves contracting for supply to be brought to the Company's distribution system, and the Company then delivering that supply to the customer's facilities. Presently, the Company offers unbundled service only to commercial and industrial customers, and only a small number subscribe to such service. The Company anticipates that the DTE's directives will mean an increase in the proportion of gas entering the Company's distribution system that is supplied by others and will entail some transfer of its gas supply, pipeline transportation and storage resources to competitive market entities during the next several years. Until such time, the Company will continue to be responsible for the management of the gas supplies, pipeline transportation and storage resources required to serve its firm sales customers. In doing so, the Company generally pays negotiated prices for pipeline-transported supplies and tariffed rates as approved by the Federal Energy Regulatory Commission ("FERC") for pipeline transportation and storage services. The following table shows the Company's sources of firm supply available to meet its gas requirements and the actual components of gas sendout for each of the last three years: 1997 1996 1995 MMcf(a) % MMcf(a) % MMcf(a) % Firm Pipeline Transportation Capacity 30,313 30,313 30,630 Firm Gas Supply Sources Contracts for Pipeline- Transported Gas (b) 18,818 75 18,698 71 18,725 70 LNG contracts 2,616 10 4,150 15 4,150 15 Storage inventory at January 1 (c) 3,754 15 3,614 14 3,956 15 Total Available 25,188 100 26,462 100 26,831 100 Gas Sendout Pipeline-Transported Supplies (d) 14,763 72 15,115 72 14,659 72 Supplemental Supplies: Underground storage 3,605 17 3,346 16 3,270 16 LNG-as liquid 680 3 1,067 5 844 4 LNG-as vapor 1,680 8 1,528 7 1,574 8 Propane-air 5 - 1 - 8 - Total Sendout 20,733 100 21,057 100 20,355 100 Ratio of available firm supply to sendout (e) 1.21 1.26 1.32 _________________________ (a) The term "MMcf" means one million cubic feet of vapor or vapor equivalent. (b) The Company's firm supply purchase contracts are structured to enable the Company to purchase volumes equivalent to the total amount of its firm pipeline transportation capacity during the winter or peak demand season, but less than total firm pipeline capacity during the off-peak season. Accordingly, the total supply purchase contract volumes shown are less than total firm transportation capacity for 1997, 1996 and 1995. (c) The Company's storage inventory is drawn down and refilled throughout the year depending upon the availability and price of gas sources and upon the requirements of the Company's customers. The Company's current level of underground storage capacity is 4,674 MMcf. (d) Includes firm and spot volumes. (e) The Company's ratio of available firm supply to sendout was determined by dividing total firm gas supply sources by total sendout. The Company's current portfolio is designed to meet the gas requirements of its firm sales customers for the foreseeable future. Additional information concerning the Company's firm gas supply related resources is set forth below. Merrimack Valley Service Area Resources The Company maintains several contracts with the Tennessee Gas Pipeline Company ("Tennessee") for the firm transportation by interstate pipeline of a total of up to 48,496 Mcf per day of gas from gas production areas to the Company's Merrimack Valley distribution system. Of this volume, 4,000 Mcf per day can be delivered on a firm basis to the Company's Cape Cod service area. These interstate pipeline transportation contracts with Tennessee have varied expiration dates of between November 1, 2000 and April 1, 2013. The supply purchase contracts for the gas to be shipped under these interstate pipeline transportation contracts are also firm, and are generally extered into for terms of one year, with renewal options for additional one year terms. In addition, the Company contracts for underground storage service which, in conjunction with other Tennessee firm transportation contracts, provide up to an additional 23,587 Mcf per day of firm deliverability in the winter season. The underground storage contracts expire on March 31, 2000 and the associated transportation contracts expire on November 1, 2000. To supplement these capabilities during the winter season, the Company's Merrimack Valley service area on-system LNG and propane- air facilities have an aggregate sendout capacity of approximately 76,100 Mcf per day. Cape Cod Service Area Resources The Company maintains several contracts with Algonquin Gas Transmission Company ("Algonquin") for the firm transportation by interstate pipeline of a total of up to 45,368 Mcf of gas per day delivered to the Company's Cape Cod distribution system. These transportation contracts have varied expiration dates of between April 30, 2012 and October 31, 2013. The Company also maintains multiple upstream firm transportation contracts from gas production areas to the Algonquin pipeline, as well as upstream storage service contracts, on seven other interstate pipelines. These upstream contracts have varied expiration dates of between October 31, 2000 and October 31, 2013. As with the Merrimack Valley system, the supply purchase contracts for gas to be shipped under firm interstate pipeline transportation contracts to the Cape Cod distribution system are also firm and are generally entered into for terms of one year, with renewal options for additional one year terms. The Company also operates on-system facilities in the Cape Cod service area capable of providing approximately 30,000 Mcf per day of sendout during the winter season. REGULATORY MATTERS The Company is a public utility subject to the jurisdiction and regulatory authority of the DTE with respect to its rates as well as to the issuance of securities, franchise territory and other related matters. On July 18, 1997, the DTE directed the Company and the other investor-owned gas utilities in Massachusetts to collaborate on developing common principles to unbundle their services to provide customers with broader supplier choice. The DTE further directed that all gas utilities have unbundled rates in effect by November 1, 1998 for all customer classes. Unbundled service separates (i) the part of the service involving procuring the gas and transporting it to the city-gate (i.e. the point where the Company takes gas from the interstate pipeline into its distribution systems); and (ii) the delivery of the gas to the customer's facility through the local distribution system. The Company presently offers an unbundled service to commercial and industrial customers who seek to have other suppliers procure their gas which the Company then delivers to them through its distribution system. The Company's proposal for further rate unbundling is being developed and is expected to be filed in the spring of 1998. In addition, the Company continues to participate in the DTE-directed Unbundling Collaborative. The Company cannot predict the outcome of the Unbundling Collaborative process or the other regulatory changes that may take place, but at this time, the Company does not anticipate that the unbundling of its services will have a material financial impact on its business. Under the present regulatory system, the DTE permits Massachusetts gas companies to utilize a cost of gas adjustment clause ("CGAC") through which firm sales customers pay, via their monthly gas bill, the costs incurred by the companies in procuring and transporting gas to the companies distribution systems. Changes in non-gas or base rates charged to customers are subject to approval by the DTE after formal proceedings. Environmental response costs, transition costs and demand side management (DSM) program costs are recovered through the CGAC, as approved by the DTE. The environmental response costs recovered through the CGAC relate to the Company's former gas manufacturing operations, as described under "Environmental Matters". Transition costs relate to FERC approved pipeline charges resulting from Order 636. In addition to full recovery of the installed conservation measures, the Company has been allowed to recover, under methodologies approved in 1995 for its residential DSM programs and in 1996 for its commercial and industrial programs, the resulting lost margins and, through 1996, financial incentives based on the attainment of performance goals. The Company has made only two requests for base rate increases since 1984. Its most recent request was made in 1993. In response to that request, the DTE approved a base rate increase that was designed to produce additional revenues of $6.7 million or 3.9% annually, effective November 1, 1993. Based upon continued strong customer growth, cost control and improved productivity, the Company's goal remains to postpone the filing of a request for its next base rate increase until at least the year 2000, while maintaining an adequate return to shareholders. Under a 1995 industry-wide ruling of the DTE, the Company will be required in its next base rate filing either to present an alternative incentive-based method of pricing or to justify continuation of the traditional cost-of-service/rate-of-return method. On the same July 18, 1997 date that the DTE issued its directive to the Massachusetts investor-owned gas utilities to collaborate on unbundling their services, the DTE issued its order declining to approve the Company's proposed joint venture with Cabot LNG Corporation. The proposed joint venture would have combined certain LNG assets and resources of the two companies, including the Company's Tewksbury LNG facility and its LNG trucking company subsidiary, Transgas Inc. The DTE's decision declining to approve the joint venture appeared to be based in large part on its unwillingness to allow a supply asset like the Tewksbury LNG facility to be used as proposed until the issues related to unbundling were resolved. The Company follows the provisions of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71") requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. Future regulatory changes could result in the Company no longer meeting the provisions of SFAS 71 for all or part of its business, thereby requiring the elimination of the financial statement effects of regulation for that portion of its business. COMPETITION As discussed above in "Regulatory Matters", the DTE has directed the Company to unbundle its services so that all customers can have the opportunity to choose their supplier of natural gas. Massachusetts law protects gas utility companies like the Company from competition with respect to the distribution of gas within its franchise areas by providing that, where the gas company exists in active operation, no other person may lay pipe in the public ways without the approval, after notice and hearing, of the municipal authorities and the DTE. If a municipality desires to enter the gas business, it must take certain procedural steps, including a favorable vote by a majority of the voters in a city election or two-thirds vote at each of two town meetings. In addition, the municipality must purchase the property of any gas company operating in the municipality (if the company elects to sell) to the extent, and at such prices, as may be agreed upon; if no agreement is reached, resolution will be determined by the DTE. In addition, although FERC orders have generally permitted larger industrial users to obtain piped gas from other sources and by-pass a utility's distribution system, the Company has not seen nor does it believe that these FERC orders will have a material adverse effect on its business, in part because large industrial users are not a significant part of its customer base. Fuel oil suppliers, electric utilities and propane suppliers provide competition generally for residential, commercial and industrial customers. Interruptible gas service is generally in competition with No. 6 fuel oil which most of the interruptible customers are equipped to use. Lower prices of oil and other fuels may adversely affect the Company's ability to retain or attract customers. The Company's rates for bundled gas service have remained generally competitive with the price of alternative fuels, but the long-term impact of changes in fuel prices and changes in state regulatory policies on the Company and its rates cannot be predicted. ENVIRONMENTAL MATTERS The Company is subject to Federal and state laws and regulations dealing with environmental protection. Compliance with such environmental laws and regulations has resulted in increased costs with respect to the Company's existing operations. Working with the Massachusetts Department of Environmental Protection, the Company is engaged in site assessments and evaluation of remedial options for contamination that has been attributed to the Company's former gas manufacturing site and at various related disposal sites. During 1990, the DTE ruled that Colonial and eight other Massachusetts gas distribution companies can recover environmental response costs related to former gas manufacturing operations over a seven-year period, without carrying costs, through the CGAC. Through December 31, 1997, the Company had incurred environmental response costs of $11,875,000 of which $8,042,000 has been recovered from customers to date. As of December 31, 1997, the Company has recorded on the balance sheet a long-term liability of $707,000 and, based upon rate recovery, has recorded a corresponding regulatory asset. This amount represents estimated future response costs for these sites based on the Company's preferred methods of remediation. Actual environmental response costs to be incurred depends on various factors, and therefore future costs may differ from the amount currently recorded as a liability. TRANSGAS INC. Transgas primarily provides over-the-road transportation of liquefied natural gas, propane and other commodities. In 1997, Transgas provided such service to approximately 25 commercial and gas utility customers located in the eastern half of the United States. Transgas also provides a highly specialized LNG portable pipeline service, which permits gas utilities to provide a continuous supply of natural gas to communities when pipeline gas is interrupted for scheduled or emergency shutdowns or when supplemental supplies are required during periods of peak winter demand. Transgas is subject to various federal and state regulations applicable to motor carriers of hazardous materials. Transgas had revenues of $5,529,000 in 1997. Approximately 72% of Transgas' revenue in 1997 was derived from transporting LNG from Distrigas of Massachusetts Corporation's import terminal, located in Everett, Massachusetts. Transgas' revenues decreased $5,502,000 or 50% compared to 1996 due primarily to the warmer than normal weather in the first quarter of 1997 which generated a significant decrease in demand for the truck transportation of LNG throughout the year. Transgas provides over-the-road transportation services by utilizing a fleet of 41 tractors. Transgas owns 53 trailers which are specifically designed for the transportation of LNG and other cryogenic liquids. Transgas also leases 16 LNG trailers. In addition, Transgas owns 5 trailers which are designed for the transportation of propane. Transgas also leases 6 LPG trailers. In addition to the equipment described above, Transgas also has 14 portable LNG vaporizer trailers, as well as 2 flat bed trailers and 2 van trailers. Transgas competes with other motor carriers engaged in the transportation of various gases and other products. Transgas believes, however, that it is the leading over-the-road transporter of LNG due to the size of its specialized LNG trailer fleet and the number of LNG loads it delivers annually. As discussed above in "Regulatory Matters", the Company's proposed joint venture with Cabot LNG Corporation, which would have included the sale to Cabot LNG Corporation of a 50% interest in Transgas, was not approved by the DTE. Accordingly, the proposed joint venture has terminated and the Company has no present plans to sell any of its interest in Transgas. Item 1A. Executive Officers of the Registrant. The following table indicates the present executive officers of the Company, their ages, the dates when their service with the Company began and their respective positions with the Company. Affiliated with Name and Age Position with Company Company Since Frederic L. Putnam, Jr. Chairman and (73) Senior Executive Officer 1953 Frederic L. Putnam, III (52) President and Chief Executive Officer 1975 Charles W. Sawyer Executive Vice President (52) and Chief Operating Officer 1976 Nickolas Stavropoulos Executive Vice President (40) - Finance, Marketing, and Chief Financial Officer 1979 John P. Harrington (55) Senior Vice President - Gas Supply and Assistant to the President 1966 Victor W. Baur (54) President - Transgas Inc. 1972 Dennis W. Carroll (51) Vice President and Treasurer 1990 Mr. Putnam, Jr. has been Chairman of the Board of Directors since 1981 and the Senior Executive Officer since February 1995 and before that the Chief Executive Officer since 1977. He has also been a Director since 1973. Mr. Putnam, III, the son of F.L. Putnam, Jr., has been President and Chief Executive Officer since February 1995. He had been President since May 1994, Executive Vice President and General Manager from April 1993 until May 1994 and before that Vice President and General Manager from August 1989 until April 1993. He has also been a Director since November 1991. Mr. Sawyer has been Executive Vice President and Chief Operating Officer since February 1995. He had been Vice President - - Operations since August 1989. Mr. Stavropoulos has been Executive Vice President - Finance, Marketing and Chief Financial Officer since February 1995. He had been Vice President - Finance and Chief Financial Officer since August 1989. He has also been a Director since February 1993. Mr. Harrington has been Senior Vice President - Gas Supply and Assistant to the President since February 1995. He had been Vice President - Gas Supply since August 1989. He has also been a Director since February 1993. Mr. Baur has been President of Transgas Inc. since July 1990. He also became a Director in August 1993. Mr. Carroll has been Vice President and Treasurer since August 1990. These officers hold office until the next annual meeting of the Board of Directors or until their successors are duly elected and qualified, subject to earlier removal. Item 2. Properties. The Company has two principal operations centers and a natural gas storage facility with approximately 1,000,000 Mcf of LNG storage capacity located in Tewksbury, Massachusetts. In general, the Company's gas production and storage facilities, metering and regulation stations and operations centers, including the Tewksbury LNG facility, are located on land it owns. A 175,000 Mcf LNG storage tank located on land owned by the Company in South Yarmouth, Massachusetts is leased from an unaffiliated company under a lease whose term is scheduled to expire in August, 1998. The Company has begun discussions with the lessor on the future use of this LNG storage tank. The Company also has a lease which expires in 2002 for office facilities in Lowell, Massachusetts. The Company's distribution mains of approximately 3,040 miles are located within public highways under franchises or permits from state or municipal authorities, or on land owned by others under easements or licenses from the owners. The Company's first mortgage bonds are collateralized by utility property. Management considers that the Company's properties are adequate for the conduct of its business for the reasonably foreseeable future. Item 3. Legal Proceedings. See Item 1, "Business--Environmental Matters" above, which is incorporated herein. Item 4. Submission of Matters to a Vote of Security Holders. No matter was submitted to a vote of the Company's security holders during the quarter ended December 31, 1997. PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's 1997 annual report to stockholders under the caption "Shareholder Information" and under Note C of the "Notes to Consolidated Financial Statements". Item 6. Selected Financial Data. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's 1997 annual report to stockholders under the caption "Selected Financial Data". Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's 1997 annual report to stockholders under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations". Item 8. Financial Statements and Supplementary Data. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's 1997 annual report to stockholders under the following captions: "Consolidated Statements of Income", "Consolidated Balance Sheets", "Consolidated Statements of Cash Flows", "Consolidated Statements of Common Equity", "Notes to Consolidated Financial Statements", "Report of Independent Certified Public Accountants" and "Shareholder Information". Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. PART III Item 10. Directors and Executive Officers of the Registrant. The information required to be reported hereunder pursuant to Item 401 of Regulation S-K for the Company's Directors is incorporated by reference to the information reported in the Company's Proxy Statement/Prospectus for its 1998 annual meeting of stockholders under the caption "INFORMATION ABOUT NOMINEES AND INCUMBENT DIRECTORS". The information required to be reported hereunder pursuant to Item 401 of Regulation S-K for the Executive Officers of the Registrant is incorporated by reference to the information in Item 1A of this Form 10-K under the caption "Executive Officers of the Registrant". The information required to be reported hereunder pursuant to Item 405 of Regulation S-K is incorporated by reference to the information reported in the Company's Proxy Statement/Prospectus for its 1998 annual meeting of stockholders under the caption "SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE." Item 11. Executive Compensation. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's Proxy Statement/Prospectus for its 1998 annual meeting of stockholders under the caption "EXECUTIVE COMPENSATION" and under the subheading "Directors' Compensation" of the caption "INFORMATION ABOUT NOMINEES AND INCUMBENT DIRECTORS". Item 12. Security Ownership of Certain Beneficial Owners and Management. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's Proxy Statement/Prospectus for its 1998 annual meeting of stockholders under the caption "SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT". Item 13. Certain Relationships and Related Transactions. The information required to be reported hereunder is incorporated by reference to the information reported in the Company's Proxy Statement/Prospectus for its 1998 annual meeting of stockholders under the caption "INFORMATION ABOUT NOMINEES AND INCUMBENT DIRECTORS". PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) 1. Financial Statements The Consolidated Financial Statements of the Company (including the Report of Independent Certified Public Accountants) required to be reported herein are incorporated by reference to the information reported in the Company's 1997 annual report to stockholders under the following captions: "Consolidated Statements of Income", "Consolidated Balance Sheets", "Consolidated Statements of Cash Flows", "Consolidated Statements of Common Equity", "Notes to Consolidated Financial Statements" and "Report of Independent Certified Public Accountants". 2. Financial Statement Schedules The following Financial Statement Schedule and report thereon are filed as part of this Form 10-K on the pages indicated below: Schedule Page Number Description Number Report of Independent Certified Public Accountants on Schedule II Valuation and Qualifying Accounts for the three years ended December 31, 1997 Schedules other than those listed above are either not required or not applicable, or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules filed have been omitted because the information is not applicable. 3. List of Exhibits Exhibit Number Exhibit Reference 3a Restated Articles of Organization of Incorporated herein Colonial Gas Company, dated April by reference. 19, 1989, as amended on July 16, 1992 and supplemented by a certificate of vote of Directors establishing a series of a class of stock filed on November 30, 1993, filed as Exhibit 3(a) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1993. 3b By-Laws of Colonial Gas Company, as Incorporated herein amended to date, filed as Exhibit by reference. 3(b) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1996. 4a Second Amended and Restated First Incorporated herein Mortgage Indenture, dated as of June by reference. 1, 1992, filed as Exhibit 4(b) to Form 10-Q of the Registrant for the quarter ended June 30, 1992. 4b First Supplemental Indenture, dated Incorporated herein as of June 15, 1992, filed as by reference. Exhibit 4(c) to Form 10-Q of the Registrant for the quarter ended June 30, 1992. 4c Form of Rights Agreement, dated as Incorporated herein of December 1, 1993, between the by reference. registrant and BankBoston, N.A. (f/k/a/ The First National Bank of Boston), as Rights Agent, together with the following exhibits thereto: (i) Form of Vote Establishing the Series A-1 Junior Participating Preferred Stock, (ii) Form of Rights Certificate, and (iii) Summary of Rights to Purchase Preferred Shares. Filed as Exhibit 1 to the Company's Registration Statement on Form 8-A filed on November 22, 1993 (File No. 0-10007). 4d Second Supplemental Indenture, Incorporated herein executed on September 27, 1995, by reference. relating to the Secured Medium Term Notes, Series A, filed as Exhibit 4(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1995. 4e Amendment to Second Supplemental Incorporated herein Indenture, dated as of October 12, by reference. 1995, relating to the Secured Medium Term Notes, Series A, filed as Exhibit 4(d) to the Registrant's Form 10-K for the fiscal year ended December 31, 1995. 4f Third Supplemental Indenture, dated Incorporated herein as of December 15, 1995 to Second by reference. Amended and Restated First Mortgage Indenture. 4g Revolving Credit Agreement for Incorporated herein Colonial Gas Company, dated as of by reference. September 12, 1997, filed as Exhibit 4(e) to Form 10-Q of the Registrant for the quarter ended September 30, 1997. 4h Revolving Credit Agreement for Incorporated herein Massachusetts Fuel Inventory Trust, by reference. dated as of September 12, 1997, filed as Exhibit 4(f) to Form 10-Q of the Registrant for the quarter ended September 30, 1997. 4i Purchase Contract, dated as of June Incorporated herein 27, 1990 between Massachusetts Fuel by reference. Inventory Trust acting by and through its Trustee, Shawmut Bank, N.A. and Colonial Gas Company, filed as Exhibit 10(e) to Form 8-K of the Registrant for quarter ended June 30, 1990. 4j Security Agreement and Assignment of Incorporated herein Contracts, dated as of September 12, by reference. 1997 made by Massachusetts Fuel Inventory Trust in favor of Fleet National Bank as Agent for designated banks, filed as Exhibit 4(h) to Form 10-Q of the Registrant for the quarter ended September 30, 1997. 4k Trust Agreement, dated as of June Incorporated herein 22, 1990 between Colonial Gas by reference. Company (as Trustor) and Shawmut Bank, N.A. (as Trustee), filed as Exhibit 10(d) to Form 8-K of the Registrant for quarter ended June 30, 1990. 10a Lease Agreement, dated as of May 1, Incorporated herein 1982, with Olde Market House by reference. Associates of Lowell, filed as Exhibit 10(y) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1982. 10b Lease of Equipment from The National Incorporated herein Shawmut Bank of Boston (now State by reference. Street Bank and Trust Company, successor) as Trustee, as Lessor dated as of May 1, 1973, filed as Exhibit 13(c) to Colonial Gas Energy System's Registration Statement on Form S-1. Commission File No. 2- 54673. 10c Form Employment Agreement for Incorporated herein corporate officers, filed as Exhibit by reference. 10(kk) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1992. 10d Rate increase deferral incentive Incorporated herein policy, dated January 1, 1995, filed by reference. as Exhibit 10(xx) to the Registrant's Annual Report on Form 10-K for the fiscal year ended December 31, 1994. 10e 1997 Transitional Executive Filed herewith as Incentive Plan. Exhibit 10e. 10f Executive Performance and Equity Incorporated herein Incentive Plan included as Appendix by reference. A to the Proxy Statement/Prospectus portion of Colonial Energy's Registration Statement on Form S-4 filed on March 6, 1998. Commission File No. 333-47441. 13a Those portions of the 1997 Annual Filed herewith as Report to Stockholders which have Exhibit 13a. been incorporated by reference in Part II Items 5 - 8 and Part IV Item 14 part a 1. 21a Subsidiaries of the Registrant. Filed herewith as Exhibit 21a. 23a Consent of Independent Certified Filed herewith as Public Accountants. Exhibit 23a. ____________________ EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS Exhibits 10c, 10d, 10e, and 10f above are management contracts or compensatory plans or arrangements in which the executive officers of the Company participate. (b) Reports on Form 8-K. None REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS ON SCHEDULE To the Shareholders of Colonial Gas Company In connection with our audit of the consolidated financial statements of Colonial Gas Company and subsidiaries referred to in our report dated January 14, 1998, which is included in the 1997 Annual Report to Stockholders and incorporated by reference in Part II of this Form 10-K, we have also audited the schedule listed at Part IV, Item 14(a)2. In our opinion, this schedule presents fairly, in all material respects, the information required to be set forth therein. GRANT THORNTON LLP Boston, Massachusetts January 14, 1998 SCHEDULE II COLONIAL GAS COMPANY AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS For the Three Years Ended December 31, 1997 (In Thousands) COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS CHARGED BALANCE AT BALANCE AT TO COSTS AT BEGINNING AND END OF DESCRIPTION OF PERIOD EXPENSES DEDUCTIONS PERIOD For the Year Ended December 31, 1997 Reserve for $2,715 $1,956 $1,468 (1) $3,203 uncollectible accounts Reserve for insurance $ 742 $ 506 $ 400 $ 848 claims For the Year Ended December 31, 1996 Reserve for $2,205 $2,127 $1,617 (1) $2,715 uncollectible accounts Reserve for insurance $ 634 $510 $ 402 $742 claims For the Year Ended December 31, 1995 Reserve for $1,670 $1,821 $1,286 (1) $2,205 uncollectible accounts Reserve for insurance $ 527 $431 $ 324 $634 claims (1) Accounts charged off, net of collections. SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities 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 Date By s/F.L. Putnam , Jr. March 12, 1998 F.L. Putnam, Jr., Chairman of the Board of Directors 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 and on the dates indicated. Signature Title Date s/F.L. Putnam, Jr. Senior Executive Officer, March 12, 1998 F.L. Putnam, Jr. Director s/Nickolas Stavropoulos Executive Vice President - March 12, 1998 Nickolas Stavropoulos Finance, Marketing and Chief Financial Officer, Director (Principal Financial Officer) s/D.W. Carroll Vice President and D.W. Carroll Treasurer (Principal March 12, 1998 Accounting Officer) s/V.W. Baur Director March 12, 1998 V.W. Baur s/J.P. Harrington Director March 12, 1998 J.P. Harrington s/H.C. Homeyer Director March 12, 1998 H.C. Homeyer s/R.L. Hull Director March 12, 1998 R.L. Hull s/R. A. Perkins Director March 12, 1998 R. A. Perkins s/F.L. Putnam, III President and Chief March 12, 1998 F.L. Putnam, III Executive Officer, Director s/J.F. Reilly, Jr. Director March 12, 1998 J.F. Reilly, Jr. s/A.B. Sides, Jr. Director March 12, 1998 A.B. Sides, Jr. s/M.M. Stapleton Director March 12, 1998 M.M. Stapleton s/C.O. Swanson Director March 12, 1998 C.O. Swanson EX-10 2 EXHIBIT 10E [EXHIBIT 10e TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1997] 1997 TRANSITIONAL EXECUTIVE INCENTIVE PLAN Colonial Gas Company (the "Company") has adopted a variable pay executive incentive plan (the "Transition Plan") effective for calendar year 1997 as a means of transitioning to the proposed Executive Performance and Equity Incentive Plan. Eligible Company executives under the Transition Plan are those holding positions of Vice President and above during 1997. With respect to such eligible executives, the Transition Plan replaces and supersedes the Company's rate increase deferral incentive policy (the "Rate Case Deferral Plan") which was effective from 1995 through 1997. The awards received by such executives under the Rate Case Deferral Plan for 1997 shall be deducted from the amounts to which they may be entitled under the Transition Plan. The Transition Plan provides eligible executives with cash incentive awards (stated as a percentage of base salary) based upon the following three factors relating to the Company's 1997 performance: 1. 1997 return on equity as compared to the Edward D. Jones natural gas distribution company index. This factor represents 31.25% of the incentive as follows: Award Potential Threshold - Colonial ranks in top 50% Target - Colonial ranks in top 25% Maximum - Colonial ranks in top 10% Award % Factor Incentive % Threshold 12.50% 31.25% 3.91% Target 25.00% 31.25% 7.81% Maximum 50.00% 31.25% 15.63% 2. 1997 Operations and Maintenance Expense per customer as compared to other New England natural gas distribution companies. This factor represents 43.75% of the incentive, as follows: Award Potential Threshold - Colonial ranks in top 25% Target - Colonial ranks in top 15% Maximum - Colonial ranks as number 1 Award % Factor Incentive % Threshold 12.50% 43.75% 5.47% Target 25.00% 43.75% 10.94% Maximum 50.00% 43.75% 21.88% 3. 1997 total shareholder return as compared to the Edward D. Jones natural gas distribution company index. This factor represents 25% of the incentive, as follows: Award Potential Threshold - Colonial ranks in top 50% Target - Colonial ranks in top 35% Maximum - Colonial ranks in top 25% Award % Factor Incentive % Threshold 12.50% 25.00% 3.13% Target 25.00% 25.00% 6.25% Maximum 50.00% 25.00% 12.50% Notwithstanding the above, no incentive award under the Transition Plan shall exceed 20% of the 1997 base salary of the applicable participant. As stated above, any incentive award under the Transition Plan will be net of the award paid in 1997 to the participant under the Rate Case Deferral Plan. [END OF EXHIBIT 10e TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1997] EX-13 3 EXHIBIT 13A [EXHIBIT 13a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1997] CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Share Amounts) Year Ended December 31, 1997 1996 1995 Operating Revenues $187,140 $169,878 $163,668 Cost of gas sold 102,455 87,188 83,631 Operating Margin 84,685 82,690 80,037 Operating Expenses: Operations 30,044 30,372 30,410 Maintenance 4,503 4,476 4,401 Depreciation and amortization 12,049 11,228 10,225 Local property taxes 3,139 3,189 3,020 Other taxes 2,122 2,183 2,130 Total Operating Expenses 51,857 51,448 50,186 Income Taxes: Federal income tax 8,264 7,001 6,879 State franchise tax 1,708 2,087 1,447 Total Income Taxes 9,972 9,088 8,326 Utility Operating Income 22,856 22,154 21,525 Other Operating Income (Expense): Energy Trucking revenues 5,529 11,031 7,576 Energy Trucking expenses, including income taxes and interest (5,202) (9,005) (6,972) Energy Trucking Net Income 327 2,026 604 Other, net of income taxes 318 250 41 Total Other Operating Income 645 2,276 645 Non-Operating Income, Net of Income Taxes 573 757 864 Income Before Interest and Debt Expense 24,074 25,187 23,034 Interest and Debt Expense 8,034 8,709 9,270 Net Income $16,040 $16,478 $13,764 Average Common Shares Outstanding 8,598 8,432 8,294 Income per Average Common Share $1.87 $1.95 $1.66 The accompanying notes are an integral part of these statements. CONSOLIDATED BALANCE SHEETS Assets December 31, (In Thousands) 1997 1996 Utility Property: At original cost $362,742 $333,319 Accumulated depreciation (88,210) (82,336) Net Utility Property 274,532 250,983 Non-Utility Property - Net 7,312 5,925 Net Property 281,844 256,908 Capital Leases - Net 2,630 1,811 Current Assets: Cash and cash equivalents 259 3,541 Accounts receivable 21,788 17,719 Allowance for doubtful accounts (3,203) (2,715) Accrued utility revenues 7,417 6,333 Unbilled gas costs 19,266 19,238 Fuel inventory - at average cost 12,959 11,958 Materials and supplies - at average cost 2,950 2,891 Prepayments and other current assets 6,531 8,593 Total Current Assets 67,967 67,558 Deferred Charges and Other Assets: Unrecovered deferred income taxes 9,014 9,774 Unrecovered demand side management costs 8,273 7,075 Unrecovered environmental costs incurred 3,833 4,011 Unrecovered environmental costs accrued 707 1,183 Unrecovered pension costs 3,455 3,135 Unrecovered transition costs accrued 2,800 4,500 Excess cost of investments over net assets acquired 2,798 2,798 Other 5,670 5,659 Total Deferred Charges and Other Assets 36,550 38,135 Total Assets $388,991 $364,412 CONSOLIDATED BALANCE SHEETS Capitalization and Liabilities December 31, (In Thousands) 1997 1996 Capitalization: Common Equity: Common Stock $ 28,932 $28,366 Premium on Common Stock 57,277 54,221 Retained earnings 35,923 31,319 Total Common Equity 122,132 113,906 Long-Term Debt 100,102 95,266 Total Capitalization 222,234 209,172 Capital Lease Obligations 1,617 930 Current Liabilities: Current maturities of long-term debt 10,164 5,152 Current capital lease obligations 1,013 881 Notes payable 49,400 50,400 Gas inventory purchase obligations 14,895 13,039 Accounts payable 15,674 14,544 Accrued interest 2,375 1,815 Current deferred income taxes 3,654 5,090 Other current liabilities 5,333 3,248 Total Current Liabilities 102,508 94,169 Deferred Credits and Reserves: Deferred income taxes - Funded 41,443 35,886 Deferred income taxes - Unfunded 9,014 9,774 Accrued environmental costs 707 1,183 Accrued transition costs 2,800 4,500 Unamortized investment tax credits 3,372 3,672 Pension reserve 4,507 4,174 Other deferred credits and reserves 789 952 Total Deferred Credits and Reserves 62,632 60,141 Total Capitalization and Liabilities $388,991 $364,412 The accompanying notes are an integral part of these statements. CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, (In Thousands) 1997 1996 1995 Cash Flows From Operating Activities: Net Income $16,040 $16,478 $13,764 Adjustments to reconcile net income to net cash: Depreciation and amortization 13,334 12,361 11,211 Deferred income taxes 3,208 7,968 1,159 Amortization of investment tax credits (300) (268) (275) Provision for uncollectible accounts 1,955 2,146 1,829 Other, net 109 171 973 34,346 38,856 28,661 Changes in current assets and liabilities: Accounts receivable and accrued utility revenues (6,620) 2,305 (9,293) Unbilled gas costs (28) (9,550) 2,490 Fuel inventory (1,001) (1,442) 2,443 Prepayments and other current assets 2,003 (4,015) 5,612 Accounts payable 1,130 2,394 2,515 Other current liabilities 2,645 (2,929) (920) Net Cash Provided by Operating Activities 32,475 25,619 31,508 Cash Flows From Investing Activities: Utility capital expenditures (35,788) (26,875) (24,096) Non-utility capital expenditures (1,888) (1,367) (1,974) Change in deferred accounts (842) (1,502) (2,077) Net Cash Used in Investing Activities (38,518) (29,744) (28,147) Cash Flows From Financing Activities: Dividends paid on Common Stock (11,435) (10,919) (10,571) Issuance of Common Stock 3,622 3,277 2,702 Issuance of long-term debt, net of issuance costs 14,870 29,787 19,685 Retirement of long-term debt, including premiums (5,152) (11,284) (27,477) Change in notes payable (1,000) (11,435) 12,335 Change in gas inventory purchase obligations 1,856 699 (1,520) Net Cash Provided by (Used in) Financing Activities 2,761 125 (4,846) Net Decrease in Cash and Cash Equivalents (3,282) (4,000) (1,485) Cash and Cash Equivalents at Beginning of Year 3,541 7,541 9,026 Cash and Cash Equivalents at End of Year $ 259 $ 3,541 $ 7,541 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest - net of amount capitalized $ 9,465 $9,149 $ 9,867 Income and state franchise taxes $ 7,509 $8,489 $ 3,444 The accompanying notes are an integral part of these statements. CONSOLIDATED STATEMENTS OF COMMON EQUITY Year ended December 31, (In Thousands Except Per Share Amounts) 1997 1996 1995 Common Stock $3.33 par value; authorized 15,000 shares; outstanding, 8,688 in 1997, 8,518 in 1996, and 8,367 in 1995 Beginning of year $28,366 $27,863 $27,397 Issuance of Common Stock through Dividend Reinvestment and Common Stock Purchase Plan and Employee savings plan (170 shares in 1997, 151 shares in 1996 and 140 shares in 1995) 566 503 466 End of year $28,932 $28,366 $27,863 Premium on Common Stock Beginning of year $54,221 $51,447 $49,211 Issuance of Common Stock through Dividend Reinvestment and Common Stock Purchase Plan and Employee savings plan 3,056 2,774 2,236 End of year $57,277 $54,221 $51,447 Retained Earnings Beginning of year $31,319 $25,760 $22,567 Net income 16,040 16,478 13,764 Cash dividends on Common Stock ($1.33 a share in 1997, $1.295 a share in 1996 and $1.275 a share in 1995) (11,435) (10,919) (10,571) End of year $35,923 $31,319 $25,760 Total Common Equity $122,132 $113,906 $105,070 The accompanying notes are an integral part of these statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note A: Summary of Significant Accounting Policies Nature of Operations - Colonial Gas Company, a Massachusetts corporation formed in 1849, is primarily a regulated natural gas distribution utility. The Company serves over 151,000 utility customers in 24 municipalities located northwest of Boston and on Cape Cod. Through its subsidiary, Transgas Inc., the Company also provides over-the-road transportation of liquefied natural gas, propane, and other commodities. Principles of Consolidation - The consolidated financial statements include the accounts of the Company and its subsidiaries. All material intercompany items have been eliminated in consolidation. Use of Estimates - 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. Utility Regulation - The Company's utility operations are subject to regulation by the Massachusetts Department of Telecommunications & Energy ("DTE"), formerly known as the Massachusetts Department of Public Utilities, with respect to rates charged for natural gas sales and transportation, among other things. The Company's policies conform with generally accepted accounting principles, as applied to regulated public utilities. Utility Property and Non-Utility Property - Utility property and non-utility property are stated at original cost, including labor, materials, taxes and overheads. The amount of interest capitalized as a component of construction overheads amounted to $594,000, $437,000, and $568,000 in 1997, 1996 and 1995, respectively. The original cost of depreciable utility property retired, together with the cost of removal, net of salvage, is charged to accumulated depreciation. Depreciation applicable to the Company's utility property in service is calculated in accordance with depreciation rates as approved by the DTE. A composite depreciation rate of approximately 3.8% is applied to the utility property balance at the beginning of each year. Depreciation on non-utility property is computed by various methods. Operating Revenues - Operating revenues are accrued based upon the amount of gas delivered to utility customers through the end of the accounting period. Accrued utility revenues of $7,417,000 and $6,333,000, as reported in the Consolidated Balance Sheets at December 31, 1997 and 1996, respectively, represent the accrual of unbilled operating revenues net of related gas costs. The Company's policy is to record lost margins and financial incentives relating to the Company's demand side management ("DSM") programs as revenue when earned by the Company and approved by the DTE. Unbilled Gas Costs - The Company charges or credits its utility customers for increases or decreases in gas costs from those reflected in its base tariffs by applying a cost of gas adjustment clause ("CGAC"). In accordance with the CGAC, any under or over recoveries of gas costs are charged or credited to the unbilled gas cost account and recorded as a current asset or liability. Such under or over recoveries are collected or refunded, with interest accrued at the prime rate, in subsequent periods. Pipeline Refunds Due Customers - The Company periodically receives refunds from interstate pipeline companies related to rate adjustments ordered by the Federal Energy Regulatory Commission ("FERC"). Refunds are returned to utility customers under methods approved by the DTE. Excess Cost of Investments over Net Assets Acquired - This asset arose principally from the pre-1971 acquisitions of utility operations. No amortization has been provided since, in the opinion of management, there has been no diminution in value of the applicable investments. Income Taxes - The Company records deferred income taxes for the income tax effect of the difference between book and tax depreciation and all other temporary book and tax differences, in accordance with Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" ("SFAS 109"). Unamortized investment tax credits, which were allowed under Federal income tax laws prior to 1987, have been deferred and are being amortized as a credit to income tax expense over the estimated service lives of the corresponding assets. Interest and Debt Expense - Interest and debt expense includes interest on long-term debt, interest on short-term notes payable and regulatory interest. As approved by the DTE, regulatory interest is interest income credited on regulatory assets or interest expense charged on regulatory liabilities. Pension Plans - The Company and its subsidiaries have 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 Company's funding policy for the qualified plans is to contribute annually an amount at least equal to the normal cost plus a 30- year amortization of the unfunded actuarially calculated accrued liability. Cash and Cash Equivalents - For the purposes of the Consolidated Balance Sheets and Statements of Cash Flows, the Company considers cash investments with an original maturity of three months or less to be cash equivalents. Fair Value of Financial Instruments - In accordance with Statement of Financial Accounting Standards No. 107 "Disclosures About Fair Values of Financial Instruments", the fair value amounts are disclosed below. These fair value amounts are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The carrying amount of cash and cash equivalents and short- term debt approximates fair value. The fair value of long-term debt is estimated based on the rates available to the Company at the end of each respective year for debt of the same remaining maturities. The carrying amount of long-term debt (including current maturities) was $110,266,000 and $100,418,000 as of December 31, 1997 and 1996, respectively. The fair value of long-term debt was $115,700,000 and $102,000,000 as of December 31, 1997 and 1996, respectively. Under current regulatory treatment, any premiums paid to refinance long-term debt, would be recovered over the life of the new debt, and would not have a significant impact on the Company's results of operations. Impairment of Long-Lived Assets - During 1996, the Company adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". This statement requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The adoption of this standard did not have a material impact on the Company's financial condition or results of operations. Reclassifications - Reclassifications are made periodically to previously issued financial statements to conform to the current year presentation. Note B: Federal Income Tax The Company records deferred income taxes for the income tax effect of the difference between book and tax depreciation and all other temporary book and tax differences, in accordance with SFAS 109. Prior to October 1981 as approved by the DTE, the Company did not record deferred income taxes but rather "flowed through" tax benefits to utility customers. At December 31, 1997, the Company has a liability of $9,014,000 on the Consolidated Balance Sheet as Deferred Income Taxes - Unfunded and a corresponding unrecovered deferred asset. The liability represents the tax effect of pre- 1981 timing differences for which deferred income taxes had not been provided and was increased in accordance with SFAS 109 for the tax effect of future revenue requirements. The Company is recovering these unfunded deferred taxes from utility customers over the remaining book life of utility property. Federal income tax expense is comprised of the following components: Year Ended December 31, (In Thousands) 1997 1996 1995 Charged (credited) to operations: Current $5,188 $1,104 $6,422 Deferred: Accelerated depreciation 1,688 2,202 2,005 Unbilled gas costs (98) 2,929 (1,523) Demand side management costs 88 747 (32) Pension costs 301 449 (38) Recovery of unfunded deferred taxes 398 398 398 Debt expense (53 (53) 848 Transition costs -- (1) (871) Environmental Response Costs (58) (246) 22 Bad debt 889 (167) (175) Miscellaneous 221 (93) 96 Amortization of investment tax credits (300) (268) 273 Total 8,264 7,001 6,879 Charged to other income 312 1,599 510 Total Federal income tax expense $8,576 $8,600 $7,389 The effective Federal income tax rate and the reasons for the difference from the statutory Federal income tax rate are as follows: 1997 1996 1995 Statutory Federal income tax rate 35% 35% 35% Increases (reductions) in taxes resulting from: Amortization of investment tax credits (1) (1) (1) Recovery of unfunded deferred taxes 2 2 2 Miscellaneous items (1) (2) (1) Effective Federal income tax rate 35% 34% 35% Temporary differences which gave rise to the following deferred tax assets (liabilities) are: December 31, (In Thousands) 1997 1996 Deferred Tax Assets: Construction contributions $ 891 $ 974 Other 227 335 Total deferred tax assets 1,118 1,309 Deferred Tax Liabilities: Accelerated depreciation (41,345) (39,580) Unbilled gas costs (3,654) (3,990) Demand side management costs (2,765) (2,659) Environmental response costs (1,502) (1,571) Cost of removal (3,033) (2,792) Other (2,930) (1,467) Total deferred tax liabilities (55,229) (52,059) Total deferred taxes $(54,111) $(50,750) Note C: Capital Stock Pursuant to the Company's dividend reinvestment and common stock purchase plan, shareholders can automatically reinvest their cash dividends and can invest optional limited amounts of cash payments in newly issued shares. The Company has authorized and unissued 547,559 shares of Class A Preferred Stock, $25 par value, of which 100,000 shares have been designated a Junior Preferred Stock series and reserved for issuance under the Rights Plan described below, and 370,000 shares of Class B Preferred Stock, $1 par value. A Shareholder Rights Plan provides one right ("Right") to purchase one one-hundredth of a share of the Company's Series A-1 Junior Participating Preferred Stock, par value $25 per share, at a price of $60 per share, subject to adjustment. The Rights expire on December 1, 2003 and only become exercisable, or separately transferable, 10 days after a person or group acquires, or announces an intention to acquire, beneficial ownership of 20% or more of the Company's Common Stock. The Rights are redeemable by the Board at a price of $.01 per Right at any time prior to the expiration of ten days after the acquisition by a person or group of beneficial ownership of 20% or more of the Company's Common Stock. Note D: Long-Term Debt The composition of long-term debt is as follows: Maturity Put December 31, (In Thousands) Date Date 1997 1996 First mortgage bonds: 9.40% Series CE due 1997 $ - $ 5,000 8.05% Series CG due 1999 20,000 20,000 8.80% Series CH due 2022 25,000 25,000 6.85% Series MTA-1 due 2025 2005 10,000 10,000 6.45% Series MTA-2 due 2025 2005 10,000 10,000 6.94% Series MTA-3 due 2026 10,000 10,000 6.20% Series MTA-4 due 1998 10,000 10,000 6.88% Series MTA-5 due 2008 10,000 10,000 6.81% Series MTA-6 due 2027 2002 15,000 0 Total 110,000 100,000 Note payable 266 418 Less: Long-term debt due within one year (10,164) (5,152) Total long-term debt $100,102 $95,266 The aggregate amount of maturities for the years 1998 through 2002 are $10,164,000 in 1998, and $20,102,000 in 1999. Bonds of $15,000,000 due in 2027 can be redeemed by the holder in 2002. 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. The note payable is collateralized by equipment. The Company has a medium term note ("MTN") program which permits the issuance of up to $75 million of MTN's as bonds under its indenture of which $65 million has been issued as of December 1997. The bonds with a put date noted above can be redeemed by the holder within a 30 day period in the year indicated. Interest Rate Instruments: - The Company has entered into treasury rate locks in order to hedge the interest rate on long- term debt anticipated to be issued in early 1998. The treasury rate locks are for $10 million at a 10 year treasury rate of 5.88% and for $20 million at a 15 year treasury rate of 5.88%. Upon issuance of the debt, any gain or loss realized on the treasury rate locks will be amortized to interest expense over the term of the related debt. Note E: Short-Term Debt In September 1997, the Company established a three-year bank line of credit of $75 million with a consortium of five banks. The bank line of credit allows the Company to borrow on a demand basis up to $75 million, less whatever amount has been borrowed through the Company's gas inventory trust (described below). The line of credit allows the Company the option to borrow under three alternative rates: based on eurodollar rate (LIBOR), prime rate, or a competitive bid option. At December 31, 1997, the credit available under the bank line of credit was $10,705,000. The weighted average interest rates for short-term debt were 6.18% and 5.87% at December 31, 1997 and 1996, respectively. The Company has an agreement with a single-purpose Massachusetts trust, the Company's gas inventory trust, under which the Company sells supplemental gas inventory to the trust at the Company's cost. The Company's agreement with the trust requires it to repurchase such inventory at cost when needed and reimburse the trust for expenses incurred to finance the gas inventory. The trust finances such purchases of inventory by borrowing under a bank line of credit with a maximum borrowing commitment of $30 million that is complementary to and on similar terms as the Company's bank line of credit described above. The DTE has approved the inventory trust arrangement and has permitted the cost of such gas inventory, including fees and financing costs, to be recovered through the Company's CGAC. During 1997, 1996 and 1995 approximately $564,000, $500,000 and $662,000, respectively, of interest costs were incurred by the trust. Note F: Lease Obligations The Company leases certain facilities and equipment used in its operations. In accordance with accounting for regulated public utilities, the Company has capitalized certain of these leases and reflects lease payments as rental expense in the periods to which they relate. This capitalization has no impact on the Company's net income. Assets held under capital leases amounted to approximately $7,703,000 and $7,685,000 at December 31, 1997 and 1996, respectively. Accumulated amortization on assets held under capital leases amounted to approximately $5,072,000 and $5,874,000 at December 31, 1997 and 1996, respectively. The most significant agreements which meet the criteria for capital lease classification are a lease which expires in 1998 for a liquefied natural gas storage tank in South Yarmouth, Massachusetts and a lease which expires in 2002 for office facilities in Lowell, Massachusetts. Both leases have fair market renewal options at the end of their initial terms. Total rental expense for the years 1997, 1996 and 1995 approximated $1,527,000, $1,493,000 and $1,429,000, respectively. At December 31, 1997, the future minimum payments (including interest) under the Company's lease agreements are: $1,069,000 in 1998; $749,000 in 1999; $619,000 in 2000; $544,000 in 2001; $201,000 in 2002; and $0 thereafter. Note G: Employee Benefit Plans Savings Plan - The Company sponsors an employee 401(k) Savings Plan. The Company's matching contribution, exclusive of plan administration costs, was $625,000, $570,000 and $459,000 for 1997, 1996 and 1995, respectively. Pension Plans - The Company and its subsidiaries have various defined benefit pension plans covering substantially all employees. Net periodic pension cost is comprised of the following components: Year Ended December 31, (In Thousands) 1997 1996 1995 Benefits earned during the period $1,042 $1,036 $ 836 Interest cost on projected benefit obligation 3,427 3,267 3,279 Actual return on plan assets (6,711) (4,710) (5,515) Net amortization and deferral 3,673 1,882 2,757 Net periodic pension cost $1,431 $1,475 $1,357 Assumptions used in actuarial calculations were as follows: Year Ended December 31, 1997 1996 1995 Weighted average discount rate 7.00% 7.75% 7.50% Future compensation increases 4.00% 4.00% 4.00% Expected long-term rate of return on assets 9.00% 9.00% 9.00% The funded status of the plans at December 31, 1997 and 1996 is as follows: 1997 1996 Assets Accumulated Assets Accumulated Exceed Benefits Exceed Benefits Accumulated Exceed Accumulated Exceed (In Thousands) Benefits Assets Benefits Assets Projected benefit obligations: Vested $(32,420) $(12,020) $(28,612) $(10,381) Nonvested (828) (1,088) (703) (956) Accumulated (33,248) (13,108) (29,315) (11,337) Due to recognition of future salary increases (4,497) (136) (4,248) (116) Total (37,745) (13,244) (33,563) (11,453) Plan assets at fair 38,765 9,567 33,743 7,715 value Projected benefit obligation 1,020 (3,677) 180 (3,738) less than (in excess of) plan assets Unrecognized net (gain) 78 729 (457) 188 loss Unrecognized 1,223 331 1,398 2,020 transition amount Unrecognized prior (60) 2,424 487 1,064 service cost Additional liability accrued - (3,350) - (3,157) Prepaid (accrued) pension costs $2,261 $ (3,543) $ 1,608 (3,623) Assets of the employee benefit plans are invested in domestic and international equities, medium-term domestic fixed income securities, international fixed income securities, real estate and other short-term debt instruments. Postretirement Life and Health Benefit Plan - The Company sponsors a postretirement 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 postretirement medical and dental benefits; the plan is noncontributory with respect to life insurance benefits. During 1993, the Company adopted Statement of Financial Accounting Standards No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106). Prior to 1993, expense was recognized when benefits were paid. In accordance with SFAS 106, the Company began recording the cost for this plan on an accrual basis in 1993. The Company amortizes the transition obligation over a twenty-year period. The Company's cost under this plan for 1997, 1996 and 1995 was $410,000, $501,000 and $672,000 respectively. A regulatory asset of $431,000 was recorded in 1993 representing the excess of postretirement benefits on the accrual basis over the paid amounts for the period of January 1, 1993 until November 1, 1993, the effective date of the DTE's approval of the Company's new rates. Currently, the DTE allows Massachusetts utilities to recover the tax deductible portion of these postretirement benefits. Beginning in 1990, the Company has funded a portion of these costs through the combination of a trust under Section 501(c)(9) of the Internal Revenue Code and separate accounts of the trust under Section 401(h) of the Internal Revenue Code. The following table sets forth the plan's funded status reconciled with the amounts recognized in the Company's financial statements at December 31, 1997 and 1996: (In Thousands) 1997 1996 Accumulated postretirement benefit obligation: Retirees $(4,564) $(3,957) Fully eligible active plan participants (1,192) (1,033) Other active plan participants (1,423) (1,239) Total (7,179) (6,229) Plan assets at fair value 5,163 4,563 Accumulated postretirement benefit obligation in excess of plan assets (2,016) (1,666) Unrecognized net (gain) from past experience different from that assumed and from changes in assumptions (1,351) (1,679) Unrecognized transition obligation 4,045 4,315 Prepaid postretirement benefit cost $ 678 $ 970 Net periodic postretirement benefit cost included the following components: Year Ended December 31, (In Thousands) 1997 1996 1995 Service cost - benefits attributable to service $113 $137 $145 during the period Interest cost on accumulated postretirement 477 461 505 benefit obligation Actual return on plan assets (779) (507) (639) Net amortization and deferral 599 410 661 Net periodic postretirement $410 $501 $672 benefit cost For measurement purposes, a 6% (4.5% for dental costs) annual rate of increase in the per capita cost of covered health care benefits was assumed for 1998; the rate of increase for medical costs was assumed to decrease gradually to 4.5% for 2001 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997 by $979,000 and the aggregate of the service and the interest cost components of net periodic postretirement benefit cost for the year then ended by $81,000. The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.0%, 7.75% and 7.5% for 1997, 1996 and 1995, respectively. The expected long-term rate of return on plan assets was 9% for assets in the Section 401(h) accounts and, after estimated taxes, was 6% for assets in the Section 501(c)(9) trust for all years presented. Note H: Other Commitments Long-Term Obligations - The Company has contracts, which expire at various dates through the year 2013, for the acquisition and delivery of gas supplies and the storage and delivery of natural gas stored underground. The contracts contain minimum payment provisions which correspond to gas purchases that, in the opinion of management, are not in excess of the Company's requirements. FERC Order 636 Transition Costs - As a result of FERC Order 636, the Company's interstate pipeline service providers have been required to unbundle their supply and transportation services. This unbundling has caused the interstate pipeline companies to incur substantial costs in order to comply with Order 636. These transition costs include four types: (1) unrecovered gas costs (gas costs that had been incurred but not yet recovered by the pipelines when they were providing bundled service to local distribution companies); (2) gas supply realignment costs (the cost of renegotiating existing gas supply contracts with producers); (3) stranded costs (unrecovered costs of assets that can not be assigned to customers of unbundled services); and (4) new facilities costs (costs of new facilities required to physically implement Order 636). Pipelines are expected to be allowed to recover prudently incurred transition costs from customers such as the Company, primarily through a demand charge, after approval by FERC. The Company's additional transition cost liabilities are estimated to range from $2,800,000 to $3,300,000. The Company is recovering these costs from its customers, as approved by the DTE in October 1994. As of December 31, 1997, the Company has recorded on the balance sheet a long-term liability of $2,800,000 ("Accrued Transition Costs") and, based upon expected rate recovery, has recorded a regulatory asset of $2,800,000 ("Unrecovered Transition Costs Accrued"). Actual transition costs to be incurred depends on various factors, and therefore future costs may differ from the amounts discussed above. Note I: Contingencies The Company is involved in various legal actions and claims arising in the normal course of business. Management does not believe the outcome of any action or claim will have a material adverse effect upon the Company's financial position or results of operations. Working with the Massachusetts Department of Environmental Protection, the Company is engaged in site assessments and evaluation of remedial options for contamination that has been attributed to the Company's former gas manufacturing site and at various related disposal sites. During 1990, the DTE ruled that Colonial and eight other Massachusetts gas distribution companies can recover environmental response costs related to former gas manufacturing operations over a seven-year period, without carrying costs, through the CGAC. Through December 31, 1997, the Company had incurred environmental response costs of $11,875,000 of which $8,042,000 has been recovered from customers to date. As of December 31, 1997, the Company has recorded on the balance sheet a long-term liability of $707,000 and, based upon expected rate recovery, has recorded a corresponding regulatory asset. This amount represents estimated future response costs for these sites based on the Company's preferred methods of remediation. Actual environmental response costs to be incurred depends on various factors, and therefore future costs may differ from the amount currently recorded as a liability. Note J: Quarterly Financial Data (Unaudited) (In Thousands Except Per Share Amounts) Income Utility (Loss) Per Dividends Operating Net Average Paid Per Operating Income Income Common Common Quarter Ended Revenues (Loss) (Loss) Share Share 1997 December 31 $62,275 $9,481 $7,814 $.90 $.335 September 30 14,877 (3,043) (4,566) (.53) .335 June 30 26,927 (556) (2,501) (.29) .335 March 31 83,061 16,974 15,293 1.79 .325 1996 December 31 $53,612 $9,289 $7,035 $.83 $.325 September 30 14,983 (2,613) (3,580) (.42) .325 June 30 23,973 (714) (2,205) (.26) .325 March 31 77,310 16,192 15,228 1.82 .320 In the opinion of management, the quarterly financial data includes all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of such information. The Company typically reports profits during the first and fourth quarters of each year while incurring losses during the second and third quarters. This is due to significantly higher natural gas sales during the colder months to satisfy customers' heating needs. REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Shareholders of Colonial Gas Company We have audited the accompanying consolidated balance sheets of Colonial Gas Company and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, cash flows, and common equity for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and the significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe 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 consolidated financial position of Colonial Gas Company and subsidiaries as of December 31, 1997 and 1996, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. GRANT THORNTON LLP Boston, Massachusetts January 14, 1998 REPORT OF MANAGEMENT To the Shareholders of Colonial Gas Company Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles as applied to regulated public utilities and necessarily include some amounts that are based on management's best estimates and judgment. The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been audited by the independent public accounting firm, Grant Thornton LLP, who also conducts a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and Grant Thornton LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants and internal auditors have direct access to the Audit Committee and periodically meet with its members without management representatives present. F. L. Putnam, III Nickolas Stavropoulos President and Chief Executive Vice President- Executive Officer Finance, Marketing and Chief Financial Officer MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Net Income and Dividends Net income and income per average common share were $16,040,000 ($1.87), $16,478,000 ($1.95), and $13,764,000 ($1.66) for the years ended December 31, 1997, 1996, and 1995, respectively. Net income was favorably impacted by colder than 20-year average temperatures in 1997, 1996 and 1995. This is summarized as follows: 1997 1996 1995 Percent colder than 20-year average 1.8% 3.0% 2.4% Percent colder (warmer) than prior year (1.2)% 0.6% (2.5)% Other items which had an impact on net income are discussed in the following sections. Dividends paid per common share were $1.33 in 1997, $1.295 in 1996 and $1.275 in 1995. The Company has paid dividends for 61 consecutive years, and has increased dividends each year for the past 18 years. Operating Revenues Operating revenues were $187,140,000 in 1997, $169,878,000 in 1996 and $163,668,000 in 1995. Operating revenues are impacted by the volumes of gas sold and transported, changes in base rates as approved by the Massachusetts Department of Telecommunications & Energy (DTE), formerly known as the Massachusetts Department of Public Utilities, and the pass-through of gas costs to customers via a cost of gas adjustment clause ("CGAC"). The volumes of gas sold are affected by fluctuations in weather and the number of customers being served. Firm customers increased by 14,900 over the last three years from 136,700 in December 1994 to 151,600 in December 1997, an increase of 10.9%. The chart below summarizes volumes of gas sold and transported and number of firm customers: 1997 1996 1995 (In MMcf) Gas sold Firm 19,997 19,56 318,560 Non-Firm 62 648 1,148 Gas transported Firm 3,278 3,918 2,537 Non-Firm 3,791 2,671 3,224 Total gas sold and transported (In MMcf) 27,128 26,800 25,469 Firm Customers 151,600 145,400 141,400 Operating revenues increased $17,262,000 or 10.2% from 1996 to 1997. This increase resulted from customer growth of 4.2% and higher gas costs, which offset weather which was 1.2% warmer than the prior year. Operating revenues increased $6,210,000, or 3.8% from 1995 to 1996. This increase resulted from weather that was 0.6% colder than the prior year and customer growth of 2.9%. Cost of Gas Sold Average cost of gas sold per Mcf was $5.08 in 1997, $4.29 in 1996 and $4.22 in 1995. Cost of gas sold is based upon the sales volumes, the price and mix of gas purchased and used to satisfy demand, and profits on non-firm sales and transportation, which flow back to firm sales customers as a credit through the CGAC. The Company distributes natural gas purchased under long-term contracts as well as gas purchased on the spot market. The following table summarizes the sources of gas purchased by the Company: (In MMcf) 1997 1996 1995 Gas purchased Pipeline 14,763 15,115 14,659 Underground storage 3,605 3,346 3,270 LNG/Other 2,365 2,596 2,426 Total gas purchased 20,733 21,057 20,355 Underground storage consists primarily of spot gas purchased and injected into storage during the summer and fall for use during the following winter. Operating Expenses Operations expense was $30,044,000 in 1997, a decrease of $328,000 or 1.1%, from 1996, and $30,372,000 in 1996, a decrease of $38,000, or 0.1%, from 1995. Maintenance expense increased $27,000, or 0.6%, in 1997 from 1996 and increased $75,000, or 1.7%, in 1996 from 1995. Depreciation and amortization expense increased $821,000 or 7.3% in 1997 and $1,003,000 or 9.8% in 1996. The increases in 1997 and 1996 were due to increases in utility property. Local property and other taxes decreased 2.1% in 1997 from 1996 due to reduced property taxes. Local property and other taxes increased 4.3% in 1996 from 1995. The increase in 1996 was due to higher property taxes and additional property subject to property taxes. Income Taxes Total Federal income and state franchise taxes increased $884,000 or 9.7% in 1997 from 1996 and increased $762,000 or 9.2% in 1996 from 1995 as a result of a higher level of income for the utility operations. Other Operating Income (Expense) Other operating income (expense), net of income taxes was $645,000 in 1997, $2,276,000 in 1996 and $645,000 in 1995. Other operating income primarily includes the results of the Company's wholly- owned energy trucking subsidiary (Transgas). Also included are heating and water heating equipment sales and installations. Transgas' 1997 financial results were driven by a 50% decrease in liquefied natural gas ("LNG") hauls leading to a $5,502,000 decrease in energy trucking revenue and a $1,699,000 decrease in energy trucking net income. This decrease in demand of transportation of LNG occurred for most of the year and was primarily due to the warmer than normal weather in the first quarter of 1997. Transgas' 1996 financial results were driven by a 68% increase in LNG hauls leading to a $3,455,000 increase in energy trucking revenue and a $1,422,000 increase in energy trucking net income. This increase in demand of transportation of LNG occurred for most of the year and was primarily due to the colder than normal weather in the fourth quarter of 1995 and the first quarter of 1996. Factors affecting the future financial results of Transgas, in addition to the impact of weather variations, include the amount of LNG used by local distribution companies throughout the northeast United States to satisfy requirements of their customers; the price of domestic and Canadian natural gas compared to imported LNG; the continued availability of imported LNG; and the level of construction and major maintenance projects of interstate pipeline companies which drives the demand for portable pipeline services. Non-Operating Income Non-operating income, net of income taxes, was $573,000 in 1997, $757,000 in 1996 and $864,000 in 1995. Non-operating income includes interest income and miscellaneous other income. Interest and Debt Expense Interest and debt expense decreased $675,000 or 7.7% in 1997 from 1996. The decrease in 1997 was due to decreased levels of short- term debt and greater interest income on higher balances of regulatory assets, which offset interest expense. These were partially offset by an increase in interest on long-term debt. Interest and debt expense decreased $561,000 or 6.1% in 1996. The decrease in 1996 was due to a decrease in interest on long-term debt resulting from the early retirement of higher interest debt in December 1995 offset by increased levels of short-term debt, although at lower short-term interest rates. Effects of Inflation Inflation generally has a negative impact upon the Company's profitability since the rates charged to the Company's utility customers, excluding changes in the cost of gas sold, cannot be increased without formal proceedings before the DTE. Changes in the cost of gas sold are automatically reflected in customer rates pursuant to semi-annual adjustments under the CGAC. In the absence of authorized rate increases, the Company must look to increased productivity and higher sales volumes to offset inflationary increases in its other costs of operations. The present regulatory process permits the Company to earn a rate of return based on the historical cost of utility property without recognition of the current replacement cost. The Company's policy is to file for an increase in rates only when increases in productivity and customers are not sufficient to counteract the impact of inflation. The Company has set a goal to defer its next base rate increase until at least the year 2000. Regulatory Matters The Company is a public utility subject to the jurisdiction and regulatory authority of the DTE with respect to its rates as well as to the issuance of securities, franchise territory and other related matters. On July 18, 1997, the DTE directed the Company and the other investor-owned gas utilities in Massachusetts to collaborate on developing common principles to unbundle their services to provide customers with broader supplier choice. The DTE further directed that all gas utilities have unbundled rates in effect by November 1, 1998 for all customer classes. Unbundled service separates (i) the part of the service involving procuring the gas and transporting it to the city-gate (i.e. the point where the Company takes gas from the interstate pipeline into its distribution systems); and (ii) the delivery of the gas to the customer's facility through the local distribution system. The Company presently offers an unbundled service to commercial and industrial customers who seek to have other suppliers procure their gas which the Company then delivers to them through its distribution system. The Company's proposal for further rate unbundling is being developed and is expected to be filed in the spring of 1998. In addition, the Company continues to participate in the DTE-directed Unbundling Collaborative. The Company cannot predict the outcome of the unbundling collaborative process or the other regulatory changes that may take place, but at this time, the Company does not anticipate that the unbundling of its services will have a material financial impact on its business. Under the present regulatory system, the DTE permits Massachusetts gas companies to utilize a CGAC through which firm sales customers pay, via their monthly gas bill, the costs incurred by the companies in procuring and transporting gas to the companies distribution systems. Changes in non-gas or base rates charged to customers are subject to approval by the DTE after formal proceedings. Environmental response costs, transition costs and demand side management ("DSM") program costs are recovered through the CGAC, as approved by the DTE. The environmental response costs recovered through the CGAC relate to the Company's former gas manufacturing operations, as described under "Environmental Matters". Transition costs relate to Federal Energy Regulatory Commission ("FERC") approved pipeline charges resulting from Order 636. In addition to full recovery of the installed conservation measures, the Company is allowed to recover, under methodologies approved in 1995 for its residential DSM programs and in 1996 for its commercial and industrial programs resulting lost margins and financial incentives based on the attainment of performance goals. The Company has made only two requests for base rate increases since 1984. Its most recent request was made in 1993. In response to that request, the DTE approved a base rate increase that was designed to produce additional revenues of $6.7 million or 3.9% annually, effective November 1, 1993. Based upon continued strong customer growth, cost control and improved productivity, the Company's goal remains to postpone the filing of a request for its next base rate increase until at least the year 2000, while maintaining an adequate return to shareholders. Under a 1995 industry wide ruling of the DTE, the Company will be required in its next base rate filing either to present an alternative incentive based method of pricing or to justify continuation of the traditional cost of service/rate of return method. On the same July 18, 1997 date that the DTE issued its directive to the Massachusetts investor-owned gas utilities to collaborate on unbundling their services, the DTE issued its order declining to approve the Company's proposed joint venture with Cabot LNG Corporation. The proposed joint venture would have combined certain LNG assets and resources of the two companies, including the Company's Tewksbury LNG facility and its LNG trucking subsidiary, Transgas Inc. The DTE's decision declining to approve the joint venture appeared to be based in large part on its unwillingness to allow a supply asset like the Tewksbury LNG facility to be used as proposed until the issues related to unbundling were resolved. The Company follows the provisions of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71") requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. Future regulatory changes could result in the Company no longer meeting the provisions of SFAS 71 for all or part of its business, thereby requiring the elimination of the financial statement effects of regulation for that portion of its business. Environmental Matters Working with the Massachusetts Department of Environmental Protection, the Company is engaged in site assessments and evaluation of remedial options for contamination that has been attributed to the Company's former gas manufacturing site and at various related disposal sites. During 1990, the DTE ruled that Colonial and eight other Massachusetts gas distribution companies can recover environmental response costs related to former gas manufacturing operations over a seven-year period, without carrying costs, through the CGAC. Through December 31, 1997, the Company had incurred environmental response costs of $11,875,000 of which $8,042,000 has been recovered from customers to date. As of December 31, 1997, the Company has recorded on the balance sheet a long-term liability of $707,000 and, based upon expected rate recovery, has recorded a corresponding regulatory asset. This amount represents estimated future response costs for these sites based on the Company's preferred methods of remediation. Actual environmental response costs to be incurred depends on various factors, and therefore future costs may differ from the amount currently recorded as a liability. Accounting Standards Impairment of Long-Lived Assets - During 1996, the Company adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". This statement requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The adoption of this standard did not have a material impact on the Company's financial condition or results of operations. The Year 2000 Issue The Company's principal computer systems are currently capable of processing the year 2000 or are in the process of being upgraded or replaced by systems that are similarly capable. The Company does not expect the cost of addressing this issue to have a material impact on the Company's financial results. LIQUIDITY AND CAPITAL RESOURCES Operating Activities The Company's liquidity is affected by its ability to generate funds from operations and to access capital markets. The Company's operations are seasonal with its cash flow reflecting this seasonality. The Company typically generates approximately 70 to 80 percent of its annual operating revenues during the November through April heating season, which results in a high level of cash flow from operations from late winter through early summer. As a result of this seasonality, the Company's liquidity can be affected by significant variations in weather. Short-term borrowings are highest during the fall and early winter months due to the completion of the annual construction program and seasonal working capital requirements. Investing Activities The Company invests in property, plant and equipment to improve and protect its distribution system, and to expand its system to meet customer demand. Utility capital expenditures were $35,788,000 in 1997, $26,875,000 in 1996 and $24,096,000 in 1995. The Company's long-range plan calls for annual utility expenditures, of which over 52% is budgeted for new business, averaging $28,000,000 over the next five years as follows: (In Thousands) 1998 1999 2000 2001 2002 Distribution $22,500 $23,100 $23,800 $24,700 $25,600 Production 1,800 100 400 300 900 Information Systems 5,000 3,100 2,400 500 400 Automated Meter Reading 3,100 300 300 300 200 General 300 300 300 300 300 Total Capital Expenditures $32,700 $26,900 $27,200 $26,100 $27,400 Financing Activities The Company has raised permanent capital during the last three years as follows: (In Thousands) 1997 1996 1995 Common Stock Under Dividend Reinvestment and Common Stock Purchase Plan and Employee Savings Plan $3,621 $3,277 $2,702 Medium term notes under the first mortgage indenture $15,000 $30,000 $20,000 The aggregate amount of maturities of Long-Term Debt for the years 1998 through 2002 are $10,164,000 in 1998, and $20,102,000 in 1999. Series MTA-6 Bonds due in 2027 can be redeemed by the holder in 2002. The Company has entered into treasury rate locks in order to hedge the interest rate on long-term debt anticipated to be issued in early 1998. The treasury rate locks are for $10 million at a 10-year treasury rate of 5.88% and for $20 million at a 15-year treasury rate of 5.88%. The Company has a $75 million credit facility expiring in September 2000, which allows it to meet its seasonal working capital needs. Up to $30 million of the credit facility can be used by the Company's gas inventory trust. The credit facility allows the Company the option to borrow under any one of three alternative rates. The equity and debt components of the Company's capital structure at the end of the year is shown in the table below: 1997 1996 1995 Equity 55% 54% 58% Long-Term Debt 45% 46% 42% As of April 1997, the quarterly dividend paid on the Company's Common Stock was increased to $.335 per share or an annualized dividend rate of $1.34 per share. Forward Looking Information This report and other Company reports contain forward looking statements which are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause actual results to differ materially from those projected in these forward looking statements include, but are not limited to, variations in weather, changes in the regulatory environment, customers' preferences on energy sources, general economic condition, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company. FINANCIAL AND OPERATING STATISTICS (For the Years Ending December 31) 1997 1996 1995 1994 1993 Operating Revenues (In Thousands) Residential $121,649 $108,879 $103,991 $104,812 $106,362 Commercial and industrial 59,163 54,324 52,926 56,358 53,933 Firm transportation 1,941 1,843 1,294 1,210 816 Non-firm sales 2,530 2,985 3,745 2,429 3,613 Non-firm transportation 631 453 424 401 409 Other 1,226 1,394 1,288 1,017 233 Total operating revenues $187,140 $169,878 $163,668 $165,327 $165,366 Gas Sold (MMcf) Residential 12,492 12,094 11,361 11,190 11,492 Commercial and industrial 7,505 7,469 7,199 7,526 7,443 Non-firm 62 648 1,148 729 1,030 Total gas sales 20,059 20,211 19,708 19,445 19,965 Gas Transported (MMcf) Firm 3,278 3,918 2,537 6,090 4,163 Non-firm 3,791 2,671 3,224 4,185 4,026 Total gas transported 7,069 6,589 5,761 10,275 8,189 Total gas sold and trans- ported 27,128 26,800 25,469 29,720 28,154 Gas Purchased (MMcf) Pipeline 14,763 15,115 14,659 14,392 14,983 Underground storage 3,605 3,346 3,270 3,112 3,501 LNG - as liquid 680 1,067 844 1,129 907 LNG - as vapor 1,680 1,528 1,574 1,236 917 Propane 5 1 8 25 8 Total gas purchased 20,733 21,057 20,355 19,894 20,316 Company use and other (674) (846) (647) (449) (351) Available for sale 20,059 20,211 19,708 19,445 19,965 Customers - End of period Residential 136,826 131,286 127,419 123,077 118,918 Commercial and industrial 14,697 14,136 13,940 13,559 13,269 Firm transportation 30 19 11 8 1 Non-firm sales 22 25 27 21 21 Non-firm transportation 15 5 2 2 2 Total customers - end of period 151,590 145,471 141,399 136,667 132,211 Average Annual Mcf Sold/Customer Residential 96 96 94 96 101 Commercial and industrial 519 533 531 569 575 Average Annual Bill/Customer Residential $935 $868 $858 $897 $939 Commercial and industrial $4,093 $3,880 $3,901 $4,260 $4,167 Average Revenue/Mcf Residential $9.74 $9.00 $9.15 $9.37 $9.26 Commercial and industrial $7.88 $7.27 $7.35 $7.49 $7.25 Residential Heating Customers as a % of all Residential Customers 91% 90% 90% 90% 90% Highest Daily Sendout (Mcf) 183,063 170,984 199,275 204,896 184,303 Percent Colder (Warmer) than 20-year average 1.8% 3.0% 2.4% 5.0% 6.3% SELECTED FINANCIAL DATA (For the Years Ending December 31) (In Thousands Except Per Share Amounts) 1997 1996 1995 1994 1993 Balance Sheet Data: Assets: Utility property - net $274,532 $250,983 $235,555 $221,685 $202,713 Non-utility property - net 7,312 5,925 5,036 3,479 3,235 Capital leases - net 2,630 1,811 2,253 2,948 3,914 Current assets 67,967 67,558 61,002 65,568 67,668 Deferred charges and other assets 36,550 38,135 38,575 37,668 34,588 Total $388,991 $364,412 $342,421 $331,348 $312,118 Capitalization and Liabilities: Capitalization: Common equity $122,132 $113,906 $105,070 $ 99,175 $ 94,283 Long-term debt 100,102 95,266 75,418 77,923 87,432 Total Capitalization 222,234 209,172 180,488 177,098 181,715 Capital lease obligations 1,617 930 1,359 2,237 3,149 Current liabilities 102,508 94,169 101,666 91,382 73,413 Deferred credits and reserves 62,632 60,141 58,908 60,631 53,841 Total $388,991 $364,412 $342,421 $331,348 $312,118 Income Statement Data: Operating revenues $187,140 $169,878 $163,668 $165,327 $165,366 Cost of gas sold (102,455) (87,188) (83,631) (87,458) (90,915) Operating margin 84,685 82,690 80,037 77,869 74,451 Operating expenses (including income taxes) (61,829) (60,536) (58,512) (60,331) (55,736) Utility operating income 22,856 22,154 21,525 17,538 18,715 Other income - net of income taxes 1,218 3,003 1,509 1,880 1,448 Interest and debt expense (8,034) (8,709) (9,270) (8,409) (8,141) Accounting change - - - - - Net income $16,040 $ 16,478 $13,764 $11,009 $ 12,022 Capitalization Ratios: Common equity 55% 54% 58% 56% 52% Long-term debt 45% 46% 42% 44% 48% Common Stock Data: Average shares outstanding 8,598 8,432 8,294 8,119 7,931 Income per share $1.87 $1.95 $1.66 $1.36(a) $1.52 Dividends paid per share: Common Stock $1.33 $1.295 $1.275 $1.255 $1.235 Class A Common Stock - - - - - Per weighted average common share $1.33 $1.295 $1.275 $1.255 $1.235 Dividend payout rate 71% 66% 77% 92% 81% Book value per share $14.06 $13.37 $12.56 $12.05 $11.74 Dividends as a percent of book value 9% 10% 10% 10% 11% Market price per share $28.81 $21.25 $20.25 $19.25 $22.50 Market price as a percent of book value 205% 159% 161% 160% 192% Return on average common equity 13.6% 15.1% 13.5% 11.4% 13.2% (a) 1994 is after a restructuring charge of $.24 per share. (b) 1988 includes the cumulative effect of an accounting change of $.33 per share. SHAREHOLDER INFORMATION Corporate Headquarters Colonial Gas Company 40 Market Street P. O. Box 3064 Lowell, MA 01853-3064 (978) 322-3000 FAX: (978) 459-2314 www.colonialgas.com Annual Meeting The Annual Meeting of Stockholders will be held on April 15, 1998 at 10:00 a.m. at BankBoston, 100 Federal Street, Boston, Massachusetts. Stock Listing The Company's Common Stock began trading on the New York Stock Exchange under the symbol "CLG" on September 18, 1997. Prior to that date, the Company traded on the NASDAQ Stock Market under the symbol "CGES". Stock trading activity is reported in financial publications under the abbreviation of ColonlGas or ColnlGa. Annual Report - Form 10-K A copy of the Company's 1997 Annual Report on Form 10-K as filed with the Securities and Exchange Commission will be sent free of charge to any shareholder who contacts the Investor Relations Department at the corporate headquarters address above. Many of the Company's financial statements are also available on its website. Transfer Agent BankBoston, N.A. c/o Boston EquiServe, L.P. P. O. Box 8040 Mail Stop: 45-02-64 Boston, MA 02266-8040 (800) 736-3001 (781) 575-3100 Independent Certified Public Accountants Grant Thornton LLP 98 North Washington Street Boston, MA 02114 (617) 723-7900 Corporate Counsel Palmer & Dodge LLP One Beacon Street Boston, MA 02108 (617) 573-0100 Dividends The Company has paid dividends on Common Stock for 61 consecutive years and has increased dividends each year for the past 18 years. Common Stock dividends are payable if and when declared by the Board of Directors. Anticipated Record Date Anticipated Payment Date February 27, 1998 March 13, 1998 June 1, 1998 June 15, 1998 September 1, 1998 September 15, 1998 December 1, 1998 December 15, 1998 Dividend Reinvestment Plan The Company's Dividend Reinvestment and Common Stock Purchase Plan ("DRIP") provides shareholders of record with an economical and convenient method for purchasing additional shares of the Company's Common Stock without paying any brokerage fees. Participants in the plan may elect to purchase additional Colonial shares at a 5% discount from the market price by reinvesting all or a portion of their dividends with no brokerage fees. Participants in the plan may also make optional cash purchases of Common Stock at the market price in amounts ranging from a minimum of $10 to a maximum of $5,000 per calendar quarter, with no brokerage fees. Features of the plan at no charge to shareholders include: - Direct deposit of dividends by electronic deposit - Automatic monthly investments by electronic funds transfer - Safekeeping of stock certificates Additional information describing the plan, including a prospectus and enrollment information, can be obtained by contacting the Company's Transfer Agent or Investor Relations Department. Investment Dates The investment date for optional cash investments under the DRIP will be the fifteenth day of each month or, if that day is not a business day, the preceding business day. Optional cash investments must be received by the Company's Transfer Agent five business days before the investment date. The dates below will help you plan for any optional cash investments during 1998. Date Investment Must Be Investment Received By Transfer Agent Dates April 8 April 15 May 8 May 15 June 8 June 15 July 8 July 15 August 7 August 14 September 8 September 15 October 7 October 15 November 6 November 13 December 8 December 15 Equity Research Equity research reports are independently prepared and distributed by the following firms: A. G. Edwards & Sons, Inc.; Edward Jones; First Dallas Securities; Merill Lynch; and Tucker Anthony Incorporated. Investment Information Colonial Gas Company is a corporate member of the National Association of Investors Corporation (NAIC). The Company is also a participant in NAIC's Low Cost Investment Plan. SHAREHOLDER INFORMATION Market Prices and Dividends The following table reflects the high and low sales prices as reported by the New York Stock Exchange (since the third quarter of 1997) and NASDAQ Stock Market, for shares of the Company's Common Stock for 1997 and 1996, and the quarterly dividends paid per share. Sales Prices Dividends High Low Paid per Share 1997 __________________________________ The Year $30-1/16 $19-1/4 $1.330 4th Quarter 30-1/16 23-11/16 .335 3rd Quarter 25-1/4 20-1/2 .335 2nd Quarter 22-3/4 19-1/4 .335 1st Quarter 24 20 .325 1996 __________________________________ The Year $24-1/4 $20 $1.295 4th Quarter 24 21-1/4 .325 3rd Quarter 24-1/4 20-1/4 .325 2nd Quarter 24-1/4 20 .325 1st Quarter 24 20-1/4 .320 Shareholders and Record Holders At December 31, 1997, there were approximately 15,000 shareholders of the Company's Common Stock, including 5,111 shareholders of record. [END OF EXHIBIT 13a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 31, 1997] EX-21 4 EXHIBIT 21A [EXHIBIT 21a TO COLONIAL GAS COMPANY FORM 10-K FOR YEAR ENDED DECEMBER 31, 1997] Colonial Gas Company Subsidiaries of Registrant Subsidiaries: Organized in: Ownership: (a) Transgas, Inc. Massachusetts 100% (a) CGI Transport Limited(b) Canada 100% (a) Included in consolidated financial statements. (b) Owned by Transgas. [END OF EXHIBIT 21a TO COLONIAL GAS COMPANY FORM 10-K FOR YEAR ENDED DECEMBER 31, 1997] EX-23 5 EXHIBIT 23A [EXHIBIT 23a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 21, 1997] EXHIBIT 23a CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We have issued our reports dated January 14, 1998 accompanying the consolidated financial statements and schedule incorporated by reference or included in the Annual Report on Form 10-K of Colonial Gas Company and subsidiaries for the year ended December 31, 1997. We hereby consent to the incorporation by reference of said reports in the Colonial Gas Company Registration Statements on Forms S-8, as amended (File No. 33-47099, File No. 33-54091, and File No. 33- 34067); on Forms S-3 (File No. 33-61863 and File No. 333-43715); and on Form S-4 (File No. 333-47441). GRANT THORNTON LLP Boston, Massachusetts March 12, 1998 [END OF EXHIBIT 23a TO COLONIAL GAS COMPANY 10-K FOR YEAR ENDED DECEMBER 21, 1997] EX-27 6
UT 1,000 12-MOS DEC-31-1997 DEC-31-1997 PER-BOOK 274,532 9,942 67,967 30,880 5,670 388,991 28,931 57,277 35,924 122,132 0 0 100,102 64,295 0 0 10,164 0 1,617 1,013 89,668 388,991 187,140 9,972 154,312 164,284 22,856 1,218 24,074 8,034 16,040 0 16,040 11,435 8,114 34,346 1.87 1.87
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