Item 1. Business
THE COMPANY
Colonial Gas Company ("Colonial" or the "Company"), a Massachusetts corporation formed in 1849, is primarily a regulated natural gas utility, or local distribution company ("LDC"). The Company serves over 154,500 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.
On October 17, 1998, the Company entered into an Agreement and Plan of Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"), a Massachusetts business trust which owns all of the outstanding stock of two other Massachusetts LDCs, Boston Gas Company ("Boston Gas") and Essex Gas Company ("Essex Gas"). The Merger Agreement provides for the merger of the Company with and into a subsidiary of Eastern, as a result of which the Company will become a wholly-owned subsidiary of Eastern (the "Pending Merger"). Pursuant to the Pending Merger, the outstanding shares of the Company's common stock would convert into the right to receive cash and Eastern common stock as set forth in the Merger Agreement. The Pending Merger was approved by shareholders of Colonial and Eastern at separate special shareholder meetings which were held on February 10, 1999. Completion of the Pending Merger is subject to receipt of satisfactory regulatory approvals, including approval of the Massachusetts Department of Telecommunications and Energy, the Securities and Exchange Commission, and antitrust clearance.
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 51% of potential customers in its service areas. Of its 154,500 customers, approximately 90% are residential accounts. The Company added 4,700 firm sales customers in 1998. 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 1998, 44% converted from other fuels and 56% were new construction.
The Company's 1998 consolidated operating revenues were derived 67% from firm gas sales to residential customers, 29% from firm gas sales to commercial and industrial customers, 1% from non-firm customers, 2% from firm transportation customers and 1% from other revenues. For the year 1998, the Company had firm gas sales of 17,575 MMcf, of which 10,347 MMcf was sold in the Merrimack Valley area and 7,228 MMcf in the Cape Cod area. At December 31, 1998, 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 large extent seasonal, being greatest in the colder months.
At December 31, 1998, the Company had 446 full-time-equivalent employees. Of those employees, 89 are covered by a collective bargaining agreement with the United Steelworkers of America which expires in April 2001 and 71 are covered by a separate collective bargaining agreement with the United Steelworkers of America which expires in February 2000. In addition, Transgas employs 53 full-time employees of which a total of 38 are covered by two separate collective bargaining agreements with the International Brotherhood of Teamsters - - one for drivers and one for mechanics. The drivers agreement expires in June 1999 while the mechanics agreement expires in July 1999.
GAS SUPPLY, TRANSPORTATION AND STORAGE RESOURCES
The Company and other LDCs have traditionally been responsible for overseeing the gas supplies, pipeline transportation and storage resources required to serve their firm sales customers. As discussed below in "Regulatory Matters", pursuant to a February 1999 order by the Massachusetts Department of Telecommunications and Energy ("DTE") on unbundling procedures, each Massachusetts LDC will retain this responsibility for a transition period that will be up to five years in duration. Generally, LDCs pay negotiated prices for pipeline-transported supplies and tariffed rates approved by the Federal Energy Regulatory Commission ("FERC") for pipeline transportation and storage.
As a result of the DTE's recent unbundling orders and directives outlined below in "Regulatory Matters", the Company anticipates that the proportion of gas entering its distribution system that is supplied by third party suppliers will increase and that it will be required to transfer some of its upstream resources to those third party suppliers. The Company does not expect that these unbundling changes will have a material financial impact on its business during the transition period.
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:
1998 1997 1996 MMcf(a) % MMcf(a) % MMcf(a) %
Firm Pipeline Transportation Capacity 30,313 30,313 30,313 ====== ====== ======
Firm Gas Supply Sources Contracts for Pipeline- Transported Gas (b) 18,473 73 18,818 75 18,698 71 LNG contracts 2,911 12 2,616 10 4,150 15 Storage inventory at January 1 (c) 3,741 15 3,754 15 3,614 14 ----- -- ----- -- ----- -- Total Available 25,125 100 25,188 100 26,462 100 ====== === ====== === ====== ===
Gas Sendout Pipeline-Transported Supplies (d) 15,100 79 14,763 72 15,115 72 Supplemental Supplies: Underground storage 2,500 13 3,605 17 3,346 16 LNG-as liquid 704 4 680 3 1,067 5 LNG-as vapor 692 4 1,680 8 1,528 7 Propane-air 2 - 5 - 1 - Total Sendout 18,998 100 20,733 100 21,057 100 ====== === ====== === ====== ===
Ratio of available firm supply to sendout (e) 1.32 1.21 1.26
- ------------------------- (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 1998, 1997 and 1996.
(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 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. Upon completion of the Pending Merger, the Company's portfolio will be integrated into the portfolios of Boston Gas and Essex Gas in order to enhance efficiencies and reliability for the natural gas sales customers of Eastern's gas distribution subsidiaries.
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 entered into for terms of one year or less, 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 has on-system LNG and propane-air facilities which 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 or less, 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. In July 1997, the DTE directed all investor-owned LDCs to work toward unbundling their rates and services in order to make supplier choice available to all their customers. Unbundled rates provide separate charges for (1) gas supply and (2) gas delivery across the LDC's distribution system. Unbundled service involves a customer
itself contracting for gas supply to be brought to the LDC's system, and then paying the LDC for the delivery of that supply to its home or business.
In November, 1998, the Company's unbundled rates took effect and the DTE approved an agreement among LDCs (including the Company) and third party suppliers that sets forth standard procedures for serving customers who elect to buy gas supply from a third party supplier. In February, 1999, the DTE directed that, for a transition period up to five years in duration: (a) LDCs must retain the obligation to plan for and procure all upstream pipeline resources required to serve their firm sales customers; and (b) any third party supplier seeking to sell gas supply to an LDC's customers must acquire from the LDC, at full cost, the slice of the LDC's upstream resources that the LDC had used to serve those customers. The DTE will reevaluate upstream market conditions at the end of the first three years of the transition period to determine if the directives should be modified. As referenced above in "Gas Supply, Transportation and Storage Resources", the Company does not expect that these unbundling changes will have a material financial impact on its business during the transition period.
In 1998, the DTE conducted an industry-wide proceeding on the calculation of lost margins that gas companies are allowed to recover as a result of their conservation or demand side management ("DSM") programs. The Company has been using a calculation method, approved by the DTE in previous individual Company filings, based on the useful life of installed conservation measures. As of this date, the DTE has not yet issued its decision in the industry-wide proceeding. The decision could result in a shortening of the time period for calculating lost DSM margins to less than the full useful life of installed measures. A shortening of the period would result in some decrease in operating revenues, but it is uncertain at this time whether or by how much the period would be shortened and, therefore, what impact it would have on the Company.
In Massachusetts, LDCs utilize a cost of gas adjustment clause ("CGAC") to pass through to firm sales customers, via their monthly gas bill, the costs incurred by the companies in procuring and transporting gas to the companies distribution systems. No mark-up is allowed on those costs, i.e. the LDCs earn no margin or profit from selling gas supply (instead, margins are earned from the LDC's distribution or delivery service).
With the effectiveness of unbundled rates, Colonial, as well as other Massachusetts LDCs use a Local Distribution Adjustment Clause ("LDAC") which provides for the recovery of certain other costs from all firm customers, regardless of whether they purchase their gas supply from Colonial. These costs include: environmental response costs (see "Environmental Matters" below), FERC Order 636 transition costs, DSM program costs, DSM related lost margins, and certain unbundling costs. These costs were previously recovered through the CGAC.
In connection with the Pending Merger, the Company has filed a proposed rate plan with the DTE. The rate plan proposes a 2.2% reduction in the total burner-tip price paid by the Company's firm sales customers in the first full year following the merger. In addition, the rate plan would establish a ten-year freeze in the Company's base (i.e. distribution service) rates and would afford Eastern and Colonial a reasonable opportunity to recover merger-related costs. Prior to this pending rate plan proposal, the Company had made only two base rate filings with the DTE since 1984. Its most recent previous filing was made
in 1993 and resulted in a base rate increase designed to generate additional revenues of $6.7 million or 3.9 percent annually effective November 1, 1993.
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, pursuant to recent DTE directives, the Company has unbundled its rates and is in the process of unbundling its services so that all customers can have the opportunity to choose their supplier of natural gas. Under these directives, natural gas provided to customers in the Company's franchise areas (whether supplied by the Company or third party suppliers) will continue to be delivered to customers through the Company's distribution system.
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, 1998, the Company had incurred environmental response costs of $12,582,000 of which $8,949,000 has been recovered from customers to date.
As of December 31, 1998, the Company has recorded on the balance sheet a long-term liability of $200,000 and, based upon anticipated 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 ("LNG"), propane and other commodities. In 1998, Transgas provided such service to approximately 24 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 and pipeline companies 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 $3,723,000 in 1998. Approximately 61% of Transgas' revenue in 1998 was derived from transporting LNG from Distrigas of Massachusetts Corporation's import terminal, located in Everett, Massachusetts. Transgas' revenues decreased $1,806,000, or 33%, compared to 1997 due primarily to a decrease in the demand for transportation of LNG which occurred for most of the year. The decrease was primarily due to the warmer than normal weather in the winter of 1997-98.
Transgas provides over-the-road transportation services by utilizing a fleet of 40 tractors. Transgas owns 60 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 propane 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.
Item 1A.
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, Chairman and Senior Jr. (74) Executive Officer 1953 Frederic L. Putnam, President and Chief Executive III (53) Officer 1975 Charles W. Sawyer (53) Executive Vice President and Chief Operating Officer 1976 Nickolas Stavropoulos (41) Executive Vice President - Finance, Marketing, and Chief Financial Officer 1979 John P. Harrington (56) Senior Vice President - Gas Supply and Assistant to the President 1966 Victor W. Baur (55) President - Transgas Inc. 1972 Dennis W. Carroll (52) 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 has been a Director of the Company since 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.
Item 2. Properties.
The Company has two principal operations centers and two principal LNG storage facilities. One of these storage facilities is located in Tewksbury, Massachusetts and has a capacity of approximately 1,000,000 Mcf of LNG and the other is located in South Yarmouth, Massachusetts and has a capacity of approximately 175,000 Mcf of LNG. In general, the Company's gas production and storage facilities, metering and regulation stations and operations centers, are located on land it owns. In addition, the Company owns its corporate headquarters, a 36,000 square foot office facility in Lowell, Massachusetts.
The Company's distribution mains of approximately 3,129 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 believes that the Company's properties are adequate for the conduct of its business for the reasonably foreseeable future.
Item 3.
Item 3. Legal Proceedings.
See Item 1, "Business--Environmental Matters" above, which is incorporated herein.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
A Special Meeting of Shareholders of the Company was held on February 10, 1999. At that Special Meeting, the shareholders voted to approve the Agreement and Plan of Reorganization dated as of October 17, 1998 between Colonial Gas Company and Eastern Enterprises, with 6,727,284 shares voting for and 217,193 shares voting against or withholding authority.
PART II
Item 5.
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters.
Colonial Gas Company's Common Stock is traded on the New York Stock Exchange under the ticker symbol CLG. Prior to September 18, 1997, the Company's Common Stock was traded on the Nasdaq Stock Market. At December 31, 1998, there were approximately 15,000 shareholders of the Company's Common Stock, including 4,721 shareholders of record.
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 1998 and 1997, and the quarterly dividends paid per share.
Sales Prices Dividends High Low Paid per Share
The Year $35.438 $26.500 $1.370 4th Quarter 35.438 28.000 .345 3rd Quarter 30.000 27.125 .345 2nd Quarter 29.250 26.500 .345 1st Quarter 29.500 26.500 .335
The Year $30.063 $19.250 $1.330 4th Quarter 30.063 23.688 .335 3rd Quarter 25.250 20.500 .335 2nd Quarter 22.750 19.250 .335 1st Quarter 24.000 20.000 .325
Item 6.
Item 6. Selected Financial Data.
- ----------------------------------------------------------------------------- (a)Customer count data has been updated for the years 1994-1997 due to the implementation in 1998 of a new customer billing system, and its improved customer count methodology.
SELECTED FINANCIAL DATA
(For the Years Ending December 31) (In Thousands Except Per Share Amounts) 1998 1997 1996 1995 1994 Balance Sheet Data: Assets: Utility property - net $292,213 $274,532 $250,983 $235,555 $221,685 Non-utility property - net 7,129 7,312 5,925 5,036 3,479 Capital leases - net 1,583 2,630 1,811 2,253 2,948 Current assets 67,568 67,967 67,558 61,002 65,568 Deferred charges and other assets 32,511 36,550 38,135 38,575 37,668 ------ ------ ------ ------ ------ Total $401,004 $388,991 $364,412 $342,421 $331,348 ======== ======== ======== ======== ======== Capitalization and Liabilities: Capitalization: Common equity $128,922 $122,132 $113,906 $105,070 $ 99,175 Long-term debt 120,000 100,102 95,266 75,418 77,923 ------- ------- ------ ------ ------ Total Capitalization 248,922 222,234 209,172 180,488 177,098 Capital lease obligations 963 1,617 930 1,359 2,237 Current liabilities 89,583 102,508 94,169 101,666 91,382 Deferred credits and reserves 61,536 62,632 60,141 58,908 60,631 ------ ------ ------ ------ ------ Total $401,004 $388,991 $364,412 $342,421 $331,348 ======== ======== ======== ======== ========
Income Statement Data: Operating revenues $167,978 $187,140 $169,878 $163,668 $165,327 Cost of gas sold (88,127)(102,455) (87,188) (83,631) (87,458) ------- -------- ------- ------- ------- Operating margin 79,851 84,685 82,690 80,037 77,869 Operating expenses (including income taxes) (58,993) (61,829) (60,536) (58,512) (60,331) ------- ------- ------- ------- ------- Utility operating income 20,858 22,856 22,154 21,525 17,538 Other income - net of income taxes 1,290 1,218 3,033 1,509 1,880 Merger-related expenses - net of income taxes (1,126) - - - - Interest and debt expense (8,734) (8,034) (8,709) (9,270) (8,409) ------ ------ ------ ------ ------ Net income $ 12,288 $16,040 $16,478 $13,764 $11,009 ======== ======= ======= ======= =======
Capitalization Ratios: Common equity 52% 55% 54% 58% 56% Long-term debt 48% 45% 46% 42% 44%
Common Stock Data: Average shares outstanding 8,781 8,598 8,432 8,294 8,119 Basic earnings per share $1.40 $1.87 $1.95 $1.66 $1.36 (a) Dividends paid per share: $1.37 $1.33 $1.295 $1.275 $1.255 Dividend payout rate 98% 71% 66% 77% 92% Book value per share $14.48 $14.06 $13.37 $12.56 $12.05 Dividends as a percent of book value 9% 9% 10% 10% 10% Market price per share $34.88 $28.81 $21.25 $20.25 $19.25 Market price as a percent of book value 241% 205% 159% 161% 160% Return on average common equity 9.8% 13.6% 15.1% 13.5% 11.4% (a) 1994 is after a restructuring charge of $.24 per share.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
RESULTS OF OPERATIONS
Net Income and Dividends Net income and basic earnings per share were $12,288,000 ($1.40), $16,040,000 ($1.87), and $16,478,000 ($1.95) for the years ended December 31, 1998, 1997, and 1996, respectively. Net income was unfavorably impacted by significantly warmer than 20-year average temperatures in 1998, and favorably impacted by colder than 20-year average temperatures in 1997 and 1996. This is summarized as follows:
1998 1997 1996 ---- ---- ---- Percent colder (warmer) than 20-year average (11.8%) 1.1% 3.0%
Percent colder (warmer) than prior year (12.8%) (1.8%) 0.6%
Other items which had an impact on net income are discussed below. Dividends paid per common share were $1.37 in 1998, $1.33 in 1997 and $1.295 in 1996. The Company has paid dividends for 62 consecutive years, and has increased dividends each year for the past 19 years.
Operating Revenues Operating revenues were $167,978,000 in 1998, $187,140,000 in 1997 and $169,878,000 in 1996. 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"), and changes in gas costs to customers via a cost of gas adjustment clause ("CGAC"). The volumes of gas sold and transported are affected by fluctuations in weather and the number of customers being served. Firm customers increased by 14,500 over the last three years from 140,000 in December 1995 to 154,500 in December 1998, an increase of 10.4%. The chart below summarizes volumes of gas sold and transported and number of firm customers:
1998 1997 1996 ---- ---- ---- (In MMcf) Gas sold Firm 17,575 19,997 19,563 Non-Firm 7 62 648 Gas transported Firm 4,797 3,278 3,918 Non-Firm 2,646 3,791 2,671 ----- ----- ----- Total gas sold and transported (In MMcf) 25,025 27,128 26,800 ====== ====== ======
Firm Customers 154,500 150,000 144,000 ======= ======= =======
Operating revenues decreased $19,162,000, or 10.2%, from 1997 to 1998. This decrease resulted from weather which was 11.8% warmer than normal and 12.8% warmer than last year, and lower gas costs, partially offset by customer growth of 3.1%.
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, despite weather which was 1.8% warmer than the prior year.
Cost of Gas Sold Average cost of gas sold per Mcf was $4.98 in 1998, $5.08 in 1997 and $4.29 in 1996. Cost of gas sold is impacted by changes in sales volumes, the price and mix of gas purchased and used to satisfy demand, and profits from non-firm sales and transportation (substantially all of which flow back to firm sales customers as a credit through the CGAC).
Operating Expenses Operations expense was $27,793,000 in 1998, a decrease of $2,251,000, or 7.5%, from 1997, and $30,044,000 in 1997, a decrease of $328,000, or 1.1%, from 1996. The significant decrease in operations expense in 1998 was due primarily to a one-time decrease in the reserve for uncollectable accounts of approximately $1,137,000 -- a direct result of the unbundling of the Company's rates on November 1, 1998. As of that date, the gas supply or commodity component of bad debt expense is being recovered through the cost of gas adjustment clause, thereby decreasing the Company's bad debt expense by approximately 50%. Other factors which impacted the decrease in operations expense in 1998 were lower bad debt expense in general, lower pension costs and lower insurance expenses. Maintenance expense increased $291,000, or 6.5%, in 1998 from 1997 and increased $27,000, or 0.6%, in 1997 from 1996. The increase in 1998 was primarily due to increased labor costs. Depreciation and amortization expense increased $1,386,000 or 11.5%, in 1998 and $821,000 or 7.3% in 1997. The increase in 1998 was due to an increase in utility property and the completion of significant software systems. The increase in 1997 was due to an increase in utility property. Local property and other taxes decreased 2.0% in 1998 from 1997 and decreased 2.1% in 1997 from 1996. The decreases in 1998 and 1997 were due to reduced property taxes, based on lower tax rates and abatements.
Income Taxes Total Federal income and state franchise taxes decreased $2,156,000, or 21.6%, in 1998 from 1997 due to a lower level of income from utility operations, and increased $884,000, or 9.7%, in 1997 from 1996 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 $393,000 in 1998, $645,000 in 1997 and $2,276,000 in 1996. Other operating income primarily includes the results of the Company's wholly-owned energy trucking subsidiary (Transgas Inc.). Also included are heating and water heating equipment sales and installations. Transgas' 1998 financial results were driven by a 37% decrease in liquefied natural gas ("LNG") hauls leading to a $1,806,000 decrease in energy trucking revenue and a $294,000 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 winter of 1997-98.
Transgas' 1997 financial results were driven by a 50% decrease in 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. Factors potentially 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, Net Non-operating income, net of income taxes, was $897,000 in 1998, $573,000 in 1997 and $757,000 in 1996. Non-operating income includes allowance for funds used during construction, interest income and miscellaneous other income.
Merger Related Expenses, Net The Company recorded $1,126,000 of after-tax merger related expenses in 1998. These costs are associated with the Company's pending merger with Eastern Enterprises.
Interest and Debt Expense Interest and debt expense increased $700,000, or 8.7% in 1998 from 1997. The increase in 1998 was due to increased short-term borrowing balances. Interest and debt expense decreased $675,000, or 7.7%, in 1997. This 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.
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.
Regulatory Matters For the impact of regulatory matters on the Company's operations, please refer to the "Regulatory Matters" section of Item 1 of this report, which is also incorporated by reference herein.
Environmental Matters For the impact of environmental matters on the Company's operations, please refer to the "Environmental Matters" section of Item 1 of this report, which is also incorporated by reference herein.
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 $31,093,000 in 1998, $35,788,000 in 1997, and $26,875,000 in 1996. The Company's long-range plan calls for annual utility expenditures averaging $27,000,000 over the next five years of which over 56% is budgeted for new business.
(In Thousands) 1999 2000 2001 2002 2003 - ------------------------------------------------------------------------------- Distribution $23,100 $23,800 $24,700 $25,600 $26,500 Production 100 400 300 900 100 Information Systems 3,100 2,400 500 400 300 Automated Meter Reading 300 300 300 200 300 General 300 300 300 300 300 --- --- --- --- --- Total Capital $26,900 $27,200 $26,100 $27,400 $27,500 ======= ======= ======= ======= ======= Expenditures
Financing Activities The Company has raised permanent capital during the last three years as follows:
(In Thousands) 1998 1997 1996 ---- ---- ---- Common Stock Under Dividend Reinvestment and Common Stock Purchase Plan and Employee Savings Plan $6,541 $3,621 $3,277 Medium term notes under the first mortgage indenture $40,000 $15,000 $30,000
Long-Term Debt instruments maturing during the years 1999 through 2003 total $102,000 in 1999, $0 in 2000, 2001 and 2002 and $10,000,000 in 2003. Long-term debt with a principal amount of $15 million, which is due in 2027, can be redeemed by the holder in 2002. 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 year-end is shown in the table below: 1998 1997 1996 ---- ---- ---- Equity 52% 55% 54% Long-Term Debt 48% 45% 46%
As of April 1998, the quarterly dividend paid on the Company's Common Stock was increased to $.345 per share or an annualized dividend rate of $1.38 per share.
YEAR 2000
State of Readiness The Company's merger with Eastern Enterprises is expected to be completed by mid-year 1999 and in connection with that pending merger, the Company anticipates addressing certain Year 2000 ("Y2K") issues through system integrations with Boston Gas Company, Eastern's largest gas utility subsidiary. The Company has established, in concert with Boston Gas, a specialized Y2K program team that is implementing a systematic program of inventory, assessment and remediation. Information technology ("IT") systems and embedded chip systems which are "mission critical", i.e. those which would have a significant adverse impact on the operation of the core business of the Company and its subsidiary, Transgas, in the event of a Y2K problem, have been identified. It is anticipated that any necessary testing, upgrading, replacement or other remediation of mission critical IT systems will be completed by the end of the second quarter of 1999. Other "less than critical" IT systems are also scheduled to be checked and tested and/or upgraded, as required, by the end of the second quarter of 1999.
With respect to embedded chip systems, the Company has completed its inventory and is finalizing its assessment and action plan. Testing, upgrading, replacement or other remediation of embedded chips is being scheduled and is anticipated to be completed by the end of the third quarter of 1999. The Company has identified critical third party vendor relationships and is working on determining the Y2K readiness of such vendors. This critical vendor component of the Company's Y2K program is scheduled for completion by the end of the second quarter of 1999. Notwithstanding the Company's efforts with third parties, there can be no assurance that the systems of third parties on which the Company's systems rely will be timely converted or that any such failure to convert by a third party would not have an adverse effect on the Company's operations.
Cost of Year 2000 Remediation Based on its current information, without any system integrations with Boston Gas, the Company believes the cost of its Y2K compliance would approximate $1.5 million. With the system integrations expected with Boston Gas, the Company anticipates actual Y2K remediation costs to be significantly lower than this amount. Substantially all Y2K remediation costs are expected to be incurred in 1999.
Risks of Year 2000 Issues and Contingency Plans Given its efforts to minimize the risk of Y2K failure by its internal systems and its distribution network control systems, the Company believes its worst case scenario would involve failures by a pipeline supplier or by telecommunications, electricity or banking services. A short term interruption in pipeline supplies would require the utilization of locally-stored liquefied natural gas supplies. A telecommunications or electric outage would require the Company to enact business contingency and disaster recovery measures to enable the continuation of service to its customers. The Company has initiated the development of a business contingency plan concerning Y2K risks to its internal systems, embedded chips and significant suppliers. Business processes are expected to be assessed and prioritized by the end of the first quarter of 1999. Detailed plans for critical business processes are expected to be developed and tested by the end of the third quarter of 1999.
PENDING MERGER WITH EASTERN ENTERPRISES
On October 17, 1998, the Company entered into an Agreement and Plan of Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"), a Massachusetts business trust which owns all of the outstanding stock of two other Massachusetts LDC's, Boston Gas Company ("Boston Gas") and Essex Gas Company ("Essex Gas"). The Merger Agreement provides for the merger of the Company with and into a subsidiary of Eastern, as a result of which the Company will become a wholly-owned subsidiary of Eastern (the "Pending Merger"). Pursuant to the Pending Merger, the outstanding shares of the Company's common stock would convert into the right to receive cash and Eastern common stock as set forth in the Merger Agreement. The Pending Merger was approved by shareholders of Colonial and Eastern at separate special shareholder meetings which were held on February 10, 1999. Completion of the Pending Merger is subject to receipt of satisfactory regulatory approvals, including approval of the Massachusetts
Department of Telecommunications and Energy, the Securities and Exchange Commission, and antitrust clearance.
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 conditions, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Consolidated Statements of Income....................................25
Consolidated Balance Sheets..........................................26
Consolidated Statements of Cash Flows................................28
Consolidated Statements of Common Equity.............................29
Notes to Consolidated Financial Statements...........................30
Report of Independent Certified Public Accountants...................42
Report of Management.................................................43
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COLONIAL GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, (In Thousands Except Per Share Amounts) 1998 1997 1996 ---- ---- ---
Operating Revenues ......................... $167,978 $187,140 $169,878 Cost of gas sold ........................... 88,127 102,455 87,188 ------ ------- ------ Operating Margin ........................ 79,851 84,685 82,690 ------ ------ ------ Operating Expenses: Operations .............................. 27,793 30,044 30,372 Maintenance ............................. 4,794 4,503 4,476 Depreciation and amortization ........... 13,435 12,049 11,228 Local property taxes .................... 3,074 3,139 3,189 Other taxes ............................. 2,081 2,122 2,183 ----- ----- ----- Total Operating Expenses .............. 51,177 51,857 51,448 ------ ------ ------ Income Taxes: Federal income tax ...................... 6,482 8,264 7,001 State franchise tax ..................... 1,334 1,708 2,087 ----- ----- ----- Total Income Taxes .................... 7,816 9,972 9,088 ----- ----- ----- Utility Operating Income ................... 20,858 22,856 22,154 ------ ------ ------ Other Operating Income (Expense): Energy Trucking revenues ................ 3,723 5,529 11,031 Energy Trucking expenses, including income taxes and interest ............. (3,690) (5,202) (9,005) ------ ------ ------ Energy Trucking Net Income ............ 33 327 2,026 Other, net of income taxes .............. 360 318 250 --- --- --- Total Other Operating Income .......... 393 645 2,276 --- --- ----- Non-Operating Income, Net of Income Taxes .. 897 573 757 --- --- --- Merger Related Expenses, Net of Income Taxes (1,126) -- -- ------ Income Before Interest and Debt Expense .... 21,022 24,074 25,187 ------ ------ ------ Interest and Debt Expense .................. 8,734 8,034 8,709 ----- ----- -----
Net Income .............................. $12,288 $ 16,040 $16,478 ======= ======== =======
Average Common Shares Outstanding ....... 8,781 8,598 8,432 ===== ===== =====
Basic Earnings per Share ................ $1.40 $1.87 $1.95 ===== ===== =====
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY CONSOLIDATED BALANCE SHEETS
Assets December 31, (In Thousands) 1998 1997 ---- ---- Utility Property: At original cost $394,222 $362,742 Accumulated depreciation (102,009) (88,210) -------- ------- Net Utility Property 292,213 274,532 Non-Utility Property - Net 7,129 7,312 ----- ----- Net Property 299,342 281,844
Capital Leases - Net 1,583 2,630 ----- -----
Current Assets: Cash and cash equivalents 3,125 259 Accounts receivable 14,591 21,788 Allowance for doubtful accounts (1,350) (3,203) Accrued utility revenues 7,876 7,417 Unbilled gas costs 18,195 19,266 Fuel inventory - at average cost 12,712 12,959 Materials and supplies - at average cost 2,906 2,950 Prepayments and other current assets 9,513 6,531 ----- ----- Total Current Assets 67,568 67,967 ------ ------
Deferred Charges and Other Assets: Unrecovered deferred income taxes 8,349 9,014 Unrecovered demand side management costs 6,661 8,273 Unrecovered environmental costs incurred 3,633 3,833 Unrecovered environmental costs accrued 200 707 Unrecovered pension costs 3,307 3,455 Unrecovered transition costs accrued 700 2,800 Excess cost of investments over net assets acquired 2,798 2,798 Other 6,863 5,670 ----- ----- Total Deferred Charges and Other Assets 32,511 36,550 ------ ------
Total Assets $401,004 $388,991 ======== ========
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY CONSOLIDATED BALANCE SHEETS
Capitalization and Liabilities December 31, (In Thousands) 1998 1997 - ------------------------------------------------------------------ Capitalization: Common Equity: Common Stock $29,669 $28,931 Premium on Common Stock 63,080 57,277 Retained earnings 36,173 35,924 ------ ------ Total Common Equity 128,922 122,132 Long-Term Debt 120,000 100,102 ------- ------- Total Capitalization 248,922 222,234 ------- ------- Long-Term Capital Lease Obligations 963 1,617 --- -----
Current Liabilities: Current maturities of long-term debt 102 10,164 Current capital lease obligations 620 1,013 Notes payable 52,000 49,400 Gas inventory purchase obligations 14,125 14,895 Accounts payable 12,186 15,674 Accrued interest 2,698 2,375 Current deferred income taxes 3,830 3,654 Other current liabilities 4,022 5,333 ----- ----- Total Current Liabilities 89,583 102,508 ------ -------
Deferred Credits and Reserves: Deferred income taxes - Funded 44,555 41,443 Deferred income taxes - Unfunded 8,349 9,014 Unamortized investment tax credits 3,072 3,372 Pension reserve 4,424 4,507 Accrued environmental costs 200 707 Accrued transition costs 700 2,800 Other deferred credits and reserves 236 789 --- --- Total Deferred Credits and Reserves 61,536 62,632 ------ ------
Total Capitalization and Liabilities $401,004 $388,991 ======== ========
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, (In Thousands) 1998 1997 1996 - ------------------------------------------------------------------------ Cash Flows From Operating Activities: Net Income $12,288 $16,040 $16,478 Adjustments to reconcile net income to net cash: Depreciation and amortization 14,764 13,334 12,361 Deferred income taxes 3,157 3,208 7,968 Amortization of investment tax credits (300) (300) (268) Provision for uncollectable accounts (601) 1,955 2,146 Other, net (227) 109 171 ---- --- --- 29,081 34,346 38,856 Changes in current assets and liabilities: Accounts receivable and accrued utility revenues 5,486 (6,620) 2,305 Unbilled gas costs 1,071 (28) (9,550) Fuel inventory 247 (1,001) (1,442) Prepayments and other current assets (2,938) 2,003 (4,015) Accounts payable (3,488) 1,130 2,394 Other current liabilities (988) 2,645 (2,929) ---- ----- ------ Net Cash Provided by Operating Activities 28,471 32,475 25,619 ------ ------ ------ Cash Flows From Investing Activities: Utility capital expenditures (31,093) (35,788) (26,875) Non-utility capital expenditures (364) (1,888) (1,367) Change in deferred accounts 972 (842) (1,502) --- ---- ------ Net Cash Used in Investing Activities (30,485) (38,518) (29,744) ------- ------- ------- Cash Flows From Financing Activities: Dividends paid on Common Stock (12,039) (11,435) (10,919) Issuance of Common Stock 6,541 3,621 3,277 Issuance of long-term debt, net of issuance costs 39,11 614,871 29,787 Retirement of long-term debt, including premiums (30,568) (5,152) (11,284) Change in notes payable 2,600 (1,000) (11,435) Change in gas inventory purchase obligations (770) 1,856 699 ---- ----- --- Net Cash Provided by Financing Activities 4,880 2,761 125 ----- ----- --- Net Increase (Decrease) in Cash and Cash Equivalents 2,866 (3,282) (4,000) Cash and Cash Equivalents at Beginning of Year 259 3,541 7,541 --- ----- ----- Cash and Cash Equivalents at End of Year $ 3,125 $ 259 $ 3,541 ======= ======= ======= Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest - net of amount capitalized $10,229 $ 9,465 $ 9,149 Income and state franchise taxes $ 7,238 $ 7,509 $ 8,489
The accompanying notes are an integral part of these statements.
COLONIAL GAS COMPANY CONSOLIDATED STATEMENTS OF COMMON EQUITY
Year ended December 31, (In Thousands Except Per Share Amounts) 1998 1997 1996 ---- ---- ----
Common Stock $3.33 par value; authorized 15,000 shares; outstanding, 8,910 in 1998, 8,688 in 1997, and 8,518 in 1996 Beginning of year $28,931 $28,366 $27,863 Issuance of Common Stock through Dividend Reinvestment and Common Stock Purchase Plan and Employee savings plan (222 shares in 1998, 170 shares in 1997 and 151 shares in 1996) 738 565 503 ---- --- --- ---
End of year $29,669 $28,931 $28,366 ------- ------- -------
Premium on Common Stock Beginning of year $57,277 $54,221 $51,447 Issuance of Common Stock through Dividend Reinvestment and Common Stock Purchase Plan and Employee savings plan 5,803 3,056 2,774 ----- ----- -----
End of year $63,080 $57,277 $54,221 ------- ------- -------
Retained Earnings Beginning of year $35,924 $31,319 $25,760 Net income 12,288 16,040 16,478 Cash dividends on Common Stock ($1.37 a share in 1998, $1.33 a share in 1997 and $1.295 a share in 1996) (12,039) (11,435) (10,919) ---- ------- ------- -------
End of year $36,173 $35,924 $31,319 ------- ------- -------
Total Common Equity $128,922 $122,132 $113,906 ======== ======== ========
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 154,500 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"), 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 $805,000, $594,000, and $437,000 in 1998, 1997 and 1996, 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 $7,876,000 and $7,417,000, as reported in the Consolidated Balance Sheets at December 31, 1998 and 1997, 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. (See Note I).
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 $120,102,000 and $110,266,000 as of December 31, 1998 and 1997, respectively. The fair value of long-term debt was $129,302,000 and $115,700,000 as of December 31, 1998 and 1997, respectively.
Under current regulatory treatment, any premiums paid to refinance long-term debt, would be recovered over the life of new debt, and would not have a significant impact on the Company's results of operations.
Earnings Per Share - The Company determines earnings per share in accordance with the provisions of Statement of Financial Accounting Standards No. 128 "Earnings Per Share" ("SFAS 128"). Earnings per share in computed by dividing net income by the average number of common shares outstanding during the period. The Company has no dilutive shares. 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, 1998, the Company has a liability of $8,349,000 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) 1998 1997 1996 ---- ---- ---- Charged (credited) to operations: Current $4,396 $5,188 $1,104 Deferred: Accelerated depreciation 1,933 1,688 2,202 Unbilled gas costs 146 (98) 2,929 Demand side management costs (394) 88 747 Pension costs 124 301 449 Recovery of unfunded deferred taxes 398 398 398 Debt expense (53) (53) (53) Environmental response costs (65) (58) (246) Bad debt 355 889 (167) Miscellaneous (57) 221 (94) Amortization of investment tax credits (301) (300) (268) ---- ---- ---- Total 6,482 8,264 7,001 ----- ----- ----- Charged (credited) to other income (605) 312 1,599 ---- --- ----- Total Federal income tax expense $5,877 $8,576 $8,600 ====== ====== ======
The effective Federal income tax rate and the reasons for the difference from the statutory Federal income tax rate are as follows:
1998 1997 1996 ---- ---- ---- Statutory Federal income tax rate 35% 35% 35% Increases (reductions) in taxes resulting from: Amortization of investment tax credits (2) (1) (1) Recovery of unfunded deferred taxes 2 2 2 Miscellaneous items (3) (1) (2) -- -- -- Effective Federal income tax rate 32% 35% 34% == == ==
Temporary differences which gave rise to the following deferred tax assets (liabilities) are:
December 31, (In Thousands) 1998 1997 ---- ---- Deferred Tax Assets: Construction contributions $ 832 $ 891 Other 222 227 --- --- Total deferred tax assets 1,054 1,118 ----- -----
Deferred Tax Liabilities: Accelerated depreciation (43,662) (41,345) Unbilled gas costs (3,830) (3,654) Demand side management costs (2,293) (2,765) Environmental response costs (1,423) (1,502) Cost of removal (3,143) (3,033) Other (3,437) (2,930) Total deferred tax liabilities (57,788) (55,229) ------- ------- Total deferred taxes $(56,734) $(54,111) ======== ========
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. By vote of the Company's Board of Directors on October 17, 1998, rights are not triggered by the Pending Merger with Eastern. 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 1998 1997 ---- ---- First mortgage bonds: 8.05% Series CG due 1999 $ --- $ 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 6.88% Series MTA-5 due 2008 10,000 10,000 6.81% Series MTA-6 due 2027 2002 15,000 15,000 6.38% Series MTA-7 due 2008 10,000 --- 6.86% Series MTB-1 due 2028 20,000 --- 5.50% Series MTB-2 due 2003 10,000 --- ---- - ---- ------ Total 120,000 110,000 Note payable 102 266 --- --- Less: Long-term debt due within one year (102) (10,164)
Total long-term debt $120,000 $100,102 ======== ========
The aggregate amount of maturities for the years 1999 through 2003 are $102,000 in 1999, and $10,000,000 in 2003. 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 in place 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 $30 million has been issued as of December 1998. The bonds with a put date noted above can be redeemed by the holder within a 30 day period in the year indicated.
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 four banks which expires in September 2000. 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: Eurodollar (LIBOR), prime, or a competitive bid option. At December 31, 1998, the credit available under the bank line of credit was $8,875,000. The weighted average interest rates for short-term debt were 5.80% and 6.18% at December 31, 1998 and 1997, 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 1998, 1997 and 1996 approximately $620,000, $564,000, and $500,000, respectively, of interest costs were incurred by the trust.
Note F: Lease Obligations
The Company leases certain 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 $2,510,000, and $7,702,000 at December 31, 1998 and 1997, respectively. In 1998, the Company purchased certain facilities used in its operations which were previously leased. Accumulated amortization on assets held under capital leases amounted to approximately $927,000 and $5,072,000 at December 31, 1998 and 1997, respectively. Total rental expense for the years 1998, 1997 and 1996 approximated $1,150,000 and $1,527,000, and $1,493,000, respectively. At December 31, 1998, the future minimum payments (including interest) under the Company's lease agreements are: $641,000 in 1999; $489,000 in 2000; $390,000 in 2001; $195,000 in 2002; $21,000 in 2003; 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 $689,000, $625,000 and $570,000 for 1998, 1997 and 1996, 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) 1998 1997 1996 ---- ---- ----
Service cost $1,220 $1,042 $1,036 Interest cost on projected benefit obligation 3,492 3,427 3,267 Expected return on plan assets (4,170) (6,711) (4,710) Net amortization and deferral 625 3,673 1,882 --- ----- ----- Net periodic pension cost $1,167 $1,431 $1,475 ====== ====== ======
Assumptions used in actuarial calculations were as follows:
Year Ended December 31, 1998 1997 1996 ---- ---- ----
Weighted average discount rate 7.00% 7.00% 7.75% Future compensation increases 4.00% 4.00% 4.00% Expected long-term rate of return on assets 9.50% 9.00% 9.00%
The following tables set forth the reconciliation of the plans' benefit obligation and fair value of assets for the years ended December 31, 1998 and 1997:
(In Thousands) 1998 1997 - ---------------------------------------------------------------------- Reconciliation of benefit obligation: Obligation at January 1 $50,989 $45,016 Service cost 1,220 1,042 Interest cost 3,492 3,427 Amendments 176 (497) Actuarial (gain) loss 393 5,067 Benefit payments (3,138) (3,066) ------ ------ Obligation at December 31 $53,132 $50,989 ======= =======
Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $48,332 $41,458 Actual return on plan assets 5,161 7,583 Employer contributions 1,484 2,357 Benefit payments (3,138) (3,066) ------ ------ Fair value of plan assets at December 31 $51,839 $48,332 ======= =======
The funded status of the plans at December 31, 1998 and 1997 is as follows:
1998 1997 Assets Accumulated Assets Accumulated Exceed Benefits Exceed Benefits Accumulated Exceed Accumulated Exceed (In Thousands) Benefits Assets Benefits Assets - --------------------------------------------------------------------------------
Projected benefit obligations: Vested ...................... $(33,064) $(12,823) $(32,420) $(12,020) Nonvested ................... (952) (1,194) (828) (1,088) ---- ------ ---- ------ Accumulated .................... (34,016) (14,017) (33,248) (13,108) Due to recognition of future ... (4,814) (285) (4,497) (136) ------ ---- ------ ---- salary increases Total .............. (38,830) (14,302) (37,745) (13,244) Plan assets at fair value ...... 41,050 10,789 38,765 9,567 ------ ------ ------ ----- Projected benefit obligation less than (in excess of).. plan assets 2,220 (3,513) 1,020 (3,677) Unrecognized net (gain) loss ... (793) 895 78 729 Unrecognized transition amount . 1,048 699 1,223 331 Unrecognized prior service cost. (33) 1,863 (60) 2,424 Additional liability accrued ... - (3,172) - (3,350) ------ ------ ------ ------
Prepaid (accrued) pension costs $ 2,442 $ (3,228) $ 2,261 $ (3,543) ======== ======== ======== ========
Assets of the employee benefit plans are invested in domestic and international equities, domestic and international fixed income securities, real estate and other short-term debt instruments.
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 1998, 1997 and 1996 was $509,000, $410,000, and $501,000, 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 trusts under Section 501(c)(9) and Section 401(h) of the Internal Revenue Code.
The following tables set forth the reconciliation of the plans' benefit obligation and fair value of plan assets for the years ended December 31, 1998 and 1997:
(In Thousands) 1998 1997 - ---------------------------------------------------------------------- Reconciliation of benefit obligation: Obligation at January 1 $7,179 $6,229 Service cost 138 113 Interest cost 534 477 Amendments (314) 0 Actuarial (gain) loss 1,272 685 Benefit payments (251) (325) ---- ---- Obligation at December 31 $8,558 $7,179 ====== ======
Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $5,163 $4,614 Actual return on plan assets 527 779 Employer contributions 0 95 Benefit payments (251) (325) ---- ---- Fair value of plan assets at December 31 $5,439 $5,163 ====== ======
The following table sets forth the plan's funded status reconciled with the amounts recognized in the Company's financial statements at December 31, 1998 and 1997:
(In Thousands) 1998 1997 - ---------------------------------------------------------------------- Accumulated postretirement benefit obligation: Retirees $(4,579) $(4,564) Fully eligible active plan (1,767) (1,192) participants Other active plan participants (2,212) (1,423) ------ ------ Total (8,558) (7,179) Plan assets at fair value 5,439 5,163 ----- ----- Accumulated postretirement benefit obligation (3,119) (2,016) in excess of plan assets Unrecognized net (gain) from past experience different from that assumed and from changes in assumptions (193) (1,351) Unrecognized transition obligation 3,481 4,045 ----- ----- Prepaid postretirement benefit cost $ 169 $ 678 ======= =======
Net periodic postretirement benefit cost included the following components:
Year Ended December 31, (In Thousands) 1998 1997 1996 - ---------------------------------------------------------------------------- Service cost - benefits attributable to service $138 $113 $137 during the period Interest cost on accumulated postretirement 534 477 461 benefit obligation Expected return on plan assets (412) (375) (507) Net amortization and deferral 249 195 410 --- --- --- Net periodic postretirement benefit $509 $410 $501 ==== ==== ==== 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 1999; the rate of increase for medical costs was assumed to decrease gradually to 4.5% for 2002 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, 1998 by $1,175,000 and the aggregate of the service and the interest cost components of net periodic postretirement benefit cost for the year then ended by $111,000. The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.0%, 7.0%, and 7.75% for 1998, 1997 and 1996, respectively. The expected long-term rate of return on plan assets was 9.5%, 9.0%, and 9.0% for 1998, 1997, and 1996, respectively, for assets in the Section 401(h) accounts and, after estimated taxes, was 6.25%, 6.0%, and 6.0% for 1998, 1997, and 1996, respectively, for assets in the Section 501(c)(9) trust.
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 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 be approximately $700,000. The Company is recovering these costs from its customers, as approved by the DTE in October 1994. As of December 31, 1998, the Company has recorded on the balance sheet a long-term liability of $700,000 ("Accrued Transition Costs") and, based upon expected rate recovery, has recorded a regulatory asset of $700,000 ("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, 1998, the Company had incurred environmental response costs of $12,582,000 of which $8,949,000 has been recovered from customers to date. As of December 31, 1998, the Company has recorded on the balance sheet a long-term liability of $200,000 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. In 1998, the DTE conducted an industry-wide proceeding on the calculation of lost margins that gas companies are allowed to recover as a result of their conservation or demand side management ("DSM") programs. The Company has been using a calculation method, approved by the DTE in previous individual Company filings, based on the useful life of installed conservation measures. As of this date, the DTE has not yet issued its decision in the industry-wide proceeding. The decision could result in a shortening of the time period for calculating lost DSM margins to less than the full useful life of installed measures. A shortening of the period would result in some decrease in operating revenues, but it is uncertain at this time whether or by how much the period would be shortened and, therefore, what impact it would have on the Company.
Note J: Quarterly Financial Data (Unaudited) (In Thousands Except Per Share Amounts) Basic Utility Earnings Dividends Operating Net (Loss) Paid Per Operating Income Income Per Common Quarter Ended Revenues (Loss) (Loss) Share Share December 31 $52,125 $7,773 $5,060 $.57 $.345 September 30 12,347 (3,246) (5,213) (.59) .345 June 30 25,684 256 (1,771) (.20) .345 March 31 77,822 16,075 14,212 1.63 .335
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
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.
Note K: Merger
On October 17, 1998, the Company entered into an Agreement and Plan of Reorganization (the "Merger Agreement") with Eastern Enterprises ("Eastern"), a Massachusetts business trust which owns all of the outstanding stock of two other Massachusetts LDC's, Boston Gas Company ("Boston Gas") and Essex Gas Company ("Essex Gas"). The Merger Agreement provides for the merger of the Company with and into a subsidiary of Eastern, as a result of which the Company will become a wholly-owned subsidiary of Eastern (the "Pending Merger"). Pursuant to the Pending Merger, the outstanding shares of the Company's common stock would convert into the right to receive cash and Eastern common stock as set forth in the Merger Agreement. The Pending Merger was approved by shareholders of Colonial and Eastern at separate special shareholder meetings which were held on February 10, 1999. Completion of the Pending Merger is subject to receipt of satisfactory regulatory approvals, including approval of the Massachusetts Department of Telecommunications and Energy, the Securities and Exchange Commission, and antitrust clearance.
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, 1998 and 1997, and the related consolidated statements of income, cash flows, and common equity for each of the three years in the period ended December 31, 1998. 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, 1998 and 1997, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
Boston, Massachusetts s/Grant Thornton LLP January 15, 1999 Grant Thornton LLP
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.
s/F. L. Putnam, III s/Nickolas Stavropoulos
F. L. Putnam, III Nickolas Stavropoulos President and Chief Executive Executive Vice President-Finance, Officer Marketing and Chief Financial Officer
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and .......Financial Disclosure.
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
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 in the Company's definitive Proxy Statement for its 1999 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 in the Company's definitive Proxy Statement for its 1999 annual meeting of stockholders under the caption "SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE".
Item 11.
Item 11. Executive Compensation.
The information required to be reported hereunder is incorporated by reference to the information in the Company's definitive Proxy Statement for its 1999 annual meeting of stockholders under the captions "EXECUTIVE COMPENSATION" and under the subheading "Directors' Compensation" of the caption "INFORMATION ABOUT NOMINEES AND INCUMBENT DIRECTORS".
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information required to be reported hereunder is incorporated by reference to the information in the Company's definitive Proxy Statement for its 1999 annual meeting of stockholders under the caption "SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT".
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information required to be reported hereunder is incorporated by reference to the information in the Company's definitive Proxy Statement for its 1999 annual meeting of stockholders under the captions "INFORMATION ABOUT NOMINEES AND INCUMBENT DIRECTORS" and "EXECUTIVE COMPENSATION".
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) 1. Financial Statements
The list of Financial Statements filed as part of this Form 10-K Report is set forth in Item 8 on page 23.
2. Financial Statement Schedules
The Financial Statement Schedules and report thereon required to be filed as part of this Form 10-K Report are as follows:
Schedule Page Number Description Number
Report of Independent Certified Public Accountants on Schedule 49
II Valuation and Qualifying Accounts for the three years ended December 31, 1998 50
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
2 Agreement and Plan of Reorganization Incorporated herein by and between Eastern Enterprises by reference. and Colonial Gas Company dated as of October 17, 1998, filed as Exhibit 2.1 to the Registrant's Form 8-K Report dated October 21, 1998.
3a Restated Articles of Organization of Incorporated herein Colonial Gas Company dated April 19, by reference. 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 as Incorporated herein of June 15, 1992, filed as Exhibit by reference. 4(c) to Form 10-Q of the Registrant for the quarter ended June 30, 1992.
4c Second Supplemental Indenture dated Incorporated herein as of September 27, 1995, filed as by reference. Exhibit 4(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1995.
4d Amendment to Second Supplemental Incorporated herein Indenture dated as of October 12, by reference. 1995, filed as Exhibit 4(d) to the Registrant's Form 10-K for the fiscal year ended December 31, 1995.
4e Third Supplemental Indenture dated as Incorporated herein of December 15, 1995, filed as by reference. Exhibit 4f to the Registrant's Form S-3 Registration Statement dated January 5, 1998.
4f Fourth Supplemental Indenture dated Incorporated herein as of March 1, 1998, filed as Exhibit by reference. 4(l) to Registrant's Form 10-Q for the quarter ended March 31, 1998.
4g Form of Rights Agreement dated as of Incorporated herein December 1, 1993, between Colonial by reference. Gas Company 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 Registrant's Registration Statement on Form 8-A filed on November 22, 1993 (File No. 0-10007).
4h Amendment to Rights Agreement between Filed herewith as Colonial Gas Company and BankBoston, Exhibit 4h. N.A. dated as of October 17, 1998.
4i 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.
4j 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.
4k 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.
4l 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.
4m Trust Agreement dated as of June 22, Incorporated herein 1990 between Colonial Gas Company (as by reference. 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 Form Employment Agreement dated as of Incorporated herein October 13, 1998, for Colonial Gas by reference. Company corporate officers, filed as Exhibit 10.l to the Registrant's Form 10-Q for the quarter ended September 30, 1998.
10b Employment Agreement dated as of Incorporated herein October 13, 1998, by and between by reference. Colonial Gas Company, Transgas Inc. and V.W. Baur, filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarter ended September 30, 1998.
10c Colonial Gas Company Retention Bonus Incorporated herein Plan, effective as of October 19, by reference. 1998, filed as Exhibit 10.3 to the Registrant's Form 10-Q for the quarter ended September 30, 1998.
10d Rate increase deferral incentive Incorporated herein policy of Colonial Gas Company dated by reference. January 1, 1995, filed as Exhibit 10(xx) to the Registrant's Form 10-K for the fiscal year ended December 31, 1994.
10e 1997 Transitional Executive Incentive Incorporated herein Plan of Colonial Gas Company, filed by reference. as Exhibit 10e to the Registrant's Form 10-K for the fiscal year ended December 31, 1997.
10f Colonial Gas Company Executive Incorporated herein Performance and Equity Incentive Plan by reference. included as Appendix A to the Proxy Statement for the Company's 1998 Annual Meeting and to the Prospectus included in the Registration Statement on Form S-4 of the Company's subsidiary, Colonial Energy, filed on March 6, 1998. (Commission File No. 333-47441.)
21a Subsidiaries of the Registrant. Filed herewith as
23a Consent of Independent Certified Filed herewith as Public Accountants. Exhibit 23a.
Exhibits 10a through 10f above are management contracts or compensatory plans or arrangements in which the executive officers of the Company participate or participated during time periods covered by this Form 10-K Report.
(b) Reports on Form 8-K. As reported on the Form 8-K filed by the Company with the Securities and Exchange Commission on October 21, 1998, the Company and Eastern Enterprises entered into an Agreement and Plan of Reorganization dated October 17, 1998, a copy of which was filed as an Exhibit to that Form 8-K.
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 15, 1999, which is included 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 15, 1999
SCHEDULE II
COLONIAL GAS COMPANY AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS For the Three Years Ended December 31, 1998 (In Thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS CHARGED BALANCE AT TO COSTS BALANCE AT BEGINNING AND END OF DESCRIPTION OF PERIOD EXPENSES DEDUCTIONS PERIOD
For the Year Ended December 31, 1998
Reserve for uncollectable $3,203 $ 537 $1,253 (1) $1,350 accounts ====== ======= ====== == ====== $1,137 (2) ====== ==
Reserve for insurance claims $1,593 $ 237 $ 422 $1,408 ====== ====== ======= ======
For the Year Ended December 31, 1997
Reserve for uncollectable $2,715 $1,956 $1,468 (1) $3,203 accounts ====== ====== ====== == ======
Reserve for insurance claims $1,486 $ 675 $ 568 $1,593 ====== ======= ======= ======
For the Year Ended December 31, 1996
Reserve for uncollectable $2,205 $2,127 $1,617 (1) $2,715 accounts ====== ====== ====== == ======
Reserve for insurance claims $1,233 $ 836 $ 583 $1,486 ====== ====== ====== ======
- ----------------------------- (1) Accounts charged off, net of collections. (2) Transfer of gas cost portion of reserve as of November 1, 1998, based on unbundling of rates
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. February 24, 1999 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, February 24, 1999 F. L. Putnam, Jr. Director
s/Nickolas Stavropoulos Executive Vice President - February 24, 1999 Nickolas Stavropoulos Finance, Marketing and Chief Financial Officer, Director (Principal Financial Officer)
s/D. W. Carroll Vice President and Treasurer February 24, 1999 D. W. Carroll (Principal Accounting Officer)
s/V.W. Baur Director February 24, 1999 V.W. Baur
s/J. P. Harrington Director February 24, 1999 J. P. Harrington
s/H. C. Homeyer Director February 24, 1999 H. C. Homeyer
s/R. L. Hull Director February 24, 1999 R. L. Hull
s/R. A. Perkins Director February 24, 1999 R. A. Perkins
s/F. L. Putnam, III President and Chief February 24, 1999 F. L. Putnam, III Executive Officer, Director
s/J. F. Reilly, Jr. Director February 24, 1999 J. F. Reilly, Jr.
s/A. B. Sides, Jr. Director February 24, 1999 A. B. Sides, Jr
s/M. M. Stapleton Director February 24, 1999 M. M. Stapleton
INDEX TO EXHIBITS INCLUDED HEREWITH
4h Amendment to Rights Agreement between Colonial Gas Company and BankBoston, N.A. dated as of October 17, 1998.
21a Subsidiaries of the Registrant.
23a Consent of Independent Certified Public Accountants.