UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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|X| Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 For the fiscal year ended December 31, 1998
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OR
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|_| Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
COMMISSION FILE NUMBER 0-10007
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COLONIAL GAS COMPANY
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(Exact name of registrant as specified in its charter)
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Massachusetts 04-1558100
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
40 Market Street, Lowell, Massachusetts 01852
(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code: (978) 322-3000
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Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $3.33 par value
(Title of Class)
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes |X| No |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K |X|
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of January 31, 1999 was $309,761,917.
The number of shares of the registrant's common stock outstanding as of
January 31, 1999 was 8,914,012.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive proxy statement for the 1999
annual meeting of shareholders to be held on April 21, 1999 are incorporated by
reference into Part III.
<PAGE>
COLONIAL GAS COMPANY
FORM 10-K ANNUAL REPORT FOR THE YEAR ENDING DECEMBER 31, 1998
TABLE OF CONTENTS
PART I
Item 1. Business 3
Item 1A. Executive Officers of the Registrant 11
Item 2. Properties 12
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security Holders 12
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters 13
Item 6. Selected Financial Data 14
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 44
PART III
Item 10. Directors and Executive Officers of the Registrant 44
Item 11. Executive Compensation 44
Item 12. Security Ownership of Certain Beneficial Owners
and Management 45
Item 13. Certain Relationships and Related Transactions 45
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 45
<PAGE>
PART I
Item 1. Business
THE COMPANY
Colonial Gas Company ("Colonial" or the "Company"), a Massachusetts
corporation formed in 1849, is primarily a regulated natural gas 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.
<PAGE>
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:
<PAGE>
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
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(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.
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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. Legal Proceedings.
See Item 1, "Business--Environmental Matters" above, which is incorporated
herein.
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.
<PAGE>
PART II
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
1998
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
1997
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
<PAGE>
Item 6. Selected Financial Data.
<TABLE>
<CAPTION>
FINANCIAL AND OPERATING STATISTICS
(For the Years Ending December 31) 1998 1997 1996 1995 1994
Operating Revenues (In Thousands)
<S> <C> <C> <C> <C> <C>
Residential - Sales .............. $113,008 $121,649 $108,879 $103,991 $104,812
Commercial and industrial - Sales 48,112 59,163 54,324 52,926 56,358
Firm transportation .............. 2,643 1,941 1,843 1,294 1,210
Non-firm sales ................... 1,809 2,530 2,985 3,745 2,429
Non-firm transportation .......... 632 631 453 424 401
Other ............................ 1,774 1,226 1,394 1,288 117
----- ----- ----- ----- ---
Total operating revenues .... $167,978 $187,140 $169,878 $163,668 $165,327
======== ======== ======== ======== ========
Gas Sold (MMcf)
Residential ...................... 11,390 12,492 12,094 11,361 11,190
Commercial and industrial ........ 6,185 7,505 7,469 7,199 7,526
Non-firm ......................... 7 62 648 1,148 729
- -- --- ----- ---
Total gas sales ............. 17,582 20,059 20,211 19,708 19,445
Gas Transported (MMcf)
Firm ............................. 4,797 3,278 3,918 2,537 6,090
Non-firm ......................... 2,646 3,791 2,671 3,224 4,185
----- ----- ----- ----- -----
Total gas transported ....... 7,443 7,069 6,589 5,761 10,275
----- ----- ----- ----- ------
Total gas sold and transported 25,025 27,128 26,800 25,469 29,720
====== ====== ====== ====== ======
Gas Purchased (MMcf)
Pipeline ......................... 15,100 14,763 15,115 14,659 14,392
Underground storage .............. 2,500 3,605 3,346 3,270 3,112
LNG - as liquid .................. 704 680 1,067 844 1,129
LNG - as vapor ................... 692 1,680 1,528 1,574 1,236
Propane .......................... 2 5 1 8 25
- - - - --
Total gas purchased ......... 18,998 20,733 21,057 20,355 19,894
Company use and other ............ (1,416) (674) (846) (647) (449)
---- ---- ---- ---- ----
Available for sale ......... 17,582 20,059 20,211 19,708 19,445
====== ====== ====== ====== ======
Customers - End of period (a)
Residential ...................... 139,575 135,655 130,161 126,323 122,024
Commercial and industrial ........ 14,725 14,100 13,565 13,387 13,018
Firm transportation .............. 175 30 19 11 8
Non-firm sales ................... 10 22 25 27 21
Non-firm transportation .......... 15 15 5 2 2
-- -- - - -
Total customers - end of .... 154,500 149,822 143,775 139,750 135,073
======= ======= ======= ======= =======
period
Average Annual Mcf Sold/Customer
Residential ...................... 83 94 94 91 96
Commercial and industrial ........ 429 543 554 545 584
Average Annual Bill/Customer
Residential ...................... $ 821 $ 915 $ 849 $ 837 $ 900
Commercial and industrial ........ $ 3,338 $ 4,277 $ 4,031 $ 4,009 $ 4,375
Average Revenue/Mcf
Residential ...................... $ 9.89 $ 9.73 $ 9.03 $ 9.20 $ 9.37
Commercial and industrial ........ $ 7.78 $ 7.88 $ 7.27 $ 7.35 $ 7.49
Residential Heating Customers as a
% of all Residential Customers 91% 91% 90% 90% 90%
Highest Daily Sendout (Mcf) ...... 169,088 183,063 170,984 199,275 204,896
Percent Colder (Warmer) than
20-year average .................. (11.8)% 1.1% 3.0% 2.4% 5.0%
</TABLE>
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(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.
<PAGE>
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.
<PAGE>
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%.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements
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
<PAGE>
[This page intentionally left blank]
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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,
<PAGE>
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.
<PAGE>
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
====== ====== ======
<PAGE>
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.
<PAGE>
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
<PAGE>
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
====== ====== ======
<PAGE>
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
======= =======
<PAGE>
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.
<PAGE>
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
======= =======
<PAGE>
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
<PAGE>
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.
<PAGE>
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
1998
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
1997
December 31 $62,275 $9,481 $7,814 $.90 $.335
September 30 14,877 (3,043) (4,566) (.53) .335
June 30 26,927 (556) (2,501) (.29) .335
March 31 83,061 16,974 15,293 1.79 .325
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.
<PAGE>
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
<PAGE>
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
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
.......Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required to be reported hereunder pursuant to Item 401 of
Regulation S-K for the Company's Directors is incorporated by reference to the
information 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. 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".
<PAGE>
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. 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. 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.
<PAGE>
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).
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
[EXHIBIT 4h TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1998]
AMENDMENT TO RIGHTS AGREEMENT
This AMENDMENT, dated as of October 17, 1998, is between Colonial
Gas Company, a Massachusetts corporation (the "Company"), and BankBoston, N.A.,
as rights agent (the "Rights Agent").
Recitals
A. The Company and the Rights Agent are parties to a Rights
Agreement dated as of December 1, 1993 (the "Rights Agreement").
B. Eastern Enterprises ("Eastern") and the Company have entered into
an Agreement and Plan of Reorganization (the "Merger Agreement") pursuant to
which the Company will merge (the "Merger") with and into a Massachusetts
corporation to be formed as a wholly-owned subsidiary of Eastern ("Merger Sub").
The Board of Directors of the Company has approved the Merger Agreement and the
Merger.
C. Pursuant to Section 27 of the Rights Agreement, the Board of
Directors of the Company has determined that an amendment to the Rights
Agreement as set forth herein is necessary and desirable in connection with the
foregoing and the Company and the Rights Agent desire to evidence such amendment
in writing.
Accordingly, the parties agree as follows:
1. Amendment of Section 1(a). Section 1(a) of the Rights Agreement
is amended to add the following sentence at the end thereof:
"Notwithstanding anything in this Rights Agreement to the contrary,
neither Eastern nor any of its existing or future Affiliates or
Associates shall be deemed to be an Acquiring Person solely by
virtue of (i) the execution of the Merger Agreement, (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger, or (iii) the consummation of the other
transactions contemplated by the Merger Agreement."
2. Amendment of Section 1(ah). Section 1(ah) of the Rights Agreement
is amended to add the following proviso at the end thereof:
"; provided, however, that no Triggering Event shall result solely
by virtue of (i) the execution of the Merger Agreement, (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger, or (iii) the consummation of the other
transactions contemplated by the Merger Agreement."
3. Amendment of Section 1. Section 1 of the Rights Agreement is
further amended to add the following subparagraphs at the end thereof:
(ai) "Eastern" shall mean Eastern Enterprises, a
Massachusetts business trust.
<PAGE>
(aj) "Merger" shall have the meaning set forth in the
Merger Agreement.
(ak) "Merger Agreement" shall mean the Agreement and Plan of
Reorganization dated as of October 17, 1998, by and between Eastern
and the Company, as amended from time to time."
4. Amendment of Section 3(a). Section 3(a) of the Rights Agreement
is amended to add the following sentence at the end thereof:
"Notwithstanding anything in this Rights Agreement to the contrary,
a Distribution Date shall not be deemed to have occurred solely by
virtue of (i) the execution of the Merger Agreement, (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger, or (iii) the consummation of the other
transactions contemplated by the Merger Agreement."
5. Amendment of Section 7(a). Section 7(a) of the Rights Agreement
is amended to add the following sentence at the end thereof:
"Notwithstanding anything in this Rights Agreement to the contrary,
neither (i) the execution of the Merger Agreement; (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger; nor (iii) the consummation of the other
transactions contemplated in the Merger Agreement, shall be deemed
to be events that cause the Rights to become exercisable pursuant to
the provisions of this Section 7 or otherwise."
6. Amendment of Section 11. Section 11 of the Rights Agreement is
amended to add the following sentence after the first sentence of said Section:
"Notwithstanding anything in this Rights Agreement to the contrary,
neither (i) the execution of the Merger Agreement; (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger; nor (iii) the consummation of the other
transactions contemplated in the Merger Agreement, shall be deemed
to cause the Rights to be adjusted or to become exercisable in
accordance with this Section 11."
7. Amendment of Section 13. Section 13 of the Rights Agreement is
amended to add the following sentence at the end thereof:
"Notwithstanding anything in this Rights Agreement to the contrary,
neither (i) the execution of the Merger Agreement; (ii) the
acquisition of Common Stock pursuant to the Merger Agreement or the
consummation of the Merger; nor (iii) the consummation of the other
transactions contemplated in the Merger Agreement, shall be deemed
to be events of the type described in this Section 13 or to cause
the Rights to be adjusted or to become exercisable in accordance
with Section 13."
<PAGE>
8. Effectiveness. This Amendment shall be deemed effective as of the
date first written above, as if executed on such date. Except as amended hereby,
the Rights Agreement shall remain in full force and effect and shall be
otherwise unaffected hereby.
9. Miscellaneous. This Amendment shall be deemed to be a contract
made under the laws of the Commonwealth of Massachusetts and for all purposes
shall be governed by and construed in accordance with the laws of such state
applicable to contracts to be made and performed entirely within such state.
This Amendment may be executed in any number of counterparts, each of such
counterparts shall for all purposes be deemed to be an original, and all such
counterparts shall together constitute but one and the same instrument. If any
provision, covenant or restriction of this Amendment is held by a court of
competent jurisdiction or other authority to be invalid, illegal or
unenforceable, the remainder of the terms, provisions, covenants and
restrictions of this Amendment shall remain in full force and effect and shall
in no way be effected, impaired or invalidated.
EXECUTED under seal as of the date set forth above.
COLONIAL GAS COMPANY
By:s/Nickolas Stavropoulos
Nickolas Stavropoulos
Executive Vice President-Finance,
Marketing and CFO
RIGHTS AGENT:
BANKBOSTON, N.A.
By: s/Joshua P. McGinn
Name: Joshua P. McGinn
Title: Sr. Account Manager
[END OF EXHIBIT 4h TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1998]
[EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1998]
Colonial Gas Company
Subsidiaries of Registrant
Subsidiaries Organized in: Ownership:
(a) Transgas, Inc. Massachusetts 100%
(a) CGI Transport Limited(b) Canada 100%
(a) Included in consolidated financial statements.
(b) Owned by Transgas.
[END OF EXHIBIT 21a TO COLONIAL GAS COMPANY
FORM 10-K FOR YEAR ENDED DECEMBER 31, 1998]
[EXHIBIT 23a TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1998]
EXHIBIT 23a
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our reports dated January 15, 1999, accompanying the consolidated
financial statements and schedule incorporated by reference or included in the
Annual Report on Form 10-K of Colonial Gas Company and subsidiaries for the year
ended December 31, 1998. We hereby consent to the incorporation by reference of
said reports in the Colonial Gas Company Registration Statements on Forms S-8,
as amended (File No. 33-47099, File No. 33-54091, and File No. 33-34067); on
Forms S-3 (File No. 333-48561 and File No. 333-43715); and on Form S-4 (File No.
333-47441).
GRANT THORNTON LLP
Boston, Massachusetts
February 26, 1999
[END OF EXHIBIT 23a TO COLONIAL GAS COMPANY
10-K FOR YEAR ENDED DECEMBER 31, 1998]
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<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
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