- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1999
or
Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from to
Commission File Number 0-10007
COLONIAL GAS COMPANY
(Exact Name of Registrant As Specified In Its Charter)
Massachusetts 04-3480443
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
One Beacon Street (617) 742-8400
Boston, Massachusetts 02108 (Registrant's Telephone Number)
(Address of Principal Executive
Offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Exchange
------------------- --------
None None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 1, 2000.
All common stock, 100 shares, are held by Eastern Enterprises.
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
COLONIAL GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 1999
TABLE OF CONTENTS
Item No. Topic Page
-------- ----- ----
PART I
1. Business...................................................... 1
General....................................................... 1
Markets and Competition....................................... 1
Gas Throughput................................................ 2
Gas Supply.................................................... 2
Regulation.................................................... 3
Seasonality and Working Capital............................... 4
Environmental Matters......................................... 5
Employees..................................................... 5
2. Properties.................................................... 5
3. Legal Proceedings............................................. 5
4. Submission of Matters to a Vote of Security Holders........... 5
Glossary...................................................... 6
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 7
6. Selected Financial Data....................................... 7
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 7
8. Financial Statements and Supplementary Data................... 9
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 9
PART III
10. Directors and Executive Officers of the Registrant............ 10
11. Executive Compensation........................................ 10
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 10
13. Certain Relationships and Related Transactions................ 10
PART IV
14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K..................................................... 11
PART I
Item 1. Business.
General
Colonial Gas Company (the "Company"), a Massachusetts corporation formed in
1849, is engaged in the transportation and sale of natural gas to
approximately 158,000 residential, commercial and industrial customers in 24
municipalities located northwest of Boston ("Merrimack Valley" area) and on
Cape Cod. All of the common stock of the Company is held by Eastern
Enterprises ("Eastern"), which is headquartered in Weston, Massachusetts. On
August 31, 1999, the Company completed a merger with Eastern in a transaction
with an enterprise value of approximately $474 million. In effecting the
transaction, Eastern paid $150 million in cash, net of cash acquired and
including transaction costs, issued approximately 4.2 million shares of common
stock valued at $186 million and assumed $138 million of debt.
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides local transportation services and gas supply to all
customer classes. The Company's services are available on a firm and non-firm
basis. Firm transportation service and sales are provided under rate tariffs
and/or contracts filed with the Massachusetts Department of Telecommunications
and Energy ("Department"), that typically obligate the Company to provide
service without interruption throughout the year. Non-firm transportation
service and sales are generally provided to large commercial/industrial
customers who can use gas or another energy source interchangeably. Non-firm
services are provided through individually negotiated contracts and, in most
cases, the price charged takes into account the price of the customer's
alternative fuel.
The Company offers unbundled services to all commercial/industrial users,
who are allowed to purchase local transportation from the Company separately
from the purchase of gas supply, which the customer may buy from third party
suppliers. The Company views these third party suppliers as partners in
marketing gas and increasing throughput and expects to work closely with them
to facilitate the unbundling process and ensure a smooth transition,
especially in the tracking and processing of transactions. The Company has
also implemented a program to educate commercial/industrial customers about
the opportunity to purchase gas from third-party suppliers, while still
relying on the utility for delivery. As of December 31, 1999, the Company had
approximately 360 firm transportation customers. Service to all residential
customers currently is on a bundled basis. Unbundled service to residential
customers is expected to be offered beginning in June 2000. While the
migration of customers to transportation-only service will lower the Company's
revenues, it has no impact on its operating earnings. The Company earns all of
its margins on the local distribution of gas and none on the resale of the
commodity itself.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers
and electricity suppliers, throughout its service territory. The Company
currently serves approximately 53% of the potential customers within its
service territory.
Gas Throughput
The following table in BCF provides information with respect to the volumes
of gas sold and transported by the Company during the three years 1997-1999.
Years Ended
December 31,
--------------
1999 1998 1997
---- ---- ----
Residential................................................... 12.0 11.4 12.5
Commercial and industrial..................................... 6.8 6.2 7.6
---- ---- ----
Total sales................................................. 18.8 17.6 20.1
Transportation of customer-owned gas.......................... 6.4 7.4 7.0
---- ---- ----
Total throughput............................................ 25.2 25.0 27.1
==== ==== ====
Total firm throughput....................................... 22.1 22.4 23.3
==== ==== ====
In 1999, residential customers comprised 90% of the Company's customer
base, while commercial and industrial establishments accounted for the
remaining 10%. Volumetrically, residential customers accounted for 37% of
total throughput and 42% of total firm throughput, while commercial and
industrial customers accounted for 63% of total throughput and 58% of total
firm throughput. Approximately 62% of commercial and industrial customers'
total throughput was transportation-only services.
No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 1999.
Gas Supply
The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1997-1999.
Years Ended
December 31,
----------------
1999 1998 1997
---- ---- ----
Natural gas purchases...................................... 15.8 15.1 14.8
Underground storage withdrawal............................. 3.1 2.5 3.6
Liquefied natural gas ("LNG") purchases.................... 1.2 1.4 2.4
---- ---- ----
Total source of supply................................... 20.1 19.0 20.8
Company use, unbilled and other............................ (1.3) (1.4) (.7)
---- ---- ----
Total sales.............................................. 18.8 17.6 20.1
==== ==== ====
Year to year variations in storage gas and unbilled gas reflect variations
in end-of-year customer requirements, due principally to weather. Given the
ready availability of supply, the Company purchased approximately 70% of its
peak pipeline supplies under firm short-term and spot contracts. The balance
of peak day pipeline requirements is purchased directly from producers and
marketers pursuant to long-term contracts which have been reviewed and
approved by the Department or by the Federal Energy Regulatory Commission
("FERC").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights
2
under these contracts. The interstate pipeline companies that provide firm
transportation service to the Company's service territory, the peak daily and
annual capacity and the contract expiration dates are as follows:
Capacity in BCF
----------------- Expiration
Pipeline Daily Annual Dates
-------- ------- -------- ----------
Algonquin Gas Transmission Company
("Algonquin")............................... .046 14.7 2000-2012
Tennessee Gas Pipeline Company
("Tennessee")............................... .072 26.3 2003-2013
In 1999, the Company restructured its long-term capacity contracts on
Tennessee Gas Pipeline. As a result, no contract expires on Tennessee before
2003. Less than 1% of the Company's capacity on Algonquin expires in 2000. In
addition, the Company has firm capacity contracts on interstate pipelines
upstream of Algonquin and Tennessee pipelines to transport natural gas
purchased by the Company from producing regions.
The Company has contracted with pipeline companies and others for the
storage of natural gas in underground storage fields located in Pennsylvania,
New York, Maryland and West Virginia. These contracts provide storage capacity
of 4.7 BCF and peak day deliverability of .044 BCF. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are purchased
from foreign and domestic sources.
In the fall of 1999, the Company, and its affiliates Boston Gas Company and
Essex Gas Company, entered into a portfolio management contract with El Paso
Energy Marketing, Inc. For a three year term commencing November 1, 1999, El
Paso will provide all of the city gate supply requirements to the three
companies at market prices and manage certain of the companies' upstream
capacity, underground storage and term supply contracts. The Department
approved the contract in October 1999.
The Company has two agreements with Distrigas of Massachusetts Corporation
that expire on October 31, 2000, which allow the Company to purchase up to
10,000 Dekatherms ("Dth") per day for 151 days and 5,000 Dth per day for 365
days of liquefied natural gas ("LNG") in either liquid or vapor form. The
Company anticipates that both agreements will be renewed. The Company may
reduce quantities purchased if normal sales fall below normal heating season
sendout.
Peak day firm throughput in BCF was 0.106 in 1999 and 0.093 in 1998 for the
Company's Merrimack Valley service area and 0.069 in 1999 and 0.060 in 1998
for the Company's Cape Cod service area. The Company provides for peak period
demand through a least cost portfolio of pipeline, storage and supplemental
supplies. Supplemental supplies include LNG and propane air, which are
vaporized at points on the Company's distribution system. The Company's
Merrimack Valley service area has on-system LNG and propane air facilities
which have an aggregate sendout capacity of approximately .080 BCF per day.
The Company also operates on-system facilities in the Cape Cod service area
capable of providing approximately .036 BCF per day. The Company considers its
peak day sendout capacity, based on its total supply resources, to be adequate
to meet the requirements of its firm customers.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause ("CGAC"), billed to firm sales
customers, allows for the semiannual adjustment of billing rates for firm gas
sales to reflect the actual cost of gas delivered to customers, including
demand charges for capacity on the interstate pipeline system. Similarly,
through its local distribution adjustment clause ("LDAC"), the Company
recovers the actual costs of approved energy efficiency programs, and the cost
of remediating former manufactured gas plant sites from all firm customers,
including those purchasing gas supply from third parties.
3
In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The freeze on base rates is subject only to certain exogenous
factors, such as changes in tax laws, accounting changes, or regulatory,
judicial, or legislative changes. As a result of the rate plan, the Company
discontinued its application of SFAS No. 71, as described in Note 1 of Notes
to Consolidated Financial Statements. Many of the administrative, operations
and maintenance functions of the Company have been integrated with those of
Boston Gas.
All of the Company's 15,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had 360 firm transportation customers. Under the approved service
unbundling program, commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which LDC tariffs for all residential
customers will substantially conform. The Model Terms and Conditions approved
by the Department are consistent with the Department's order of February 1,
1999, which provided that, for a five year transition period, LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata
basis to marketers selling gas supply to the LDC's customers. The approved
mandatory assignment method eliminates the possibility that the costs of
upstream capacity purchased by the Company to serve firm customers will be
absorbed by the LDC or other customers through the transition period. The
Department also found that, through the transition period, LDC's will retain
primary responsibility for upstream capacity planning and procurement to
assure that adequate capacity is available at Massachusetts city gates to
support customer requirements and growth. In year three of the five-year
transition period, the Department intends to evaluate the extent to which the
upstream capacity market for Massachusetts is workably competitive based on a
number of factors, and accelerate or decelerate the transition period
accordingly. The Department's Model Terms and Conditions also require that
LDC's provide default and peaking supply services at cost-based rates.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years past the installation of DSM measures. This ruling changes the Company's
previous calculation method as approved by the Department. However, based on
the Department's order approving the merger and rate plan, the Company can
recover any resulting reduction in lost margins as an exogenous adjustment.
Seasonality and Working Capital
The Company's revenues, earnings and cash flow are highly seasonal as most
of its transportation services and sales are directly related to temperature
conditions. Since the majority of its revenues are billed in the November
through April heating season, significant cash flows are generated from late
winter to early summer. In addition, through the cost of gas adjustment
clause, the Company bills its customers over the heating season for the
majority of the pipeline demand charges paid by the Company over the entire
year. This difference, along with other costs of gas distributed but unbilled,
is reflected as deferred gas costs and is financed through short-term
borrowings. Short-term borrowings are also required from time to time to
finance normal business operations. As a result of these factors, short-term
borrowings are generally highest during the late fall and early winter.
4
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site,
related satellite disposal sites, one non-MGP site and one federal superfund
site. Information with respect to the remediation of MGP related sites may be
found in Note 9 of Notes to Consolidated Financial Statements. Such
information is incorporated herein by reference.
Employees
As of December 31, 1999, the Company had 336 employees, 46% of whom are
organized in local unions with which the Company has collective bargaining
agreements that expire in 2001 and 2003.
Item 2. Properties.
The Company has two principal operations centers and two principal LNG
storage facilities. One of the storage facilities is located in Tewksbury,
Massachusetts and has a capacity of approximately 1.0 BCF of LNG and the other
is located in South Yarmouth, Massachusetts and has a capacity of
approximately .18 BCF of LNG. In addition, the Company owns its former
corporate headquarters, a 36,000 square foot facility located in Lowell,
Massachusetts.
On December 31, 1999, the Company's distribution system included
approximately 3,200 miles of gas mains, 139,000 services and 159,000 active
customer meters.
The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned in fee.
In 1999, the Company's capital expenditures were $20 million. Capital
expenditures were principally made for improvements to the distribution
system, for system expansion to meet customer growth and for productivity
improvements. The Company plans to spend approximately $23 million for similar
purposes in 2000.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of Security Holders in the fourth quarter
of 1999.
5
Glossary
BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.
Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and peak-
shaving services.
Capacity--The capability of pipelines and supplemental facilities to deliver
and/or store gas.
City Gate--Physical interconnection between an interstate pipeline and the
local distribution company.
Core Customer--Generally, customers with no readily available energy
services alternative.
Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.
Firm Service--Sales and/or transportation service provided without
interruption throughout the year. Uninterrupted seasonal services are also
available for less than 365 days. Firm services are provided under either filed
rate tariffs or through individually negotiated contracts.
Gas Marketer (Broker)--A non-regulated buyer and seller of gas.
Interstate Transportation--Transportation of gas by an interstate pipeline
to the city gate.
Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to end-
user facilities.
Local Transportation Service--Transportation of gas by the LDC from the city
gate to the customer's burner tip.
Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.
Non-Firm Service--Sales and transportation service offered at a lower level
of reliability and cost. Under this service, the LDC can interrupt customers on
short notice, typically during the winter season. Non-firm services are
provided through individually negotiated contracts and, in most cases, the
price charged takes into account the price of the customer's energy
alternative.
Throughput--Gas volume delivered to customers through the LDC's gas
distribution system.
Unbundled Service--Service that is offered and priced separately, such as
separating the cost of gas commodity delivered to the LDC's city gate from the
cost of transporting the gas from the city gate to the end user. Unbundled
services can also include daily or monthly balancing, back-up or stand-by
services and pooling. With unbundled services, customers have the opportunity
to select only the services they desire.
6
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Eastern is the holder of record of all of the outstanding common equity
securities of the Company. Dividends paid to Eastern amounted to $2.5 million
in 1999.
Item 6. Selected Financial Data.
Not required.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
RESULTS OF OPERATIONS
1999 Compared to 1998
Weather for the four months ended December 1999 was 7% warmer than normal.
The four months ended December 1999 included amortization of goodwill of $2.0
million and interest on the $100 million advance from Eastern of $1.6 million.
Weather for the eight months ended August 1999 was 5% warmer than normal.
The eight months ended August 1999 included merger-related costs of $3.8
million incurred by the Company prior to the merger.
1998 Compared to 1997
Net earnings applicable to common stock for 1998 were $12.3 million, a
decrease of $3.7 million, or 23%, as compared to 1997.
Revenues in 1998 decreased $19.2 million or 10% compared to 1997. This
decrease resulted from weather which was 12% warmer than normal and 13% warmer
than the prior year, and lower gas costs, partially offset by customer growth
of 3%.
Operating margin decreased $4.8 million, or 6%, due to the warmer weather
referenced earlier.
Operating expenses decreased $1.7 million or 3%. The decrease in operations
expense was due primarily to an adjustment to the reserve for uncollectable
accounts of approximately $1.1 million, a result of the unbundling of the
Company's rates on November 1, 1998. As of that date, the gas cost component
of bad debt expense is being recovered through the cost of gas adjustment
clause. Other factors that impacted the decrease in operations expense were
lower pension costs and insurance expense. Depreciation and amortization
expense increased $1.4 million, or 11%, reflecting continued investment in
system expansion and replacement and the completion of software systems
projects.
YEAR 2000 ISSUE
The Company experienced no significant issues as a result of the transition
from December 31, 1999 to January 1, 2000. The Company does not expect to
incur any significant Year 2000 related costs beyond January 2000. On August
31, 1999, the Company was merged with Eastern, the parent company of Boston
Gas Company. In connection with the merger, the Company addressed any
remaining Year 2000 issues through conversion to systems operated by Boston
Gas Company.
FORWARD-LOOKING INFORMATION
This report and other Company reports and statements issued or made from
time to time contain certain "forward-looking statements" concerning projected
future financial performance, expected plans or future
7
operations. The Company cautions that actual results and developments may
differ materially from such projections or expectations.
Investors should be aware of important factors that could cause actual
results to differ materially from forward-looking projections or expectations.
These factors include, but are not limited to: the effect of strategic
initiatives on earnings and cash flow, the impact of any merger-related
activities, the ability to successfully integrate natural gas distribution
operations, temperatures above or below normal, changes in economic
conditions, including interest rates, regulatory and court decisions and
developments with respect to previously disclosed environmental liabilities.
Most of these factors are difficult to predict accurately and are generally
beyond the control of the Company.
LIQUIDITY AND CAPITAL RESOURCES
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 Company expects capital expenditures for 2000 to be approximately $23
million. Capital expenditures will be largely for improvements to the
distribution system and for system expansion to meet customer growth.
The Company believes that projected cash flow from operations, in
combination with currently available resources, is more than sufficient to
meet 2000 capital expenditures, working capital requirements, dividend
payments and normal debt repayments.
OTHER MATTERS
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause, billed to firm sales customers,
allows for the semiannual adjustment of billing rates for firm gas sales to
reflect the actual cost of gas delivered to customers, including demand
charges for capacity on the interstate pipeline system. Similarly, through its
local distribution adjustment clause, the Company recovers the actual costs of
approved energy efficiency programs and the cost of remediating former
manufactured gas plant sites from all firm customers, including those
purchasing gas supply from third parties.
In connection with the acquisition by Eastern Enterprises in 1999 on July
15, 1999, the Department approved the merger and rate plan, resulting in a
2.2% reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The freeze on base rates is subject only to certain exogenous
factors, such as changes in tax laws, accounting changes, or regulatory,
judicial, or legislative changes. As a result of the rate plan, the Company
discontinued its application of SFAS No. 71, as described in Note 1 of Notes
to Consolidated Financial Statements. Many of the administrative, operations
and maintenance functions of the Company have been integrated with those of
Boston Gas.
All of the Company's 15,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had 360 firm transportation customers. Under the approved service
unbundling program, commercial and industrial customers migrating from firm
sales to firm transportation are assigned, at cost, a pro-rata share of the
upstream pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which LDC tariffs for
8
all residential customers will substantially conform. The Model Terms and
Conditions approved by the Department are consistent with the Department's
order of February 1, 1999, which provided that, for a five year transition
period, LDC contractual commitments to upstream capacity will be assigned on a
mandatory, pro rata basis to marketers selling gas supply to the LDC's
customers. The approved mandatory assignment method eliminates the possibility
that the costs of upstream capacity purchased by the Company to serve firm
customers will be absorbed by the LDC or other customers through the
transition period. The Department also found that, through the transition
period, LDC's will retain primary responsibility for upstream capacity
planning and procurement to assure that adequate capacity is available at
Massachusetts city gates to support customer requirements and growth. In year
three of the five-year transition period, the Department intends to evaluate
the extent to which the upstream capacity market for Massachusetts is workably
competitive based on a number of factors, and accelerate or decelerate the
transition period accordingly. The Department's Model Terms and Conditions
also require that LDC's provide default and peaking supply services at cost-
based rates.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years past the installation of DSM measures. This ruling changes the Company's
previous calculation method as approved by the Department. However, based on
the Department's order approving the merger and rate plan, the Company can
recover any resulting reduction in lost margins as an exogenous adjustment.
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site and
related satellite disposal sites, one non-MGP site and one federal superfund
site, as described in Note 9 of Notes to Consolidated Financial Statements.
The Company has recorded a liability of approximately $850,000, which
represents its best estimate at this time of remediation costs. However, there
can be no assurance that actual costs will not vary considerably from this
estimate.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
9
PART III
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11. Executive Compensation.
Not required.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13. Certain Relationships and Related Transactions.
Not required.
10
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.
(3) List of Exhibits.
2 Agreement and Plan of Reorganization by and between Eastern Enterprises
and Colonial Gas Company dated as of October 17, 1998, filed as Exhibit
2.1 to the Registrant's Form 8-K Report dated October 21, 1998.*
3.1 Restated Articles of Organization for Colonial Gas Company dated August
5, 1999. (Filed herewith).
3.2 By-Laws of Colonial Gas Company dated August 5, 1999. (Filed herewith).
4.1 Second Amended and Restated First Mortgage Indenture dated as of June 1,
1992, filed as Exhibit 4(b) to Form 10-Q of the Registrant for the
quarter ended June 30, 1992.*
4.2 First Supplemental Indenture dated as of June 15, 1992, filed as Exhibit
4(c) to Form 10-Q of the Registrant for the quarter ended June 30,
1992.*
4.3 Second Supplemental Indenture dated as of September 27, 1995, filed as
Exhibit 4(c) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1995.*
4.4 Amendment to Second Supplemental Indenture dated as of October 12, 1995,
filed as Exhibit 4(d) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
4.5 Third Supplemental Indenture dated as of December 15, 1995, filed as
Exhibit 4(f) to the Registrant's Form S-3 Registration Statement dated
January 5, 1998.*
4.6 Fourth Supplemental Indenture dated as of March 1, 1998, filed as
Exhibit 4(l) to the Registrant's Form 10-Q for the quarter ended March
31, 1998.*
4.7 Form of Rights Agreement dated as of December 1, 1993, between Colonial
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).*
4.8 Amendment to Rights Agreement between Colonial Gas Company and
BankBoston, N.A. dated as of October 17, 1998, filed as Exhibit 4(h) to
the Registrant's Form 10-K for the fiscal year ended December 31, 1998.*
4.9 Revolving Credit Agreement for Colonial Gas Company dated as of
September 12, 1997, filed as Exhibit 4(e) to Form 10-Q of the Registrant
for the quarter ended September 30, 1997.*
4.10 Revolving Credit Agreement for Massachusetts Fuel Inventory Trust 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.*
4.11 Purchase Contract dated as of June 27, 1990 between Massachusetts Fuel
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 the quarter ended June 30, 1990.*
4.12 Security Agreement and Assignment of Contracts dated as of September 12,
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.*
11
4.13 Trust Agreement dated as of June 22, 1990 between Colonial Gas Company
(as Trustor) and Shawmut Bank, N.A. (as Trustee), filed as Exhibit 10
(d) to Form 8-K of the Registrant for the quarter ended June 30, 1990.*
10.1 Storage Service Agreement with Penn-York Energy Corporation, dated as of
December 21, 1984, filed as Exhibit 10 (r) to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1984.*
10.2 Gas Transportation Contract for Firm Reserved Service with Iroquois,
dated February 7, 1991, filed as Exhibit 10 (v) to the Registrant's
Annual Report on Form 10-K for the fiscal year ended December 31, 1990.*
10.3 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-E), dated June 1, 1993,
filed as Exhibit 10 (p) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.4 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (q) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.5 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (r) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.6 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (s) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.7 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-E), dated June 1, 1993,
filed as Exhibit 10 (t) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.8 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (u) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.9 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1, 1993,
filed as Exhibit 10 (v) to the Registrant's Annual Report on From 10-K
for the fiscal year ended December 31, 1993.*
10.10 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated June 1, 1993,
filed as Exhibit 10 (w) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.11 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 1996 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.12 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FTS-8), dated June 1, 1993,
filed as Exhibit 10 (y) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.13 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FTS-7), dated June 1, 1993,
filed as Exhibit 10 (z) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.14 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 7,918 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.15 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 2,222 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
10.16 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 104 dth per day (under Rate Schedule FT-1),
dated June 1, 1993. (Filed herewith).
12
10.17 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated August 1, 1993,
filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.18 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
1993, filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.19 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
1993, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.20 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
1993, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.21 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule FTNN), dated October 1, 1993, filed as
Exhibit 10 (rr) to the Registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1993.*
10.22 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS), dated October 1, 1993, filed as
Exhibit 10 (ss) to the Registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1993.*
10.23 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract no. 400009, dated
November 1, 1998. (Filed herewith).
10.24 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FT-1), dated October 1, 1993,
filed as Exhibit 10 (uu) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.25 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
1993, filed as Exhibit 10 (vv) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.26 Service Agreement between National Fuel Gas Supply Corporation and
Colonial Gas Company (under Rate Schedule EFT), dated October 28, 1993,
filed as Exhibit 10 (ww) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.27 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated September 1,
1993, filed as Exhibit 10 (xx) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.28 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AIT-1), dated September 15,
1993, filed as Exhibit 10 (yy) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.29 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated October 1, 1993,
filed as Exhibit 10 (zz) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.30 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FT-1), dated August 18, 1994,
filed as Exhibit 10 (kk) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.31 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated August 29, 1994,
filed as Exhibit 10 (ll) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.32 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
filed as Exhibit 10 (mm) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
13
10.33 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29, 1994,
filed as Exhibit 10 (nn) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994.*
10.34 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule SS-1), dated November 30,
1994, filed as Exhibit 10 (oo) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.35 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated November 30,
1994, filed as Exhibit 10 (pp) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.36 Letter Agreement between Algonquin Gas Transmission Company and Colonial
Gas Company, Regarding transfer of transportation entitlements, dated
March 28, 1994, filed as Exhibit 10 (qq) to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994.*
10.37 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (ss) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.38 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (tt) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1994.*
10.39 Firm Natural Gas Transportation agreement between Tennessee Gas Pipeline
and Colonial Gas Company (under Rate Schedule NET-Northeast), dated
August 1, 1995, filed as Exhibit 10 (qq) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1995.*
10.40 Gas Transportation Agreement between Tennessee Gas Pipeline Company and
Colonial Gas Company (under Rate Schedule FT-A), dated June 1, 1995,
filed as Exhibit 10 (rr) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1995.*
10.41 Amendment No. 1 (dated July 1, 1995 to Gas Storage Contract between
Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate
Schedule FS), dated December 1, 1994 (which superseded contract dated
September 1, 1993), filed as Exhibit 10 (ss) to the Registrant's Form
10-K for the fiscal year ended December 31, 1995.*
10.42 Amendment to Gas Transportation Contract for Firm Reserved Service with
Iroquois Gas Transmission System, L.P., dated September 1, 1995, filed
as Exhibit 10 (tt) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
10.43 Service Agreement between Algonquin Transmission Company and Colonial
Gas Company (Under Rate Schedule AFT-1), dated December 1, 1995, filed
as Exhibit 10 (uu) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1995.*
10.44 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated August 25, 1999.
(Filed herewith).
10.45 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract No. 300114, dated
November 1, 1998. (Filed herewith).
10.46 Service Agreement between CNG Transmission Corporation and Colonial Gas
Company (under Rate Schedule GSS-II), contract No. 300115, dated
November 1, 1998. (Filed herewith).
10.47 Amended Service Agreement between Texas Eastern Transmission Corporation
and Colonial Gas Company (under Rate Schedules CDS & FT-1) dated January
6, 1999. (Filed herewith).
10.48 Redacted Gas Resources Portfolio Management and Gas Sales Agreement
between Colonial Gas Company and El Paso Energy Marketing Company dated
September 14, 1999, as amended. (Filed herewith as Exhibit 10.1 to Form
10-K of Eastern Enterprises for the year ended December 31, 1999, and
incorporated herein by reference).
14
10.49 Contract Restructuring Agreement between Colonial Gas Company and
Tennessee Gas Pipeline dated August 2, 1999. (Filed herewith).
10.50 Form Employment Agreement dated as of October 13, 1998, for Colonial Gas
Company corporate officers, filed as Exhibit 10.l to the Registrant's
Form 10-Q for the quarter ended September 30, 1998.*
10.51 Employment Agreement dated as of October 13, 1998, by and between
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.*
10.52 Colonial Gas Company Retention Bonus Plan, effective as of October 19,
1998, filed as Exhibit 10.3 to the Registrant's Form 10-Q for the
quarter ended September 30, 1998.*
10.53 Rate increase deferral incentive policy of Colonial Gas Company dated
January 1, 1995, filed as Exhibit 10 (xx) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1994.*
10.54 1997 Transitional Executive Incentive Plan of Colonial Gas Company,
filed as Exhibit 10e to the Registrant's Form 10-K for the fiscal year
ended December 31, 1997.*
10.55 Colonial Gas Company Executive Performance and Equity Incentive Plan
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).*
23a Consent of Independent Certified Public Accountants.
23b Consent of Independent Certified Public Accountants.
27 Financial Data Schedule for the four months ended December 31, 1999 and
the eight months ended August 31, 1999.
There were no reports on Form 8-K filed in the Fourth Quarter of 1999.
- --------
* Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
and Regulations under the Securities Exchange Act of 1934, reference is
made to the document previously filed with the Commission.
15
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Colonial Gas Company (Registrant)
Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza
Senior Vice President and
Treasurer
(Principal Financial and
Accounting Officer)
Date: March 14, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 14th day of March, 2000.
Signature Title
--------- -----
Chester R. Messer Director and President
___________________________________________
Chester R. Messer
Anthony J. DiGiovanni Director and Senior Vice President
___________________________________________
Anthony J. DiGiovanni
Joseph F. Bodanza Director and Senior Vice President and
___________________________________________ Treasurer (Principal Financial and
Joseph F. Bodanza Accounting Officer)
J. Atwood Ives Director
___________________________________________
J. Atwood Ives
Fred C. Raskin Director
___________________________________________
Fred C. Raskin
Walter J. Flaherty Director
___________________________________________
Walter J. Flaherty
L. William Law, Jr. Director
___________________________________________
L. William Law, Jr.
16
COLONIAL GAS COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
Reports of Independent Public Accountants........................ F-18 and F-19
Consolidated Statements of Earnings for the Four Months Ended
December 31, 1999, Eight
Months Ended August 31, 1999, and Two Years Ended December 31,
1998............................................................ F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998.... F-3 and F-4
Consolidated Statements of Retained Earnings for the Four Months
Ended December 31, 1999, Eight Months Ended August 31, 1999, and
Two Years Ended December 31, 1998............................... F-5
Consolidated Statements of Cash Flows for the Four Months Ended
December 31, 1999, Eight Months Ended August 31, 1999, and Two
Years Ended December 31, 1998................................... F-6
Notes to Consolidated Financial Statements...................... F-7 to F-17
Interim Financial Information for the Two Years Ended December
31, 1999 (Unaudited)............................................ F-20
Schedules for the Three Years Ended December 31, 1999:
II--Valuation and Qualifying Accounts......................... F-21 to F-24
Schedules other than those listed above have been omitted as the
information has been included in the consolidated financial statements and
related notes or is not applicable nor required.
F-1
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Operating revenues...... $54,098 $122,626 $167,978 $187,140
Cost of gas sold........ 26,087 65,320 88,127 102,455
------- -------- -------- --------
Operating margin........ 28,011 57,306 79,851 84,685
------- -------- -------- --------
Operating expenses:
Operations............ 9,101 19,818 27,793 30,044
Maintenance........... 1,151 4,835 4,794 4,503
Depreciation and
amortization......... 2,857 10,086 13,435 12,049
Amortization of
goodwill............. 2,008 -- -- --
Income taxes.......... 3,406 3,639 7,134 9,972
Taxes, other than
income............... 1,626 3,861 5,155 5,261
Merger related
expenses............. -- 3,788 1,808 --
------- -------- -------- --------
Total operating
expenses............. 20,149 46,027 60,119 61,829
------- -------- -------- --------
Operating earnings...... 7,862 11,279 19,732 22,856
Other earnings (loss),
net.................... 237 (20) 485 624
------- -------- -------- --------
Earnings before interest
expense................ 8,099 11,259 20,217 23,480
------- -------- -------- --------
Interest expense:
Long-term debt........ 2,844 5,689 8,130 8,113
Other, including
amortization of debt
expense.............. 2,569 1,244 604 (79)
Less--Interest during
construction......... (27) (194) (805) (594)
------- -------- -------- --------
Total interest
expense.............. 5,386 6,739 7,929 7,440
------- -------- -------- --------
Net earnings............ $ 2,713 $ 4,520 $ 12,288 $ 16,040
======= ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
------------------------
1999 1998
--------- -------------
(In Thousands)
(Predecessor)
Gas plant, at cost.................................... $ 390,447 $ 389,777
Construction work-in-progress......................... 2,914 7,136
Less-Accumulated depreciation....................... (109,628) (102,936)
--------- ---------
Net plant......................................... 283,733 293,977
--------- ---------
Non-Utility Property, Net............................. -- 6,948
--------- ---------
Current assets:
Cash................................................ 389 3,125
Accounts receivable, less reserves of $2,677 at
December 31, 1999 and $2,551 at December 31, 1998.. 15,987 13,241
Accrued utility margin.............................. 8,074 7,876
Deferred gas costs.................................. 13,803 18,195
Natural gas and other inventories, at average cost.. 11,581 12,712
Materials and supplies, at average cost............. 2,277 2,906
Current income taxes................................ 4,182 --
Prepaid expenses.................................... 330 9,513
--------- ---------
Total current assets.............................. 56,623 67,568
--------- ---------
Other assets:
Excess of cost over fair value of acquired net
assets, less amortization.......................... 239,045 --
Deferred charges and other assets................... 4,646 32,511
--------- ---------
Total other assets................................ 243,691 32,511
--------- ---------
Total assets...................................... $ 584,047 $ 401,004
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
Capitalization:
Common stockholder's investment--
Common stock, $1 par value--
Authorized and outstanding--100 shares at December
31, 1999............................................. $ -- $ --
Common Stock, $3.33 par value--
Authorized shares--15,000,000 at December 31, 1998;
Issued shares--8,910,000 at December 31, 1998......... -- 29,669
Amounts in excess of par value........................ 225,667 63,080
Retained earnings..................................... 229 36,173
-------- --------
Total common stockholder's investment............... 225,896 128,922
Long-term obligations, less current portion............. 121,021 120,963
-------- --------
Total capitalization................................ 346,917 249,885
-------- --------
Advances from parent company............................ 100,000 --
-------- --------
Current liabilities:
Current portion of long-term obligations.............. 646 722
Notes payable......................................... 29,000 52,000
Gas inventory financing............................... 15,009 14,125
Accounts payable...................................... 16,578 12,186
Accounts payable--affiliates.......................... 17,916 --
Accrued interest...................................... 2,936 2,698
Customer deposits..................................... 644 818
Refunds due customers................................. 5,331 --
Other................................................. 389 7,034
-------- --------
Total current liabilities........................... 88,449 89,583
-------- --------
Reserves and deferred credits:
Unrecovered deferred income taxes..................... -- 8,349
Deferred income taxes................................. 32,276 44,555
Unamortized investment tax credits.................... 2,811 3,072
Postretirement benefits obligation.................... 5,136 --
Other................................................. 8,458 5,560
-------- --------
Total reserves and deferred credits................. 48,681 61,536
-------- --------
Total capitalization and liabilities................ $584,047 $401,004
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Balance at beginning of
period................. $ -- $36,173 $ 35,924 $ 31,319
Net earnings.......... 2,713 4,520 12,288 16,040
Cash dividends on
common stock......... (2,484) (6,255) (12,039) (11,435)
------- ------- -------- --------
Balance at end of
period................. $ 229 $34,438 $ 36,173 $ 35,924
======= ======= ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Cash flows from
operating activities:
Net earnings........... $ 2,713 $ 4,520 $ 12,288 $ 16,040
Adjustments to
reconcile net earnings
to cash provided by
operating activities:
Depreciation and
amortization......... 4,865 10,086 14,764 13,334
Deferred taxes........ 404 (12,683) 3,157 3,208
Other changes in
assets and
liabilities:
Accounts receivable.. (4,548) 1,802 5,344 (3,581)
Accrued utility
margin.............. (7,420) 7,222 (459) (1,084)
Accounts payable--
affiliates.......... 15,084 2,832 -- --
Inventories.......... 1,120 640 247 (1,001)
Deferred gas costs... (13,888) 18,280 1,071 (28)
Accounts payable..... 5,666 (1,274) (3,488) 1,130
Federal and state
income taxes........ (3,406) (776) (2,164) 2,708
Refunds due
customers........... (202) 5,533 (669) 1,445
Other................ (7,279) 17,351 (648) (538)
-------- -------- -------- --------
Cash (used for)
provided by
operating
activities......... (6,891) 53,533 29,443 31,633
-------- -------- -------- --------
Cash flows from
investing activities:
Capital expenditures... (7,105) (12,715) (31,457) (37,676)
-------- -------- -------- --------
Cash flows from
financing activities:
Changes in notes
payable, net.......... 10,000 (33,000) 2,600 (1,000)
Changes in inventory
financing............. 4,139 (3,255) (770) 1,856
Issuance of long-term
debt, net of issuance
cost.................. -- -- 39,116 14,871
Retirement of long-term
debt, including
premiums.............. -- (102) (30,568) (5,152)
Issuance of common
stock................. -- 1,399 6,541 3,621
Cash dividends paid on
common stock.......... (2,484) (6,255) (12,039) (11,435)
-------- -------- -------- --------
Cash provided by
(used for)
financing
activities......... 11,655 (41,213) 4,880 2,761
-------- -------- -------- --------
Increase (decrease) in
cash................... (2,341) (395) 2,866 (3,282)
Cash at beginning of
period................. 2,730 3,125 259 3,541
-------- -------- -------- --------
Cash at end of period... $ 389 $ 2,730 $ 3,125 $ 259
======== ======== ======== ========
Supplemental disclosure
of cash flow
information:
Cash paid during the
year for:
Interest, net of
amounts
capitalized........ $ 1,657 $ 8,434 $ 10,229 $ 9,465
Income taxes........ $ 4,376 $ 3,595 $ 7,238 $ 7,509
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
General
The Company is a gas distribution company engaged in the transportation and
sale of natural gas to residential, commercial and industrial customers. The
Company's service territory includes 24 municipalities located northwest of
Boston and on Cape Cod.
Principles of Consolidation
The Company is a wholly-owned subsidiary of Eastern Enterprises
("Eastern"). The consolidated financial statements include the accounts of the
Company and its affiliate, Massachusetts Fuel Inventory Trust and, for periods
prior to August 31, 1999 ("Predecessor Financial Statements"), the operations
of Colonial Gas Company, its affiliate, Massachusetts Fuel Inventory Trust,
and a wholly-owned subsidiary, Transgas Inc. The Predecessor Financial
Statements have been prepared using the historical cost of the Company's
assets and have not been adjusted to reflect the merger with Eastern. However,
certain accounts for the prior periods have been reclassified to conform to
the presentation as of December 31, 1999. Transgas ceased to be a subsidiary
of Colonial Gas Company and became a subsidiary of Eastern upon closing of the
merger. All material intercompany balances and transactions between the
Company and its subsidiary have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Merger
On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In
effecting the transaction, Eastern paid $150 million in cash, net of cash
acquired and including transaction costs, issued approximately 4.2 million
shares of common stock valued at $186 million and assumed $138 million of
debt.
The Colonial merger was accounted for using the purchase method of
accounting for business combinations. The purchase price was allocated to the
net assets acquired based on their fair value. The historical cost basis of
Colonial's assets and liabilities, with the exception of the adjustments
described below, was determined to represent the fair value due to the
existence of a regulatory-approved rate plan based upon the recovery of
historical costs and a fair return thereof. Most of the operations of the
Company have been integrated into the operations of its affiliate, Boston Gas,
a wholly-owned subsidiary of Eastern.
In connection with the merger, the Department of Telecommunications and
Energy (the "Department") approved a rate plan resulting in a ten year freeze
of base rates at current levels. As part of the approved rate plan, the
Company will be charged by Boston Gas for incremental costs incurred by Boston
Gas on behalf of the Company. Due to the length of the base rate freeze, the
Company was required to discontinue its application of Statement of Financial
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain
Types of Regulation".
Accordingly, as of the merger, the Company assigned no value to regulatory
assets of approximately $18 million, consisting principally of deferred demand
side management program costs, deferred environmental costs and unrecovered
deferred income taxes.
F-7
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
In addition, the Company assigned no value to information systems and
computer equipment approximating $15 million, which were no longer used or
useful, as the Company has integrated the majority of its information
technology software applications into those of Boston Gas. Also, the Company
recorded merger-related costs of approximately $10 million consisting
primarily of severance, early retirement, change in control costs, investment
banking fees and a software license termination fee, and recorded a liability
equal to the pension and other post retirement benefit obligations in excess
of the market value of plan assets of $6 million.
The allocation of the purchase price remains subject to adjustment upon
final valuation of certain acquired balances. The excess of consideration over
the fair value of the assets acquired of $241 million has been recorded as
goodwill, which is being amortized on a straight-line basis over a 40-year
period. Of the $241 million, $141 million was recorded as an increase to
common equity and $100 million as advances from the parent company.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities.
For the periods prior to the approval of the merger and rate plan, the
accounting policies conformed to generally accepted accounting principles as
applied to regulated public utilities and reflected the effects of the
ratemaking process in accordance with SFAS No. 71. Under SFAS No. 71, the
Company was allowed to defer certain costs that otherwise would be expensed in
recognition of the ability to recover them in future rates. As described
above, the Company discontinued application of SFAS No. 71 as a result of the
rate plan approved by the Department in connection with its approval of the
merger of the Company with Eastern.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand side management ("DSM") programs, the Department ruled
in November 1999 that effective for filings for the twelve-month period
beginning May 1, 1999, the Company may recover lost margins for only four
years after the DSM measures are installed. The ruling will change the
Company's previous calculation method as approved by the Department in the
Company's previous filings. However, based on the Department's order approving
the merger and rate plan, the Company can recover the resulting decrease in
lost margins as an exogenous adjustment.
Gas Operating Revenues
Gas operating revenues are accrued based upon the amount of gas delivered
to customers through the end of the accounting period. Accrued Utility Margin
of $8,074,000 and $7,876,000, as reported in the Consolidated Balance Sheets
at December 31, 1999 and 1998, respectively, represents the accrual of
unbilled operating revenues net of related gas costs. The Company records lost
margins and incentives assocated with the Company's DSM programs as revenue
when earned and therefore billable by the Company.
Depreciation
Depreciation is provided at rates designed to amortize the cost of
depreciable property, plant and equipment over their estimated remaining
useful lives. The composite depreciation rate, expressed as a percentage of
the average depreciable property in service, is 3.7% for all periods
presented.
Accumulated depreciation is charged with original cost and the cost of
removal, less salvage value, of units retired. Expenditures for repairs,
upkeep of units of property and renewal of minor items of property replaced
independently of the unit of which they are a part are charged to maintenance
expense as incurred.
F-8
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
Pending Accounting Changes
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by SFAS No. 137, is effective for fiscal quarters of
all fiscal years beginning after June 15, 2000. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or a liability measured at
its fair value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting. The Company has not yet quantified the impact of adopting SFAS No.
133 on the consolidated financial statements. However, SFAS No. 133 could
increase volatility in earnings and other comprehensive income.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
(2) Cost of Gas Adjustment Clause and Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires the Company to semi-
annually adjust its rates for firm gas sales in order to track changes in the
cost of gas distributed, with an annual adjustment of subsequent rates for any
over or under recovery of actual costs incurred. As a result, the Company
defers the cost of any firm gas that has been distributed, but is unbilled at
the end of a period, to the period in which the gas is billed to customers.
In its Order of August 14, 1998, the Department modified the CGAC to
recover the gas cost portion of the Company's bad debt write-offs effective
November 1, 1998. The order also approved a local distribution adjustment
clause ("LDAC") to recover the amortization of all environmental response
costs associated with former manufactured gas plant ("MGP") sites, FERC Order
636 transition costs, and costs related to the Company's various demand side
management programs from the Company's firm sales and transportation
customers. These costs were previously recovered through the CGAC. Upon the
discontinuance of the application of SFAS No. 71, the Company records amounts
recoverable under the LDAC as revenue when billable to its customers.
(3) Income Taxes
Since its acquisition, the Company is a member of an affiliated group of
companies that files a consolidated federal income tax return. The Company's
effective income tax rate was 49% in 1999, 37% in 1998, and 38% in 1997. State
taxes and the nondeductibility of goodwill amortization after September 1,
1999, represent the majority of the difference between the effective rate and
the federal income tax rate of 35% for 1999, and state taxes represent the
majority of the difference for 1998 and 1997.
F-9
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
A summary of the provision for income taxes is as follows:
Four Months Eight Months Years Ended
Ended Ended December 31,
December 31, August 31, ---------------------------
1999 1999 1998 1997
------------ ------------- ------------- -------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Current--
Federal............... $1,028 $5,344 $3,827 $5,188
State................. 180 1,046 718 1,228
------ ------ ------ ------
Total Current
Provision.......... 1,208 6,390 4,545 6,416
------ ------ ------ ------
Deferred--
Federal............... 1,800 (2,328) 2,387 3,376
State................. 398 (423) 503 480
------ ------ ------ ------
Total Deferred
Provision.......... 2,198 (2,751) 2,890 3,856
------ ------ ------ ------
Amortization of
investment tax credit.. -- -- (301) (300)
------ ------ ------ ------
Provision for income
taxes.................. $3,406 $3,639 $7,134 $9,972
====== ====== ====== ======
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. Income tax
credits are deferred and credited to income over the lives of the property
giving rise to such credits.
For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives, as permitted by the Internal Revenue Code.
Deferred federal and state taxes are provided for the tax effects of all
temporary differences between financial reporting and taxable income.
Significant items making up deferred tax assets and liabilities at December
31, 1999 and 1998 are as follows:
December 31,
-----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
Assets:
Total deferred tax assets........................... $ 1,077 $ 1,054
-------- --------
Liabilities:
Accelerated Depreciation.............................. (37,813) (43,662)
Deferred Gas Costs.................................... (748) (3,830)
Other................................................. 5,683 (10,296)
-------- --------
Total deferred tax liabilities...................... (32,878) (57,788)
-------- --------
Total net deferred taxes............................ $(31,801) $(56,734)
======== ========
F-10
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Commitments
Long-term Obligations
The following table provides information on long-term obligations as of:
December 31,
-----------------------
1999 1998
-------- -------------
(In Thousands)
(Predecessor)
First Mortgage Bonds:
8.80%, Series CH, due 2022........................... $ 25,000 $ 25,000
6.38%--6.94%, Medium-Term Notes, Series A, due 2008--
2027................................................ 65,000 65,000
5.50%--6.86%, Medium-Term Notes, Series B, due 2003--
2028................................................ 30,000 30,000
Capital lease obligations (Note 6)..................... 1,667 1,583
Note payable........................................... -- 102
Less current portion................................... (646) (722)
-------- --------
$121,021 $120,963
======== ========
The Company currently has a shelf registration covering the issuance of up
to $75,000,000 of Medium-Term Notes, of which $30,000,000 of Medium-Term
Notes, Series B have been issued.
Bonds of $10,000,000 are due in 2003. Bonds of $15,000,000 due in 2027 can
be redeemed by the holder in 2002. Bonds of $20,000,000 due in 2025 can be
redeemed by the holder in 2005. Bonds of $20,000,000 due in 2028 can be
redeemed by the holder in 2008.
The first mortgage bonds are collateralized by utility property. The
Company's first mortgage bond indenture includes, among other provisions,
limitations on the issuance of long-term debt, leases and the payment of
dividends from retained earnings.
Annual maturities of capital lease obligations are $646,000, $499,000,
$337,000, $154,000, and $31,000 for 2000 through 2004, respectively.
Short-Term Debt and Lines of Credit
The Company maintains a bank line of credit 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 $75,000,000, 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,
1999, the credit available under the bank line of credit was $30,991,000. The
weighted average interest rate on these borrowings was 6.66% and 5.80% at
December 31, 1999 and 1998, respectively.
Gas Inventory Financing
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 financing costs incurred. The trust finances such
purchases of inventory by borrowing under a bank line of credit with a maximum
borrowing commitment of $30,000,000 that is complementary to and on similar
terms as the Company's bank line of credit described above. The Department has
approved the inventory trust arrangement and has allowed the cost of such gas
inventory, including fees and financing costs, to be recovered through the
Company's CGAC.
F-11
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits
Effective January 1, 1999, the Company adopted SFAS No. 132, "Employers'
Disclosures about Pensions and Other Post-retirement Benefits," which revises
prior disclosure requirements. Previous information has been restated to
conform to the current presentation.
Pension Plans
The Company has defined benefit pension plans covering substantially all
employees. These include two qualified union plans, one qualified plan for
non-union employees, and various unqualified individual retirement agreements
covering certain key employees and retirees. The 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. The net periodic pension cost was as follows:
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Service cost............ $ 243 $ 850 $ 1,220 $ 1,042
Interest cost on
projected benefits
obligations............ 1,239 2,447 3,492 3,427
Expected return on plan
assets................. (1,302) (2,977) (4,170) (3,638)
Amortization of prior
service cost........... -- 97 161 196
Amortization of
transitional
obligation............. -- 238 357 357
Recognized actuarial
loss................... -- 96 107 47
Curtailment............. -- 295 -- --
------- ------- ------- -------
Total net pension cost.. $ 180 $ 1,046 $ 1,167 $ 1,431
======= ======= ======= =======
Postretirement Life and Health Care
The Company has 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.
Beginning in 1990, the Company has funded a portion of these costs through
the combination of trusts under Section 501(c)(9) and Section 401(h) of the
Internal Revenue Code.
Net periodic expense for postretirement benefits other than pensions was as
follows:
Four Months Eight Months
Ended Ended Years Ended December 31,
December 31, August 31, --------------------------
1999 1999 1998 1997
------------ ------------- ------------ ------------
(In Thousands)
(Predecessor) (Predecessor) (Predecessor)
Service cost............ $ 39 $ 94 $ 138 $ 113
Interest cost on
accumulated benefits
obligations............ 247 400 534 477
Expected return on plan
assets................. (127) (292) (412) (375)
Amortization of
transition obligation.. -- 166 249 270
Recognized actual gain.. -- -- -- (75)
Curtailment............. -- 308 -- --
----- ----- ----- -----
Total net retiree health
care cost.............. $ 159 $ 676 $ 509 $ 410
===== ===== ===== =====
F-12
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The tables above do not reflect retirement enhancements for pension and
health care of $2,667,000 and $33,000, respectively for the eight months ended
August 31, 1999.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's pension plans and
amounts recorded in the Company's balance sheet as of December 31, 1999,
August 31, 1999 and December 31, 1998. Actuarial measurement dates are October
1, 1999, August 31, 1999 and December 31, 1998, respectively.
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- -------------
(In Thousands)
(Predecessor) (Predecessor)
Pensions
- --------
Change in benefit obligation
Balance at beginning of period....... $53,805 $53,132 $50,989
Service cost......................... 243 850 1,220
Interest cost........................ 1,239 2,447 3,492
Plan amendments...................... -- -- 177
Curtailment loss..................... -- 557 --
Special termination benefits......... -- 2,667 --
Benefits paid........................ (1,152) (2,045) (3,139)
Subsidiary spun-off.................. -- (2,557) --
Actuarial (gain) loss................ (1,149) (1,246) 393
------- ------- -------
Balance at end of period............. $52,986 $53,805 $53,132
======= ======= =======
Change in plan assets
Fair value, beginning of period...... $50,055 $51,839 $48,332
Actual return on plan assets......... (486) 1,564 5,161
Employer contributions............... 67 569 1,484
Benefits paid........................ (1,152) (2,045) (3,138)
Subsidiary spun-off.................. -- (1,872) --
------- ------- -------
Fair value at end of period.......... $48,484 $50,055 $51,839
======= ======= =======
Reconciliation of funded status
Funded status........................ $(4,502) $(3,750) $(1,293)
Contributions for fourth quarter..... 158 -- --
Unrecognized actuarial loss.......... 640 -- 102
Unrecognized transition obligation... -- -- 1,747
Unrecognized prior service........... -- -- 1,830
------- ------- -------
Net amount recognized at end of
period.............................. $(3,704) $(3,750) $ 2,386
======= ======= =======
Amounts recognized in balance sheet
Prepaid benefit cost................. $ 130 $ 92 $ 2,442
Accrued benefit liability............ (3,904) (3,842) (3,228)
Intangible asset..................... -- -- 2,126
Accumulated other comprehensive
income.............................. 70 -- 1,046
------- ------- -------
Net amount........................... $(3,704) $(3,750) $ 2,386
======= ======= =======
F-13
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Assets of the employee benefit plans are invested in domestic and
international equities, domestic and international fixed income securities,
real estate and other short-term debt instruments.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's post-retirement
life and health benefit plans and amounts recorded in the Company's balance
sheet as of December 31, 1999, August 31, 1999 and December 31, 1998.
Actuarial measurement dates are October 1, 1999, August 31, 1999 and December
31, 1998, respectively.
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- -------------
(In Thousands)
(Predecessor) (Predecessor)
Healthcare
- ----------
Change in benefit obligation
Balance at beginning of period....... $10,235 $ 8,558 $ 7,179
Service cost......................... 39 94 138
Interest Cost........................ 247 400 534
Amendments........................... -- -- (315)
Curtailment gain..................... -- (270) --
Special termination benefits......... -- 33 --
Benefits paid........................ (49) (278) (251)
Subsidiary spun-off.................. -- (586) --
Actuarial loss....................... 289 2,284 1,273
------- ------- -------
Balance at end of period............. $10,761 $10,235 $ 8,558
======= ======= =======
Change in plan assets
Fair value, beginning of period...... $ 5,363 $ 5,439 $ 5,163
Actual return on plan assets......... (141) 245 527
Employer contributions............... -- 252 --
Benefits paid........................ (50) (278) (251)
Subsidiary spun-off.................. -- (295) --
------- ------- -------
Fair value, end of period............ $ 5,172 $ 5,363 $ 5,439
======= ======= =======
Reconciliation of funded status
Funded status........................ $(5,589) $(4,872) $(3,119)
Unrecognized actuarial (gain) or
loss................................ 558 -- (193)
Unrecognized transition obligation... -- -- 3,481
Unrecognized prior service........... -- -- --
------- ------- -------
Net amount recognized at end of
period.............................. $(5,031) $(4,872) $ 169
======= ======= =======
Amounts recognized in balance sheet
Prepaid benefit cost................. $ -- $ -- $ 169
Accrued benefit liability............ (5,031) (4,872) --
------- ------- -------
Net amount........................... $(5,031) $(4,872) $ 169
======= ======= =======
F-14
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
Four Months Eight Months
Ended Ended Year Ended
December 31, August 31, December 31,
1999 1999 1998
------------ ------------- ------------
(Predecessor) (Predecessor)
Discount rate......................... 7.5% 7.5% 7.0%
Return on plan assets................. 8.5% 8.5% 9.5%
Increase in future compensation....... 4.5% 4.5% 4.0%
Health care inflation trend........... 8.0-10.0% 8.0-10.0% 6.0%
The health care inflation rate for 2000 is assumed to be 8.0% and 10.0% for
pre-65 and post-65 health care benefits, respectively. The rate is assumed to
decrease gradually to 5.0% in 2006 for pre-65 benefits (2008 for post-65
benefits) and remain at that level thereafter. A one percentage point increase
or decrease in the assumed health care trend rate for 1999 would have the
following effects:
One-Percentage One-Percentage
Point Increase Point Decrease
-------------- --------------
(In Thousands)
Service cost and interest cost components......... $ 39 $ (33)
Post-retirement benefit obligation................ $1,258 $(1,048)
(6) Leases
The Company leases certain equipment used in its operations. The Company
has capitalized certain of these leases and reflects lease payments as rental
expense in the periods to which they relate.
Total rental expense for the four months ended December 31, 1999 and eight
months ended August 31, 1999 approximated $265,000 and $545,000, respectively.
For the years ended December 31, 1998 and 1997, total rental expense
approximated $1,150,000 and $1,527,000, respectively.
The remaining minimum rental commitment for capital leases at December 31,
1999 is as follows:
Year
---- (In Thousands)
2000...................................................... $ 670
2001...................................................... 550
2002...................................................... 401
2003...................................................... 205
2004...................................................... 40
Later years............................................... --
--------
Total minimum lease payments.............................. 1,866
Less--Amount representing interest and executory costs.... 199
--------
Present value of minimum lease payments on capital
leases................................................... $ 1,667
========
(7) Fair Values of Financial Instruments
The following methods and assumptions were used to estimate the fair values
of financial instruments:
Cash--The carrying amounts approximate fair value.
F-15
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Fair Values of Financial Instruments (Continued)
Short-term Debt--The carrying amounts of the Company's short-term debt,
including notes payable and gas inventory financing, approximate their fair
value.
Long-term Debt--The fair value of long-term debt is estimated based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term
debt at December 31, 1999 and 1998 are as follows:
1999 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands)
(Predecessor)
Long-term debt........................... $121,667 $116,462 $121,685 $130,885
(8) Related Party Transactions
The Company paid Eastern $240,000 in 1999 for legal, tax and corporate
services rendered.
Included in the Consolidated Balance Sheet at December 31, 1999 is an
advance payable to Eastern in the amount of $100,000,000. Interest is charged
based on the quarterly short-term applicable federal rate issued by the
Internal Revenue Service and was 5.45% as of December 31, 1999.
Substantially all of the administrative functions and supporting
information technology systems are integrated with those of Boston Gas
Company, an affiliated company. As allowed by the Department, the Company is
charged for costs incrementally incurred to provide these services.
(9) Environmental Matters
The Company, like many other companies in the natural gas industry, is
party to governmental proceedings requiring investigation and possible
remediation of former manufactured gas plant ("MGP") and related sites. The
Company may have or share responsibility under applicable environmental laws
for the remediation of one former MGP site and related satellite disposal
sites, as well as one non-MGP site and a federal superfund site. The Company
has estimated its potential share of the costs of investigating and
remediating these sites in accordance with SFAS No. 5, "Accounting for
Contingencies," and the American Institute of Certified Public Accountants
Statement of Position 96-1, "Environmental Remediation Liabilities." The
Company has recorded a liability of approximately $850,000, which represents
its best estimate at this time of remediation costs. However, there can be no
assurance that actual costs will not vary considerably from this estimate.
Factors that may bear on actual costs differing from estimates include,
without limit, changes in regulatory standards, changes in remediation
technologies and practices and the type and extent of contaminants discovered
at the sites.
The Company has received and responded to Requests for Information from the
U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the
Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), regarding one federal superfund site that the EPA is currently
investigating. It is not possible at this time to reasonably estimate the
amount of the Company's obligation for remediation of the site; however, the
Company expects that its share, if any, will be de minimis.
By a rate order issued on May 25, 1990, the Department approved recovery of
all prudently incurred environmental response costs associated with former MGP
related sites over separate, seven-year amortization periods, without a return
on the unamortized balance. The Company currently believes, in light of the
Department
F-16
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Environmental Matters (Continued)
rate order, that it is not probable that actual costs will materially affect
its financial condition or results of operations.
(10) Merger
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
(11) Commitments and Contingencies
The Company maintains employment agreements with certain employees. The
pending KeySpan merger is expected to trigger the change of control provisions
under these agreements which, in the event of a termination, provide for one
to three times salary and bonus as severance and, in certain circumstances, a
tax gross-up and enhanced retirement benefits. The maximum contingent
liability under these agreements is approximately $9 million.
F-17
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Colonial Gas Company:
We have audited the accompanying consolidated balance sheet of Colonial Gas
Company (a Massachusetts Corporation and wholly-owned subsidiary of Eastern
Enterprises) and subsidiary as of December 31, 1999, and the related
consolidated statements of income, retained earnings and cash flows for the
year then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audit. The
consolidated financial statements of Colonial Gas Company and subsidiaries as
of December 31, 1998, were audited by other auditors whose report dated
January 15, 1999, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provided a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Colonial Gas Company and
subsidiary as of December 31, 1999 and the results of its operations and its
cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
As discussed in Note 1, as a result of the merger, the approved rate plan
and related discontinuance of SFAS No. 71, the Company changed certain
accounting practices to comply with generally accepted accounting principles
for non-regulated entities.
Arthur Andersen LLP
Boston, Massachusetts
January 21, 2000
F-18
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To Colonial Gas Company:
We have audited the accompanying consolidated balance sheet of Colonial Gas
Company and subsidiaries as of December 31, 1998, and the related consolidated
statements of income, cash flows, and common equity for each of the two 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 significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provided 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 the consolidated results
of their operations and their consolidated cash flows for each of the two
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required
to be set forth therein in relation to the basic financial statements taken as
a whole.
Grant Thornton LLP
Boston, Massachusetts
January 15, 1999
F-19
COLONIAL GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 1999 (Unaudited)
Three Months Ended Two Months One Month Three Months
-------------------------- Ended August Ended Ended
March 31 June 30 31 Sept. 30 Dec. 31
------------- ------------ ------------ --------- ------------
(Predecessor) (Predecessor) (Predecessor)
(In Thousands)
1999
Operating revenues...... $87,994 $25,580 $ 9,052 $ 4,446 $49,652
Operating margin........ $39,451 $13,648 $ 4,207 $ 2,161 $25,850
Utility operating
earnings (loss)........ $16,535 $ (385) $(4,871) $(1,018) $ 8,880
Net earnings (loss)..... $13,716 $(2,797) $(6,399) $(2,276) $ 4,989
Three Months Ended
---------------------------
March 31 June 30 September 30 December 31
------------- ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor) (Predecessor)
(In Thousands)
1998
Operating revenues...... $77,822 $25,684 $12,347 $52,125
Operating margin........ $36,905 $12,022 $ 6,150 $24,774
Utility operating
earnings (loss)........ $16,075 $ 256 $(3,246) $ 6,647
Net earnings (loss)..... $14,212 $(1,771) $(5,213) $ 5,060
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.
F-20
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Four Months Ended December 31, 1999
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
September 1, (Credited) to Other from December 31,
Description 1999 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............ $3,168 $344 $ -- $ 835 $ 2,677
====== ==== ===== ===== =======
RESERVES INCLUDED IN
LIABILITIES:
Reserve for
postretirement
benefit cost........ $4,872 $159 $ -- $ -- $ 5,031
Reserve for self-
insurance........... 1,008 100 -- -- 1,108
Reserve for
environmental
expenses............ 200 -- 650 -- 850
Reserve for pension.. 3,842 180 -- 118 3,904
------ ---- ----- ----- -------
Total reserves
included in
liabilities....... $9,922 $439 $ 650 $ 118 $10,893
====== ==== ===== ===== =======
F-21
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Eight Months Ended August 31, 1999
(In Thousands)
(Predecessor)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from August 31,
Description 1998 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ----------
Reserves deducted from
assets:
Reserves for doubtful
accounts............ $2,551 $1,234 $ -- $ 617 $3,168
====== ====== ====== ====== ======
Reserves included in
liabilities:
Reserve for
postretirement
benefit cost........ $ -- $ 676 $4,196(1) $ -- $4,872
199
Reserve for self-
insurance........... 1,408 559 -- 760(2) 1,008
Reserve for
environmental
expenses............ 200 -- -- -- 200
Reserve for pension.. 3,228 1,046 137(1) 569 3,842
------ ------ ------ ------ ------
Total reserves
included in
liabilities....... $4,836 $2,281 $4,333 $1,528 $9,922
====== ====== ====== ====== ======
- --------
(1) Recognition of added liability at acquisition, net of Transgas liability
spun off.
(2) Reserve Balance spun off from Transgas at acquisition.
F-22
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
(Predecessor)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1997 to Income Accounts Reserves 1998
----------- ------------ ---------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts............ $3,203 $ 654 $ -- $1,306 $2,551
====== ====== ==== ====== ======
RESERVES INCLUDED IN
LIABILITIES:
Reserve for self-
insurance........... $1,593 $ 237 $ -- $ 422 $1,408
Reserve for
environmental
expenses............ 707 -- -- 507 200
Reserve for pension.. 3,543 1,167 -- 1,482 3,228
------ ------ ---- ------ ------
Total reserves
included in
liabilities....... $5,843 $1,404 $ -- $2,411 $4,836
====== ====== ==== ====== ======
F-23
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
(In Thousands)
(Predecessor)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1996 to Income Accounts Reserves 1997
----------- ------------ ---------- -------- ---------- ------------
Reserves deducted from
assets:
Reserves for doubtful
accounts............ $2,715 $1,956 $ -- $1,468 $3,203
====== ====== ===== ====== ======
Reserves included in
liabilities:
Reserve for self-
insurance........... $1,486 $ 675 $ -- $ 568 $1,593
Reserve for
environmental
expenses............ 1,183 -- -- 476 707
Reserve for pension.. 3,157 1,431 -- 1,045 3,543
------ ------ ----- ------ ------
Total reserves
included in
liabilities....... $5,826 $2,106 $ -- $2,089 $5,843
====== ====== ===== ====== ======
F-24