UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2001
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number 0-10007
COLONIAL GAS COMPANY
D/B/A/ KEYSPAN ENERGY DELIVERY NEW ENGLAND
(Exact Name of Registrant As Specified In Its Charter)
Massachusetts 04-3480443
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
One Beacon Street (617) 742-8400
Boston, Massachusetts 02108 (Registrant's Telephone Number)
(Address of Principal Executive Offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Exchange
------------------- --------
None None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X].
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 1, 2002.
All common stock, 100 shares, are held by Eastern Enterprises.
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.
COLONIAL GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 2001
TABLE OF CONTENTS
Item No. Page
- -------- ----
PART I
1.Business................................................................................... 1
General.................................................................................... 1
Markets and Competition.................................................................... 1
Gas Throughput............................................................................. 2
Gas Supply................................................................................. 2
Regulation................................................................................. 3
Seasonality and Working Capital............................................................ 4
Environmental Matters...................................................................... 4
Employees.................................................................................. 4
2.Properties................................................................................. 4
3.Legal Proceedings.......................................................................... 5
4.Submission of Matters to a Vote of Security Holders........................................ 5
Glossary................................................................................... 6
PART II
5.Market for the Registrant's Common Equity and Related Stockholder Matters.................. 7
6.Selected Financial Data.................................................................... 7
7.Management's Discussion and Analysis of Financial Condition and Results of Operations...... 7
7A.Quantitative and Qualitative Disclosure about Market Risk.................................. 9
8.Financial Statements and Supplementary Data................................................ 10
9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....... 10
PART III
10.Directors and Executive Officers of the Registrant......................................... 11
11.Executive Compensation..................................................................... 11
12.Security Ownership of Certain Beneficial Owners and Management............................. 11
13.Certain Relationships and Related Transactions............................................. 11
PART IV
14.Exhibits, Financial Statement Schedules and Reports on Form 8-K............................ 12
PART I
Item 1. Business.
General
Colonial Gas Company D/B/A KeySpan Energy Delivery New England (the
"Company"), a Massachusetts corporation formed in 1849, is engaged in the
transportation and sale of natural gas to approximately 168,000 residential,
commercial and industrial customers in 24 municipalities located northwest of
Boston ("Merrimack Valley" area) and on Cape Cod.
The Company is a wholly-owned subsidiary of Eastern Enterprises
("Eastern"). On November 8, 2000, KeySpan Corporation ("KeySpan") acquired all
of the common stock of Eastern. The transaction was accounted for as a purchase,
with KeySpan being the acquiring company. Previous to this transaction, Eastern
had owned Colonial Gas since August 31, 1999. KeySpan is a registered holding
company under the Public Utilities Holding Company Act ("PUCHA") of 1935, as
amended. As a result, its activities, as well as certain activities of its
subsidiaries, including, the Company, are regulated by the Securities and
Exchange Commission under PUHCA.
On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In effecting
the transaction, Eastern paid $150 million in cash, net of cash acquired and
including transaction costs, issued approximately 4.2 million shares of common
stock valued at $186 million and assumed $138 million of debt.
For definition of certain industry-specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides local transportation services and gas supply to all
customer classes. The Company's services are available on a firm and non-firm
basis. Firm transportation service and sales are provided under rate tariffs
and/or contracts filed with the Massachusetts Department of Telecommunications
and Energy ("Department") that typically obligate the Company to provide service
without interruption throughout the year. Non-firm transportation service and
sales are generally provided to large commercial/industrial customers who can
use gas or another energy source interchangeably. Non-firm services are provided
through individually negotiated contracts and, in most cases, the price charged
takes into account the price of the customer's alternative fuel.
The Company offers unbundled services to all of its customers, who are
allowed to purchase local transportation from the Company separately from the
purchase of gas supply, which the customer may buy from third-party suppliers.
The Company views these third-party suppliers as partners in marketing gas and
increasing throughput and expects to work closely with them to facilitate the
unbundling process and ensure a smooth transition, especially in the tracking
and processing of transactions. The Company has also implemented programs to
educate customers about the opportunity to purchase gas from third-party
suppliers, while still relying on the utility for delivery. As of December 31,
2001, the Company had approximately 549 firm commercial and industrial
transportation customers. Unbundled service to residential customers became
available on November 1, 2000. While the migration of customers to
transportation-only service will lower the Company's revenues, it has no impact
on its operating earnings. The Company earns all of its margins on the local
distribution of gas and none on the resale of the commodity itself.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers
and electricity suppliers, throughout its service territory. Over the last four
years, the Company has increased its market share in the total stationary energy
market from 42% to 48%. This market share compares to the national level of
approximately 44% and represents a growth opportunity for the Company. However,
the future market share cannot be predicted with certainty and will depend on
such factors as the price of competitive energy sources, the level of investment
required and customer perception of relative value.
1
Gas Throughput
The following table in BCF provides information with respect to the
volumes of gas sold and transported by the Company during the three years
1999-2001.
Years Ended
-----------
December 31,
------------
2001 2000 1999
---- ---- ----
Residential ......................................... 12.7 13.0 12.0
Commercial and industrial ........................... 6.5 7.4 6.8
---- ---- ----
Total sales ................................... 19.2 20.4 18.8
Transportation of customer-owned gas ................ 2.7 3.8 6.4
---- ---- ----
Total throughput .............................. 21.9 24.2 25.2
==== ==== ====
Total firm throughput ......................... 21.8 22.4 22.1
==== ==== ====
In 2001, residential customers comprised 89% of the Company's customer
base, while commercial and industrial establishments accounted for the remaining
11%. Volumetrically, residential customers accounted for 58% of total firm
throughput, while commercial and industrial customers accounted for 42% of total
firm throughput. Approximately 29% of commercial and industrial customers' total
throughput was transportation-only services.
No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 2001.
Gas Supply
The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1999-2001.
Years Ended
-----------
December 31,
------------
2001 2000 1999
---- ---- ----
Natural gas purchases ......................... 17.1 18.1 15.8
Underground storage withdrawal ................ 3.1 4.7 3.1
Liquefied natural gas ("LNG") purchases ....... 0.9 1.4 1.2
---- ---- ----
Total source of supply .................. 21.1 24.2 20.1
Company use, unbilled and other ............... (1.9) (3.8) (1.3)
---- ---- ----
Total sales ............................. 19.2 20.4 18.8
==== ==== ====
Year-to-year variations in storage gas and unbilled gas reflect variations
in end-of-year customer requirements, due principally to weather.
The vast majority of the Company's gas supplies are transported on
interstate pipeline systems to the Company's service territory pursuant to
long-term contracts. Federal Energy Regulatory Commission ("FERC") approved
tariffs provide for fixed demand charges for the firm capacity rights under
these contracts. For the interstate pipeline companies that provide firm
transportation service to the Company's service territory, the peak daily and
annual capacity and the contract expiration dates are as follows:
Capacity in BCF
--------------- Expiration
Pipeline Daily Annual Dates
-------- ----- ------ -----
Algonquin Gas Transmission Company ("Algonquin") .. .056 18.7 2005-2013
Tennessee Gas Pipeline Company ("Tennessee") ...... .072 26.3 2003-2013
---- ---- ---- ----
.128 45.0
==== ====
In 1999, the Company restructured its long-term capacity contracts on
Tennessee Gas Pipeline. As a result, the majority of these Tennessee contracts
are up for renewal in 2003. In addition, the Company has firm capacity
2
contracts on interstate pipelines upstream of Algonquin and Tennessee pipelines
to transport natural gas purchased by the Company from various areas of gas
production.
The Company has contracted with pipeline companies and others for the
storage of natural gas in underground storage fields located in Pennsylvania,
New York, Maryland and West Virginia. These contracts provide storage capacity
of 3.6 BCF and peak day deliverability of .041 BCF. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are produced by
and purchased from foreign and domestic sources.
The Company and its Massachusetts affiliates, Boston Gas Company and Essex
Gas Company, continue to operate under the portfolio management contract with El
Paso Merchant Energy - Gas L.P. This arrangement has a three year primary term
that commenced on November 1, 1999. El Paso is responsible for providing the
majority of the city gate supply requirements to the three companies and
managing certain of the companies' upstream capacity, underground storage and
term supply contracts. The Department approved the contract in October 1999.
The Company has two agreements with Distrigas of Massachusetts Corporation
that expire on October 31, 2002, which allow the Company to purchase up to
10,000 Dekatherms ("Dth") per day for 151 days and 5,000 Dth per day for 365
days of liquefied natural gas ("LNG") in either liquid or vapor form.
Peak day firm throughput in BCF was 0.102 in 2001, 0.126 in 2000 and 0.106
in 1999 for the Company's Merrimack Valley service area and 0.071 in 2001, 0.087
in 2000 and 0.069 in 1999 for the Company's Cape Cod service area. The Company
provides for peak period demand through a least-cost portfolio of pipeline,
storage and supplemental supplies. Supplemental supplies include LNG and propane
air, which are vaporized at points on the Company's distribution system. The
Company's Merrimack Valley service area has on-system LNG and propane air
facilities which have an aggregate sendout capacity of approximately .087 BCF
per day. The Company also operates on-system facilities in the Cape Cod service
area capable of providing approximately .029 BCF per day. The Company considers
its peak day sendout capacity, based on its total supply resources, to be
adequate to meet the requirements of its firm customers.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for gas sales and transportation service, distribution
safety practices, issuance of securities and affiliate transactions are
regulated by the Department. Rates for transportation service and gas sales are
subject to approval by and are on file with the Department. The Company's cost
of gas adjustment clause ("CGAC") billed to firm sales customers, allows for the
semiannual, and based on certain criteria, monthly adjustment of billing rates
for firm gas sales to reflect the actual cost of gas delivered to customers,
including demand charges for capacity on the interstate pipeline system.
Similarly, through its local distribution adjustment clause for ratemaking
purposes, the Company recovers the actual costs of approved energy efficiency
programs and the cost of remediating former manufactured gas plant sites from
all firm customers, including those purchasing gas supply from third parties.
In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a 2.2%
reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The base rate freeze is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. The Office of the Attorney General appealed the
Department's order to the Supreme Judicial Court, which appeal is still pending.
As a result of the rate plan, the Company discontinued its application of
Statement of Financial Accounting Standards ("SFAS") No. 71, as described in
Note 1 of Notes to Consolidated Financial Statements.
On November 1, 2001, the DTE issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002 and providing potential penalties up to two percent of distribution service
revenues.
3
All of the Company's customers are eligible to purchase unbundled local
transportation service from the Company and to purchase their gas supply from
third parties. In 2000, the Department approved Model Terms and Conditions for
the Company's tariffs for all its residential customers effective November 1,
2000. The Model Terms and Conditions are consistent with the Department's order
of February 1, 1999 which provided that, for a five-year transition period,
local distribution company ("LDC") contractual commitments to upstream capacity
will be assigned on a mandatory, pro rata basis to marketers selling gas supply
to the LDC's customers. The approved mandatory assignment method eliminates the
possibility that, because of the migration of customers to the gas supply
service of marketers, the costs of upstream interstate gas pipeline capacity
purchased by the Company to serve firm customers would be absorbed by the LDC or
other customers through the transition period. The Department also found that,
through the transition period, LDCs will retain primary responsibility for
upstream capacity planning and procurement to assure that adequate capacity is
available at Massachusetts city gates to support customer requirements and
growth. In year three of the five-year transition period, the Department intends
to evaluate the extent to which the upstream capacity market for Massachusetts
is workably competitive based on a number of factors and accelerate or
decelerate the transition period accordingly.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand-side management ("DSM") programs, the Department ruled in
November 1999 that, effective for filings for the twelve-month period beginning
May 1, 1999, the Company may recover lost margins for only four years past the
installation of DSM measures. This ruling changed the Department's previous
approved calculation method. However, based on the Department's order approving
the merger and rate plan, the Company has petitioned the Department for recovery
of the resulting reduction in lost margins as an exogenous adjustment. The
Department has approved the recovery of these costs as an exogenous adjustment
subject to the condition that Company earnings are reasonable.
Seasonality and Working Capital
The Company's revenues, earnings and cash flow are highly seasonal because
most of its transportation services and sales are directly related to
temperature conditions. Since the majority of its revenues are billed in the
November through April heating season, significant cash flows are generated from
late winter to early summer. In addition, through the cost of gas adjustment
clause, the Company bills its customers over the heating season for the majority
of the pipeline demand charges paid by the Company over the entire year. This
difference, along with other costs of gas distributed but unbilled, is reflected
as unbilled gas costs receivable and is financed through short-term borrowings.
Short-term borrowings are also required from time to time to finance normal
business operations. As a result of these factors, short-term borrowings are
generally highest during the late fall and early winter.
Environmental Matters
The Company has or shares responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site,
related satellite disposal sites, one non-MGP site and one federal superfund
site. Information with respect to the remediation of MGP related sites may be
found in Note 9 of Notes to Consolidated Financial Statements. Such information
is incorporated herein by reference.
Employees
As of December 31, 2001, the Company had approximately 227 employees, 59%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 2002 and 2003.
Item 2. Properties.
The Company has two principal operations centers and two principal LNG
storage facilities. One of the storage facilities is located in Tewksbury,
Massachusetts and has a capacity of approximately 1.0 BCF and the other is
located in South Yarmouth, Massachusetts and has a capacity of approximately .18
BCF. In addition, the Company owns a 36,000 square foot facility located in
Lowell, Massachusetts used for administrative purposes.
4
On December 31, 2001, the Company's distribution system included
approximately 3,300 miles of gas mains, 148,000 services and 168,000 active
customer meters.
The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned.
In 2001, the Company's capital expenditures were approximately $26
million. Capital expenditures were principally made for improvements to the
distribution system, for system expansion to meet customer growth and for
productivity improvements. The Company plans to spend approximately $32 million
for similar purposes in 2002.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of Security Holders in the fourth
quarter of 2001.
5
Glossary
BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.
Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and
peak-shaving services.
Capacity--The capability of pipelines and supplemental facilities to
deliver and/or store gas.
City Gate--Physical interconnection between an interstate pipeline and the
local distribution company.
Core Customer--Generally, customers with no readily available energy
services alternative.
Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.
Firm Service--Sales and/or transportation service provided without
interruption. This could be for the year, or for an agreed-upon period less than
365 days. Firm services are provided under either filed rate tariffs or through
individually negotiated contracts.
Gas Marketer (Broker)--A non-regulated buyer and seller of gas.
Interstate Transportation--Transportation of gas by an interstate pipeline
to the city gate.
Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to
end-user facilities.
Local Transportation Service--Transportation of gas by the LDC from the
city gate to the customer's burner tip.
Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.
Non-Firm Service--Sales and transportation service offered at a lower
level of reliability and cost. Under this service, the LDC can interrupt
customers on short notice, typically during the winter season. Non-firm services
are provided through individually negotiated contracts and, in most cases, the
price charged takes into account the price of the customer's energy alternative.
Throughput--Gas volume delivered to customers through the LDC's gas
distribution system.
Unbundled Service--Service that is offered and priced separately, such as
separating the cost of gas commodity delivered to the LDC's city gate from the
cost of transporting the gas from the city gate to the end user. Unbundled
services can also include daily or monthly balancing, back-up or stand-by
services and pooling. With unbundled services, customers have the opportunity to
select only the services they desire.
6
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Eastern Enterprises ("Eastern"), a wholly-owned subsidiary of KeySpan
Corporation ("KeySpan"), is the holder of record of all of the outstanding
common equity securities of the Company.
Item 6. Selected Financial Data.
Not required.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
RESULTS OF OPERATIONS
As discussed under Note 1 of the Notes to the Consolidated Financial Statements,
the Company became an indirect wholly-owned subsidiary of KeySpan Corporation
when its parent company, Eastern, merged with KeySpan on November 8, 2000.
Year ended December 31, 2001
Net loss for 2001 was $1.6 million. Weather for this period was 5.0%
warmer that normal. As a result of the merger, this period included a full year
of amortization of goodwill of $9.4 million and interest and debt issuance costs
of $17.8 million related to the $200 million advance from KeySpan.
Period from November 8, 2000 through December 31, 2000
Weather for this period was 13% warmer than normal. Based on the merger
with KeySpan, this period includes amortization of goodwill of $1.6 million and
$2.3 million of interest and debt issuance costs on the $250 million advance
from KeySpan.
Period from January 1, 2000 through November 7, 2000
Weather for the period was 2% colder than normal. Based on the merger with
KeySpan, the Company recorded merger-related expenses of approximately $8.8
million consisting primarily of separation payments to officers, payment of
vested stock options and other compensation related matters.
This period includes a restructuring charge of $7.0 million related to the
Company's exit of the gas appliance rental and service business. The charge
includes $5.1 million to write down to fair value the equipment used in the
rental business and $1.2 million for employee severance and termination benefits
associated with the service business. The remaining $0.7 million is associated
with the disposal of inventory and other related costs.
7
FORWARD-LOOKING INFORMATION
Certain statements contained in this Annual Report on Form 10-K concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are "forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosures about Market
Risk" relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements. Among the factors that could cause actual results to differ
materially are: general economic conditions, especially in Massachusetts;
available sources and cost of fuel; federal and state regulatory initiatives
that increase competition, threaten cost and investment recovery, and impact
rate structures; the ability of the Company to successfully reduce its cost
structure; inflationary trends and interest rates; and other risks detailed from
time to time in other reports and other documents filed by the Company with SEC.
For any of these statements, the Company claims the protection of the safe
harbor for forward-looking information contained in the Private Securities
Litigation Reform Act of 1995, as amended. For additional discussion on these
risks, uncertainties and assumptions, see "Item 1. Business" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosures about Market
Risk" contained herein.
LIQUIDITY AND CAPITAL RESOURCES
On November 8, 2000, KeySpan Corporate Services LLC, a KeySpan subsidiary,
became an affiliate of the Company, through the Company's transaction with
KeySpan. KeySpan Corporate Services provides financing requirements to the
Company for working capital and gas inventory through the Company's
participation in a Utility Money Pool. Interest charged equals interest incurred
by KeySpan Corporate Services to borrow funds to meet the needs of the Company
plus a proportional share of the administrative costs incurred in obtaining the
required funds.
As part of the KeySpan merger, the Company recorded in November, 2000 a
$250 million advance payable to KeySpan, of which $100 million was previously
owed to Eastern. During 2001, $50 million was repaid to KeySpan after an
additional investment in equity by KeySpan of $50 million. Interest charges are
equal to the interest incurred by KeySpan on debt borrowings issued by KeySpan
and recorded on the books of the Company. Issuance expense is charged to the
Company from KeySpan equal to the actual issuance costs incurred by KeySpan on
its debt borrowings. These costs are amortized over the life of the borrowings.
The Company expects capital expenditures for 2002 to be approximately $32
million. Capital expenditures will be largely for system expansion to meet
customer growth and improvements to the distribution system.
The Company believes that projected cash flow from operations, in
combination with currently available resources, is sufficient to meet 2002
capital expenditures, working capital requirements, dividend payments and normal
debt repayments.
OTHER MATTERS
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for gas sales and transportation service, distribution
safety practices, issuance of securities and affiliate transactions are
regulated by the Department. Rates for transportation service and gas sales are
subject to approval by and are on file with the Department. The Company's cost
of gas adjustment clause ("CGAC") billed to firm sales customers, allows for the
semiannual, and based on certain criteria, monthly adjustment of billing rates
for firm gas sales to reflect the actual cost of gas delivered to customers,
including demand charges for capacity on the interstate pipeline system.
Similarly, through its local distribution adjustment clause for ratemaking
purposes, the Company recovers the actual
8
costs of approved energy efficiency programs and the cost of remediating former
manufactured gas plant sites from all firm customers, including those purchasing
gas supply from third parties.
In connection with the acquisition by Eastern Enterprises in 1999, on July
15, 1999, the Department approved the merger and rate plan, resulting in a 2.2%
reduction in the total burner-tip price paid by the Company's firm sales
customers in the first full year following the merger and a ten-year freeze of
base rates. The base rate freeze is subject only to certain exogenous factors,
such as changes in tax laws, accounting changes, or regulatory, judicial, or
legislative changes. The Office of the Attorney General appealed the
Department's order to the Supreme Judicial Court, which appeal is still pending.
As a result of the rate plan, the Company discontinued its application of
Statement of Financial Accounting Standards ("SFAS") No. 71, as described in
Note 1 of Notes to Consolidated Financial Statements.
On November 1, 2001, the DTE issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002 and providing potential penalties up to two percent of distribution service
revenues.
All of the Company's customers are eligible to purchase unbundled local
transportation service from the Company and to purchase their gas supply from
third parties. In 2000, the Department approved Model Terms and Conditions for
the Company's tariffs for all its residential customers effective November 1,
2000. The Model Terms and Conditions are consistent with the Department's order
of February 1, 1999 which provided that, for a five-year transition period,
local distribution company ("LDC") contractual commitments to upstream capacity
will be assigned on a mandatory, pro rata basis to marketers selling gas supply
to the LDC's customers. The approved mandatory assignment method eliminates the
possibility that, because of the migration of customers to the gas supply
service of marketers, the costs of upstream interstate gas pipeline capacity
purchased by the Company to serve firm customers would be absorbed by the LDC or
other customers through the transition period. The Department also found that,
through the transition period, LDCs will retain primary responsibility for
upstream capacity planning and procurement to assure that adequate capacity is
available at Massachusetts city gates to support customer requirements and
growth. In year three of the five-year transition period, the Department intends
to evaluate the extent to which the upstream capacity market for Massachusetts
is workably competitive based on a number of factors and accelerate or
decelerate the transition period accordingly.
After conducting an industry-wide proceeding regarding the calculation of
lost margins that gas companies are allowed to recover as a result of their
conservation or demand-side management ("DSM") programs, the Department ruled in
November 1999 that, effective for filings for the twelve-month period beginning
May 1, 1999, the Company may recover lost margins for only four years past the
installation of DSM measures. This ruling changed the Department's previous
approved calculation method. However, based on the Department's order approving
the merger and rate plan, the Company has petitioned the Department for recovery
of the resulting reduction in lost margins as an exogenous adjustment. The
department has approved the recovery of these costs as an exogenous adjustment
subject to the condition that company earnings are reasonable.
Environmental Matters
The Company has or shares responsibility under applicable environmental
law for the remediation of one former manufactured gas plant ("MGP") site,
related satellite disposal sites, one non-MGP site and one federal superfund
site. Information with respect to the remediation of MGP related sites may be
found in Note 9 of Notes to Consolidated Financial Statements. Such information
is incorporated herein by reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are subject to various risk exposures and uncertainties associated with
our operations. The most significant contingency involves the evolution of the
gas distribution industry towards more competitive and deregulated environments.
In addition, we are exposed to commodity price risk and interest risk. Set forth
below is a description of these exposures and an explanation as to how we have
managed and, to the extent possible, sought to reduce these risks.
9
REGULATORY ISSUES AND THE COMPETITIVE ENVIRONMENT
In July 1997, the DTE directed Massachusetts gas distribution companies to
undertake a collaborative process with other stakeholders to develop common
principles under which comprehensive gas service unbundling might proceed. A
settlement agreement by the Local Distribution Company's ("LDC's") and the
marketer group regarding model terms and conditions for unbundled transportation
service was approved by the DTE in November 1998. In February 1999, the DTE
issued its order on how unbundling of natural gas service will proceed. For a
five year transition period, the DTE determined that LDC contractual commitments
to upstream capacity will be assigned on a mandatory, pro rata basis to
marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that the costs of upstream capacity
purchased by the LDCs to serve firm customers will be absorbed by the LDC or
other customers through the transition period. The DTE also found that, through
the transition period, LDCs will retain primary responsibility for upstream
capacity planning and procurement to assure that adequate capacity is available
to support customer requirements and growth. The DTE approved the LDCs Terms and
Conditions of Distribution Service that conform to the settled upon model terms
and conditions. Since November 1, 2000, all Massachusetts gas customers have the
option to purchase their gas supplies from third party sources other than the
LDCs.
We believe that the actions described above strike a balance among
competing stakeholder interests in order to most effectively make available the
benefits of the unbundled gas supply market to all customers.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
10
PART III
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11. Executive Compensation.
Not required.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13. Certain Relationships and Related Transactions.
Not required.
11
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this
Report. Such information is incorporated herein by reference.
(3) List of Exhibits.
2 Agreement and Plan of Reorganization by and between Eastern
Enterprises and Colonial Gas Company dated as of October 17, 1998,
filed as Exhibit 2.1 to the Registrant's Form 8-K Report dated
October 21, 1998.*
3.1 Restated Articles of Organization for Colonial Gas Company dated
August 5, 1999, filed as Exhibit 3.1 to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1999.*
3.2 By-Laws of Colonial Gas Company dated August 5, 1999, filed as
Exhibit 3.2 to the Registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1999.*
4.1 Second Amended and Restated First Mortgage Indenture dated as of
June 1, 1992, filed as Exhibit 4(b) to Form 10-Q of the Registrant
for the quarter ended June 30, 1992.*
4.2 First Supplemental Indenture dated as of June 15, 1992, filed as
Exhibit 4(c) to Form 10-Q of the Registrant for the quarter ended
June 30, 1992.*
4.3 Second Supplemental Indenture dated as of September 27, 1995, filed
as Exhibit 4(c) to the Registrant's Annual Report on Form 10-K for
the fiscal year ended December 31, 1995.*
4.4 Amendment to Second Supplemental Indenture dated as of October 12,
1995, filed as Exhibit 4(d) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1995.*
4.5 Third Supplemental Indenture dated as of December 15, 1995, filed as
Exhibit 4(f) to the Registrant's Form S-3 Registration Statement
dated January 5, 1998.*
4.6 Fourth Supplemental Indenture dated as of March 1, 1998, filed as
Exhibit 4(l) to the Registrant's Form 10-Q for the quarter ended
March 31, 1998.*
4.7 Utility Money Pool Agreement, filed as Exhibit 4.7 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 2000.*
10.2 Gas Transportation Contract for Firm Reserved Service with Iroquois,
dated February 7, 1991, filed as Exhibit 10 (v) to the Registrant's
Annual Report on Form 10-K for the fiscal year ended December 31,
1990.*
10.3 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-E), dated June 1,
1993, filed as Exhibit 10 (p) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.4 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1,
1993, filed as Exhibit 10 (q) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
12
10.5 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1,
1993, filed as Exhibit 10 (r) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.6 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1,
1993, filed as Exhibit 10 (s) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.7 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-E), dated June 1,
1993, filed as Exhibit 10 (t) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.8 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1,
1993, filed as Exhibit 10 (u) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.9 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 1,
1993, filed as Exhibit 10 (v) to the Registrant's Annual Report on
From 10-K for the fiscal year ended December 31, 1993.*
10.10 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated June 1, 1993,
filed as Exhibit 10 (w) to the Registrant's Annual Report on Form
10-K for the fiscal year ended December 31, 1993.*
10.11 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 1996 dth per day (under Rate Schedule
FT-1), dated June 1, 1993, filed as Exhibit 10.11 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1999.*
10.12 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FTS-8), dated June 1,
1993, filed as Exhibit 10 (y) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993. *
10.13 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FTS-7), dated June 1,
1993, filed as Exhibit 10 (z) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993. *
10.14 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 7,918 dth per day (under Rate Schedule
FT-1), dated June 1, 1993, filed as Exhibit 10.14 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1999.*
10.15 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 2,222 dth per day (under Rate Schedule
FT-1), dated June 1, 1993, filed as Exhibit 10.15 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1999.*
10.16 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company for 104 dth per day (under Rate Schedule FT-1),
dated June 1, 1993, filed as Exhibit 10.16 to the Registrant's
Annual Report on Form 10-K for the fiscal year ended December 31,
1999.*
10.17 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated August 1,
1993, filed as Exhibit 10 (ll) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.18 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated September
1, 1993, filed as Exhibit 10 (nn) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
13
10.19 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated September
1, 1993, filed as Exhibit 10 (oo) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.20 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated September
1, 1993, filed as Exhibit 10 (pp) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.21 Service Agreement between CNG Transmission Corporation and Colonial
Gas Company (under Rate Schedule FTNN), dated October 1, 1993, filed
as Exhibit 10 (rr) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.22 Service Agreement between CNG Transmission Corporation and Colonial
Gas Company (under Rate Schedule GSS), dated October 1, 1993, filed
as Exhibit 10 (ss) to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993.*
10.23 Service Agreement between CNG Transmission Corporation and Colonial
Gas Company (under Rate Schedule GSS-II), contract no. 400009, dated
November 1, 1998, filed as Exhibit 10.23 to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1999.*
10.24 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FT-1), dated October 1,
1993, filed as Exhibit 10 (uu) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.25 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated September
1, 1993, filed as Exhibit 10 (vv) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.26 Service Agreement between National Fuel Gas Supply Corporation and
Colonial Gas Company (under Rate Schedule EFT), dated October 28,
1993, filed as Exhibit 10 (ww) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1993.*
10.27 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated September
1, 1993, filed as Exhibit 10 (xx) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.28 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AIT-1), dated September
15, 1993, filed as Exhibit 10 (yy) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.29 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated October
1, 1993, filed as Exhibit 10 (zz) to the Registrant's Annual Report
on Form 10-K for the fiscal year ended December 31, 1993.*
10.30 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FT-1), dated August 18,
1994, filed as Exhibit 10 (kk) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.31 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated August 29,
1994, filed as Exhibit 10 (ll) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.32 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29,
1994, filed as Exhibit 10 (mm) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
14
10.33 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule CDS), dated August 29,
1994, filed as Exhibit 10 (nn) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.34 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule SS-1), dated November 30,
1994, filed as Exhibit 10 (oo) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.35 Service Agreement between Texas Eastern Transmission Corporation and
Colonial Gas Company (under Rate Schedule FSS-1), dated November 30,
1994, filed as Exhibit 10 (pp) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.36 Letter Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company, Regarding transfer of transportation
entitlements, dated March 28, 1994, filed as Exhibit 10 (qq) to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1994.*
10.37 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (ss) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.38 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated November 1,
1994, filed as Exhibit 10 (tt) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.*
10.39 Firm Natural Gas Transportation agreement between Tennessee Gas
Pipeline and Colonial Gas Company (under Rate Schedule
NET-Northeast), dated August 1, 1995, filed as Exhibit 10 (qq) to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended December 31, 1995.*
10.40 Gas Transportation Agreement between Tennessee Gas Pipeline Company
and Colonial Gas Company (under Rate Schedule FT-A), dated June 1,
1995, filed as Exhibit 10 (rr) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1995.*
10.41 Amendment No. 1 (dated July 1, 1995 to Gas Storage Contract between
Tennessee Gas Pipeline Company and Colonial Gas Company (under Rate
Schedule FS), dated December 1, 1994 (which superseded contract
dated September 1, 1993), filed as Exhibit 10 (ss) to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995.*
10.42 Amendment to Gas Transportation Contract for Firm Reserved Service
with Iroquois Gas Transmission System, L.P., dated September 1,
1995, filed as Exhibit 10 (tt) to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1995.*
10.43 Service Agreement between Algonquin Transmission Company and
Colonial Gas Company (Under Rate Schedule AFT-1), dated December 1,
1995, filed as Exhibit 10 (uu) to the Registrant's Annual Report on
Form 10-K.
10.44 Service Agreement between Algonquin Gas Transmission Company and
Colonial Gas Company (under Rate Schedule AFT-1), dated June 23,
2000, filed as Exhibit 10.44 to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1995.
10.45 Service Agreement between CNG Transmission Corporation and Colonial
Gas Company (under Rate Schedule GSS-II), contract No. 300114, dated
November 1, 1998, filed as Exhibit 10.45 to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1999.*
10.46 Service Agreement between CNG Transmission Corporation and Colonial
Gas Company (under Rate Schedule GSS-II), contract No. 300115, dated
November 1, 1998, filed as Exhibit 10.46 to the Registrant's Annual
Report on Form 10-K for the fiscal year ended December 31, 1999.*
15
10.47 Amended Service Agreement between Texas Eastern Transmission
Corporation and Colonial Gas Company (under Rate Schedules CDS &
FT-1) dated January 6, 1999, filed as Exhibit 10.47 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1999.*
10.48 Redacted Gas Resources Portfolio Management and Gas Sales Agreement
between Colonial Gas Company and El Paso Energy Marketing Company
dated September 14, 1999, as amended, filed herewith as Exhibit 10.1
to Form 10-K of Eastern Enterprises for the year ended December 31,
1999.*
10.49 Contract Restructuring Agreement between Colonial Gas Company and
Tennessee Gas Pipeline dated August 2, 1999, filed as Exhibit 10.49
to the Registrant's Annual Report on Form 10-K for the fiscal year
ended December 31, 1999.*
10.50 Precedent Agreement between the Company and Algonquin Gas
Transmission Company dated as of June 13, 2001, filed herewith.
99.1 Letter by the Company to the Securities and Exchange Commission
regarding representations of Arthur Andersen LLP, filed herewith.
There were no reports on Form 8-K filed in the Fourth Quarter of 2001.
* Not filed herewith. In accordance with Rule 12(b)(32) of the General
Rules and Regulations under the Securities Exchange Act of 1934,
reference is made to the document previously filed with the Commission.
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
COLONIAL GAS COMPANY
D/B/A KEYSPAN ENERGY DELIVERY NEW
ENGLAND
(Registrant)
By: /s/ JOSEPH F. BODANZA
--------------------------------------------
Joseph F. Bodanza
Senior Vice President
Finance, Accounting and Regulatory Affairs
(Principal Financial and Accounting Officer)
Date: March 29, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 29th day of March, 2002.
Signature Title
- ------------------------------------ ----------------------
/s/ CHESTER R. MESSER
- --------------------------------
Chester R. Messer Director and President
17
COLONIAL GAS COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
Report of Independent Public Accountants................................................................ F-20
Consolidated Statements of Earnings for the Year Ended December 31, 2001, Period from
November 8, 2000 through December 31, 2000, Period from January 1, 2000
through November 7, 2000, Four Months Ended December 31, 1999, and Eight
Months Ended August 31, 1999...................................................................... F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000............................................ F-3 and F-4
Consolidated Statements of Retained Earnings and Consolidated
Statements of Comprehensive Income for the Year Ended December 31,
2001, Period from November 8, 2000 through December 31, 2000, Period
from January 1, 2000 through November 7, 2000, Four Months Ended
December 31, 1999, and Eight Months Ended August 31, 1999......................................... F-5
Consolidated Statements of Cash Flows for the Year Ended December 31, 2001, Period from
November 8, 2000 through December 31, 2000, Period from January 1, 2000
through November 7, 2000, Four Months Ended December 31, 1999, and Eight
Months Ended August 31, 1999...................................................................... F-6
Notes to Consolidated Financial Statements.............................................................. F-7 to F-19
Interim Financial Information for the Two Years Ended December 31, 2001 (Unaudited)..................... F-21
Schedule for the Year Ended December 31, 2001, Period from November 8, 2000 through
December 31, 2000, Period from January 1, 2000 through November 7, 2000, and Year Ended
December 31, 1999.................................................................................
Schedule II--Valuation and Qualifying Accounts.................................................... F-21
Schedules other than that listed above have been omitted as the
information has been included in the consolidated financial statements and
related notes or is not applicable nor required.
F-1
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
Period from Period from
November 8, January 1, 2000 Four Months Eight Months
Year Ended 2000 through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Operating revenues .......................... $ 246,122 $ 61,414 $ 138,142 $ 54,098 $ 122,626
Cost of gas sold ............................ 159,064 32,384 72,658 26,087 65,320
--------- -------- --------- -------- ---------
Operating margin ............................ 87,058 29,030 65,484 28,011 57,306
--------- -------- --------- -------- ---------
Operating expenses:
Operations ........................... 26,615 7,220 19,797 9,101 19,818
Maintenance .......................... 3,503 576 2,950 1,151 4,835
Depreciation and amortization ........ 14,465 2,875 11,359 2,857 10,086
Amortization of goodwill ............. 9,366 1,556 5,020 2,008 --
Income taxes ......................... 5,584 5,429 1,601 3,406 3,639
Taxes, other than income ............. 4,400 830 3,748 1,626 3,861
Restructuring charge ................. -- -- 7,000 -- --
Merger related expenses .............. -- -- 8,795 -- 3,788
--------- -------- --------- -------- ---------
Total operating expenses .......... 63,933 18,486 60,270 20,149 46,027
--------- -------- --------- -------- ---------
Operating earnings .......................... 23,125 10,544 5,214 7,862 11,279
Other earnings (loss), net .................. 17 19 315 237 (20)
--------- -------- --------- -------- ---------
Earnings before interest expense ............ 23,142 10,563 5,529 8,099 11,259
--------- -------- --------- -------- ---------
Interest expense:
Long-term debt ....................... 8,515 1,422 7,111 2,844 5,689
Other, including amortization of debt
expense ........................... 16,339 2,316 5,842 2,569 1,244
Less--Interest during construction ... (128) (31) (64) (27) (194)
--------- -------- --------- -------- ---------
Total interest expense ............... 24,726 3,707 12,889 5,386 6,739
--------- -------- --------- -------- ---------
Net (loss) earnings ......................... $ (1,584) $ 6,856 $ (7,360) $ 2,713 $ 4,520
========= ======== ========= ======== =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
------------------------
2001 2000
--------- ---------
(In Thousands)
Gas plant, at cost .................................................................. $ 418,099 $ 394,509
Construction work-in-progress ....................................................... 9,763 7,751
Less-Accumulated depreciation ................................................. (133,127) (119,564)
--------- ---------
Net plant ............................................................... 294,735 282,696
--------- ---------
Current assets:
Cash .......................................................................... 121 124
Accounts receivable, less reserves of $3,709 at December 31, 2001 and $2,964
at December 31, 2000 ....................................................... 19,531 24,285
Accounts receivable - affiliates .............................................. 25,713 5,235
Accrued utility revenue ....................................................... 19,064 22,414
Deferred gas costs ............................................................ 15,579 33,550
Natural gas and other inventories, at average cost ............................ 16,832 13,246
Materials and supplies, at average cost ....................................... 695 1,709
Prepaid expenses .............................................................. 72 262
--------- ---------
Total current assets .................................................... 97,607 100,825
--------- ---------
Other assets:
Goodwill ...................................................................... 377,652 371,850
Deferred charges and other assets ............................................. 6,998 4,077
--------- ---------
Total other assets ...................................................... 384,650 375,927
--------- ---------
Total assets ............................................................ $ 776,992 $ 759,448
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
COLONIAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-----------------------
2001 2000
--------- --------
(In Thousands)
Capitalization:
Common stockholder's investment--
Common stock, $1 par value--
Authorized and outstanding--100 shares ............... $ -- $ --
Amounts in excess of par value .......................... 269,430 203,558
Retained earnings ....................................... 5,272 6,856
Accumulated comprehensive income ........................ (5,281) --
--------- --------
Total common stockholder's investment ............. 269,421 210,414
Long-term obligations, less current portion ................... 120,205 120,621
--------- --------
Total capitalization .............................. 389,626 331,035
Advance from KeySpan .......................................... 200,000 250,000
--------- --------
Total capitalization and advance from KeySpan ................. 589,626 581,035
--------- --------
Current liabilities:
Current portion of long-term obligations ................ 296 572
Notes payable - utility pool ............................ 68,517 47,209
Notes payable - utility pool gas inventory financing .... 21,958 19,216
Accounts payable ........................................ 12,538 38,765
Accounts payable--affiliates ............................ -- 6,486
Accrued taxes ........................................... 896 533
Accrued income taxes .................................... (75) 291
Accrued interest ........................................ 8,726 4,263
Customer deposits ....................................... 538 738
Other current liabilities ............................... 656 2,929
--------- --------
Total current liabilities ......................... 114,050 121,002
--------- --------
Reserves and deferred credits:
Deferred income taxes ................................... 38,322 36,641
Unamortized investment tax credits ...................... 2,402 2,605
Postretirement benefits obligation ...................... 6,770 5,972
Other ................................................... 25,822 12,193
--------- --------
Total reserves and deferred credits ............... 73,316 57,411
--------- --------
Total capitalization and liabilities .............. $ 776,992 $759,448
========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Period from Period from
November 8, 2000 January 1, 2000 Four Months Eight Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Balance at beginning of period ......... $ 6,856 $ -- $ 229 $ -- $ 36,173
Net (loss) earnings .............. (1,584) 6,856 (7,360) 2,713 4,520
Cash dividends on common stock ... -- -- (6,039) (2,484) (6,255)
------- ------ -------- ------- --------
Balance at end of period ............... $ 5,272 $6,856 $(13,170) $ 229 $ 34,438
======= ====== ======== ======= ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Period from Period from
November 8, 2000 January 1, 2000 Four Months Eight Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Net (loss) earnings .................... $(1,584) $6,856 $ (7,360) $ 2,713 $ 4,520
Accrued unfunded pension obligation .... (8,125) -- -- -- --
Income tax effect ...................... 2,844 -- -- -- --
------- ------ -------- ------- --------
Comprehensive (loss) income ............ $(6,865) $6,856 $ (7,360) $ 2,713 $ 4,520
======= ====== ======== ======= ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
COLONIAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Period from Period from
November 8, 2000 January 1, 2000 Four Months Eight Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Cash flows from operating activities:
Net (loss) earnings ......................... $ (1,584) $ 6,856 $ (7,360) $ 2,713 $ 4,520
Adjustments to reconcile net (loss) earnings
to provided by operating activities:
Depreciation and amortization ............ 23,831 4,431 16,379 4,865 10,086
Deferred taxes ........................... 1,681 4,724 4,194 2,198 (2,751)
Other changes in assets and liabilities:
Accounts receivable ................... (15,724) (7,986) (6,122) (4,548) 1,802
Accrued utility margin ................ 3,350 (7,955) 7,350 (7,420) 7,222
Accounts payable--affiliates .......... (6,486) 4,859 (15,714) 15,084 2,832
Inventories ........................... (2,572) 8,752 (9,850) 1,120 640
Deferred gas costs .................... 17,971 (21,475) (12,006) (13,888) 18,280
Accounts payable ...................... (26,227) 10,548 11,639 5,666 (1,274)
Accrued income taxes .................. (366) 1,333 3,853 (5,200) (10,708)
Other ................................. 8,521 2,014 3,929 (7,481) 22,884
-------- -------- -------- -------- --------
Cash (used for) provided by operating
activities .................................. 2,395 6,101 (3,708) (6,891) 53,533
-------- -------- -------- -------- --------
Cash flows from investing activities:
Capital expenditures ........................ (26,448) (6,943) (12,092) (7,105) (12,715)
-------- -------- -------- -------- --------
Cash used for investing activities ............. (26,448) (6,943) (12,092) (7,105) (12,715)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net ............... 21,308 (191) 18,400 10,000 (33,000)
Changes in inventory financing .............. 2,742 1,031 3,176 4,139 (3,255)
Advance from KeySpan ........................ (50,000) -- -- -- (102)
Addition to equity .......................... 50,000 -- -- -- 1,399
Cash dividends paid on common stock ......... -- -- (6,039) (2,484) (6,255)
-------- -------- -------- -------- --------
Cash provided by (used for) financing
activities .................................. 24,050 840 15,537 11,655 (41,213)
-------- -------- -------- -------- --------
Decrease in cash ............................... (3) (2) (263) (2,341) (395)
Cash at beginning of period .................... 124 126 389 2,730 3,125
-------- -------- -------- -------- --------
Cash at end of period .......................... $ 121 $ 124 $ 126 $ 389 $ 2,730
======== ======== ======== ======== ========
Supplemental disclosure of cash flow
information:
Cash paid (refunded) during the year for:
Interest, net of amounts
capitalized ...................... $ 22,134 $ 623 $ 14,206 $ 1,657 $ 8,434
======== ======== ======== ======== ========
Income taxes ....................... $ 3,440 $ -- $ (6,921) $ 4,376 $ 3,595
======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
General
Colonial Gas Company (the "Company") is a gas distribution company engaged
in the transportation and sale of natural gas to residential, commercial and
industrial customers. The Company's service territory includes 24 municipalities
located northwest of Boston and on Cape Cod. The Company is a wholly-owned
subsidiary of Eastern Enterprises ("Eastern") and an indirect wholly-owned
subsidiary of KeySpan Corporation ("KeySpan"), a registered holding company
under the Public Utility Holding Company Act of 1935, as amended.
Basis of Presentation
The consolidated financial statements include the accounts of the Company
and its affiliate, Massachusetts Fuel Inventory Trust (through December 31,
2000) and its wholly-owned subsidiary, Transgas Inc.(through August 31, 1999).
Transgas ceased to be a subsidiary of Colonial Gas Company and became a
subsidiary of Eastern upon closing of the Eastern merger discussed below. All
material intercompany balances and transactions between the Company and its
subsidiary have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
KeySpan Merger and Goodwill
On November 8, 2000, KeySpan acquired all of the common stock of Eastern
for $64.56 per share in cash. The transaction has been accounted for using the
purchase method of accounting for business combinations. The purchase price was
allocated to the net assets acquired of Eastern and its subsidiaries based upon
their fair value. Consistent with the Eastern merger, the historical cost basis
of the Company's assets and liabilities, with minor exceptions, was determined
to represent the fair value due to the existence of regulatory-approved rate
plans based upon the recovery of historical costs and a fair return thereon.
Under "push-down" accounting, the excess of the purchase price over the fair
value of the Company's net assets acquired, or goodwill, of approximately $139
million was recorded as an asset and is being amortized over a period of 40
years. The push-down accounting resulted in a decrease to equity of $8.9 million
and the recording of a $250 million advance from KeySpan, $100 million of which
was previously owed to Eastern. An additional $15.2 million was recorded as
goodwill in finalizing the purchase price allocation of which $15.9 million was
an addition to equity.
As prescribed by SFAS 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", the carrying value of
goodwill is reviewed if the facts and circumstances, such as significant
declines in sales, earnings or cash flows, or material adverse changes in the
business climate suggest it might be impaired. If this review indicates that
goodwill is not recoverable, as determined based upon the estimated undiscounted
cash flows of the equity acquired, impairment would be measured by comparing the
carrying value of the investment in such entity to its fair value. Fair value
would be determined based on quoted market values, appraisals, or discounted
cash flows. For the year ended December 31, 2001, no write-down of goodwill was
determined to be necessary.
On January 1, 2002, the Company adopted SFAS 141, " Business
Combinations", and SFAS 142 "Goodwill and Other Intangible Assets". The key
concepts from the two interrelated Statements include mandatory use of the
purchase method when accounting for business combinations, discontinuance of
goodwill amortization, a revised
F-7
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
framework for testing goodwill impairment at a "reporting unit" level, and new
criteria for the identification and potential amortization of other intangible
assets. Other changes to existing accounting standards involve the amount of
goodwill to be used in determining the gain or loss on the disposal of assets,
and a requirement to test goodwill for impairment at least annually. The annual
impairment test is to be performed within six months of adopting SFAS 142 with
any resulting impairment reflected as either a change in accounting principle,
or a charge to operations in the financial statements. The result of this
analysis is not complete at this time, and the Company is unable to determine
the impact this analysis may have on its results of operations or financial
condition. However, a change in the measurement of the realization of goodwill
could result in a significant change in its carrying value.
Eastern Merger
On August 31, 1999, the Company completed a merger with Eastern in a
transaction with an enterprise value of approximately $474 million. In effecting
the transaction, Eastern paid $150 million in cash, net of cash acquired and
including transaction costs, issued approximately 4.2 million shares of common
stock valued at $186 million and assumed $138 million of debt.
The merger was accounted for using the purchase method of accounting for
business combinations. The purchase price was allocated to the net assets
acquired based on their fair value. The historical cost basis of the Company's
assets and liabilities, with the exception of the adjustments described below,
was determined to represent the fair value due to the existence of a
regulatory-approved rate plan based upon the recovery of historical costs and a
fair return thereof. The administrative functions of the Company have been
integrated into the functions of its affiliate, KeySpan Corporate Services LLC,
an indirect wholly-owned subsidiary of KeySpan.
In connection with the merger, the Department of Telecommunications and
Energy (the "Department") approved a rate plan resulting in a ten-year freeze of
base rates at current levels. Due to the length of the base rate freeze, the
Company was required to discontinue its application of Statement of Financial
Accounting Standards ("SFAS") No. 71 "Accounting for the Effects of Certain
Types of Regulation".
Accordingly, as of the merger, the Company assigned no value to regulatory
assets of approximately $18 million, consisting principally of deferred demand
side management program costs, deferred environmental costs and unrecovered
deferred income taxes.
The excess of consideration over the fair value of the assets acquired of
$241 million was recorded as goodwill, which was being amortized on a
straight-line basis over a 40-year period. Of the $241 million, $141 million was
recorded as an increase to common equity and $100 million as an advance from
Eastern.
Regulation
The Company is regulated as to rates, accounting and other matters by the
Department.
For the periods prior to the merger with Eastern and the approved rate
plan, the accounting policies conformed to generally accepted accounting
principles as applied to regulated public utilities and reflected the effects of
the ratemaking process in accordance with SFAS No. 71. Under SFAS No. 71, the
Company was allowed to defer certain costs that otherwise would be expensed in
recognition of the ability to recover them in future rates. As
F-8
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
described above, the Company discontinued application of SFAS No. 71 as a result
of the rate plan approved by the Department in connection with its approval of
the merger of the Company with Eastern.
Gas Operating Revenues
Customers are billed monthly on a cycle basis. Revenues include unbilled
amounts related to the estimated gas usage that occurred from the most recent
meter reading to the end of each month.
Cost of Gas Adjustment Clause and Unbilled Gas Costs Receivable
The cost of gas adjustment clause ("CGAC") requires the Company to
semiannually, and based on certain criteria, monthly adjust its rates for firm
gas sales in order to track changes in the cost of gas distributed, with an
annual adjustment of subsequent rates for any over or under recovery of actual
costs incurred. As a result, the cost of any firm gas that has been distributed,
but is unbilled at the end of a period, is deferred by the Company to the period
in which the gas is billed to customers. The Company recovers the gas cost
portion of its bad debt write-offs through the CGAC. In addition, through a
local distribution adjustment clause ("LDAC"), the Company is allowed to recover
the amortization of environmental response cost associated with former
manufactured gas plant ("MGP") sites, costs related to the Company's various
conservation and load management programs, and other specified costs from the
Company's firm sales and transportation customers. Upon the discontinuance of
the application of SFAS No. 71, the Company records amounts recoverable under
the LDAC as revenue when billed to customers.
Depreciation
Depreciation is provided at rates designed to amortize the cost of
depreciable property, plant and equipment over their estimated remaining useful
lives. The composite depreciation rate, expressed as a percentage of the average
depreciable property in service, was 3.6% in 2001, and 3.7% in 2000 and 1999.
Accumulated depreciation is charged with original cost and the cost of
removal, less salvage value, of units retired. Expenditures for repairs, upkeep
of units of property and renewal of minor items of property replaced
independently of the unit of which they are a part are charged to maintenance
expense as incurred.
Recent Accounting Pronouncements
In June of 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations". The Standard requires entities to record the fair value
of a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost increasing the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its then present value, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The standard is effective for fiscal
years beginning after June 15, 2002, with earlier application encouraged. We
currently do not anticipate that implementation of this Statement will have a
significant effect on its results of operation and financial condition.
F-9
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
SFAS 144, " Accounting for the Impairment of Disposal of Long-Lived
Assets," is effective January 1, 2002, and addresses accounting and reporting
for the impairment of disposal of long-lived assets. SFAS 144 supersedes SFAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
144 retains the fundamental provisions of SFAS 121 and expands the reporting of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal transaction.
We currently do not anticipate that implementation of this Statement will have a
significant effect on our results of operation and financial condition.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
(2) Income Taxes
For 2001, the Company will file a consolidated income tax return with
KeySpan Corporation. Under the KeySpan tax sharing agreement, the allocation of
the realized tax liability or benefit on the federal consolidated income tax
return will be based upon separate return contributions of each company in the
consolidated group to the consolidated taxable income or loss. For the four
months ended December 31, 1999, the period January 1 through November 7, 2000,
and the period from November 8 through December 31, 2000, the Company filed a
consolidated federal income tax return with Eastern Enterprises. For these
periods, the Company followed the policy, established for the group, of
providing for income taxes payable on a separate company basis.
The Company's effective income tax rate was 140% for 2001, 44% for the
period from November 8, 2000 through December 31, 2000, 56% for the four months
ended December 31, 1999 and 45% for the eight months ended August 31, 1999.
State taxes and the nondeductibility of goodwill amortization associated with
the Eastern and KeySpan mergers, represent the majority of the difference
between the effective rate and the federal income tax rate of 35% for 2001, 2000
and 1999. For the period from January 1 through November 7, 2000, the effective
tax rate was incalculable as there was income tax expense even though the
Company had a loss. This was due to the non-deductibility of goodwill
amortization and certain merger costs.
A summary of the provision for income taxes is as follows:
Period from Period from Eight
November 8, January 1, Four Months Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Current--
Federal ......................... $ 11,788 $ 588 $(2,166) $1,028 $ 5,344
State ........................... 2,378 117 (427) 180 1,046
-------- ------ ------- ------ -------
Total Current Provision ... 14,166 705 (2,593) 1,208 6,390
-------- ------ ------- ------ -------
Deferred--
Federal ......................... (7,072) 3,942 3,476 1,800 (2,328)
State ........................... (1,510) 782 718 398 (423)
-------- ------ ------- ------ -------
Total Deferred Provision .. (8,582) 4,724 4,194 2,198 (2,751)
-------- ------ ------- ------ -------
Provision for income taxes ............ $ 5,584 $5,429 $ 1,601 $3,406 $ 3,639
======== ====== ======= ====== =======
F-10
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Income tax credits are
deferred and credited to income over the lives of the property giving rise to
such credits.
For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives, as permitted by the Internal Revenue Code. Deferred
federal and state taxes are provided for the tax effects of all temporary
differences between financial reporting and taxable income. Significant items
making up deferred tax assets and liabilities at December 31, 2001 and 2000 are
as follows:
December 31,
-------------------------
2001 2000
-------- --------
(In Thousands)
Assets:
Total deferred tax assets .......................... $ 15,494 $ 13,437
-------- --------
Liabilities:
Accelerated Depreciation ................................. (36,682) (35,296)
Deferred Gas Costs ....................................... (4,673) (12,389)
Other .................................................... (11,899) (7,960)
-------- --------
Total deferred tax liabilities ..................... (53,254) (55,645)
-------- --------
Total net deferred taxes ........................... $(37,760) $(42,208)
======== ========
Deferred taxes are reflected in the balance sheet as follows:
Accrued income taxes (current deferred) .................. $ 562 $ (5,567)
Deferred income taxes (long-term) ........................ (38,322) (36,641)
-------- --------
Total .............................................. $(37,760) $(42,208)
======== ========
F-11
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Debt
Long-term Obligations
The following table provides information on long-term obligations as of:
December 31,
-------------------------
2001 2000
--------- ---------
(In Thousands)
First Mortgage Bonds:
8.80%, Series CH, due 2022 ................................. $ 25,000 $ 25,000
6.38%--6.94%, Medium-Term Notes, Series A, due 2008--2027 .. 65,000 65,000
5.50%--6.86%, Medium-Term Notes, Series B, due 2003--2028 .. 30,000 30,000
Capital lease obligations (Note 5) ............................... 501 1,193
Less current portion ............................................. (296) (572)
--------- ---------
$ 120,205 $ 120,621
========= =========
Bonds of $10,000,000 are due in 2003. Bonds of $15,000,000 due in 2027 can
be redeemed by the holder in 2002. Bonds of $20,000,000 due in 2025 can be
redeemed by the holder in 2005. Bonds of $20,000,000 due in 2028 can be redeemed
by the holder in 2008.
The first mortgage bonds are collateralized by utility property. The
Company's first mortgage bond indenture includes, among other provisions,
limitations on the issuance of long-term debt, leases and the payment of
dividends from retained earnings.
Annual maturities of capital lease obligations are $296,000, $167,000,
$35,000, $3,000 and $0 for 2002 through 2006, respectively.
Utility Money Pool Borrowings
KeySpan Corporate Services provides financing to the Company for working
capital and gas inventory through the Company's participation in a Utility Money
Pool. At December 31, 2001, the Company had outstanding borrowings of
$68,517,000 and $21,958,000 for working capital and gas inventory, respectively.
Interest charged equals interest incurred by KeySpan Corporate Services to
borrow funds to meet the needs of the Company, plus a proportional share of the
administrative costs incurred by KeySpan in obtaining the required funds. All
costs related to the gas inventory borrowings are recoverable from customers
through the CGAC. The average yearly rate on these borrowings was 4.16%.
Advance from KeySpan Corporation
As part of the merger, the Company recorded in November 2000, a $250
million advance payable to KeySpan. Interest charges equal interest incurred by
KeySpan on debt borrowings issued by KeySpan and recorded on the books of the
Company. During 2001, $50 million was repaid to KeySpan. The interest rate on
these borrowings is 7.625%. Issuance expense is charged to the Company from
KeySpan equal to the actual issuance costs incurred by KeySpan on its debt
borrowings. These costs are amortized over the life of the borrowings.
F-12
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Retiree Benefits
Pension Plans
The Company has defined benefit pension plans covering substantially all
employees. These include two qualified union plans, one qualified plan for
non-union employees, and various unqualified individual retirement agreements
covering certain key employees and retirees. The funding of retirement and
employee benefit plans is in accordance with the requirements of the plans and,
where applicable, in sufficient amounts to satisfy the "Minimum Funding
Standards" of the Employee Retirement Income Security Act ("ERISA"). Cost for
these plans and agreements charged to expense was as follows:
Period from Period from
November 8 January 1 Four Months Eight Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Service cost .................................. $ 753 $ 184 $ 643 $ 243 $ 850
Interest cost on projected benefits
obligation ................................... 4,315 679 3,092 1,239 2,447
Expected return on plan assets ................ (4,161) (700) (3,197) (1,302) (2,977)
Amortization of prior service cost ............ -- -- -- -- 97
Amortization of transitional obligation ....... -- -- -- -- 238
Recognized actuarial loss ..................... 263 -- -- -- 96
Curtailment ................................... -- -- -- -- 295
------- ----- ------- ------- -------
Total net pension cost ........................ $ 1,170 $ 163 $ 538 $ 180 $ 1,046
======= ===== ======= ======= =======
Post-retirement Life and Health Care
The Company has a post-retirement benefit plan that covers substantially
all employees. The plan provides medical, dental and life insurance benefits.
The plan is contributory for retirees, with respect to post-retirement medical
and dental benefits; the plan is noncontributory with respect to life insurance
benefits.
Beginning in 1990, the Company has funded a portion of these costs through
the combination of trusts under Section 501(c)(9) and Section 401(h) of the
Internal Revenue Code.
Net periodic expense for post-retirement benefits other than pensions was
as follows:
Period from Period from
November 8 January 1 Four Months Eight Months
Year Ended through through Ended Ended
December 31, December 31, November 7, December 31, August 31,
2001 2000 2000 1999 1999
---- ---- ---- ---- ----
(In Thousands)
(Predecessor II) (Predecessor II) (Predecessor I)
Service cost .................................... $ 236 $ 81 $ 107 $ 39 $ 94
Interest cost on accumulated benefits
obligations ................................... 887 161 649 247 400
Expected return on plan assets .................. (397) (76) (304) (127) (292)
Amortization of transition obligation ........... -- -- -- -- 166
Recognized actual loss .......................... 10 -- -- -- --
Curtailment ..................................... -- -- -- -- 308
------- ----- ------- ------- -------
Total net retiree health care cost .............. $ 736 $ 166 $ 452 $ 159 $ 676
======= ===== ======= ======= =======
F-13
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Retiree Benefits (Continued)
The tables above do not reflect retirement enhancements for pension and
health care of $2,667,000 and $33,000, respectively for the eight months ended
August 31, 1999.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's pension plans and
amounts recorded in the Company's balance sheet as of December 31, 2001,
December 31, 2000 and November 7, 2000 using actuarial measurement dates of
December 31, 2001, December 31, 2000, and November 7, 2000 respectively:
Period from Period from
November 8 January 1
Year Ended through through
December 31, December 31, November 7,
2001 2000 2000
---- ---- ----
(In Thousands)
(Predecessor II)
Pensions
Change in benefit obligation
Balance at beginning of period ............... $ 60,311 $ 55,503 $ 52,986
Adjustment ................................... 2,949 -- --
Service cost ................................. 753 183 643
Interest cost ................................ 4,315 691 3,079
Plan amendments .............................. 3,444 -- --
Benefits paid ................................ (4,933) (475) (3,370)
Actuarial (gain) loss ........................ (1,990) 4,409 2,165
-------- -------- --------
Balance at end of period ..................... $ 64,849 $ 60,311 $ 55,503
======== ======== ========
Change in plan assets
Fair value, beginning of period .............. $ 48,999 $ 49,971 $ 48,484
Adjustment ................................... 1,831 -- --
Actual return on plan assets ................. (4,909) (520) 4,318
Employer contributions ....................... 1,985 23 539
Benefits paid ................................ (4,933) (475) (3,370)
-------- -------- --------
Fair value at end of period .................. $ 42,973 $ 48,999 $ 49,971
======== ======== ========
Reconciliation of funded status
Funded status ................................ $(21,876) $(11,312) $ (5,532)
Contributions for fourth quarter ............. -- -- --
Unrecognized actuarial loss .................. 7,795 5,641 3,000
Unrecognized prior service ................... 3,444 -- --
-------- -------- --------
Net amount recognized at end of period ....... $(10,637) $ (5,671) $ (2,532)
======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost ......................... $ -- $ 59 $ 73
Accrued benefit liability .................... (19,362) (5,730) (2,605)
Intangible asset ............................. 3,444 -- --
Accumulated other comprehensive income ....... 5,281 -- --
-------- -------- --------
Net amount ................................... $(10,637) $ (5,671) $ (2,532)
======== ======== ========
F-14
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Retiree Benefits (Continued)
Assets of the employee benefit plans are invested in domestic and
international equities, domestic and international fixed income securities, real
estate and other short-term debt instruments.
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's post-retirement life
and health benefit plans and amounts recorded in the Company's balance sheet as
of December 31, 2001, December 31, 2000, and November 7, 2000 using actuarial
measurement dates of December 31, 2001, December 31, 2000, and November 7, 2000
respectively:
Period from Period from
November 8 January 1
Year Ended through through
December 31, December 31, November 7,
2001 2000 2000
---- ---- ----
(In Thousands)
(Predecessor II)
Healthcare
Change in benefit obligation
Balance at beginning of period .......... $ 12,819 $ 11,396 $ 10,761
Adjustment .............................. 771 -- --
Service cost ............................ 236 81 108
Interest cost ........................... 887 161 649
Plan participant's contribution ......... 473 -- --
Curtailment loss ........................ -- -- --
Special termination benefits ............ -- -- --
Benefits paid ........................... (1,517) (49) (545)
Subsidiary spun-off ..................... -- -- --
Actuarial (gain) loss ................... (534) 1,230 423
-------- -------- --------
Balance at end of period ................ $ 13,135 $ 12,819 $ 11,396
======== ======== ========
Change in plan assets
Fair value, beginning of period ......... $ 4,937 $ 5,184 $ 5,172
Adjustment .............................. 294 -- --
Actual return on plan assets ............ (1,132) (198) 557
Employer contributions .................. 356 -- --
Benefits paid ........................... (1,517) (49) (545)
Subsidiary spun-off ..................... -- -- --
Plan participant's contribution ......... 473 -- --
-------- -------- --------
Fair value at end of period ............. $ 3,411 $ 4,937 $ 5,184
======== ======== ========
Reconciliation of funded status
Funded status ........................... $ (9,724) $ (7,882) $ (6,212)
Unrecognized actuarial loss ............. 2,577 1,504 400
-------- -------- --------
Net amount recognized at end of period .. $ (7,147) $ (6,378) $ (5,812)
======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost .................... $ 153 $ 113 $ --
Accrued benefit liability ............... (7,300) (6,491) (5,812)
-------- -------- --------
Net amount .............................. $ (7,147) $ (6,378) $ (5,812)
======== ======== ========
F-15
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
Period from Period from
November 8 January 1
Year Ended through through
December 31, December 31, November 7,
2001 2000 2000
---- ---- ----
(Predecessor II)
Discount rate............................. 7.0% 7.0% 7.5%
Return on plan assets..................... 8.5% 8.5% 8.5%
Increase in future compensation........... 4.0% 5.0% 5.0%
Health care inflation rate................ 5.0-10.0% 8.0% 8.0%
The health care inflation rate for 2002 is assumed to be 10%. The rate is
assumed to decrease gradually to 5% in 2009 and remain at that level thereafter.
A one percentage point increase or decrease in the assumed health care trend
rate for 2001 would have the following effects:
One-Percentage One-Percentage
Point Increase Point Decrease
-------------- --------------
(In Thousands)
Service cost and interest cost components ... $ 162 $ (142)
Post-retirement benefit obligation .......... $1,578 $(1,433)
Unfunded Pension Obligations
At December 31, 2001 accumulated benefit obligations were in excess of
pension assets. Pursuant to FAS 87 "Employers' Accounting for Pensions", the
Company was required to record an additional $5.1 million minimum liability for
this unfunded pension obligation. As allowed for under current accounting
guidelines, this accrual can be offset by a corresponding debit to a long-term
asset up to the amount of accumulated unrecognized prior service costs. Any
remaining amount is to be recorded as a direct charge to equity. Therefore, at
year-end, the Company recorded a $3.4 million debit in Deferred Charges Other
and a $5.3 million debit in Accumulated Other Comprehensive Income. In December
2002, the Company will re-measure the accumulated benefit obligations and
pension assets, and adjust the accrual and deferrals as appropriate.
(5) Leases
The Company leases certain equipment used in its operations. The Company
has capitalized certain of these leases and reflects lease payments as rental
expense in the periods to which they relate.
Total rent expense for the year ended December 31, 2001 was $592,000.
Total rental expense for the period from November 8 through December 31, 2000
and the period from January 1 through November 7, 2000 approximated $128,000 and
$688,000, respectively. Total rental expense for the four months ended December
31, 1999 and eight months ended August 31, 1999 approximated $265,000 and
$545,000, respectively.
F-16
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Leases (Continued)
The remaining minimum rental commitment for capital leases at December 31,
2001 is as follows:
Year (In Thousands)
- ----
2002 ........................................................ $296
2003 ........................................................ 167
2004 ........................................................ 35
2005 ........................................................ 3
2006 ........................................................ --
Later years ................................................. --
----
Total minimum lease payments ................................ $501
====
(6) Fair Values of Financial Instruments
The following methods and assumptions were used to estimate the fair
values of financial instruments:
Cash--The carrying amounts approximate fair value.
Short-term Debt--The carrying amounts of the Company's short-term
debt, including notes payable and gas inventory financing, approximate
their fair value.
Long-term Debt--The fair value of long-term debt is estimated based
on currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term
debt at December 31, 2001 and 2000 are as follows:
2001 2000
------------------------ -----------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
------ ---------- ------ ----------
(In Thousands)
Long-term debt ...... $120,868 $120,653 $121,193 $121,606
(7) Related Party Transactions
In 2001, the Company was charged $9,080,000 by KeySpan Corporate Services
for services, which included: executive and administrative, corporate affairs,
customer services, environmental services, financial services (including
accounting, auditing, risk management, tax, treasury/finance), human resources,
information technology, legal, materials management and purchasing, and
strategic planning.
KeySpan Corporate Services also purchases and/or develops and implements
software and purchases hardware which are or will be used by the Company.
Capital costs charged to the Company for these technology assets totaled
$5,616,000 during 2001.
The Company paid Eastern $145,000 for the period November 8, 2000 through
December 31, 2000, $725,000 for the period January 1, 2000 through November 7,
2000 and $240,000 in 1999 for legal, tax and corporate services rendered.
On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through the Company's merger with KeySpan. KeySpan Corporate Services
provides financing to the Company for working
F-17
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Related Party Transactions (Continued)
capital and gas inventory through the Company's participation in a Utility Money
Pool. At December 31, 2001, the Company had outstanding borrowings of
$68,517,000 and $21,958,000 for working capital and fuel inventory,
respectively. In 2001, the Company was charged by KeySpan Corporate Services
$1,347,000 and $547,000 for interest on working capital and fuel inventory
borrowings, respectively. At December 31, 2000, the Company had outstanding
borrowings of $47,209,000 and $19,216,000 for working capital and gas inventory,
respectively. In 2000, the Company paid KeySpan Corporate Services $170,000 and
$42,000 for interest on these working capital and gas inventory borrowings,
respectively. Interest charged is equal to actual interest incurred by KeySpan
Corporate Services to borrow funds to meet the needs of the Company, plus a
proportional share of the administrative costs incurred in obtaining the funds
to meet the combined short-term borrowing requirements of the members of the
Utility Pool Agreement.
As of December 31, 2001, $200 million in advances were recorded on the
books of the Company from KeySpan Corporation. A $100 million of this advance
was previously owed to Eastern and is reflected in the Balance Sheet at December
31, 1999. In 2001, the Company was charged by KeySpan Corporation $17,141,000
and $650,000 for interest and debt issuance costs, respectively. Interest
charged is equal to actual interest incurred by KeySpan Corporation on such
advances by KeySpan Corporation. Issuance expense is charged to the Company from
KeySpan Corporation equal to the actual issuance costs incurred by KeySpan
Corporation on such advances. These costs are amortized over the life of the
borrowings.
(8) Restructuring Charge
During the third quarter of 2000, the Company recorded a restructuring
charge of $7.0 million related to its decision to exit the gas appliance repair
and service and appliance rental business. The charge includes $5.1 million to
write down to fair value the equipment used in the rental business and $1.2
million for employee severance and termination benefits associated with the
service business. The remaining $0.7 million is associated with the disposal of
inventory and related costs.
(9) Environmental Matters
The Company, like many other companies in the natural gas industry, is
party to governmental proceedings requiring investigation and possible
remediation of former manufactured gas plant ("MGP") and related sites. The
Company may have or share responsibility under applicable environmental laws for
the remediation of one former MGP site and related satellite disposal sites, as
well as one non-MGP site and a federal superfund site. The Company has estimated
its potential share of the costs of investigating and remediating these sites in
accordance with SFAS No. 5, "Accounting for Contingencies," and the American
Institute of Certified Public Accountants Statement of Position 96-1,
"Environmental Remediation Liabilities." The Company presently estimates the
remaining cost of its MGP-related environmental cleanup activities will be $2.4
million, which amount has been accrued by the Company as a reasonable estimate
of probable cost for known sites. However, there can be no assurance that actual
costs will not vary considerably from this estimate. Factors that may bear on
actual costs differing from estimates include, without limit, changes in
regulatory standards, changes in remediation technologies and practices and the
type and extent of contaminants discovered at the sites.
By a rate order issued on May 25, 1990, the Department approved, for
ratemaking purposes, recovery of all prudently incurred environmental response
costs associated with former MGP related sites over separate, seven-year
amortization periods, without a return on the unamortized balance. The Company
currently believes, in light of the Department rate order, that it is not
probable that actual costs will materially affect its financial condition or
results of operations.
F-18
COLONIAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Environmental Matters (Continued)
The Company has received and responded to Requests for Information from
the U.S. Environmental Protection Agency ("EPA") pursuant to Section 104 of the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
regarding one federal superfund site that the EPA is currently investigating.
Although the Company cannot determine the amount of its liability at this time,
it does not believe that any such liability will have a material adverse effect
on the Company's financial condition.
(10) Workforce Reduction Program
As a result of the KeySpan merger, the Company implemented a severance
program in an effort to reduce the workforce. The Company recorded a liability
of $1.7 million associated with this severance program. During the year ended
December 31, 2001 the Company reduced this liability by $1.1 million as a result
of lower than anticipated costs per employee and recorded a corresponding
reduction to Goodwill. This severance program was targeted to reduce the
Company's workforce by an additional 20 employees. At December 31, 2001 the
Company paid $0.6 million for this program, which was completed in 2001.
F-19
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Colonial Gas Company:
We have audited the accompanying consolidated balance sheet of Colonial
Gas Company (a Massachusetts Corporation and an indirect wholly-owned subsidiary
of KeySpan Corporation) and subsidiary as of December 31, 2001 and 2000, and the
related consolidated statements of earnings, retained earnings, comprehensive
income and cash flows for the year ended December 31, 2001, the period from
November 8, 2000 through December 31, 2000, the period from January 1, 2000
through November 7, 2000, the four months ended December 31, 1999 and the eight
months ended August 31, 1999. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Colonial Gas Company and
subsidiary as of December 31, 2001 and 2000 and the results of their operations
and their cash flows for the year ended December 31,2001,the period from
November 8, 2000 through December 31, 2000, the period from January 1, 2000
through November 7, 2000, the four months ended December 31, 1999 and the eight
months ended August 31, 1999, in conformity with accounting principles generally
accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the index to
consolidated financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state, in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN LLP
New York, New York
February 4, 2002
F-20
COLONIAL GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 2001 (Unaudited)
Three Months Ended
------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In Thousands)
2001
Operating revenues ................. $122,048 $ 42,185 $ 19,482 $62,407
Operating margin ................... $ 42,681 $ 13,754 $ 6,564 $24,059
Utility operating earnings (loss) .. $ 18,867 $ 579 $ (3,062) $ 6,741
Net earnings (loss) ................ $ 12,474 $ (5,777) $ (9,227) $ 946
Period from Period from
Three Months Ended October 1 November 8
---------------------------- through through
March 31 June 30 Sept. 30 Nov. 7 Dec. 31
-------- ------- -------- ------ -------
(Predecessor II) (Predecessor II) (Predecessor II) (Predecessor II)
(In Thousands)
2000
Operating revenues ................. $86,335 $ 26,718 $ 16,222 $ 8,867 $61,414
Operating margin ................... $41,494 $ 13,953 $ 6,654 $ 3,383 $29,030
Utility operating earnings (loss) .. $17,243 $ 2,379 $ (5,922) $(8,486) $10,544
Net earnings (loss) ................ $13,695 $ (1,565) $(10,229) $(9,261) $ 6,856
In the opinion of management, the quarterly financial data includes all
adjustments, unless otherwise noted in the accompanying footnotes, consisting
only of normal recurring accruals, necessary for a fair presentation of such
information.
F-21
SCHEDULE II
COLONIAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
Additions
--------- Net
Balance at Charged Charged Deductions Balance at
Beginning (Credited) to Other from End
Description Of Period to Income Accounts Reserves Of Period
----------- --------- --------- -------- -------- ---------
For the Year Ended December 31, 2001
------------------------------------
Reserves for doubtful accounts $2,964 $2,820 $ -- $2,075 $3,709
====== ====== ====== ====== ======
Reserve self-insurance $1,886 $ 275 $ -- $ 566 $1,595
====== ====== ====== ====== ======
Reserve for environmental expenses $ 850 $ -- $1,664 $ 96 $2,418
====== ====== ====== ====== ======
For the Period from November 8 through December 31, 2000
--------------------------------------------------------
Reserves for doubtful accounts $2,897 $ 286 $ -- $ 219 $2,964
====== ====== ====== ====== ======
Reserve self-insurance $1,427 $ 459 $ -- $ -- $1,886
====== ====== ====== ====== ======
Reserve for environmental expenses $ 850 $ -- $ -- $ -- $ 850
====== ====== ====== ====== ======
For the Period from January 1 through November 7, 2000
------------------------------------------------------
(Predecessor II)
----------------
Reserves for doubtful accounts $2,677 $1,695 $ -- $1,475 $2,897
====== ====== ====== ====== ======
Reserve self-insurance $1,108 $ 793 $ -- $ 474 $1,427
====== ====== ====== ====== ======
Reserve for environmental expenses $ 850 $ -- $ -- $ -- $ 850
====== ====== ====== ====== ======
For the Four Months Ended December 31, 1999
-------------------------------------------
(Predecessor II)
----------------
Reserves for doubtful accounts $3,168 $ 344 $ -- $ 835 $2,677
====== ====== ====== ====== ======
Reserve self-insurance $1,008 $ 100 $ -- $ -- $1,108
====== ====== ====== ====== ======
Reserve for environmental expenses $ 200 $ -- $ 650 $ -- $ 850
====== ====== ====== ====== ======
For the Eight Months Ended August 31, 1999
------------------------------------------
(Predecessor I)
---------------
Reserves for doubtful accounts $2,551 $1,234 $ -- $ 617 $3,168
====== ====== ====== ====== ======
$ (760)*
Reserve self-insurance $1,408 $ 559 $ -- $ 199 $1,008
====== ====== ====== ====== ======
Reserve for environmental expenses $ 200 $ -- $ -- $ -- $ 200
====== ====== ====== ====== ======
* Reserve Balance spun off from Transgas at acquisition
F-22