Back to GetFilings.com
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
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, 2000
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 2-23416
BOSTON GAS COMPANY
D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND
(Exact Name of Registrant As Specified In Its Charter)
Massachusetts 04-1103580
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
One Beacon Street (617) 742-8400
Boston, Massachusetts 02108 (Registrant's Telephone Number)
(Address of Principal Executive
Offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Exchange
------------------- --------
None None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
Indicate the number of shares outstanding of the registrant's class of
common stock as of March 1, 2000.
All common stock, 514,184 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.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
BOSTON GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 2000
TABLE OF CONTENTS
Item
No. Topic Page
---- ----- ----
PART I
1. Business
General........................................................... 1
Markets and Competition........................................... 1
Gas Throughput.................................................... 1
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
8. Financial Statements and Supplementary Data....................... 9
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 9
PART III
10. Directors and Executive Officers of the Registrant................ 10
11. Executive Compensation............................................ 10
12. Security Ownership of Certain Beneficial Owners and Management.... 10
13. Certain Relationships and Related Transactions.................... 10
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 11
PART I
Item 1. Business.
General
Boston Gas Company D/B/A KeySpan Energy Delivery New England (the
"Company") is engaged in the transportation and sale of natural gas to
approximately 550,000 residential, commercial and industrial customers in
Boston, Massachusetts and 73 other communities in eastern and central
Massachusetts. The Company is the largest natural gas distribution company in
New England and has been in business for 178 years.
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 the Company since 1929.
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,
2000, the Company had approximately 3,600 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,
throughout its service territory. Over the last eight years, the Company has
increased its share in the total stationary energy market from 31% to 38%.
This market share compares to the national level of approximately 42%, and
represents a growth opportunity for the Company. However, 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.
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 1998-2000.
1
Years Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
Residential.................................... 43.2 39.3 37.9
Commercial and industrial...................... 25.4 27.3 28.2
Off-system sales............................... 2.6 5.6 12.7
-------- -------- --------
Total sales.................................. 71.2 72.2 78.8
Transportation of customer-owned gas........... 55.8 56.4 65.6
Less: Off-system sales......................... (2.6) (5.6) (12.7)
-------- -------- --------
Total throughput............................. 124.4 123.0 131.7
======== ======== ========
Total firm throughput........................ 122.4 109.1 107.8
======== ======== ========
The above table excludes the effect of the accrual method of revenue
recognition as discussed in Note 1 of Notes to Consolidated Financial
Statements.
In 2000, residential customers comprised 92% of the Company's customer
base, while commercial and industrial establishments accounted for the
remaining 8%. Volumetrically, residential customers accounted for 35% of total
firm throughput, while commercial and industrial customers accounted for 65%
of total firm throughput. Approximately 69% of commercial and industrial
customers' total throughput was transportation-only service. Sithe Energy, an
independent power generator on the Company's system, was responsible for
approximately 18% of this transportation throughput under a contract which was
renewed through February, 2002.
No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 2000.
Gas Supply
The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1998-2000.
Years Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
Natural gas purchases.......................... 59.6 65.9 71.2
Underground storage withdrawal................. 12.5 9.9 10.9
Liquefied natural gas ("LNG") purchases........ 5.3 1.9 --
-------- -------- --------
Total source of supply....................... 77.4 77.7 82.1
Company use, unbilled and other................ (6.2) (5.5) (3.3)
-------- -------- --------
Total sales.................................. 71.2 72.2 78.8
======== ======== ========
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. 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").................................. 0.29 86.0 2001-2012
Tennessee Gas Pipeline Company ("Tennessee").... 0.21 77.1 2003-2012
------- --------
0.50 163.1
======= ========
2
In 1999, the Company restructured its long-term capacity contracts with
Tennessee Gas Pipeline. As a result, no contracts expire on Tennessee before
2003. Less than 1% of the Company's capacity on Algonquin expires in 2001. In
addition, the Company has firm capacity contracts on interstate pipelines
upstream of the 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 16.4 BCF and peak day deliverability of 0.18 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 affiliates, Colonial 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 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.
Peak day firm throughput in BCF was 0.80 in 2000, 0.64 in 1999, and 0.57 in
1998. 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 owns propane air facilities and an
LNG facility in Dorchester, Massachusetts. The Company also leases two LNG
facilities sited on land owned by the Company in Salem and Lynn, Massachusetts
and leases space in facilities located in Providence, Rhode Island and
Everett, Massachusetts. 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, billed to firm sales customers, allows for the
semiannual adjustment of billing rates for firm gas sales to reflect the
actual cost of gas delivered to customers, including demand charges for
capacity on the interstate pipeline system. Similarly, through its local
distribution adjustment clause, the Company collects 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.
The Company's rates for local transportation service are governed by the
five-year performance-based rate plan approved by the Department's 1996 order
in D.P.U. 96-50. Under the plan, the Company's local transportation rates are
recalculated annually to reflect inflation for the previous 12 months and
reduced by a productivity factor. The plan also provides for penalties if the
Company fails to meet specified service quality measures, with a maximum
potential exposure of $1 million. There is a sharing mechanism whereby 25% of
earnings in excess of a 15% return on year-ending equity are to be passed back
to ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. The final year of the plan is November 1, 2001
through October 31, 2002. The size of the productivity factor, by which rates
are reduced, continues to be in dispute. In the Department's order of D.P.U.
96-50, it set the productivity factor at 1.50% and expanded the service
quality penalty beyond the $1 million proposed by the Company. The Company
appealed the Department's order in D.P.U. 96-50 and the Supreme Judicial Court
issued an order vacating: 1) the "accumulated inefficiencies" component of the
productivity factor, thereby reducing the productivity factor from 1.5% to
0.5%; and 2) the expansion of the service quality penalty beyond $1 million,
and remanded these matters to the Department for further proceedings. On
January 16, 2001, the Department issued its order in the remand proceeding.
The order limited the maximum service quality adjustment to $1 million but
imposed a 0.5 percent
3
accumulated inefficiencies component to the productivity factor to be
implemented retroactively as of November 1, 1999 thereby increasing the
productivity factor from 0.5% to 1.0%. The retroactive implementation of the
0.5% accumulated inefficiencies factor reduces revenues by approximately $3.9
million and the inclusion of this factor over the final year of the plan
further reduces revenues by $4.0 million. On January 30, 2001, the Company
appealed the imposition of the 0.5% accumulated inefficiencies adjustment to
the Supreme Judicial Court and was granted a stay of the Department's order
pending a final decision by the Court on the merits of the appeal. The Company
can not predict the outcome of the pending appeal nor when the Court will
render its decision.
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.
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 deferred gas costs and is financed through short-
term borrowings. Short-term borrowings are also required from time to time to
finance normal business operations. As a result of these factors, short-term
borrowings are generally highest during the late fall and early winter.
Environmental Matters
The Company has or shares responsibility under applicable environmental law
for the remediation of former manufactured gas plant operations, including
former operating plants, gas holder locations and satellite disposal sites.
Information with respect to the remediation of these sites may be found in
Note 10 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
Employees
As of December 31, 2000, the Company had approximately 1,280 employees, 71%
of whom are organized in local unions with which the Company has three-year
collective bargaining agreements that expire iin 2002.
Item 2. Properties.
The Company operates three LNG facilities in Dorchester, Salem, and Lynn,
Massachusetts. These facilities provide the Company with local storage of gas,
because the stored LNG can be vaporized into the Company's
4
distribution system to supplement pipeline gas in periods of high demand. The
Company owns the Dorchester facility. The Company owns the real property at
the Salem and Lynn facilities and rents the storage facilities under a long-
term lease arrangement.
The Company owns propane-air facilities at various locations throughout its
service territory.
On December 31, 2000, the Company's distribution system included
approximately 6,000 miles of gas mains, 430,000 services and 556,000 active
customer meters. A majority of the gas mains consist of cast iron and bare
steel, which require ongoing maintenance and replacement.
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 2000, the Company's capital expenditures were approximately $71 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 $82
million for similar purposes in 2001.
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 2000.
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.
Performance-Based Regulatory Plan--Incentive ratemaking mechanism, typically
a price cap plan, whereby rates are adjusted annually pursuant to a pre-
determined formula tied to a measure of inflation, less a productivity offset,
subject to the achievement of service quality measures and the incurrence of
exogenous factors.
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. Dividends on such common equity
amounted to $22.5 million and $27.3 million for 2000 and 1999, respectively.
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 Notes to Consolidated Financial Statements,
the Company became an indirect wholly-owned subsidiary of KeySpan when its
parent company, Eastern, merged with KeySpan on November 8, 2000.
Period from November 8, 2000 through December 31, 2000
Weather for this period was 11% colder than normal. As a result of the
merger, this period includes amortization of goodwill of $3.2 million and
interest and debt issuance costs of $5.5 million on the $600 million advance
from KeySpan.
Period from January 1, 2000 through November 7, 2000
Weather for the period was normal. This period includes merger-related
expenses of approximately $23.3 million consisting primarily of separation
payments to officers, payment of vested stock options and other compensation
related matters associated with the KeySpan merger.
1999 Compared to 1998
Net earnings applicable to common stock for 1999 were $37.9 million
compared to $44.4 million for 1998. The 1998 results include a one-time
increase in net earnings of $8.2 million due to the cumulative effect of a
change in accounting for revenue recognition. Excluding the cumulative effect
of the accounting change, net earnings applicable to common stock for 1999
increased $1.7 million, or 4.6%, from 1998.
Operating revenues in 1999 decreased $17.6 million, or 2.9%, primarily due
to lower gas costs ($22 million), the migration of customers from sales to
transportation service ($12 million) and lower non-firm sales ($19 million).
The revenue reduction associated with lower gas costs and the migration of
customers to transportation service has no impact on earnings, as the Company
earns all of its margins on the local distribution of gas and none on the sale
of the commodity itself. Partially offsetting this decrease was increased
revenues due to colder weather ($24 million) and customer growth ($9 million).
Operating margin increased $11.9 million, or 4.2% due to weather which was
5% colder than 1998 ($7 million) and customer growth ($4 million). Weather for
1999 was 5% warmer than normal.
Operations and maintenance expenses increased $10.6 million, or 7.5%,
principally due to the absence of service contract revenue of approximately $5
million for annual contracts not renewed due to the Company's decision to exit
the gas appliance service business in 1997. In addition, the increase was due
to a charge of $2.2
7
million for an early retirement program and increased maintenance, insurance
and information technology expenses. These were partially offset by lower bad
debt expense reflecting improved collection experience.
Other earnings, net increased $1.4 million due to interest income of $.8
million on a tax settlement with the Internal Revenue Service and a higher
level of short-term investments.
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains certain "forward-looking
statements" concerning projected future financial performance, expected plans
or future operations. The Company cautions that actual results and
developments may differ materially from such projections or expectations.
Investors should be aware of important factors that could cause actual
results to differ materially from forward-looking projections or expectations
contained herein. These factors include, but are not limited to: the effect of
strategic initiatives on earnings and cash flow, the impact of any merger-
related activities, the ability to successfully integrate natural gas
distribution operations, temperatures above or below normal, changes in
economic conditions, including interest rates, regulatory and court decisions
and developments with respect to previously-disclosed environmental
liabilities. Most of these factors are difficult to predict accurately and are
generally beyond the control of the Company.
LIQUIDITY AND CAPITAL RESOURCES
On November 8, 2000, KeySpan Corporate Services, a KeySpan subsidiary,
became an affiliate of the Company, through Eastern's merger 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 merger, the Company recorded in November 2000, a $600
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. 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 2001 to be approximately $82
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 2001
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, billed to firm sales customers, allows for the
semiannual adjustment of billing rates for firm gas sales to reflect the
actual cost of gas delivered to customers, including demand charges for
capacity on the interstate pipeline system. Similarly, through its local
distribution adjustment clause, the Company collects 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.
8
The Company's rates for local transportation service are governed by the
five-year performance-based rate plan approved by the Department's 1996 order
in D.P.U. 96-50. Under the plan, the Company's local transportation rates are
recalculated annually to reflect inflation for the previous 12 months and
reduced by a productivity factor. The plan also provides for penalties if the
Company fails to meet specified service quality measures, with a maximum
potential exposure of $1 million. There is a sharing mechanism whereby 25% of
earnings in excess of a 15% return on year-ending equity are to be passed back
to ratepayers. Similarly, ratepayers absorb 25% of any shortfall below a 7%
return on year-ending equity. The final year of the plan is November 1, 2001
through October 31, 2002. The size of the productivity factor, by which rates
are reduced, continues to be in dispute. In the Department's order of D.P.U.
96-50, it set the productivity factor at 1.50% and expanded the service
quality penalty beyond the $1 million proposed by the Company. The Company
appealed the Department's order in D.P.U. 96-50 and the Supreme Judicial Court
issued an order vacating: 1) the "accumulated inefficiencies" component of the
productivity factor, thereby reducing the productivity factor from 1.5% to
0.5%; and 2) the expansion of the service quality penalty beyond $1 million,
and remanded these matters to the Department for further proceedings. On
January 16, 2001, the Department issued its order in the remand proceeding.
The order limited the maximum service quality adjustment to $1 million but
imposed a 0.5% accumulated inefficiencies component to the productivity factor
to be implemented retroactively as of November 1, 1999 thereby increasing the
productivity factor from 0.5% to 1.0%. The retroactive implementation of the
0.5 percent accumulated inefficiencies factor reduces revenues by
approximately $3.9 million and the inclusion of this factor over the final
year of the plan further reduces revenues by $4.0 million. On January 30,
2001, the Company appealed the imposition of the 0.5% accumulated
inefficiencies adjustment to the Supreme Judicial Court and was granted a stay
of the Department's order pending a final decision by the Court on the merits
of the appeal. The Company can not predict the outcome of the pending appeal
nor when the Court will render its decision.
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.
Environmental Matters
The Company has or shares responsibility under applicable environmental law
for the remediation of former manufactured gas plant operations, including
former operating plants, gas holder locations and satellite disposal sites.
Information with respect to the remediation of these sites may be found in
Note 10 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
9
PART III
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11. Executive Compensation.
Not required.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13. Certain Relationships and Related Transactions.
Not required.
10
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.
(3) List of Exhibits.
3.1 --Restated Articles of Organization, as amended (Filed as Exhibit 3.1 to
the registration statement of the Company on Form S-3 (File No. 33-
48525)).*
3.2 --By-Laws of the Company as amended (Filed as Exhibit 1 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1976
(File No. 2-23416)).*
(Note: Certain instruments with respect to long-term debt of the Company
or its subsidiary are not filed herewith since no such instrument
authorizes securities in an amount greater than 10% of the total assets
of the Company and its subsidiary on a consolidated basis. The Company
agrees to furnish to the Securities and Exchange Commission upon request
a copy of any such omitted instrument of the Company or its subsidiary.)
4.1 --Indenture dated as of December 1, 1989 between the Company and The Bank
of New York, Trustee (Filed as Exhibit 4.2 to the registration statement
of the Company on Form S-3 (File No. 33-31869)).*
4.2 --Agreement of Registration, Appointment and Acceptance dated as of
November 18, 1992 among the Company, The Bank of New York as Resigning
Trustee, and The First National Bank of Boston as Successor Trustee.
(Filed as an exhibit to registration statement of the Company on Form S-
3 (File No. 33-31869)).*
4.3 --Utility Money Pool Agreement, (filed herewith).
10.1 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline Company dated as of September 1, 1993 providing for
transportation of approximately 94,000 dekatherms of natural gas per day
(Filed as Exhibit 10.1 to the Annual Report of the Company on Form 10-K
for the year ended December 31, 1993).*
10.2 --Gas Transportation Contract between the Company and Texas Eastern dated
October 29, 1999 providing for transportation of approximately 48,133
dekatherms of natural gas per day. (Filed as Exhibit 10.2 to the Annual
Report of the Company on Form 10-K for the year ended December
31,1999).*
10.3 --Gas Transportation Contract between the Company and Texas Eastern dated
December 30, 1993 providing for transportation of approximately 32,000
dekatherms of natural gas per day. (Filed as Exhibit 10.3 to the Annual
Report of the Company on Form 10-K for the year ended December 31,
1993).*
10.4 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 45,000
dekatherms of natural gas per day. (Filed as Exhibit 10.4 to the Annual
Report of the Company on Form 10-K for the year ended December 31,
1999).*
10.5 --Gas Storage Agreement between the Company and Consolidated Gas Supply
Corporation dated February 18, 1980 providing for storage demand of 934
dekatherms of natural gas per day. (Filed as Exhibit 20.3 to the
Quarterly Report of the Company on Form 10-Q for the quarter ended March
31, 1982).*
11
10.6 --Gas Storage Agreement between the Company and Honeoye Storage
Corporation dated October 11, 1985 providing for storage demand of
6,150 dekatherms of natural gas per day. (Filed as Exhibit 10.17 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1985).*
10.7 --Firm Gas Transportation agreement between the Company and Algonquin
Gas Transmission Company dated July 27, 2000 providing for
transportation of approximately 15,000 Dekatherms of natural gas per
day, (filed herewith).
10.8 --Gas Sales Contract between the Company and Esso Resources Canada,
Limited, (now Imperial Oil of Canada, Ltd.) dated as of May 1, 1989.
(Filed as Exhibit 10.12 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1989).*
10.9 --Amendment to Exhibit 10.9, Gas Sales Contract between the Company
and Esso Resources (now Imperial Oil of Canada), dated as of November
12, 1997 and Bridge Agreement dated as of October 23, 1997, executed
pursuant to Master Agreement dated as of November 1, 1997. (Filed as
Exhibit 10.9.2 to the Annual Report of the Company on Form 10K for
the year ended December 31, 1998).*
10.10 --Gas Sales Agreement between the Company and Boundary Gas, Inc.,
dated as of September 14, 1987; and First Amendment hereto dated as
of January 1, 1990; Second Amendment thereto dated as of July 1,
1990; Third Amendment thereto dated as of 1991; Fourth Amendment
thereto dated as of June 5, 1991; Fifth Amendment thereto dated as of
May 4, 1993; Sixth Amendment thereto dated as of September 9, 1993;
Amendment thereto dated as of March 8, 1996; and Amendment thereto
dated as of August 20, 1997. (Filed as Exhibit 10.10 to the Annual
Report of the Company on Form 10K for the year ended December 31,
1994.)*
10.11 --Gas Sales Agreement between the Company and Alberta Northeast Gas,
Ltd. dated as of February 7, 1991. (Filed as Exhibit 10.16 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1990).*
10.12 --Amendments to Exhibit 10.12, Gas Sales Agreement between the Company
and Alberta Northeast Gas, Ltd., dated as of October 1, 1992; May 5,
1993; November 27, 1995; March 14, 1996; and November 27, 1995.
(Filed as Exhibit 10.12.1 to the Annual Report of the Company on Form
10-K For the year ended December 31, 1998).*
10.13 --Firm Gas Transportation Agreement between the Company and Iroquois
Gas Transmission System, L.P. dated as of February 7, 1991. (Filed as
Exhibit 10.17 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1990).*
10.13.1 --Agreement between the Company and Iroquois Gas Transmission System
L.P. amending Exhibit 10.13 as of November 3, 1998. (Filed as Exhibit
10.13.1 to the Annual Report of the Company on Form 10-K for the year
ended December 31, 1999).*
10.14 --Firm Gas Transportation Agreement between the Company and Tennessee
Gas Pipeline Company dated as of February 7, 1991. (Filed as Exhibit
10.18 to the Annual Report of the Company on Form 10-K for the year
ended December 31, 1990).*
10.15 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 29,000
dekatherms of natural gas per day. (Filed as Exhibit 10.15 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1999).*
10.16 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 96,000
dekatherms of natural gas per day. (Filed as Exhibit 10.16 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1999).*
12
10.17 --Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 20,000
dekatherms of natural gas per day. (Filed as Exhibit 10.17 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1999).*
10.18 --Gas Transportation Contract between the Company and Algonquin dated
December 1, 1994 providing for transportation of approximately 20,000
dekatherms of natural gas per day. (Filed as Exhibit 10.19 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1997).*
10.19 --Gas Transportation Contract between the Company and Algonquin dated
January 1, 1998 providing for transportation of approximately 27,000
dekatherms of natural gas per day. (Filed as Exhibit 10.20 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1997).*
10.20 --Gas Transportation Contract between the Company and CNG Transmission
dated October 1, 1993 providing for transportation of approximately
21,000 dekatherms of natural gas per day. (Filed as Exhibit 10.23 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.21 --Gas Storage Contract between the Company and CNG Transmission dated
November 1993 providing for storage demand of 42,000 dekatherms of
natural gas per day. (Filed as Exhibit 10.24 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1997).*
10.22 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 10,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.25 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.23 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 8,600 dekatherms of natural gas per day. (Filed as
Exhibit 10.28 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.24 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1993 providing for transportation of
approximately 41,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.29 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.25 --Gas Storage Contract between the Company and Tennessee Gas Pipeline
dated December 1, 1994 providing for storage demand of approximately
71,000 dekatherms of natural gas per day. (Filed as Exhibit 10.31 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.26 --Gas Transportation Contract between the Company and Tennessee Gas
Pipeline dated September 1, 1996 providing for transportation of
approximately 13,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.32 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.27 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 39,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.33 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1997).*
10.27.1 --Agreement between the Company and Texas Eastern Transmission
amending Exhibit 10.27 dated as of October 29, 1998. (Filed as
Exhibit 10.27.1 to the Annual Report of the Company on Form 10-K for
the year ended December 31, 1999).*
13
10.28 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 21,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.34 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.29 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 5,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.35 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.30 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated October 29, 1999 providing for transportation of
approximately 29,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.30 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1999).*
10.31 --Gas Transportation Contract between the Company and Texas Eastern
Transmission dated October 29, 1999 providing for transportation of
approximately 3,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.31 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1999).*
10.32 --Gas transportation contract between the Company and Transcontinental
Gas Pipeline dated June 1, 1993 providing for transportation of
approximately 6,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.40 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997). *
10.33 --Gas Transportation Contract between the Company and Texas Gas
Transmission dated November 1, 1993 providing for transportation of
approximately 13,000 dekatherms of natural gas per day. (Filed as
Exhibit 10.41 to the Annual Report of the Company on Form 10-K for the
year ended December 31, 1997).*
10.34 --Agreement between the Company and Tennessee Gas Pipeline dated as of
September 1, 1993 providing for transportation of approximately 10,500
dekatherms of natural gas per day. (Filed as Exhibit 10.34 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1999).*
10.35 --Agreement between the Company and Texas Eastern Transmission dated as
of October 29, 1999 providing for storage demand of approximately
68,700 dekatherms of natural gas per day. (Filed as Exhibit 10.35 to
the Annual Report of the Company on Form 10-K for the year ended
December 31, 1999).*
10.36 --Agreement between the Company and Algonquin LNG, Corp. dated as of
October 29, 1999 providing for storage demand of approximately 35,000
dekatherms of natural gas per day. (Filed as Exhibit 10.36 to the
Annual Report of the Company on Form 10-K for the year ended December
31, 1999).*
10.37 --Contract Restructuring Agreement between the Company and Tennessee Gas
Pipeline dated as of August 2, 1999 amending Exhibits 10.1, 10.31 and
10.32. (Filed as Exhibit 10.37 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1999).*
10.38 --Redacted Gas Resource Portfolio Management and Gas Sales Agreement
between the Company, Colonial Gas Company, Essex Gas Company and El
Paso Energy Marketing Company dated as of September 14, 1999, as
amended. (Filed as Exhibit 10.1 to the Form 10-K of Eastern Enterprises
for the year ended December 31, 1999.).*
10.39 --Amended and Restated Lease Agreement between Industrial National
Leasing Corporation, Lessor, and Boston Gas Company, Lessee, dated as
of April 30, 1999. (Filed as Exhibit 10.39 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1999).*
14
18.1 --Letter from Arthur Andersen LLP regarding change in Accounting
Principle. (Filed as Exhibit 18.1 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1998).*
23 --Consent of Independent Public Accountants.
There were no reports on Form 8-K filed in the Fourth Quarter of 2000.
- --------
* Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
and Regulations under the Securities Exchange Act of 1934, reference is made
to the document previously filed with the Commission.
15
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Boston Gas Company
D/B/A KeySpan energy delivery new
england
Registrant
Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza
Senior Vice President
Finance, Accounting and Regulatory
Affairs
(Principal Financial and
Accounting Officer)
Dated: April 2, 2001
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 2nd day of April, 2001.
Signature Title
Chester R. Messer Director and
- ------------------------------------- President
Chester R. Messer
16
BOSTON 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 Period from November
8, 2000 through December 31, 2000, the Period from January 1,
2000 through November 7, 2000, and the Two Years Ended December
31, 1999......................................................... F-2
Consolidated Balance Sheets as of December 31, 2000 and 1999...... F-3 and F-4
Consolidated Statements of Retained Earnings for the Period from
November 8, 2000 through December 31, 2000, the Period from
January 1, 2000 through November 7, 2000, and the Two Years Ended
December 31, 1999................................................ F-5
Consolidated Statements of Cash Flows for the Period from November
8, 2000 through December 31, 2000, the Period from January 1,
2000 through November 7, 2000, and the Two Years Ended December
31, 1999......................................................... F-6
Notes to Consolidated Financial Statements........................ F-7 to F-19
Interim Financial Information for the Two Years Ended December 31,
2000 (Unaudited)................................................. F-21
Schedule for the Period from November 8, 2000 through December 31,
2000, the Period from January 1, 2000 through November 7, 2000,
and the Two Years Ended December 31, 1999:
Schedule II--Valuation and Qualifying Accounts.................. F-22
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
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
Period from
Period from January 1, 2000
November 8, 2000 through Year Ended Year Ended
through December November 7, December 31, December 31,
1, 2000 2000 1999 1998
---------------- --------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
--------------- ------------- -------------
(In Thousands)
--------------
Operating revenues...... $202,842 $453,783 $592,719 $610,313
Cost of gas sold........ 123,307 224,755 295,022 324,538
-------- -------- -------- --------
Operating margin........ 79,535 229,028 297,697 285,775
-------- -------- -------- --------
Operating expenses:
Operations............ 25,244 116,327 128,102 120,765
Maintenance........... 5,161 24,304 23,037 19,819
Depreciation and
amortization......... 10,745 39,515 45,779 46,535
Amortization of
goodwill............. 3,226 -- -- --
Income taxes.......... 9,718 (3,468) 24,093 23,927
Taxes, other than
income............... 4,557 18,918 22,042 21,144
Merger related
expenses............. 101 23,347 -- --
Restructuring charge.. -- -- -- (1,550)
-------- -------- -------- --------
Total operating
expenses........... 58,752 218,943 243,053 230,640
-------- -------- -------- --------
Operating earnings...... 20,783 10,085 54,644 55,135
Other earnings, net..... 451 719 1,979 583
-------- -------- -------- --------
Earnings before interest
expense................ 21,234 10,804 56,623 55,718
-------- -------- -------- --------
Interest expense:
Long-term debt........ 2,806 13,984 16,775 16,767
Other, including
amortization of debt
expense.............. 6,564 1,812 926 1,248
Less--Interest during
construction......... (202) (704) (852) (469)
-------- -------- -------- --------
Total interest
expense............ 9,168 15,092 16,849 17,546
-------- -------- -------- --------
Earnings before
cumulative effect of
change in accounting
principle.............. 12,066 (4,288) 39,774 38,172
Cumulative effect of
change in accounting
after tax.............. -- -- -- 8,193
-------- -------- -------- --------
Net earnings (loss)..... 12,066 (4,288) 39,774 46,365
Preferred stock
dividends.............. 183 1,174 1,862 1,926
-------- -------- -------- --------
Earnings (loss)
applicable to common
stock.................. $ 11,883 $ (5,462) $ 37,912 $ 44,439
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
-------------------------
2000 1999
---------- -------------
(Predecessor)
-------------
(In Thousands)
Gas plant, at cost................................... $ 969,429 $963,672
Construction work-in-progress........................ 26,688 16,458
Less--Accumulated depreciation..................... (388,668) (393,991)
---------- --------
Net plant........................................ 607,449 586,139
---------- --------
Current assets:
Cash............................................... 3,916 172
Accounts receivable, less reserves of $13,681 at
December 31, 2000 and $14,816 at December 31,
1999.............................................. 100,326 61,429
Accounts receivable--affiliates.................... -- 23,644
Accrued utility margin............................. 22,325 20,067
Deferred gas costs................................. 127,163 47,872
Natural gas and other inventories, at average
cost.............................................. 57,082 45,172
Materials and supplies, at average cost............ 4,062 3,399
Prepaid expenses................................... 1,112 1,263
---------- --------
Total current assets............................. 315,986 203,018
---------- --------
Other assets:
Goodwill........................................... 771,089 --
Deferred postretirement benefits cost.............. 44,085 72,760
Deferred charges and other assets.................. 37,089 40,975
---------- --------
Total other assets............................... 852,263 113,735
---------- --------
Total assets..................................... $1,775,698 $902,892
========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
------------------------
2000 1999
---------- -------------
(Predecessor)
-------------
(In Thousands)
Capitalization:
Common stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at
December 31, 2000 and 1999........................ $ 51,418 $ 51,418
Amounts in excess of par value..................... 374,377 43,233
Retained earnings.................................. 11,883 189,517
---------- --------
Total common stockholder's investment............. 437,678 284,168
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized 1,200,000 shares; outstanding--682,700
shares at December 31, 2000 and 1,080,000 at
December 31, 1999................................... 16,742 26,454
Long-term obligations, less current portion.......... 224,017 224,399
---------- --------
Total capitalization.............................. 678,437 535,021
Advance from KeySpan................................. 600,000 --
Gas inventory financing.............................. -- 54,020
---------- --------
Total capitalization, advance from KeySpan and gas
inventory financing.............................. 1,278,437 589,041
---------- --------
Current liabilities:
Current portion of long-term obligations............ 385 950
Note payable utility pool........................... 114,843 --
Note payable utility pool-gas inventory financing... 82,307 --
Notes payable....................................... -- 51,200
Accounts payable.................................... 104,657 47,969
Accounts payable--affiliates........................ 686 --
Accrued taxes....................................... 1,728 1,255
Accrued income taxes................................ 10,758 5,543
Accrued interest.................................... 4,411 4,354
Customer deposits................................... 2,013 2,060
Other current liabilities........................... 2,015 512
---------- --------
Total current liabilities......................... 323,803 113,843
---------- --------
Reserves and deferred credits:
Deferred income taxes............................... 80,136 78,921
Unamortized investment tax credits.................. 3,398 4,240
Postretirement benefits obligation.................. 50,393 77,310
Environmental liability............................. 18,000 18,000
Other............................................... 21,531 21,537
---------- --------
Total reserves and deferred credits............... 173,458 200,008
---------- --------
Total capitalization and liabilities.............. $1,775,698 $902,892
========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Period From Period From
November 8, 2000 January 1, 2000
through through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
---------------- --------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
--------------- ------------- -------------
(In Thousands)
Balance at beginning of
period................. $ -- $189,517 $178,857 $152,312
Net earnings (loss)... 12,066 (4,288) 39,774 46,365
Preferred Stock
dividend............. (183) (1,174) (1,862) (1,926)
Common Stock
dividend............. -- (22,496) (27,252) (17,894)
------- -------- -------- --------
Balance at end of
period................. $11,883 $161,559 $189,517 $178,857
======= ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Period From Period From
November 8, 2000 January 1, 2000
through through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
---------------- --------------- ------------- -------------
(Predeccessor) (Predecessor) (Predecessor)
--------------- ------------- -------------
(In Thousands)
Cash flows from
operating activities:
Net earnings (loss).... $ 12,066 $ (4,288) $ 39,774 $ 46,365
Adjustments to
reconcile net earnings
(loss) to cash
provided by operating
activities:
Depreciation and
amortization......... 13,971 39,515 45,779 46,535
Deferred taxes........ 7,011 17,718 1,536 (3,478)
Other changes in
assets and
liabilities:
Accounts receivable.. (61,736) 46,483 (20,815) 25,601
Accrued utility
margin.............. (16,287) 14,029 (5,920) (14,147)
Inventory............ 18,987 (31,560) (4,344) 3,679
Deferred gas costs... (51,225) (28,066) 6,420 12,303
Accounts payable..... 25,060 32,314 (1,017) (12,945)
Accrued income
taxes............... 5,249 (20,495) (3,335) (561)
Other................ 3,237 4,056 6,850 373
-------- -------- -------- --------
Cash provided by (used
in) operating
activities............. (43,667) 69,706 64,928 103,725
-------- -------- -------- --------
Cash flows from
investing activities:
Capital expenditures.. (21,802) (52,958) (57,256) (60,266)
Net cost of removal... (1,272) (4,628) (4,379) (5,099)
-------- -------- -------- --------
Cash used for investing
activities............. (23,074) (57,586) (61,635) (65,365)
-------- -------- -------- --------
Cash flows from
financing activities:
Changes in notes
payable, net......... 54,843 8,800 22,300 (10,800)
Changes in inventory
financing............ 13,719 14,568 5,721 (7,203)
Amortization of
preferred stock
issuance costs....... 4 217 94 34
Redemption of
preferred stock...... -- (9,933) (3,000) --
Cash dividends paid on
common and preferred
stock................ (183) (23,670) (29,114) (19,820)
-------- -------- -------- --------
Cash provided by (used
in) financing
activities............. 68,383 (10,018) (3,999) (37,789)
-------- -------- -------- --------
Increase (decrease) in
cash................... 1,642 2,102 (706) 571
Cash at beginning of
period................. 2,274 172 878 307
-------- -------- -------- --------
Cash at end of period... $ 3,916 $ 2,274 $ 172 $ 878
======== ======== ======== ========
Supplemental disclosure
of cash flow
information:
Cash paid during the
year for:
Interest, net of
amounts
capitalized......... $ 18,255 $ -- $ 18,462 $ 18,879
======== ======== ======== ========
Income taxes......... $ (1,718) $ 115 $ 26,486 $ 34,046
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Accounting Policies
General
Boston 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 Boston and 73
other communities in eastern and central Massachusetts. The Company is a
wholly-owned subsidiary of Eastern Enterprises ("Eastern") and an indirect
wholly-owned subsidiary of KeySpan Corporation ("KeySpan").
Basis of Presentation
The accounting policies of the Company conform to generally accepted
accounting principles and reflect the effects of the rate-making process in
accordance with Statement of Financial Accounting Standards ("SFAS") No. 71,
"Accounting for the Effects of Certain Types of Regulation."
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiary, Massachusetts LNG Incorporated, which became
inactive in 1999.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Merger
On 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. 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. The allocation of the purchase
price remains subject to adjustment upon final valuation of certain acquired
balances of the Company. 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 $774 million has been recorded as an asset and is
being amortized over a period of 40 years. The push-down accounting resulted
in an increase in equity of $170 million and the recording of a $600 million
advance from KeySpan.
Regulation
The Company is regulated as to rates, accounting and other matters by the
Massachusetts Department of Telecommunications and Energy ("the Department").
Therefore, the Company accounts for the economic effects of regulation in
accordance with the provisions of SFAS 71. In the event the Company determines
that it no longer meets the criteria for following SFAS 71, the accounting
impact would be an extraordinary, non-cash charge to operations of an amount
that could be material. Management believes that this amount would approximate
$62 million as of December 31, 2000. Criteria that give rise to the
discontinuance of SFAS 71 include (1) increasing competition that restricts
the Company's ability to establish prices to recover specific costs or (2) a
significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The Company has reviewed
these criteria and believes that the continuing application of SFAS 71 is
appropriate.
F-7
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
Regulatory assets have been established that represent probable future
revenue to the Company associated with certain costs that will be recovered
from customers through the rate-making process. Regulatory liabilities
represent probable future reductions in revenues associated with the amounts
that are to be credited to customers through the rate-making process.
The following regulatory assets were reflected in the consolidated balance
sheets as of December 31:
2000 1999
------- -------------
(In Thousands)
(Predecessor)
Post-retirement benefit costs....................... $44,085 $72,760
Environmental costs................................. 18,060 17,703
Other............................................... -- 733
------- -------
$62,145 $91,196
======= =======
Regulatory liabilities total approximately $7,694,000 and $8,586,000 at
December 31, 2000 and 1999 respectively, and relate to income taxes.
As of December 31, 2000, all of the Company's regulatory assets and
liabilities are reflected in rates charged or credited to customers over
periods ranging from 1 to 20 years. For additional information regarding
deferred income taxes, post-retirement benefit costs and environmental costs,
see Notes 2, 5 and 10, respectively.
Change in Accounting Principle
During the fourth quarter of 1998, the Company changed its method of
accounting for unbilled revenues, retroactively applied as of January 1, 1998.
Previously, substantially all revenues were recorded when billed. Under the
unbilled method, the estimated margin on unbilled sales is recorded at the end
of each accounting period. This change in accounting resulted in a one-time
cumulative effect for the years prior to 1998 of $8,193,000.
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 Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires the Company to semi-
annually adjust its rates for firm gas sales in order to track changes in the
cost of gas distributed, with an annual adjustment of subsequent rates for any
over or under recovery of actual costs incurred. As a result, the 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 costs 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.
F-8
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
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 5.0% in 2000 and in 1999, and
5.2% in 1998. Amortization is provided on intangible assets, principally
software, over the estimated useful life of the asset.
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
The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" on January 1, 2001, which at that time had no effect
on the Company's financial statements since the Company had no outstanding
derivatives at December 31, 2000.
The Financial Accounting Standards Board ("FASB") recently issued a
revision to its Exposure Draft ("ED") on "Business Combinations and Intangible
Assets". In the revised ED, the FASB concluded that the amortization of
goodwill will no longer be required. Instead, companies will need to perform
yearly impairment tests on the recorded amount of goodwill and determine
whether an impairment charge is necessary. The comment deadline on the revised
ED was March 16, 2001 and we believe the FASB will finalize its deliberations
on goodwill amortization in the third or fourth quarter of 2001. Goodwill
amortization for 2001 is estimated to be approximately $19,400,000. Depending
on the timing of the final statement, the Company may realize a significant
benefit to earnings in 2001 if the Company is required to discontinue the
amortization of goodwill. Such enhancement to earnings will not affect cash
flow.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
(2) Income Taxes
The Company is a member of an affiliated group of companies that files a
consolidated federal income tax return. The Company follows the policy,
established for the group, of providing for income taxes that would be payable
on a separate company basis. The Company's effective income tax rate was 44.6%
for the period from November 8 through December 31, 2000, 44.7% for the period
from January 1 through November 7, 2000, 38.2% in 1999, and 38.5% in 1998.
State income taxes and the nondeductibility of goodwill amortization after
November 8, 2000 represent the majority of the difference between the
effective rate and the federal income tax rate of 35% for the period from
November 8 through December 31, 2000 and state income taxes represent the
majority of the difference for the period from January 1 through November 7,
2000 and 1999 and 1998.
F-9
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
A summary of the provision for income taxes is as follows:
Period from Period from
November 8 through January 1 through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
------------------ ----------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
----------------- ------------- -------------
(In Thousands)
Current--
Federal............... $2,258 $(17,695) $17,756 $21,997
State................. 449 (3,491) 4,801 5,408
------ -------- ------- -------
Total current
provision.......... 2,707 (21,186) 22,557 27,405
Deferred--
Federal............... 5,835 14,713 2,244 (2,119)
State................. 1,176 3,005 (708) (1,359)
------ -------- ------- -------
Total deferred
provision.......... 7,011 17,718 1,536 (3,478)
------ -------- ------- -------
Provision for income
taxes.................. $9,718 $ (3,468) $24,093 $23,927
====== ======== ======= =======
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.
At December 31, 2000 the Company had a regulatory liability of $1,793,000
which represents the tax benefit of unamortized investment tax credits. This
benefit is being passed back to customers over the lives of property giving
rise to the investment credit. The Company also has a regulatory liability for
excess deferred taxes being returned to customers over a 30-year period
pursuant to a 1988 rate order with a balance to be refunded to customers of
$5,901,000 as of December 31, 2000.
F-10
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Income Taxes (Continued)
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, 2000 and 1999 are as follows:
2000 1999
--------- -------------
(Predecessor)
-------------
(In Thousands)
Assets:
Regulatory liabilities.......................... $ 3,133 $ 3,425
Other........................................... 21,621 16,723
--------- --------
Total deferred tax assets....................... 24,754 20,148
--------- --------
Liabilities:
Accelerated depreciation........................ (84,533) (84,151)
Deferred gas costs.............................. (39,303) (14,183)
Other........................................... (12,080) (11,073)
--------- --------
Total deferred tax liabilities.................. (135,916) (109,407)
--------- --------
Total net deferred taxes........................ $(111,162) $(89,259)
========= ========
Deferred income taxes are reflected in the balance
sheet as follows:
Accrued income taxes (current deferred)......... $ (31,026) $(10,338)
Deferred income taxes (long-term)............... (80,136) (78,921)
--------- --------
$(111,162) $(89,259)
========= ========
Investment tax credits are deferred and credited to income over the lives
of the property giving rise to such credits. The credit to income was $140,000
for the period from November 8 through December 31, 2000, $702,000 for the
period from January 1 through November 7, 2000, $842,000 in 1999 and $849,000
in 1998.
(3) Debt
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
2000 1999
-------- -------------
(Predecessor)
-------------
(In Thousands)
8.33%--9.75%, Medium-Term Notes Series A, due
2005--2022........................................ $100,000 $100,000
6.93%--8.50%, Medium-Term Notes, Series B, due
2006--2024........................................ 50,000 50,000
6.80%--7.25%, Medium-Term Notes, Series C, due
2012--2025........................................ 60,000 60,000
Capital lease obligations (Note 6)................. 14,402 15,349
Less current portion............................... (385) (950)
-------- --------
$224,017 $224,399
======== ========
F-11
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Debt (Continued)
There are no sinking fund requirements for the next four years related to
the $210,000,000 of Medium-Term Notes outstanding at December 31, 2000 and
none are callable prior to maturity. In 2005, $15,000,000 of 8.875% Medium-
Term Notes Series A, mature.
Annual maturities of capital lease obligations for 2001 through 2005 are
$385,000, $586,000, $840,000, $891,000 and $945,000, respectively.
Utility Money Pool Borrowings
On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through Eastern's merger with KeySpan. 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,
2000, the Company had outstanding borrowings of $114,843,000 and $82,307,000
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 in obtaining the required funds. All costs related to the gas
inventory borrowings are recoverable from customers through the CGAC. The
average rate on these borrowings was 6.92%.
Advance from KeySpan Corporation
As part of the merger, the Company recorded in November 2000, a $600
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. The weighted-average interest rate on these borrowings is 7.78%.
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.
(4) Preferred Stock
The Company has outstanding 682,700 shares of 6.421% Cumulative Preferred
Stock, which is non-voting and has a liquidation value of $25 per share. The
preferred stock requires 5% annual sinking fund payments beginning on
September 1, 1999 with a final redemption on September 1, 2018. At the
Company's option, the annual sinking fund payment may be increased to 10%. The
preferred stock is not callable prior to 2003. On September 1, 2000 the
Company redeemed 120,000 shares, or 10% of the outstanding shares, at the
liquidation price of $25 per share. In addition to the 120,000 shares
redeemed, the Company purchased 277,300 shares on the open market which were
subsequently retired.
(5) Retiree Benefits
The Company provides retirement benefits for substantially all of its
employees. These plans include pensions, health and life insurance benefits.
Pension benefits for salaried plans are based on salary and years of
service, while union retirement and welfare plans are based on negotiated
benefits and years of service. Employees hired before 1993 who are
participants in the pension plans become eligible for post-retirement health
care benefits if they reach retirement age while working for the Company. 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").
F-12
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
Effective January 1, 1998, the Company adopted SFAS No. 132, "Employers'
Disclosures about Pensions and Other Post-retirement Benefits," which revises
prior disclosure requirements. The net cost for these plans and agreements
charged to expense was as follows:
Pensions
Period from Period from
November 8 January 1
through through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
------------ ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
------------- ------------- -------------
(In Thousands)
Service cost............ $ 410 $ 2,272 $ 2,819 $ 2,676
Interest cost on
projected benefit
obligation............. 1,835 8,170 8,988 8,490
Expected return on plan
assets................. (2,176) (10,698) (12,127) (11,488)
Amortization of prior
service cost........... -- 1,090 1,173 1,048
Amortization of
transitional
obligation............. -- 186 217 217
Recognized actuarial
gain................... -- (821) (760) (710)
Settlement and
curtailment gain....... -- -- (1,216) --
------- -------- -------- --------
Total net pension cost.. $ 69 $ 199 $ (906) $ 233
======= ======== ======== ========
Health Care
Period from Period from
November 8 January 1
through through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
------------ ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
------------- ------------- -------------
(In Thousands)
Service cost............ $ 131 $ 624 $ 757 $ 828
Interest cost on
accumulated benefits
obligation............. 1,110 4,736 5,458 5,726
Expected return on plan
assets................. (405) (1,787) (2,066) (2,029)
Amortization of prior
service cost........... -- (882) (1,124) (1,190)
Recognized actuarial
gain................... -- (726) (900) (761)
Regulatory deferral..... 486 4,646 5,808 5,359
------ ------- ------- -------
Total net retiree health
care cost.............. $1,322 $ 6,611 $ 7,933 $ 7,933
====== ======= ======= =======
The previous tables do not reflect retirement pension enhancements of
$2,066,000 and $3,224,000 for 1999 and 1998, respectively, and retirement
health care enhancements of $143,000 for 1998.
F-13
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of Company plans and amounts
recorded in the Company's balance sheet as of December 31, 2000, November 7,
2000 and December 31, 1999 using actuarial measurement dates of December 31,
2000, November 7, 2000 and October 1, 1999:
Pensions
Period from Period from
November 8 January 1
through through Year Ended
December 31, November 7, December 31,
2000 2000 1999
------------ ------------- -------------
(Predecessor) (Predecessor)
------------- -------------
(In Thousands)
Change in benefit obligation
Balance at beginning of period........ $146,703 $131,873 $125,161
Service cost.......................... 410 2,272 2,819
Interest cost......................... 1,835 8,170 8,988
Plan merger........................... -- 6,283 --
Settlement loss....................... -- -- 306
Special termination benefits.......... -- -- 2,066
Benefits paid......................... (1,191) (6,700) (7,168)
Settlement payments................... -- -- (3,316)
Actuarial (gain) or loss.............. 9,528 4,805 3,017
-------- -------- --------
Balance at end of period.............. $157,285 $146,703 $131,873
======== ======== ========
Change in plan assets
Fair value, beginning of period....... $153,934 $154,143 $152,195
Plan merger........................... -- 5,707 --
Actual return on plan assets.......... 585 784 12,432
Employer contributions................ -- -- --
Benefits paid......................... (1,191) (6,700) (7,168)
Settlement payments................... -- -- (3,316)
Administrative expenses............... -- -- --
-------- -------- --------
Fair value at end of period........... $153,328 $153,934 $154,143
======== ======== ========
Reconciliation of funded status
Funded status......................... $ (3,957) $ 7,231 $ 22,270
Contributions for fourth quarter...... -- -- --
Unrecognized actuarial loss (gain).... 11,118 (5,800) (30,861)
Unrecognized transition obligation.... -- -- 221
Unrecognized prior service............ -- -- 12,417
-------- -------- --------
Net amount recognized for period...... $ 7,161 $ 1,431 $ 4,047
======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost.................. $ 7,161 $ 1,431 $ 7,424
Accrued benefit liability............. -- -- (3,377)
-------- -------- --------
Net amount............................ $ 7,161 $ 1,431 $ 4,047
======== ======== ========
F-14
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of Company plans and amounts
recorded in the Company's balance sheet as of December 31, 2000, November 7,
2000 and December 31, 1999 using actuarial measurement dates of December 31,
2000, November 7, 2000 and October 1, 1999:
Health Care
Period from Period from
November 8 January 1
through through Year Ended
December 31, November 7, December 31,
2000 2000 1999
------------ ------------- -------------
(Predecessor) (Predecessor)
------------- -------------
(In Thousands)
Change in benefit obligation
Balance at beginning of period........ $ 78,452 $ 78,223 $ 76,774
Service cost.......................... 131 623 757
Interest cost......................... 1,110 4,736 5,459
Plan amendments....................... -- -- 1,574
Settlement loss....................... -- -- --
Special termination benefits.......... -- -- --
Benefits paid......................... (467) (5,135) (5,602)
Settlement payments................... -- -- --
Actuarial (gain) or loss.............. 8,214 5 (739)
-------- -------- --------
Balance at end of period.............. $ 87,440 $ 78,452 $ 78,223
======== ======== ========
Change in plan assets
Fair value, beginning of period....... $ 28,600 $ 25,220 $ 24,308
Actual return on plan assets.......... (1,168) 3,380 912
Employer contributions................ 467 5,135 5,602
Benefits paid......................... (467) (5,135) (5,602)
Settlement payments................... -- -- --
Administrative expenses............... -- -- --
-------- -------- --------
Fair value at end of period........... $ 27,432 $ 28,600 $ 25,220
======== ======== ========
Reconciliation of funded status
Funded status......................... $(60,008) $(49,852) $(53,003)
Contributions for fourth quarter...... -- -- 1,401
Unrecognized actuarial loss (gain).... 9,788 (23,100) (19,570)
Unrecognized transition obligation.... -- -- --
Unrecognized prior service............ -- -- (6,138)
-------- -------- --------
Net amount recognized for period...... $(50,220) $(72,952) $(77,310)
======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost.................. $ -- $ -- $ --
Accrued benefit liability............. (50,220) (72,952) (77,310)
-------- -------- --------
Net amount............................ $(50,220) $(72,952) $(77,310)
======== ======== ========
F-15
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Retiree Benefits (Continued)
To fund health care benefits under its collective bargaining agreements,
the Company maintains a Voluntary Employee Beneficiary Association ("VEBA")
Trust to which it makes contributions from time to time. Plan assets are
invested in debt and equity marketable securities.
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
Period from Period from
November 8 January 1
through through Years Ended December 31,
December 31, November 7, ---------------------------
2000 2000 1999 1998
------------ ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor)
------------- ------------- -------------
Discount rate........... 7.0% 7.5% 7.5% 7.25%
Return on plan assets... 8.5% 8.5% 8.5% 8.5%
Increase in future
compensation........... 5.0% 5.0% 4.0 - 4.5% 4.5 - 5.0%
Health care inflation
trend.................. 8.0% 8.0% 8.0 - 10.0% 8.0%
The health care inflation rate for 2001 is assumed to be 8%. The rate is
assumed to decrease to 6% in 2005 and remain at that level thereafter. A one-
percentage-point increase or decrease in the assumed health care trend rate
for 2000 would have the following effects:
One- One-
Percentage- Percentage-
Point Increase Point Decrease
-------------- --------------
(In Thousands)
Service cost and interest cost components.... $ 58 $ (55)
Post-retirement benefit obligation........... $4,372 $(4,164)
(6) Leases
The Company leases certain facilities and equipment under long-term leases
which expire on various dates through the year 2014. Total rentals charged to
income under all lease agreements were $2,247,000 for the period November 8
through December 31, 2000, $8,685,000 for the period January 1 through
November 7, 2000, $9,846,000 in 1999, and $9,367,000 in 1998. The Company has
capitalized leases for an operations center (with a related party) and two LNG
facilities. A summary of property held under capital leases as of December 31
is as follows:
2000 1999
------- -------------
(Predecessor)
-------------
(In Thousands)
LNG Facilities......................................... $14,834 $14,834
Buildings.............................................. 6,000 6,000
------- -------
$20,834 $20,834
Less--Accumulated depreciation......................... 6,432 5,485
------- -------
Total Capital Leases................................... $14,402 $15,349
======= =======
In April 1999 the Company entered into a 15 year lease agreement for the
LNG facilities located in Salem and Lynn, Massachusetts. The facilities had
previously been leased by the Company's subsidiary, Mass LNG, under a lease
agreement which expired in 1997.
F-16
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Leases (Continued)
Under the terms of SFAS 71, the timing of expense recognition on
capitalized leases conforms with regulatory rate treatment. The Company has
included the rental payments on its financing leases in its cost of service
for rate purposes.
The Company also has various operating lease agreements for office
facilities and other equipment. The remaining minimum rental commitment for
these and all other noncancellable leases, including the financing leases, at
December 31, 2000 is as follows:
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
2001..................................................... $ 1,228 $ 6,587
2002..................................................... 1,379 3,524
2003..................................................... 1,584 1,394
2004..................................................... 1,584 785
2005..................................................... 1,584 370
Later Years.............................................. 13,464 --
------- -------
Total minimum lease payments............................. $20,823 $12,660
=======
Less--Amount representing interest and executory costs... 6,421
-------
Present value of minimum lease payments on capital
leases.................................................. $14,402
=======
(7) Fair Values of Financial Instruments
The following methods and assumptions were used to estimate the fair values
of financial instruments:
Cash--The carrying amounts approximate fair value.
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.
Preferred Stock--The fair value of the preferred stock is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term
debt and preferred stock at December 31, 2000 and 1999 are as follows:
2000 1999
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(Predecessor)
-----------------
(In Thousands)
Long-term debt........................... $224,402 $229,138 $225,349 $219,525
Preferred stock.......................... $ 16,742 $ 13,203 $ 26,454 $ 26,730
F-17
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(8) Restructuring Charge
During 1997, the Company recorded a restructuring charge of $8,692,000
related to its decision to exit the gas appliance repair and service business.
The charge included employee severance and termination benefits and other
costs. The Company completed its restructuring plan in 1998 resulting in a
$1,550,000 credit to income reflecting the amount by which the estimated cost
exceeded the actual costs of the restructuring.
(9) Related Party Transactions
The Company paid Eastern $833,000 for the period November 8 through
December 31, 2000, $4,167,000 for the period January 1 through November 7,
2000, $4,500,000 in 1999, and $4,200,000 in 1998 for legal, tax and corporate
services rendered.
The Company paid $129,000 for the period November 8 through December 31,
2000, $646,000 for the period January 1 through November 7, 2000, and $775,000
annually in 1999 and 1998 to lease an operations center from an affiliated
company.
On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through Eastern's merger with KeySpan. 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,
2000, the Company had outstanding borrowings of $114,843,000 and $82,307,000
for working capital and gas inventory, respectively. In 2000, the Company
expensed $868,000 and $811,000 for interest on these working capital and gas
inventory borrowings, 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 in
obtaining the required funds.
In November, 2000, the Company recorded a $600 million advance payable to
KeySpan. In 2000, the Company expensed $5,504,000 for interest and debt
issuance costs on this advance. Interest charges equal 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.
(10) 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") operations, including
former operating plants, gas holder locations and satellite disposal sites.
The Company may have or share responsibility under applicable environmental
laws for the remediation of 19 such sites. A subsidiary of New England
Electric System ("NEES") has assumed responsibility for remediating 11 of
these sites, subject to a limited contribution from the Company. The Company
also may have or share responsibility for the remediation of one non-MGP site.
The Company has estimated its potential share of the costs of investigating
and remediating the former MGP related sites and the non-MGP site in
accordance with SFAS No. 5, "Accounting for Contingencies," and the American
Institute of Certified Public Accountants Statement of Position 96-1,
"Environmental Remediation Liabilities." The Company has recorded a liability
of $18 million, which represents its best estimate of the likely cost within a
range of reasonable, foreseeable costs. However, there can be no assurance
that actual costs will not vary considerably from these estimates. 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.
F-18
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) Environmental Matters (Continued)
The Company is aware of 31 other former MGP related sites within its
service territory, one of which was identified in 2000. The NEES subsidiary
has provided full indemnification to the Company with respect to eight of the
31 sites. At this time, there is substantial uncertainty as to whether the
Company has or shares responsibility for remediating any of these sites. No
notice of responsibility has been issued to the Company for these sites from
any governmental environmental authority.
By a rate order issued on May 25, 1990, the Department approved the
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 has recognized an
insurance receivable of $3.3 million, reflecting a negotiated settlement with
an insurance carrier for MGP-related environmental expense indemnity, and a
regulatory asset of $14.7 million, representing the expected rate recovery of
environmental remediation costs, net of the insurance settlement. In light of
the indemnity agreement with the NEES subsidiary, the Department rate order on
MGP-related cost recovery, and the expected cost of remediating the non-MGP
site, the Company believes that it is not probable that actual costs will
materially affect its financial condition or results of operations.
(11) Workforce Reduction Program
As a result of the KeySpan merger, the Company has implemented a severance
program in an effort to reduce its workforce. The Company has recorded a
merger related liability of $6 million associated with this severance program.
This severance program is targeted to reduce the Company's workforce by an
additional 80 employees.
F-19
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Boston Gas Company:
We have audited the accompanying consolidated balance sheets of Boston Gas
Company (a Massachusetts Corporation and an indirect wholly-owned subsidiary
of KeySpan Corporation) and subsidiary as of December 31, 2000 and 1999, and
the related consolidated statements of earnings, retained earnings and cash
flows for the period from November 8, 2000 through December 31, 2000, the
period from January 1, 2000 through November 7, 2000, the year ended December
31, 1999 and the year ended December 31, 1998. 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 Boston Gas Company and
subsidiary as of December 31, 2000 and 1999 and the results of their
operations and their cash flows for the period from November 8, 2000 through
December 31, 2000, the period from January 1, 2000 through November 7, 2000,
the year ended December 31, 1999 and the year ended December 31, 1998, 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 a 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
January 24, 2001
F-20
BOSTON GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 2000 (Unaudited)
Period from Period from
Three Months Ended October 1 November 8
----------------------------------------- through through
March 31 June 30 Sept. 30 November 7 Dec. 31
------------- ------------- ------------- ------------- -----------
(Predecessor) (Predecessor) (Predecessor) (Predecessor)
------------- ------------- ------------- -------------
(In Thousands)
2000
Operating revenues...... $248,598 $93,459 $ 71,399 $ 40,327 $202,842
Operating margin........ $117,839 $53,787 $ 38,669 $ 18,733 $ 79,535
Operating earnings
(loss)................. $ 30,039 $ 593 $ (6,394) $(14,153) $ 20,783
Net earnings (loss)
applicable to common
stock.................. $ 25,030 $(3,900) $(10,790) $(15,802) $ 11,883
Three Months Ended
-------------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
------------- ------------- ------------- -------------
(Predecessor) (Predecessor) (Predecessor) (Predecessor)
------------- ------------- ------------- -------------
(In Thousands)
1999
Operating revenues...... $258,234 $96,958 $62,164 $175,363
Operating margin........ $117,497 $52,460 $38,585 $ 89,155
Operating earnings
(loss)................. $ 32,249 $ 1,242 $(3,548) $ 24,701
Net earnings (loss)
applicable to common
stock.................. $ 27,570 $(2,838) $(6,896) $ 20,076
In the opinion of management, the quarterly financial data includes all
adjustments, consisting only of normal recurring accruals, necessary for a
fair presentation of such information.
F-21
SCHEDULE II
BOSTON 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 Period From November 8, 2000 Through December 31, 2000
--------------------------------------------------------------
Reserve for doubtful
accounts............... $12,329 $ 2,687 $-- $ 1,335 $13,681
Reserve self-insurance.. $ 2,901 $ 250 $-- $ 260 $ 2,891
Reserve for
environmental
expenses............... $18,000 $ -- $-- $ -- $18,000
For The Period From January 1, 2000 Through November 7, 2000
------------------------------------------------------------
(Predecessor)
------------
Reserve for doubtful
accounts............... $14,816 $ 7,761 $-- $10,248 $12,329
Reserve self-insurance.. $ 3,913 $ 1,616 $-- $ 2,628 $ 2,901
Reserve for
environmental
expenses............... $18,000 $ -- $-- $ -- $18,000
For The Year Ended December 31, 1999
------------------------------------
(Predecessor)
------------
Reserve for doubtful
accounts............... $15,651 $10,975 $-- $11,810 $14,816
Reserve self-insurance.. $ 2,964 $ 2,829 $-- $ 1,880 $ 3,913
Reserve for
environmental
expenses............... $18,750 $ -- $-- $ 750 $18,000
For The Year Ended December 31, 1998
------------------------------------
(Predecessor)
------------
Reserve for doubtful
accounts............... $15,783 $12,950 $-- $13,082 $15,651
Reserve self-insurance.. $ 2,870 $ 1,873 $-- $ 1,779 $ 2,964
Reserve for
environmental
expenses............... $19,500 $ -- $-- $ 750 $18,750
F-22