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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
----------------
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1999
or
Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from to
Commission File Number 2-23416
BOSTON GAS COMPANY
(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.
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BOSTON GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 1999
TABLE OF CONTENTS
Item
No. Topic Page
---- ----- ----
PART I
1. Business
General........................................................... 1
Markets and Competition........................................... 1
Gas Throughput.................................................... 2
Gas Supply........................................................ 2
Regulation........................................................ 3
Seasonality and Working Capital................................... 4
Environmental Matters............................................. 5
Employees......................................................... 5
2. Properties........................................................ 5
3. Legal Proceedings................................................. 5
4. Submission of Matters to a Vote of Security Holders............... 5
Glossary.......................................................... 6
PART II
5. Market for the Registrant's Common Equity and Related Stockholder 7
Matters...........................................................
6. Selected Financial Data........................................... 7
7. Management's Discussion and Analysis of Financial Condition and 7
Results of Operations.............................................
8. Financial Statements and Supplementary Data....................... 10
9. Changes in and Disagreements with Accountants on Accounting and 10
Financial Disclosure..............................................
PART III
10. Directors and Executive Officers of the Registrant................ 11
11. Executive Compensation............................................ 11
12. Security Ownership of Certain Beneficial Owners and Management.... 11
13. Certain Relationships and Related Transactions.................... 11
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 12
PART I
Item 1. Business.
General
Boston Gas Company (the "Company"), is engaged in the transportation and
sale of natural gas to approximately 541,000 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 177 years.
All of the common stock of the Company is held by Eastern Enterprises
("Eastern"), which is headquartered in Weston, Massachusetts. Eastern has
owned Boston Gas Company since 1929.
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
For definition of certain industry specific terms, see the Glossary at the
end of Part I and appearing on page 6.
The Company provides local transportation services and gas supply to all
customer classes. The Company's services are available on a firm and non-firm
basis. Firm transportation service and sales are provided under rate tariffs
and/or contracts filed with the Massachusetts Department of Telecommunications
and Energy ("Department"), that typically obligate the Company to provide
service without interruption throughout the year. Non-firm transportation
service and sales are generally provided to large commercial/industrial
customers who can use gas or another energy source interchangeably. Non-firm
services are provided through individually negotiated contracts and, in most
cases, the price charged takes into account the price of the customer's
alternative fuel.
The Company offers unbundled services to all commercial/industrial users,
who are allowed to purchase local transportation from the Company separately
from the purchase of gas supply, which the customer may buy from third party
suppliers. The Company views these third party suppliers as partners in
marketing gas and increasing throughput and expects to work closely with them
to facilitate the unbundling process and ensure a smooth transition,
especially in the tracking and processing of transactions. The Company has
also implemented a program to educate commercial/industrial customers about
the opportunity to purchase gas from third-party suppliers, while still
relying on the utility for delivery. As of December 31, 1999, the Company had
approximately 4,700 firm transportation customers. Service to all residential
customers currently is on a bundled basis. Unbundled service to residential
customers is expected to be offered beginning in June 2000. While the
migration of customers to transportation-only service will lower the Company's
revenues, it has no impact on its operating earnings. The Company earns all of
its margins on the local distribution of gas and none on the resale of the
commodity itself.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. Over the last seven 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 43%, 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.
1
Gas Throughput
The following table in BCF provides information with respect to the volumes
of gas sold and transported by the Company during the three years 1997-1999.
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
Residential.................................... 39.3 37.9 41.7
Commercial and industrial...................... 27.3 28.2 35.7
Off-system sales............................... 5.6 12.7 7.4
-------- -------- --------
Total sales.................................. 72.2 78.8 84.8
Transportation of customer-owned gas........... 56.4 65.6 80.9
Less: Off-system sales......................... (5.6) (12.7) (7.4)
-------- -------- --------
Total throughput............................. 123.0 131.7 158.3
======== ======== ========
Total firm throughput........................ 109.1 107.8 120.0
======== ======== ========
The above table excludes the effect of adopting the accrual method of
revenue recognition as discussed in Note 1 of Notes to Consolidated Financial
Statements.
In 1999, 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 32% of total
throughput and 36% of total firm throughput, while commercial and industrial
customers accounted for 68% of total throughput and 64% of total firm
throughput. Approximately 67% 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 28% of
this transportation throughput under a contract which expires in November,
2000. The Company is uncertain whether or to what extent this contract will be
renewed.
No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 1999.
Gas Supply
The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1997-1999.
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
Natural gas purchases.......................... 65.9 71.2 75.2
Underground storage withdrawal................. 9.9 10.9 14.5
Liquefied natural gas ("LNG") purchases........ 1.9 -- 1.4
-------- -------- --------
Total source of supply....................... 77.7 82.1 91.1
Company use, unbilled and other................ (5.5) (3.3) (6.3)
-------- -------- --------
Total sales.................................. 72.2 78.8 84.8
======== ======== ========
Year to year variations in storage gas and unbilled gas reflect variations
in end-of-year customer requirements, due principally to weather. Given the
ready availability of supply, the Company purchased approximately two-thirds
of its peak pipeline supplies under firm short-term and spot contracts. The
balance of peak day pipeline requirements is purchased directly from producers
and marketers pursuant to long-term
2
contracts which have been reviewed and approved by the Department or by the
Federal Energy Regulatory Commission ("FERC").
Pipeline supplies are transported on interstate pipeline systems to the
Company's service territory pursuant to long-term contracts. FERC-approved
tariffs provide for fixed demand charges for the firm capacity rights 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")... 0.27 80.4 2000-2012
Tennessee Gas Pipeline Company ("Tennessee")....... 0.18 66.9 2003-2012
---- -----
0.45 147.3
==== =====
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 2000. 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 producing regions.
The Company has contracted with pipeline companies and others for the
storage of natural gas in underground storage fields located in Pennsylvania,
New York, Maryland and West Virginia. These contracts provide storage capacity
of 17.3 BCF and peak day deliverability of 0.16 BCF. The Company utilizes its
existing transportation contracts to transport gas from the storage fields to
its service territory. Supplemental supplies of LNG and propane are purchased
and produced from foreign and domestic sources.
In the fall of 1999, the Company, and its affiliates Colonial Gas Company
and Essex Gas Company, entered into a portfolio management contract with El
Paso Energy Marketing, Inc. For a three year term commencing November 1, 1999,
El Paso will provide all of the city gate supply requirements to the three
companies at market prices and manage certain of the companies' upstream
capacity, underground storage and term supply contracts. The Department
approved the contract in October 1999.
Peak day firm throughput in BCF was 0.64 in 1999, 0.57 in 1998, and 0.61 in
1997. 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, RI and
Everett, MA. The Company considers its peak day sendout capacity, based on its
total supply resources, to be adequate to meet the requirements of its firm
customers.
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause ("CGAC"), billed to firm sales
customers, allows for the semiannual adjustment of billing rates for firm gas
sales to reflect the actual cost of gas delivered to customers, including
demand charges for capacity on the interstate pipeline system. Similarly,
through its local distribution adjustment clause ("LDAC"), the Company
recovers the actual costs of approved energy efficiency programs, and the cost
of remediating former manufactured gas plant sites from all firm customers,
including those purchasing gas supply from third parties.
3
The Company's rates for local transportation service are governed by the
five year performance-based rate plan approved by the Department in 1996.
Under the plan approved by the Department, the Company's local transportation
rates are recalculated annually to reflect inflation for the previous 12
months, and reduced by a productivity factor of .50 percent. The productivity
factor will be the subject of a remand proceeding at the Department as
discussed below. The plan also provides for penalties if the Company fails to
meet specified service quality measures, with a maximum potential exposure of
$1 million, which will also be a subject in the Department's remand
proceeding. There is a margin 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. With respect to the appeal by the Company of the
Department's Order in D.P.U. 96-50, the Supreme Judicial Court issued an order
vacating: 1) the "accumulated inefficiencies" component of the productivity
factor, thereby reducing the productivity factor from 1.50 percent to .50
percent; and 2) the expansion of the service quality penalty beyond the $1
million proposed by the Company, and remanded these matters to the Department
for further proceedings, which actions were requested by the Department in its
motion for discharge of report and remand. The Department has stated that it
would consider in the remand proceedings whether there should be retroactive
recovery of those charges vacated by the court.
All of the Company's 43,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had approximately 4,700 firm transportation customers. Under the
February 1, 1999 Order by the Department which approved the service unbundling
program, commercial and industrial customers migrating from firm sales to firm
transportation are assigned, at cost, a pro-rata share of the upstream
pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which Local Distribution Companies
("LDC") tariffs for all residential customers will substantially conform. The
Model Terms and Conditions approved by the Department are consistent with the
Department's order of February 1, 1999, which provided that, for a five year
transition period, LDC contractual commitments to upstream capacity will be
assigned on a mandatory, pro rata basis to marketers selling gas supply to the
LDC's customers. The approved mandatory assignment method eliminates the
possibility that the costs of upstream capacity purchased by the Company to
serve firm customers will be absorbed by the LDC or other customers through
the transition period. The Department also found that, through the transition
period, LDC's will retain primary responsibility for upstream capacity
planning and procurement to assure that adequate capacity is available at
Massachusetts city gates to support customer requirements and growth. In year
three of the five year transition period, the Department intends to evaluate
the extent to which the upstream capacity market for Massachusetts is workably
competitive based on a number of factors, and accelerate or decelerate the
transition period accordingly. The Department's Model Terms and Conditions
also require that LDC's provide default and peaking supply services at cost-
based rates.
Seasonality and Working Capital
The Company's revenues, earnings and cash flow are highly seasonal as most
of its transportation services and sales are directly related to temperature
conditions. Since the majority of its revenues are billed in the November
through April heating season, significant cash flows are generated from late
winter to early summer. In addition, through the cost of gas adjustment
clause, the Company bills its customers over the heating season for the
majority of the pipeline demand charges paid by the Company over the entire
year. This difference, along with other costs of gas distributed but unbilled,
is reflected as deferred gas costs and is financed through short-term
borrowings. Short-term borrowings are also required from time to time to
finance normal business operations. As a result of these factors, short-term
borrowings are generally highest during the late fall and early winter.
4
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of former manufactured gas plant ("MGP") 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 11 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.
Employees
As of December 31, 1999, the Company had approximately 1,300 employees, 70%
of whom are organized in local unions with which the Company has collective
bargaining agreements that expire in 2002. During 1999, the Company entered
into new three-year labor agreements with the bargaining units representing
union employees.
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,
as the stored LNG can be vaporized into the 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, 1999, the Company's distribution system included
approximately 6,000 miles of gas mains, 422,000 services and 546,000 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 fee.
In 1999, the Company's capital expenditures were approximately $57 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 $67
million for similar purposes in 2000.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of Security Holders in the fourth quarter
of 1999.
5
Glossary
BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.
Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and peak-
shaving services.
Capacity--The capability of pipelines and supplemental facilities to deliver
and/or store gas.
City Gate--Physical interconnection between an interstate pipeline and the
local distribution company.
Core Customer--Generally, customers with no readily available energy
services alternative.
Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.
Firm Service--Sales and/or transportation service provided without
interruption throughout the year. Uninterrupted seasonal services are also
available for less than 365 days. Firm services are provided under either filed
rate tariffs or through individually negotiated contracts.
Gas Marketer (Broker)--A non-regulated buyer and seller of gas.
Interstate Transportation--Transportation of gas by an interstate pipeline
to the city gate.
Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to end-
user facilities.
Local Transportation Service--Transportation of gas by the LDC from the city
gate to the customer's burner tip.
Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.
Non-Firm Service--Sales and transportation service offered at a lower level
of reliability and cost. Under this service, the LDC can interrupt customers on
short notice, typically during the winter season. Non-firm services are
provided through individually negotiated contracts and, in most cases, the
price charged takes into account the price of the customer's energy
alternative.
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 is the holder of record of all of the outstanding common equity
securities of the Company. Dividends on such common equity amounted to $27.3
million and $17.9 million for 1999 and 1998, 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
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 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.
1998 Compared to 1997
Net earnings applicable to common stock for 1998 were $44.4 million which
includes the effect of a change in accounting for revenue recognition (see
Note 1 of Notes to The Financial Statements). This change in accounting
increased net earnings by $8.6 million, consisting of a one-time cumulative
effect for the years prior to 1998 of $8.2 million plus the impact of the
change on 1998 earnings of $.4 million. Excluding the effect of the change in
accounting, net earnings applicable to common stock were $35.8 million, a
decrease of $.8 million, or 2%, as compared to 1997.
Revenues in 1998 decreased $90.6 million or 13% compared to 1997. This
decrease reflects warmer weather ($46 million), the migration of customers
from sales to transportation service ($22 million), lower gas costs ($15
7
million), the absence of a 1997 non-recurring increase in revenues of $8.9
million related to a 1996 rate ruling in the recovery mechanism for the
portion of bad debt expense associated with gas costs and lower non-firm
sales, partially offset by throughput growth and higher average rates. The
revenue decrease associated with customer migration and lower gas costs 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.
Operating margin decreased $16.6 million, or 5.5%, principally due to
weather which was 13% warmer than 1997 ($13 million) and the absence of a 1997
non-recurring increase in revenues of $8.9 million described earlier partially
offset by customer growth ($4 million) and higher rates. Weather for 1998 was
9% warmer than normal compared to 4% colder than normal as experienced in
1997.
Operations and maintenance expenses decreased $7.9 million or 5.3%,
principally due to the recognition of service contract revenue of
approximately $5 million for annual contracts expiring in the third quarter of
1998 in addition to the reduction of related costs due to the Company's
decision to exit the gas appliance service business in 1997. Also contributing
to the decrease were warmer weather conditions and continued cost control
measures partially offset by the absence of a $2.1 million gain on the
settlement of pension obligations which occured in 1997.
Depreciation and amortization increased $2.1 million, or 5%, reflecting
continued investment in system expansion and replacement.
The absence of a 1997 restructuring charge of $8.7 million was offset by
the absence of the 1997 non-recurring revenue increase described earlier.
YEAR 2000 ISSUE
The Company experienced no significant issues as a result of the transition
from December 31, 1999 to January 1, 2000. The Company does not expect to
incur any significant Year 2000 related costs beyond January 2000.
The Company's cost to achieve Year 2000 compliance was approximately $15
million. Approximately 70% of these costs were incurred for capital projects
that resulted in added functionality.
FORWARD-LOOKING INFORMATION
This report and other Company reports and statements issued or made from
time to time contain certain "forward-looking statements" concerning projected
future financial performance, expected plans or future operations. The Company
cautions that actual results and developments may differ materially from such
projections or expectations.
Investors should be aware of important factors that could cause actual
results to differ materially from forward-looking projections or expectations.
These factors include, but are not limited to: the effect of strategic
initiatives on earnings and cash flow, the impact of any merger-related
activities, the ability to successfully integrate natural gas distribution
operations, temperatures above or below normal, changes in economic
conditions, including interest rates, regulatory and court decisions and
developments with respect to previously-disclosed environmental liabilities.
Most of these factors are difficult to predict accurately and are generally
beyond the control of the Company.
LIQUIDITY AND CAPITAL RESOURCES
To meet cash requirements and support its commercial paper program, the
Company has available up to $75 million of Eastern's committed credit
agreement and a $40 million uncommitted line of credit. The Company
8
also maintains a credit agreement that provides for the borrowing of up to $70
million for the exclusive purpose of funding its inventory of gas supplies or
to back commercial paper issued for the same purpose.
The Company expects capital expenditures for 2000 to be approximately $67
million. Capital expenditures will be largely for improvements to the
distribution system, for system expansion to meet customer growth and for
productivity improvements.
The Company believes that projected cash flow from operations, in
combination with currently available resources, is more than sufficient to
meet 2000 capital expenditures, working capital requirements, dividend
payments and normal debt repayments.
OTHER MATTERS
Regulation
The Company's operations are subject to Massachusetts statutes applicable
to gas utilities. Rates for transportation service, gas purchases and sales,
pipeline safety practices, issuance of securities, and affiliate transactions
are regulated by the Department. Rates for transportation service and gas
sales are subject to approval by and are on file with the Department. The
Company's cost of gas adjustment clause, billed to firm sales customers,
allows for the semiannual adjustment of billing rates for firm gas sales to
reflect the actual cost of gas delivered to customers, including demand
charges for capacity on the interstate pipeline system. Similarly, through its
local distribution adjustment clause, the Company 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 in 1996.
Under the plan approved by the Department, the Company's local transportation
rates are recalculated annually to reflect inflation for the previous 12
months, and reduced by a productivity factor of .50 percent. The productivity
factor will be the subject of a remand proceeding at the Department as
discussed below. The plan also provides for penalties if the Company fails to
meet specified service quality measures, with a maximum potential exposure of
$1 million, which will also be a subject in the Department's remand
proceeding. There is a margin 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. With respect to the appeal by the Company of the
Department's Order in D.P.U. 96-50, the Supreme Judicial Court issued an order
vacating: 1) the "accumulated inefficiencies" component of the productivity
factor, thereby reducing the productivity factor from 1.50 percent to .50
percent; and 2) the expansion of the service quality penalty beyond the $1
million proposed by the Company, and remanded these matters to the Department
for further proceedings, which actions were requested by the Department in its
motion for discharge of report and remand. The Department has stated that it
would consider in the remand proceedings whether there should be retroactive
recovery of those charges vacated by the court.
All of the Company's 43,000 commercial and industrial customers are
eligible to purchase unbundled local transportation service from the Company
and to purchase their gas supply from third parties. As of December 31, 1999,
the Company had approximately 4,700 firm transportation customers. Under the
February 1, 1999 Order by the Department which approved the service unbundling
program, commercial and industrial customers migrating from firm sales to firm
transportation are assigned, at cost, a pro-rata share of the upstream
pipeline capacity held by the Company to serve them.
Anticipating a date of June 1, 2000 for offering residential customers the
opportunity to purchase gas supply from third parties, the Department has
approved Model Terms and Conditions to which Local Distribution Companies
("LDC") tariffs for all residential customers will substantially conform. The
Model Terms and Conditions approved by the Department are consistent with the
Department's order of February 1, 1999, which
9
provided that, for a five year transition period, LDC contractual commitments
to upstream capacity will be assigned on a mandatory, pro rata basis to
marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that the costs of upstream
capacity purchased by the Company to serve firm customers will be absorbed by
the LDC or other customers through the transition period. The Department also
found that, through the transition period, LDC's will retain primary
responsibility for upstream capacity planning and procurement to assure that
adequate capacity is available at Massachusetts city gates to support customer
requirements and growth. In year three of the five year transition period, the
Department intends to evaluate the extent to which the upstream capacity
market for Massachusetts is workably competitive based on a number of factors,
and accelerate or decelerate the transition period accordingly. The
Department's Model Terms and Conditions also require that LDC's provide
default and peaking supply services at cost-based rates.
Environmental Matters
The Company may have or share responsibility under applicable environmental
law for the remediation of 19 sites related to former manufactured gas plant
("MGP") operations, including former operating plants, gas holder locations
and satellite disposal sites, as described in Note 11 of Notes to Consolidated
Financial Statements. 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 may also have or share
responsibility for the remediation of one non-MGP site. The Company has
recorded a liability of $18 million, which represents its best estimate at
this time of remediation costs, which may reasonably be estimated to range
from $18 million to $34 million. However, there can be no assurance that
actual costs will not vary considerably from these estimates.
The Company is aware of 30 other former MGP related sites within its
service territory, nine of which were identified in 1999. The NEES subsidiary
has provided full indemnification to the Company with respect to eight of the
30 sites. At this time, there is substantial uncertainty as to whether the
Company has or shares responsibility for remediating any of these other sites.
No notice of responsibility has been issued to the Company for any of 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 environmental expense indemnity, and a regulatory
asset of $14.7 million, representing the expected rate recovery of
environmental remediation costs. 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 such costs will materially affect its financial
condition or results of operations.
Item 8. Financial Statements and Supplementary Data.
Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
10
PART III
Item 10. Directors and Executive Officers of the Registrant.
Not required.
Item 11. Executive Compensation.
Not required.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Not required.
Item 13. Certain Relationships and Related Transactions.
Not required.
11
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.
(3) List of Exhibits.
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)).*
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 herewith).
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 herewith).
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).*
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).*
12
10.7 --Gas Storage Agreement between the Company and National Fuel
(formerly PennYork Energy Corporation) dated as of December 21, 1984
providing for storage demand of 6,031 dekatherms of Nataural gas per
day. (Filed as Exhibit 10.18 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1985).*
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 herewith).
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 herewith).
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 herewith).
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 herewith).
13
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
herewith).
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).*
14
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
herewith).
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
herewith).
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 herewith).
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 herewith).
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 herewith).
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 herewith).
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, and incorporated herein by
reference).
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 herewith).
10.40 --Credit Agreement dated as of December 22, 1993 by and among the
Company, Morgan Guaranty Trust Company of New York, National
Westminster Bank PLC, Shawmut Bank, N.A. and The First National Bank of
Boston. (Filed as Exhibit 10.17 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1993).*
10.41 --Sublease between the Company and Eastern Enterprises dated November 5,
1987. (Filed as Exhibit 10.20 to the Annual Report of the Company on
Form 10-K for the year ended December 31, 1987).*
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).*
15
22 --Subsidiaries of the Company (Filed as Exhibit 22 to the Annual Report
of the Company on Form 10-K for the year ended December 31, 1985).*
23 --Consent of Independent Certified Public Accountants.
27 --Financial Data Schedule for the twelve months ended December 31, 1999.
There were no reports on Form 8-K filed in the Fourth Quarter of 1999.
- --------
* Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
and Regulations under the Securities Exchange Act of 1934, reference is made
to the document previously filed with the Commission.
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Boston Gas Company
Registrant
Joseph F. Bodanza
By: _________________________________
Joseph F. Bodanza Senior Vice
President and Treasurer (Principal
Financial and Accounting Officer)
Dated: March 14, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 14th day of March, 2000.
Signature Title
Chester R. Messer Director and
- ------------------------------------- President
Chester R. Messer
Anthony J. DiGiovanni Director and Senior Vice
- ------------------------------------- President
Anthony J. DiGiovanni
Joseph F. Bodanza Director and Senior Vice President
- ------------------------------------- and
Joseph F. Bodanza Treasurer (Principal Financial and
Accounting Officer)
J. Atwood Ives Director
- -------------------------------------
J. Atwood Ives
Fred C. Raskin Director
- -------------------------------------
Fred C. Raskin
Walter J. Flaherty Director
- -------------------------------------
Walter J. Flaherty
L. William Law, Jr. Director
- -------------------------------------
L. William Law, Jr.
17
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-18
Consolidated Statements of Earnings for the Three Years Ended
December 31, 1999.............................................. F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998.... F-3 and F-4
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1999........................................ F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1999.............................................. F-6
Notes to Consolidated Financial Statements...................... F-7 to F-17
Interim Financial Information for the Two Years Ended December
31, 1999 (Unaudited)........................................... F-19
Schedule for the Three Years Ended December 31, 1999:
II--Valuation and Qualifying Accounts......................... F-20 to F-22
Schedules other than those listed above have been omitted as the
information has been included in the consolidated financial statements and
related notes or is not applicable nor required.
F-1
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
Operating revenues.............................. $592,719 $610,313 $700,945
Cost of gas sold................................ 295,022 324,538 398,566
-------- -------- --------
Operating margin................................ 297,697 285,775 302,379
-------- -------- --------
Operating expenses:
Operations.................................... 128,102 120,765 129,343
Maintenance................................... 23,037 19,819 19,134
Depreciation and amortization................. 45,779 46,535 44,413
Income taxes.................................. 24,093 23,927 22,510
Taxes, other than income...................... 22,042 21,144 22,027
Restructuring charge.......................... -- (1,550) 8,692
-------- -------- --------
Total operating expenses.................... 243,053 230,640 246,119
-------- -------- --------
Operating earnings.............................. 54,644 55,135 56,260
Other earnings, net............................. 1,979 583 298
-------- -------- --------
Earnings before interest expense................ 56,623 55,718 56,558
-------- -------- --------
Interest expense:
Long-term debt................................ 16,775 16,767 16,767
Other, including amortization of debt
expense...................................... 926 1,248 1,889
Less--Interest during construction............ (852) (469) (609)
-------- -------- --------
Total interest expense...................... 16,849 17,546 18,047
-------- -------- --------
Earnings before cumulative effect of change
in accounting principle........................ 39,774 38,172 38,511
Cumulative effect of change in accounting after
tax............................................ -- 8,193 --
-------- -------- --------
Net earnings.................................... 39,774 46,365 38,511
Preferred stock dividends....................... 1,862 1,926 1,926
-------- -------- --------
Earnings applicable to common stock............. $ 37,912 $ 44,439 $ 36,585
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
BOSTON GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
--------------------
1999 1998
--------- ---------
(In Thousands)
Gas plant, at cost....................................... $ 963,672 $ 914,017
Construction work-in-progress............................ 16,458 11,644
Less-Accumulated depreciation.......................... (393,991) (368,609)
--------- ---------
Net plant............................................ 586,139 557,052
--------- ---------
Current assets:
Cash................................................... 172 878
Accounts receivable, less reserves of $14,816 at
December 31, 1999 and $15,651 at December 31, 1998.... 61,429 62,250
Accounts receivable--affiliates........................ 23,644 2,008
Accrued utility margin................................. 20,067 14,147
Deferred gas costs..................................... 47,872 54,292
Natural gas and other inventories, at average cost..... 45,172 41,375
Materials and supplies, at average cost................ 3,399 2,852
Prepaid expenses....................................... 1,263 2,255
--------- ---------
Total current assets................................. 203,018 180,057
--------- ---------
Other assets:
Deferred postretirement benefits cost.................. 72,760 78,567
Deferred charges and other assets...................... 40,975 43,483
--------- ---------
Total other assets................................... 113,735 122,050
--------- ---------
Total assets......................................... $ 902,892 $ 859,159
========= =========
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,
-----------------
1999 1998
-------- --------
(In Thousands)
Capitalization:
Common stockholder's investment--
Common stock, $100 par value--
Authorized and outstanding--514,184 shares at December 31,
1999 and 1998............................................ $ 51,418 $ 51,418
Amounts in excess of par value............................ 43,233 43,233
Retained earnings......................................... 189,517 178,857
-------- --------
Total common stockholder's investment.................... 284,168 273,508
Cumulative preferred stock, $1 par value,
(liquidation preference, $25 per share)--
Authorized 1,200,000 shares; outstanding--1,080,000 shares
at December 31, 1999 and 1,200,000 at December 31, 1998... 26,454 29,360
Long-term obligations, less current portion................. 224,399 210,675
-------- --------
Total capitalization..................................... 535,021 513,543
Gas inventory financing..................................... 54,020 48,299
-------- --------
Total capitalization and gas inventory financing......... 589,041 561,842
-------- --------
Current liabilities:
Current portion of long-term obligations................... 950 561
Notes payable.............................................. 51,200 28,900
Accounts payable........................................... 47,969 48,986
Accrued taxes.............................................. 1,255 959
Accrued income taxes....................................... 5,543 10,282
Accrued interest........................................... 4,354 4,414
Customer deposits.......................................... 2,060 2,187
Refunds due customers...................................... 512 140
-------- --------
Total current liabilities................................ 113,843 96,429
-------- --------
Reserves and deferred credits:
Deferred income taxes...................................... 78,921 75,981
Unamortized investment tax credits......................... 4,240 5,082
Postretirement benefits obligation......................... 77,310 81,067
Environmental liability.................................... 18,000 18,750
Other...................................................... 21,537 20,008
-------- --------
Total reserves and deferred credits...................... 200,008 200,888
-------- --------
Total capitalization and liabilities..................... $902,892 $859,159
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
Balance at beginning of year..................... $178,857 $152,312 $133,980
Net earnings................................... 39,774 46,365 38,511
Preferred stock dividends ($1.61 per share in
1999, 1998 and 1997).......................... (1,862) (1,926) (1,926)
Cash dividends on common stock ($53.00 per
share in 1999, $34.80 per share in 1998, and
$35.50 per share in 1997)..................... (27,252) (17,894) (18,253)
-------- -------- --------
Balance at end of year........................... $189,517 $178,857 $152,312
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
BOSTON GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
----------------------------
1999 1998 1997
-------- -------- --------
(In Thousands)
Cash flows from operating activities:
Net earnings.................................... $ 39,774 $ 46,365 $ 38,511
Adjustments to reconcile net earnings to cash
provided by operating activities:
Depreciation and amortization.................. 45,779 46,535 44,413
Deferred taxes................................. 2,940 (3,147) 2,851
Other changes in assets and liabilities:
Accounts receivable........................... (20,815) 25,601 (13,027)
Accrued utility margin........................ (5,920) (14,147) --
Inventory..................................... (4,344) 3,679 5,190
Deferred gas costs............................ 6,420 12,303 8,742
Accounts payable.............................. (1,017) (12,945) (11,382)
Federal and state income taxes................ (4,739) (892) 21,585
Refunds due customers......................... 372 (2,996) (248)
Other......................................... 6,478 3,369 4,177
-------- -------- --------
Cash provided by operating activities............ 64,928 103,725 100,812
-------- -------- --------
Cash flows from investing activities:
Capital expenditures........................... (57,256) (60,266) (55,388)
Net cost of removal............................ (4,379) (5,099) (4,683)
-------- -------- --------
Cash used for investing activities............... (61,635) (65,365) (60,071)
-------- -------- --------
Cash flows from financing activities:
Changes in notes payable, net.................. 22,300 (10,800) (17,300)
Changes in inventory financing................. 5,721 (7,203) (92)
Amortization of preferred stock issuance
costs......................................... 94 34 34
Redemption of preferred stock.................. (3,000) -- --
Cash dividends paid on common and preferred
stock......................................... (29,114) (19,820) (24,550)
-------- -------- --------
Cash used for financing activities............... (3,999) (37,789) (41,908)
-------- -------- --------
Increase (decrease) in cash...................... (706) 571 (1,167)
Cash at beginning of year........................ 878 307 1,474
-------- -------- --------
Cash at end of year.............................. $ 172 $ 878 $ 307
======== ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized.......... $ 18,462 $ 18,879 $ 19,704
======== ======== ========
Income taxes.................................. $ 26,486 $ 34,046 $ 900
======== ======== ========
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
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 accounting policies of Boston Gas Company (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
No. 71 ("SFAS 71"), "Accounting for the Effects of Certain Types of
Regulation".
Principles of Consolidation
The Company is a wholly owned subsidiary of Eastern Enterprises
("Eastern"). The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary, Massachusetts LNG Incorporated, which
became inactive in 1999. All material intercompany balances and transactions
between the Company and its subsidiary have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
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. 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.
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:
1999 1998
------- -------
(In Thousands)
Post-retirement benefit costs............................ $72,760 $78,567
Environmental costs...................................... 17,703 18,190
Other.................................................... 733 1,365
------- -------
$91,196 $98,122
======= =======
F-7
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(1) Accounting Policies (Continued)
Regulatory liabilities total approximately $8,586,000 and $9,479,000 at
December 31, 1999 and 1998 respectively, and relate to income taxes.
As of December 31, 1999, all of the Company's regulatory assets and
liabilities are being 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 3, 6 and 11, respectively.
Gas Operating Revenues--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 increased net earnings by
$8,598,000, consisting of a one-time cumulative effect for the years prior to
1998 of $8,193,000 plus the impact of the change on 1998 earnings of $405,000.
On a proforma basis, this change would have increased 1997 net earnings by
$1,590,000.
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 1999, 5.2% in 1998,
and 5.2% in 1997. 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.
Pending Accounting Changes
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by SFAS No. 137, is effective for fiscal quarters of
all fiscal years beginning after June 15, 2000. SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or a liability measured at
its fair value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting. The Company has not yet quantified the impact of adopting SFAS No.
133 on the consolidated financial statements. However, SFAS No. 133 could
increase volatility in earnings and other comprehensive income.
Reclassifications
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
F-8
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(2) Cost of Gas Adjustment Clause and Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires the Company to semi-
annually adjust its rates for firm gas sales in order to track changes in the
cost of gas distributed, with an annual adjustment of subsequent rates for any
over or under recovery of actual costs incurred. As a result, the Company
defers the cost of any firm gas that has been distributed, but is unbilled at
the end of a period, to the period in which the gas is billed to customers. In
its order of November 29, 1996, the Department modified the CGAC to recover
the gas cost portion of the Company's bad debt write-offs effective December
1, 1996. The order also approved a local distribution adjustment clause
("LDAC") to recover the amortization of all environmental response costs
associated with former manufactured gas plant ("MGP") sites, FERC Order 636
transition costs, and costs related to the Company's various conservation and
load management programs from the Company's firm sales and transportation
customers. These costs were previously recovered through the CGAC.
(3) 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 38.2%
in 1999, 38.5% in 1998, and 36.9% in 1997 which includes the effect of prior
years tax benefits of 1.8%. State taxes represent the majority of the
difference between the effective rate and the federal income tax rate of 35%.
A summary of the provision for income taxes for the three years ended
December 31 is as follows:
1999 1998 1997
------- ------- -------
(In Thousands)
Current--
Federal......................................... $17,756 $21,997 $11,670
State........................................... 4,801 5,408 2,692
------- ------- -------
Total current provision....................... 22,557 27,405 14,362
Deferred--
Federal......................................... 2,244 (2,119) 6,998
State........................................... (708) (1,359) 1,150
------- ------- -------
Total deferred provision...................... 1,536 (3,478) 8,148
------- ------- -------
Provision for income taxes........................ $24,093 $23,927 $22,510
======= ======= =======
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, 1999 the Company had a regulatory liability of $2,250,000
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
$6,336,000 as of December 31, 1999.
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
F-9
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
temporary differences between financial reporting and taxable income.
Significant items making up deferred tax assets and liabilities at December
31, 1999 and 1998 are as follows:
1999 1998
--------- ---------
(In Thousands)
Assets:
Regulatory liabilities.............................. $ 3,425 $ 3,775
Other............................................... 16,723 13,948
--------- ---------
Total deferred tax assets........................... $ 20,148 $ 17,723
--------- ---------
Liabilities:
Accelerated depreciation............................ $ (84,151) $ (82,985)
Deferred gas costs.................................. (14,183) (13,062)
Other............................................... (11,073) (14,231)
--------- ---------
Total deferred tax liabilities...................... $(109,407) $(110,278)
--------- ---------
Total net deferred taxes............................ $ (89,259) $ (92,555)
========= =========
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
approximately $842,000 in 1999, $849,000 in 1998 and $906,000 in 1997.
(4) Commitments
Long-term Obligations
The following table provides information on long-term obligations as of
December 31:
1999 1998
-------- --------
(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 7)..................... 15,349 1,236
Less current portion................................... (950) (561)
-------- --------
$224,399 $210,675
======== ========
The Company currently has a shelf registration covering the issuance of up
to $100,000,000 of Medium-Term Notes, of which $60,000,000 of Medium-Term
Notes, Series C have been issued as of December 31, 1999.
There are no sinking fund requirements for the next five years related to
the $210,000,000 of Medium-Term Notes outstanding at December 31, 1999 and
none are callable prior to maturity.
Annual maturities of capital lease obligations for the next five years are
$950,000, $408,000, $586,000, $840,000 and $891,000 for 2000 through 2004,
respectively.
Gas Inventory Financing
Under the terms of the general rate order issued by the Department
effective October 1, 1988, the Company funds its inventory of gas supplies
through external sources. All costs related to this funding are recoverable
F-10
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Commitments (Continued)
from customers. The Company maintains a long-term credit agreement with a
group of banks which provides for the borrowing of up to $70,000,000 for the
exclusive purpose of funding its inventory of gas supplies or for backing
commercial paper issued for the same purpose. The Company had $54,020,000 and
$48,299,000 of commercial paper outstanding to fund its inventory of gas
supplies at December 31, 1999 and 1998, respectively. Because the commercial
paper is supported by the credit agreement, these borrowings have been
classified as non-current in the accompanying consolidated balance sheets. The
credit agreement includes a one-year revolving credit facility which may be
converted to a two-year term loan at the Company's option if the one-year
revolving credit facility is not renewed by the banks. The Company may select
the agent bank's prime rate or, at the Company's option, various pricing
alternatives. The agreement requires a facility fee of 8.5 basis points on the
commitment. No borrowings were outstanding under this agreement during 1999
and 1998.
Short-Term Debt and Lines of Credit
Eastern maintains a credit agreement with a group of banks which provides
for the borrowing by Eastern of up to $100,000,000 (of which up to $75,000,000
may be borrowed or used to back commercial paper issued by the Company) at any
time through December 31, 2001. The interest rate for borrowings is the agent
bank's prime rate, or at the borrower's option, various pricing alternatives.
The Company had outstanding borrowings of $20,000,000 and $28,900,000 in
commercial paper backed by this agreement at December 31, 1999 and 1998,
respectively. The weighted average interest rate on these borrowings was 6.05%
at December 31, 1999 and 5.10% at December 31, 1998.
In addition to the $75,000,000 available under the Eastern credit
agreement, the Company has an uncommitted line of credit of $40,000,000 under
which it may borrow through December 31, 2000. The interest rate for such
borrowings is a function of federal funds, money market or prime rates. The
Company had outstanding borrowings of $31,200,000 at December 31, 1999 at a
weighted average interest rate of 5.95%. There were no borrowings outstanding
under this uncommitted line at December 31, 1998.
(5) Preferred Stock
The Company has outstanding 1,080,000 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, 1999 the
Company redeemed 120,000 shares, or 10% of the outstanding shares, at the
liquidation price of $25 per share.
(6) Retiree Benefits
The Company, through participation in Eastern-administered plans and other
union retirement and welfare plans, 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-11
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) 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 information for 1997 has been restated to
conform to the current presentation. The net cost for these plans and
agreements charged to expense was as follows:
Pensions
1999 1998 1997
-------- -------- --------
(In Thousands)
Service cost................................. $ 2,819 $ 2,676 $ 2,838
Interest cost on projected benefit
obligation.................................. 8,988 8,490 8,632
Expected return on plan assets............... (12,127) (11,488) (10,925)
Amortization of prior service cost........... 1,173 1,048 1,048
Amortization of transitional obligation...... 217 217 217
Recognized actuarial gain.................... (760) (710) (310)
Settlement and curtailment gain.............. (1,216) -- (2,003)
-------- -------- --------
Total net pension cost....................... $ (906) $ 233 $ (503)
======== ======== ========
Health Care
1999 1998 1997
-------- -------- --------
(In Thousands)
Service cost................................. $ 757 $ 828 $ 789
Interest cost on accumulated benefits
obligation.................................. 5,458 5,726 5,704
Expected return on plan assets............... (2,066) (2,029) (1,523)
Amortization of prior service cost........... (1,124) (1,190) (1,190)
Recognized actuarial gain.................... (900) (761) (484)
Regulatory deferral.......................... 5,808 5,359 4,637
-------- -------- --------
Total net retiree health care cost........... $ 7,933 $ 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-12
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) 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, 1999 and 1998 using
actuarial measurement dates of October 1, 1999 and 1998:
Pensions Health Care
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
(In Thousands)
Change in benefit obligation
Balance at beginning of year........... $125,161 $115,945 $ 76,774 $ 78,800
Service cost........................... 2,819 2,676 757 828
Interest cost.......................... 8,988 8,490 5,459 5,726
Plan amendments........................ -- -- 1,574 --
Settlement loss........................ 306 -- -- --
Special termination benefits........... 2,066 3,224 -- 143
Benefits paid.......................... (7,168) (7,686) (5,602) (5,019)
Settlement payments.................... (3,316) -- -- --
Actuarial (gain) or loss............... 3,017 2,512 (739) (3,704)
-------- -------- -------- --------
Balance at end of year................. $131,873 $125,161 $ 78,223 $ 76,774
======== ======== ======== ========
Change in plan assets
Fair value, beginning of year.......... $152,195 $165,857 $ 24,308 $ 23,877
Actual return on plan assets........... 12,432 (5,929) 912 431
Employer contributions................. -- -- 5,602 5,019
Benefits paid.......................... (7,168) (7,686) (5,602) (5,019)
Settlement payments.................... (3,316) -- -- --
Administrative expenses................ -- (47) -- --
-------- -------- -------- --------
Fair value at end of year.............. $154,143 $152,195 $ 25,220 $ 24,308
======== ======== ======== ========
Reconciliation of funded status
Funded status.......................... $ 22,270 $ 27,034 $(53,003) $(52,466)
Contributions for fourth quarter....... -- -- 1,401 1,254
Unrecognized actuarial (gain).......... (30,861) (32,120) (19,570) (21,018)
Unrecognized transition obligation..... 221 437 -- --
Unrecognized prior service............. 12,417 9,855 (6,138) (8,837)
-------- -------- -------- --------
Net amount recognized year end......... $ 4,047 $ 5,206 $(77,310) $(81,067)
======== ======== ======== ========
Amounts recognized in balance sheet
Prepaid benefit cost................... $ 7,424 $ 8,139 $ -- $ --
Accrued benefit liability.............. (3,377) (2,933) (77,310) (81,067)
-------- -------- -------- --------
Net amount............................. $ 4,047 $ 5,206 $(77,310) $(81,067)
======== ======== ======== ========
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.
F-13
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the
projected benefit obligation:
1999 1998 1997
---------- --------- ----------
Discount rate............................. 7.5% 7.25% 7.5%
Return on plan assets..................... 8.5% 8.5% 8.5%
Increase in future compensation........... 4.0 - 4.5% 4.5 - 5.0% 4.75 - 5.0%
Health care inflation trend............... 8.0 - 10.0% 8.0% 7.0%
The health care inflation rate for 2000 is assumed to be 8.0% and 10.0% for
pre-65 and post-65 health care benefits, respectively. The rate is assumed to
decrease gradually to 5.0% in 2006 for pre-65 benefits (2008 for post-65
benefits) and remain at that level thereafter. A one-percentage-point increase
or decrease in the assumed health care trend rate for 1999 would have the
following effects:
One- One-
Percentage- Percentage-
Point Increase Point Decrease
-------------- --------------
(In Thousands)
Service cost and interest cost components.... $ 449 $ (398)
Post-retirement benefit obligation........... $5,178 $(4,631)
(7) 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 approximately $9,846,000 in 1999,
$9,367,000 in 1998, and $10,112,000 in 1997. The Company has capitalized
leases for an operations center and two LNG facilities. A summary of property
held under capital leases as of December 31 is as follows:
1999 1998
------- ------
(In Thousands)
LNG Facilities............................................... $14,834 $ --
Buildings.................................................... 6,000 6,000
------- ------
$20,834 $6,000
Less--Accumulated depreciation............................... 5,485 4,764
------- ------
Total Capital Leases......................................... $15,349 $1,236
======= ======
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.
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. Therefore, the total depreciation and interest expense that
was recorded on the leases was equal to the rental payments included in other
operating and maintenance expense in the accompanying consolidated statements
of earnings.
F-14
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(7) Leases (Continued)
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, 1999 is as follows:
Capital Operating
Year Leases Leases
---- ------- ---------
(In Thousands)
2000..................................................... $ 1,833 $ 4,647
2001..................................................... 1,228 3,437
2002..................................................... 1,379 2,092
2003..................................................... 1,584 436
2004..................................................... 1,584 236
Later Years.............................................. 15,048 --
------- -------
Total minimum lease payments............................. $22,656 $10,848
=======
Less--Amount representing interest and executory costs... 7,307
-------
Present value of minimum lease payments on capital
leases.................................................. $15,349
=======
(8) 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, 1999 and 1998 are as follows:
1999 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(In Thousands) (In Thousands)
Long-term debt........................... $225,349 $219,525 $211,236 $248,341
Preferred stock.......................... $ 26,454 $ 26,730 $ 29,360 $ 30,076
(9) Restructuring Charge
During the fourth quarter of 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 $5,369,000 for employee severance
and termination benefits associated with the elimination of approximately 130
bargaining unit and management positions. The remaining $3,323,000 related to
the disposition of assets, the cancellation of lease obligations,
communications, legal and other related 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. The restructuring charge is reported as a component of
operating expenses in the consolidated statement of earnings.
F-15
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) Related Party Transactions
The Company paid Eastern $4,500,000 in 1999, $4,200,000 in 1998, and
$4,300,000 in 1997 for legal, tax and corporate services rendered.
In December 1996, Eastern Rivermoor Company, Inc., a wholly owned
subsidiary of Eastern, purchased the Company's primary operations center from
a third party and assumed the current lease agreement with the Company. During
1999, 1998 and 1997 the Company paid $775,000, $775,000 and $752,000,
respectively to Eastern Rivermoor Company, Inc.
(11) 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. The nineteenth site was identified
in 1999. 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 at this time of remediation costs, which may
reasonably be estimated to range from $18 million to $34 million. 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.
The Company is aware of 30 other former MGP related sites within its
service territory, nine of which were identified in 1999. The NEES subsidiary
has provided full indemnification to the Company with respect to eight of the
30 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.
(12) Merger
On November 4, 1999, Eastern signed a definitive agreement to be acquired
by KeySpan Corporation. Subject to receipt of satisfactory regulatory
approvals and the approval of Eastern shareholders, the transaction is
expected to close in mid to late 2000, although it is possible that the
transaction will not close until 2001.
F-16
BOSTON GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(13) Commitments and Contingencies
Boston Gas maintains employment agreements with certain employees. The
pending KeySpan merger is expected to trigger the change of control provisions
under these agreements which, in the event of a termination, provide for one
to three times salary and bonus as severance and, in certain circumstances, a
tax gross-up and enhanced retirement benefits. The maximum contingent
liability under these agreements is approximately $8 million.
F-17
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 wholly-owned subsidiary of Eastern
Enterprises) and subsidiary as of December 31, 1999 and 1998, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1999. These consolidated
financial statements and the schedules referred to below 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, 1999 and 1998 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index to
consolidated financial statements are presented for purposes of complying with
the Securities and Exchange Commission's rules and are not a part of the basic
financial statements. These schedules have 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.
As explained in Note 1 to the financial statements, effective January 1,
1998, the Company changed its method of accounting for unbilled revenue.
Arthur Andersen LLP
Boston, Massachusetts
January 21, 2000
F-18
BOSTON GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the Two Years Ended December 31, 1999 (Unaudited)
Three Months Ended
------------------------------------
Sept.
March 31 June 30 30 Dec. 31
-------- -------- ------- --------
(In Thousands)
1999
Operating revenues....................... $258,234 $ 96,958 $62,164 $175,363
Operating margin......................... $117,497 $ 52,460 $37,585 $ 90,155
Operating earnings (loss)................ $ 32,249 $ 1,287 $(3,548) $ 24,656
Net earnings (loss) applicable to common
stock................................... $ 27,570 $ (2,838) $(6,896) $ 20,076
1998
Operating revenues....................... $267,204 $107,763 $62,777 $172,569
Operating margin......................... $111,688 $ 53,526 $37,584 $ 82,977
Operating earnings (loss)................ $ 30,931 $ 5,229 $(2,623) $ 21,598
Cumulative effect of change in accounting
principle............................... $ 8,193 $ -- $ -- $ --
Net earnings (loss) applicable to common
stock................................... $ 34,005 $ 573 $(7,011) $ 16,872
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-19
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1999
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1998 to Income Accounts Reserves 1999
----------- ------------ ---------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 15,651 $10,975 $-- $11,810 $ 14,816
======== ======= ==== ======= ========
RESERVES INCLUDED IN
LIABILITIES:
Reserve for
postretirement benefit
cost.................. $ 81,067 $ 2,579 $-- $ 6,336 $ 77,310
Reserve for self-
insurance............. 2,964 2,829 -- 1,880 3,913
Reserve for
environmental
expenses.............. 18,750 -- -- 750 18,000
Reserve for pension.... 2,933 1,661 -- 1,217 3,377
-------- ------- ---- ------- --------
Total reserves included
in liabilities........ $105,714 $ 7,069 $-- $10,183 $102,600
======== ======= ==== ======= ========
F-20
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1997 to Income Accounts Reserves 1998
----------- ------------ ---------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $ 15,783 $12,950 $-- $13,082 $ 15,651
======== ======= ==== ======= ========
RESERVES INCLUDED IN
LIABILITIES
Reserve for
postretirement benefit
cost.................. $ 83,274 $ 2,717 $-- $ 4,924 $ 81,067
Restructuring Reserve.. 6,845 (1,550) -- 5,295 --
Reserve for self-
insurance............. 2,870 1,873 -- 1,779 2,964
Reserve for
environmental
expenses.............. 19,500 -- -- 750 18,750
Reserve for pension.... 1,648 1,285 -- -- 2,933
-------- ------- ---- ------- --------
Total reserves included
in liabilities........ $114,137 $ 4,325 $ $12,748 $105,714
======== ======= ==== ======= ========
F-21
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
(In Thousands)
Additions
------------------- Net
Balance, Charged Charged Deductions Balance,
December 31, (Credited) to Other from December 31,
Description 1996 to Income Accounts Reserves 1997
----------- ------------ ---------- -------- ---------- ------------
RESERVES DEDUCTED FROM
ASSETS:
Reserves for doubtful
accounts.............. $15,963 $13,222 $ -- $13,402 $ 15,783
======= ======= ======= ======= ========
RESERVES INCLUDED IN
LIABILITIES:
Postretirement benefit
cost.................. $84,827 $ 3,295 $ -- $ 4,848 $ 83,274
Restructuring Reserve.. -- 8,692 -- 1,847 6,845
Reserve for self-
insurance............. 2,240 2,461 -- 1,831 2,870
Reserve for
environmental
expenses.............. -- -- 19,500 -- 19,500
Reserve for pension.... 2,992 (1,344) -- -- 1,648
------- ------- ------- ------- --------
Total reserves included
in liabilities........ $90,059 $13,104 $19,500 $ 8,526 $114,137
======= ======= ======= ======= ========
F-22