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, 2002
or
___ Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from to
Commission File Number 2-23416
BOSTON GAS COMPANY
D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND
(Exact Name of Registrant As Specified In Its Charter)
Massachusetts 04-1103580
(State or other jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
One Beacon Street (617) 742-8400
Boston, Massachusetts 02108 (Registrant's Telephone Number)
(Address of Principal Executive Offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Exchange
------------------- --------
None None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
Indicate the number of shares outstanding of the registrant's class of common
stock as of March 1, 2002.
All common stock, 514,184 shares, are held by KeySpan New England LLC .
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.
BOSTON GAS COMPANY
FORM 10-K
Fiscal Year Ended December 31, 2002
TABLE OF CONTENTS
Item
No Topic Page
-- ----- ----
PART I
1. Business
General............................................................................................................ 1
Forward-Looking Information........................................................................................ 1
Markets and Competition............................................................................................ 2
Gas Throughput..................................................................................................... 2
Gas Supply......................................................................................................... 3
Regulation......................................................................................................... 4
Seasonality and Working Capital.................................................................................... 4
Environmental Matters.............................................................................................. 4
Employees.......................................................................................................... 4
2. Properties......................................................................................................... 5
3. Legal Proceedings.................................................................................................. 5
4. Submission of Matters to a Vote of Security Holders................................................................ 5
Glossary........................................................................................................... 6
PART II
5. Market for the Registrant's Common Equity and Related Stockholder Matters.......................................... 7
6. Selected Financial Data............................................................................................ 7
7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 7
7A. Quantitative and Qualitative Disclosures About Market Risk......................................................... 10
8. Financial Statements and Supplementary Data........................................................................ 11
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................... 11
PART III
10. Directors and Executive Officers of the Registrant................................................................. 12
11. Executive Compensation............................................................................................. 12
12. Security Ownership of Certain Beneficial Owners and Management..................................................... 12
13. Certain Relationships and Related Transactions..................................................................... 12
14. Controls and Procedures............................................................................................ 12
PART IV
15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................................................... 13
PART I
Item 1. Business.
General
Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein
as the "Company", "we", "us" and "our"), is a gas distribution company engaged
in the transportation and sale of natural gas to approximately 563,000
residential, commercial and industrial customers in Boston, Massachusetts and 73
other communities in eastern and central Massachusetts. We are the largest
natural gas distribution company in New England and have been in business for
180 years.
We are a wholly-owned subsidiary of KeySpan New England, LLC ("KNE LLC")
(formerly known as Eastern Enterprises). On November 8, 2000, KeySpan
Corporation ("KeySpan") acquired all of the common stock of KNE LLC. The
transaction was accounted for as a purchase, with KeySpan being the acquiring
company. KNE LLC has owned Boston Gas Company since 1929. KeySpan is a
registered holding company under the Public Utility Holding Company Act
("PUHCA") of 1935, as amended. As a result, its activities, as well as certain
activities of its subsidiaries, including the Company, are regulated by the
Securities and Exchange Commission (the "SEC") under PUHCA.
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. Our 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 us to provide service without
interruption throughout the year. Non-firm transportation service and sales are
generally provided to large commercial/industrial customers who can use gas or
another energy source interchangeably. Non-firm services are provided through
individually negotiated contracts and, in most cases, the price charged takes
into account the price of the customer's alternative fuel.
The Company offers unbundled services to all of its customers who are allowed to
purchase local transportation from us separately from the purchase of gas
supply, which the customer may buy from third-party suppliers. We view these
third-party suppliers as partners in marketing gas and increasing throughput and
expect to work closely with them to facilitate the unbundling process and ensure
a smooth transition, especially in the tracking and processing of transactions.
We implemented programs to educate customers about the opportunity to purchase
gas from third-party suppliers, while still relying on us for delivery. As of
December 31, 2002, we had approximately 5,800 firm commercial and industrial
transportation customers. Unbundled service to residential customers became
available on November 1, 2000. While the migration of customers to
transportation-only service will lower our revenues, it has no impact on our
operating earnings. We earn all of our margins on the local distribution of gas
and none on the resale of the commodity itself.
Forward-Looking Information
Certain statements contained in this Annual Report on Form 10-K concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are " forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosure about Market
Risk," relating to our future outlook, anticipated capital expenditures, future
cash flows and borrowings, pursuit of potential future acquisition opportunities
and sources of funding, are forward-looking statements. Such forward-looking
statements reflect numerous assumptions and involve a number of risks and
uncertainties and actual results may differ materially from those discussed in
such statements.
1
Among the factors that could cause actual results to differ materially are:
general economic conditions, especially in Massachusetts; fluctuations in
weather; volatility of energy prices, including natural gas; available sources
and cost of fuel; federal and state regulatory initiatives that increase
competition, threaten cost and investment recovery, and impact rate structures;
the ability of the Company to successfully reduce its cost structure;
inflationary trends and interests rates; implementation of new accounting
standards; retention of key personnel; creditworthiness of counter-parties to
derivative instruments and commodity contracts; and other risks detailed from
time to time in other reports and other documents filed by the Company with the
SEC. For any of these statements, the Company claims the protection of the safe
harbor for forward-looking information contained in the Private Securities
Litigation Reform Act of 1995, as amended. For additional discussion on these
risks, uncertainties and assumptions, see Item 1. "Business", Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." and Item 7A. "Quantitative and Qualitative Disclosure about Market
Risk," contained herein.
Markets and Competition
The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. We believe that there are significant
opportunities to increase the number of natural gas customers by converting
residential, industrial and commercial customers from oil-to-gas for space
heating purposes. However, increasing the number of natural gas customers cannot
be predicted with certainty and will depend on such factors as the price of
competitive energy sources, the level of investment required and customer
perception of relative value.
Gas Throughput
The following table in BCF provides information with respect to the volumes of
gas sold and transported by the Company during the three years 2000-2002.
- ------------------------------------------------------------------------------------------------
Years Ended December 31,
2002 2001 2000
- ------------------------------------------------------------------------------------------------
Residential 41.7 41.9 43.2
Commercial and industrial 20.9 21.9 25.4
Off-system sales 0.1 0.2 2.6
- ------------------------------------------------------------------------------------------------
Total sales 62.7 64.0 71.2
Transportation of customer-owned gas 65.6 61.9 55.8
Less: Off-system sales (0.1) (0.2) (2.6)
- ------------------------------------------------------------------------------------------------
Total throughput 128.2 125.7 124.4
- ------------------------------------------------------------------------------------------------
Total firm throughput 127.3 124.9 122.4
- ------------------------------------------------------------------------------------------------
The above table excludes the effect of the accrual method of revenue recognition
as discussed in Note 1 of the Notes to Financial Statements.
In 2002, residential customers comprised 91% of our customer base, while
commercial and industrial customers accounted for the remaining 9%.
Volumetrically, residential customers accounted for 33% of total firm
throughput, while commercial and industrial customers accounted for 67% of total
firm throughput. Approximately 76% of commercial and industrial customers' total
throughput was transportation-only service. Sithe Energy, an independent power
generator on our system, was responsible for approximately 25% of this
transportation throughput under a contract which was renewed through March,
2004. Sithe, however, has an option to cancel the contract with 60 days
notification. They have also notified us that they do not intend to extend the
contract beyond March 2004. The anticipated loss in annual transportation
revenues is expected to be $3.4 million, or $2.2 million, net of taxes.
No customer, or group of customers under common control, accounted for 2% or
more of total firm revenues in 2002.
2
Gas Supply
The following table in BCF provides information with respect to our sources of
supply during the three years 2000-2002.
- ---------------------------------------------------------------------------------------------------
Years Ended December 31,
2002 2001 2000
- ---------------------------------------------------------------------------------------------------
Natural gas purchases 58.3 52.3 59.6
Underground storage withdrawal 8.5 6.0 12.5
Liquefied natural gas ("LNG") purchases 1.3 1.9 5.3
- ---------------------------------------------------------------------------------------------------
Total source of supply 68.1 60.2 77.4
Company use, unbilled and other (5.4) 3.8 (6.2)
- ---------------------------------------------------------------------------------------------------
Total sales 62.7 64.0 71.2
- ---------------------------------------------------------------------------------------------------
Year-to-year variations in storage gas and unbilled gas reflect variations in
end-of-year customer requirements, due principally to weather.
The vast majority of our gas supplies are transported on interstate pipeline
systems to our service territory pursuant to long-term contracts. Federal Energy
Regulatory Commission ("FERC") approved tariffs provide for fixed demand charges
for the firm capacity rights under these contracts for the interstate pipeline
companies that provide firm transportation service to our service territory. The
peak daily, annual capacity and contract expiration dates are as follows:
Capacity in BCF
- ------------------------------------------------------------------------------------------------------------------
Expiration
Pipeline Daily Annual Dates
- ------------------------------------------------------------------------------------------------------------------
Algonquin Gas Transmission Company ("Algonquin") 0.29 85.9 10/05-04/13
Tennessee Gas Pipeline Company ("Tennessee") 0.24 88.1 10/08-11/12
- ------------------------------------------------------------------------------------------------------------------
0.53 174.0
- ------------------------------------------------------------------------------------------------------------------
In addition to capacity on the Algonquin and Tennessee systems, we have firm
capacity contracts upstream of both pipelines in order to transport natural gas
purchased by us from various areas of gas production.
We have also contracted with pipeline companies and others for the storage of
natural gas in underground storage fields located in Pennsylvania, New York,
Maryland and West Virginia. These contracts provide storage capacity of 16.3 BCF
and peak day deliverability of 0.18 BCF. We utilize existing transportation
contracts to transport gas from the storage fields to our service territory.
Supplemental supplies of LNG and propane are produced by and purchased from
foreign and domestic sources.
The Company operated under a portfolio management contract with El Paso Merchant
Energy Gas, L.P. ("El Paso"), from November 1, 1999 through October 31, 2002. El
Paso was responsible for providing the majority of the city gate supply
requirements to the Company, in addition to managing certain of the Company's
and certain affiliates upstream capacity, underground storage and term supply
contracts. We negotiated an interim agreement with Entergy-Koch that replaced
the expired El Paso agreement. The interim agreement commenced on November 1,
2002 and extends through March 31, 2003. On April 1, 2003, a new portfolio
management agreement will become effective with Entergy-Koch with a term of
three years.
3
Peak day firm throughput in BCF was 0.86 in 2002, 0.63 in 2001, and 0.80 in
2000. We provide 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 mainly at points on our distribution
system. We own propane air facilities and one LNG facility in Dorchester,
Massachusetts. We also lease two LNG facilities sited on land owned by us in
Salem and Lynn, Massachusetts and also lease space in facilities located in
Providence, Rhode Island and Everett, Massachusetts. We consider our peak day
sendout capacity, based on our total supply resources, to be adequate to meet
the requirements of our firm customers.
Fluctuations in utility gas costs have little impact on our operating results
because the current gas rate structure includes a gas adjustment clause whereby
variations between actual gas costs incurred and gas costs billed are deferred
and subsequently refunded to or collected from customers.
Regulation
Our operations are subject to Massachusetts statutes applicable to gas
utilities. Rates for gas sales and transportation service, distribution safety
practices, issuance of securities and affiliate transactions are regulated by
the Department. Rates for transportation service and gas sales are subject to
approval by and are on file with the Department. Our cost of gas adjustment
clause, allows for a semiannual adjustment, and based on certain criteria, a
monthly adjustment of billing rates for firm gas sales to reflect the actual
cost of gas delivered to customers, including demand charges for capacity on the
interstate pipeline system. Similarly, through our local distribution adjustment
clause, we collect the actual cost 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. For more
detailed information regarding regulation, see Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operation-Other Matters
- -Regulation."
Seasonality and Working Capital
Our revenues, earnings and cash flows are highly seasonal because most
transportation services and sales are directly related to temperature
conditions. Since the majority of 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, we bill
our customers over the November - April heating season for the majority of the
pipeline demand charges incurred and paid by us over the entire year. This
timing difference, along with other costs of gas distributed but unbilled, is
reflected as deferred gas costs on the Balance Sheet and is financed through
short-term borrowings. Short-term borrowings are also required from time to time
to finance normal business operations. As a result of these factors, short-term
borrowings are generally highest during the late fall and early winter.
Environmental Matters
We have or share responsibility under applicable environmental law for the
remediation of former manufactured gas plant operations, including former
operating plants, gas holder locations and satellite disposal sites. Information
with respect to the remediation of these sites may be found in Note 9 of the
Notes to Financial Statements. Such information is incorporated herein by
reference.
Employees
As of December 31, 2002, Boston Gas had approximately 775 employees, 87% of whom
are organized in local unions with which we have collective bargaining
agreements. In March 2002, we entered into a four-year collective bargaining
agreement with the largest bargaining units representing union employees; these
agreements expire in 2006.
4
Item 2. Properties.
We operate three LNG facilities in Dorchester, Salem, and Lynn, Massachusetts.
These facilities provide us with local storage of gas, because the stored LNG
can be vaporized into our distribution system to supplement pipeline gas in
periods of high demand. We own the Dorchester facility. We also own the real
property at the Salem and Lynn facilities and rent the storage facilities under
a long-term lease arrangement. In addition, we own propane-air facilities at
various locations throughout our service territory.
On December 31, 2002, our distribution system included approximately 6,200 miles
of gas mains, 450,000 services and 563,000 active customer meters. A majority of
the gas mains consist of cast iron and bare steel, which require ongoing
maintenance and replacement.
Our gas mains and services are usually located on public ways or private
property not owned by us. In general, our occupation of such property is
pursuant to easements, licenses, permits or grants of location. Except as stated
above, the principal items of property are owned.
In 2002 our capital expenditures were approximately $110 million. Capital
expenditures were principally made for improvements to the distribution system
and for system expansion to meet customer growth. We plan to spend approximately
$100 million, including costs of removal, for similar purposes in 2003.
Information with respect to the Company's material properties used in the
conduct of its business is set forth in, or incorporated by reference in, Item 1
hereof. Except where otherwise specified, all such properties are owned or, in
the case of certain rights of way used in the conduct of its gas distribution
business, held pursuant to municipal consents, easements or long-term leases.
In addition, we lease other office and building space, office equipment, and
vehicles. Our properties are adequate and suitable to meet our current and
expected business requirements. Moreover, their productive capacity and
utilization meet our needs for the foreseeable future. We continually examine
our real property and other property for its contribution and relevance to our
businesses and when such properties are no longer productive or suitable, they
are disposed of as promptly as possible. In the case of leased office space, we
anticipate no significant difficulty in leasing alternative space at reasonable
rates in the event of the expiration, cancellation or termination of a lease.
Item 3. Legal Proceedings.
Other than routine litigation incidental to the business, there are no material
pending legal proceedings involving the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of Security Holders in the fourth quarter of
2002.
5
Glossary
BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.
Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and
peak-shaving services.
Capacity--The capability of pipelines and supplemental facilities to deliver
and/or store gas.
City Gate--Physical interconnection between an interstate pipeline and the local
distribution company.
Core Customer--Generally, customers with no readily available energy services
alternative.
Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.
Firm Service--Sales and/or transportation service provided without interruption.
This could be for the year, or for an agreed upon period less than 365 days.
Firm services are provided under either filed rate tariffs or through
individually negotiated contracts.
Gas Marketer (Broker)--A non-regulated buyer and seller of gas.
Interstate Transportation--Transportation of gas by an interstate pipeline to
the city gate.
Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to
end-user facilities.
Local Transportation Service--Transportation of gas by the LDC from the city
gate to the customer's burner tip.
Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.
Non-Firm Service--Sales and transportation service offered at a lower level of
reliability and cost. Under this service, the LDC can interrupt customers on
short notice, typically during the winter season. Non-firm services are provided
through individually negotiated contracts and, in most cases, the price charged
takes into account the price of the customer's energy alternative.
Performance-Based Regulatory Plan--Incentive ratemaking mechanism, 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 typically have the
opportunity to select only the services they desire.
Utility Money Pool--KeySpan has established a money pool for its utility
subsidiaries for purposes of reducing outside borrowings and for a more
efficient use of funds. Utility subsidiaries can borrow from/or lend to the
money pool depending upon its financing needs. The money pool is funded by
commercial paper and operating funds of net lenders to the pool. It is
administered by a wholly-owned KeySpan subsidiary, KeySpan Corporate Services
LLC ("KCS") and its operation is subject to PUHCA regulation.
6
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
KNE LLC, a wholly-owned subsidiary of KeySpan Corporation, is the holder of
record of all of the outstanding common equity securities of the Company.
Item 6. Selected Financial Data.
Not required.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
RESULTS OF OPERATIONS
The net loss applicable for common stock for the year ended December 31, 2002
was $3.4 million compared to a net loss of $31.3 million in the prior year. The
improvement of $27.8 million, or 89%, over the prior year is due primarily to an
increase in operating margin and the discontinuance of goodwill amortization
offset, in part, by higher interest expense and income taxes.
Operating revenues for the year ended December 31, 2002 declined $190 million,
or 23%, from 2001. The decrease was due to a decline of $213 million, or 38%, in
the cost of gas sold to customers, which are fully recovered through revenues.
The decrease in gas costs reflects a 40% decline in the average commodity price
of gas combined with a 4.3% decrease in throughput. The decline in throughput
was primarily due to significantly warmer weather in the first quarter of 2002
versus the prior year's first quarter.
Our gas rate structure includes a gas adjustment clause, pursuant to which gas
costs are fully recovered. Further, variations between actual gas costs incurred
and gas costs billed are deferred and refunded to or collected from customers in
a subsequent period. As a result, fluctuations in the cost of gas sold have
little or no impact on operating margin.
Operating margin (revenues less the cost of gas sold) for the year ended
December 31, 2002 increased $23.0 million, or 8.5%, from the year ended December
31, 2001. Primarily contributing to the improvement was an increase of $13.8
million due to customer growth, a base rate increase of $3.6 million associated
with our performance-based rate plan ("PBR") (see "Other Matters-Regulation")
and an additional benefit of $6.3 million attributable to the favorable court
decision which resulted in the elimination of an "accumulated inefficiencies
factor" included in the PBR (see "Other Matters-Regulation"). Other gas margins,
which include sales to non-core customers and regulatory rate incentives,
increased $3.9 million.
The improvement in operating margin was partially offset by a reduction of $1.6
million as a result of lower gas throughput due to the warmer first quarter
weather and a net reduction of $3.3 million in revenues associated with weather
derivatives that hedged approximately 7.4% colder than normal weather during the
fourth quarter. (See Item 7A. "Quantitative and Qualitative Disclosures About
Market Risk -Weather Derivatives" for further information).
Total operating expenses, excluding goodwill amortization, declined $5.1 million
or 2% over the prior year. Operations and maintenance expense decreased $2.9
million, or 1.8% over the prior year, primarily due to cost saving synergies
realized during the year as well as lower bad debt expense due to the lower
average levels of customer receivables in 2002. These decreases were offset, in
part, by allocated payroll taxes associated with general and administrative
services provided by KCS, which were included in 2002 operations and maintenance
expense, whereas in 2001, these general and administrative services were
provided by our employees and the related taxes were charged to operating taxes.
7
Depreciation expense increased as a result of continued investments in the
distribution infrastructure. Operating taxes decreased primarily due to the
lower payroll taxes (as discussed above) and lower property taxes. In accordance
with SFAS 142, as of January 1, 2002, we are no longer amortizing goodwill. For
the year ended December 31, 2001, amortization of goodwill was $19.4 million.
For the year ended December 31, 2002, interest expense on long term debt was
comparable to the prior year. For the year ended December 31, 2002, other
interest expense increased $6.8 million, or 15.5%, versus 2001. This increase
resulted from a full year of interest expense in 2002 versus six months of
interest expense in 2001 on a $50 million advance from KeySpan made on June 30,
2001. For the year ended December 31, 2002, interest capitalized for
construction increased $1.8 million over the prior year principally due to the
investment in software in 2002.
Income tax expense for the year ended December 31, 2002 increased $12.4 million
from 2001. The increase in expense is primarily attributable to higher taxable
income.
LIQUIDITY AND CAPITAL RESOURCES
In 2002, we received capital contributions of $200 million from KNE LLC. The
proceeds were used to pay down borrowings from the utility money pool.
On September 1, 2002, we made the required $1.5 million annual sinking fund
payment on our 6.42% Cumulative Preferred Stock. For details on the Preferred
Stock, see Note 4 in the Notes to Financial Statements.
On November 8, 2000, KCS, a subsidiary of KeySpan, became an affiliate of the
Company, as a result of KeySpan's acquisition of KNE LLC. KCS provides financing
requirements to the Company for working capital and gas inventory through the
Company's participation in a utility money pool. Interest charged equals
interest incurred by KeySpan to borrow funds to meet the needs of the Company
plus a proportional share of the administrative costs incurred in obtaining the
required funds.
As part of the transaction with KeySpan, the Company recorded in November 2000,
a $600 million advance payable to KeySpan. During 2001, an additional $50
million advance was received from KeySpan and a $50 million dividend was paid to
KeySpan. Interest charges are equal to the interest incurred by KeySpan on debt
borrowings issued by KeySpan and recorded on the books of the Company. Issuance
expense is charged to the Company from KeySpan equal to the amortization of
actual issuance costs incurred by KeySpan on its debt borrowings. KeySpan
amortizes these costs over the life of the related KeySpan borrowings.
We have $210 million of Medium-Term Notes outstanding at December 31, 2002. For
details on debt, see Note 3 in the Notes to Financial Statements. The ratings on
the long-term debt have remained on stable outlook. At December 31, 2002,
Moody's Investor Services and Standard & Poor's rated the debt A2.
As discussed, revenues, earnings and cash flows are highly seasonal. Since the
majority of revenues are billed during the heating season, significant cash
flows are generated from late winter to early summer. Alternatively, in
preparation for the heating season (i.e. purchasing and storing of natural gas),
short-term borrowings are highest during the late fall and early winter.
The Company expects capital expenditures for 2003 to be approximately $100
million, including costs of removal. Capital expenditures will be largely for
system expansion to meet customer growth and improvements to the distribution
system.
The Company believes that projected cash flow from operations, in combination
with currently available resources (i.e. utility money pool), is sufficient to
meet 2003 capital expenditures, working capital requirements, preferred dividend
payments and normal debt repayments.
8
OTHER MATTERS
Regulation
Our operations are subject to Massachusetts statutes applicable to gas
utilities. Rates for gas sales and transportation service, distribution safety
practices, issuance of securities and affiliate transactions are regulated by
the Department. Rates for transportation service and gas sales are subject to
approval by and are on file with the Department. Our cost of gas adjustment
clause, billed to firm sales customers, allows for the semiannual adjustment,
and based on certain criteria, a monthly adjustment of billing rates for firm
gas sales to reflect the actual cost of gas delivered to customers, including
demand charges for capacity on the interstate pipeline system. Similarly,
through its local distribution adjustment clause, we collect 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 had been governed by a
five-year performance-based rate plan (the "Plan") approved in D.P.U. 96-50.
Under the Plan, our local transportation rates had been adjusted annually to
reflect inflation for the previous 12 months and reduced by a productivity
factor. The Plan also provided for penalties if we failed to meet specified
service quality measures, with a maximum potential exposure of $1 million. There
was a margin sharing mechanism whereby 25% of earnings in excess of a 15% return
on year-ending equity were to be passed back to ratepayers. Similarly,
ratepayers were to absorb 25% of any shortfall below a 7% return on year-ending
equity. Although the Plan expired October 31, 2002, distribution rates
established under the Plan continue to be effective. We expect to propose a new
rate plan with the Department during the spring of 2003.
In D.P.U. 96-50, the productivity factor was set at 1.50% and the service
quality penalty was expanded beyond the $1 million proposed in our Plan. We
appealed D.P.U. 96-50 and on January 16, 2001, the Department limited the
maximum service quality adjustment to $1 million and adjusted the productivity
factor to 1.0%. On January 30, 2001, we appealed the imposition of the 0.5%
accumulated inefficiencies adjustment and on March 7, 2002, the Supreme Judicial
Court of Massachusetts ruled in favor of the Company and eliminated the
accumulated inefficiencies factor of 0.5%, thereby reducing the productivity
factor to 0.5%.
On November 1, 2001, the Department issued an order requiring all Massachusetts
electric and gas utilities to develop service quality plans effective January 1,
2002. On April 17, 2002, the Department issued an order approving our service
quality plan that was filed with the Department on March 1, 2002. Service
quality will be tracked and measured against historical benchmarks. Our failure
to meet the Department's service quality standards is subject to a maximum
penalty equivalent to 2% of its distribution service revenues. Each measurement
period will be a calendar year. The first measurement period began on January 1,
2002. For the year ended 2002, we met the Department's service quality standards
and were not subject to any penalties.
All of our customers are eligible to purchase unbundled local transportation
service from the Company and to purchase their gas supply from third parties. In
2000, the Department approved Model Terms and Conditions for residential
customer tariffs effective November 1, 2000. The Model Terms and Conditions are
consistent with the Department's order of February 1, 1999 which provided that,
for a five-year transition period, local distribution company ("LDC")
contractual commitments to upstream capacity will be assigned on a mandatory,
pro rata basis to marketers selling gas supply to the LDC's customers. The
approved mandatory assignment method eliminates the possibility that because of
the migration of customers to the gas supply service of third parties, the costs
of upstream interstate gas pipeline capacity purchased by the Company to serve
firm customers would be absorbed by the LDC or other customers through the
transition period. The Department also found that, through the transition
period, LDCs will retain primary responsibility for upstream capacity planning
and procurement to assure that adequate capacity is available at Massachusetts
city gates to support customer requirements and growth. In year three of the
five-year transition period, the Department intends to evaluate the extent to
which the upstream capacity market for Massachusetts is workably competitive
based on a number of factors and accelerate or decelerate the transition period
accordingly.
9
Securities and Exchange Commission Regulation
The Company, as a wholly owned subsidiary of KeySpan, is subject to the
jurisdiction of the SEC under PUHCA. The rules and regulations under PUHCA
generally limit the operations of a registered holding company to a single
integrated public utility system, plus additional energy-related businesses. In
addition, the principal regulatory provisions of PUHCA: (i) regulate certain
transactions among affiliates within a holding company system including the
payment of dividends by such subsidiaries to a holding company; (ii) govern the
issuance, acquisition and disposition of securities and assets by a holding
company and its subsidiaries; (iii) limit the entry by registered holding
companies and their subsidiaries into businesses other than electric and/or gas
utility businesses; and (iv) require SEC approval for certain utility mergers
and acquisitions.
As a result of an order issued by the SEC on November 8, 2000, in connection
with KeySpan's acquisition of KNE LLC and EnergyNorth, Inc., and as amended on
December 6, 2002 and February 14, 2003, we are committed through December 31,
2003 to have common equity of at least 30% of total capitalization, including
affiliated debt. At December 31, 2002, our common equity was 35.8% of total
capitalization, including affiliated debt.
Environmental Matters
The Company has or shares responsibility under applicable environmental law for
the remediation of former manufactured gas plant operations, including former
operating plants, gas holder locations and satellite disposal sites. Information
with respect to the remediation of these sites may be found in Note 9 of the
Notes to Financial Statements. Such information is incorporated herein by
reference.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are subject to various risk exposures and uncertainties associated with our
operations. The most significant contingency involves the evolution of the gas
distribution industry towards a more competitive and deregulated environment. In
addition, we are exposed to commodity price risk. Set forth below is a
description of these exposures and an explanation as to how we have managed and,
to the extent possible, sought to reduce these risks.
Regulatory Issues and the Competitive Environment
In July 1997, the Department directed Massachusetts gas distribution companies
to undertake a collaborative process with other stakeholders to develop common
principles under which comprehensive gas service unbundling might proceed. A
settlement agreement by the LDC's and the marketer group regarding model terms
and conditions for unbundled transportation service was approved by the
Department in November 1998. In February 1999, the Department issued its order
on how unbundling of natural gas service will proceed. For a five-year
transition period, the Department determined that LDC's 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 LDC's to serve firm customers will be absorbed by other
customers through the transition period. The Department also found that, through
the transition period, LDCs will retain primary responsibility for upstream
capacity planning and procurement to assure that adequate capacity is available
to support customer requirements and growth. The Department approved the LDC's
Terms and Conditions of Distribution Service that conform to the settled upon
model terms and conditions. Since November 1, 2000, all Massachusetts gas
customers have the option to purchase their gas supplies from third party
sources other than the LDC's.
We believe that the actions described above strike a balance among competing
stakeholder interests in order to most effectively make available the benefits
of the unbundled gas supply market to all customers.
10
Commodity Price and Credit Risk
Weather Derivatives
The utility tariffs associated with our operations do not contain a weather
normalization clause. As a result, fluctuations from normal weather may have a
significant positive or negative effect on the results of operations. To
mitigate the effect of fluctuations from normal weather on our financial
position and cash flows, we sold heating degree-day call options and purchased
heating-degree day put options for the November 2002 - April 2003 winter season.
With respect to sold call options, we are required to make a payment of $40,000
per heating degree day to our counter-parties when actual weather experienced
during the November 2002 - April 2003 time frame is above 4,470 heating degree
days, which equates to approximately 1% colder than normal weather. With respect
to purchased put options, we will receive a $20,000 per heating degree day
payment from our counter-parties when actual weather is below 4,150 heating
degree days, or is approximately 7% warmer than normal. Based on the terms of
such contracts, as discussed in Note 11 of the Notes to Financial Statements, we
account for such instruments pursuant to the requirements of EITF 99-2,
"Accounting for Weather Derivatives." In this regard, we account for such
instruments using the "intrinsic value method" as set forth in such guidance.
During the fourth quarter of 2002, weather was approximately 7.4% colder than
normal and we recorded a $3.3 million reduction to revenues with a corresponding
liability due to our counter-parties.
Our derivative contracts are primarily used to manage exposure to market risk
arising from changes in demand as a result of weather colder or warmer than
normal. In the event of nonperformance by a counter-party to a derivative
contract, the desired impact may not be achieved. The risk of a counter-party
nonperformance is generally considered credit risk and is actively managed by
assessing each counter-party credit profile and negotiating appropriate levels
of collateral and credit support.
Physically-Settled Commodity Derivative Instruments:
On April 1, 2002 we implemented Derivative Implementation Group ("DIG") C16 of
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as
amended and interpreted, incorporating SFAS 137 and 138 and certain
implementation issues (collectively "SFAS 133"). Issue C16 relates to the
exemption (as normal purchases and normal sales) of contracts that combine a
forward contract and a purchased option contract. Based upon a review of our
physical commodity contracts, we determined that certain contracts for the
physical purchase of natural gas can no longer be exempted as normal purchases
from the requirements of SFAS 133. Since these contracts are for the purchase of
natural gas sold to regulated firm gas sales customers, the accounting for these
contracts is subject to SFAS 71. Therefore, changes in the market value of these
contracts are recorded as a deferred asset or deferred liability on the Balance
Sheet.
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.
Arthur Andersen LLP ("Arthur Andersen") served as the Company's independent
public accountants since May 1998. On March 29, 2002, our Board of Directors,
determined not to renew the engagement of Arthur Andersen and appointed Deloitte
& Touche LLP ("Deloitte & Touche") as independent public accountants. During the
past two fiscal years through March 29, 2002, there was no report on the
financial statements of the Company by Arthur Andersen that contained an adverse
opinion or a disclaimer of opinion, or was qualified or modified as to
uncertainty, audit scope, or accounting principles. During the past two fiscal
years through March 29, 2002, there were no disagreements with Arthur Andersen
on any matter of accounting principles or practices, financial statement
disclosure or auditing scope or procedure which, if not resolved to the
satisfaction of Arthur Andersen, would have caused the firm to make reference to
the subject matter of such disagreements in connection with their respective
reports.
11
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.
Item 14. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Within 90 days prior to the date of this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including its Chief Operating Officer and Principal Financial and
Accounting Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures. The Company's disclosure controls
and procedures are designed to ensure that information required to be disclosed
by the Company in its periodic SEC filings is recorded, processed and reported
within the time periods specific in the SEC's rules and forms. Based upon that
evaluation, the Chief Operating Officer and Principal Financial and Accounting
Officer concluded that the Company's disclosure controls and procedures are
effective in timely alerting them to material information relating to the
Company required to be included in its periodic SEC filings.
Changes In Internal Controls
There were no significant changes in the Company's internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.
12
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
List of Financial Statements and Financial Statement Schedules.
Information with respect to these items appears on Page F-1 of this Report. Such
information is incorporated herein by reference.
(3) List of Exhibits.
3.1 Restated Articles of Organization, as amended (Filed as Exhibit 3.1 to the
registration statement of the Company on Form S-3 (File No. 33-48525)).*
3.2 By-Laws of the Company as amended (Filed as Exhibit 1 to the Annual Report
of the Company on Form 10-K for the year ended December 31, 1976 (File No.
2-23416)).*
(Note: Certain instruments with respect to long-term debt of the Company or
its subsidiary are not filed herewith since no such instrument authorizes
securities in an amount greater than 10% of the total assets of the Company
and its subsidiary on a consolidated basis. The Company agrees to furnish
to the Securities and Exchange Commission upon request a copy of any such
omitted instrument of the Company or its subsidiary.)
4.1 Indenture dated as of December 1, 1989 between the Company and The Bank of
New York, Trustee (Filed as Exhibit 4.2 to the registration statement of
the Company on Form S-3 (File No. 33-31869)).*
4.2 Agreement of Registration, Appointment and Acceptance dated as of November
18, 1992 among the Company, The Bank of New York as Resigning Trustee, and
The First National Bank of Boston as Successor Trustee. (Filed as an
exhibit to registration statement of the Company on Form S-3 (File No.
33-31869)).*
4.3 Utility Money Pool Agreement. (filed as an exhibit 4.3 to the Annual Report
of the company on Form 10-K for the year ended December 31, 2000).*
10.1 Gas Transportation Contract between the Company and Tennessee Gas Pipeline
Company dated as of September 1, 1993 providing for transportation of
approximately 94,000 dekatherms of natural gas per day (Filed as Exhibit
10.1 to the Annual Report of the Company on Form 10-K for the year ended
December 31, 1993).*
10.2 Gas Transportation Contract between the Company and Texas Eastern dated
October 29, 1999 providing for transportation of approximately 48,133
dekatherms of natural gas per day. (Filed as Exhibit 10.2 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.3 Gas Transportation Contract between the Company and Texas Eastern dated
December 30, 1993 providing for transportation of approximately 32,000
dekatherms of natural gas per day. (Filed as Exhibit 10.3 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1993).*
10.4 Gas Transportation Contract between the Company and Algonquin dated October
29, 1999 providing for transportation of approximately 45,000 dekatherms of
natural gas per day. (Filed as Exhibit 10.4 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1999).*
13
10.5 Agreement between the Company and Maritimes Northeast Pipeline L.L.C. dated
January 4, 1999 providing for transportation of approximately 43,200
dekatherms of natural gas per day. (Filed as Exhibit 10.5 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 2001).*
10.6 Gas Storage Agreement between the Company and Honeoye Storage Corporation
dated October 11, 1985 providing for storage demand of 6,150 dekatherms of
natural gas per day. (Filed as Exhibit 10.17 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1985).*
10.7 Firm Gas Transportation agreement between the Company and Algonquin Gas
Transmission Company dated July 27, 2000 providing for transportation of
approximately 15,000 dekatherms of natural gas per day. Filed as Exhibit
10.7 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).*
10.8.1 Amendment to the 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).*
10.9 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.)*
10.10Gas 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).*
10.10.1 Amendments to the Gas Sales Agreement between the Company and Alberta
Northeast Gas, Ltd., dated as of October 1, 1992; May 5, 1993; November 27,
1995; and March 14, 1996. (Filed as Exhibit 10.12.1 to the Annual Report of
the Company on Form 10-K for the year ended December 31, 1998).*
10.11Firm 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).*
10.11.1 Amendment dated as of November 3, 1998 to the Firm Gas Transportation
Agreement between the Company and Iroquois Gas Transmission System, L.P.
dated as of February 7, 1991. (Filed as Exhibit 10.13.1 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.12Firm 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).*
10.13Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 29,000
dekatherms of natural gas per day. (Filed as Exhibit 10.15 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.14Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 96,000
dekatherms of natural gas per day. (Filed as Exhibit 10.16 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
14
10.15Gas Transportation Contract between the Company and Algonquin dated
October 29, 1999 providing for transportation of approximately 20,000
dekatherms of natural gas per day. (Filed as Exhibit 10.17 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.16Gas 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).*
10.17Gas 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).*
10.18Gas 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).*
10.18.1 Amendment dated as of August 1, 2002 to the Gas Transportation Contract
between the Company and CNG Transmission dated October 1, 1993 providing
for a MDQ reduction to 12,978 dekatherms, and extending the term to October
31, 2005. (Filed herewith).
10.19Gas 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).*
10.20Gas 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).*
10.20.1 Amendment dated October 31, 2002 to the Gas Transportation Contract
between the Company and Tennessee Gas Pipeline dated September 1, 1993
providing for transportation of approximately 10,533 dekatherms of natural
gas per day and extending term of the agreement to October 31, 2008. (Filed
herewith).
10.21Gas 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).*
10.22Gas 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).*
10.22.1 Amendment dated October 31, 2002 to the Gas Transportation Contract
between the Company and Tennessee Gas Pipeline dated September 1, 1993
providing for transportation of approximately 41,687 dekatherms of natural
gas per day and extending term of the agreement to October 31, 2008. (Filed
herewith).
10.23Gas 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).*
15
10.23.1 Amendment dated as of October 31, 2002 to the Gas Storage Contract
between the Company and Tennessee Gas Pipeline dated September 1, 1993
providing for storage demand of approximately 41,687 dekatherms of natural
gas per day and extending term of the agreement to October 31, 2008. (Filed
herewith).
10.24Gas 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).*
10.24.1 Amendment dated as of October 31, 2002 to the Gas Transportation
Contract between the Company and Tennessee Gas Pipeline dated September 1,
1996 providing for transportation of approximately 13,027 dekatherms of
natural gas per day and extending term of the agreement to October 31,
2008. (Filed herewith).
10.25Gas 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).*
10.25.1 Amendment dated as of October 29, 1998 to the 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 10.27.1 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1999).*
10.26Gas Transportation Contract between the Company and Texas Eastern
Transmission dated December 30, 1993 providing for transportation of
approximately 21,000 dekatherms of natural gas per day. (Filed as Exhibit
10.34 to the Annual Report of the Company on Form 10-K for the year ended
December 31, 1997).*
10.27Gas 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 (terminated on
October 31, 2002). (Filed as Exhibit 10.35 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1997).*
10.28Gas Transportation Contract between the Company and Texas Eastern
Transmission dated October 29, 1999 providing for transportation of
approximately 29,000 dekatherms of natural gas per day. (Filed as Exhibit
10.30 to the Annual Report of the Company on Form 10-K for the year ended
December 31, 1999).*
10.29Gas 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). *
10.30Gas 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).*
16
10.31Gas 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).*
10.31.1 Amendment dated as of October 31, 2002 to the Gas Transportation
Contract between the Company and Tennessee Gas Pipeline dated September 1,
1993 providing for transportation of approximately 94,312 dekatherms of
natural gas per day and extending term of the agreement to October 31,
2008. (Filed herewith).
10.32Agreement between the Company and Texas Eastern Transmission dated as of
October 29, 1999 providing for storage demand of approximately 68,700
dekatherms of natural gas per day. (Filed as Exhibit 10.35 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.33Agreement between the Company and Algonquin LNG, Corp. dated as of October
29, 1999 providing for storage demand of approximately 35,000 dekatherms of
natural gas per day. (Filed as Exhibit 10.36 to the Annual Report of the
Company on Form 10-K for the year ended December 31, 1999).*
10.34Contract Restructuring Agreement between the Company and Tennessee Gas
Pipeline dated as of August 2, 1999. (Filed as Exhibit 10.37 to the Annual
Report of the Company on Form 10-K for the year ended December 31, 1999).*
10.35Redacted 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 (terminated on
October 31, 2002). (Filed as Exhibit 10.1 to the Form 10-K of Eastern
Enterprises for the year ended December 31, 1999.).*
10.36Amended and Restated Lease Agreement between Industrial National Leasing
Corporation, Lessor, and Boston Gas Company, Lessee, dated as of April 30,
1999. (Filed as Exhibit 10.39 to the Annual Report of the Company on Form
10-K for the year ended December 31, 1999).*
10.37Precedent Agreement between the Company and Algonquin Gas Transmission
Company dated as of June 13, 2001 providing for transportation of
approximately 20,000 dekatherms of natural gas per day.* (Filed as Exhibit
10.40 to the Company's Form 10-K for the year ended December 31, 2001).*
10.38Agreement between the Company and Maritimes Northeast Gas Pipeline Limited
Partnership dated June 16, 1999 providing for transportation of
approximately 43,200 dekatherms of natural gas per day.* (Filed as Exhibit
10.41 to the Company's Form 10-K for the year ended December 31, 2001).*
10.39Redacted Gas Resource Portfolio Management and Gas Sales Agreement between
the Company, Colonial Gas Company and Essex Gas Company and Entergy-Koch
Trading, LP, dated as of October 29, 2002. (Filed herewith).
17
Reports on Form 8-K
There were no reports on Form 8-K filed in the Fourth Quarter of 2002.
* 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.
18
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Boston Gas Company
D/B/A KeySpan Energy Delivery New England
Registrant
By: /s/NICKOLAS STAVROPOULOS
-----------------------------
Nickolas Stavropoulos
Chief Operating Officer
and President
By: /s/JOSEPH F. BODANZA
------------------------
Joseph F. Bodanza
Senior Vice President
Finance, Accounting and Regulatory Affairs
(Principal Financial and Accounting Officer)
Dated: March 28, 2003
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 28th day of March, 2003.
Signature Title
--------- -----
Nickolas Stavropoulos
---------------------
Nickolas Stavropoulos Director
19
Certification Pursuant to Rule 13a-14 and 15d-14 of
the Securities and Exchange Act of 1934
CHIEF OPERATING OFFICER'S CERTIFICATION
I, Nickolas Stavropoulos, certify that:
1. I have reviewed this annual report on Form 10-K of Boston Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/Nickolas Stavropoulos
Nickolas Stavropoulos
President and Chief Operating Officer
20
Certification Pursuant to Rule 13a-14 and 15d-14 of
the Securities and Exchange Act of 1934
CHIEF FINANCIAL OFFICER'S CERTIFICATION
I, Joseph F. Bodanza, certify that:
1. I have reviewed this annual report on Form 10-K of Boston Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 28, 2003
/s/ Joseph F. Bodanza
Joseph F. Bodanza
Senior Vice President
Finance, Accounting and Regulatory Affairs
(Principal Financial and Accounting Officer)
21
BOSTON GAS COMPANY
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
(Information required by Items 8 and 14 (a) of Form 10-K)
Independent Auditors' Report.................................................................................... F-25
Report of Independent Public Accountants - 2001 and prior....................................................... F-26
Statements of Operations for the Years Ended December 31, 2002 and 2001, and the Periods from
November 8, 2000 through December 31, 2000 and January 1, 2000 through November 7, 2000..................... F-2
Balance Sheets as of December 31, 2002 and 2001................................................................. F-3 and F-4
Statements of Retained Earnings (Deficit) and Statements of Comprehensive Income (Loss)for the
Years Ended December 31, 2002 and 2001, and the Periods from November 8,
2000 through December 31, 2000 and January 1, 2000 through November 7, 2000 ..................................... F-5
Statements of Cash Flows for the Years Ended December 31, 2002 and 2001, and the Periods
from November 8, 2000 through December 31, 2000 and January 1, 2000 through
November 7, 2000.......................................................................................... F-6
Notes to Financial Statements.................................................................................... F-7 to F-24
Interim Financial Information for the Two years Ended December 31, 2002 (unaudited).............................. F-27
Schedule for the Years Ended December 31, 2002 and 2001, and the Periods from November 8,
2000 through December 31, 2000 and January 1, 2000 through November 7, 2000:
Schedule II--Valuation and Qualifying Accounts......................................................... F-28
Schedules other than that listed above have been omitted as the information has
been included in the financial statements and related notes or is not applicable
or required.
F-1
BOSTON GAS COMPANY
STATEMENTS OF OPERATIONS
- -----------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Year Ended December 31, 2000 through 2000 through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- --------------------------------------------------------------------------------------------------------------------------------
Predecessor
Operating Revenues $ 639,111 $ 828,938 $ 202,842 $ 453,783
Cost of gas sold 345,823 558,683 131,516 247,548
--------------------- -------------------- ------------------- -----------------
Operating Margin 293,288 270,255 71,326 206,235
Operating Expenses:
Operations and maintenance 154,095 156,956 25,259 123,667
Depreciation and amortization 56,203 52,261 10,745 39,515
Amortization of goodwill - 19,439 3,226 -
Operating taxes 17,401 23,570 4,557 18,918
Merger related expenses - - 101 23,347
--------------------- -------------------- ------------------- -----------------
Total Operating Expenses 227,699 252,226 43,888 205,447
--------------------- -------------------- ------------------- -----------------
Operating Income 65,589 18,029 27,438 788
--------------------- -------------------- ------------------- -----------------
Other Income 258 2,775 451 719
Interest Expense:
Long-term debt 16,855 16,835 2,806 13,984
Other, including amortization of
debt expense 50,658 43,867 3,501 (4,017)
Less-Interest during construction (2,501) (686) (202) (704)
--------------------- -------------------- ------------------- -----------------
Total Interest Expense 65,012 60,016 6,105 9,263
--------------------- -------------------- ------------------- -----------------
Income Before Income Taxes 835 (39,212) 21,784 (7,756)
Income Taxes
Current (63,870) 26,839 2,707 (21,186)
Deferred 67,179 (35,895) 7,011 17,718
--------------------- -------------------- ------------------- -----------------
Total Income Tax Expense (Benefit) 3,309 (9,056) 9,718 (3,468)
--------------------- -------------------- ------------------- -----------------
Net (Loss)Income (2,474) (30,156) 12,066 (4,288)
Preferred stock dividends 975 1,096 183 1,174
--------------------- -------------------- ------------------- -----------------
Net Income (Loss) applicable for Common Stock $ (3,449) $ (31,252) $ 11,883 $ (5,462)
===================== ==================== =================== =================
The accompanying notes are an integral part of these financial statements.
F-2
BOSTON GAS COMPANY
BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Property:
Gas plant, at cost $ 1,194,842 $ 1,070,610
Construction in progress 10,415 27,875
Less-Accumulated depreciation (470,556) (425,163)
---------------------------- -----------------------------
734,701 673,322
---------------------------- -----------------------------
Current assets:
Cash and temporary cash investments 2,168 3,104
Accounts receivable 123,681 95,393
Allowance for uncollectible accounts (14,666) (14,730)
Accounts receivable-affiliates 4,195 8,851
Accrued utility revenue 66,619 50,693
Deferred gas costs 68,647 15,670
Natural Gas and other inventories, at average cost 74,549 79,544
Material and supplies, at average cost 4,754 3,996
Prepaid expenses and other 371 377
---------------------------- -----------------------------
330,318 242,898
---------------------------- -----------------------------
Other Assets:
Goodwill 790,285 790,285
Deferred postretirement cost 44,360 42,585
Deferred charges and other assets 96,378 56,261
---------------------------- -----------------------------
931,023 889,131
---------------------------- -----------------------------
Total Assets $ 1,996,042 $ 1,805,351
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
F-3
BOSTON GAS COMPANY
BALANCE SHEETS
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITALIZATION
Capitalization
Common stock, $100 par value-authorized and
outstanding-514,184 shares $ 51,418 $ 51,418
Amounts in excess in par value 560,575 360,575
Accumulated deficit (22,817) (19,368)
Accumulated other comprehensive income (9,823) (692)
-------------------------- ---------------------------
Total common stockholder's investment 579,353 391,933
Cumulative Preferred stock, $1 par value, liquidation
preference $25 per share-562,700 and 622,700 shares
at December 31, 2002 and 2001,
respectively 13,840 15,289
Long-term obligations, less current portion 222,563 223,403
-------------------------- ---------------------------
Total Capitalization 815,756 630,625
-------------------------- ---------------------------
Advance from KeySpan 650,000 650,000
-------------------------- ---------------------------
Total Capitalization and Advance from KeySpan 1,465,756 1,280,625
-------------------------- ---------------------------
Commitments and Contingencies(See Note 6)
Current Liabilities
Current portion of long-term obligations 840 586
Notes payable utility pool 67,174 147,350
Notes payable utility pool - gas inventory financing 83,907 85,401
Accounts payable and affiliates 131,380 99,608
Accrued taxes 4,495 5,740
Accrued income taxes (6,747) (2,432)
Accrued interest 4,334 11,377
Customer deposits 1,563 1,884
Other current liabilities - 157
-------------------------- ---------------------------
286,946 349,671
-------------------------- ---------------------------
Deferred Credits and Other Liabilities
Deferred income tax 141,408 73,609
Unamortized investment tax credits 1,714 2,556
Postretirement benefits obligation 53,747 50,901
Environmental liability 28,831 31,878
Other 17,640 16,111
-------------------------- ---------------------------
243,340 175,055
-------------------------- ---------------------------
Total Capitalization and Liabilities $ 1,996,042 $ 1,805,351
- ------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
F-4
BOSTON GAS COMPANY
STATEMENTS OF RETAINED EARNINGS (DEFICIT)
- ----------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1, 2000
Year Ended December 31, 2000 through through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Predecessor
Balance at beginning of period $ (19,368) $ 11,883 $ - $ 189,517
Net (loss) income (2,474) (30,155) 12,066 (4,288)
Preferred stock dividend (975) (1,096) (183) (1,174)
Common stock dividend - - - (22,496)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance at end of period $ (22,817) $ (19,368) $ 11,883 $ 161,559
- ----------------------------------------------------------------------------------------------------------------------------------
BOSTON GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
- ------------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1, 2000
Year Ended December 31, 2000 through through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Predecessor
Net (loss) income $ (2,474) $ (30,155) $ 12,066 $(4,288)
- ------------------------------------------------------------------------------------------------------------------------------------
Other Comprehensive income (loss) net of tax
Accrued unfunded pension obligation (9,374) (692) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Other Comprehensive income (loss) net of tax $ (9,374) $ (692) $ - $ -
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive (loss) income $ (11,848) $ (30,847) $ 12,066 $(4,288)
- ------------------------------------------------------------------------------------------------------------------------------------
Related tax (benefit) expense
Accrued unfunded pension obligation (5,047) (373) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total tax (benefit) $ (5,047) $ (373) $ - $ -
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
F-5
STATEMENTS OF CASH FLOWS
- -----------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Year Ended Year Ended 2000 through 2000 through
(In Thousands of Dollars) December 31, 2002 December 31, 2001 December 31, 2000 November 7, 2000
- -----------------------------------------------------------------------------------------------------------------------------------
Predecessor
Operating Activities
Net (loss) income $ (2,474) $ (30,155) $ 12,066 $ (4,288)
Adjustments to reconcile net income to net
cash provided by (used in) operating activities
Depreciation and amortization 56,203 71,700 13,971 39,515
Deferred income tax 67,179 (35,895) 7,011 17,718
Changes in assets and liabilities
Accounts receivable and affiliates (23,637) 10,812 (61,736) 46,483
Accrued utility revenue (15,926) 21,130 (16,287) 14,029
Natural Gas and other inventories 4,237 (22,396) 18,987 (31,560)
Deferred gas costs (52,977) 61,995 (51,225) (28,066)
Accounts payable and affiliates (31,772) (5,735) 25,060 32,314
Accrued income taxes (5,560) 16,178 5,249 (20,495)
Other 6,200 (2,929) 3,237 4,056
---------------- ---------------- ---------------- ----------------
Net Cash Provided by (Used in) Operating Activities 1,473 84,705 (43,667) 69,706
---------------- ---------------- ---------------- ----------------
Investing Activities
Capital expenditures (110,360) (111,735) (21,802) (52,958)
Net cost of removal (7,904) (6,834) (1,272) (4,628)
---------------- ---------------- ---------------- ----------------
Net Cash Used in Investing Activities (118,264) (118,569) (23,074) (57,586)
---------------- ---------------- ---------------- ----------------
Financing Activities
Changes in advance from KeySpan 50,000
Capital Contribution from KNE LLC 200,000
Changes in notes payable - utility money pool (80,176) 32,507 54,843 8,800
Changes in gas inventory financing - utility money pool (1,494) 3,094 13,719 14,568
Redemption of preferred stock (1,500) (1,500) (9,933)
Dividends paid on common and preferred stock (975) (51,096) (183) (23,670)
Other 47 4 217
---------------- ---------------- ---------------- ----------------
Net Cash Provided by (Used in) Financing Activities 115,855 33,052 68,383 (10,018)
---------------- ---------------- ---------------- ----------------
Net (Decrease) or Increase in Cash and Cash Equivalents $ (936) $ (812) $ 1,642 $ 2,102
================ ================ ================ ================
Cash and Cash Equivalents at Beginning of Period 3,104 3,916 2,274 172
---------------- ---------------- ---------------- ----------------
Cash and Cash Equivalents at End of Period $ 2,168 $ 3,104 $ 3,916 $ 2,274
================ ================ ================ ================
Interest Paid $ 79,813 $ 75,438 $ 18,255 $ -
Income Tax Paid $ 1,310 $ 2,489 $ (1,718) $ 115
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
F-6
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Accounting Policies
General
Boston Gas Company D/B/A KeySpan Energy Delivery New England (referred to herein
as the "Company", "we" "us and "our") is a gas distribution company engaged in
the transportation and sale of natural gas to residential, commercial and
industrial customers. The Company's service territory includes Boston and 73
other communities in eastern and central Massachusetts. The Company is a
wholly-owned subsidiary of KeySpan New England LLC ("KNE LLC") (Formerly known
as Eastern Enterprises) and an indirect wholly-owned subsidiary of KeySpan
Corporation ("KeySpan"), a registered holding company under the Public Utility
Holding Company Act ("PUHCA") of 1935, as amended.
Basis of Presentation
The accounting records are maintained in accordance with the Uniform System of
Accounts prescribed by the Massachusetts Department of Telecommunications and
Energy (the "Department"). The accounting policies of the Company conform to
generally accepted accounting principles and reflect the effects of the
rate-making process in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation". This statement recognizes the ability of regulators, through the
ratemaking process, to create future economic benefits and obligations affecting
rate-regulated companies. Accordingly, we record these future economic benefits
and obligations as Regulatory Assets and Regulatory Liabilities on the Balance
Sheet, respectively.
The financial statements include the accounts of the Company and its
wholly-owned subsidiary, Massachusetts LNG Incorporated, which became inactive
in 1999.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Certain reclassifications have been made to the prior year financial statements
to conform to the current year presentation.
Merger and Goodwill
On November 8, 2000, KeySpan acquired all of the common stock of KNE LLC for
$64.56 per share in cash. The transaction was accounted for using the purchase
method of accounting for business combinations. The purchase price was allocated
to the net assets acquired of KNE LLC and its subsidiaries based upon their fair
value. The historical cost basis of the Company's assets and liabilities, with
minor exceptions, was determined to represent the fair value due to the
existence of regulatory-approved rate plans based upon the recovery of
historical costs and a fair return thereon. Under "push-down" accounting, the
excess of the purchase price over the fair value of the Company's net assets
acquired, or goodwill, of approximately $774 million was recorded as an asset
and was being amortized over a period of 40 years (see below). The push-down
accounting resulted in an increase in equity of $170 million and the recording
of a $600 million advance from KeySpan. An additional $38.7 million was recorded
as goodwill in finalizing the purchase price allocation, of which $36.2 million
was an addition to equity.
F-7
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Accounting Policies (Continued)
On January 1, 2002, the Company adopted SFAS 142 "Goodwill and Other Intangible
Assets". Under SFAS 142, among other things, goodwill is no longer required to
be amortized and is to be tested for impairment at least annually. The initial
impairment test was to be performed within six months of adopting SFAS 142 using
a discounted cash flow method, compared to an undiscounted cash flow method
allowed under a previous standard. Any amounts impaired using data as of January
1, 2002, was to be recorded as a "Cumulative Effect of an Accounting Change".
Any amounts impaired using data after the initial adoption date will be recorded
as an operating expense. During the second quarter of 2002, we completed our
initial impairment analysis for the Company and determined that no impairment
existed. Also, in the fourth quarter of 2002, we updated our review of the
carrying value of goodwill compared to the fair value of the assets by reporting
unit and determined that no impairment existed.
As required by SFAS 142, below is a reconciliation of reported net income (loss)
applicable for common stockholders for the years ended December 31, 2002 and
2001 and the periods from November 8, 2000 through December 31, 2000 and January
1, 2000 through November 7, 2000 and pro-forma net income (loss), for the same
periods, adjusted for the discontinuance of goodwill amortization.
- ------------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Year Ended December 31, 2000 through 2000 through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Predecessor
Net income (loss) applicable for common stock $ (3,449) $ (31,251) $ 11,883 $ (5,462)
Add back: goodwill amortization - 19,439 3,226 -
- ------------------------------------------------------------------------------------------------------------------------------------
Adjusted net income (loss) applicable for common stock $ (3,449) $ (11,812) $ 15,109 $ (5,462)
- ------------------------------------------------------------------------------------------------------------------------------------
Recent Accounting Pronouncements
On January 1, 2002, we adopted SFAS 141, "Business Combinations", and SFAS 142
"Goodwill and Other Intangible Assets". The key concepts from the two
interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for testing goodwill impairment at a "reporting unit" level
and new criteria for the identification and potential amortization of other
intangible assets. Other changes to existing accounting standards involve the
amount of goodwill to be used in determining the gain or loss on the disposal of
assets and a requirement to test goodwill for impairment at least annually.
In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143,
"Accounting for Asset Retirement Obligations." SFAS 143 requires an entity to
record a liability and corresponding asset representing the present value of
legal obligations associated with the retirement of tangible, long-lived assets.
SFAS 143 is effective for fiscal years beginning after June 2002.
F-8
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Accounting Policies (Continued)
We have completed our assessment of SFAS 143. Our asset base is primarily
composed of storage, and distribution assets which we believe operate in
perpetuity and, therefore, have indeterminate cash flow estimates. A legal
obligation may be construed to exist due to certain safety requirements at final
abandonment. In addition, a legal obligation may be construed to exist with
respect to our LNG storage tanks due to clean up responsibilities upon cessation
of use. Since that exposure is in perpetuity and cannot be measured, no
liability will be recorded. Our asset retirement obligation will be re-evaluated
annually.
SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", was
effective January 1, 2002, and addresses accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 144 supersedes SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business". SFAS
144 retains the fundamental provisions of SFAS 121 and expands the reporting of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal transaction.
For 2002, implementation of this Statement did not have any effect on our
results of operations and financial position.
In June of 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities". This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability recognition for
Certain Employee Termination benefits and Other Costs to Exit an Activity". This
Statement is effective for exit or disposal activities initiated after December
31, 2002, with early application encouraged.
In November 2002, the FASB issued FASB Interpretation No. 45("FIN 45"),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires the guarantor to
recognize a liability for the non-contingent component of a guarantee; that is,
the obligation to stand ready to perform in the event that specified triggering
events or conditions occur. The initial measurement of this liability is the
fair value of the guarantee at inception. The recognition of the liability is
required even if it is not probable that payments will be required under the
guarantee or if the guarantee was issued with a premium payment or as part of a
transaction with multiple elements. FIN 45 also requires additional disclosures
related to guarantees. The disclosure requirements are effective for interim and
annual financial statements for periods ending after December 15, 2002. The
recognition and measurement provisions of FIN 45 are effective for all
guarantees entered into or modified after December 31, 2002. We currently do not
anticipate that implementation of this Statement will have any effect on our
results of operations and financial condition.
In January 2003, the FASB issued FASB Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."
FIN 46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. At the present time, we do not
have any arrangements with variable interest entities.
F-9
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Accounting Policies (Continued)
Regulation
The Company is regulated as to rates, accounting and other matters by the
Department. Therefore, we account for the economic effects of regulation in
accordance with the provisions of SFAS 71. In the event that we determine that
the Company no longer meets the criteria for following SFAS 71, the accounting
impact would be an extraordinary, non-cash charge to operations of an amount
that could be material. Management believes that this amount would approximate
$49.0 million, net of taxes, as of December 31, 2002. Criteria that gives rise
to the discontinuance of SFAS 71 include (1) increasing competition that
restricts our ability to establish prices to recover specific costs or (2) a
significant change in the manner in which rates are set by regulators. We have
reviewed these criteria and believe that the continued 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 amounts that are to be
credited to customers through the rate-making process.
The following regulatory assets were reflected on the balance sheet as of
December 31:
- ----------------------------------------------------------------------------
In Thousands of Dollars 2002 2001
- ----------------------------------------------------------------------------
Post-retirement benefit costs $ 44,360 $ 42,585
Environmental costs 36,939 35,917
- ----------------------------------------------------------------------------
$ 81,299 $ 78,502
- ----------------------------------------------------------------------------
Environmental costs are included in Deferred Charges and Other Assets on the
Balance Sheet. Regulatory liabilities, primarily relating to income taxes, total
approximately $5.9 million and $6.8 million at December 31, 2002 and 2001,
respectively. These amounts are included in Other Deferred Credits and Other
Liabilities on the Balance Sheet.
As of December 31, 2002, all of our regulatory assets and liabilities for which
cash expenditures have been made or cash has been received are reflected in
rates charged or credited to customers. We estimate that full recovery of our
regulatory assets will not exceed 20 years. For additional information regarding
deferred income taxes, post-retirement benefit costs and environmental costs,
see Notes 2, 5 and 9, respectively.
Gas Operating Revenues
Customers are billed monthly on a cycle basis. Revenues include unbilled amounts
related to the estimated gas usage that occurred from the most recent meter
reading to the end of each month.
F-10
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(1) Accounting Policies (Continued)
Cost of Gas Adjustment Clause and Deferred Gas Costs
The cost of gas adjustment clause ("CGAC") requires us to semiannually, or based
on certain criteria monthly, adjust rates for firm gas sales in order to track
changes in the cost of gas distributed, with an annual adjustment of subsequent
rates made for any over or under recovery of actual costs incurred. As a result,
the cost of firm gas that has been distributed to customers but is unbilled at
the end of a period is deferred to the period in which the gas is billed to
customers. We recover the gas cost portion of bad debt write-offs through the
CGAC. In addition, through a local distribution adjustment clause ("LDAC"), we
are allowed to recover the amortization of environmental response costs
associated with former manufactured gas plant ("MGP") sites, costs related to
the our various conservation and load management programs, and other specified
costs from our firm sales and transportation customers.
Property and Depreciation
Utility gas property is stated at original cost of construction, which includes
allocations of overheads, including taxes, and an allowance for funds used
during construction.
Depreciation is provided at rates designed to amortize the cost of depreciable
property, plant and equipment over their estimated remaining useful lives. The
composite depreciation rate, expressed as a percentage of the average
depreciable property in service, is approximately 5.0% for all periods
presented. Amortization is provided on intangible assets, principally software,
over the estimated useful life of these assets.
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.
(2) Income Taxes
For 2002, the Company will file a consolidated income tax return with KeySpan.
We also filed a consolidated return with KeySpan for the year ended 2001 and the
period from November 8, 2000 through December 31, 2000. Under the KeySpan tax
sharing agreement, the allocation of the realized tax liability or benefit on
the federal consolidated income tax return will be based upon separate return
contributions of each company in the consolidated group to the consolidated
taxable income or loss. For the period January 1, 2000 through November 7, 2000,
we filed a consolidated federal income tax return with KNE LLC. For this period,
we followed a policy, established for the group, of providing for income taxes
payable on a separate company basis.
Our effective income tax rate was 396% in 2002, 23.1% for 2001, and 44.6% for
the period from November 8 through December 31, 2000, and 44.7% for the period
from January 1 through November 7, 2000. The majority of the differences between
the effective rate and the federal income tax rate of 35% are primarily due to
state income taxes for each of the periods as well as the non-deductibility of
goodwill amortization for the periods from November 8, 2000 through December 31,
2001. In 2002, the effective income tax rate of 396% is primarily a function of
$4.4 million in state taxes, net of a federal tax benefit, on only $895,000 of
pre-tax book income. The state tax expense is high in relation to the book
income due to deductions primarily related to pension contributions and deferred
gas costs, which resulted in the Company generating a current state tax benefit
and a deferred state tax expense. Massachusetts does not allow regulated
utilities to utilize state net operating losses. Therefore, the Company is
unable to offset its deferred tax expense with its current state tax benefit,
resulting in the disproportionate expense for the current year.
F-11
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(2) Income Taxes (Continued)
A summary of the provision (benefit) for income taxes is as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Year Ended December 31, 2000 through 2000 through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- ----------------------------------------------------------------------------------------------------------------------------------
Predecessor
Current-
Federal $ (60,391) $ 22,378 $ 2,258 $ (17,695)
State (3,479) 4,461 449 (3,491)
----------------- ------------------ ------------------------ -----------------------
Total current provision(benefit) (63,870) 26,839 2,707 (21,186)
Deferred-
Federal 56,972 (30,198) 5,835 14,713
State 10,207 (5,697) 1,176 3,005
----------------- ------------------ ------------------------ -----------------------
Total deferred provision(benefit) 67,179 (35,895) 7,011 17,718
Total provision(benefit) for income taxes $ 3,309 $ (9,056) $ 9,718 $ (3,468)
- ----------------------------------------------------------------------------------------------------------------------------------
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, 2002, the Company had a regulatory tax liability of $879,000
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. We also had a regulatory liability of $5.0 million at
December 31, 2002, for excess deferred taxes being returned to customers over a
30-year period pursuant to a 1988 rate order.
For income tax purposes, we use accelerated depreciation and shorter
depreciation lives, as permitted by the Internal Revenue Code. Deferred federal
and state taxes are provided for the tax effects of all temporary differences
between financial reporting and taxable income. Significant items making up
deferred tax assets and liabilities at December 31, 2002 and 2001 are as
follows:
F-12
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(2) Income Taxes (Continued)
Year Ended Year Ended
In Thousands of Dollars December 31, 2002 December 31, 2001
- -------------------------------------------------------------------------------------------------------------------
Assets:
Regulatory liabilities $ 2,381 $ 2,718
Other 35,965 31,784
--------------------------- --------------------------
Total deferred tax assets 38,346 34,502
--------------------------- --------------------------
Liabilities:
Accelerated depreciation (97,737) (85,333)
Deferred gas costs (46,884) 2,604
Other (38,916) (19,752)
--------------------------- --------------------------
Total deferred tax liabilities (183,537) (102,481)
--------------------------- --------------------------
- -------------------------------------------------------------------------------------------------------------------
Total net deferred taxes $ (145,191) $ (67,979)
- -------------------------------------------------------------------------------------------------------------------
Deferred income taxes are reflected in the balance sheet as follows:
Accrued income taxes (current deferred) $ (3,783) $ 5,630
Deferred income taxes (long-term) (141,408) (73,609)
--------------------------- --------------------------
$ (145,191) $ (67,979)
=========================== ==========================
Investment tax credits are deferred and credited to income over the lives of the
property giving rise to such credits. The credits to income for both 2002 and
2001 were $842,000, $140,000 for the period from November 8 through December 31,
2000 and $702,000 for the period from January 1 through November 7, 2000.
(3) Debt
Long-term Obligations
The following table provides information on long-term obligations as of December
31:
(In Thousands of Dollars) 2002 2001
- -----------------------------------------------------------------------------------------------------------------------
8.33%--9.75%, Medium-Term Notes Series A, due 2005--2022 $ 100,000 $ 100,000
6.93%--8.50%, Medium-Term Notes, Series B, due 2006--2024 50,000 50,000
6.80%--7.25%, Medium-Term Notes, Series C, due 2012--2025 60,000 60,000
Capital lease obligations (Note 6) 13,403 13,989
Less current portion (840) (586)
- -----------------------------------------------------------------------------------------------------------------------
$ 222,563 $ 223,403
- -----------------------------------------------------------------------------------------------------------------------
F-13
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(3) Debt (Continued)
There are no sinking fund requirements for the next two years related to the
$210 million of Medium-Term Notes and none are callable prior to maturity. In
2005, $15 million of 8.875% Medium-Term Notes Series A, mature. In 2006, $12
million of 8.09% Medium-Term Notes Series B, mature.
Annual maturities of capital lease obligations for 2003 through 2007 are
$840,000, $891,000, $945,000, $1.0 million and $1.06 million, respectively.
Utility Money Pool Borrowings
Financing for the Company for working capital and gas inventory needs is
obtained through the Company's participation in a utility money pool. The
utility money pool is administered by KeySpan Corporate Services ("KCS"). At
December 31, 2002, the Company had outstanding borrowings of $67.2 million and
$83.9 million for working capital and gas inventory, respectively. Interest
charged on outstanding borrowings is generally equal to KeySpan's short term
borrowing rate, plus a proportional share of the administrative costs incurred
in obtaining the required funds. All costs related to gas inventory borrowings
are recoverable from customers through the CGAC. The average annual interest
rate on these borrowings for 2002 was 2.9%.
Advance from KeySpan
As part of the acquisition by KeySpan in November 2000, the Company recorded a
$600 million advance payable to KeySpan. During 2001, an additional $50 million
was advanced from Keyspan. Interest charges equal interest incurred by KeySpan
on debt borrowings issued by KeySpan. The weighted-average interest rate on
these borrowings for 2002 is 7.78 %. Issuance expense is charged to the Company
from KeySpan equal to the amortization of actual issuance costs incurred by
KeySpan on its debt borrowings. KeySpan amortizes these costs over the life of
the related KeySpan borrowings.
(4) Preferred Stock
The Company has outstanding 562,700 shares of 6.421% Cumulative Preferred Stock,
which is non-voting and has a liquidation value of $25 per share. The preferred
stock requires 5% annual sinking fund payments beginning on September 1, 1999
with a final redemption on September 1, 2018. At the Company's option, the
annual sinking fund payment may be increased to 10%. The preferred stock is
callable at par in September 2003. The Company redeemed 60,000 shares, or 5% at
$25 per share, on both September 1, 2002 and September 3, 2001.
(5) Retiree Benefits
The Company provides post-retirement benefits, including pension ("pension"),
medical and life insurance (collectively "health care") benefits for
substantially all of its employees. The plan is contributory for retirees, with
respect to medical benefits and noncontributory with respect to life insurance
benefits.
F-14
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(5) Retiree Benefits (Continued)
The Company is subject to deferral accounting requirements, as previously
ordered by the Department, for other postretirement benefit costs. In addition,
per department approval dated January 28, 2003, we will defer, and record as
either a regulatory asset or regulatory liability, the difference between the
level of pension expense that is included in rates charged to gas customers and
the actuarial determined amounts.
Pension benefits for salaried employees are based on salary and years of
service, while pension benefits for union employees are based on negotiated
benefits and years of service. Employees hired before 1993 who are participants
in the pension benefit plans become eligible for post-retirement health care
benefits if they reach retirement age while working for the Company. The funding
of these pension 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").
Effective December 31, 2002, KeySpan merged our qualified pension plans, with
other KeySpan pension plans, into a consolidated Pension Plan (thus forming The
KeySpan Retirement Plan). Thus, for 2002, the pension disclosures presented
below represent the portion of The KeySpan Retirement Plan as it relates to
direct employees of the Company, with the exception of management employees of
an affiliate, Essex Gas Company, who are included in this plan and for which the
benefit obligation attributed to them approximates 3.8% of the total benefit
obligation at December 31, 2002. Prior to 2002, plan information was for the
Company's separate pension plans. The health care plans have not been merged
with our KeySpan plans and therefore, continue to remain separate plans of the
Company.
F-15
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(5) Retiree Benefits (Continued)
The net cost for these plans were charged to expense as follows:
- ------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Pensions Year Ended December 31, 2000 through 2000 through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- ------------------------------------------------------------------------------------------------------------------------------
Predecessor
Service cost - benefits earned during the period $ 3,536 $ 2,964 $ 410 $ 2,272
Interest cost on benefit obligation 11,941 10,690 1,835 8,170
Expected return on plan assets (12,330) (12,701) (2,176) (10,698)
Amortization of prior service cost 945 - - 1,090
Amortization of transitional obligation - - - 186
Amortization of net actuarial (gain)/loss 1,918 60 - (821)
- ------------------------------------------------------------------------------------------------------------------------------
Total pension cost $ 6,010 $ 1,013 $ 69 $ 199
- ------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Period from Period from
November 8, January 1,
Health Care Year Ended December 31, 2000 through 2000 through
(In Thousands of Dollars) 2002 2001 December 31, 2000 November 7, 2000
- -------------------------------------------------------------------------------------------------------------------------------
Predecessor
Service cost-benefits earned during the period $ 1,386 $ 1,358 $ 131 $ 624
Interest cost on benefit obligation 6,683 6,687 1,110 4,736
Expected return on plan assets (2,193) (2,349) (405) (1,787)
Amortization of prior service cost 12 - - (882)
Amortization of net actuarial (gain)/loss 895 636 - (726)
Regulatory deferral - - 486 4,646
- -------------------------------------------------------------------------------------------------------------------------------
Total health care cost $ 6,783 $ 6,332 $ 1,322 $ 6,611
- -------------------------------------------------------------------------------------------------------------------------------
F-16
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(5) Retiree Benefits (Continued)
The following table sets forth the change in benefit obligation and plan assets
and reconciliation of funded status of our pension plans and amounts recorded on
the balance sheet as of December 31, 2002, and December 31, 2001:
- --------------------------------------------------------------------------------
Pensions December 31,
(In Thousands of Dollars) 2002 2001
- --------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ 162,953 $ 157,285
Service cost 3,536 2,964
Interest cost 11,941 10,690
Amendments 7,452 4,419
Actuarial gain (loss) 9,883 (8,403)
Benefits paid (8,859) (4,002)
- --------------------------------------------------------------------------------
Benefit obligation at end of period 186,906 162,953
- --------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 150,240 153,328
Actual return on plan assets (30,322) (8,968)
Employer contributions 44,460 19,000
Adjustment - (4,717)
Benefits paid (8,858) (8,403)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of period 155,520 150,240
- --------------------------------------------------------------------------------
Reconciliation of funded Status:
Funded status (31,386) (12,713)
Unrecognized actuarial loss 75,938 33,085
Unrecognized prior service cost 10,030 4,419
- --------------------------------------------------------------------------------
Net prepaid pension cost reflected on balance sheet $ 54,582 $ 24,791
- --------------------------------------------------------------------------------
Prepaid pension costs are reflected in Deferred Charges and Other Assets on the
Balance Sheet.
F-17
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(5) Retiree Benefits (Continued)
The following table sets forth the change in benefit obligation and plan assets
and reconciliation of funded status of our health care plans and amounts
recorded on the balance sheet as of December 31, 2002 and December 31, 2001:
- ----------------------------------------------------------------------------------------------------------------
Health Care December 31,
(In Thousands of Dollars) 2002 2001
- ----------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at beginning of period $ 100,877 $ 87,440
Service cost 1,386 1,358
Interest cost 6,683 6,686
Amendments 87 21
Plan participants contributions 27 -
Actuarial gain (loss) 5,106 11,860
Benefits paid (5,421) (6,488)
- ----------------------------------------------------------------------------------------------------------------
Benefit obligation at end of period 108,745 100,877
- ----------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of period 27,695 27,432
Actual return on plan assets (4,723) 783
Employer contributions 3,910 5,947
Plan participants contributions 27 21
Benefits paid (5,421) (6,488)
- ----------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period 21,488 27,695
- ----------------------------------------------------------------------------------------------------------------
Reconciliation of funded Status:
Funded status (87,257) (73,182)
Unrecognized actuarial loss 34,827 22,577
Unrecognized prior service cost 75 -
- ----------------------------------------------------------------------------------------------------------------
Net (accrued) health care cost reflected on balance sheet $ (52,355) $ (50,605)
- ----------------------------------------------------------------------------------------------------------------
Accrued health care costs are primarily reflected in Postretirement Benefit
Obligation on the Balance Sheet.
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. Pension and health care plan
assets are invested principally in common stock and fixed income assets.
F-18
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(5) Retiree Benefits (Continued)
Following are the weighted-average assumptions used in developing the projected
and accumulated benefit obligations:
- --------------------------------------------------------------------------------
Year Ended December 31,
(In Thousands of Dollars) 2002 2001 2000
- --------------------------------------------------------------------------------
Assumptions:
Obligation discount 6.75% 7.00% 7.00%
Asset return 8.50% 8.50% 8.50%
Average annual increase in compensation 4.00% 4.00% 5.00%
Health care inflation trend 5.0-9.0% 5.0-10.0% 8.00%
- --------------------------------------------------------------------------------
The health care inflation rate for 2003 is assumed to be 9%. The rate is assumed
to decrease gradually to 5% in 2009 and remain at that level thereafter. A
one-percentage-point increase or decrease in the assumed health care trend rate
for 2002 would have the following effects:
One- One-
Percentage Percentage
Point Point
(In Thousands of Dollars) Increase Decrease
- -------------------------------------------------------------------------------
Net periodic healthcare expense $ 606 $ (554)
Postretirement benefit obligation $ 7,474 $ (6,979)
- -------------------------------------------------------------------------------
Unfunded Pension Obligations
At December 31, 2002, accumulated benefit obligations were in excess of pension
assets. Pursuant to SFAS 87 "Employers' Accounting for Pensions", an additional
minimum liability would normally be recorded for this unfunded pension
obligation. As allowed for under current accounting guidelines, this accrual can
be offset by a corresponding debit to an intangible asset up to the amount of
accumulated unrecognized prior service costs with the remaining amount recorded
as a direct charge to other comprehensive income. However, as the pension plans
were merged into The KeySpan Retirement Plan, an additional minimum liability is
not determined based upon the subsidiary plan information, but rather based upon
the minimum liability associated with The KeySpan Retirement Plan. Therefore, a
minimum liability is not recorded based upon the above plan information.
F-19
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(6) Contractual Obligations and Contingencies (Continued)
Leases
Since the beginning of 2002, substantially all operating leases are the
obligation of KCS, a wholly owned subsidiary of KeySpan. The Company records, as
an inter-company expense, costs incurred for the use of leased equipment such as
buildings, office equipment and vehicles. These inter-company expenses, were
approximately $5.2 million in 2002 and are reflected in Operations and
Maintenance expense in the Statement of Operations. Prior to 2002, rental
expense was a direct charge to the Company and was $7.4 million in 2001, $2.3
million for the period November 8, 2000 through December 31, 2000 and $8.7
million for the period January 1 through November 7, 2000.
In April 1999, the Company entered into a 15 year capital lease for the LNG
facilities located in Salem and Lynn, Massachusetts. A summary of property held
under capital leases as of December 31 is as follows:
- ------------------------------------------------------------------------------
In Thousands of Dollars 2002 2001
- ------------------------------------------------------------------------------
LNG Facilities $ 14,834 $ 14,834
Less: Accumulated Depreciation 1,431 845
- ------------------------------------------------------------------------------
Total Capital Lease $ 13,403 $ 13,989
- ------------------------------------------------------------------------------
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 capital leases in its cost of service for rate purposes.
The remaining minimum rental commitment for the capital leases at December 31,
2002 is approximately $1.6 million a year through 2007, and $10.3 million
thereafter. Included in these future obligations are interest and executory
costs of approximately $4.8 million. As discussed above, minimum rental lease
payments for operating leases are paid by KCS.
Fixed Charges Under Firm Contracts
We have entered into various contracts for gas delivery, storage and supply
services. The contracts have remaining terms that cover from one to ten years.
Certain of these contracts require payment of annual demand charges in the
aggregate amount of approximately $127.0 million. We are liable for these
payments regardless of the level of service we require from third parties. Such
charges are currently recovered from utility customers through the gas
adjustment clause.
F-20
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
(6) Contractual Obligations and Contingencies (Continued)
Legal
From time to time we are subject to various legal proceedings arising out of the
ordinary course of our business. We do not consider any of such proceedings to
be material to our business or likely to result in a material adverse effect on
our results of operations, financial condition and cash flows.
(7) Fair Values of Financial Instruments
The following methods and assumptions were used to estimate the fair values
of financial instruments:
Cash--The carrying amounts approximate fair value.
Short-term Debt--The carrying amounts of the Company's short-term debt,
including notes payable and gas inventory financing, approximate their fair
value.
Long-term Debt--The fair value of long-term debt is estimated based on
currently quoted market prices.
Preferred Stock--The fair value of the preferred stock is based on
currently quoted market prices.
The carrying amounts and estimated fair values of the Company's long-term debt
and preferred stock at December 31, 2002 and 2001 are as follows:
- -------------------------------------------------------------------------------------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------
In Thousands of Dollars Carrying Amount Fair Value Carrying Amount Fair Value
- -------------------------------------------------------------------------------------------------------------
Long-term debt $ 223,403 $ 260,477 $ 223,989 $ 229,499
Preferred stock 13,840 14,067 15,289 15,209
- -------------------------------------------------------------------------------------------------------------
$ 237,243 $ 274,544 $ 239,278 $ 244,708
- -------------------------------------------------------------------------------------------------------------
F-21
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--(Continued)
(8) Related Party Transactions
On November 8, 2000, KCS became an affiliate of the Company, through KNE LLC's
merger with KeySpan. KCS provides financing to the Company for working capital
and gas inventory through a utility money pool. At December 31, 2002 and 2001,
we had outstanding borrowings of $67.2 million and $147.4 million for working
capital, respectively, and $83.9 and $85.4 million for fuel inventory,
respectively.
KCS also provides the Company with services, including executive and
administrative, corporate affairs, customer services, environmental services,
financial services (including accounting, auditing, risk management, tax,
treasury/finance), human resources, information technology, legal, materials
management and purchasing, and strategic planning. In 2002 and 2001, we were
charged $86.8 million and $37.3 million, respectively, for these services. The
increase in amounts charged by KCS is primarily due to the labor costs
associated with a large number of employees who were previously employees of the
Company, but are now employees of KCS.
KCS also purchases and/or develops and implements software and purchases
hardware used by the Company. The amount charged to us by KCS for these
technology assets totaled $18.0 and $21.8 million during 2002 and 2001,
respectively. These charges have been recorded as property assets on our Balance
Sheet.
In 2002 and 2001, we were charged by KCS $8.8 million and $7.3 million,
respectively, for interest on working capital and gas inventory borrowings. In
2000, the Company expensed $1.7 million for interest on these borrowings.
Interest charged is equal to actual interest incurred by KeySpan to issue
commercial paper, plus a proportional share of the administrative costs incurred
in obtaining the funds to meet the combined short-term borrowing requirements of
the members of the Utility Pool Agreement.
As of December 31, 2002, $650 million in advances were recorded on the books of
the Company from KeySpan Corporation. In 2002 and 2001, we were charged by
KeySpan Corporation $51.8 and $49.9 million for interest and debt issuance
costs, respectively. In 2000, we expensed $5.5 million for interest and debt
issuance costs on the advance outstanding in 2000. Interest charges equal
interest incurred by KeySpan on debt borrowings issued by KeySpan. Issuance
expense is charged to the Company from KeySpan equal to the amortization of
actual issuance costs incurred by KeySpan on its debt borrowings. KeySpan
amortizes these costs over the life of the related KeySpan borrowings.
F-22
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--(Continued)
(9) Environmental Matters
The Company, like many other companies in the natural gas industry, is party to
governmental proceedings requiring investigation and possible remediation of
former manufactured gas plant ("MGP") operations, including former operating
plants, gas holder locations and satellite disposal sites. We may have or share
responsibility under applicable environmental laws for the remediation of 19
such sites. A subsidiary of National Grid USA (formerly New England Electric
System) has assumed responsibility for remediating 11 of these sites, subject to
a limited contribution from the Company. In addition, we are aware of 31 other
former MGP related sites within our service territory. The National Grid USA
subsidiary has provided full indemnification to the Company with respect to
eight of the 31 sites. At this time, there is substantial uncertainty as to
whether we have or share responsibility for remediating any of these sites.
However, no notice of responsibility has been issued to us for these sites from
any governmental environmental authority.
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." We estimate the remaining cost of its MGP-related
environmental cleanup activities will be $28.9 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
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. Expenditures incurred to date with respect to these
MGP-related activities total $17.7 million.
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 a regulatory asset of
$36.9 million, representing the expected rate recovery of environmental
remediation costs. This amount is included in Deferred Charges and Other Assets
on the Balance Sheet.
F-23
BOSTON GAS COMPANY
NOTES TO FINANCIAL STATEMENTS--(Continued)
(10) Workforce Reduction Program
In November, 2000, as a result of the KeySpan merger, we recorded a liability
for $6.0 million for a severance program implemented to reduce the workforce.
This severance program was to continue through 2002. During the year ended
December 31, 2001, we paid $1.3 million for this program and reduced our
liability by $3.3 million as a result of lower than anticipated costs per
employee and recorded a corresponding reduction to Goodwill. The remaining
liability at December 31, 2001 was $1.4 million. In 2002, approximately $0.4
million was paid with the remaining liability of approximately $0.2 million
reversed and recorded to earnings. There is a remaining liability of
approximately $0.8 million which is schedule to be paid out in 2003.
(11) Derivatives
The utility tariffs associated with our operations do not contain a weather
normalization clause. As a result, fluctuations from normal weather may have a
significant positive or negative effect on the results of operations. To
mitigate the effect of fluctuations from normal weather on our financial
position and cash flows, we sold heating degree-day call options and purchased
heating-degree day put options for the November 2002 - April 2003 winter season.
With respect to sold call options, we are required to make a payment of $40,000
per heating degree day to our counter-parties when actual weather experienced
during the November 2002 - April 2003 time frame is above 4,470 heating degree
days, which equates to approximately 1% colder than normal weather. With respect
to purchased put options, we will receive a $20,000 per heating degree day
payment from our counter-parties when actual weather is below 4,150 heating
degree days, or is approximately 7% warmer than normal. Based on the terms of
such contracts, we account for such instruments pursuant to the requirements of
EITF 99-2, "Accounting for Weather Derivatives." In this regard, we account for
such instruments using the "intrinsic value method" as set forth in such
guidance. During the fourth quarter of 2002, weather was approximately 7.4%
colder than normal and we recorded a $3.3 million reduction to revenues with a
corresponding liability due to our counter-parties.
On April 1, 2002, we adopted Implementation Issue C16 of SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities" as amended and interpreted
incorporating SFAS 137 and 138 and certain implementation issues (collectively
"SFAS 133"). Issue C16 establishes new criteria that must be satisfied in order
for contracts that combine a forward contract and a purchased option contract to
be exempted as normal purchases and sales.
Based upon a review of its physical gas purchase commodity contracts, we
determined that certain contracts could no longer be exempted as normal
purchases from the requirements of SFAS 133. At December 31, 2002, the fair
value of these contracts was a liability of $0.6 million. Since these contracts
are for the purchase of natural gas sold to firm gas sales customers, the
accounting for these contracts is subject to SFAS 71. Therefore, changes in the
market value of these contracts are recorded as a deferred asset or deferred
liability on the Balance Sheet.
F-24
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors of Boston Gas Company:
We have audited the accompanying Balance Sheet of Boston Gas Company (the
Company) (an indirectly wholly-owned subsidiary of KeySpan Corporation,) as of
December 31, 2002, and the related Statements of Operations, Retained Earnings
(Deficit), Comprehensive Income (Loss), and Cash Flows for the year then ended.
Our audit also included the financial statement schedule, for the year ended
December 31, 2002, listed in the Index to Financial Statements and Schedules.
These financial statements and the financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and the financial schedule based on our
audit. The financial statements of Boston Gas Company as of December 31, 2001,
and for the year then ended, the period from November 8, 2000 through December
31, 2000 and the period from January 1, 2000 through November 7, 2000 were
audited by other auditors who have ceased operations. Their report, dated
February 4, 2002, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Boston Gas Company as of
December 31, 2002, and the results of their operations and their cash flows for
the year then ended in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly in all material respects, the information set forth
therein.
As discussed in Note 1 to the Financial Statements, on January 1, 2002, the
Company adopted Statement of Financial Accounting Standards No. 142 "Goodwill
and Other Intangible Assets," (SFAS No. 142) to change its method of accounting
for goodwill and other intangible assets.
As discussed above, the financial statements of the Company as of December 31,
2001, and for the year then ended, the period from November 8, 2000 through
December 31, 2000 and the period from January 1, 2000 through November 7, 2000
were audited by other auditors who have ceased operations. Note 1 to these
financial statements has been revised to include the transitional disclosures
required by SFAS No. 142. Our audit procedures with respect to the disclosures
in Note 1 for the 2001 and 2000 periods included (i) agreeing the previously
reported net income (loss) applicable for common stock to the previously issued
financial statements and the adjustments to net income (loss) applicable for
common stock representing amortization expense recognized in those periods
related to goodwill to the Company's underlying records obtained from
management, and (ii) testing the mathematical accuracy of the reconciliation of
adjusted net income (loss) to reported net income (loss) available for common
stock. In our opinion, the disclosures in Note 1 are appropriate and have been
properly applied. However, we were not engaged to audit, review, or apply any
procedures to the 2001 and 2000 financial statements of the Company other than
with respect to such adjustments and, accordingly, we do not express an opinion
or any other form of assurance on the 2001 and 2000 financial statements taken
as a whole.
DELOITTE & TOUCHE LLP
New York, New York
February 10, 2003
F-25
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Boston Gas Company:
We have audited the accompanying consolidated balance sheets of Boston Gas
Company (a Massachusetts Corporation and an indirect wholly-owned subsidiary of
KeySpan Corporation) and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of earnings, retained earnings, comprehensive
income and cash flows for the year ended December 31, 2001, the period from
November 8, 2000 through December 31, 2000, the period from January 1, 2000
through November 7, 2000, and the year ended December 31, 1999. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Boston Gas Company and
subsidiary as of December 31, 2001 and 2000 and the results of their operations
and their cash flows for the year ended December 31, 2001, the period from
November 8, 2000 through December 31, 2000, the period from January 1, 2000
through November 7, 2000, and the year 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 schedule listed in the index to
consolidated financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not a part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states, in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN LLP
New York, New York
February 4, 2002
Readers of these financial statements should be aware that this report is a copy
of a previously issued Arthur Andersen LLP report and that this report has not
been reissued by Arthur Andersen LLP. Furthermore, this report has not been
updated since February 4, 2002 and Arthur Andersen LLP completed its last post
audit review of the December 31, 2001 financial statements on April 29, 2002.
F-26
BOSTON GAS COMPANY
INTERIM FINANCIAL INFORMATION
For the two years ended December 31, 2002 and 2001 (Unaudited)
Quarters Ended 2002
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(In Thousands) March 31 June 30 Sept. 30 Dec. 31
- -------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 244,291 $ 101,771 $ 64,424 $ 228,625
Operating margin $ 110,804 $ 54,886 $ 40,592 $ 87,006
Operating earnings (loss) including income taxes $ 41,539 $ 3,683 $ (6,153) $ 23,211
Net earnings (loss) applicable to common stock $ 25,262 $ (11,814) $ (23,692) $ 6,795
- -------------------------------------------------------------------------------------------------------------------------------
Quarters Ended 2001
- -------------------------------------------------------------------------------------------------------------------------------
(In Thousands) March 31 June 30 Sept. 30 Dec. 31
- -------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 401,020 $ 148,042 $ 84,462 $195,414
Operating margin $ 109,273 $ 49,897 $ 36,626 $ 74,459
Operating earnings (loss) including income taxes $ 32,652 $ (4,555) $ (11,193) $ 10,181
Net earnings (loss) applicable to common stock $ 19,626 $ (20,446) $ (26,949) $ (3,482)
- -------------------------------------------------------------------------------------------------------------------------------
In the opinion of management, the annual financial data includes all
adjustments, unless otherwise noted in the accompanying footnotes, consisting
only of normal recurring accruals, necessary for a fair presentation of such
information.
F-27
SCHEDULE II
BOSTON GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
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Charged Net
Balance at Charged (Credited)to Deductions
Beginning of (Credited) other from Balance at
(In Thousands) Period to Income Accounts Reserves End of Period
For the Year Ended December 31, 2002
Reserves for doubtful accounts $ 14,730 $ 15,503 $ - $ 15,567 $ 14,666
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Reserve for self-insurance $ 843 $ 1,250 $ - $ 1,425 $ 668
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Reserve for environmental expenses $ 31,878 $ - $ 3,047 $ - $ 28,831
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For the Year Ended December 31, 2001
Reserves for doubtful accounts $ 13,681 $ 11,192 $ - $ 10,143 $ 14,730
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Reserve for self-insurance $ 2,891 $ 675 $ - $ 2,723 $ 843
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Reserve for environmental expenses $ 18,000 $ - $ 13,878 $ - $ 31,878
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For the Period From November 8, 2000
Through December 31, 2000
Reserves for doubtful accounts $ 12,329 $ 2,687 $ - $ 1,335 $ 13,681
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Reserve for self-insurance $ 2,901 $ 250 $ - $ 260 $ 2,891
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Reserve for environmental expenses $ 18,000 $ - $ - $ - $ 18,000
======== ======== ======== ======== ========
For the Period From January 1, 2000
Through November 7, 2000(Predecessor)
Reserves for doubtful accounts $ 14,816 $ 7,761 $ - $ 10,248 $ 12,329
======== ======== ======== ======== ========
Reserve for self-insurance $ 3,913 $ 1,616 $ - $ 2,628 $ 2,901
======== ======== ======== ======== ========
Reserve for environmental expenses $ 18,000 $ - $ - $ - $ 18,000
======== ======== ======== ======== ========
F-28