<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1999
-----------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to_______________
Commission file number 2-7749
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COMMONWEALTH ELECTRIC COMPANY
----------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Massachusetts 04-1659070
- ------------------------------- ------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
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(Address of principal executive offices) (Zip Code)
(617) 424-2000
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(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
--------------------------- -----------------------------------------
None None
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
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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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Outstanding at
Class of Common Stock March 30, 2000
--------------------------- --------------
Common Stock, $25 par value 2,043,972 shares
The Company meets the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this Form
with the reduced disclosure format.
Documents Incorporated by Reference Part in Form 10-K
- ----------------------------------- -----------------
None Not Applicable
List of Exhibits begins on page 44 of this report.
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COMMONWEALTH ELECTRIC COMPANY
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TABLE OF CONTENTS
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PART I
PAGE
----
Item 1. Business........................................ 3
Item 2. Properties...................................... 6
Item 3. Legal Proceedings............................... 6
PART II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters..................... 7
Item 7. Management's Discussion and Analysis of
Results of Operations........................... 8
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk............................... 14
Item 8. Financial Statements and Supplementary Data..... 14
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 14
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................... 34
Signatures.................................................. 44
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PART I.
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Item 1. Business
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(a) General
-------
Commonwealth Electric Company (the Company) is engaged in the distribution and
sale of electricity to approximately 329,000 retail customers (including 44,600
seasonal customers) in 40 communities located in southeastern Massachusetts,
including Cape Cod and the island of Martha's Vineyard, having an approximate
year-round population of 549,000 and a large influx of summer residents.
The Company, which was organized on April 4, 1850 pursuant to a special act of
the legislature of the Commonwealth of Massachusetts, operates under the
jurisdiction of the Massachusetts Department of Telecommunications and Energy
(MDTE) that regulates retail rates, accounting, issuance of securities and other
matters. In addition, the Company files its wholesale rates with the Federal
Energy Regulatory Commission (FERC). The Company is wholly-owned by Commonwealth
Energy System (COM/Energy) which is a wholly-owned indirect subsidiary by NSTAR.
NSTAR is the new holding company that was formed, effective August 25, 1999
after receipt of all necessary approvals and upon completion of a merger
transaction between Commonwealth Energy System (COM/Energy, formerly the parent
of the Company) and BEC Energy. The merger created an energy delivery company
which includes the Company, serving approximately 1.3 million customers located
in Massachusetts including more than one million electric customers in 81
communities and 240,000 gas customers in 51 communities. NSTAR is an exempt
public utility holding company under the provisions of the Public Utility
Holding Company Act of 1935 and, in addition to its investment in the Company,
has interests in other utility and several nonregulated companies.
(b) Electric Industry Restructuring
-------------------------------
On November 25, 1997, the Governor of Massachusetts signed into law the Electric
Industry Restructuring Act (the Act). This legislation provided, among other
things, that customers of retail electric utility companies who take standard
offer service receive a 10 percent rate reduction and be allowed to choose their
energy supplier, effective March 1, 1998. The Act also provides that utilities
be allowed full recovery of transition costs subject to review and an audit
process. The rate reduction mandated by the legislation increased to 15 percent
effective September 1, 1999 for customers who continue to take standard offer
service.
The Company, together with affiliates Cambridge Electric Light Company
(Cambridge Electric) and Canal Electric Company (Canal Electric), had filed a
comprehensive electric restructuring plan with the MDTE in November 1997 that
was substantially approved by the MDTE in February 1998. The divestiture of the
Company's non-nuclear generation assets was an integral part of COM/Energy's
restructuring plan and is consistent with the Act.
On May 27, 1998, Canal Electric selected Southern Energy to buy Canal Units 1
and 2. The sale was conducted through an auction process that was outlined in a
restructuring plan filed with the MDTE in November 1997 in conjunction with
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the state's industry restructuring legislation enacted in 1997. The sale was
approved by the MDTE on October 30, 1998 and by the FERC on November 12, 1998.
Proceeds from the sale of Canal Electric's and the Company's non-nuclear
generating assets amounted to approximately $395 million or 6 times their book
value of approximately $65.4 million. The proceeds from the sale, net of book
value, transaction costs and certain other adjustments, amounted to
approximately $298 million and are being used to reduce transition costs of
Cambridge Electric and the Company related to electric industry restructuring
that otherwise would have been collected through a non-bypassable transition
charge. An adjustment of $5.1 million was recorded in the first quarter of 1999
that reduced the book value to $60.3 million.
On December 23, 1998, the MDTE approved the divestiture filing and COM/Energy's
proposal to establish a special purpose affiliate, Energy Investment Services,
Inc. (EIS), that will administer the above-book value net proceeds from the sale
of the Company's units with the goal of preserving capital and maximizing
earnings for the benefit of retail customers. EIS will credit the proceeds and
any return earned to the accounts of the Company and Cambridge Electric,
resulting in a reduction in the transition costs to be billed to customers.
The electric industry has continued to change in response to legislative,
regulatory and marketplace demands for improved customer service at lower
prices. These demands have resulted in an increasing trend in the industry to
seek competitive advantages and other benefits through business combinations.
NSTAR was created to operate in this new marketplace by combining the resources
of its utility subsidiaries and concentrating its activities in the transmission
and distribution of energy. In response to the significant changes that have
taken place in the electric utility industry, the Company sold all of its
generating assets in late 1998 to focus on the distribution of energy and
related services.
(c) Sources and Availability of Electric Power Supply
-------------------------------------------------
NSTAR on behalf of its electric retail subsidiaries, the Company, Boston Edison
and Cambridge Electric entered into a six-month agreement effective January 1,
2000 to transfer all of the unit output entitlements in long-term power purchase
contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In
return, Select will provide full energy service requirements, including New
England Power Pool (NEPOOL) capability responsibilities at FERC approved tariff
rates through June 30, 2000.
During 1997, NEPOOL was restructured with changes taking effect to the
membership and governance provisions of the power pooling agreement along with
the transfer of operating responsibility of the integrated transmission and
generation system in New England to ISO New England. Previously, NEPOOL
dispatched generating units for operation based on the lowest operating costs of
available generation and transmission. Under the new structure, generators are
required to provide ISO New England with market prices at which they will
sell short-term energy supply. These prices formed the basis for dispatch that
began in the second quarter of 1999. As noted, the Company will receive all of
its power supply requirements from Select through June 30, 2000. Therefore, the
change to NEPOOL's operations and pricing structure is expected to have no
material impact on the Company's costs for purchased electric energy through the
second quarter of 2000.
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(d) Franchises
----------
Through its charters, which is unlimited in time, the Company has the right to
engage in the business of distributing and selling electricity and is entitled
to all the rights and privileges of and subject to the duties imposed upon
electric companies under Massachusetts laws. The locations in public ways for
electric transmission and distribution lines are obtained from municipal and
other state authorities which, in granting these locations, act as agents for
the state. In some cases the action of these authorities is subject to appeal
to the Massachusetts Department of Telecommunications and Energy (MDTE). The
rights to these locations are not limited in time, but are not vested and are
subject to the action of these authorities and the legislature. Pursuant to the
Massachusetts Electric Restructuring Act enacted in November 1997, the MDTE has
defined the service territory of the Company based on the territory actually
served on July 1, 1997, and following, to the extent possible, municipal
boundaries. The legislation further provided that, until terminated by effect
of law or otherwise, these companies shall have the exclusive obligation to
provide distribution service to all retail customers within such service
territory. No other entity shall provide distribution service within this
territory without the written consent of the Company which consent, must be
filed with the MDTE and the municipality so affected.
(e) Retail Electric Rates
---------------------
As a result of electric industry restructuring, the Company unbundled its rates,
provided customers with a 10 percent rate reduction as of March 1, 1998 and has
afforded customers the opportunity to purchase generation supply in the
competitive market. The 10 percent rate reduction mandated by the legistation
increased to 15 percent effective September 1, 1999 for customers who continue
to take standard offer service. Unbundled delivery rates are composed of a
distribution charge (to collect the costs of delivering and billing for
electricity), a transition charge (to collect past costs for investments in
generating plants and costs related to power contracts), a transmission charge
(to collect the cost of moving the electricity over high voltage lines from a
generating plant), an energy conservation charge (to collect costs for demand-
side management programs) and a renewable energy charge (to collect the cost to
support the development and promotion of renewable energy projects). Electricity
supply services provided by the Company include optional standard offer service
and default service.
Standard offer service is the electricity that is supplied by the local retail
electric subsidiaries until a competitive power supplier is chosen by the
customer. It is designed as a seven-year transitional service to give the
customer time to learn about competitive power suppliers. The price of standard
offer service will increase over time. Default service is supplied by the local
distribution company when a customer is not receiving power from either standard
offer service or a competitive power supplier. The market price for default
service will fluctuate based on the average market price for power. Amounts
collected through these various charges will be reconciled to actual
expenditures on an on-going basis.
Prior to the implementation of industry restructuring on March 1, 1998, the
Company had Fuel Charge rate schedules that generally allowed for current
recovery, from retail customers, of fuel used in electric production, purchased
power and transmission costs.
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(f) Demand-Side Management Programs
-------------------------------
The Company has implemented a variety of DSM programs that are
designed to reduce future energy use by its customers. Pursuant to the
Restructuring Act, the Company has agreed to mandatory charges per KWH to fund
energy efficiency and demand-side management activities.
(g) Capital Expendituring and Financing
-----------------------------------
Management continuously reviews its capital expenditure and financing programs.
These programs and, therefore, the estimates included in this Form 10-K are
subject to revision due to changes in regulatory requirements, environmental
standards, availability and cost of capital, interest rates and other
assumptions.
Plant expenditures in 1999 were $21 million and consisted primarily of
additions to the Company's distribution and transmission systems. The majority
of these expenditures were for system reliability and control improvements,
customer service enhancements and capacity expansion to allow for long-range
growth in the Company service territory.
(h) Seasonal Nature of Business
---------------------------
Kilowatt-hour sales and revenues are typically higher in the winter and summer
than in the spring and fall as sales tend to vary with weather conditions.
(i) Competitive Conditions
----------------------
The electric industry has continued to change in response to legislative,
regulatory and marketplace demands for improved customer service at lower
prices. These pressures have resulted in an increasing trend in the industry to
seek competitive advantages and other benefits through business combinations.
NSTAR was created to operate in this new marketplace by combining the resources
of its utility subsidiaries and its activities in the transmission and
distribution of energy.
(j) Employees
---------
The total number of full-time employees for the Company declined 9.5% in 1999 to
629 from 695 employees at year-end 1998. The Company has 470 employees (74.7%)
who are represented by the Utility Workers of New England, Inc. under three
separate collective bargaining units with agreements that expire October 31,
2001, September 30, 2002 and April 30, 2003. Employee relations have generally
been satisfactory.
Item 2. Properties
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The principal properties of the Company consist of an integrated system of
transmission and distribution lines, substations, an office building in the Town
of Wareham, MA and other structures such as garages and service buildings. On
December 30, 1998, the Company sold to an affiliate of The Southern Company of
Atlanta, GA, two diesel plants with a combined capability of 13.8 MW located on
the island of Martha's Vineyard that were used for standby and emergency
purposes. Also sold was the Company's 1.4% joint-ownership interest in Central
Maine Power Company's Wyman Unit 4 with an entitlement of 8.8 MW.
At December 31, 1999, the electric transmission and distribution system
consisted of 5,787 pole miles of overhead lines, 3,888 cable miles of
underground line, 140 substations and 343,988 active customer meters.
Item 3. Legal Proceedings
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Along with other Massachusetts investor-owned utilities, the Company has been
named as a defendant in a class action suite seeking to declare certain
provisions of the Massachusetts electric industry restructuring legislation
unconstitutional.
Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.
Merger Rate Plan
An integral component of the merger which created NSTAR was a rate plan filed
by its retail utility subsidiaries, including the Company. The MDTE issued an
order approving most major elements of the rate plan on July 27, 1999. The
highlights of the rate plan include a four-year distribution rate freeze for
each of the NSTAR retail utility subsidiaries, including the Company, the
collection from customers of recovery of transaction and integration costs
initially estimated at approximately $111 million over 10 years. The
Massachusetts Attorney General and a group of four interveners filed separate
appeals of the MDTE order with the Massachusetts Supreme Judicial Court (SJC)
regarding the rate plan. While management anticipates that the MDTE's decision
to approve the rate plan will be upheld by the SJC, it cannot determine the
ultimate outcome of these appeals or their impact on the rate plan.
Other Litigation
In the normal course of its business the Company is also involved in certain
other legal matters. Management is unable to fully determine a range of
reasonably possible legal costs in excess of amounts accrued. Based on the
information currently avaiable, it does not believe that it is probable that any
such additional costs will have a material impact on its consolidated
finacnial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.
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PART II.
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Item 5. Market for the Registrant's Common Stock and Related Stockholder
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Matters
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(a) Principal Market
----------------
Not applicable. The Company is wholly-owned by Commonwealth Energy
Systems and is a wholly-owned indirect subsidiary of NSTAR.
(b) Number of Shareholders at December 31, 1999
-------------------------------------------
One
(c) Frequency and Amount of Dividends Declared in 1999 and 1998
-----------------------------------------------------------
1999 1998
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Per Share Per Share
Declaration Date Amount Declaration Date Amount
---------------- --------- ---------------- ---------
January 27,1999 $ 1.00 May 11, 1998 $3.40
April 28, 1999 2.00 October 26, 1998 1.55
July 23, 1999 1.85 -----
October 28, 1999(1) 7.30 $4.95
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$12.15
======
(1) The dividend declared on October 28, 1999 constituted a return of
capital.
Reference is made to Note 7 of the Notes to Financial Statements filed
under Item 8 of this report for the restriction against the payment of
cash dividends.
(d) Future dividends may vary depending upon the Company's earnings and
capital requirements as well as financial and other conditions existing
at that time.
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Item 7. Management's Discussion and Analysis of Results of Operations
- ------- -------------------------------------------------------------
The following is a discussion of certain significant factors that have affected
operating revenues, expenses and net income during the periods included in the
accompanying Statements of Income and is presented to facilitate an
understanding of the results of operations. This discussion should be read in
conjunction with Item 1 of this report and the Notes to Financial Statements
filed under Item 8 of this report.
In the accompanying statements, the Company prior to the Merger is labeled as
the "Predecessor" and after the Merger as the "Successor". The eight month
(predecessor period) and the 4 month (successor period), ended August 25, 1999
and December 31, respectively, have been combined per the purpose of comparing
the results of the twelve month period ended December 31, 1998 with the twelve
month period ended December 31, 1999.
Unit Sales and Customers
- ------------------------
The following is a summary of unit sales and customers for the periods
indicated:
<TABLE>
<CAPTION>
Years Ended December 31,
-----------------------------
1999 1998
--------- ---------
%
Unit Sales (MWH): Change
-------
<S> <C> <C> <C>
Residential 1,798,145 8.8 1,652,797
Commercial 1,568,657 6.4 1,473,761
Industrial 374,763 3.1 363,559
Streetlighting 16,432 3.9 15,815
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Total retail 3,757,997 7.2 3,505,932
Wholesale 1,072,198 (26.6) 1,460,170
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Total 4,830,195 (2.7) 4,966,102
========= =========
Customers - 12 Month Average:
Residential (a) 287,188 0.5 285,659
Commercial (a) 40,747 1.9 39,978
Industrial 288 (1.4) 292
Streetlighting 1,109 0.8 1,106
--------- ---------
Total 329,332 0.7 327,035
========= =========
</TABLE>
(a) Includes seasonal customers of 44,577 in 1999, 45,537 in 1998 and 46,147 in
1997. Service is considered to be "seasonal" when the kilowatthours used
in the billing months ending between June 1 and September 30 exceed the
kilowatthours used in the preceding eight months.
Retail unit sales increased in 1999 due to higher than normal summer
temperatures and a continuing strong local economy.
The Company's residential customer segment provides approximately 48% of its
total retail sales and approximately 8% of those customers rely on electricity
for space heating.
Operating Revenues
- ------------------
Operating revenues for 1999 increased $1 million (0.2%) due to higher retail
unit sales, somewhat offset by the 10 percent rate reduction (increased to 15
percent effective September 1, 1999) (further discussed below),
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and a net decrease in electricity purchased for resale, fuel and
transmission charges of $16.1 million (6%). The decline in these costs reflects
a cost deferral of $19.6 million in conjunction with the Company's restructuring
plan as approved by the Massachusetts Department of Telecommunications and
Energy (MDTE). As a result of Electric Industry Restructuring Act, the Company
has unbundled its rates and currently provides its standard offer customers
service at inflation adjusted rates that are 15% lower than rates in effect
prior to March 1, 1998. The Company has also afforded customers the opportunity
to purchase generation supply in the competitive market. Delivery rates are
composed of a customer charge, a distribution charge, a transition charge (to
collect stranded costs), a transmission charge, an energy conservation charge
(to collect costs for demand-side management programs) and a renewable energy
charge. Electricity supply services provided by the Company include optional
standard offer service and default service. Amounts collected through these
various charges will be reconciled to actual expenditures on an on-going basis.
Wholesale revenues were $20.3 million, $27.9 million, and $27.8 million in 1999,
1998 and 1997, respectively.
Electricity Purchased for Resale, Transmission and Fuel
- -------------------------------------------------------
To satisfy demand requirements and provide required reserve capacity, the
Company purchased power on a long and short-term basis through entitlements
pursuant to power contracts with other New England and Canadian utilities. The
Company supplemented these sources with its own generating capacity that was
sold on December 30, 1998.
The cost of electricity purchased for resale, fuel and transmission constituted
59.6% in 1999 of electric operating revenues. These costs reflect higher unit
sales and in addition, a cost deferral of $19.6 million in 1999 that resulted
primarily from providing the required 10% rate reduction, which was adjusted to
15% in September 1999, for retail customers.
NSTAR on behalf of its electric retail subsidiaries of the Company, Boston
Edison and Cambridge Electric, entered into a six-month agreement effective
January 1,
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2000 to transfer all of the unit output entitlements in long-term power purchase
contracts to Select Energy (Select), a subsidiary of Northeast Utilities. In
return, Select will provides full energy service requirements, including NEPOOL
capability responsibilities, at FERC approved tariff rates through June 30,
2000.
Other Operating Expenses
- ------------------------
Other operation increased $25.7 million (36.5%) in 1999 primarily due to the
recognition of costs allocated to the Company that relate to various
compensation plans whose benefits have vested as a result of a change in control
at the NSTAR level including $8.3 million in pension costs that were previously
deferred that were expensed during 1999. In addition, other factors that
impacted other operation in 1999 were costs related to Hurricane Floyd ($2
million) and an increase in the provision for bad debts ($1.4 million).
In 1999, maintenance increased $5.1 million (44.1%) due to costs associated with
transmission and distribution to repair overhead conductors ($1.2 million) and
storm damage repairs of $3.3 million.
Depreciation and amortization expense declined $1.1 million in 1999 despite
reflecting merger-related amortization of $2.1 million. These costs were
somewhat offset by a reduction in other amortized costs from those in 1998 and
included certain prior-period deferred costs, including costs associated with
DSM programs, purchased power, certain postretirement benefits, and litigation
costs related to the Pilgrim nuclear power unit.
Federal and state income taxes declined $5.6 million (61.2%) in 1999 and due
mainly to the change in pretax income.
Local property and other taxes in 1999 increased primarily due to higher
property tax assessments and rates. Payroll and other taxes increased $165,000
in 1999.
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Other Income (Expense)
- ----------------------
Other income increased in 1999 due to interest accrued on deferred transition
costs associated with electric industry restructuring.
Interest Charges
- ----------------
Total interest charges increased in 1999 due primarily to interest on customer
refunds ($4.7 million).
Merger with BEC Energy
- ----------------------
NSTAR was created through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public utility holding
company. NSTAR's utility subsidiaries are Boston Edison Company (Boston
Edison), Commonwealth Electric Company (the Company), Cambridge Electric Light
Company (Cambridge Electric), Canal Electric Company (Canal Electric) and
Commonwealth Gas Company (ComGas). Utility operations accounted for more than
98% of revenues in both 1999 and 1998. NSTAR's nonutility operations include
telecommunications, district heating and cooling operations and liquefied
natural gas services.
As a result of the merger, the fourth quarter dividend amounting to
approximately $15 million was reflected as a return of capital and, as a result,
reduced paid-in capital. As of August 25, 1999, approximately $34 million of
retained earnings was reclassified as additional paid-in capital.
The electric and natural gas industries have continued to change in response to
legislative, regulatory and marketplace demands for improved customer service at
lower prices. These demands have resulted in an increasing trend in the
industry to seek competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new marketplace by combining
the resources of its utility subsidiaries and concentrating its activities in
the transmission and distribution of energy. This is illustrated by the sale of
Boston Edison's fossil generating facilities in 1998 and its nuclear generating
facility in 1999. Substantially all of COM/Energy's generating facilities were
sold in 1998.
The utility companies of NSTAR form an energy delivery company serving
approximately 1.3 million customers located in Massachusetts, including more
than one million electric customers in 81 communities and 240,000 gas customers
in 51 communities.
The merger became effective after receipt of various regulatory approvals. The
Federal Energy Regulatory Commission approved the merger on June 24, 1999. The
Nuclear Regulatory Commission approved the transfer of control of subsidiary
Canal Electric's interest in the Seabrook nuclear plant from COM/Energy to NSTAR
on August 11, 1999. The Securities and Exchange Commission issued its approval
on August 24, 1999.
An integral part of the merger is the rate plan that was filed by the retail
utility subsidiaries of BEC and COM/Energy in February 1999 and approved by the
MDTE on July 27, 1999. Significant elements of the rate plan include a four-
year distribution rate freeze (after an adjustment to the distribution rates of
affiliate Cambridge Electric and the Company to collect the appropriate level of
distribution costs that is offset by a reduction in the transition charge that
was previously approved by the MDTE), recovery of the acquisition premium
(goodwill) over 40 years and recovery of transaction and integration costs
(costs to achieve) over 10 years.
The merger was accounted for by BEC as an acquisition of COM/Energy under
the purchase method of accounting. The total goodwill associated with the
acquisition was approximately $486 million on a consolidated basis, while the
original estimate of costs to achieve the merger was $111 million on a
consolidated basis. Costs to achieve which have been allocated to the Company
were approximately $18.6 million as of December 31, 1999, and are included as
merger costs in regulatory assets on the Company's balance sheet (Note 2(c)).
Costs to achieve will be recovered over the amortization period of 10 years. The
amount of goodwill allocated to the Company as of the merger date was
approximately $235 million, and is being amortized over a period of 40 years. A
portion of the goodwill amortization will be allocated to Boston Edison Company
(an NSTAR subsidiary) on an anuual basis in accordance with the MDTE rate order
approving the merger.
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A group of four intervenors and the Massachusetts Attorney General filed two
separate appeals of the MDTE's rate plan order with the Massachusetts Supreme
Judicial Court (SJC) in August 1999. While management anticipates that the
MDTE's decision to approve the rate plan will be upheld by the SJC, it is unable
to determine the ultimate outcome of these appeals or their impact on the rate
plan.
Provisions of Statement of Financial Accounting Standards No. 71
- ----------------------------------------------------------------
As described in Note 2(b) of the Notes to Financial Statements, the Company
follows the provisions of Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation." In the event
the Company is somehow unable to meet the criteria for following SFAS No. 71,
the accounting impact would be an extraordinary, non-cash charge to operations
in an amount that could be material. Conditions that could give rise to the
discontinuance of SFAS No. 71 include: 1) increasing competition restricting the
Company's ability to establish prices to recover specific costs, and 2) a
significant change in the current manner in which rates are set by regulators.
The Company monitors these criteria to ensure that the continuing application of
SFAS No. 71 is appropriate. Based on the current evaluation of the various
factors and conditions that are expected to impact future cost recovery, the
Company believes that its utility operations remain subject to SFAS No. 71 and
its regulatory assets.
Year 2000
- ---------
NSTAR's mission critical systems and other important business systems were
considered ready for the year 2000 prior to December 31, 1999. The North
American Electric Reliability Council defined mission critical systems as those
whose mis-operation could result in loss of electric generation, transmission or
load interruption. To date, NSTAR has not experienced any significant year 2000
problems. NSTAR will continue to monitor systems in order to address any
potential continuing risk of non-compliant internal business software, internal
non-business software and embedded chip technology and external noncompliance of
third parties.
Under its year 2000 program NSTAR inventoried mission critical systems that were
date-sensitive and that used embedded technology such as micro-controllers or
microprocessors. Approximately 27% and 20% of BEC's and COM/Energy's systems,
respectively, required modification or replacement.
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NSTAR also inventoried important business systems that were date-sensitive and
determined that approximately one-third of BEC's systems and approximately 90%
of COM/Energy's systems needed modification or replacement. Plans were
developed and implemented to correct and test all affected systems, with
priorities based on the importance of the supported activity. As systems were
remediated, they were tested for operational and year 2000 readiness in their
own environment. After implementation, the systems were then tested for their
integration and compatibility with other interactive systems.
In addition, all non-critical internal productivity systems were inventoried and
assessed as part of the year 2000 program. Approximately one-third of BEC's
systems and approximately 90% of COM/Energy's systems required modification or
replacement. All of these systems were declared ready by September 30, 1999.
Costs incurred to upgrade or remediate systems have been expensed as incurred.
In addition, a decision was made to replace some of the less efficient
centralized business systems. Systems replacement costs are being capitalized
and amortized over future periods. NSTAR has expended a total of approximately
$39 million on this project through December 31, 1999. Future costs are
anticipated to be immaterial.
In addition to its internal efforts, BEC and COM/Energy initiated formal
communications with their significant suppliers, service providers and other
vendors to determine the extent to which they may be vulnerable to these
parties' failure to correct their own year 2000 issues. To date, NSTAR has not
experienced any significant year 2000 problems associated with its reliance on
third parties.
NSTAR's year 2000 program included contingency plans. If required, these plans
were intended to address both internal risks as well as potential external risks
related to vendors, customers and energy suppliers. Plans were developed in
conjunction with available national and regional guidance and were based on
system emergency plans that were developed and successfully tested over the past
several years. Included within its contingency plans were procedures for the
procurement of short-term power supplies and emergency distribution system
restoration procedures. In the event that a problem is to arise in 2000 (or
beyond), these contingency plans would become effective in order to remediate
the problem.
Environmental Matters
- ---------------------
The Company is subject to laws and regulations administered by federal, state
and local authorities relating to the quality of the environment. These laws
and regulations affect, among other things, the siting and operation of electric
generating and transmission facilities and can require the installation of
expensive air and water pollution control equipment. These regulations have had
an impact on the Company's operations in the past, however their impact on
future operations, capital costs and construction schedules is not expected to
be significant since all of the Company's non-nuclear generating assets were
sold in 1998.
New Accounting Principles
- -------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts possibly including
fixed-price fuel supply and power contracts) be recorded on the Consolidated
Balance Sheets as either an asset or liability measured at its fair value, SFAS
133, as amended by SFAS 137, "Accounting for Derivative
-13-
<PAGE>
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No 133", is effective for fiscal years beginning after June 15, 2000
(January 1, 2001 for calendar year companies). Initial application shall be as
of the beginning of an entity's fiscal quarter.
The Company will adopt SFAS 133 as of January 1, 2001. The impact of adoption
cannot be currently estimated and will be dependent upon the fair value, nature
and purpose of the derivative instruments held, if any, as of January 1, 2001.
Safe Harbor Cautionary Statement
- --------------------------------
Management occasionally makes forward-looking statements such as forecasts and
projections of expected future performance or statements of its plans and
objectives. These forward-looking statements may be contained in filings with
the Securities and Exchange Commission (SEC), press releases and oral
statements. Actual results could potentially differ materially from these
statements. Therefore, no assurances can be given that the outcomes stated in
such forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about
operating results, year 2000 and environmental and legal issues.
The impacts of continued cost control procedures on operating results could
differ from current expectations. The effects of changes in economic
conditions, tax rates, interest rates, technology and the prices and
availability of operating supplies could materially affect the projected
operating results.
The timing and total costs related to the year 2000 plan could differ from
current expectations. Factors that may cause such differences include the
ability to locate and correct all relevant computer codes and the availability
of personnel trained in this area. In addition, management cannot predict the
nature or impact on operations of third party noncompliance.
The impacts of various environmental and legal issues could differ from current
expectations. New regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than expected. The
effects of changes in specific hazardous waste site conditions and cleanup
technology could affect the estimated cleanup liabilities. The impacts of
changes in available information and circumstances regarding legal issues could
affect estimated litigation costs.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
- -------- ----------------------------------------------------------
Although the Company has material commodity purchase contracts and financial
instruments (debt), these instruments are not subject to market risk. The
Company has a standard offer service mechanism which allows for the recovery of
fuel costs from customers. The fuel adjustment mechanism allows the Company to
pass all costs related to the purchase of commodities to the customer, thereby
insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's prudently
incurred debt obligations realized by the Company would be borne by customers
through future rates.
Item 8. Financial Statements and Supplementary Data
- ------- -------------------------------------------
The Company's financial statements required by this item are filed herewith on
pages 23 through 43 of this report.
Item 9. Changes in and Disagreements With Accountants on Accounting
- ------- -----------------------------------------------------------
and Financial Disclosure
------------------------
None.
-14-
<PAGE>
Item 8. Financial Statements and Supplementary Data
- ------- -------------------------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To the Board of Directors of Commonwealth Electric Company:
In our opinion, the financial statements listed in the index appearing under
Item 14(a)(1) on page 34, present fairly, in all material respects, the
financial position of Commonwealth Electric Company at December 31, 1999, and
the results of its operations and its cash flows for the period from January 1,
1999 through August 24, 1999 and for the period from August 25, 1999 through
December 31, 1999, in conformity with accounting principles generally accepted
in the United States. In addition, in our opinion, the financial statement
schedules listed in the index appearing under Item 14(a)(2) on page 34, present
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedules are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedules based on our audit. We
conducted our audit of these statements in accordance with auditing standards
generally accepted in the United States, which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
January 26, 2000
-15-
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Commonwealth Electric Company:
We have audited the accompanying balance sheets of COMMONWEALTH ELECTRIC COMPANY
(a Massachusetts corporation and wholly-owned subsidiary of Commonwealth Energy
System) as of December 31, 1998, and the related statements of income, retained
earnings and cash flows for each of the two years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our 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 Commonwealth Electric Company
as of December 31, 1998, and the results of its operations and its cash flows
for each of the two years in the period ended December 31, 1998 in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 18, 1999
-16-
<PAGE>
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
-------------------------------------------
PART II.
--------
ITEM 8
FINANCIAL STATEMENTS
Report of Independent Public Accountants.......................... 15
Balance Sheets at December 31, 1999 and 1998...................... 18
Statements of Income for the 1999 periods August 25 to
December 31 and January 1 to August 24 and for the Years Ended
December 31, 1998 and 1997........................................ 20
Statements of Retained Earnings for the Years Ended
December 31, 1999, 1998 and 1997.................................. 21
Statements of Cash Flows for the 1999 periods August 25 to
December 31 and January 1 to August 24 and for the Years Ended
December 31, 1998 and 1997........................................ 22
Notes to Financial Statements..................................... 23
PART IV.
--------
SCHEDULES
Valuation and Qualifying Accounts - Years Ended December 31, 1999, 1998 and 1997
SCHEDULES OMITTED
All other schedules are not submitted because they are not applicable or not
required or because the required information is included in the financial
statements or notes thereto.
Financial statements of 50% or less owned companies accounted for by the equity
method have been omitted because they do not, considered individually,
constitute a significant subsidiary.
-17-
<PAGE>
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
BALANCE SHEETS
--------------
DECEMBER 31, 1999 AND 1998
--------------------------
ASSETS
------
<TABLE>
<CAPTION>
1999 1998
---------- ----------
(Dollars in thousands)
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT, at original cost $581,167 $566,477
Less - Accumulated depreciation 195,139 182,345
-------- --------
386,028 384,132
Add - Construction work in progress 4,975 2,544
-------- --------
391,003 386,676
-------- --------
Goodwill 233,422 -
-------- --------
INVESTMENTS
Equity in nuclear electric power company 404 485
Other 14 14
-------- --------
418 499
-------- --------
LONG-TERM RECEIVABLE - AFFILIATE 114,774 307,618
-------- --------
CURRENT ASSETS
Cash 3,607 3,584
Accounts receivable -
Affiliates 5,229 1,483
Customers, less allowances of $1,571 in 1999
and $1,069 in 1998 35,972 40,114
Unbilled revenues 6,221 4,646
Inventories, at average cost 3,046 2,669
Prepaid taxes -
Property 3,436 3,153
Income 8,421 -
Other 1,212 1,192
-------- --------
67,144 56,841
-------- --------
DEFERRED CHARGES
Regulatory assets 58,025 67,964
Purchased power costs 58,956 33,931
Other 3,903 3,068
-------- --------
120,884 104,963
-------- --------
$927,645 $856,597
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-18-
<PAGE>
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
BALANCE SHEETS
--------------
DECEMBER 31, 1999 AND 1998
--------------------------
CAPITALIZATION AND LIABILITIES
------------------------------
<TABLE>
<CAPTION>
1999 1998
---------- ----------
(Dollars in thousands)
<S> <C> <C>
CAPITALIZATION
Common Equity -
Common stock, $25 par value -
Authorized and outstanding -
2,043,972 shares wholly-owned by
NSTAR $ 51,099 $ 51,099
Amounts paid in excess of par value 350,323 97,112
Retained earnings (929) 36,984
-------- --------
400,493 185,195
Long-term debt, less current
sinking fund requirements and
debt discount 142,609 143,651
-------- --------
543,102 328,846
-------- --------
CURRENT LIABILITIES
Interim Financing -
Notes payable to banks 20,600 -
Advances from affiliates 6,455 40,350
-------- --------
27,055 40,350
-------- --------
Other Current Liabilities -
Current sinking fund requirements 1,053 3,553
Accounts payable -
Affiliates 9,645 14,159
Other 34,064 26,370
Accrued taxes -
Local property and other 3,995 3,343
Income - 35,945
Accrued interest 3,959 3,751
Other 17,940 20,416
-------- --------
70,656 107,537
-------- --------
97,711 147,887
-------- --------
DEFERRED CREDITS
Regulatory liabilities 144,145 297,693
Accumulated deferred income taxes 96,211 51,297
Unamortized investment tax credits 5,814 6,224
Other 40,662 24,650
-------- --------
286,832 379,864
-------- --------
COMMITMENTS AND CONTINGENCIES
$927,645 $856,597
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-19-
<PAGE>
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
STATEMENTS OF INCOME
--------------------
<TABLE>
<CAPTION>
For the 1999 Periods
--------------------
August 25 January 1
to to Years Ended
December 31 August 24 December 31,
-------------- ----------
(Successor) (Predecessor) 1998 1997
------------ ---------
(Dollars in thousands)
<S> <C> <C> <C> <C>
ELECTRIC OPERATING REVENUES $139,921 $286,090 $424,999 $471,449
-------- -------- -------- --------
OPERATING EXPENSES
Electricity purchased for
resale and fuel 79,884 164,091 263,087 304,782
Transmission 3,847 6,083 6,927 5,266
Other operation 31,301 64,545 70,195 72,917
Maintenance 8,285 8,231 11,458 12,871
Depreciation and amortization 8,863 14,095 24,024 23,961
Taxes -
Income (394) 3,946 9,156 10,398
Local property 2,207 4,439 6,413 5,980
Payroll and other 678 1,878 2,391 2,762
-------- -------- -------- --------
134,671 267,308 393,651 438,937
-------- -------- -------- --------
OPERATING INCOME 5,250 18,782 31,348 32,512
OTHER INCOME (EXPENSE), NET 613 1,642 64 (206)
-------- -------- -------- --------
INCOME BEFORE INTEREST CHARGES 5,863 20,424 31,412 32,306
-------- -------- -------- --------
INTEREST CHARGES
Long-term debt 4,281 8,602 13,253 13,586
Other interest charges 2,511 5,115 3,050 1,797
-------- -------- -------- --------
6,792 13,717 16,303 15,383
-------- -------- -------- --------
NET INCOME (Loss) $ (929) $ 6,707 $ 15,109 $ 16,923
======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-20-
<PAGE>
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
STATEMENTS OF RETAINED EARNINGS
-------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
----------------------------------------------------
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
(Dollars in thousands)
<S> <C> <C> <C>
Balance at beginning of year $ 36,984 $ 31,993 $ 27,334
Add (Deduct) - 15,109 16,923
Net income -
January 1, 1999 to August 24, 1999 6,707 (10,118) (12,264)
Dividends on common stock -
January 1, 1999 to August 24, 1999 (9,913) - -
-------- -------- --------
33,778 36,984 31,993
Reclassification to additional
Paid-in capital at August 24, 1999 (33,778) - -
Add
Net (Loss) August 25, 1999 to
December 31, 1999 (929) - -
-------- -------- --------
Balance at end of year $ (929) $ 36,984 $ 31,993
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-21-
<PAGE>
<TABLE>
<CAPTION>
COMMONWEALTH ELECTRIC COMPANY
---------------------------------------
STATEMENTS OF CASH FLOWS
---------------------------------------
For the 1999 Periods
------------------------
August 25 January 1
to to Years Ended
December 31 August 24 December 31,
----------- ---------
(Successor) (Predecessor) 1998 1997
-------- --------
(Dollars in thousands)
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES
Net (loss) income $ (929) $ 6,707 $ 15,109 $ 16,923
Effects of noncash items -
Depreciation and
amortization 8,864 14,096 24,024 23,961
Deferred income taxes, net (596) 4,020 14,285 3,720
Investment tax credits (122) (288) (472) (430)
Change in working capital -
Accounts receivable and
unbilled revenues 4,746 (5,925) 8,421 (4,067)
Income taxes, net (5,891) (38,475) (24,309) 3,652
Local property and other
taxes, net 470 (101) (66) 255
Accounts payable and
other (4,105) 2,120 6,097 6,968
Reduction in
generation-related costs - 44,255 - -
Power contract buyouts - (107,227) - -
EIS proceeds 28,040 164,804 - -
Transition costs deferral (4,812) (14,783) (35,254) -
Fuel charge stabilization
deferral, net - - 1,465 (5,543)
All other operating items (35,039) 524 10,182 (8,240)
-------- --------- -------- --------
Net cash (used in) provided
by operating activities (9,374) 69,727 19,482 37,199
-------- --------- -------- --------
INVESTING ACTIVITIES
Proceeds from sale of
generating assets - - 709 -
Additions to property,
plant and equipment
(exclusive of AFUDC) (6,894) (14,102) (24,416) (22,255)
Allowance for borrowed
funds used
during construction (45) (118) (163) (145)
-------- --------- -------- --------
Net cash used for
investing activities (6,939) (14,220) (23,870) (22,400)
-------- --------- -------- --------
FINANCING ACTIVITIES
Payment of dividends - (9,914) (10,118) (12,264)
Return of capital (14,920) - - -
Proceeds from (payment of)
short-term borrowings 20,600 - (14,900) (100)
Advances from (payment
to) affiliates 10,905 (44,800) 35,035 2,245
Retirement of long-term debt
through sinking funds 3 (1,045) (3,541) (3,542)
-------- --------- -------- --------
Net cash provided by (used
for) financing activities 16,588 (55,759) 6,476 (13,661)
-------- --------- -------- --------
Net increase (decrease) in
cash 275 (252) 2,088 1,138
Cash at beginning of period 3,332 3,584 1,496 358
-------- --------- -------- --------
Cash at end of period $ 3,607 $ 3,332 $ 3,584 $ 1,496
======== ========= ======== ========
SUPPLEMENTAL DISCLOSURES
OF CASH FLOW INFORMATION
Cash paid (refunded)
during the periods for:
Interest (net of
capitalized amounts) $ 4,428 $ 9,733 $ 15,168 $ 14,948
Income taxes $ 6,300 $ (2,469) $ 1,680 $ 5,019
======= ========= ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-22-
<PAGE>
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(1) General Information
-------------------
Commonwealth Electric Company (the Company) is a wholly-owned subsidiary of
NSTAR. NSTAR is the new holding company that was formed, effective August 25,
1999, after receipt of all necessary approvals and upon completion of a merger
transaction between Commonwealth Energy System (COM/Energy, formerly the parent
of the Company) and BEC Energy formerly the parent company of Boston Edison
Company). The merger creates and energy delivery company that includes the
Company, serving approximately 1.3 million customers located in Massachusetts
including more than one million electric customers in 81 communities and 240,000
gas customers in 51 communities. NSTAR is an exempt public utility holding
company under the provisions of the Public Utility Holding Company Act of 1935
and, in addition to its investment in the Company, has interests in various
other utility and nonregulated companies. The Company's operations have been
involved in the production, distribution and sale of electricity to 327,000
customers (including 45,500 seasonal) in 40 communities located in southeastern
Massachusetts, including Cape Cod and the island of Martha's Vineyard, having an
approximate year-round population of 549,000 and a large influx of summer
residents.
The Company has 629 regular employees including 470 (74.7%) represented by three
collective bargaining units covered by separate contracts with expiration dates
of October 2001 , September 2002 and April 2003. Employee relations have
generally been satisfactory.
In response to the significant changes that have taken place in the utility
industry, the Company sold all of its non-nuclear generating assets in 1998 to
focus on the transmission and distribution of energy and related services.
(2) Significant Accounting Policies
-------------------------------
(a) Principles of Accounting
------------------------
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 prior year amounts are reclassified from time to time to conform with
the presentation used in the current year's financial statements.
(b) Merger and Financial Statement Presentation
-------------------------------------------
On August 25, 1999 BEC Energy (BEC) and COM/Energy merged to form NSTAR as an
exempt public utility holding company. NSTAR's utility subsidiaries include the
Company. The merger was accounted for by NSTAR as an acquisition by BEC of
COM/Energy and all of its subsidiaries including the Company come under the
purchase method of accounting.
In the accompanying statements, the Company prior to the merger is labeled as
the "Predecessor" and after the merger as the "Successor."
As a result of this merger, the fourth quarter dividend amounting to
approximately $15 million was reflected as a return of capital and, as a
result, reduced paid-in capital. As of August 25, 1999, approximately $34
million of retained earnings was reclassified as additional paid-in capital.
The merger was accounted for by BEC as an acquisition of COM/Energy under the
purchase method of accounting. The total goodwill associated with the
acquisition was approximately $486 million on a consolidated basis, while the
original estimate of costs to achieve the merger was $111 million on a
consolidated basis. Costs to achieve which have been allocated to the Company
were approximately $18.6 million as of December 31, 1999, and are included as
merger costs in regulatory assets on the Company's balance sheet (Note 2(c)).
Costs to achieve will be recovered over the amortization period of 10 years. The
amount of goodwill allocated to the Company as of the merger date was
approximately $235 million, and is being amortized over a period of 40 years. A
portion of the goodwill amortization will be allocated to the Boston Edison
Company (an NSTAR subsidiary) on an annual basis in accordance with the MDTE
rate order approving the merger.
(c) Regulatory Assets and Liabilities
---------------------------------
The Company is regulated as to rates, accounting and other matters by various
authorities, including the Federal Energy Regulatory Commission (FERC) and the
Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, the Company accounts for the economic
effects of regulation in accordance with the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
-23-
<PAGE>
of Certain Types of Regulation." The Company has established various regulatory
assets in cases where the DTE and/or the FERC have permitted or are expected to
permit recovery of specific costs over time. Similarly, the regulatory
liabilities established by the Company are required to be refunded to customers
over time. In the event the criteria for applying SFAS No. 71 are no longer
met, the accounting impact would be an extraordinary, non-cash charge to
operations of an amount that could be material. Criteria that give rise to the
discontinuance of SFAS No. 71 include: 1) increasing competition that restricts
the Company's ability to establish prices to recover specific costs, and 2) a
significant change in the current manner in which rates are set by regulators
from cost based regulation to another form of regulation. These criteria are
reviewed on a regular basis to ensure the continuing application of SFAS No. 71
is appropriate. Based on the current evaluation of the various factors and
conditions that are expected to impact future cost recovery, the Company
believes that its regulatory assets, including those related to generation, are
probable of future recovery.
The principal regulatory assets included in deferred charges were as follows:
<TABLE>
<CAPTION>
1999 1998
----------- ----------
(Dollars in thousands)
<S> <C> <C>
Merger costs $ 53,756 -
Transition costs 3,137 4,691
Power contract buy-out - 15,717
Fuel charge stabilization 33 26,682
Postretirement benefit costs 2,694 12,269
Yankee Atomic unrecovered plant
and decommissioning costs 830 2,042
Canal 1/Canal 2 EPA sales proceeds (2,995) -
Pilgrim nuclear plant litigation costs (251) 5,417
Other 821 1,146
-------- --------
$ 58,025 $ 67,964
======== ========
The regulatory liabilities, reflected in the accompanying Balance Sheets
were as follows:
1999 1998
-------- --------
(Dollars in thousands)
Regulatory liability related to
sale of generating assets $138,540 $293,186
Other 5,605 4,507
-------- --------
$144,145 $297,693
======== ========
</TABLE>
The regulatory liability of $293.2 million was established pursuant to the
Company's divestiture filing that was approved by the MDTE in which the
-24-
<PAGE>
Company agreed to use its share of the net proceeds from affiliate Canal
Electric Company's (Canal Electric) sale of generation assets and the sale of
its own generating assets to reduce transition costs that are billed to its
retail electric customers over the next several years as a result of electric
industry restructuring. COM/Energy established Energy Investment Services, Inc.
as the vehicle to invest the net proceeds from the sale of Canal Electric's
generating assets. These proceeds are invested in a conservative portfolio
of securities that is designed to maintain principal and earn a reasonable
return. Both the principal amount and income earned will be used to reduce the
transition costs that would otherwise be billed to customers of the Company and
Cambridge Electric. The Company's share of the net proceeds from the sale of
Canal Electric's generating assets has been classified as a long-term
receivable-affiliate on the accompanying Balance Sheets.
The Company's regulatory assets, including the costs associated with an existing
power contract with the Yankee Atomic nuclear power plant that was shut down
permanently (see Note 3(d)), and all of its regulatory liabilities are reflected
in rates charged to customers. Regulatory assets are to be recovered over the
next 11 years pursuant to the legislation discussed below.
In November 1997, the Commonwealth of Massachusetts enacted a comprehensive
Electric Utility Restructuring Act. On November 19, 1997, the Company, together
with affiliates Cambridge Electric Light Company (Cambridge Electric) and Canal
Electric, filed a restructuring plan with the MDTE. The plan, approved by the
MDTE on February 27, 1998, provides that the Company and Cambridge Electric,
beginning March 1, 1998, initiate a ten percent rate reduction for all customer
classes and allow customers to choose their energy supplier. As part of the
plan, the MDTE authorized the recovery of certain strandable costs and provides
that certain future costs may be deferred to achieve or maintain the rate
reductions that the restructuring bill mandates. The legislation gives the MDTE
the authority to determine the amount of strandable costs that will be eligible
for recovery. Costs that will qualify as strandable costs and be eligible for
recovery include, but are not limited to, certain above market costs associated
with generating facilities, costs associated with long-term commitments to
purchase power at above market prices from independent power producers and
regulatory assets and associated liabilities related to the generation portion
of the electric business.
(c) Transactions with Affiliates
----------------------------
Transactions between the Company and other NSTAR companies include purchases and
sales of electricity, including purchases from Canal Electric, an affiliated
wholesale electric generating company. Other Canal transactions include costs
relating to the abandonment of Seabrook 2 (in 1997) and the recovery of a
portion of Seabrook 1 pre-commercial operation costs. In addition, payments for
management, accounting, data processing and other services are made to an
affiliate, COM/Energy Services Company. Transactions with other COM/Energy
companies are subject to review by the MDTE.
-25-
<PAGE>
The Company's operating expenses include the following major intercompany
transactions for the periods indicated:
<TABLE>
<CAPTION>
Purchased Power
Purchased Power and Transmission
Purchased Power and Transmission From Canal
Period Canal Units Seabrook 1 as Agent
- ------------------------------- --------------- ---------------- ----------------
(Dollars in thousands)
<S> <C> <C> <C>
January 1 - August 24, 1999 $ - $21,794 $1,670
August 25 - December 31, 1999 - 12,015 799
1998 56,269 29,403 2,605
1997 61,087 31,417 6,524
</TABLE>
The costs for the Canal and Seabrook 1 units are included in the long-term
obligation table listed in Note 3(b). The Company sold electricity to other
affiliates, primarily station service for Canal, totaling $0, $1,026,000, and
$1,290,000 in 1999, 1998 and 1997, respectively.
(d) Operating Revenues
------------------
Customers are billed for their use of electricity on a cycle basis throughout
the month. To reflect revenues in the proper period, the estimated amount of
unbilled sales revenue is recorded each month.
The Company is generally permitted to bill customers for costs associated with
purchased power and transmission, fuel used in electric production and
conservation and load management (C&LM) costs. The amount of such costs
incurred by the Company but not yet reflected in customers' bills is recorded as
unbilled revenues.
(e) Depreciation
------------
Depreciation is provided using the straight-line method at rates intended to
amortize the original cost and the estimated cost of removal less salvage of
properties over their estimated economic lives. The average composite
depreciation rates were 3.53% in 1999, 3.33% in 1998 and 3.32% in 1997.
(f) Maintenance
-----------
Expenditures for repairs of property and replacement and renewal of items
determined to be less than units of property are charged to maintenance expense.
Additions, replacements and renewals of property considered to be units of
property are charged to the appropriate plant accounts. Upon retirement,
accumulated depreciation is charged with the original cost of property units and
the cost of removal less salvage.
(g) Allowance for Funds Used During Construction
--------------------------------------------
Under applicable rate-making practices, the Company is permitted to include an
allowance for funds used during construction (AFUDC) as an element of its
depreciable property costs. This allowance is based on the amount of
construction work in progress that is not included in the rate base on which the
Company earns a return. An amount equal to the AFUDC capitalized in the current
period is reflected in other interest charges in the Company's Statements of
Income and amounted to $162,000, $163,000 and $145,000 in 1999, 1998 and 1997,
respectively.
-26-
<PAGE>
While AFUDC does not provide funds currently, these amounts are recoverable in
revenues over the service life of the constructed property. The amount of AFUDC
recorded was at a weighted average rate of 5.25% in 1999, 5.75% in 1998 and
6.25% in 1997.
(3) Commitments and Contingencies
-----------------------------
(a) Financing and Construction Programs
-----------------------------------
The Company is engaged in a continuous construction program presently estimated
at $139.8 million for the five-year period 2000 through 2004. Of that amount,
$32 million is estimated for 2000. The program is subject to periodic review
and revision because of factors such as changes in business conditions, rates of
customer growth, effects of inflation, maintenance of reliable and safe service,
equipment delivery schedules, licensing delays, availability and cost of capital
and environmental factors. The Company expects to finance these expenditures on
an interim basis with internally generated funds and short-term borrowings that
are ultimately expected to be repaid with the proceeds from sales of long-term
debt and equity securities.
(b) Long-Term Contracts for the Purchase of Electricty
--------------------------------------------------
The Company has long-term contracts to purchase capacity from various generating
facilities. Generally, these contracts are for fixed periods and require
payment of a demand charge for the capacity entitlement and an energy charge to
cover the cost of fuel. In addition, the Company pays its share of
decommissioning expenses under its nuclear contracts.
NSTAR on behalf of the Company, entered into a six-month agreement effective
January 1, 2000 to transfer all of the unit output entitlements in long-term
power purchase contracts to Select Energy (Select), a subsidiary of Northeast
Utilities, In return, Select will provide full energy service requirements,
including NEPOOL capability responsibilities, at FERC approved tariff rates
through June 30 2000.
Information relating to the contracts as of December 31, 1999 is as follows:
<TABLE>
<CAPTION>
proportionate share (in thousands)
-----------------------------------------------
Units of
Range of Capacity Capacity Charge
Contract Purchased 1999 Obligation 1999
Fuel Type of Expiration ---------------------- Capacity Through Contract Total
Generating Unit Dates % MW Cost Expiration Date Cost
- ----------------- ------------------------------ ---------- ---------- ---------------- --------------- --------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas 2008-2017 11.1-100 28.8-68.2 $ 64,070 $ 420,086 $109,654
Nuclear 2004-2026 2.9-11 32.8-74.1 50,983 511,680 62,974
Waste-to-energy 2015 100 76.9 - - 45,880
Hydro 2014-2023 100 1.3-20 - 10,505
Oil 2002 20 112.9 7,807 21,529 22,182
- ----------------- ------------------------------ ---------- ---------- ---------------- --------------- --------
Total $122,860 $ 953,295 $251,195
=========================================================================================== ============== ========
</TABLE>
Energy is paid for based on a price per kWh actually received. In 1999, the
Company's did not pay a proportionate share of capital and fixed operating costs
for 229.4 MW purchased.
The Company's total fixed and variable costs associated with these contracts in
1999, 1998 and 1997 were approximately $251 million, $267 million and $288
million, respectively. The Company's capacity charge obligation under these
contracts for the years after 1999 are as follows:
-27-
<PAGE>
Capacity Charge
(in thousands) Obligation
- --------------------------------------------------------
2000 $ 80,182
2001 56,722
2002 56,673
2003 51,095
2004 50,963
Years thereafter 657,660
- --------------------------------------------------------
Total $ 953,295
========================================================
(c) Pilgrim Power Contract
----------------------
The Company had an 11% (73.6 megawatts) contract entitlement in the output of
the Pilgrim nuclear power plant, located in Plymouth, MA, which was sold by
Boston Edison Company (Boston Edison) on July 13, 1999 to Entergy Nuclear
Generating Company (Entergy). On April 29, 1999, the Nuclear Regulatory
Commission issued an order approving the transfer of the operating license for
the plant from Boston Edison to Entergy. In conjunction with this sale, the
Company reached an agreement with Boston Edison to buy out of this
life-of-the-unit contract, terminating the Company's rights and obligations
under the contract regarding the power output of the plant. Pursuant to the
buy-out agreement, the Company paid approximately $105 million in July 1999 to
terminate this contract with Boston Edison. The buy-out was paid with funds held
by affiliate EIS (see Note 2(b)) that were provided from the Company's share of
the net proceeds from Canal Electric's sale of its generating assets. The DTE
approved the buy-out transaction as a mitigation measure and approved inclusion
of the buy-out payment as a transition cost for purposes of cost recovery by the
Company. In a transaction related to the sale of the Pilgrim plant, the Company
will buy power generated by the Pilgrim plant from Entergy on a declining basis
through 2004.
(d) Environmental Matters
---------------------
The Company is subject to laws and regulations administered by federal, state
and local authorities relating to the quality of the environment. These laws
and regulations affect, among other things, the siting and operation of electric
generating and transmission facilities and can require the installation of
expensive air and water pollution control equipment. These regulations have had
an impact on the Company's operations in the past and will continue to have an
impact on future operations, capital costs and construc- tion schedules of major
transmission and distribution facilities.
(4) Income Taxes
------------
For financial reporting purposes, the Company provides federal and state income
taxes on a separate-return basis. However, for federal income tax purposes, the
Company's taxable income and deductions are included in the consolidated income
tax return of NSTAR (COM/Energy prior to the merger), the Parent and it makes
tax payments or receives refunds on the basis of its tax attributes in the tax
return in accordance with applicable regulations.
Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS 109). SFAS
109 requires the recognition of deferred tax assets and liabilities for the
future tax effects of temporary differences between the carrying amounts and the
tax basis of assets and liabilities.
Accumulated deferred income taxes consisted of the following:
<TABLE>
<CAPTION>
1999 1998
----------- -----------
(Dollars in thousands)
<S> <C> <C>
Liabilities
Property-related $ 44,874 $ 55,342
Transition costs 24,374 14,778
Fuel charge stabilization 11,242 11,300
Power contract buy-out 5,401 6,135
All other 14,458 9,447
-------- --------
100,349 97,002
-------- --------
Assets
Deferred tax asset -- 114,340
Investment tax credit 3,752 4,046
All other 386 9,454
-------- --------
4,138 127,840
-------- --------
Accumulated deferred
tax asset, net $ 96,211 $(30,838)
======== ========
</TABLE>
-28-
<PAGE>
The effective income tax rates reflected in the accompanying financial
statements and the reasons for their differences from the statutory federal
income tax rate were as follows:
<TABLE>
<CAPTION>
For the 1999 Periods
--------------------
August 25 January 1
to to
December 31, August 24, 1998 1997
-------------------------- -------- --------
(Successor) (Predecessor)
(Dollars in thousands)
<S> <C> <C> <C> <C>
Federal statutory rate 35% 35% 35% 35%
===== ====== ====== =======
Federal income tax expense at
statutory levels (463) 3,728 $8,493 $ 9,562
Increase (Decrease) from statutory levels:
Merger cost 394 - - -
State tax net of federal tax benefit (27) 459 1,046 1,171
Tax versus book depreciation - 99 198 105
Amortization of investment tax credits (122) (288) (472) (430)
Reversals of capitalized expenses 57 (53) (76) (63)
Other (117) 1 (33) 53
----- ------ ------ -------
$(394) $3,946 $9,156 $10,398
===== ====== ====== =======
Effective federal income tax rate 30% 37% 38% 38%
===== ====== ====== =======
</TABLE>
The following is a summary of the Company's provisions for income taxes for the
years ended December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
For the 1999 Periods
---------------------
August 25 January 1
to to
December 31, August 24, 1998 1997
------------------------- --------- --------
(Successor) (Predecessor)
(Dollars in thousands)
<S> <C> <C> <C> <C>
Federal
Current $ 266 $ 175 $(3,824) $ 5,852
Deferred (496) 3,352 11,843 3,174
Investment tax credits, net (122) (288) (472) (430)
----- ------ ------- -------
(352) 3,239 7,547 8,596
----- ------ ------- -------
State
Current 58 39 (833) 1,254
Deferred (100) 668 2,442 548
----- ------ ------- -------
(42) 707 1,609 1,802
----- ------ ------- -------
$(394) $3,946 $ 9,156 $10,398
===== ====== ======= =======
</TABLE>
The significant change in the current and deferred provisions for income taxes
in 1998 reflects the current tax related to the sale of the company's non-
nuclear generating assets and the related deferred tax benefit.
(5) Employee Benefit Plans
----------------------
Effective December 31, 1999, the pension and other postretirment benefit plans
of BEC and COM/Energy were combined under NSTAR.
-29-
<PAGE>
(a) Pension
-------
NSTAR has a defined benefit funded retirement plan with certain contribution
features that covers substantially all employees, including employees of the
Company. NSTAR also maintains an unfunded supplemental retirement plan for
certain management employees. Effective January 1, 2000, the defined benefit
plan was amended to provide management employees lump sum benefits under a final
average pay pension equity formula. Prior to January 1, 2000 these pension
benefits were provide under a traditional final average pay formula. This
amendment is reflected in the December 31, 1999 benefit obligation.
The periodic costs allocated to the Company was $2,639,000, $3,324,000 and
$3,702,000 in 1999, 1998 and 1997, respectively. The accrued pension cost in
the Company's statement of financial position was $10,470,000 and $7,427,000 in
1999 and 1998, respectively.
As a result of the merger-related separation packages, amounts recognized for
curtailment and special termination benefit costs were $4,928,000 and
$3,605,000, respectively, for 1999. These amounts are recoverable as part of
the approved rate plans of the retail utility subsidiaries of NSTAR.
(b) Other Postretirement Benefits
-----------------------------
Certain employees are eligible for postretirement benefits if they meet specific
requirements. These benefits could include health and life insurance coverage
and reimbursement of Medicare Part B premiums. Under certain circumstances,
eligible employees are required to make contributions for postretirement
benefits.
To fund postretirement benefits, the Company makes contributions to various
voluntary employees; beneficiary association (VEBA) trusts that were established
pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The
Company also makes contributions to a subaccount of the COM/Energy pension plan
and its successor pursuant to section 401(h) of the Code to fund a portion of
its postretirement benefit obligation.
The funded status of the Plan cannot be presented separately for the Company
since the Company participates in the Plan trusts and subaccount with other
subsidiaries of NSTAR. Plan assets are available to provide benefits for all
Plan participants who are former employees of the Company and of other
subsidiaries of NSTAR.
The net periodic postretirement benefit cost allocated to the Company was
$4,883,000, $5,418,000 and $5,654,000 in 1999, 1998 and 1997, respectively. The
accrued benefit cost in the Company's statement of financial position was
$32,157,000 and $0 at December 31, 1999 and 1998, respectively.
-30-
<PAGE>
(c) Savings Plan
------------
The Company has an Employees Savings Plan that provides for Company
contributions to eligible employees. The total Company contribution was
$1,441,000 in 1999, $1,435,000 in 1998 and $1,672,000 in 1997.
(6) Long-Term Debt and Interim Financing
------------------------------------
(a) Long-Term Debt Maturities and Retirements
-----------------------------------------
Long-term debt outstanding, exclusive of current maturities, current sinking
fund requirements and related premiums, is as follows:
<TABLE>
<CAPTION>
Original Balance December 31,
--------------------
Issue 1999 1998
-------- --------- ---------
(Dollars in thousands)
<S> <C> <C> <C>
15-Year Term Loan, 9.30%, due 2002 $ 30,000 $ 30,000 $ 30,000
25-Year Term Loan, 9.37%, due 2012 20,000 12,632 13,684
10-Year Notes, 7.43%, due 2003 15,000 15,000 15,000
15-Year Notes, 9.50%, due 2004 15,000 5,000 5,000
15-Year Notes, 7.70%, due 2008 10,000 10,000 10,000
18-Year Notes, 9.55%, due 2007 10,000 10,000 10,000
20-Year Notes, 7.98%, due 2013 25,000 25,000 25,000
25-Year Notes, 9.53%, due 2014 10,000 10,000 10,000
30-Year Notes, 9.60%, due 2019 10,000 10,000 10,000
30-Year Notes, 8.47%, due 2023 15,000 15,000 15,000
-------- -------- --------
$160,000 $142,632 $143,684
======== ======== ========
</TABLE>
The Company, under favorable conditions, may purchase its outstanding notes
in advance; however, an early payment premium may be incurred. Certain of these
agreements require the Company to make periodic sinking fund payments for
retirement of outstanding long-term debt.
The required sinking fund payments for the five years subsequent to December
31, 1998 are as follows:
<TABLE>
<CAPTION>
Sinking Fund Maturing
Year Payments Debt Issues Total
- ---------------- ------------ ----------- -------
(Dollars in thousands)
<S> <C> <C> <C>
2000 $1,053 $ - $ 1,053
2001 3,481 - 3,481
2002 3,481 30,000 33,481
2003 3,481 15,000 18,481
2004 3,481 15,000 18,481
</TABLE>
(b) Notes Payable to Banks
----------------------
The Company and other NSTAR companies maintain both committed and uncommitted
lines of credit for the short-term financing of their construction programs and
other corporate purposes. As of December 31, 1999, NSTAR had
-31-
<PAGE>
$115 million of committed lines of credit that will expire at varying intervals
in 2000. These lines are normally renewed upon expiration and require annual
fees of up to .1875% of the individual line. At December 31, 1998, the
uncommitted lines of credit totaled $10 million. Interest rates on the
outstanding borrowings generally are at an adjusted money market rate and
averaged 5.8% in 1999 and 1998, respectively. The Company had notes payable to
banks of $20,600,000 at December 31, 1999 and no notes outstanding at December
31, 1998.
(c) Advances from Affiliates
------------------------
The Company is a member of the COM/Energy Money Pool (the Pool), an
arrangement among affiliates whereby short-term cash surpluses are used to help
meet the short-term borrowing needs of the utility subsidiaries. In general,
lenders to the Pool receive a higher rate of return than they otherwise would on
such investments, while borrowers pay a lower interest rate than those available
from banks. Interest rates on the outstanding borrowings are based on the
monthly average rate the Company would otherwise have to pay banks, less one-
half the difference between that rate and the monthly average U.S. Treasury Bill
weekly auction rate. The borrowings are for a period of less than one year and
are payable upon demand. Rates on these borrowings averaged 5.1% and 5.3% in
1999 and 1998, respectively. Notes payable to the Pool totaled $6,455,000 and
$40,350,000 at December 31, 1999 and 1998, respectively.
The Company had no notes payable to the Parent at December 31, 1999 or December
31, 1998. However, this source of financing may be utilized by the Company and
notes are written for a term of up to 11 months and 29 days. Interest is at the
prime rate and is adjusted for changes in that rate during the term of the
notes. The rate averaged 8% and 8.3% in 1999 and 1998, respectively.
(d) Disclosures About Fair Value of Financial Instruments
-----------------------------------------------------
The fair value of certain financial instruments included in the accompanying
Balance Sheets as of December 31, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
1999 1998
-------- --------
(Dollars in thousands)
<S> <C> <C> <C> <C>
Carrying Fair Carrying Fair
Value Value Value Value
-------- -------- -------- --------
Long-term debt $143,663 $151,460 $147,204 $171,667
</TABLE>
The carrying amount of cash, notes payable to banks and advances to/from
affiliates approximates the fair value because of the short maturity of these
financial instruments.
The estimated fair value of long-term debt is based on quoted market prices of
the same or similar issues or on the current rates offered for debt with the
same remaining maturity. The fair values shown above do not purport to
represent the amounts at which those obligations would be settled.
-32-
<PAGE>
(7) Dividend Restriction
--------------------
At December 31, 1999, there was no common equity restricted against the
payment of cash dividends pursuant to the Company's term loans and note
agreements securing long-term debt.
(8) Lease Obligations
-----------------
The Company leases equipment and office space under arrangements that are
classified as operating leases. These lease agreements are for terms of one
year or longer. Leases currently in effect contain no provisions that prohibit
the Company from entering into future lease agreements or obligations.
Future minimum lease payments, by period and in the aggregate, of non-cancelable
operating leases consisted of the following at December 31, 1998:
<TABLE>
<CAPTION>
Operating Leases
----------------
(Dollars in thousands)
<S> <C>
2000 $1,458
2001 834
2002 834
2003 452
2004 444
Beyond 2005 1,399
------
$5,421
======
</TABLE>
Total rent expense for all operating leases, except those with terms of a month
or less, amounted to $2,766,000 in 1999, $2,718,000 in 1998 and $3,174,000 in
1997. There were no contingent rentals and no sublease rentals for the years
1999, 1998 and 1997.
-33-
<PAGE>
PART IV.
--------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- ------------------------------------------------------------------------
(a) 1. Index to Financial Statements
-----------------------------
Financial statements and notes thereto of the Company together with the Report
of Independent Public Accountants, are filed under Item 8 of this report and
listed on the Index to Financial Statements and Schedules (page 17).
(a) 2. Index to Financial Statement Schedules
--------------------------------------
Filed herewith at page(s) indicated -
Schedule II - Valuation and Qualifying Accounts - Years Ended December
-----------
31, 1999, 1998 and 1997 (page 43).
(a) 3. Exhibits:
--------
Notes to Exhibits -
-------------------
a. Unless otherwise designated, the exhibits listed below are incorporated by
reference to the appropriate exhibit numbers and the Securities and
Exchange Commission file numbers indicated in parentheses.
b. During 1981, the Company sold its gas business and properties to
Commonwealth Gas and changed its corporate name from New Bedford Gas and
Edison Light Company to Commonwealth Electric Company.
c. The following is a glossary of NSTAR and subsidiary companies' acronyms
that are used throughout the following Exhibit Index:
CES ...................... Commonwealth Energy System
CEL ...................... Cambridge Electric Light Company
CEC ...................... Canal Electric Company
CG ....................... Commonwealth Gas Company
NBGEL .................... New Bedford Gas and Edison Light Co.
EXHIBIT INDEX:
Exhibit 3. Articles of incorporation and by-laws
- ---------- -------------------------------------
3.1.1 By-laws of the Company as amended, (Refiled as Exhibit 1 to the CE 1991
Form 10-K, File No. 2-7749).
3.1.2 Articles of Incorporation, as amended, of NBGEL, including certification
of name change to Commonwealth Electric Company as filed with the
Massachusetts Secretary of State on March 1, 1981 (Refiled as Exhibit 1
to the CE 1990 Form 10-K, File No. 2-7749).
-34-
<PAGE>
Exhibit 10. Material Contracts.
- ----------- -------------------
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December
1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and NBGEL
dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to
the CE 1991 Form 10-K, File No. 2-7749).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE
Form 10-Q (June 1988), File No. 2-7749).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July
1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989),
File No. 2-7749).
10.1.3 Agreement between NBGEL and Boston Edison Company (BECO) for the
purchase of electricity from BECO's Pilgrim Unit No. 1 dated August 1,
1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.3.1 Service Agreement between NBGEL and BECO for purchase of stand-by
power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.3.2 System Power Sales Agreement by and between CE and BECO dated July 12,
1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2-
7749).
10.1.3.3 Power Exchange Agreement by and between BECO and CE dated December 1,
1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.4 Agreement for Joint-Ownership, Construction and Operation of New
Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to
the NBGEL Form S-1 dated October 1973, File No. 2-49013), and as
amended below:
10.1.5 Purchase and Sale Agreement together with an implementing Addendum
dated December 31, 1981, between CE and CEC, for the purchase and sale
of the CE 3.52% joint-ownership interest in the Seabrook units, dated
January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File
No. 2-7749).
10.1.5.1 Agreement to transfer ownership, construction and operational interest
in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981
(Refiled as Exhibit 3 to the CE 1991 Form 10-K, File No. 2-7749).
-35-
<PAGE>
10.1.6 Power Contract, as amended to February 28, 1990, superseding the Power
Contract dated September 1, 1986 and amendment dated June 1, 1988,
between CEC (seller) and CE and CEL (purchasers) for seller's entire
share of the Net Unit Capability of Seabrook 1 and related energy
(Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-30057).
10.1.7 Capacity Acquisition Agreement between CEC,CEL and CE dated September
25, 1980 (Exhibit 1 to the CEC 1991 Form 10-K, File No. 2-30057).
10.1.7.1 Supplement to 10.1.7 consisting of three Capacity Acquisition
Commitments each dated May 7, 1987, concerning Phases I and II of the
Hydro-Quebec Project and electricity acquired from Connecticut Light
and Power Company CL&P) (Exhibit 1 to the CEC Form 10-Q (September
1987), File No. 2-30057).
10.1.7.2 Amendment to 10.1.7 as amended and restated June 1, 1993, henceforth
referred to as the Capacity Acquisition and Disposition Agreement,
whereby CEC, as agent, in addition to acquiring power may also sell
bulk electric power which CEL and/or the Company owns or otherwise has
the right to sell (Exhibit 1 to the CEC Form 10-Q (September 1993),
File No. 2-30057).
10.1.8 Phase 1 Vermont Transmission Line Support Agreement and Amendment No.
1 thereto between Vermont Electric Transmission Company, Inc. and
certain other New England utilities, dated December 1, 1981 and June
1, 1982, respectively (Refiled as Exhibits 5 and 6 to the 1992 CE Form
10-K, File No. 2-7749).
10.1.8.1 Amendment No. 2 to 10.1.8 as amended November 1, 1982 (Exhibit 5 to
the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.8.2 Amendment No. 3 to 10.1.8 as amended January 1, 1986 (Exhibit 2 to the
CE 1986 Form 10-K, File No. 2-7749).
10.1.9 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for
the purchase of available hydro-electric energy produced by a facility
located in Ware, Massachusetts, dated September 1, 1983 (Refiled as
Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.10 Power Purchase Agreement between Corporation Investments, Inc. (CI),
and CE for the purchase of available hydro-electric energy produced by
a facility located in Lowell, Massachusetts, dated January 10, 1983
(Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.10.1 Amendment to 10.1.12 between CI and Boott Hydropower, Inc., an
assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the
CE 1984 Form 10-K, File No. 2-7749).
10.1.11 Phase 1 Terminal Facility Support Agreement dated December 1, 1981,
Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November
1, 1982, between New England Electric Transmission Corporation (NEET),
other New England utilities and CE (Exhibit 1 to the CE Form 10-Q
(June 1984), File No. 2-7749).
-36-
<PAGE>
10.1.11.1 Amendment No. 3 to 10.1.11 (Exhibit 2 to the CE Form 10-Q (June
1986), File No. 2-7749).
10.1.12 Preliminary Quebec Interconnection Support Agreement dated May 1,
1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated
June 1, 1982, Amendment No. 3 dated November 1, 1982, Amendment No. 4
dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among
certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE
Form 10-Q (June 1984), File No. 2-7749).
10.1.13 Agreement with Respect to Use of Quebec Interconnection dated December
1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated
November 1, 1982 among certain NEPOOL utilities (Exhibit 3 to the CE
Form 10-Q (June 1984), File No. 2-7749).
10.1.13.1 Amendatory Agreement No. 3 to 10.1.13 as amended June 1, 1990, among
certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September
1990), File No. 2-30057).
10.1.14 Phase I New Hampshire Transmission Line Support Agreement between NEET
and certain other New England Utilities dated December 1, 1981
(Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.15 Agreement, dated September 1, 1985, with Respect To Amendment of
Agreement With Respect To Use Of Quebec Interconnection, dated
December 1, 1981, among certain NEPOOL utilities to include Phase II
facilities in the definition of "Project" (Exhibit 1 to the CEC Form
10-Q (September 1985), File No. 2-30057).
10.1.16 Preliminary Quebec Interconnection Support Agreement - Phase II among
certain New England electric utilities dated June 1, 1984 (Exhibit 6
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.1 First, Second and Third Amendments to 10.1.16 as amended March 1,
1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to
the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.16.2 Fifth, Sixth and Seventh Amendments to 10.1.16 as amended October 15,
1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to
the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.16.3 Fourth and Eighth Amendments to 10.1.16 as amended July 1, 1987 and
August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.16.4 Ninth and Tenth Amendments to 10.1.16 as amended November 1, 1988 and
January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K,
File No. 2-30057).
10.1.16.5 Eleventh Amendment to 10.1.16 as amended November 1, 1989 (Exhibit 4
to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.16.6 Twelfth Amendment to 10.1.16 as amended April 1, 1990 (Exhibit 1 to
the CEC Form 10-Q (June 1990), File No. 2-30057).
-37-
<PAGE>
10.1.17 Phase II Equity Funding Agreement for New England Hydro-Transmission
Electric Company, Inc. (New England Hydro) (Massachusetts), dated June
1, 1985, between New England Hydro and certain NEPOOL utilities
(Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.18 Phase II Massachusetts Transmission Facilities Support Agreement dated
June 1, 1985, refiled as a single agreement incorporating Amendments 1
through 7 dated May 1, 1986 through January 1, 1989, respectively,
between New England Hydro and certain NEPOOL utilities (Exhibit 2 to
the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.19 Phase II New Hampshire Transmission Facilities Support Agreement dated
June 1, 1985, refiled as a single agreement incorporating Amendments 1
through 8 dated May 1, 1986 through January 1, 1990, respectively,
between New England Hydro-Transmission Corporation (New Hampshire
Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q
(September 1990), File No. 2-30057).
10.1.20 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June
1, 1985, between New Hampshire Hydro and certain NEPOOL util- ities
(Ex. 3 to the CEC Form 10-Q (Sept. 1985), File No. 2-30057).
10.1.20.1 Amendment No. 1 to 10.1.20 dated May 1, 1986 (Exhibit 6 to the CEC
Form 10-Q (March 1987), File No. 2-30057).
10.1.20.2 Amendment No. 2 to 10.1.20 as amended September 1, 1987 (Exhibit 3 to
the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.21 Phase II New England Power AC Facilities Support Agreement, dated June
1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the
CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.21.1 Amendments Nos. 1 and 2 to 10.1.21 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March
1987), File No. 2-30057).
10.1.21.2 Amendments Nos. 3 and 4 to 10.1.21 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.22 Phase II Boston Edison AC Facilities Support Agreement, dated June 1,
1985, between BECO and certain NEPOOL utilities (Exhibit 7 to the CEC
Form 10-Q (September 1985), File No. 2-30057).
10.1.22.1 Amendments Nos. 1 and 2 to 10.1.22 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March
1987), File No. 2-30057).
10.1.22.2 Amendments Nos. 3 and 4 to 10.1.22 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
-38-
<PAGE>
10.1.23 Agreement Authorizing Execution of Phase II Firm Energy Contract,
dated September 1, 1985, among certain NEPOOL utilities in regard to
participation in the purchase of power from Hydro-Quebec (Exhibit 8 to
the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Agreements by and between Swift River Company and CE for the purchase
of available hydro-electric energy to be produced by units located in
Chicopee and North Willbraham, Massachusetts, both dated September 1,
1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.24.1 Transmission Service Agreement between Northeast Utilities' companies
(NU) - The Connecticut Light and Power Company (CL&P) and Western
Massachusetts Electric Company (WMECO), and CE for NU companies to
transmit power purchased from Swift River Company's Chicopee Units to
CE, dated October 1, 1984 (Exhibit 14 to the CE 1984 Form 10-K, File
No. 2-7749).
10.1.24.2 Transformation Agreement between WMECO and CE whereby WMECO is to
transform power to CE from the Chicopee Units, dated December 1, 1984
(Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.25 Power Purchase Agreement by and between SEMASS Partnership, as seller,
to construct, operate and own a solid waste disposal facility at its
site in Rochester, Massachusetts and CE, as buyer of electric energy
and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form
10-K, File No. 2-7749).
10.1.25.1 Power Sales Agreement to 10.1.25 for all capacity and related energy
produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K,
File No. 2-7749).
10.1.25.2 Amendment to 10.1.25 for all additional electric capacity and related
energy to be produced by an addition to the Original Unit, dated March
14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-7749).
10.1.25.3 Second Amendment to 10.1.25.2 for all additional electric capacity and
related energy to be produced by an addition to the Original Unit,
dated May 24, 1991 (Exhibit 1 to the CE Form 10-Q (June 1991), File
No. 2-7749).
10.1.26 Power Sale Agreement by and between CE (buyer) and Northeast Energy
Associates, Ltd. (NEA) (seller) of electric energy and capacity, dated
November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File
No. 2-7749).
10.1.26.1 First Amendment to 10.1.26 as amended August 15, 1988 (Exhibit 1 to
the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.26.2 Second Amendment to 10.1.26 as amended January 1, 1989 (Exhibit 2 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.26.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the
purchase of 21 MW of electricity (Exhibit 2 to the CE Form
10-Q (September 1988), File No. 2-7749).
-39-
<PAGE>
10.1.26.4 Amendment to 10.1.26.3 as amended January 1, 1989 (Exhibit 3 to the
CE 1988 Form 10-K, File No. 2-7749).
10.1.27 Power Purchase Agreement and First Amendment, dated September 5, 1989
and August 3, 1990, respectively, by and between CE (buyer) and
Dartmouth Power Associates Limited Partnership (seller), whereby buyer
will purchase all of the energy (67.6 MW) produced by a single gas
turbine unit (Exhibit 1 to the CE Form 10-Q (June 1992), File No. 2-
7749).
10.1.27.1 Second Amendment, dated June 23, 1994, to 10.1.27 (Exhibit 4 to the
CE Form 10-Q (June 1995), File No. 2-7749).
10.1.28 Power Purchase Agreement by and between Masspower (seller) and the
Company (buyer) for a 11.11% entitlement to the electric capacity and
related energy of a 240 MW gas-fired cogeneration facility, dated
February 14, 1992 (Exhibit 1 to the CE Form 10-Q (September 1993),
File No. 2-7749).
10.1.29 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller)
and the Company (buyer) for a 17.2% entitlement to the electric
capacity and related energy of a 160 MW gas-fired cogeneration
facility, dated February 20, 1992 (Exhibit 2 to the CE Form 10-Q
(September 1993), File No. 2-7749).
10.1.29.1 System Exchange Agreement by and among Altresco Pittsfield, L.P.,
CEL, the Company and New England Power Company, dated July 2, 1993
(Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749).
10.1.29.2 First Amendment, dated November 7, 1994, to 10.1.29 by and between
the Company and Altresco Pittsfield, L.P. dated February 20, 1992
10.2 Other agreements.
10.2.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993 (Exhibit
1 to the CES Form 10-Q (Sept. 1993), File No. 1-7316).
10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies as amended and restated as of January 1, 1993 (Ex-hibit 2 to
the CES Form 10-Q (September 1993), File No. 1-7316).
10.2.2.1 First Amendment to the Employees Savings Plan of Commonwealth Energy
System and Subsidiary Companies, as amended and restated as of January
1, 1993, effective October 1, 1994. (Exhibit 1 to CES Form S-8
(January 1995), File No. 1-7316).
10.2.2.2 Second Amendment to the Employees Savings Plan of Commonwealth Energy
System and Subsidiary Companies, as amended and restated as of January
1, 1993, effective April 1, 1996. (Exhibit 1 to CES Form 10-K/A
Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.2.2.3 Third Amendment to the Employees Savings Plan of Commonwealth Energy
System and Subsidiary Companies, as amended and restated as of January
1, 1993, effective January 1, 1997. (Exhibit 1 to CES Form 10-K/A
Amendment No. 1 (April 29, 1997), File No. 1-7316).
-40-
<PAGE>
10.2.2.4 Fourth Amendment to the Employees Savings Plan of Commonwealth Energy
System and Subsidiary Companies, as amended and restated as of January
1, 1993, effective January 1, 1998. (Exhibit 1 to CES Form 10-K/A
Amendment No. 1 (April 29, 1998), File No. 1-7316).
10.2.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as
amended through August 1, 1977, between NEGEA Service Corporation, as
agent for CEL, CEC, NBGEL, and various other electric utilities
operating in New England together with amendments dated August 15,
1978, January 31, 1979 and February 1, 1980 (Exhibit 5(c)13 to New
England Gas and Electric Association's Form S-16 (April 1980), File
No. 2-64731).
10.2.3.1 Thirteenth Amendment to 10.2.3 as amended September 1, 1981 (Refiled
as Exhibit 3 to the CES 1991 Form 10-K, File No. 1-7316).
10.2.3.2 Fourteenth through Twentieth Amendments to 10.2.3 as amended December
1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985,
August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the
CES Form 10-Q (Sept. 1985), File No. 1-7316).
10.2.3.3 Twenty-first Amendment to 10.2.3 as amended to January 1, 1986
(Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316).
10.2.3.4 Twenty-second Amendment to 10.2.3 as amended to September 1, 1986
(Exhibit 1 to the CES Form 10-Q (Sept. 1986), File No. 1-7316).
10.2.3.5 Twenty-third Amendment to 10.2.3 as amended to April 30, 1987 (Exhibit
1 to the CES Form 10-Q (June 1987), File No. 1-7316).
10.2.3.6 Twenty-fourth Amendment to 10.2.3 as amended March 1, 1988 (Exhibit 1
to the CES Form 10-Q (March 1989), File No. 1-7316).
10.2.3.7 Twenty-fifth Amendment to 10.2.3. as amended to May 1, 1988 (Exhibit 1
to the CES Form 10-Q (March 1988), File No. 1-7316).
10.2.3.8 Twenty-sixth Agreement to 10.2.3 as amended March 15, 1989 (Exhibit 1
to the CES Form 10-Q (March 1989), File No. 1-7316).
10.2.3.9 Twenty-seventh Agreement to 10.2.3 as amended October 1, 1990 (Exhibit
3 to the CES 1990 Form 10-K, File No. 1-7316).
10.2.3.10 Twenty-eighth Agreement to 10.2.3 as amended September 15, 1992
(Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.2.3.11 Twenty-ninth Agreement to 10.2.3 as amended May 1, 1993 (Exhibit 2 to
the CES Form 10-Q (September 1994), File No. 1-7316).
(b) Reports on Form 8-K
-------------------
No reports on Form 8-K were filed during the three months ended
December 31, 1998.
-41-
<PAGE>
Exhibit 27. Financial Data Schedule
- -----------------------------------
Filed herewith as Exhibit 1 is the Financial Data Schedule for the year
ended December 31, 1999.
-42-
<PAGE>
SCHEDULE II
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
VALUATION AND QUALIFYING ACCOUNTS
---------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 and 1997
----------------------------------------------------
(Dollars in thousands)
<TABLE>
<CAPTION>
Additions
----------------------------
Deductions
Balance Provision ----------- Balance
Beginning Charged to Accounts End
Description of Year Operations Recoveries Written Off of Year
- --------------------- ------------ ------------- ------------- ----------- -------
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1999
----------------------------
Allowance for
Doubtful Accounts $1,069 $2,278(a) $624 $2,400 $1,571
=======
Year Ended December 31, 1998
----------------------------
$2,044 $ 917 $638 $2,530 $1,069
=======
Year Ended December 31, 1997
----------------------------
$1,792 $2,415 $703 $2,866 $2,044
======
</TABLE>
(a) includes $354,000 adjustment to provision.
-43-
<PAGE>
FORM 10-K DECEMBER 31, 1999
--------- -----------------
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
COMMONWEALTH ELECTRIC COMPANY
-----------------------------
(Registrant)
By: /s/ THOMAS J. MAY
------------------------------
Thomas J. May,
Chairman of the Board and
Chief Executive Officer
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 and on the dates indicated.
Principal Executive Officers:
/s/THOMAS J. MAY March 30, 2000
- ---------------------------------------------
Thomas J. May
Chairman of the Board and
Chief Executive Officer
/s/R. D. WRIGHT March 30, 2000
- ---------------------------------------------
R. D. Wright,
President and Chief Operating Officer
Principal Financial and Accounting Officer:
/s/ROBERT J. WEAFER, JR March 30, 2000
- ---------------------------------------------
Robert J. Weafer, Jr.,
Vice President, Controller and
Chief Accounting Officer
A majority of the Board of Directors:
/s/THOMAS J. MAY March 30, 2000
- ---------------------------------------------
Thomas J. May, Director
/s/R. D. WRIGHT March 30, 2000
- ---------------------------------------------
Russell D. Wright, Director
/s/JAMES J. JUDGE March 30, 2000
- ---------------------------------------------
James J. Judge, Director
-44-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE
SHEET, STATEMENT OF INCOME, STATEMENT OF RETAINED EARNINGS AND STATEMENT OF CASH
FLOWS CONTAINED IN FORM 10-K OF COMMONWEALTH ELECTRIC COMPANY FOR THE FISCAL
YEAR ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 391,003
<OTHER-PROPERTY-AND-INVEST> 418
<TOTAL-CURRENT-ASSETS> 67,144
<TOTAL-DEFERRED-CHARGES> 120,884
<OTHER-ASSETS> 348,196
<TOTAL-ASSETS> 927,645
<COMMON> 51,099
<CAPITAL-SURPLUS-PAID-IN> 331,466
<RETAINED-EARNINGS> 17,928
<TOTAL-COMMON-STOCKHOLDERS-EQ> 400,493
0
0
<LONG-TERM-DEBT-NET> 142,609
<SHORT-TERM-NOTES> 27,055
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,053
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 356,435
<TOT-CAPITALIZATION-AND-LIAB> 927,645
<GROSS-OPERATING-REVENUE> 426,011
<INCOME-TAX-EXPENSE> 3,552
<OTHER-OPERATING-EXPENSES> 398,427
<TOTAL-OPERATING-EXPENSES> 401,979
<OPERATING-INCOME-LOSS> 24,032
<OTHER-INCOME-NET> 2,255
<INCOME-BEFORE-INTEREST-EXPEN> 26,287
<TOTAL-INTEREST-EXPENSE> 20,509
<NET-INCOME> 5,778
0
<EARNINGS-AVAILABLE-FOR-COMM> 5,778
<COMMON-STOCK-DIVIDENDS> 24,834
<TOTAL-INTEREST-ON-BONDS> 12,883
<CASH-FLOW-OPERATIONS> 60,353
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
