<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 2-7909
CAMBRIDGE ELECTRIC LIGHT COMPANY
----------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Massachusetts 04-1144610
- ---------------------------------------------------------- --------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
- ------------------------------------------ ----------
(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
--------------
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 346,600 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 40 of this report.
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TABLE OF CONTENTS
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PART I
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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............................................................. 13
Item 8. Financial Statements and Supplementary Data...................... 16
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure......................................... 32
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 33
Signatures................................................................. 41
</TABLE>
<PAGE>
PART I.
-------
Item 1. Business
- ------- --------
(a) General
-------
Cambridge Electric Light Company (the Company) is engaged in the
transmission, distribution and sale of electricity to approximately 45,900
retail customers in the city of Cambridge, Massachusetts. The service territory
encompasses a seven square mile area with a population of approximately 96,000.
In addition, the Company sold power for resale to the Independent System
Operator (ISO) - New England (the agency that operates a centralized facility to
ensure reliability of service and dispatch of economically available generating
units throughout New England), the Town of Belmont, Massachusetts (Belmont), and
sold steam from its electric generating stations at wholesale to an affiliated
company for distribution to customers for space heating and other purposes.
The Company, which was organized on January 28, 1886 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), which 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) that is a wholly-owned indirect
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 an 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 other utilities 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 its affiliates Commonwealth Electric Company
(Commonwealth 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 the
state's industry restructuring legislation enacted in 1997. The sale was
approved by the MDTE on October 30, 1998
<PAGE>
and by the FERC on November 12, 1998. Proceeds from the sale of 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 the
Company and Commonwealth Electric 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 Service,
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 Commonwealth 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 Commonwealth 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 (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 will
be 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
their 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.
(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,
<PAGE>
in granting these locations, act as agents for the state. In some cases the
action of these authorities is subject to appeal to the 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 legislation
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 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.
(f) Demand-Side Management Programs
-------------------------------
The Company has implemented a variety of cost-effective 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.
<PAGE>
(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 $5.6 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 and
customer service enhancements.
(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 6.8% in 1999 to
96 from 103 employees at year-end 1998. The Company has 470 employees (74%) who
are represented by the Utility Workers of America, A.F.L. - C.I.O The existing
collective bargaining agreement is in effect through March 1, 2001. Employee
relations have generally been satisfactory.
Item 2. Properties
- ------- ----------
The Company owns and operates one steam generating plant located in Cambridge
with a total capability of 15.3 MW together with an integrated system of
distribution lines and substations.
At December 31, 1999, the Company's electric transmission and distribution
system consisted of 93 pole miles of overhead lines, 756 cable miles of
underground line, 249 substations and 46,579 active customer meters.
Item 3. Legal Proceedings
- ------- -----------------
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 available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial 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.
<PAGE>
PART II.
--------
Item 5. Market for the Registrant's Common Stock and Related Stockholder
- ------ ----------------------------------------------------------------
Matters
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(a) Principal Market
----------------
Not applicable. The Company is wholly-owned by Commonwealth Energy
System and is a wholly-owned subsidiary of NSTAR
(b) Number of Shareholders at December 31, 1999
-------------------------------------------
One
(c) Frequency and Amount of Dividends Declared in 1999 and 1998
-----------------------------------------------------------
<TABLE>
<CAPTION>
1999 1998
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Per Share Per Share
Declaration Date Amount Declaration Date Amount
---------------- --------- ---------------- ---------
<S> <C> <C> <C>
January 29, 1999 $12.25 May 8, 1998 $ 7.50
July 30, 1999 .85 July 23, 1998 2.00
October 29, 1999(1) 14.40 October 23, 1998 2.75
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$27.50 $12.25
====== ======
</TABLE>
(1) The dividend declared on October 29, 1999 constituted a return on
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.
<PAGE>
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
---- ----
%
Change
------
<S> <C> <C> <C>
Unit Sales (MWH):
Residential 169,823 3.6 163,928
Commercial 1,141,134 3.8 1,099,867
Industrial 65,236 (4.0) 67,925
Streetlighting 8,237 (2.2) 8,423
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Total retail 1,384,430 3.3 1,340,143
Wholesale 110,210 (49.5) 218,039
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Total 1,494,640 (4.1) 1,558,182
========= =========
Customers:
Residential 38,672 (0.1) 38,724
Commercial 6,839 0.5 6,802
Industrial 35 (5.4) 37
Streetlighting 320 (0.3) 321
--------- ------- ---------
Total 45,866 -- 45,884
========= =========
</TABLE>
During 1999 the Company's retail unit sales increased 3.3%, driven by increased
sales to residential and commercial customers. This increase is due to higher
than normal summer temperatures and a continuing strong local economy. The
increase in retail sales was more than offset by a decrease in wholesale sales
reflecting lower sales to Independent System Operator (ISO) - New England (the
agency that operates a centralized facility to ensure reliability of service and
dispatch of economically available generating units throughout New England).
Operating Revenues
- ------------------
Operating revenues for 1999 decreased $6.9 million or 5.8% reflecting the 10
percent rate reduction (discussed further below), offset in part by a net
increase in electricity purchased for resale, fuel and transmission charges of
$4.6 million or 6.8%. The increase in these costs reflects lower cost deferrals
associated with the company's restructuring plan as approved by the
Massachusetts Department of Telecommunications and Energy (MDTE). As a result of
the Electric Industry Restructuring Act, the company has unbundled its rates and
currently provides their standard offer customers rates that are 15% lower than
rates in effect prior to March 1, 1998. The company has afforded the customers
the opportunity to purchase generation supply in the competitive market.
Delivery rates are composed of a customer charge (to collect metering and
billing costs), 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 have declined 4.8% from $117 million in 1998 to $111 million
in 1999.
<PAGE>
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,
Qualifying Facilities and other non-utility generators through a competitive
bidding process that was regulated by the MDTE. 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
65.1%, 63.5% and 65.8% in 1999, 1998 and 1997, respectively, of electric
operating revenues. These costs reflect higher unit sales in each succeeding
year and in addition, a cost deferral of $35.3 million in 1998 that resulted
primarily from providing the required 10% rate reduction, which was adjusted to
15% in 1999, for retail customers.
NSTAR, on behalf of its electric retail subsidiaries, including Cambridge
Electric, Boston Edison and Commonwealth 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 provides full energy
service requirements, including NEPOOL capability responsibilities, at Federal
Energy Regulatory commission (FERC) approved tariff rates through June 30, 2000.
Other Operating Expense
- -----------------------
Other operations and maintenance increased $3.5 million (14.1%) in 1999. This
increase was primarily due to higher postretirement benefit expenses ($0.8
million), costs related to employee separation costs ($1.2 million) and costs
related to restoration efforts following Hurricane Floyd ($0.1 million). These
unfavorable variances were partially offset by lower bad debt expense ($0.3
million).
Depreciation and amortization decreased $4.3 million (50.3%) in 1999. This was
due to the sale of the Company's generating assets to The Southern Company on
December 30, 1998 and amortization of the gain on the sale beginning in 1999.
The decrease in depreciation and amortization was partially offset by the
commencement of amortization of goodwill ($161,000) and costs to achieve the
merger ($148,000).
Federal and state income tax expense decreased $4.2 million (123.5%) in 1999.
This is due to the decline in pretax income from 1998 levels.
Local property and other taxes decreased $1.1 million (31.4%) in 1999. This is
due to the reduction in plant assets and employees as a result of the sale of
the Company's generating assets in December 1998.
Other Income (Expense)
- ----------------------
Other income decreased $1.0 million (46.0%) in 1999 due to gain on the sale of
property ($1.3 million after tax) in 1998.
Interest Charges
- ----------------
Total interest charges increased $2.7 million (80.2%) in 1999. The increase
reflects interest calculated on the gain on the sale of Canal Electric's
generating stations which is being returned to customers of the Company and
ComElectric.
<PAGE>
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 (Commonwealth Electric), Cambridge
Electric Light Company (the Company), 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.
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 Company'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 Commonwealth 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. Actual costs to achieve which have been allocated to the
Company were approximately $4.4 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 $56 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.
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.
<PAGE>
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.
As a result of electric industry restructuring, the Company discontinued
application of accounting principles applied to its electric generation
facilities effective March 1, 1998. The Company will not be required to write
off any of its generation-related assets, including regulatory assets. These
assets will be retained on the Company's Balance Sheets because the legislation
and the MDTE's plan for a restructured electric industry specifically provide
for their recovery through the non-bypassable transition charge.
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.
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.
<PAGE>
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.
However, under the terms of the Asset Sale Agreement with Southern Energy dated
May 15, 1998, the Company agreed to perform environmental work necessary to
achieve a "Response Action Outcome" (RAO) (as defined in the state regulations)
regarding the spill of jet fuel at the Kendall Station site. The Company
installed a water treatment system that operated for over a year and
significantly reduced concentrations. The system is now shut down and the
Company will be performing periodic sampling to insure clean-up levels have been
achieved. An RAO statement could be filed later in 2000.
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 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
<PAGE>
(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 rate making 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.
<PAGE>
Item 8. Financial Statements and Supplementary Data
- ------- -------------------------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To the Board of Directors of Cambridge Electric Light Company:
In our opinion, the financial statements listed in the index appearing under
Item 14(a)(1) on page 16 present fairly, in all material respects, the financial
position of Cambridge Electric Light 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 4(a)(2) on page 16, present fairly, in
all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements 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 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
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Cambridge Electric Light Company:
We have audited the accompanying balance sheets of CAMBRIDGE ELECTRIC LIGHT
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 Cambridge Electric Light
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
<PAGE>
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
-------------------------------------------
PART II.
--------
ITEM 8
FINANCIAL STATEMENTS
Report of independent public accountant................................ 14
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............................................. 19
Statements of Retained Earnings for the Years Ended
December 31, 1999, 1998 and 1997....................................... 20
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............................................. 21
Notes to Financial Statements
PART IV.
--------
SCHEDULES
Valuation and Qualifying Accounts - Years Ended
December 31, 1999, 1998 and 1997.......................................... 40
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.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT 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 $144,190 $140,642
Less - Accumulated depreciation 49,352 47,179
-------- --------
94,838 93,463
Add - Construction work in progress 2,181 937
-------- --------
97,019 94,400
--------
INVESTMENTS
Equity in nuclear electric power companies 9,859 9,906
Other 5 5
-------- --------
9,864 9,911
-------- --------
GOODWILL 55,549 -
-------- --------
LONG-TERM RECEIVABLE - AFFILIATE 25,052 35,441
-------- --------
CURRENT ASSETS
Cash 415 778
Advances to affiliates 22,400 27,450
Accounts receivable -
Affiliated companies 1,375 1,729
Customers, less allowances of $410 in 1999
and $465 in 1998 11,070 10,774
Unbilled revenues 620 1,577
Inventories, at average cost -
Materials and supplies 833 717
Electric production fuel oil 53 35
Prepaid property taxes 1,126 1,410
Other 365 324
-------- --------
38,257 44,794
-------- --------
DEFERRED CHARGES
Regulatory assets 61,208 70,372
Other 4,828 2,012
-------- --------
66,036 72,384
-------- --------
$291,777 $256,930
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT 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 -
346,600 shares in 1999 and 1998,
wholly-owned by NSTAR (Parent) $ 8,665 $ 8,665
Amounts paid in excess of par value 92,395 27,953
Retained earnings 800 16,182
-------- --------
101,940 52,800
Long-term debt, including premiums, less
current sinking fund requirements and
maturing debt 27,201 7,301
-------- --------
129,141 60,101
-------- --------
CURRENT LIABILITIES
Interim Financing -
Maturing long-term debt - 10,000
-------- --------
Other Current Liabilities -
Current sinking fund requirements 100 100
Accounts payable -
Affiliated companies 5,058 2,818
Other 8,909 28,767
Accrued local property and other taxes 1,132 1,468
Accrued income taxes 3,253 -
Accrued interest 330 463
Other 5,781 7,475
-------- --------
24,563 41,091
-------- --------
24,563 51,091
-------- --------
DEFERRED CREDITS
Regulatory liabilities 67,216 65,124
Accumulated deferred income taxes 10,610 15,328
Connecticut Yankee purchased power contract 22,412 25,185
Maine Yankee purchased power contract 28,014 30,646
Yankee Atomic purchased power contract 532 1,634
Unamortized investment tax credits and other 9,289 7,821
-------- --------
138,073 145,738
-------- --------
COMMITMENTS AND CONTINGENCIES
$291,777 $256,930
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT 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 $36,133 $75,636 $118,707 $131,327
------- ------- -------- --------
OPERATING EXPENSES
Fuel used in electric production (19) (71) 2,602 4,322
Electricity purchased for resale 12,825 52,730 59,387 77,879
Transmission 3,166 4,094 6,072 5,121
Other operation 13,031 12,272 21,711 23,599
Maintenance 1,344 2,052 3,439 2,749
Depreciation and amortization 1,741 2,487 8,502 4,335
Taxes -
Income 709 (1,504) 3,423 2,591
Local property 577 1,338 2,828 3,060
Payroll and other 149 405 775 885
------- ------- -------- --------
33,523 73,803 108,739 124,541
------- ------- -------- --------
OPERATING INCOME 2,610 1,833 9,968 6,786
OTHER INCOME (EXPENSE) 273 934 2,236 1,774
------- ------- -------- --------
INCOME BEFORE INTEREST CHARGES 2,883 2,767 12,204 8,560
------- ------- -------- --------
INTEREST CHARGES
Long-term debt 362 550 1,442 1,560
Other interest charges 1,661 3,579 1,997 1,815
-------- --------
Allowance for borrowed funds used
During construction (20) (37) (56) (31)
------- ------- -------- --------
2,003 4,092 3,383 3,344
------- ------- -------- --------
NET INCOME (Loss) $ 880 $(1,325) $ 8,821 $ 5,216
======= ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT 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 $16,182 $11,607 $ 9,233
Add (Deduct):
Net income (loss) - 8,821 5,216
January 1, 1999 to August 24, 1999 (1,325)
Dividends on common stock - (4,246) (2,842)
January 1, 1999 to August 24, 1999 (4,541) - -
------- ------- -------
10,316 16,182 11,607
Reclassification to additional
Paid in capital at August 24, 1999 (10,316) - -
Add (Deduct)
Net income - 880 - -
------- ------- -------
Balance at end of year $ 880 $16,182 $11,607
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT COMPANY
--------------------------------
STATEMENTS OF CASH FLOWS
------------------------
<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>
OPERATING ACTIVITIES
Net income $ 880 $ (1,325) $ 8,821 $ 5,216
Effects of noncash items -
Depreciation and
amortization 1,742 2,486 8,502 4,335
Deferred income taxes, net 16,457 (173) (19,391) (448)
Investment tax credits, net - (60) (484) (91)
Earnings from corporate
joint ventures 68 (462) (1,041) (1,119)
Dividends from corporate
joint ventures 156 285 984 673
Change in working
capital, exclusive of
cash and interim
financing -
Accounts receivable and
unbilled revenues 351 664 4,193 (2,785)
Income taxes 3,908 (1,817) 1,192 (224)
Accounts payable and
other (596) (19,076) 23,914 (294)
Transition costs deferral (3,116) 1,968 (7,244) -
Deferred charges, net,
primarily
Merger-related costs (12,930) 19,393 - -
EIS proceeds 4,813 5,576 - -
All other operating items (6,889) (12,403) (8,239) 722
-------- -------- -------- -------
Net cash provided by
operating activities 4,844 (4,944) 11,207 5,985
-------- -------- -------- -------
INVESTING ACTIVITIES
Proceeds from sale of
generating assets - - 58,992 -
Additions to property,
plant and
equipment (exclusive of
AFUDC) (2,298) (3,326) (7,799) (4,873)
Allowance for borrowed
funds used
during construction (20) (37) (56) (31)
Payments from advances to
affiliates (17,490) 22,540 (27,450) -
-------- -------- -------- -------
Net cash used for
investing activities (19,808) 19,177 23,687 (4,904)
-------- -------- -------- -------
FINANCING ACTIVITIES
Payment of dividends (4,991) (4,541) (4,246) (2,842)
Proceeds from (payment of)
short-term borrowings - - (19,000) 275
Proceeds from (payments
to) affiliates - - (11,290) 6,225
Long-term debt issues
(refunded) 20,000 (10,000) - (4,260)
Retirement of long-term
debt
through sinking funds - (100) (101) (101)
-------- -------- -------- -------
Net cash provided by (used
for) financing activities 15,009 (14,641) (34,637) (703)
-------- -------- -------- -------
Change in cash 45 (408) 257 378
Cash at beginning of period 370 778 521 143
-------- -------- -------- -------
Cash at end of period $ 415 $ 370 $ 778 $ 521
======== ======== ======== =======
SUPPLEMENTAL DISCLOSURES
OF CASH FLOW INFORMATION
Cash paid (refunded)
during the periods for:
Interest (net of
capitalized amounts) $ 295 $ 733 $ 3,080 $ 3,371
Income taxes $ 341 $ 981 $ 3,871 $ 2,319
======== ======== ======== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
NOTES TO FINANCIAL STATEMENTS
- -----------------------------
(1) General Information
-------------------
Cambridge Electric Light Company (the Company) is a wholly-owned subsidiary of
Commonwealth Energy System which is an indirect 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 45,900
retail customers in the City of Cambridge, Massachusetts. The service territory
encompasses a seven square-mile area with a population of approximately 96,000.
The Company has 96 regular employees including 71 (74%) of whom are represented
by a single collective bargaining unit with a contract that expires on March 1,
2001. 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 of August 25, 1999, approximately $10.3 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. Actual costs to achieve which have been allocated to the
Company were approximately $4.4 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 $56 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 (MDTE).
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 of
Certain Types of Regulation." The Company has established various regulatory
assets in cases where the MDTE 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
<PAGE>
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.
As a result of electric industry restructuring, the Company discontinued
application of accounting principles applied to its investment in electric
generation facilities effective March 1, 1998. The Company will not be required
to write off any of its generation-related assets, including regulatory assets.
These assets will be retained on the Company's Balance Sheets because the
legislation and the MDTE's plan for a restructured electric industry
specifically provide for their recovery through a non-bypassable transition
charge.
The principal regulatory assets included in deferred charges were as follows:
<TABLE>
<CAPTION>
1999 1998
---- ----
(Dollars in thousands)
<S> <C> <C>
Yankee Atomic unrecovered plant
and decommissioning costs $ 664 $ 1,634
Connecticut Yankee unrecovered plant
and decommissioning costs 22,412 25,185
Maine Yankee unrecovered plant
and decommissioning costs 27,882 30,646
Transition costs (732) 9,149
Merger-related costs 8,469 -
Postretirement benefits costs 1,840 3,120
Other 673 638
------- -------
$61,208 $70,372
======= =======
</TABLE>
The regulatory liabilities, reflected in the accompanying Balance Sheets were as
follows:
<TABLE>
<CAPTION>
1999 1998
---- ----
(Dollars in thousands)
<S> <C> <C>
Regulatory liability related to
sale of generating assets $51,988 $61,040
Merger-related costs 10,596 -
Deferred income taxes 2,239 2,402
Demand-side management deferral 2,393 1,682
------- -------
$67,216 $65,124
======= =======
</TABLE>
The regulatory liability related to the sale of generating assets was
established pursuant to the Company's divestiture filing that was approved by
the MDTE in which the 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 will be invested in a conservative
portfolio
<PAGE>
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 Commonwealth Electric Company (Commonwealth 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 Commonwealth 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.
(d) Transactions with Affiliates
----------------------------
Transactions between the Company and other COM/Energy 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 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.
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 $ - $5,589 $ 710
August 25 - December 31, 1999 - 2,794 355
1998 14,014 7,323 1,062
1997 15,772 7,825 2,358
</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 $1,026,000 and
$1,290,000 in 1998, and 1997, respectively.
<PAGE>
(e) 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.
(f) 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 2.72% in 1999, 2.88% in 1998 and 2.68% in 1997.
(g) 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.
(h) 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 $57,000, $163,000 and $145,000 in 1999, 1998 and 1997,
respectively.
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 6.75% in 1999, 5.75% in 1998 and
6.00% in 1997.
(3) Commitments and Contingencies
-----------------------------
(a) Financing and Construction Programs
-----------------------------------
The Company is engaged in a continuous construction program presently estimated
at $31.6 million for the five-year period 2000 through 2004. Of that amount, $9
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.
<PAGE>
(b) Long-Term Contracts for the Purchase of Electricity
--------------------------------------------------
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 2011 17.2 29.8 $12,306 $ 19,780 $15,633
Nuclear 2012-2026 .7-2.3 8.2-11.9 12,392 180,061 13,070
Oil 2002 5 28.1 1,922 5,362 5,543
- -----------------------------------------------------------------------------------------------------
Total $26,620 $205,203 $34,246
=====================================================================================================
</TABLE>
<PAGE>
The Company's total fixed and variable costs associated with these contracts in
1999, 1998 and 1997 were approximately $34 million, $36 million and $33 million,
respectively. NSTAR's capacity charge obligation under these contracts for the
years after 1999 are as follows:
<TABLE>
<CAPTION>
Capacity Charge
(in thousands) Obligation
- --------------------------------------------------------
<S> <C>
2000 $ 12,367
2001 12,600
2002 12,505
2003 11,068
2004 11,458
Years thereafter 145,205
- --------------------------------------------------------
Total $ 205,203
========================================================
</TABLE>
(c) 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 construction 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 $17,735 $ 15,099
Transition costs 1,400 3,189
All other 2,162 1,453
------- --------
21,297 19,741
------- --------
Assets
Sale of generation assets 5,984 25,572
Investment tax credit 764 764
All other 2,777 4,092
------- --------
9,525 30,428
------- --------
Accumulated deferred
tax asset, net $11,772 $(10,687)
======= ========
</TABLE>
<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 557 (991) $8,493 $ 9,562
Increase (Decrease) from
statutory levels:
State tax net of federal tax
benefit 67 (139) 1,046 1,171
Tax versus book depreciation - - 198 105
Amortization of investment tax
credits 1 (60) (472) (430)
Reversals of capitalized
expenses - (25) (76) (63)
Other 84 (289) (33) 53
---- ------- ------ -------
$709 $(1,504) $9,156 $10,398
==== ======= ====== =======
Effective federal income tax rate 45% 53% 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 $ 2,530 $(1,061) $ 20,117 $2,574
Deferred (1,924) (170) (16,050) (287)
Investment tax credits, net - (60) (484) (91)
------- ------- -------- ------
606 (1,291) 3,583 2,196
------- ------- -------- ------
State
Current 496 (211) 4,013 556
Deferred (393) (2) (3,155) (48)
------- ------- -------- ------
103 (213) 858 508
------- ------- -------- ------
$ 709 $(1,504) $ 9,156 $2,704
======= ======= ======== ======
</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 postretirement benefit plans
of BEC and COM/Energy were combined under NSTAR.
(a) Pension
-------
NSTAR has a defined benefit funded retirement plan with certain contribution
features that covers substantially all employees. NSTAR also maintains an
unfunded supplemental
<PAGE>
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 $201,000, $554,000 and $447,000
in 1999, 1998 and 1997, respectively. The accrued pension cost in the Company's
statement of financial position was $(403,000) and $2,573,000 in 1999 and 1998,
respectively.
As a result of the merger-related separation packages, amounts recognized for
curtailment and special termination benefit costs were $778,000 and $453,000,
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
$903,000, $1,121,000 and $1,087,000 in 1999, 1998 and 1997, respectively. The
accrued benefit cost in the Company's statement of financial position was
$5,960,000 and $0 at December 31, 1999 and 1998, respectively.
(c) Savings Plan
------------
The Company has an Employees Savings Plan that provides for Company
contributions to eligible employees of up to four percent of each employee's
compensation rate. The total Company contribution was $215,000 in 1999, $294,000
in 1998 and $302,000 in 1997.
(6) Long-Term Debt and Interim Financing
------------------------------------
(a) Long-Term Debt Maturities and Retirements
-----------------------------------------
<PAGE>
Long-term debt outstanding, exclusive of current maturities, current sinking
fund requirements and related premiums, is as follows:
<TABLE>
<CAPTION>
Balance December 31,
Original --------------------
Issue 1999 1998
-------- ---- ----
(Dollars in thousands)
<S> <C> <C> <C>
7-Year Notes - 7.62%, due 2006 $20,000 $ 20,00 $ -
15-Year Notes - 8.7%, due 2007 5,000 5,000 5,000
30-Year Notes - 7.75%, due 2002 5,000 2,200 2,300
------- ------
$27,200 $7,300
======= ======
</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, 1999 are as follows:
<TABLE>
<CAPTION>
Sinking Fund Maturing
Year Payments Debt Issues Total
---- ------------ ----------- -----
(Dollars in thousands)
<S> <C> <C> <C>
2000 $ 100 $ - $ 100
2001 100 - 100
2002 100 2,000 2,100
2003 - - -
2004 - - -
</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 $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, 1999, NSTAR's 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 no notes payable to banks at December 31,
1999 and 1998.
(c) Advances from Affiliates
------------------------
The Company is a member of the NSTAR Money Pool (the Pool), an arrangement
among the subsidiaries of the Parent, 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. The Company had no borrowings from the Pool at
December 31, 1999 and 1998.
<PAGE>
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
----------------- -----------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- ------- -------- -------
(Dollars in thousands)
<S> <C> <C> <C> <C>
Long-term debt $27,301 $27,560 $17,401 $18,362
</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.
(7) Dividend Restriction
--------------------
At December 31, 1999, there were no retained earnings 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, 1999:
<TABLE>
<CAPTION>
Operating Leases
----------------------
(Dollars in thousands)
<S> <C>
2000 1,287
2001 1,109
2002 1,109
2003 1,109
2004 1,109
Beyond 2004 2,238
------
Total future minimum lease payments $7,961
======
</TABLE>
Total rent expense for all operating leases, except those with terms of a month
or less, amounted to $1,526,000 in 1999, $1,307,000 in 1998 and $1,683,000 in
1997. There were no contingent rentals and no sublease rentals for the years
1999, 1998 and 1997.
<PAGE>
CAMBRIDGE ELECTRIC LIGHT COMPANY
--------------------------------
PART V.
-------
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 16).
(a) 2. Index to Financial Statement Schedules
--------------------------------------
Filed herewith at page(s) indicated -
Schedule II - Valuation and Qualifying Accounts - Years Ended
-----------
December 31,1998, 1997 and 1996 (page 58).
(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. The following is a glossary of Commonwealth Energy System and subsidiary
companies' acronyms that are used throughout the following Exhibit Index:
CES.....................Commonwealth Energy System
CE......................Commonwealth Electric Company
CEL.....................Cambridge Electric Light Company
CEC.....................Canal Electric Company
CG......................Commonwealth Gas Company
NBGEL...................New Bedford Gas and Edison Light Company
Exhibit Index
-------------
(b) Reports on Form 8-K
-------------------
No reports on Form 8-K were filed during the three months ended December 31,
1998.
Exhibit 3. Articles of incorporation and by-laws.
- --------- -------------------------------------
3.1 Articles of incorporation of CEL (Exhibit 1 to the CEL Form 10-K for
1990, File No.2-7909).
3.2 By-laws of CEL, as amended (Exhibit 2 to the CEL Form 10-K for 1990,
File No.2-7909).
Exhibit 4. Instruments defining the rights of security holders; including
- --------- --------------------------------------------------------------
indentures.
----------
Indenture of Trust or Supplemental Indenture of Trust.
4.1.1 Original Indenture on Form S-1 (April 1949) (Exhibit 7(a),
File No. 2-7909).
4.1.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-7909).
4.1.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-7909).
4.1.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1,
File No. 2-7909).
4.1.5 Seventh Supplemental on Form 10-Q (June 1992) (Exhibit 1,
File No. 2-7909).
<PAGE>
Exhibit 10. Material Contracts.
- ---------- ------------------
10.1 Power Contracts.
10.1.1 Power Contract between CEC and CEL dated December 1, 1965 (Exhibit
13(a)(1) to the CEC Form S-1, File No. 2-30057).
10.1.2 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 produced and other provisions (Exhibit 1 to the CEC Form 10-Q
(March 1990), File No. 2-30057).
10.1.3 Agreement for Joint-Ownership, Construction and Operation of the New
Hampshire Nuclear Units (Seabrook) between CE, Public Service Company
of New Hampshire (PSNH) and others dated May 1, 1973 and filed by CE
as Exhibit 13(N) on Form S-1 dated October 1973, File No. 2-49013,
and as amended below:
10.1.3.1 First through Fifth Amendments to 10.1.3 dated May 24, 1974, June 21,
1974, September 25, 1975, October 25, 1974 and January 31, 1975,
respectively (Exhibit 13(m) to CE's Form S-1, (November 7, 1975),
File No. 2-54995).
10.1.3.2 Sixth through Eleventh Amendments to 10.1.3 dated April 18, 1979,
April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and
December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC
Form 10-K for 1989, File No. 2-30057).
10.1.3.3 Twelfth through Fourteenth Amendments to 10.1.3 dated May 16, 1980,
December 31, 1980 and June 1, 1982, respectively (Refiled as Exhibits
1, 2 and 3 to the CE 1992 Form 10-K), File No. 2-7749).
10.1.3.4 Fifteenth and Sixteenth Amendment to 10.1.3 dated April 27, 1984 and
June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-Q (June
1984), File No. 2-30057).
10.1.3.5 Seventeenth Amendment to 10.1.3 dated March 8, 1985 (Exhibit 1 to the
CEC Form 10-Q (March 1985), File No. 2-30057).
10.1.3.6 Eighteenth Amendment to 10.1.3 dated March 14, 1986 (Exhibit 1 to the
CEC Form 10-Q (March 1986), File No. 2-30057).
10.1.3.7 Nineteenth Amendment to 10.1.3 dated May 1, 1986 (Exhibit 1 to the
CEC Form 10-Q (June 1986), File No. 2-30057).
10.1.3.8 Twentieth Amendment to 10.1.3 dated September 19, 1986 (Exhibit 1 to
the CEC Form 10-K for 1986, File No. 2-30057).
10.1.3.9 Twenty-First Amendment to 10.1.3 dated November 12, 1987 (Exhibit 1
to the CEC Form 10-K for 1989, File No. 2-30057).
<PAGE>
10.1.3.10 Twenty-Second Amendment and Settlement Agreement to 10.1.3 both dated
January 13, 1989, (Exhibit 4 to the CEC Form 10-K for 1988, File No.
2-30057).
10.1.4 Capacity Acquisition Agreement between CEC, CEL and CE dated
September 25, 1980 (Exhibit 1 to the 1991 CEC Form 10-K,
File No. 2-30057).
10.1.4.1 Amendment to 10.1.4 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 the Company and/or CE owns or otherwise has
the right to sell (Exhibit 1 to CE's Form 10-Q (September 1993), File
No. 2-30057).
10.1.5 Power Contract between Yankee Atomic Electric Company and CEL, dated
June 30, 1959, as amended April 1, 1975 (Exhibit 1 to the CEL
Form 10-K, File No. 2-7909).
10.1.5.1 Second, Third and Fourth Amendments to 10.1.5 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the
CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.5.2 Fifth and Sixth Amendments to 10.1.5 as amended June 26, 1989 and
July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (September
1989), File No. 2-7909).
10.1.6 Power Contract between Connecticut Yankee Atomic Power Company and
CEL dated July 1, 1964 (Exhibit 13-K1 to the CES Form S-1, (April
1967) File No. 2-25597).
10.1.6.1 Additional Power Contract to 10.1.6 providing for extension on the
contract term dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q
(June 1984), File No. 2-7909).
10.1.6.2 Second Supplementary Power Contract to 10.1.6 providing for
decommissioning financing dated April 30, 1984 (Exhibit 6 to the CEL
Form 10-Q (June 1984), File No. 2-7909).
10.1.7 Power Contract between CEL and Vermont Yankee Nuclear Power
Corporation dated February 1, 1968 (Exhibit 3 to the CEL 1984
Form 10-K, File No. 2-7909).
10.1.7.1 First Amendment (Section 7) and Second Amendment (decommissioning
financing) to 10.1.7 as amended June 1, 1972 and April 15, 1983,
respectively (Exhibits 1 and 2, respectively, to the CEL Form 10-Q
(June 1984), File No. 2-7909).
10.1.7.2 Third and Fourth Amendments to 10.1.7 as amended April 1, 1985 and
June 1, 1985, respectively (Exhibit 1 and 2 to the CEL Form 10-Q
(June 1986) File No. 2-7909).
10.1.7.3 Fifth and Sixth Amendments to 10.1.7 both as amended May 6, 1988
(Exhibit 1 to the CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.7.4 Seventh Amendment to 10.1.7 as amended June 15, 1989 (Exhibit 2 to
the CEL Form 10-Q (September 1989), File No. 2-7909).
10.1.7.5 Additional Power Contract between CEL and Vermont Yankee Nuclear
Power Corporation providing for decommissioning financing and
contract extension dated February 1, 1984 (Refiled as Exhibit 1 to
the 1993 CEL Form 10-K, File No. 2-7909).
<PAGE>
10.1.8 Power Contract between Maine Yankee Atomic Power Company and CEL
dated May 20, 1968 (Exhibit 5 to the CES Form S-7, File No. 2-38372).
10.1.8.1 First Amendment (decommissioning financing) and Second Amendment
(supplementary payments) to 10.1.9 as amended March 1, 1984 and
January 1, 1984, respectively (Exhibits 3 and 4 to the CEL Form 10-Q
(June 1984), File No. 2-7909).
10.1.8.2 Third Amendment to 10.1.8 as amended October 1, 1984 (Exhibit 1 to
the CEL Form 10-Q (September 1984), File No. 2-7909).
10.1.9 Participation Agreement between Maine Electric Power Company and CEL
and/or NBGEL for the construction of a 345 KV transmission line
between Wiscasset, Maine and Mactaquac, New Brunswick, Canada and for
the purchase of base and peaking capacity from the New Brunswick
Electric Power Commission, dated June 20, 1969 (Exhibit 13 to the CES
Form 10-K for 1984, File No. 1-7316).
10.1.9.1 Supplement Amending 10.1.9, as amended June 24, 1970 (Exhibit 8 to
the CES Form S-7, Amendment No. 1, File No. 2-38372).
10.1.10 Service Agreement for Non-Firm Transmission Service between Boston
Edison Company and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984
Form 10-K, File No. 2-7909).
10.1.11 Agreement, dated September 1, 1985, With Respect To Amendment of
Agreement With Respect To Use Of Quebec Interconnection, dated
December 1, 1981, among certain New England Power Pool (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).
10.1.11.1 Amendatory Agreement No. 3 to 10.1.11, as amended June 1, 1990
(Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.12 Preliminary Quebec Interconnection Support Agreement - Phase II among
certain NEPOOL utilities, dated June 1,1984 (Exhibit 6 to the CE Form
10-Q (June 1984), File No. 2-7749).
10.1.12.1 First, Second and Third Amendments to 10.1.12 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).
10.1.12.2 Fourth and Eighth Amendments to 10.1.12 as amended July 1, 1987 and
August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.12.3 Fifth, Sixth and Seventh Amendments to 10.1.12 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).
10.1.12.4 Ninth and Tenth Amendments to 10.1.12 as amended November 1, 1988 and
January 15, 1989, respectively (Exhibit 2 to the CEC Form 10-K for
1988, File No. 2-30057).
10.1.12.5 Eleventh Amendment to 10.1.12 as amended November 1, 1989 (Exhibit 4
to the CEC Form 10-K for 1989, File No. 2-30057).
<PAGE>
10.1.12.6 Twelfth Amendment to 10.1.12 as amended April 1, 1990 (Exhibit 1 to
the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.13 Agreement to Preliminary Quebec Interconnection Support Agreement -
Phase II among PSNH, New England Power Company, Boston Edison Company
and CEC whereby PSNH assigns a portion of its interests under the
original Agreement to the other three parties, dated October 1, 1987
(Exhibit 2 to the CEC 1987 Form 10-K, File No. 2-30057).
10.1.14 Phase II Equity Funding Agreement for New England Hydro-Transmission
Electric Company, Inc. (New England Hydro (Massachusetts) between
New England Hydro and certain NEPOOL utilities, dated June 1, 1985
(Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.15 Phase II Equity Funding Agreement for New England Hydro-Transmission
Corporation (New Hampshire Hydro) between New Hampshire Hydro and
certain NEPOOL utilities, dated June 1, 1985 (Exhibit 3 to the CEC
Form 10-Q (September 1985), File No. 2-30057).
10.1.15.1 Amendment No. 1 to 10.1.15 as amended May 1, 1986 (Exhibit 6 to the
CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.15.2 Amendment No. 2 to 10.1.15 as amended September 1, 1987 (Exhibit 3 to
the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.16 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-Transmission Electric
Company, Inc. (New England Hydro) and certain NEPOOL utilities
(Exhibit 2 the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.17 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).
10.1.18 Phase II New England Power AC Facilities Support Agreement between
New England Power and certain NEPOOL utilities, dated June 1, 1985
(Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.18.1 Amendments Nos. 1 and 2 to 10.1.18 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March
1987), File No. 2-30057).
10.1.18.2 Amendments Nos. 3 and 4 to 10.1.18 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.19 Phase II Boston Edison AC Facilities Support Agreement between Boston
Edison Company and certain NEPOOL utilities, dated June 1, 1985
(Exhibit 7 to the CEC Form 10-Q (September 1985), File No. 2-30057).
<PAGE>
10.1.19.1 Amendments Nos. 1 and 2 to 10.1.19 as amended May 1, 1986 and
February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q
(March 1987), File No. 2-30057).
10.1.19.2 Amendments Nos. 3 and 4 to 10.1.19 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.20 Agreement Authorizing Execution of Phase II Firm Energy Contract
among certain NEPOOL utilities in regard to participation in the
purchase of power from Hydro Quebec, dated September 1, 1985 (Exhibit
8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.21 System Power Sales Agreement by and between Connecticut Light and
Power (CL&P), Western Massachusetts Electric Company (Northeast
Utilities companies), as sellers, and CEL, as buyer, of power in
excess of firm power customer requirements from the electric systems
of the Northeast Utilities companies, dated June 1, 1984, as
effective October 25, 1985 (Exhibit 1 to the CEL 1985 Form 10-K,
File No. 2-7909).
10.1.22 Power Sale Agreement by and between Altresco Pittsfield, L. P. and
the Company for entitlement to the electric capacity and related
energy to be produced by a cogeneration facility located in
Pittsfield, Massachusetts, dated February 20, 1992 (Exhibit 1 to the
CEL Form 10-Q (September 1993), File No. 2-7909).
10.1.22.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., the
Company, CE and New England Power Company, dated July 2, 1993
(Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749).
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 (September 1993), File No. 1-7316).
10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsidiary
Companies as amended and restated January 1, 1993 (Exhibit 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 the 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 the 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 the CES
Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
<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 the CES
Form 10-K/A Amendment No. 1 (April 29, 1998), File No. 1-7316).
10.2.3 NEPOOL Agreement 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 the CES Form S-16 (April 1980),
File No. 2-64731).
10.2.3.1 Thirteenth Amendment to 10.2.3 dated September 1, 1981 (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 (September 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 January 1, 1986
(Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316).
10.2.3.5 Twenty-third Amendment to 10.2.3 as amended 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 1987 Form 10-K, File No. 1-7316).
10.2.3.7 Twenty-fifth Amendment to 10.2.3 as amended May 1, 1988 (Exhibit 1 to
the CES Form 10-Q (March 1988), File No. 1-7316).
10.2.3.8 Twenty-sixth Amendment 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 Amendment 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 Amendment 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 Amendment to 10.2.3 as amended May 1, 1993 (Exhibit 2 to
the CES Form 10-Q (September 1994), File No. 1-7316).
10.2.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as
initial lender) covering the unconditional guarantee of a portion of
the payment obligations of Maine Yankee Atomic Power Company under a
loan agreement and note initially between Maine Yankee and MYA Fuel
Company (Exhibit 3 to the CEL 1985 Form 10-K, File No. 2-7909).
Exhibit 27. Financial Data Schedule
- ---------- -----------------------
Filed herewith is the Financial Data Schedule for the twelve months ended
December 31, 1999
<PAGE>
SCHEDULE II
CAMBRIDGE ELECTRIC LIGHT COMPANY
--------------------------------
VALUATION AND QUALIFYING ACCOUNTS
---------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND
-----------------------------------------------
(Dollars in Thousands)
<TABLE>
<CAPTION>
Additions
---------------------- Deductions
Balance at Provision ----------- Balance
Beginning Charged to Accounts End
Description of Year Operations Recoveries Written Off of Year
----------- ---------- ---------- ---------- ----------- -------
<CAPTION>
Year Ended December 31, 1999
------------------------------------
<S> <C> <C> <C> <C> <C>
Allowance for
Doubtful Accounts $465 $205 $ 98 $358 $410
==== ==== ===== ==== ====
<CAPTION>
Year Ended December 31, 1998
------------------------------------
<S> <C> <C> <C> <C> <C>
Allowance for
Doubtful Accounts $297 $560 $ 101 $493 $465
==== ==== ===== ==== ====
<CAPTION>
Year Ended December 31, 1997
------------------------------------
<S> <C> <C> <C> <C> <C>
Allowance for
Doubtful Accounts $482 $343 $ 49 $577 $297
==== ==== ===== ==== ====
</TABLE>
- 2 -
<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.
CAMBRIDGE ELECTRIC LIGHT 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
- 3 -
<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 CAMBRIDGE ELECTRIC LIGHT COMPANY FOR FISCAL YEAR
ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
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> 97,019
<OTHER-PROPERTY-AND-INVEST> 9,864
<TOTAL-CURRENT-ASSETS> 38,257
<TOTAL-DEFERRED-CHARGES> 66,036
<OTHER-ASSETS> 80,601
<TOTAL-ASSETS> 291,777
<COMMON> 8,665
<CAPITAL-SURPLUS-PAID-IN> 92,395
<RETAINED-EARNINGS> 880
<TOTAL-COMMON-STOCKHOLDERS-EQ> 101,940
0
0
<LONG-TERM-DEBT-NET> 27,201
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 100
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 162,536
<TOT-CAPITALIZATION-AND-LIAB> 291,777
<GROSS-OPERATING-REVENUE> 111,769
<INCOME-TAX-EXPENSE> (795)
<OTHER-OPERATING-EXPENSES> 108,121
<TOTAL-OPERATING-EXPENSES> 107,326
<OPERATING-INCOME-LOSS> 4,443
<OTHER-INCOME-NET> 1,207
<INCOME-BEFORE-INTEREST-EXPEN> 5,650
<TOTAL-INTEREST-EXPENSE> 6,095
<NET-INCOME> (445)
0
<EARNINGS-AVAILABLE-FOR-COMM> (445)
<COMMON-STOCK-DIVIDENDS> 9,532
<TOTAL-INTEREST-ON-BONDS> 912
<CASH-FLOW-OPERATIONS> (100)
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
