Annual Report 1995
Massachusetts Electric Company
A Subsidiary of
New England Electric System
[LOGO] Massachusetts Electric
A NEES Company
Massachusetts Electric Company
25 Research Drive,
Westborough, Massachusetts 01582
Directors
(As of December 31, 1995)
Urville J. Beaumont
Treasurer and Director, Beaumont and Campbell, P.A. (Attorneys), Salem, New
Hampshire
Joan T. Bok
Chairman of the Board of New England Electric System
Sally L. Collins
Director, Workplace Health Services, Greenfield, Massachusetts
John H. Dickson
President and Chief Executive Officer of the Company
Dr. Kalyan K. Ghosh
President, Worcester State College
Charles B. Housen
Chairman and President, Erving Industries, Erving, Massachusetts
Patricia McGovern
Of Counsel, Goulston and Storrs, P.C., Boston, Massachusetts
John F. Reilly
President and Chief Executive Officer of Fred C. Church, Inc., Lowell,
Massachusetts
John W. Rowe
President and Chief Executive Officer of New England Electric System
Richard P. Sergel
Chairman of the Company and Vice President of New England Electric System
Richard M. Shribman
Treasurer, Norick Realty Corporation, Salem, Massachusetts
Roslyn M. Watson
President, Watson Ventures, Boston, Massachusetts
Officers
(As of December 31, 1995)
Richard P. Sergel
Chairman of the Company and Vice President of New England Electric System
John H. Dickson
President and Chief Executive Officer
John C. Amoroso
Vice President
Eric P. Cody
Vice President
Peter H. Gibson
Vice President
Gregory A. Hale
Vice President
Cheryl A. LaFleur***
Vice President
Charles H. Moser
Vice President
Lydia M. Pastuszek
Vice President of the Company and President of an affiliate
Anthony C. Pini
Vice President
Thomas E. Rogers**
Vice President
Christopher E. Root
Vice President
Nancy H. Sala
Vice President
Dennis E. Snay
Vice President
Michael E. Jesanis
Treasurer of the Company and of New England Electric System
Robert King Wulff
Clerk of the Company and of certain
affiliates
Howard W. McDowell
Controller and Assistant Treasurer of
the Company and Controller of certain affiliates
Frederic E. Greenman*
Assistant Clerk and General Counsel of the Company and Senior Vice President,
General Counsel, and Secretary of New England Electric System
Thomas G. Robinson**
Assistant Clerk and General Counsel of the Company
* retired December 31, 1995
** elected effective December 31, 1995
*** resigned effective December 31, 1995
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock
State Street Bank and Trust Company, Boston, Massachusetts
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
Massachusetts Electric Company
Massachusetts Electric Company is a wholly-owned subsidiary of New England
Electric System operating in Massachusetts. The Company's business is the
distribution and sale of electricity at retail. Electric service is provided
to approximately 950,000 customers in 146 cities and towns having a population
of approximately 2,160,000 (1990 Census). The Company's service area covers
approximately 43 percent of Massachusetts. The cities and towns served by the
Company include the highly diversified commercial and industrial cities of
Worcester, Lowell, and Quincy, the Interstate 495 high technology belt,
suburban communities, and many rural towns. The principal industries served
include computer manufacturing and related businesses, electrical and
industrial machinery, plastic goods, fabricated metals and paper, and chemical
products. In addition, a broad range of professional, banking, medical, and
educational institutions is served. There are a number of proposals that
would increase competition in the electric utility industry and result in
customers having a choice of power suppliers (see "Financial Review").
The properties of the Company consist principally of substations and
distribution lines interconnected with transmission and other facilities of
New England Power Company (NEP), an affiliate. The Company buys its electric
energy requirements from NEP under a contract which obligates NEP to furnish
such requirements at its standard resale rate. The Company participates
through NEP in the New England Power Pool, which provides for the coordination
of the planning and operation of the generation and transmission facilities in
New England, and the region-wide central dispatch of generation.
Report of Independent Accountants
Massachusetts Electric Company, Westborough, Massachusetts:
We have audited the accompanying balance sheets of Massachusetts Electric
Company (the Company), a wholly-owned subsidiary of New England Electric
System, as of December 31, 1995 and 1994 and the related statements of income,
retained earnings, and cash flows for each of the three years in the period
ended December 31, 1995. 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 the Company as of December
31, 1995 and 1994, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1995 in conformity
with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
March 1, 1996
Massachusetts Electric Company
Financial Review
Overview
Net income for 1995 decreased $6 million. Although the Company experienced
growth in sales and reduced operation and maintenance costs, such increases in
income were more than offset by increased purchased power costs, increased
interest expense and a decrease in revenue due to the operation of the
Company's purchased power adjustment (PPCA) mechanism.
Net income for 1994 increased by $11 million compared with 1993. The
increase was primarily due to the inclusion in 1993 of one-time charges
associated with an early retirement program and the establishment of
additional gas waste reserves. In addition, the increase in 1994 earnings
reflects increased kilowatt-hour (kWh) sales. These factors were partially
offset by increased operation and maintenance expenses excluding the effect of
the one-time charges discussed above.
Competitive Conditions
The electric utility business is being subjected to rapidly increasing
competitive pressures, stemming from a combination of trends, including the
presence of surplus generating capacity, a disparity in electric rates among
regions of the country, improvements in generation efficiency, increasing
demand for customer choice, and new regulations and legislation intended to
foster competition. To date, this competition has been most prominent in the
bulk power market, in which non-utility generators have significantly
increased their market share. Electric utilities have had exclusive
franchises for the retail sale of electricity in specified service
territories. As a result, competition in the retail market has been limited
to (i) competition with alternative fuel suppliers, primarily for heating and
cooling, (ii) competition with customer-owned generation, and (iii) direct
competition among electric utilities to attract major new facilities to their
service territories. These competitive pressures have led the Company and
other utilities to offer, from time to time, special discounts or service
packages to certain large customers.
In states across the country, including Massachusetts, there have been an
increasing number of proposals to allow retail customers to choose their
electricity supplier, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems (also known as
"retail wheeling"). If electric customers were allowed to choose their
electricity supplier, the Company's role would change and it would provide
only distribution services. Power would be provided by power generators and
marketers, which could be either affiliated or non-affiliated companies. In
these competitive circumstances, utilities across the country that operate
generation plants, such as the Company's affiliate, New England Power Company
(NEP), would face the risk that market prices may not be sufficient to recover
the costs of the commitments incurred to supply customers under a regulated
industry structure. The amount by which costs exceed market prices is
commonly referred to as "stranded costs."
The Company purchases electricity on behalf of its customers under a
wholesale all-requirements contract with NEP. NEP derives approximately 72
percent of its electric sales revenues from sales to the Company.
Choice: New England
In October 1995, the New England Electric System (NEES) companies announced
a plan to allow all customers of electric utilities in Massachusetts, Rhode
Island, and New Hampshire to choose their power supplier beginning in 1998.
The plan, Choice: New England, was developed in response to 1995 decisions by
the Massachusetts Department of Public Utilities (MDPU) and the Rhode Island
Public Utilities Commission that approved a set of principles for industry
restructuring. These principles include allowing utilities the opportunity to
recover stranded costs. Choice: New England was formally filed with the MDPU
in February 1996.
Under Choice: New England, the Company would no longer sell electricity to
its customers. Instead, customers would purchase electricity from a supplier
of their choice, with the Company remaining responsible for providing
distribution services to customers under regulated rates. Transmission
services would be provided by a new affiliate of the Company, which would be
formed by NEES to provide comparable service across the NEES companies'
transmission system.
Under Choice: New England, the pricing of generation would be deregulated.
However, customers would have the right to receive service under a "standard
offer" from the incumbent utility or its affiliate, the pricing of which would
be approved in advance by legislators or regulators. Customers electing the
standard offer would be eligible to choose an alternative power supplier at
any time, but would not be allowed to return to the standard offer.
Under Choice: New England, the Company's wholesale contract with NEP would
be terminated. In return, Choice: New England proposes that the cost of NEP's
past generation commitments be recovered from the Company and its retail
affiliates through a contract termination charge. The Company would, in turn,
seek to recover the payments to NEP through a wires access or transition
charge to retail customers. Those commitments primarily consist of (i)
generating plant commitments, (ii) regulatory assets, (iii) purchased power
contracts, and (iv) the operating cost of nuclear plants which cannot be
mitigated by shutting down the plants (otherwise referred to as "nuclear costs
independent of operation"). The portion of these commitments incurred by NEP
to serve the Company's customers is currently estimated at approximately $3
billion on a present value basis. Sunk costs associated with utility
generating plants, such as past capital investments, and regulatory assets
would be recovered over ten years. Purchased power contract costs and nuclear
costs independent of operation would be recovered as incurred over the life of
those obligations, a period expected to extend beyond ten years. The access
charge would be set at three cents per kWh for the first three years.
Thereafter, the access charge would vary, but is expected to decline. The
provisions of Choice: New England, including the proposed access charge, are
subject to state approval and Federal Energy Regulatory Commission (FERC)
approval.
In March 1996, the Company filed a request with the MDPU to allow the
implementation of two pilot programs to test the plan. The first would allow
certain high technology customers in Massachusetts representing 1 percent of
the NEES companies' retail sales to have direct access to alternative power
suppliers beginning in July 1996. The second would allow residential and
small business customers in Massachusetts representing 0.5 percent of the NEES
companies' retail sales to have direct access beginning September 1, 1996.
Three other utilities and the Massachusetts Division of Energy Resources
(DOER) also filed plans with the MDPU in February 1996. The DOER's plan also
calls for direct access for all customers beginning in 1998 with a pilot
program beginning in 1997. The DOER plan, however, proposes that, in exchange
for stranded cost recovery, utilities divest their generating assets, either
through sale or spinoff. The NEES companies do not support the DOER mandatory
divestiture proposal. The MDPU is expected to issue regulations on industry
restructuring in September 1996 and to issue orders on the individual utility
plans in 1997.
Other Legislative and Regulatory Initiatives
In February 1996, the MDPU denied the recovery of stranded power generation
costs in the context of the town of Stow, Massachusetts attempting to purchase
the distribution assets in that town owned by the neighboring Hudson Municipal
Light Department. Although the MDPU reaffirmed its general position that
utilities should have a reasonable opportunity to recover net, non-mitigable,
stranded costs, it refused to allow recovery in this case stating that Hudson
had not sufficiently demonstrated that stranded costs would be incurred and
made no effort to mitigate any such costs. Both parties have appealed the
MDPU decision and the MDPU has stayed its decision pending appeal.
In August 1995, the MDPU issued an order requiring a customer of another
utility who installed cogenerating equipment to pay 75 percent of that
utility's stranded costs attributable to serving the customer's load. The
MDPU indicated the decision did not set a precedent for stranded cost recovery
as part of industry restructuring. In March 1996, the FERC ruled that it
would not review the MDPU's decision. The customer is expected to appeal the
decision to the courts.
In March 1995, the FERC issued a Notice of Proposed Rulemaking in which it
stated that it is appropriate that legitimate and verifiable stranded costs be
recovered from departing customers as a result of wholesale competition. The
FERC also indicated that costs stranded as a result of retail competition
would be subject to state commission review if the necessary statutory
authority exists and subject to FERC review if the state commission does not
have such authority. A final decision is expected during 1996.
Risk Factors
The major risk factors affecting the Company relate to the possibility of
adverse regulatory decisions or legislation which limit the level of revenues
the Company is allowed to charge for its services. The Company's
all-requirements purchased power contract with NEP requires either party to
give seven years notice prior to terminating the contract. Termination of the
contract would create stranded costs at NEP that NEP would seek to recover
from the Company pursuant to the contract. In that event, the Company would
seek recovery of such stranded costs from its customers. However, there is no
assurance that the final restructuring plans ordered by state regulatory
bodies or state legislatures will include provisions that allow the Company to
fully recover any stranded costs passed on to the Company by NEP. In such an
event, the Company could be faced with a significant amount of costs being
billed to it by NEP that the Company could not fully recover from retail
customers, for which the Company would seek a remedy in the courts. In
addition, there is no assurance that any performance incentive system, which
regulators might ultimately adopt with respect to the Company's distribution
activities, would allow the Company to fully recover prudently incurred costs
and earn a reasonable return on investment.
Historically, electric utility rates have been based on a utility's costs.
As a result, electric utilities are subject to certain accounting standards
that are not applicable to other business enterprises in general. Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets and liabilities, and thereby
defer the income statement impact of certain costs that are expected to be
recovered in future rates. The effects of regulatory, legislative, or utility
initiatives could, in the near future, cause all or a portion of the Company's
operations to cease meeting the criteria of FAS 71. In that event, the
application of FAS 71 to such operations would be discontinued and a non-cash
write-off of previously established regulatory assets and liabilities related
to such operations would be required. At December 31, 1995, the Company had
pre-tax regulatory assets (net of regulatory liabilities) of approximately $54
million. If competitive or regulatory change should cause a substantial
revenue loss, a write-down of plant assets could be required pursuant to
Financial Accounting Standards No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (FAS 121). In
addition, FAS 121 requires that all regulatory assets, which must have a high
probability of recovery to be initially established, must continue to meet
that high probability standard to avoid being written off. FAS 121, which is
effective for the Company in January 1996, is not expected to have a material
adverse impact on the financial condition or results of operations upon
adoption, based on the current regulatory environment in which the Company
operates. However, the impact in the future may change as competitive factors
and potential restructuring influence the electric utility industry. For
further discussion, see Note B.
Rate Activity
The MDPU approved a $31 million increase to base rates for the Company
effective October 1, 1995.
In 1993, the MDPU approved a rate agreement filed by the Company, the
Massachusetts Attorney General, and two groups of large commercial and
industrial customers. Under the agreement, effective December 1, 1993, the
Company implemented an 11 month general rate decrease of $26 million (annual
basis). This rate reduction continued in effect through October 31, 1994, at
which time rates increased to the previously approved levels. The agreement
also provided for the recognition of electricity delivered but not yet billed
(unbilled revenues) for accounting purposes. Unbilled revenues at September
30, 1993 of approximately $35 million were amortized to income over 13 months
ending December 1994. The agreement further provided for rate discounts for
large commercial and industrial customers who signed agreements to give a
five-year notice to the Company before they purchase power from another
supplier or generate any additional power themselves. In addition, commencing
in 1995, the cost of these discounts is being passed on to NEP as a result of
a NEP rate settlement that was approved by the FERC in early 1995.
The 1993 agreement also resolved all rate recovery issues associated with
environmental remediation costs of Massachusetts manufactured gas waste sites
formerly owned by the Company and its affiliates, as well as certain other
environmental cleanup costs (see "Hazardous Waste" section).
Demand-Side Management (DSM)
The Company has received approval from the MDPU to recover DSM program
expenditures in rates on a current basis. These expenditures were $53
million, $59 million, and $47 million in 1995, 1994, and 1993, respectively.
Since 1990, the Company has been allowed to earn incentives based on the
results of its DSM programs. The Company recorded before-tax incentives of
$5.1 million, $7.1 million, and $6.7 million in 1995, 1994, and 1993,
respectively.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
- ------------------------------------------------------------------------------
(In Millions) 1995 1994
- ------------------------------------------------------------------------------
Sales growth $11 $12
Fuel recovery 38 (16)
PPCA mechanism (11) 7
Rate changes/service extension discount (SEDs) 26 (22)
Unbilled revenues recognized under rate agreement (32) 21
DSM recovery (8) 12
--- ---
$24 $14
In 1995, kWh sales increased by 0.9 percent compared with a 1.8 percent
increase in 1994. Peak demand billing levels to commercial and industrial
customers increased by 2.0 percent in 1995 while remaining flat between 1994
and 1993. The increase in kWh sales in 1995 reflects a warmer summer and a
return to more normal weather conditions in the fourth quarter of 1995,
partially offset by mild weather in the first quarter of 1995.
The Company's rates contain a fuel clause and a PPCA provision. These
mechanisms are designed to allow the Company to pass on to its customers
changes in purchased energy costs resulting from rate increases or decreases
by NEP. The PPCA mechanism is also designed to pass on to customers the
effects of NEP's seasonal rates. Although the Company experienced an increase
in purchased power costs in 1995, NEP's seasonal rates reduced the impact of
this increase. The passback to customers of this benefit is reflected as a
reduction in revenues under the PPCA mechanism.
Rate changes in 1995 reflect the November 1994 expiration of a temporary
rate decrease, as well as a general rate increase, that went into effect on
October 1, 1995.
Unbilled revenues recognized under the Company's rate agreement reflect the
Company's completion of the recognition of $35 million of unbilled revenues
over a 13 month period that ended in December 1994 in accordance with an
October 1993 rate agreement.
Operating Expenses
The following table summarizes the changes in operating expenses:
Increase (Decrease) in Operating Expenses
- ------------------------------------------------------------------------------
(In Millions) 1995 1994
- ------------------------------------------------------------------------------
Purchased electric energy:
Fuel costs $38 $(16)
SED reimbursements (9)
Purchases and demand charges from NEP 10 4
NEP refunds 4
Other operation and maintenance:
DSM (6) 11
Other (9) (17)
Depreciation 2 2
Taxes (1) 13
--- ---
$25 $1
The 1995 increase in fuel costs from NEP reflects decreased nuclear
generation due to overhauls and decreased hydro production resulting from low
water levels. The decrease in the fuel cost component of purchased power in
1994 includes a decrease in the amount of New England Energy Incorporated's
(NEEI) costs passed through by NEP. NEEI is an affiliated company involved in
oil and gas exploration and development.
The reduction in other operation and maintenance expenses in 1995 reflects
decreased distribution line-related expenses. This decrease was partially
offset by increased postretirement benefit expenses commensurate with
additional amounts being recovered from customers.
The decrease in other operation and maintenance expenses in 1994 was
primarily the result of one-time charges in 1993 of $26 million for the
establishment of additional gas waste reserves and $13 million associated with
an early retirement program, partially offset by the effects, in 1993, of the
Company's rate agreement which allowed recovery of amounts previously charged
to expense (see "Rate Activity" section). Other operation and maintenance
expenses in 1994 also included increased computer system development costs,
increased postretirement benefit expenses, and general increases in other
areas.
The decrease in taxes in 1995 was primarily due to decreased income,
partially offset by increased municipal property taxes. The increase in taxes
in 1994 reflects increased income and increased municipal property taxes.
Hazardous Waste
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict,
joint and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates a range
of potentially hazardous products and by-products in its operations. NEES
subsidiaries currently have an environmental audit program in place intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for 18 sites at which hazardous waste
is alleged to have been disposed. Private parties have also contacted or
initiated legal proceedings against the Company regarding hazardous waste
cleanup. The most prevalent types of hazardous waste sites with which the
Company has been associated are manufactured gas locations. The Company is
aware of approximately 35 such locations in Massachusetts (including seven of
the 18 locations for which the Company is a PRP). The Company is currently
aware of other sites, and may in the future become aware of additional sites,
that it may be held responsible for remediating.
In 1993, the MDPU approved a rate agreement filed by the Company (see "Rate
Activity" section) that allows for remediation costs of former manufactured
gas sites and certain other hazardous waste sites located in Massachusetts to
be met from a non-rate-recoverable, interest-bearing fund of $30 million
established on the Company's books in 1993. Rate-recoverable contributions of
$3 million, adjusted for inflation, are added to the fund annually in
accordance with the agreement. Any shortfalls in the fund would be paid by
the Company and be recovered through rates over seven years.
Predicting the potential costs to investigate and remediate hazardous waste
sites continues to be difficult. There are also significant uncertainties as
to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by the Company.
Where appropriate, the Company intends to seek recovery from its insurers and
from other PRPs, but it is uncertain whether, and to what extent, such efforts
will be successful. At December 31, 1995, the Company had total reserves for
environmental response costs of $39 million and a related regulatory asset of
$16 million. The Company believes that hazardous waste liabilities for all
sites of which it is aware, and which are not covered by a rate agreement, are
not material to its financial position.
Electric and Magnetic Fields (EMF)
Concerns have been raised about whether EMF, which occur near transmission
and distribution lines as well as near household wiring and appliances, cause
or contribute to adverse health effects. Numerous studies on the effects of
these fields, some of them sponsored by electric utilities (including NEES
companies), have been conducted and are continuing. Some of the studies have
suggested associations between certain EMF and health effects, including
various types of cancer, while other studies have not substantiated such
associations. It is impossible to predict the ultimate impact on the Company
and the electric utility industry if further investigations were to
demonstrate that the present electricity delivery system is contributing to
increased risk of cancer or other health problems.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In any
event, the Company believes that it currently has adequate insurance coverage
for personal injury claims.
Several state courts have recognized a cause of action for damage to
property values in transmission line condemnation cases based on the fear that
power lines cause cancer. It is difficult to predict what the impact on the
Company would be if this cause of action is recognized in Massachusetts and in
contexts other than condemnation cases.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $90 million in 1995. The funds
necessary for utility plant expenditures during 1995 were primarily provided
by net cash from operating activities, after the payment of dividends,
long-term debt issues, and capital contributions from NEES. Cash expenditures
for utility plant for 1996 are estimated to be approximately $105 million.
Internally generated funds are expected to meet approximately 70 percent of
capital expenditure requirements in 1996.
In 1995, the Company issued $88 million of first mortgage bonds, bearing
interest rates ranging from 6.72 percent to 8.46 percent. The Company plans
to issue $20 million of long-term debt in 1996 to fund capital expenditures.
At December 31, 1995, the Company had $55 million of short-term debt
outstanding including $54 million of commercial paper borrowings and $1
million of borrowings from affiliates. As of December 31, 1995, the Company
had lines of credit with banks totaling $90 million which are available to
provide liquidity support for commercial paper borrowings and other corporate
purposes. There were no borrowings under these lines of credit at December
31,1995.
March 25, 1996
Massachusetts Electric Company
Statements of Income
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Operating revenue $1,505,676 $1,482,070 $1,468,540
---------- ---------- ----------
Operating expenses:
Purchased electric energy, principally
from New England Power Company,
an affiliate 1,113,673 1,074,402 1,081,918
Other operation 206,660 215,794 229,438
Maintenance 29,525 35,502 28,168
Depreciation 44,829 42,775 40,848
Taxes, other than income taxes 30,022 28,664 26,527
Income taxes 19,297 22,265 11,055
---------- ---------- ----------
Total operating expenses 1,444,006 1,419,402 1,417,954
---------- ---------- ----------
Operating income 61,670 62,668 50,586
Other income (expense), net (541) (995) (64)
---------- ---------- ----------
Operating and other income 61,129 61,673 50,522
---------- ---------- ----------
Interest:
Interest on long-term debt 25,901 20,967 23,403
Other interest 6,784 6,366 3,638
Allowance for borrowed funds used during
construction credit (657) (386) (298)
---------- ---------- ----------
Total interest 32,028 26,947 26,743
---------- ---------- ----------
Net income $29,101 $34,726 $23,779
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Retained earnings at beginning of year $136,911 $135,276 $134,670
Net income 29,101 34,726 23,779
Dividends declared on cumulative
preferred stock (3,114) (3,114) (3,772)
Dividends declared on common
stock, $5.25, $12.50, and $7.75
per share, respectively (12,590) (29,977) (18,585)
Premium on redemption of preferred stock (816)
-------- -------- --------
Retained earnings at end of year $150,308 $136,911 $135,276
======== ======== ========
The accompanying notes are an integral part of these financial statements.
Massachusetts Electric Company
Balance Sheets
At December 31, (In Thousands) 1995 1994
Assets ---------- ----------
Utility plant, at original cost $1,420,069 $1,346,824
Less accumulated provisions for depreciation 399,711 373,501
---------- ----------
1,020,358 973,323
Construction work in progress 21,118 22,672
---------- ----------
Net utility plant 1,041,476 995,995
---------- ----------
Current assets:
Cash 1,840 1,225
Accounts receivable:
From sales of electric energy 160,795 137,431
Other (including $1,776 and $6,609
from affiliates) 3,527 36,022
Less reserves for doubtful accounts 12,544 10,394
---------- ----------
151,778 163,059
Unbilled revenues (Note A-3) 49,800 42,800
Materials and supplies, at average cost 10,602 11,524
Prepaid and other current assets 22,514 21,583
---------- ----------
Total current assets 236,534 240,191
---------- ----------
Deferred charges and other assets (Note B) 65,090 59,536
---------- ----------
$1,343,100 $1,295,722
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $25 per share,
authorized and outstanding 2,398,111 shares $59,953 $59,953
Premiums on capital stocks 45,862 45,862
Other paid-in capital 155,310 141,310
Retained earnings 150,308 136,911
---------- ----------
Total common equity 411,433 384,036
Cumulative preferred stock (Note G) 50,000 50,000
Long-term debt 353,267 265,631
---------- ----------
Total capitalization 814,700 699,667
---------- ----------
Current liabilities:
Long-term debt due in one year 35,000
Short-term debt (including $1,000 and $8,650
to affiliates) 55,450 81,820
Accounts payable (including $165,515 and
$157,076 to affiliates) 181,943 182,102
Accrued liabilities:
Taxes 7,371 906
Interest 9,502 7,945
Other accrued expenses (Note F) 17,136 27,132
Customer deposits 4,633 4,985
Dividends payable 1,977 13,968
---------- ----------
Total current liabilities 278,012 353,858
---------- ----------
Deferred federal and state income taxes 184,575 176,913
Unamortized investment tax credits 17,684 18,816
Other reserves and deferred credits 48,129 46,468
Commitments and contingencies (Note D)
---------- ----------
$1,343,100 $1,295,722
========== ==========
The accompanying notes are an integral part of these financial statements.
Massachusetts Electric Company
Statements of Cash Flows
Year Ended December 31, (In Thousands) 1995 1994 1993
Operating activities: ---- ---- ----
Net income $29,101 $ 34,726 $ 23,779
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation 44,829 42,775 40,848
Deferred income taxes and
investment tax credits, net 6,666 28,909 3,126
Allowance for borrowed funds
used during construction (657) (386) (298)
Amortization of unbilled revenues (32,300) (2,700)
Early retirement program 7,665
Decrease (increase) in accounts
receivable, net and unbilled revenues 4,281 (7,580) (46,434)
Decrease (increase) in materials and
supplies 922 (923) (682)
Decrease (increase) in prepaid and
other current assets (931) (1,593) 6,229
Increase (decrease) in accounts payable (159) 3,985 (9,112)
Increase (decrease) in other current
liabilities (2,326) (10,379) 32,507
Other, net (2,340) (12,982) 14,723
------- ------- -------
Net cash provided by operating
activities $79,386 $44,252 $69,651
------- ------- -------
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $(89,735) $(94,105) $(80,473)
Other investing activities (1,972) (4,892)
------- ------- -------
Net cash used in investing
activities $(91,707) $(98,997) $(80,473)
------- ------- -------
Financing activities:
Capital contributions from parent $14,000 $50,572
Dividends paid on common stock (24,580) $(21,584) (19,185)
Dividends paid on preferred stock (3,114) (3,114) (3,850)
Changes in short-term debt (26,370) 43,895 (7,775)
Long-term debt issues 88,000 36,000 116,000
Long-term debt retirements (35,000) (117,000)
Preferred stock issues 35,000
Preferred stock retirements (35,000)
Premium on reacquisition of long-term debt (7,089)
Premium on redemption of preferred stock (816)
------- ------- -------
Net cash provided by financing
activities $12,936 $55,197 $10,857
------- ------- -------
Net increase in cash and cash equivalents $615 $452 $35
Cash and cash equivalents at beginning
of year 1,225 773 738
------- ------- -------
Cash and cash equivalents at end of year $1,840 $1,225 $773
======= ======= =======
Supplementary information:
Interest paid less amounts capitalized $29,130 $24,562 $25,220
------- ------- -------
Federal and state income taxes paid
(refunded) $(8,026) $1,645 $12,090
------- ------- -------
The accompanying notes are an integral part of these financial statements.
Massachusetts Electric Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of Operations:
The Company is a wholly-owned subsidiary of New England Electric System (NEES)
operating in Massachusetts. The Company's business is the distribution and
sale of electricity at retail. Electric service is provided to approximately
950,000 customers in 146 cities and towns having a population of approximately
2,160,000 (1990 Census). The Company's service area covers approximately 43
percent of Massachusetts. The properties of the Company consist principally of
substations and distribution lines interconnected with transmission and other
facilities of New England Power Company (NEP), an affiliate. The Company
purchases all of its electric energy requirements from NEP under a contract
which obligates NEP to furnish such requirements at its standard resale rate.
This contract requires either party to give seven years notice prior to
terminating the contract.
2. System of Accounts:
The accounts of the Company are maintained in accordance with the Uniform
System of Accounts prescribed by regulatory bodies having jurisdiction.
In preparing the financial statements, management is required to make
estimates that affect the reported amounts of assets and liabilities and
disclosures of asset recovery and contingent liabilities as of the date of the
balance sheets and revenues and expenses for the period. These estimates may
differ from actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates.
3. Electric Sales Revenue:
The Company, pursuant to a 1993 rate agreement, began accruing revenues for
electricity delivered but not yet billed (unbilled revenues). Unbilled
revenues at December 31, 1995, 1994, and 1993 were $50 million, $43 million,
and $43 million, respectively of which $7 million, $32 million, and $11
million were recognized in income in the respective years. Included in these
income amounts are $32 million in 1994 and $3 million in 1993 which represent
amortization of the initial effect of recording unbilled revenues in
accordance with the rate agreement. Accrued revenues are also recorded in
accordance with rate adjustment mechanisms.
4. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC represents an
allowance for the cost of funds used to finance construction. AFDC is
capitalized in "Utility plant" with offsetting non-cash credits to "Interest."
This method is in accordance with an established rate-making practice under
which a utility is permitted a return on, and the recovery of, prudently
incurred capital costs through their ultimate inclusion in rate base and in
the provision for depreciation. The composite AFDC rates were 6.0 percent, 4.8
percent, and 3.5 percent, in 1995, 1994, and 1993, respectively.
5. Depreciation:
Depreciation is provided annually on a straight-line basis. The provision for
depreciation as a percentage of weighted average depreciable property was 3.3
percent in each of the years 1995, 1994, and 1993.
6. Cash:
The Company classifies short-term investments with a maturity of 90 days or
less at time of purchase as cash.
Note B - Competitive Conditions
The electric utility business is being subjected to rapidly increasing
competitive pressures and increasing demands for customer choice. Accordingly,
in February 1996, the Company filed a plan, Choice: New England, with
Massachusetts regulators, which would allow all customers of electric
utilities in Massachusetts to choose their power supplier beginning in 1998.
Under Choice: New England, pricing of generation would be deregulated while
transmission and distribution rates would remain regulated, although subject
to greater rewards and penalties based on performance. Choice: New England
proposes that the cost of past commitments to serve customers be recovered
through a wires access or transition charge. Those past commitments include
generating plant commitments, regulatory assets, purchased power contracts,
and nuclear costs independent of operation.
Historically, electric utility rates have been based on a utility's costs. As
a result, electric utilities are subject to certain accounting standards that
are not applicable to other business enterprises in general. Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (FAS 71), requires regulated entities, in appropriate
circumstances, to establish regulatory assets and liabilities, and thereby
defer the income statement impact of certain costs that are expected to be
recovered in future rates. The effects of regulatory, legislative, or utility
initiatives could, in the near future, cause all or a portion of the Company's
operations to cease meeting the criteria of FAS 71. In that event, the
application of FAS 71 to such operations would be discontinued and a non-cash
write-off of previously established regulatory assets and liabilities related
to such operations would be required. In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of (FAS 121). This standard clarifies when and how to recognize
an impairment of long-lived assets. If competitive or regulatory change
should cause a substantial revenue loss, a write-down of plant assets could be
required pursuant to FAS 121. In addition, FAS 121 requires that all
regulatory assets, which must have a high probability of recovery to be
initially established, must continue to meet that high probability standard to
avoid being written off. However, if written off, a regulatory asset can be
restored if it again has a high probability of recovery. FAS 121, which is
effective for the Company in January 1996, is not expected to have a material
adverse impact on the financial condition or results of operations upon
adoption, based on the current regulatory environment in which the Company
operates. However, the impact in the future may change as competitive factors
and potential restucturing influence the electric utility industry.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1995 1994
---- ----
Regulatory assets (liabilities) included in current
assets and liabilities:
Rate adjustment mechanisms (See Note F) $(792) $(2,059)
------- -------
Regulatory assets included in deferred charges:
Unamortized losses on reacquired debt 8,034 8,848
Deferred SFAS No. 106 costs (See Note E-2) 17,185 16,079
Deferred SFAS No. 109 costs (See Note C) 8,308 8,445
Environmental response costs (See Note D-2) 15,526 9,417
Deferred storm costs 4,433 6,545
Other 1,312 1,764
------- -------
54,798 51,098
------- -------
$54,006 $49,039
======= =======
Amounts included in "Deferred charges and other assets" on the Company's
balance sheets that do not represent regulatory assets totaled $10,292,000 and
$8,438,000 at December 31, 1995 and 1994, respectively.
Note C - Income Taxes
The Company and other subsidiaries participate with NEES in filing
consolidated federal income tax returns. The Company's income tax provision is
calculated on a separate return basis. Federal income tax returns have been
examined and reported on by the Internal Revenue Service (IRS) through 1991.
The returns for 1992 and 1993 are currently under examination by the IRS.
Total income taxes in the statements of income are as follows:
<CAPITON>
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Income taxes charged to operations $19,297 $22,265 $11,055
Income taxes charged (credited) to
"Other income" (901) (642) 101
------- ------- -------
Total income taxes $18,396 $21,623 $11,156
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Current income taxes $11,730 $(7,286) $8,030
Deferred income taxes 7,798 30,137 4,354
Investment tax credits, net (1,132) (1,228) (1,228)
------- ------- -------
Total income taxes $18,396 $21,623 $11,156
======= ======= =======
Investment tax credits have been deferred and are being amortized over the
estimated lives of the property giving rise to the credits.
Total income taxes, as shown above, consist of federal and state components as
follows:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Federal income taxes $14,461 $16,942 $7,808
State income taxes 3,935 4,681 3,348
------- ------- -------
Total income taxes $18,396 $21,623 $11,156
======= ======= =======
Consistent with rate-making policies of the Massachusetts Department of Public
Utilities (MDPU), the Company has adopted comprehensive interperiod tax
allocation (normalization) for temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal
statutory tax rates to income before taxes. The reasons for the differences
are as follows:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Computed tax at statutory rate $16,624 $19,722 $12,227
Increases (reductions) in tax resulting from:
Amortization of investment tax credits (1,132) (1,228) (1,228)
Adjustment of prior year tax accruals (155) (110) (2,528)
State income taxes, net of federal income
tax benefit 2,558 3,043 2,459
All other differences 501 196 226
------- ------- -------
Total income taxes $18,396 $21,623 $11,156
======= ======= =======
The following table identifies the major components of total deferred income
taxes:
At December 31, (In Millions) 1995 1994
---- ----
Deferred tax asset:
Plant related $9 $8
Investment tax credits 7 8
All other 42 45
---- ----
58 61
---- ----
Deferred tax liability:
Plant related (209) (201)
All other (34) (37)
---- ----
(243) (238)
---- ----
Net deferred tax liability $(185) $(177)
==== ====
There were no valuation allowances for deferred tax assets deemed necessary.
Note D - Commitments and Contingencies
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be approximately
$105 million in 1996. At December 31, 1995, substantial commitments had been
made relative to future planned expenditures.
2. Hazardous Waste:
The Federal Comprehensive Environmental Response, Compensation and Liability
Act, more commonly known as the "Superfund" law, imposes strict, joint and
several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates a range of
potentially hazardous products and by-products in its operations. NEES
subsidiaries currently have an environmental audit program in place intended
to enhance compliance with existing federal, state, and local requirements
regarding the handling of potentially hazardous products and by-products.
The Company has been named as a potentially responsible party (PRP) by either
the U.S. Environmental Protection Agency or the Massachusetts Department of
Environmental Protection for 18 sites at which hazardous waste is alleged to
have been disposed. Private parties have also contacted or initiated legal
proceedings against the Company regarding hazardous waste cleanup. The most
prevalent types of hazardous waste sites with which the Company has been
associated are manufactured gas locations. The Company is aware of
approximately 35 such locations in Massachusetts (including seven of the 18
locations for which the Company is a PRP). The Company is currently aware of
other sites, and may in the future become aware of additional sites, that it
may be held responsible for remediating.
In 1993, the MDPU approved a rate agreement filed by the Company that allows
for remediation costs of former manufactured gas sites and certain other
hazardous waste sites located in Massachusetts to be met from a
non-rate-recoverable, interest-bearing fund of $30 million established on the
Company's books composed of previously recorded reserves of $21 million plus
$9 million of additional reserves recorded in the fourth quarter of 1993.
Rate-recoverable contributions of $3 million, adjusted for inflation, are
added to the fund annually in accordance with the agreement. Any shortfalls in
the fund would be paid by the Company and be recovered through rates over
seven years.
Predicting the potential costs to investigate and remediate hazardous waste
sites continues to be difficult. There are also significant uncertainties as
to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by the Company.
Where appropriate, the Company intends to seek recovery from its insurers and
from other PRPs, but it is uncertain whether, and to what extent, such efforts
will be successful. At December 31, 1995, the Company had total reserves for
environmental response costs of $39 million and a related regulatory asset of
$16 million. The Company believes that hazardous waste liabilities for all
sites of which it is aware, and which are not covered by a rate agreement, are
not material to its financial position.
Note E - Employee Benefits
1. Pension Plans:
The Company participates with other subsidiaries of NEES in noncontributory,
defined-benefit plans covering substantially all employees of the Company. The
plans provide pension benefits based on the employee's compensation during the
five years prior to retirement. The Company's funding policy is to contribute
each year the net periodic pension cost for that year. However, the
contribution for any year will not be less than the minimum contribution
required by federal law or greater than the maximum tax deductible amount.
Net pension cost for 1995, 1994, and 1993 included the following components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Service cost benefits earned during the period $3,992 $4,134 $3,348
Plus (less):
Interest cost on projected benefit obligation 17,576 16,435 16,905
Return on plan assets at expected
long-term rate (18,122) (17,223) (16,683)
Amortization 99 1,060 (208)
------ ------ ------
Net pension cost $3,545 $4,406 $3,362
====== ====== ======
Actual return on plan assets $47,717 $1,541 $25,785
======= ======= =======
1996 1995 1994 1993
---- ---- ---- ----
Assumptions used to determine pension cost:
Discount rate 7.25% 8.25% 7.25% 8.25%
Average rate of increase in
future compensation levels 4.13% 4.63% 4.35% 5.35%
Expected long-term rate of
return on assets 8.50% 8.75% 8.75% 8.75%
Service cost for 1993 does not reflect $13 million of costs incurred in
connection with an early retirement and special severance program offered by
the Company in that year.
The funded status of the plans cannot be presented separately for the Company
as the Company participates in the plans with other NEES subsidiaries. The
following table sets forth the funded status of the NEES companies' plans at
December 31:
Retirement Plans, (In Millions) 1995 1994
---- ----
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
-------- -------- -------- ---------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $293 $343 $251 $308
Non-vested 8 10 8 9
---- ---- ---- ----
Total $301 $353 $259 $317
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of
projected benefit liability $346 $402 $303 $355
Unrecognized prior service costs (7) (4) (8) (4)
Unrecognized transition liability - (1) - (1)
Unrecognized net loss (1) (23) (13) (33)
---- ---- ---- ----
338 374 282 317
---- ---- ---- ----
Pension fund assets at fair
value 349 392 293 323
Unrecognized transition asset (11) - (13) -
---- ---- ---- ----
338 392 280 323
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ - $(18) $2 $(6)
The plans' funded status at December 31, 1995 and 1994 were calculated using
the assumed rates from 1996 and 1995, respectively, and the 1983 Group Annuity
Mortality table.
Plan assets are composed primarily of corporate equity, guaranteed investment
contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions (PBOPs):
The Company provides health care and life insurance coverage to eligible
retired employees. Eligibility is based on certain age and length of service
requirements and in some cases retirees must contribute to the cost of their
coverage.
The total cost of PBOPs for 1995, 1994, and 1993 included the following
components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Service cost benefits earned during
the period $2,368 $2,840 $2,613
Plus (less):
Interest cost on accumulated benefit
obligation 11,699 11,050 12,007
Return on plan assets at expected
long-term rate (4,165) (3,306) (2,095)
Amortization 6,628 7,287 7,302
------ ------ ------
Net postretirement benefit cost $16,530 $17,871 $19,827
====== ====== ======
Actual return on plan assets $12,209 $ 265 $ 2,125
====== ====== ======
1996 1995 1994 1993
---- ---- ---- ----
Assumptions used to determine postretirement
benefit cost:
Discount rate 7.25% 8.25% 7.25% 8.25%
Expected long-term rate of return
on assets 8.25% 8.50% 8.50% 8.50%
Health care cost rate 1994 and 1993 11.00% 12.00%
Health care cost rate 1995 to 1999 8.00% 8.50% 8.50% 9.50%
Health care cost rate 2000 to 2004 6.25% 8.50% 8.50% 9.50%
Health care cost rate 2005 and beyond 5.25% 6.25% 6.25% 7.25%
The following table sets forth benefits earned and the plans' funded status:
At December 31, (In Millions) 1995 1994
---- ----
Accumulated postretirement benefit obligation:
Retirees $93 $92
Fully eligible active plan participants 12 19
Other active plan participants 44 33
--- ---
Total benefits earned 149 144
Unrecognized prior service costs (1) -
Unrecognized transition obligation (124) (131)
Unrecognized net gain 26 15
--- ---
50 28
Plan assets at fair value 65 44
--- ---
Prepaid postretirement benefit costs recorded on books $15 $16
=== ===
The plans' funded status at December 31, 1995 and 1994 were calculated using
the assumed rates in effect for 1996 and 1995, respectively.
The health care cost trend rate assumption has a significant effect on the
amounts reported. Increasing the assumed rates by 1 percent in each year would
increase the accumulated postretirement benefit obligation as of December 31,
1995 by approximately $18 million and the net periodic cost for the year 1995
by approximately $2 million.
The Company funds the annual tax deductible contributions. Plan assets are
invested in equity and debt securities and cash equivalents.
Note F - Short-term Borrowings and Other Accrued Expenses
At December 31, 1995, the Company had $55 million of short-term debt
outstanding including $54 million in commercial paper borrowings and $1
million of borrowings from affiliates. NEES and certain subsidiaries,
including the Company, with regulatory approval, operate a money pool to more
effectively utilize cash resources and to reduce outside short-term
borrowings. Short-term borrowing needs are met first by available funds of the
money pool participants. Borrowing companies pay interest at a rate designed
to approximate the cost of outside short-term borrowings. Companies which
invest in the pool share the interest earned on a basis proportionate to their
average monthly investment in the money pool. Funds may be withdrawn from or
repaid to the pool at any time without prior notice.
At December 31, 1995, the Company had lines of credit with banks totaling $90
million which are available to provide liquidity support for commercial paper
borrowings and other corporate purposes. There were no borrowings under these
lines of credit at December 31, 1995. Fees are paid in lieu of compensating
balances on most lines of credit.
The weighted average rate on outstanding short-term borrowings was 5.9 percent
at December 31, 1995. The fair value of the Company's short-term debt equals
carrying value.
The components of other accrued expenses are as follows:
At December 31, (In Thousands) 1995 1994
---- ----
Rate adjustment mechanisms $3,908 $15,087
Accrued wages and benefits 11,066 9,969
Other 2,162 2,076
------ ------
$17,136 $27,132
====== ======
Note G - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1995 and 1994 is as follows
(in thousands of dollars except for share data):
A summary of cumulative preferred stock at December 31, 1995 and 1994 is as follows
(in thousands of dollars except for share data):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
--------------- ------ ------------ -----
1995 1994 1995 1994 1995 1994
---- ---- ---- ---- ---- ---- -----
$25 Par value
6.84% Series 600,000 600,000$15,000 $15,000 $1,026 $1,026 (a)
$100 Par value
4.44% Series 75,000 75,000 7,500 7,500 333 333$104.068
4.76% Series 75,000 75,000 7,500 7,500 357 357 103.730
6.99% Series 200,000 200,000 20,000 20,000 1,398 1,398 (b)
------- -------------- -------------- -------
Total 950,000 950,000$50,000 $50,000 $3,114 $3,114
======= ============== ============== =======
(a) Callable on or after October 1, 1998 at $25.80.
(b) Callable on or after August 1, 2003 at $103.50.
The annual dividend requirement for total cumulative preferred stock was $3,114,000 for
1995 and 1994.
There are no mandatory redemption provisions on the Company's cumulative preferred stock.
Note H - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In Thousands)
Series Rate % Maturity 1995 1994
- -----------------------------------------------------------------------------
First Mortgage Bonds:
R(92-2) 5.875 February 6, 1995 $10,000
S(92-1) 5.860 June 26, 1995 15,000
S(92-8) 4.730 September 18, 1995 10,000
R(92-4) 7.230 June 3, 1997 $10,000 10,000
R(92-5) 7.210 June 3, 1997 5,000 5,000
S(92-6) 6.120 August 15, 1997 12,000 12,000
S(92-7) 6.010 August 15, 1997 3,000 3,000
U(95-3) 7.800 February 13, 1998 5,000
U(95-4) 7.790 February 16, 1998 5,000
R(92-1) 7.240 December 30, 1998 10,000 10,000
S(92-3) 6.630 August 12, 1999 7,500 7,500
S(92-4) 6.600 August 12, 1999 7,500 7,500
U(95-5) 7.930 February 14, 2000 6,000
S(92-2) 6.980 July 17, 2000 5,000 5,000
S(92-9) 6.310 September 15, 2000 10,000 10,000
R(92-6) 7.710 July 1, 2002 10,000 10,000
S(92-11) 7.250 October 28, 2002 5,000 5,000
S(92-12) 7.340 November 25, 2002 10,000 10,000
T(93-2) 7.090 January 27, 2003 20,000 20,000
T(93-5) 6.400 June 24, 2003 10,000 10,000
U(93-1) 6.240 November 17, 2003 5,000 5,000
U(94-6) 8.520 November 30, 2004 10,000 10,000
U(95-1) 8.450 January 10, 2005 10,000
U(95-2) 8.220 January 24, 2005 10,000
U(95-7) 7.920 March 3, 2005 9,000
V(95-1) 6.720 June 23, 2005 10,000
T(93-7) 6.660 June 23, 2008 5,000 5,000
T(93-8) 6.660 June 30, 2008 5,000 5,000
T(93-10) 6.110 September 8, 2008 10,000 10,000
T(93-11) 6.375 November 17, 2008 10,000 10,000
R(92-3) 8.550 February 7, 2022 5,000 5,000
S(92-5) 8.180 August 1, 2022 10,000 10,000
S(92-10) 8.400 October 26, 2022 5,000 5,000
T(93-1) 8.150 January 20, 2023 10,000 10,000
T(93-3) 7.980 January 27, 2023 10,000 10,000
T(93-4) 7.690 February 24, 2023 10,000 10,000
T(93-6) 7.500 June 23, 2023 3,000 3,000
T(93-9) 7.500 June 29, 2023 7,000 7,000
U(93-2) 7.200 November 15, 2023 10,000 10,000
U(93-3) 7.150 November 24, 2023 1,000 1,000
U(94-1) 7.050 February 2, 2024 10,000 10,000
U(94-2) 8.080 May 2, 2024 5,000 5,000
U(94-3) 8.030 June 14, 2024 5,000 5,000
U(94-4) 8.160 August 9, 2024 5,000 5,000
U(94-5) 8.850 November 7, 2024 1,000 1,000
U(95-6) 8.460 February 28, 2025 3,000
V(95-2) 7.630 June 27, 2025 10,000
V(95-3) 7.600 September 12, 2025 10,000
V(95-4) 7.630 September 12, 2025 10,000
Unamortized discounts (1,733) (1,369)
-------- --------
Total long-term debt 353,267 300,631
======== ========
Long-term debt due in one year (35,000)
-------- --------
$353,267 $265,631
======== ========
Substantially all of the properties and franchises of the Company are subject
to the lien of mortgage indentures under which the first mortgage bonds have
been issued.
The Company will make cash payments of $30,000,000 in 1997, $20,000,000 in
1998, $15,000,000 in 1999, and $21,000,000 in 2000 to retire maturing mortgage
bonds. There are no cash payments required in 1996.
At December 31, 1995, the Company's long-term debt had a carrying value of
approximately $353,000,000 and had a fair value of approximately $380,000,000.
The fair market value of the Company's long-term debt was estimated based on
the quoted prices for similar issues or on the current rates offered to the
Company for debt of the same remaining maturity.
Note I - Restrictions on Retained Earnings Available for Dividends on Common
Stock
As long as any preferred stock is outstanding, certain restrictions on payment
of dividends on common stock would come into effect if the "junior stock
equity" was, or by reason of payment of such dividends became, less than 25
percent of "Total capitalization." However, the junior stock equity at
December 31, 1995 was 50 percent of total capitalization, and accordingly,
none of the Company's retained earnings at December 31, 1995 were restricted
as to dividends on common stock under the foregoing provisions.
Under restrictions contained in the indentures relating to first mortgage
bonds, $20,113,000 of the Company's retained earnings at December 31, 1995
were restricted as to dividends on common stock.
Note J - Supplementary Income Statement Information
Advertising expenses, expenditures for research and development, and rents
were not material and there were no royalties paid in 1995, 1994, or 1993.
Taxes, other than income taxes, charged to operating expenses are set forth by
classes as follows:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Municipal property taxes $23,119 $21,186 $19,620
Federal and state payroll and other taxes 6,903 7,478 6,907
------- ------- -------
$30,022 $28,664 $26,527
New England Power Service Company, an affiliated service company operating
pursuant to the provisions of Section 13 of the Public Utility Holding Company
Act of 1935, furnished services to the Company at the cost of such services.
These costs amounted to $66,195,000, $71,107,000, and $61,515,000, including
capitalized construction costs of $7,660,000, $8,977,000, and $9,038,000, for
each of the years 1995, 1994, and 1993, respectively.
Massachusetts Electric Company
Operating Statistics (Unaudited)
Year Ended December 31, 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Sources of Energy (Thousands of kWh)
Purchased energy:
From New England Power
Company, an affiliate 16,594,81216,455,77416,179,20416,005,08715,971,746
From others 2,887 3,364 12,676 13,916 12,865
--------------------------------------------------
Total purchased 16,597,69916,459,13816,191,88016,019,00315,984,611
Losses, company use, etc. (730,608) (733,804) (740,390) (711,157) (730,694)
--------------------------------------------------
Total sources of energy 15,867,09115,725,33415,451,49015,307,84615,253,917
==================================================
Sales of Energy
(Thousands of kWh)
Residential 5,768,635 5,798,806 5,694,539 5,645,350 5,568,452
Commercial 5,999,555 5,936,170 5,743,924 5,645,867 5,585,604
Industrial 3,998,506 3,885,391 3,850,075 3,907,040 3,979,418
Other 89,759 95,382 99,991 105,842 113,444
Total sales to --------------------------------------------------
ultimate customers 15,856,45515,715,74915,388,52915,304,09915,246,918
Sales for resale 10,636 9,585 62,961 3,747 6,999
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Total sales of energy 15,867,09115,725,33415,451,49015,307,84615,253,917
==================================================
Maximum Demand
(kW one hour peak) 3,029,000 3,016,000 2,819,000 2,791,000 2,888,000
Average Annual Use per
Residential Customer (kWh) 6,844 6,948 6,888 6,886 6,832
Number of Customers at
December 31
Residential 847,437 839,443 831,223 824,072 817,270
Commercial 97,211 95,430 93,414 92,281 81,355
Industrial 4,503 4,551 4,637 4,624 4,650
Other 854 880 906 952 986
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Total ultimate customers 950,005 940,304 930,180 921,929 904,261
Other (for resale) 179 178 278 22 21
--------------------------------------------------
Total customers 950,184 940,482 930,458 921,951 904,282
==================================================
Operating Revenue (In Thousands)
Residential $610,856 $588,518 $593,336 $549,884 $521,140
Commercial 543,715 523,826 518,965 510,638 490,078
Industrial 312,057 301,502 316,140 319,905 318,502
Other 17,991 17,147 17,416 17,489 18,304
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Total revenue from
ultimate customers 1,484,619 1,430,993 1,445,857 1,397,916 1,348,024
Amortization of unbilled revenues 32,300 2,700
Sales for resale 1,013 924 5,399 278 518
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Total revenue from
electric sales 1,485,632 1,464,217 1,453,956 1,398,194 1,348,542
Other operating revenue 20,044 17,853 14,584 14,754 15,346
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Total operating revenue $1,505,676$1,482,070$1,468,540$1,412,948$1,363,888
==================================================
Massachusetts Electric Company
Selected Financial Information
Year Ended December 31, (In Millions) 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $1,072 $1,088 $1,062 $1,012 $984
Fuel cost recovery 414 376 392 386 365
Other 20 18 15 15 15
------ ------ ------ ------ ------
Total operating revenue $1,506 $1,482 $1,469 $1,413 $1,364
Net income $29 $35 $24 $35 $25
Total assets $1,343 $1,296 $1,232 $1,015 $1,017
Capitalization:
Common equity $412 $384 $382 $331 $313
Cumulative preferred stock 50 50 50 50 50
Long-term debt 353 266 265 266 194
------ ------ ------ ------ ------
Total capitalization $815 $700 $697 $647 $557
Preferred dividends declared $3 $3 $4 $3 $3
Common dividends declared $13 $30 $19 $23 $5
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter*
------- ------- ------- -------
1995
Operating revenue $373,092 $355,431 $392,575 $384,578
Operating income $13,349 $11,173 $11,799 $25,349
Net income $5,126 $2,567 $3,653 $17,755
1994
Operating revenue $381,712 $339,886 $376,582 $383,890
Operating income $17,124 $15,054 $10,120 $20,370
Net income $9,572 $8,215 $1,431 $15,508
*See "Rate Activity" section of Financial Review
Per share data is not relevant because the Company's common stock is wholly-owned by New
England Electric System.
A copy of Massachusetts Electric Company's Annual Report on Form 10-K to the Securities
and Exchange Commission for the year ended December 31, 1995 will be available on or about
April 1, 1996, without charge, upon written request to Massachusetts Electric Company,
Shareholder Services Department, 25 Research Drive, Westborough, Massachusetts 01582.