Annual Report 1995
New England Power Company
A Subsidiary of
New England Electric System
[LOGO] New England Power
A NEES Company
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of December 31, 1995)
Joan T. Bok
Chairman of the Board of New England Electric System
Frederic E. Greenman*
Vice President, General Counsel, and Assistant Clerk of the Company and Senior
Vice President, General Counsel, and Secretary of New England Electric System
Alfred D. Houston
Executive Vice President and Chief Financial Officer of New England
Electric System
Cheryl A. LaFleur**
Vice President and General Counsel of the Company and Vice President, General
Counsel, and Secretary of New England Electric System
John W. Newsham*
Executive Vice President of the Company and Vice President of New England
Electric System
John W. Rowe
Chairman of the Company and President and Chief Executive Officer of New
England Electric System
Jeffrey D. Tranen
President of the Company and Vice President of New England Electric System
Officers
(As of December 31, 1995)
John W. Rowe
Chairman of the Company and President and Chief Executive Officer of New
England Electric System
Jeffrey D. Tranen
President of the Company and Vice President of New England Electric System
John W. Newsham*
Executive Vice President of the Company and Vice President of New England
Electric System
Frederic E. Greenman*
Vice President, General Counsel, and Assistant Clerk of the Company and Senior
Vice President, General Counsel, and Secretary of New England Electric System
Cheryl A. LaFleur**
Vice President and General Counsel of the Company and Vice President, General
Counsel, and Secretary of New England Electric System
Andrew H. Aitken
Vice President
Lawrence E. Bailey
Vice President
Jeffrey A. Donahue
Vice President
John F. Malley
Vice President
Arnold H. Turner
Vice President
Jeffrey W. VanSant
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
John G. Cochrane
Assistant Treasurer of the Company and of certain affiliates and Vice
President of an affiliate
Kirk L. Ramsauer
Assistant Clerk of the Company and of an affiliate
Howard W. McDowell
Controller of the Company and of certain affiliates
* retired December 31, 1995
** elected effective December 31, 1995
Transfer Agent and Dividend Paying Agent of Preferred Stock
Bank of Boston, Boston, Massachusetts
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.
New England Power Company
New England Power Company, a wholly-owned subsidiary of New England
Electric System, is a Massachusetts corporation and is qualified to do
business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. The Company is subject, for certain purposes, to the
jurisdiction of the regulatory commissions of these six states, the Securities
and Exchange Commission and the Federal Energy Regulatory Commission. The
Company's business is principally that of generating, purchasing,
transmitting, and selling electric energy in wholesale quantities to other
electric utilities, principally its affiliates Granite State Electric Company,
Massachusetts Electric Company, and The Narragansett Electric Company. In
1995, 95 percent of the Company's revenue from the sale of electricity was
derived from sales to affiliated companies and 5 percent from sales to
municipal and other utilities. 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 Company, through its own generating units, entitlements and purchase
power contracts, has a total capability of 5,704 megawatts. In 1995, the
Company's energy mix was 38 percent coal, 22 percent gas, 14 percent nuclear,
10 percent hydro, 10 percent oil, and 6 percent renewable non-utility
generation.
The Company is a member of the New England Power Pool, which coordinates
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
New England Power Company, Westborough, Massachusetts:
We have audited the accompanying balance sheets of New England Power
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
New England Power Company
Financial Review
Overview
Net income increased by $2 million in 1995 compared with 1994. This
increase reflects higher sales, lower depreciation and amortization expense
and lower maintenance expense. Partially offsetting these increases to 1995
earnings were increased purchased power costs excluding fuel, increased costs
related to postretirement benefits other than pensions (PBOPs), increased
reimbursements to affiliates for service extension discounts (SEDs) to
customers and generation and transmission costs incurred for the benefit of
the Company. In addition, interest costs also increased in 1995.
Net income increased by $8 million in 1994 reflecting decreased purchased
power charges excluding fuel, lower interest expense and increased allowance
for funds used during construction. In addition, earnings in 1993 were
reduced by a one-time after-tax charge of $6 million ($10 million before-tax)
associated with an early retirement program. Partially offsetting these
increases to 1994 earnings were increased operation and maintenance expenses
and the reimbursement of certain power plant dismantlement costs through
revenue credits to The Narragansett Electric Company (Narragansett), an
affiliate.
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 New England
Electric System (NEES) companies 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, Rhode Island, and
New Hampshire, 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, utilities across the
country 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 derives approximately 72 percent, 20 percent, and 3 percent of
its electric sales revenues from sales to Massachusetts Electric Company
(Massachusetts Electric), Narragansett, and Granite State Electric Company,
respectively. These affiliated companies purchase electricity under wholesale
all-requirements contracts with the Company and resell it to their customers.
Legislative or utility initiatives, such as Choice: New England, could
ultimately result in changes in the relationship between the Company and its
all-requirements customers.
Choice: New England
In October 1995, the 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
(RIPUC) 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 by Massachusetts Electric with
the MDPU in February 1996. Narragansett plans to file a similar version of
Choice: New England with the RIPUC in April 1996 to comply with a RIPUC order
to file restructuring plans.
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, transmission and distribution rates would remain
regulated. As described in the "Rate Activity" section, the Company has
recently filed a proposed tariff rate with the Federal Energy Regulatory
Commission (FERC) whereby its transmission facilities would be operated by
another NEES subsidiary pursuant to a support agreement.
Under Choice: New England, the Company's wholesale contract with its
affiliates would be terminated. In return, Choice: New England proposes that
the cost of the Company's past generation commitments be recovered through a
wires access or transition charge. Those commitments, which are currently
estimated at approximately $4 billion on a present value basis, 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"). Sunk costs associated with utility
generating plants, such as past capital investments, and regulatory assets
would be recovered over ten years. The return on equity related to the
unrecovered capital investments and regulatory assets would be reduced to one
percentage point over the rate on long-term "BBB" rated utility bonds.
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 kilowatt-hour (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 FERC approval.
In March 1996, Massachusetts Electric 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.
Rhode Island Legislation
In February 1996, the Speaker and Majority Leader of the House of
Representatives of the Rhode Island Legislature announced the filing of
legislation which would allow electric consumers in Rhode Island to choose
their power supplier. Under the proposed legislation, large manufacturing
customers and new large non-manufacturing customers would gain access to
alternative power suppliers over a two-year period beginning in 1998. These
customers represent approximately 14 percent of Narragansett's retail kWh
sales. The balance of Rhode Island customers would gain access over a
two-year period beginning in the year 2000, or earlier if consumers of 50
percent of the electricity in New England gain similar rights to choose their
power supplier. The NEES companies have announced their support for the
proposed legislation.
A key provision of the legislation authorizes utilities to recover the cost
of past generation commitments through a transition access charge on utility
distribution wires. The legislation divides those past commitments in the
same manner as Choice: New England. The legislation proposes a 12-year
recovery period for utility generation commitments and regulatory assets.
Consideration by the Rhode Island Legislature of the proposed legislation is
expected to be completed by the summer of 1996.
Previously, in 1995, the Rhode Island Legislature passed legislation that
would have allowed certain industrial customers to buy power from alternative
suppliers, rather than through the local electric utility. Narragansett urged
the Governor of Rhode Island to veto the legislation because Narragansett
believed it would result in piecemeal deregulation that would not be fair to
customers or shareholders. The Governor vetoed the proposed legislation, in
part because of commitments by Narragansett to provide a two-year rate
discount to manufacturing customers and to submit a specific and detailed
proposal to the RIPUC addressing the issues associated with providing large
customers with access to Narragansett's distribution system for the purpose of
choosing an alternative power supplier.
Other Legislative and Regulatory Initiatives
In February 1996, the New Hampshire House of Representatives passed a bill
requiring utilities in that state to file plans by June 1996 with the New
Hampshire Public Utilities Commission (NHPUC) to provide customers with access
to alternative suppliers. The bill allows the NHPUC significant discretion in
determining the appropriate level of stranded cost recovery. The bill would
authorize the NHPUC to impose a plan on utilities if none is filed and
approved by July 1997. The bill is pending in the state Senate.
In January 1996, Granite State reached an agreement with the NHPUC staff to
conduct a retail access pilot for 3 percent of Granite State's customers. If
approved by the NHPUC and the FERC, participating customers in the pilot will
pay access charges that are on average over 90 percent of the charges proposed
under Choice: New England. The agreement was reached in response to 1995
legislation which directed the NHPUC to establish a pilot program for the
state's utilities. The agreement includes more favorable terms regarding
stranded cost recovery than preliminary pilot guidelines issued by the NHPUC.
In February 1996, the NHPUC indicated that further review of certain
assumptions made in the agreement was necessary. The Commission also expanded
the pilot to include new large commercial and industrial customers.
Separately, in June 1995, the NHPUC issued a decision stating that franchise
territories in New Hampshire are not exclusive as a matter of law. That
decision is under appeal.
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 (NOPR) 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. The NOPR also addressed open access transmission and indicated that
those utilities owning transmission facilities would be required to file a
tariff to make available comparable transmission service. (See "Rate
Activity" section for further discussion.)
Risk Factors
The major risk factors affecting recovery of at-risk assets are: (i)
regulatory and legal decisions, (ii) the market price of power, and (iii) the
amount of market share retained by the Company. First, there can be no
assurance that a final restructuring plan ordered by regulatory bodies, or the
courts, or through legislation will include an access charge that would fully
recover stranded costs. If laws are enacted or regulatory decisions are made
that do not offer an opportunity to recover stranded costs, the Company
believes it has strong legal arguments to challenge such laws or decisions.
Such a challenge would be based, in part, on the assertion that subjecting
utility generating assets to competition without compensation for stranded
costs while requiring utilities to open access to their wires at historic
cost-based rates, would constitute an unconstitutional taking of property
without just compensation. Second, the access charge proposed under Choice:
New England recovers only sunk costs, such as plant expenditures and
contractual commitments. Because of a regional surplus of electric generation
capacity, current wholesale power prices in the short-term market are based on
the short-run fuel costs of generating units. Such wholesale prices are not
currently providing a significant contribution toward other marginal costs,
such as operation and maintenance expenses. The Company expects this
situation to continue in a retail market. Third, revenues will also be
affected by the Company's ability to retain existing customers and attract new
customers in a competitive environment. As a result of the pressure on market
prices and market share, it is likely that, even if Choice: New England is
implemented, the Company would experience losses in revenue for an
indeterminate period and increased revenue volatility.
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, such as the proposed Rhode Island legislation or Choice: New
England, 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
$300 million. In addition, the Company's affiliate, New England Energy
Incorporated (NEEI), has a regulatory asset of approximately $200 million,
which is recoverable in its entirety from the Company. If competitive or
regulatory change should cause a substantial revenue loss or lead to the
permanent shutdown of any generating facilities, 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
In February 1995, the FERC approved a rate agreement filed by the Company.
Under the agreement, which became effective January 1995, the Company's base
rates are frozen through 1996. Before this rate agreement, the Company's rate
structure contained two surcharges that were recovering the costs of a coal
conversion project and a portion of the Company's investment in the Seabrook 1
nuclear unit (Seabrook 1). These two surcharges fully recovered their related
costs by mid-1995. However, under the rate agreement, the revenues continue
to be collected as part of base rates. The agreement also provides for (i)
full recovery of costs associated with the Manchester Street Station
repowering project, which began commercial operation in the second half of
1995, (ii) the recovery of approximately $50 million of deferred costs
associated with terminated purchased power contracts and PBOPs over seven
years, (iii) full recovery of currently incurred PBOP costs, (iv) the recovery
over three years of $27 million of costs related to the dismantling of a
retired generating station in Rhode Island and the replacement of a turbine
rotor at one of the Company's generating units, and (v) increased recovery of
depreciation expense by approximately $8 million annually to recognize costs
that will be incurred upon the eventual dismantling of its Brayton Point and
Salem Harbor generating plants. Under the agreement, approximately $15
million of the $38 million in Seabrook 1 costs scheduled for recovery in 1995
pursuant to a 1988 settlement agreement were deferred for recovery in 1996.
Finally, the agreement provided that the Company would reimburse its wholesale
customers for discounts provided by those wholesale customers to their retail
customers under SED programs. Under these programs, retail customers are
entitled to such discounts only if they have signed an agreement not to
purchase power from another supplier or generate any additional power
themselves for a three to five year period. Reimbursements in 1995 totaled
$12 million.
The FERC's approval of this rate agreement applies to all of the Company's
customers except the Milford Power Limited Partnership (MPLP). MPLP, owner of
a gas-fired power plant in Milford, Massachusetts, has protested the rate
agreement based on issues related to the Manchester Street Station repowering
project. (See "Purchased Power Contract Dispute" section.)
In response to the FERC NOPR discussed above, the Company and NEES
Transmission Services, Inc. (NEES Trans), a proposed new subsidiary of NEES,
filed transmission tariffs in March 1996 at the FERC that will become
applicable for all wholesale transmission transactions, including those of the
NEES retail distribution affiliates. Under the proposed tariffs and
accompanying support agreements, NEES Trans will provide all wholesale
transmission services involving the NEES companies' facilities under
comparable, nondiscriminatory transmission rates. The existing NEES
companies, including the Company, would turn operational control of their
transmission facilities over to NEES Trans in exchange for support payments
from NEES Trans for these facilities. The Company may, at a later date,
transfer its transmission assets to NEES Trans. The net book value of the
Company's transmission system is approximately $340 million. The Company is
requesting that its filing become effective by June 1, 1996 or upon approval
by the Securities and Exchange Commission, for the establishment of this new
company. If approved as filed, the implementation of the tariffs would not
have a significant impact on the Company's revenues.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
(In Millions) 1995 1994
---- ----
Fuel recovery $27 $(6)
Accrued NEEI fuel revenues 4 (7)
Narragansett integrated facilities credit (10) (6)
SED reimbursements (12)
Sales growth 15 10
Other 6 1
---- ----
$30 $(8)
Accrued NEEI fuel revenues and accrued NEEI fuel costs (see "Operating
Expenses" section) reflect losses incurred by NEEI, an affiliate of the
Company, on its rate-regulated oil and gas operations. These revenues are
accrued in the year of the loss but are billed to the Company's customers
through its fuel adjustment clause in the following year. Changes in accrued
NEEI fuel revenues and fuel costs are principally due to fluctuations in NEEI
production (see "Fuel Supply" section).
The entire output of Narragansett's generating capacity is made available
to the Company. Narragansett receives a credit on its purchased power bill
from the Company for its fuel costs and other generation and
transmission-related costs. The increased credits in 1995 reflect costs
associated with a new transmission line that went into service in September
1994 and with Narragansett's portion of the repowered Manchester Street
generating station that went into service in the second half of 1995. In
addition, the credits increased in both 1995 and 1994 due to increased costs
associated with the dismantlement of the previously retired South Street
generating facility. However, a portion of the 1995 credits had been deferred
for recovery from ratepayers in 1996 and 1997.
See the "Rate Activity" section for a discussion of SED reimbursements.
Operating Expenses
The following table summarizes the changes in operating expenses:
Increase (Decrease) in Operating Expenses
(In Millions) 1995 1994
---- ----
Fuel costs $27 $(7)
Accrued NEEI fuel costs 4 (7)
Purchased energy excluding fuel 22 (11)
Other operation and maintenance (2) 18
Depreciation and amortization (35) 6
Taxes (1) 5
---- ----
$15 $4
Total fuel costs represent fuel for generation and the portion of purchased
electric energy permitted to be recovered through the Company's fuel
adjustment clause. The increase in fuel costs in 1995 reflects decreased
nuclear generation due to overhauls and decreased hydro production resulting
from low water levels.
Purchased energy excluding fuel represents purchased electric energy costs
not recovered through the fuel clause. The increase in these costs in 1995
and the decrease in 1994 reflects costs associated with scheduled plant
overhauls and refueling shutdowns at partially-owned nuclear power facilities.
The 1995 increase includes the amortization of previously deferred purchased
power contract termination costs and costs to repair the steam generator tubes
at Maine Yankee, in which the Company has a 20 percent interest. Maine Yankee
returned to service at 90 percent capacity in January 1996.
The decrease in other operation and maintenance expenses in 1995 reflects
lower overhaul costs at wholly-owned generating units, primarily in the fourth
quarter of 1995, partially offset by the recognition of currently incurred and
previously incurred deferred PBOP costs in accordance with the Company's 1995
rate agreement, increased transmission system related costs and general and
administrative costs.
The increase in other operation and maintenance expenses in 1994 reflects
increases in generating plant maintenance costs associated with overhauls of
wholly-owned generating units in part to achieve compliance with the Clean Air
Act. The increase also reflects cost increases in computer system
development, increased demand-side management program expenses, and general
increases in other areas. These increases were partially offset by a one-time
charge in 1993 of $10 million associated with an early retirement program.
Depreciation and amortization expense decreased in 1995 due to reduced
amortization of Seabrook 1 and the completion, in the second quarter of 1995,
of the amortization of certain coal conversion facilities, partially offset by
the effects of increased depreciation rates approved in the Company's 1995
rate agreement and depreciation of new plant expenditures, including the
Manchester Street Station, which began commercial operation in the second half
of 1995. The increase in depreciation and amortization expense in 1994
primarily reflects increased amortization of Seabrook 1 as part of a 1988 rate
settlement and increased depreciation on new plant expenditures.
The increase in taxes in 1994 primarily reflects increased income taxes and
municipal property taxes.
Under the existing terms of certain purchased power contracts with other
utilities, the Company will reduce its power purchases by $19 million in 1996.
The Company is a 15 percent stockholder in Connecticut Yankee Atomic Power
Company (Connecticut Yankee) which owns a 580 megawatt (MW) nuclear generating
unit. The Company also has an approximately 12 percent ownership interest in
Millstone 3, a 1,150 MW nuclear unit. In March 1996, the Nuclear Regulatory
Commission (NRC) issued a letter requiring Millstone 3 and Connecticut Yankee
to demonstrate to the NRC within 30 days a plan and schedule to ensure that
the future operation of those units will be conducted in accordance with their
operating licenses and safety provisions or face license suspension.
Millstone 3 was also added to the NRC's problem plant list in January 1996.
It is unknown what effect the increased NRC scrutiny will have on the
operations and cost of Millstone 3 and Connecticut Yankee. Other
non-affiliated facilities which have been on the problem plant list have
incurred substantial additional capital and operating expenditures before the
NRC designation was changed.
Interest Expense
The increase in interest expense in 1995 was primarily due to an increase
in combined long-term and short-term debt balances and higher interest rates
earlier in 1995. The decrease in interest expense in 1994 is primarily due to
significant refinancings of corporate debt at lower interest rates during
1993. In addition, the decrease in 1994 also reflects reduced interest on
rate refunds and taxes primarily in the fourth quarter, partially offset by
increased interest on short-term debt.
Allowance for Funds Used During Construction (AFDC)
AFDC increased in 1995 and 1994 due to increased construction work in
progress associated with the repowering of the Manchester Street Station. The
accrual of AFDC ended for this project when the units began commercial
operation in the second half of 1995. (See "Utility Plant Expenditures and
Financing" section.)
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 six 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 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.
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. The Company believes that hazardous waste liabilities for
all sites of which it is aware 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 the states in which
the Company operates and in contexts other than condemnation cases.
Purchased Power Contract Dispute
In October 1994, the Company was sued by MPLP, a venture of Enron
Corporation and Jones Capital that owns a 149 MW gas-fired power plant in
Milford, Massachusetts. The Company purchases 56 percent of the power output
of the facility under a long-term contract with MPLP. The suit alleges that
the Company has engaged in a scheme to cause MPLP and its power plant to fail
and has prevented MPLP from finding a long-term buyer for the remainder of the
facility's output. The complaint includes allegations that the Company has
violated the Federal Racketeer Influenced and Corrupt Organizations Act,
engaged in unfair or deceptive acts in trade or commerce, and breached
contracts. MPLP also asserts that the Company deliberately misled regulatory
bodies concerning the Manchester Street Station repowering project. MPLP
seeks compensatory damages in an unspecified amount, as well as treble
damages. The Company believes that the allegations of wrongdoing are without
merit. The Company has filed counterclaims and crossclaims against MPLP,
Enron Corporation, and Jones Capital, seeking monetary damages and termination
of the purchased power contract.
MPLP also intervened in the Company's current rate filing before the FERC,
making similar allegations to those asserted in MPLP's lawsuit. Hearings on
this claim concluded in October 1995. An Administrative Law Judge initial
decision is expected by mid-1996.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $163 million for 1995,
including $85 million related to the Manchester Street Station repowering
project discussed below. The funds necessary for utility plant expenditures
during the period were provided by net cash from operating activities, after
the payment of dividends, and proceeds of long-term debt issues. Cash
expenditures for utility plant for 1996 are estimated to be $85 million.
Internally generated funds are estimated to fully cover the Company's 1996
capital expenditure requirements for utility plant.
In 1995, the Company issued $50 million of mortgage bonds at rates ranging
from 6.69 percent to 7.94 percent. In addition, the Company refinanced $10
million of variable rate mortgage bonds in 1995. The Company has issued $40
million of variable rate mortgage bonds to date in 1996 to refinance a like
amount of outstanding debt.
In the second half of 1995, the Company and Narragansett completed the 489
MW repowering of the Manchester Street Station. The Company owns a 90 percent
interest and Narragansett owns a 10 percent interest in the Manchester Street
Station. The total cost for the generating station will be approximately $450
million, including AFDC. In addition, related transmission improvements,
which were principally the responsibility of Narragansett, were placed in
service in September 1994 at a cost of approximately $60 million.
At December 31, 1995, the Company had $125 million of short-term debt
outstanding including $124 million of commercial paper borrowings and $1
million of borrowings from affiliates. At December 31, 1995, the Company had
lines of credit and bond purchase facilities with banks totaling $510 million
which are available to provide liquidity support for commercial paper
borrowings and for $342 million of the Company's outstanding variable rate
mortgage bonds in tax-exempt commercial paper mode and for other corporate
purposes. There were no borrowings under these lines of credit at December
31, 1995.
March 25, 1996
New England Power Company
Statements of Income
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Operating revenue, principally from
affiliates $1,570,539 $1,540,757 $1,549,014
---------- ---------- ----------
Operating expenses:
Fuel for generation 279,849 260,540 273,347
Purchased electric energy 547,926 513,583 525,985
Other operation 211,872 196,610 186,087
Maintenance 92,954 110,528 103,261
Depreciation and amortization 102,758 137,979 131,932
Taxes, other than income taxes 58,716 54,400 51,931
Income taxes 91,051 96,596 93,997
---------- ---------- ----------
Total operating expenses 1,385,126 1,370,236 1,366,540
---------- ---------- ----------
Operating income 185,413 170,521 182,474
Other income:
Allowance for equity funds used during
construction 7,746 9,142 3,252
Equity in income of nuclear power
companies 5,721 4,816 5,646
Other income (expense), net (1,610) (293) (566)
---------- ---------- ----------
Operating and other income 197,270 184,186 190,806
---------- ---------- ----------
Interest:
Interest on long-term debt 46,797 38,711 45,837
Other interest 10,525 1,956 5,427
Allowance for borrowed funds used
during construction credit (11,479) (5,854) (1,926)
---------- ---------- ----------
Total interest 45,843 34,813 49,338
---------- ---------- ----------
Net income $151,427 $149,373 $141,468
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Retained earnings at beginning of year $372,763 $346,153 $321,699
Net income 151,427 149,373 141,468
Dividends declared on cumulative
preferred stock (3,433) (3,440) (4,883)
Dividends declared on common stock,
$21.00, $18.50, and $17.25 per share,
respectively (135,448) (119,323) (111,261)
Premium on redemption of preferred stock (870)
-------- -------- --------
Retained earnings at end of year $385,309 $372,763 $346,153
======== ======== ========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
At December 31, (In Thousands) 1995 1994
Assets ---- ----
Utility plant, at original cost $2,941,469 $2,524,544
Less accumulated provisions for
depreciation and amortization 1,047,982 1,001,393
---------- ----------
1,893,487 1,523,151
Net investment in Seabrook 1 under rate
settlement (Note D-2) 15,210 38,283
Construction work in progress 41,566 314,777
---------- ----------
Net utility plant 1,950,263 1,876,211
---------- ----------
Investments:
Nuclear power companies, at equity (Note D-1) 47,055 46,349
Non-utility property and other investments 26,627 22,980
---------- ----------
Total investments 73,682 69,329
---------- ----------
Current assets:
Cash 2,607 377
Accounts receivable:
Affiliated companies 204,314 197,655
Accrued NEEI revenues (Note E-1) 43,731 39,794
Others 17,821 29,738
Fuel, materials, and supplies, at average cost 54,664 73,361
Prepaid and other current assets 27,986 33,729
---------- ----------
Total current assets 351,123 374,654
---------- ----------
Deferred charges and other assets (Note B) 273,275 292,644
---------- ----------
$2,648,343 $2,612,838
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
authorized and outstanding 6,449,896 shares $128,998 $128,998
Premiums on capital stocks 86,829 86,829
Other paid-in capital 288,000 288,000
Retained earnings 385,309 372,763
---------- ----------
Total common equity 889,136 876,590
Cumulative preferred stock, par value $100
per share (Note H) 60,516 60,516
Long-term debt 735,440 695,466
---------- ----------
Total capitalization 1,685,092 1,632,572
---------- ----------
Current liabilities:
Long-term debt due in one year 10,000
Short-term debt (including $1,025 and
$16,575 to affiliates) 125,150 145,575
Accounts payable (including $50,760 and
$69,089 to affiliates) 163,791 179,761
Accrued liabilities:
Taxes 3,447 6,133
Interest 10,482 9,914
Other accrued expenses (Note G) 10,834 10,866
Dividends payable 32,249
---------- ----------
Total current liabilities 355,953 352,249
---------- ----------
Deferred federal and state income taxes 390,197 364,073
Unamortized investment tax credits 57,509 59,014
Other reserves and deferred credits 159,592 204,930
Commitments and contingencies (Note E)
---------- ----------
$2,648,343 $2,612,838
========== ==========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows
Year Ended December 31, (In Thousands) 1995 1994 1993
Operating activities: ---- ---- ----
Net income $151,427 $149,373 $141,468
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 108,384 142,764 135,746
Deferred income taxes and
investment tax credits, net 25,683 23,051 20,665
Allowance for funds used during
construction (19,225) (14,996) (5,178)
Early retirement program 2,967
Decrease (increase) in accounts
receivable 1,321 (6,932) 31,323
Decrease (increase) in fuel, materials,
and supplies 18,697 (17,406) 16,902
Decrease (increase) in prepaid and
other current assets 5,743 (7,275) (4,908)
Increase (decrease) in accounts payable (15,970) 35,661 (35,913)
Increase (decrease) in other current
liabilities (2,150) (30,823) 25,205
Other, net (28,244) (26,845) (46,559)
--------- --------- ---------
Net cash provided by operating
activities $245,666 $246,572 $281,718
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(162,766) $(229,015) $(156,614)
Other investing activities (3,614) (3,053) (2,402)
--------- --------- ---------
Net cash used in investing activities $(166,380) $(232,068) $(159,016)
--------- --------- ---------
Financing activities:
Dividends paid on common stock $(103,198) $(133,835) $(120,936)
Dividends paid on preferred stock (3,433) (3,440) (4,883)
Changes in short-term debt (20,425) 95,050 32,200
Long-term debt issues 60,000 28,000 224,000
Long-term debt retirements (10,000) (224,000)
Preferred stock retirements (512) (25,000)
Premium on reacquisition of long-term debt (3,255)
Premium on redemption of preferred stock (870)
--------- --------- ---------
Net cash used in financing activities $(77,056) $(14,737) $(122,744)
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents $2,230 $(233) $(42)
Cash and cash equivalents at beginning of
year 377 610 652
--------- --------- ---------
Cash and cash equivalents at end of year $2,607 $377 $610
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $41,557 $32,510 $42,390
--------- --------- ---------
Federal and state income taxes paid $57,948 $83,455 $78,300
--------- --------- ---------
Dividends received from investments
at equity $5,014 $4,809 $5,103
--------- --------- ---------
The accompanying notes are an integral part of these financial statements.
New England Power Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of Operations:
The Company, a wholly-owned subsidiary of New England Electric System (NEES),
is a Massachusetts corporation and is qualified to do business in
Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont.
The Company is subject, for certain purposes, to the jurisdiction of the
regulatory commissions of these six states, the Securities and Exchange
Commission and the Federal Energy Regulatory Commission. The Company's
business is principally that of generating, purchasing, transmitting, and
selling electric energy in wholesale quantities to other electric utilities,
principally its affiliates Granite State Electric Company, Massachusetts
Electric Company (Massachusetts Electric), and The Narragansett Electric
Company (Narragansett).
2. System of Accounts:
The accounts of the Company are maintained in accordance with the Uniform
System or 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. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC represents
the composite interest and equity costs of capital funds used to finance that
portion of construction costs not eligible for inclusion in rate base. In
1995, an average of $21 million of construction work in progress was included
in rate base, all of which was attributable to the Manchester Street Station
repowering project. AFDC is capitalized in "Utility plant" with offsetting
non-cash credits to "Other income" and "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 7.5 percent, 7.8 percent, and 8.1 percent, in 1995,
1994, and 1993, respectively.
4. Depreciation and Amortization:
The depreciation and amortization expense included in the statements of income
is composed of the following:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Depreciation $66,309 $52,834 $53,128
Nuclear decommissioning costs (Note E-5) 2,629 1,951 1,951
Amortization:
Investment in Seabrook 1 under rate
settlement (Note D-2) 23,074 65,061 58,437
Oil Conservation Adjustment 4,467 11,854 12,137
Property losses 6,279 6,279 6,279
------- ------- -------
Total depreciation and amortization
expense $102,758 $137,979 $131,932
======= ======= =======
Depreciation is provided annually on a straight-line basis. The provision for
depreciation as a percentage of weighted average depreciable property was 2.7
percent in 1995, 2.4 percent in 1994, and 2.5 percent in 1993. The Oil
Conservation Adjustment was designed to recover expenditures for coal
conversion facilities at the Company's Salem Harbor Station. These costs were
fully amortized at December 31, 1995.
5. 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, Massachusetts Electric, an affiliate, 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. Another affiliate, Narragansett, will file a similar version of
Choice: New England with the Rhode Island Public Utilities Commission in April
1996. 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
of the Company 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, such as proposed legislation in Rhode Island or Choice: New
England, 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 or lead to the permanent shutdown of any
generating facilities, a write-down of plant assets could be required pursuant
to FAS 121. At December 31, 1995, the Company had net plant investments
totaling approximately $2 billion, of which approximately $1.6 billion is
generation related. 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
restructuring influence the electric utility industry.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1995 1994
---- ----
Regulatory assets included in current assets and
liabilities:
Accrued NEEI losses (see Note E-1) $43,731 $39,794
Regulatory assets included in deferred charges:
Accrued Yankee Atomic costs (see Note D-1) 67,566 122,452
Unamortized losses on reacquired debt 32,571 34,862
Deferred SFAS No. 106 costs (see Note F-2) 16,416 19,149
Deferred SFAS No. 109 costs (see Note C) 30,059 34,482
Purchased power contract termination costs 23,494 29,012
Deferred gas pipeline charges (see Note E-4) 62,873 37,562
Unamortized property losses 12,044 7,373
Other 22,049 2,542
-------- --------
267,072 287,434
-------- --------
$310,803 $327,228
======== =======
In addition to the regulatory assets recorded on its books, the Company is
obligated to reimburse an affiliate, New England Energy Incorporated (NEEI),
for losses which NEEI has been incurring in connection with its fuel
exploration, development and production program (see Note E-1). The Company's
ability to pass such losses on to customers was favorably resolved in the
Company's 1988 rate settlement. NEEI has a regulatory asset of approximately
$200 million, which is recoverable in its entirety from the Company.
Approximately $300 to $350 million of total regulatory assets, including
NEEI's regulatory asset, are expected to be recovered within the next five
years. Amounts included in "Deferred charges and other assets" on the balance
sheets that do not represent regulatory assets totaled $6,203,000 and
$5,210,000 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:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Income taxes charged to operations $91,051 $96,596 $93,997
Income taxes charged (credited) to
"Other income" 353 (994) 838
------- ------- -------
Total income taxes $91,404 $95,602 $94,835
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Current income taxes $65,721 $72,551 $74,171
Deferred income taxes 27,188 26,628 23,270
Investment tax credits, net (1,505) (3,577) (2,606)
------- ------- -------
Total income taxes $91,404 $95,602 $94,835
======= ======= =======
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 $74,590 $78,274 $77,593
State income taxes 16,814 17,328 17,242
------- ------- -------
Total income taxes $91,404 $95,602 $94,835
======= ======= =======
With regulatory approval from the Federal Energy Regulatory Commission (FERC),
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 $84,991 $85,741 $82,706
Increases (reductions) in tax
resulting from:
Amortization of investment tax credits (2,227) (3,045) (2,511)
State income taxes, net of federal
income tax benefit 10,929 11,263 10,770
All other differences (2,289) 1,643 3,870
------- ------- -------
Total income taxes $91,404 $95,602 $94,835
======= ======= =======
The following table identifies the major components of total deferred income
taxes:
At December 31, (In Millions) 1995 1994
---- ----
Deferred tax asset:
Plant related $92 $96
Investment tax credits 24 25
All other 43 29
---- ----
159 150
---- ----
Deferred tax liability:
Plant related (397) (384)
Equity AFDC (47) (47)
All other (105) (83)
---- ----
(549) (514)
---- ----
Net deferred tax liability $(390) $(364)
===== =====
There were no valuation allowances for deferred tax assets deemed necessary.
Note D - Nuclear Power Investments
1. Yankee Nuclear Power Companies (Yankees):
The Company has minority interests in four Yankee Nuclear Power Companies.
These ownership interests are accounted for on the equity method. The
Company's share of the expenses of the Yankees is accounted for in "Purchased
electric energy" on the statements of income. A summary of combined results
of operations, assets, and liabilities of the four Yankees is as follows:
(In Thousands) 1995 1994 1993
---- ---- ----
Operating revenue $695,781 $631,940 $700,148
========== ========= =========
Net income $31,657 $30,345 $30,061
========== ========= =========
Company's equity in net income $5,721 $4,816 $5,646
========== ========= =========
Net plant 443,967 537,103 591,650
Other assets 1,418,681 1,458,186 1,286,923
Liabilities and debt (1,612,843) (1,748,960) (1,633,139)
---------- ---------- ----------
Net assets $249,805 $246,329 $245,434
========== ========= =========
Company's equity in net assets $47,055 $46,349 $46,342
========== ========= =========
Company's purchased electric energy $115,647 $106,404 $118,362
========== ========= --------=
At December 31, 1995, $13 million of undistributed earnings of the Yankees
were included in the Company's retained earnings.
The Company has a 30 percent ownership interest in Yankee Atomic Electric
Company (Yankee Atomic), which owns a 185 megawatt (MW) nuclear generating
station in Rowe, Massachusetts. In 1992, the Yankee Atomic board of directors
decided to permanently cease power operation of the facility and to proceed
with decommissioning. The Company has recorded an estimate of its total
future payment obligations for post operating costs to Yankee Atomic as a
liability and an offsetting regulatory asset of $68 million each at December
31, 1995, reflecting its expected future rate recovery of such costs (see Note
B).
2. Jointly-Owned Nuclear Generating Units:
The Company is also a 12 percent and 10 percent joint owner, respectively, of
the Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 MW. The
Company's net investment in Millstone 3, included in "Net utility plant" is
approximately $392 million. The Company's unamortized pre-1988 investment in
Seabrook 1, is approximately $15 million and is shown separately on the
Company's balance sheet. It will be fully amortized in 1996, pursuant to a
settlement agreement. The Company's net investment in Seabrook 1 since January
1, 1988, which is approximately $54 million, is included in "Net utility
plant" on the Company's balance sheet and is being depreciated over the term
of Seabrook 1's operating license. The Company's share of expenses for these
units is included in "Operating expenses."
Note E - Commitments and Contingencies
1. Oil and Gas Operations:
NEEI, a subsidiary of NEES, is engaged in domestic oil and gas exploration,
development, and production. NEEI operates under an intercompany pricing
policy (Pricing Policy) with the Company which has been approved by the
Securities and Exchange Commission (SEC). The Pricing Policy requires the
Company to purchase all fuel meeting its specifications offered to it by NEEI.
Under the Pricing Policy, NEEI's oil and gas exploration program is composed
of prospects entered into through December 31, 1983 under a rate-regulated
program. NEEI has incurred operating losses since 1986, due to low oil and gas
prices, and expects to incur substantial additional losses in the future.
These losses are passed on to the Company in the year after they are incurred
by NEEI and, in turn, are being recovered from customers through the Company's
fuel clause. The Company's ability to pass these losses on to its customers
was favorably resolved in the Company's 1988 FERC rate settlement. This
settlement covered all costs incurred by or resulting from commitments made by
NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are
subject to normal regulatory review. In 1995, 1994, and 1993, the Company
recorded accrued fuel expenses and accrued revenues of $44 million, $40
million, and $46 million, respectively, representing losses incurred by NEEI
in each year.
In the absence of the Pricing Policy, the SEC's cost center "ceiling test"
rule requires non-rate-regulated companies to write down capitalized costs to
a level which approximates the present value of their proved oil and gas
reserves. Based on NEEI's 1995 average oil and gas selling prices,
application of the ceiling test would have resulted in a write-down of
approximately $112 million after tax ($178 million before tax) at December 31,
1995.
2. Plant Expenditures:
The Company's utility plant expenditures are estimated to be $85 million in
1996. At December 31, 1995, substantial commitments had been made relative to
future planned expenditures.
3. Hydro-Quebec Interconnection:
The Company is a participant in both the Hydro-Quebec Phase I and Phase II
projects. The Company's participation percentage in both projects is
approximately 18 percent. The Hydro-Quebec Phase I and Phase II projects were
established to transmit power from Hydro-Quebec to New England. Three
affiliates of the Company were created to construct and operate transmission
facilities related to these projects. The participants, including the Company,
have entered into support agreements that end in 2020, to pay monthly their
proportionate share of the total cost of constructing, owning, and operating
the transmission facilities. The Company accounts for these support agreements
as capital leases and accordingly recorded approximately $73 million in
utility plant at December 31, 1995. Under the support agreements, the Company
has agreed, in conjunction with any Hydro-Quebec Phase II project debt
financing, to guarantee its share of project debt. At December 31, 1995, the
Company had guaranteed approximately $30 million of project debt.
4. Natural Gas Pipeline Capacity:
In connection with serving the Company's gas-burning electric generation
facilities, the Company has entered into several contracts for natural gas
pipeline capacity and gas supply. These agreements require minimum fixed
payments that are currently estimated to be approximately $60 million to $65
million per year from 1996 to 2000. Remaining fixed payments from 2001 through
2014 total approximately $625 million.
As part of a rate settlement, the Company was recovering 50 percent of the
fixed pipeline capacity payments through its current fuel clause and deferring
the recovery of the remaining 50 percent until the Manchester Street
repowering project was completed. These deferrals ended in November 1995, at
which time the Company had deferred payments of approximately $63 million
which will be amortized over 25 years in accordance with rate settlements (see
Note B).
In connection with managing its fuel supply, the Company uses a portion of
this pipeline capacity to sell natural gas. Proceeds from the sale of natural
gas and pipeline capacity of $71 million, $55 million, and $21 million, in
1995, 1994, and 1993, respectively, have been passed to customers through the
Company's fuel clause. These proceeds have been included in "Fuel for
generation" in the Company's statements of income as an offset to the related
fuel expense. Natural gas sales are expected to decrease as a result of the
Manchester Street Station entering commercial operation in the second half of
1995.
5. 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 six 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 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.
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. The Company believes that hazardous waste liabilities for
all sites of which it is aware are not material to its financial position.
6. Nuclear Plant Decommissioning and Nuclear Fuel Disposal:
The Company is recovering its share of projected decommissioning costs for
Millstone 3 and Seabrook 1 through depreciation expense. Projected
decommissioning costs include estimated costs to decontaminate the units as
required by the Nuclear Regulatory Commission (NRC), as well as costs to
dismantle the non-contaminated portion of the units. The Company records
decommissioning cost expense on its books consistent with its rate recovery.
In addition, the Company is paying its portion of projected decommissioning
costs for all of the Yankees through purchased power expense. Such costs
reflect estimates of total decommissioning costs approved by the FERC.
Each of the operating nuclear units in which the Company has an ownership
interest has established decommissioning trust funds or escrow funds into
which payments are being made to meet the projected costs of decommissioning
each plant. Listed below is information on each operating nuclear plant in
which the Company has an ownership interest.
The Company's
share of (in millions of dollars)
---------------------------------
Estimated
Decommiss-
Ownership ioning Cost Fund License
Unit Interest (in 1995 $) Balances** Expiration
Connecticut Yankee 15% 58 27 2007
Maine Yankee *** 20% 71 28 2008
Vermont Yankee 20% 71 27 2012
Millstone 3 * 12% 58 14 2025
Seabrook 1 * 10% 43 6 2026
* Fund balances are included in "Non-utility property and other
investments" on the balance sheets and approximate market value.
** Certain additional amounts are anticipated to be available through tax
deductions.
*** A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally
liable for the shortfall.
There is no assurance that decommissioning costs actually incurred by the
Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these
amounts. For example, decommissioning cost estimates assume the availability
of permanent repositories for both low-level and high-level nuclear waste that
do not currently exist. If any of the units were shut down prior to the end of
their operating licenses, the funds collected for decommissioning to that
point would be insufficient.
The Nuclear Waste Policy Act of 1982 establishes that the federal government
is responsible for the disposal of spent nuclear fuel. The federal government
requires the Company to pay a fee based on its share of the net generation
from Millstone 3 and Seabrook 1. The Company is recovering this fee through
its fuel clause. Similar costs are incurred by Connecticut Yankee, Maine
Yankee, and Vermont Yankee. These costs are billed to the Company and also
recovered from customers through the Company's fuel clause.
7. Nuclear Insurance:
The Price-Anderson Act limits the amount of liability claims that would have
to be paid in the event of a single incident at a nuclear plant to $8.9
billion (based upon 110 licensed reactors). The maximum amount of commercially
available insurance coverage to pay such claims is $200 million. The remaining
$8.7 billion would be provided by an assessment of up to $79.3 million per
incident levied on each of the participating nuclear units in the United
States, subject to a maximum assessment of $10 million per incident per
nuclear unit in any year. The maximum assessment, which was most recently
adjusted in 1993, is adjusted for inflation at least every five years. The
Company's current interest in the Yankees (excluding Yankee Atomic), Millstone
3, and Seabrook 1 would subject the Company to a $58 million maximum
assessment per incident. The Company's payment of any such assessment would be
limited to a maximum of $7.3 million per incident per year. As a result of the
permanent cessation of power operation of the Yankee Atomic plant, Yankee
Atomic has received from the NRC a partial exemption from obligations under
the Price-Anderson Act. However, Yankee Atomic must continue to maintain $100
million of commercially available nuclear insurance coverage.
Each of the nuclear units in which the Company has an ownership interest also
carries nuclear property insurance to cover the costs of property damage,
decontamination or premature decommissioning, and workers' claims resulting
from a nuclear incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units covered by this
insurance occurring in a prior six-year period exceed the accumulated funds
available. The Company's maximum potential exposure for these assessments,
either directly, or indirectly through purchased power payments to the
Yankees, is approximately $18 million per year.
8. Long-term Contracts for the Purchase of Electricity:
The Company purchases a portion of its electricity requirements pursuant to
long-term contracts that expire in various years from 1996 to 2029, with
owners of various generating units.
Certain of these contracts require the Company to make minimum fixed payments,
even when the supplier is unable to deliver power, to cover the Company's
proportionate share of the capital and fixed operating costs of these
generating units. The fixed portion of payments under these contracts totaled
$215 million in 1995, $190 million in 1994, and $220 million in 1993. These
contracts have minimum fixed payment requirements of $190 million in 1996,
$185 million in 1997, $190 million in 1998, $180 million in 1999 and 2000, and
approximately $1.8 billion thereafter. Approximately 97 percent of the
payments under these contracts are to the Yankees (excluding Yankee Atomic -
see Note D-1) and Ocean State Power, entities in which the Company or its
affiliates hold ownership interests.
The Company's other contracts, principally with non-utility generators,
require the Company to make payments only if power supply capacity and energy
are deliverable from such suppliers. The Company's payments under these
contracts amounted to $245 million in 1995, and $210 million in 1994 and 1993,
respectively.
9. Purchased Power Contract Dispute:
In October 1994, the Company was sued by Milford Power Limited Partnership
(MPLP), a venture of Enron Corporation and Jones Capital that owns a 149 MW
gas-fired power plant in Milford, Massachusetts. The Company purchases 56
percent of the power output of the facility under a long-term contract with
MPLP. The suit alleges that the Company has engaged in a scheme to cause MPLP
and its power plant to fail and has prevented MPLP from finding a long-term
buyer for the remainder of the facility's output. The complaint includes
allegations that the Company has violated the Federal Racketeer Influenced and
Corrupt Organizations Act, engaged in unfair or deceptive acts in trade or
commerce, and breached contracts. MPLP also asserts that the Company
deliberately misled regulatory bodies concerning the Manchester Street Station
repowering project. MPLP seeks compensatory damages in an unspecified amount,
as well as treble damages. The Company believes that the allegations of
wrongdoing are without merit. The Company has filed counterclaims and
crossclaims against MPLP, Enron Corporation, and Jones Capital, seeking
monetary damages and termination of the purchased power contract.
MPLP also intervened in the Company's current rate filing before the FERC,
making similar allegations to those asserted in MPLP's lawsuit. Hearings on
this claim concluded in October 1995. An Administrative Law Judge initial
decision is expected by mid-1996.
Note F - 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 $2,231 $2,202 $1,953
Plus (less):
Interest cost on projected benefit obligation 6,406 6,403 6,070
Return on plan assets at expected long-term
rate (6,488) (6,554) (5,850)
Amortization 131 557 47
------- ------- -------
Net pension cost $2,280 $2,608 $2,220
======= ======= =======
Actual return on plan assets $17,108 $608 $8,949
======= ======= =======
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 $10 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 $1,344 $1,628 $1,632
Plus (less):
Interest cost on accumulated
benefit obligation 4,013 3,954 4,275
Return on plan assets at expected
long-term rate (1,374) (1,111) (725)
Amortization 2,079 2,591 2,558
------ ------ ------
Net postretirement benefit cost $6,062 $7,062 $7,740
====== ====== ======
Actual return on plan assets $4,137 $54 $ 746
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 $30 $31
Fully eligible active plan participants 1 3
Other active plan participants 20 17
--- ---
Total benefits earned 51 51
Unrecognized transition obligation (43) (46)
Unrecognized net gain 12 6
--- ---
20 11
--- ---
Plan assets at fair value 23 15
--- ---
Prepaid postretirement benefit costs recorded on books $3 $4
=== ===
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 $6 million and the net periodic cost for the year 1995
by approximately $1 million.
The Company funds the annual tax deductible contributions. Plan assets are
invested in equity and debt securities and cash equivalents.
Note G - Short-term Borrowings and Other Accrued Expenses
At December 31, 1995, the Company had $125 million of short-term debt
outstanding including $124 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 and standby bond
purchase facilities with banks totaling $510 million which are available to
provide liquidity support for commercial paper borrowings and for $342 million
of the Company's outstanding variable rate mortgage bonds in tax-exempt
commercial paper mode (see Note I) and for other corporate purposes. There
were no borrowings under these lines of credit at December 31, 1995. Fees are
paid on the lines and facilities in lieu of compensating balances.
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
---- ----
Accrued wages and benefits $6,258 $6,397
Capital lease obligations due within one year 4,323 4,324
Other 253 145
------ ------
$10,834 $10,866
====== ======
Note H - 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):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
--------------- ------ ------------ -----
1995 1994 1995 1994 1995 1994
---- ---- ---- ---- ---- ---- -----
$100 Par value
6.00% Series 75,020 75,020 $7,502 $7,502 $451 $458 (a)
4.56% Series 100,000 100,000 10,000 10,000 456 456$104.08
4.60% Series 80,140 80,140 8,014 8,014 368 368 101.00
4.64% Series 100,000 100,000 10,000 10,000 464 464 102.56
6.08% Series 100,000 100,000 10,000 10,000 608 608 102.34
7.24% Series 150,000 150,000 15,000 15,000 1,086 1,086 103.06
------- ------- ------ ------ ----- -----
Total 605,160 605,160$60,516 $60,516 $3,433 $3,440
(a) Noncallable.
The annual dividend requirement for total cumulative preferred stock was $3,433,000 for
1995 and 1994.
Note I - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In Thousands)
Series Rate % Maturity 1995 1994
- -----------------------------------------------------------------------------
General and Refunding Mortgage Bonds:
W(93-3) 5.12 February 2, 1996 $5,000 $5,000
W(93-8) 5.06 February 5, 1996 5,000 5,000
Y(94-3) 8.10 December 22, 1997 3,000 3,000
W(93-2) 6.17 February 2, 1998 4,300 4,300
W(93-4) 6.14 February 2, 1998 1,300 1,300
W(93-5) 6.17 February 3, 1998 5,000 5,000
W(93-7) 6.10 February 4, 1998 10,000 10,000
W(93-9) 6.04 February 4, 1998 29,400 29,400
Y(94-4) 8.28 December 21, 1999 10,000 10,000
W(93-6) 6.58 February 10, 2000 5,000 5,000
Y(95-1) 7.94 February 14, 2000 5,000
Y(95-2) 7.93 February 14, 2000 10,000
Y(95-3) 7.40 March 21, 2000 10,000
Y(95-4) 6.69 June 5, 2000 25,000
W(93-1) 7.00 February 3, 2003 25,000 25,000
Y(94-2) 8.33 November 8, 2004 10,000 10,000
K 7.25 October 15, 2015 38,500 38,500
L 7.80 April 1, 2016 29,850 29,850
X variable March 1, 2018 79,250 79,250
R variable November 1, 2020 117,850 107,850
S variable November 1, 2020 20,750 20,750
T variable November 1, 2020 18,000 28,000
U 8.00 August 1, 2022 170,000 170,000
V variable October 1, 2022 106,150 106,150
Y(94-1) 8.53 September 20, 2024 5,000 5,000
Unamortized discounts (2,910) (2,884)
-------- --------
Total long-term debt 745,440 695,466
======== ========
Long-term debt due in one year (10,000)
-------- --------
$735,440 $695,466
======== ========
Substantially all of the properties and franchises of the Company are subject
to the lien of the mortgage indentures under which the general and refunding
mortgage bonds have been issued.
The Company will make cash payments of $10 million in 1996, $3 million in
1997, $50 million in 1998, $10 million in 1999, and $55 million in 2000 to
retire maturing mortgage bonds.
The terms of $342 million of variable rate pollution control revenue bonds
(PCRBs) collateralized by the Company's mortgage bonds require the Company to
reacquire the bonds under certain limited circumstances. At December 31, 1995,
interest rates on the Company's variable rate bonds ranged from 3.35 percent
to 6.00 percent. To date in 1996, the Company has issued $40 million of
additional variable rate PCRBs to refinance $10 million of Series T bonds and
$30 million of Series L bonds.
At December 31, 1995, the Company's long-term debt had a carrying value of
$745,000,000 and had a fair value of approximately $785,000,000. The fair
value of debt that reprices frequently at market rates approximates carrying
value. For all other debt, 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 J - Restrictions on Retained Earnings Available for Dividends on Common
Stock
Pursuant to the provisions of the Articles of Organization and the By-Laws
relating to the Dividend Series Preferred Stock, 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 52 percent of total capitalization, including long-term
debt due in one year, 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 general and
refunding mortgage bonds (Series K), none of the Company's retained earnings
at December 31, 1995 were restricted as to dividends on common stock.
However, a portion of the Company's retained earnings (less than $20 million)
may be restricted due to regulatory requirements related to hydroelectric
licensed projects.
Note K - 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 $49,807 $46,506 $44,124
Federal and state payroll and other taxes 8,909 7,894 7,807
------- ------- -------
$58,716 $54,400 $51,931
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 $103,529,000, $103,961,000, and $94,366,000, including
capitalized construction costs of $24,671,000, $22,396,000, and $20,335,000,
for each of the years 1995, 1994, and 1993, respectively.
New England Power Company
Operating Statistics (Unaudited)
Year Ended December 31, 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Sources of Energy (Thousands of kWh)
Net generation thermal 11,547,85610,971,31911,621,03812,087,77513,569,122
Net generation conventional
hydro 1,257,533 1,352,600 1,253,925 1,212,155 1,507,656
Generation pumped storage 519,931 525,653 548,358 530,796 498,895
Net generation nuclear 1,812,468 1,767,959 1,696,677 1,592,340 1,033,332
Nuclear entitlements 1,278,598 2,535,534 2,196,998 2,214,976 2,713,947
Purchased energy from
non-affiliates (B) 8,857,842 8,674,191 7,800,975 7,287,856 6,323,144
Energy for pumping (716,279) (723,352) (750,784) (738,364) (685,659)
--------------------------------------------------
Total generated and
purchased 24,557,94925,103,90424,367,18724,187,53424,960,437
Losses, company use, etc. (690,626) (635,695) (548,228) (632,850) (589,001)
--------------------------------------------------
Total sources of energy 23,867,32324,468,20923,818,95923,554,68424,371,436
Sales of Energy (Thousands of kWh)
Resale:
Affiliated companies 22,338,30122,182,76121,858,49121,497,99321,496,098
Less generation by
affiliated Company (A) (64,035) (5,781) (4,506) (83,753) (162,844)
--------------------------------------------------
Net sales to affiliated
companies 22,274,26622,176,98021,853,98521,414,24021,333,254
Other utilities (B) 947,537 1,731,225 1,528,686 1,705,591 2,613,034
Municipals 633,970 551,866 426,525 415,659 411,171
--------------------------------------------------
Total sales for resale 23,855,77324,460,07123,809,196 23,535,490 24,357,459
Ultimate customers 11,550 8,138 9,763 19,194 13,977
--------------------------------------------------
Total sales of energy 23,867,32324,468,20923,818,95923,554,68424,371,436
Operating Revenue (In Thousands)
Revenue from electric sales
Resale:
Affiliated companies $1,498,848$1,448,503$1,459,619$1,450,831$1,384,222
Less G and T
credits (A) (43,532) (32,346) (26,001) (38,697) (50,961)
Net sales to affiliated
companies 1,455,316 1,416,157 1,433,618 1,412,134 1,333,261
Other utilities (B) 41,193 56,306 52,695 55,156 76,162
Municipals 37,036 32,055 27,574 26,980 25,755
--------------------------------------------------
Total revenue from
sales for resale 1,533,545 1,504,518 1,513,887 1,494,270 1,435,178
Ultimate customers 945 606 752 1,399 1,097
---------------------------------------- ---------
Total revenue from
electric sales 1,534,490 1,505,1241,514,639 1,495,669 1,436,275
Other operating revenue 36,049 35,633 34,375 35,206 36,016
--------------------------------------------------
Total operating revenue $1,570,539$1,540,757$1,549,014$1,530,875$1,472,291
Annual Maximum Demand
(kW one hour peak) 4,381,000 4,385,000 4,081,0003,964,000 4,250,000
<FN>
(A) The generation and transmission facilities of affiliates are operated as an
integrated part of the Company's power supply and the affiliates receive generation and
transmission (G and T) credits against their power bills for costs of facilities so
integrated.
(B)Includes transactions with the New England Power Pool.
</FN>
New England Power Company
Selected Financial Information
Year Ended December 31, (In Millions) 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $941 $942 $939 $907 $861
Fuel cost recovery 594 563 576 589 575
Other 36 36 34 35 36
------ ------ ------ ------ ------
Total operating revenue $1,571 $1,541 $1,549 $1,531 $1,472
Net income $151 $149 $141 $134 $135
Total assets $2,648 $2,613 $2,441 $2,387 $2,277
Capitalization:
Common equity $889 $877 $850 $825 $797
Cumulative preferred stock 61 61 61 86 86
Long-term debt 735 695 667 666 730
------ ------ ------ ------ ------
Total capitalization $1,685 $1,633 $1,578 $1,577 $1,613
Preferred dividends declared $3 $3 $5 $6 $6
Common dividends declared $135 $119 $111 $100 $116
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
1995
Operating revenue $391,118 $378,177 $421,935 $379,309
Operating income $40,089 $33,454 $69,669 $42,201
Net income $30,982 $27,689 $61,684 $31,072
1994
Operating revenue $399,574 $356,488 $419,555 $365,140
Operating income $56,873 $32,192 $55,217 $26,239
Net income $49,189 $26,182 $49,818 $24,184
Per share data is not relevant because the Company's common stock is wholly-owned by New
England Electric System.
A copy of New England Power 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 New England Power Company,
Shareholder Services Department, 25 Research Drive, Westborough, Massachusetts 01582.