ANNUAL REPORT 1994
NEW ENGLAND POWER COMPANY
A Subsidiary of
New England Electric System
[LOGO] New England Power
A New England Electric System company
NEW ENGLAND POWER COMPANY
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of December 31, 1994)
Joan T. Bok John W. Newsham
Chairman of the Board of New Executive Vice President of the Company
England Electric System and Vice President of New England
Electric System
Frederic E. Greenman
Vice President, General Counsel, John W. Rowe
and Assistant Clerk of the Company Chairman of the Company and President
and Senior Vice President, General and Chief Executive Officer of New
Counsel, and Secretary of New England Electric System
England Electric System
Jeffrey D. Tranen
Alfred D. Houston President of the Company and Vice
Executive Vice President and Chief President of New England Electric System
Financial Officer of New England
Electric System
Officers
(As of December 31, 1994)
John W. Rowe John F. Malley
Chairman of the Company and Vice President
President and Chief Executive
Officer of New England Electric Arnold H. Turner
System Vice President
Jeffrey D. Tranen Jeffrey W. VanSant
President of the Company and Vice Vice President
President of New England Electric
System Michael E. Jesanis
Treasurer of the Company and of New
John W. Newsham England Electric System
Executive Vice President of the
Company and Vice President of New Robert King Wulff
England Electric System Clerk of the Company and of certain
affiliates
Lawrence E. Bailey
Vice President John G. Cochrane
Assistant Treasurer of the Company and
Jeffrey A. Donahue of an affiliate
Vice President
Kirk L. Ramsauer
Frederic E. Greenman Assistant Clerk of the Company and of an
Vice President, General Counsel, and affiliate
Assistant Clerk of the Company and
Senior Vice President, General Howard W. McDowell
Counsel, and Secretary of New Controller of the Company and of certain
England Electric System affiliates
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 1994, 94 percent of the Company's revenue from the sale
of electricity was derived from sales for resale to affiliated companies and
6 percent from sales for resale to municipal and other utilities.
The Company, through its own generating units, entitlements and purchase
power contracts, has a total capability of 5,533 megawatts. In 1994, the
Company's energy mix was 37 percent coal, 19 percent nuclear, 16 percent gas,
12 percent hydro, 10 percent oil, and 6 percent renewable non-utility
generation.
The Company is a member of the New England Power Pool, which provides
for the coordination of the planning and operation of the generation and
transmission facilities in New England, and the region-wide central dispatch
of generation.
Report of Independent Accountants
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, 1994 and 1993 and the related statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 27, 1995
NEW ENGLAND POWER COMPANY
Financial Review
Overview
Net income increased by $8 million in 1994 compared with 1993,
reflecting decreased purchased power charges excluding fuel, lower interest
expense and increased allowance for funds used during construction. The
decrease in purchased power was due to overhauls and refueling shutdowns of
partially-owned nuclear power suppliers in 1993. 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 in 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.
Net income increased by $7 million in 1993, primarily as a result of
increased revenues attributable to increased peak-demands for electricity in
the summer of 1993, lower costs of scheduled overhauls at thermal generating
units in 1993, and reduced interest costs achieved through debt refinancings.
The increased earnings were partially offset by the one-time charge in
connection with the early retirement program discussed above as well as
increases in operation and maintenance expenses.
Rate Activity
In February 1995, the Federal Energy Regulatory Commission (FERC)
approved a rate agreement filed by the Company. Under the agreement, which
is effective January 1995, the Company's base rates will be frozen until
1997. Before this rate agreement, the Company's rate structure contained two
surcharges which 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). Under the rate agreement, these two surcharges, which were due
to expire in mid-1995, will be rolled into base rates. The agreement also
provides for the costs resulting from the Manchester Street Station
repowering project, which is expected to be completed in late 1995, to be
included in rate base, without a rate increase (see "Utility Plant
Expenditures and Financings" section). In addition, the agreement allows the
Company to recover approximately $50 million of deferred costs associated
with terminated purchased power contracts and postretirement benefits other
than pensions (PBOPs) over seven years. The agreement also provides for full
current recovery of PBOP costs commencing in 1995. The agreement further
provides for the recovery over three years of $27 million of costs related
to the dismantling of a retired Narragansett generating station and the
replacement of a turbine rotor at one of the Company's generating units. The
agreement also increases the Company's recovery of depreciation expense by
approximately $8 million annually to recognize costs associated with 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 due to be recovered in 1995 pursuant to a 1988 settlement
agreement will be deferred and recovered in 1996. The agreement further
allows for deferral of additional purchased power contract termination costs
and any increases in nuclear decommissioning payments for recovery in future
rates. Yankee Atomic Electric Company, of which the Company is a 30 percent
owner, recently announced a new decommissioning cost estimate, which, if
approved by the FERC, would increase annual billings to the Company by $11
million, beginning in late 1995 and ending in July 2000. (See Note C-1 of
the "Notes to Financial Statements" for a discussion of a 1995 shutdown of
the Maine Yankee nuclear unit.)
The settlement rates provide for approximately $24 million in revenues
in 1996 to complete the amortization of pre-1988 Seabrook 1 costs and the
costs associated with the cancelled Seabrook 2 nuclear unit. To the extent
the settlement rates stay in effect beyond 1996, the agreement provides that
these revenues be applied first to accelerate recovery of deferred PBOP
costs, and then to additional amortization of the Company's investment in the
Millstone 3 nuclear unit.
Finally, the agreement provided that the Company would reimburse its
wholesale customers for approximately $15 million of discounts provided by
these customers under service extension discount 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.
The FERC's approval of this rate agreement applies to all of the
Company's customers except the Town of Norwood, Massachusetts and the Milford
Power Limited Partnership (MPLP), who intervened in the rate case. A
separate hearing will be conducted to determine the appropriate rate to
charge these two parties, who represent less than 2 percent of the Company's
sales.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
----------------------------------------
(In Millions) 1994 1993
- ------------- ---- ----
Sales growth $10 $17
Narragansett integrated facilities credit
(excluding fuel) (6) 11
Rate changes - 3
Fuel recovery (6) (4)
Accrued NEEI fuel revenues (7) (8)
Other 1 (1)
--- ---
$(8) $18
=== ===
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 credit in 1994 reflects increased
dismantlement costs being incurred on Narragansett's previously retired South
Street generating facility. The decrease in the credit in 1993 shown in the
table above reflects reduced non-fuel related credits due to the mid-1992
sale by Narragansett to the Company of 90 percent of its ownership interest
in the Manchester Street Station (see "Utility Plant Expenditures and
Financings" section).
Accrued New England Energy Incorporated (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).
Operating Expenses
The following table summarizes the changes in total operating expenses
discussed below:
Increase (Decrease) in Operating Expenses
-----------------------------------------
(In Millions) 1994 1993
- ------------ ---- ----
Fuel costs $(7) $(3)
Accrued NEEI fuel costs (7) (8)
Purchased energy excluding fuel (11) (2)
Other operation and maintenance 18 13
Depreciation and amortization 6 4
Taxes 5 15
--- ---
$ 4 $19
=== ===
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.
Purchased energy excluding fuel represents the remainder of purchased
electric energy costs. The 1994 decrease in purchased energy excluding fuel
was primarily due to overhauls and refueling shutdowns of partially-owned
nuclear power suppliers in 1993.
The increase in other operation and maintenance expense 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.
The increase in other operation and maintenance expense in 1993
primarily reflects the previously mentioned early retirement program costs,
$2 million associated with the adoption of a new accounting standard for
postemployment benefits, increased computer systems development costs, and
general increases in other areas. These increases were partially offset by
an $8 million decrease in generating plant maintenance costs.
The increases in depreciation and amortization expense in 1994 and 1993
primarily reflect increased amortization of Seabrook 1 as part of a 1988 rate
settlement and increased depreciation on new plant expenditures. The
increase in 1993 was partially offset by a decrease in depreciation as a
result of new lower depreciation rates established in a prior rate case,
which went into effect in March 1992.
The increase in taxes in 1994 and 1993 primarily reflects increased
income taxes and municipal property taxes. The increase in income taxes in
1993 also includes the effects of the 1993 increase in the federal income tax
rate from 34 percent to 35 percent.
Interest Expense
The decreases in interest expense in 1994 and 1993 are primarily due to
significant refinancings of corporate debt at lower interest rates during
1993 and 1992. 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 1994 and 1993 due to increased construction work in
progress associated with the repowering of the Manchester Street Station (see
"Utility Plant Expenditures and Financings" section).
Fuel Supply
NEEI is engaged in domestic oil and gas exploration, development, and
production. NEEI operates under an intercompany pricing policy (Pricing
Policy) with the Company which was approved by the Securities and Exchange
Commission under the Public Utility Holding Company Act of 1935. The Pricing
Policy requires the Company to purchase all fuel meeting its specifications
offered to it by NEEI. Due to precipitate declines in oil and gas prices,
NEEI has incurred operating losses since 1986, and expects to incur
substantial additional losses in the future. These losses are being passed
on to the Company under the Pricing Policy. The Company is allowed to
recover these losses from its customers under the Company's 1988 FERC rate
settlement, which 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.
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 in its
operations a range of potentially hazardous products and by-products. New
England Electric System (NEES) subsidiaries currently have in place an
environmental audit program 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 (EPA) 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 would be successful. The Company believes that hazardous
waste liabilities for all sites of which it is aware will not be material to
its financial position.
Electric and Magnetic Fields (EMF)
In recent years, 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.
Legislation has been introduced in Massachusetts that, if passed, would
require state agencies to study existing EMF-related research and make
recommendations for further legislation.
Clean Air Requirements
Approximately 45 percent of the Company's electricity is produced at
eight older thermal generating units in Massachusetts. Six are fueled by
coal, one by oil, and one by oil and gas. The federal Clean Air Act requires
significant reduction in utility sulfur dioxide (SO2) and nitrogen oxides
(NOx) emissions that result from burning fossil fuels by the year 2000 to
reduce acid rain and ground-level ozone (smog).
The Company is reducing SO2 emissions under Phase 1 of the federal acid
rain program that became effective in 1995. The Company is also subject to
Massachusetts SO2 and NOx reduction regulations taking effect in 1995. The
SO2 and NOx reductions that are being made to meet 1995 Phase 1 requirements
have resulted in one-time operation and maintenance costs of $16 million and
capital costs of $88 million through December 31, 1994. Additional
expenditures in 1995 are expected to be less than $10 million and $30
million, respectively. Depending on fuel prices, the Company also expects
to incur up to $5 million annually in increased costs to purchase cleaner
fuels to meet SO2 emission reduction requirements.
All eight of the Company's thermal units will be subject to Phase 2 of
the federal and state acid rain regulations that become effective in 2000.
The Company believes that the SO2 controls already installed for the 1995
requirements will satisfy the Phase 2 acid rain regulations.
In connection with the federal ozone emission requirements, state
environmental agencies in ozone non-attainment areas are developing a second
phase of NOx reduction regulations that would have to be fully implemented
by the Company no later than 1999. While the exact costs are not known, the
Company estimates that the cost of implementing these regulations would not
jeopardize continued operation of its units.
The generation of electricity from fossil fuel also emits trace amounts
of certain hazardous air pollutants and fine particulates. An EPA study of
utility hazardous air pollutant emissions will be completed in 1995. The
study's conclusions could lead to new emission standards requiring costly
controls or fuel restrictions on the Company's plants. At this time, NEES
and its subsidiaries cannot estimate the impact the findings of this research
might have on the Company's operations.
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 megawatt (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 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 rate filing (see "Rate Activity"
section).
Competitive Conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, 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 generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of the Company's new generating capability has come from
independent generating sources and Hydro-Quebec.
Since 94 percent of the Company's revenues are from its affiliates that
serve retail customers, the Company is affected by increased competition that
these affiliates are facing in the retail market. Currently, retail
competition includes competition with alternative fuel suppliers (including
natural gas companies) for heating and cooling, competition with
customer-owned generation to displace purchases from electric utilities, and
direct competition among electric utilities to attract major new facilities
to their service territories. Electric utilities, including the NEES
companies, are under increasing pressure from large commercial and industrial
customers to discount rates or face the possibility that such customers might
relocate or seek alternate suppliers. Across the country, including the
states serviced by the NEES companies, there have been an increasing number
of proposals to allow retail customers to choose their electricity supplier,
with utilities required to deliver that electricity over their transmission
and distribution systems. In Massachusetts, the Massachusetts Division of
Energy Resources (DOER) proposed in January 1995 that the Massachusetts
Department of Public Utilities (MDPU) modify its regulations to allow retail
utility customers to choose a supplier and bid for access to the local
utility's transmission and distribution systems in situations where new
generating capacity is needed. The NEES companies have indicated their
support for the DOER proposal. The Company's Massachusetts retail affiliate
has announced plans to propose a limited bidding experiment consistent with
the DOER proposal. Also in Massachusetts, the MDPU initiated a proceeding
in February 1995 regarding electric industry regulation and structure. In
Rhode Island, the Rhode Island Public Utilities Commission has convened a
task force of utilities, commercial and industrial customers, regulators, and
other interested parties to prepare a report by May 1995 regarding
restructuring the industry. In New Hampshire, the New Hampshire Public
Utilities Commission is considering the proposal of a new company to sell
electricity at retail to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning
and operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could
be substantial, have been referred to by the industry as stranded costs.
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have
taken the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the
FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a
utility may recover such stranded costs from a departing wholesale
requirements customer. On appeal, the United States Court of Appeals for the
District of Columbia Circuit has questioned whether allowing utilities to
recover stranded costs is anti-competitive and the Court remanded the case
back to the FERC for further proceedings and development of the competitive
issues.
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The wholesale business unit has responded to increased competition by
freezing base rates until at least 1997 (wholesale base rates were last
raised in March 1992), terminating certain purchased power and gas pipeline
contracts, shutting down uneconomic generating stations, and accelerating the
recovery of uneconomic assets and other deferred costs. In addition, the
Company's wholesale tariff requires its wholesale customers, including NEES's
retail subsidiaries, to provide seven years notice before they may terminate
the tariff.
The retail business unit's response to competition includes the
EnergyFIT program, which offers comprehensive value-added services for large
business customers, intensified business development efforts, including
economic development rates and service packages to encourage businesses to
locate in the retail companies' service territories, and development of new
pricing and service options for customers. Additionally, more than 80
percent of the NEES companies' currently eligible large commercial and
industrial customers have signed service extension discount contracts
providing for discounts in exchange for agreements requiring three to five
years notice before they may change electricity suppliers. As part of their
long-term planning process, the NEES companies are from time to time
evaluating other strategies, such as business combinations and other forms
of restructuring, to better respond to the changing competitive environment.
Electric utility rates are generally 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. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable. In
addition, if, because of competition, utilities are unable to recover all of
their costs in rates, it may be necessary to write off those costs that are
not recoverable.
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $229 million for 1994
including $142 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 and short-term debt
issues. Cash expenditures for utility plant for 1995 are estimated to be
$160 million (including $110 million related to the repowering of Manchester
Street Station). Internally generated funds are estimated to provide 90
percent of the Company's 1995 capital expenditure requirements for utility
plant. Cash expenditures for utility plant for 1995 are also expected to be
funded through the issuance of long-term and short-term debt.
In 1994, the Company issued $28 million of mortgage bonds at rates
ranging from 8.10 percent to 8.53 percent. The Company has issued $25
million of long-term debt to date in 1995 at interest rates ranging from 7.40
percent to 7.94 percent. In addition, the Company has refinanced $10 million
of variable rate mortgage bonds to date in 1995. The Company plans to issue
an additional $25 million of long-term debt in 1995.
The Company's major construction project is the repowering of Manchester
Street Station, a 140 MW electric generating station in Providence, Rhode
Island. Repowering will more than triple the power generation capacity of
Manchester Street Station and substantially increase the plant's thermal
efficiency. To facilitate financing this project, Narragansett sold a 90
percent interest in the existing station to the Company effective July 1,
1992. The total cost for the generating station, scheduled to be placed in
service in late 1995, is estimated to be approximately $520 million,
including AFDC. At December 31, 1994, $298 million, including AFDC, had been
spent on the generating station ($270 million by the Company). 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. Substantial commitments have been made relative
to future planned expenditures for this project.
At December 31, 1994, the Company had $146 million of short-term debt
outstanding including $129 million in the form of commercial paper borrowings
and $17 million of borrowings from affiliates. At December 31, 1994, the
Company had lines of credit and bond purchase facilities with banks totaling
$490 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, 1994.
March 22, 1995
NEW ENGLAND POWER COMPANY
Statements of Income
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating revenue, principally from
affiliates $1,540,757 $1,549,014 $1,530,875
Operating expenses:
Fuel for generation 260,540 273,347 288,868
Purchased electric energy 513,583 525,985 524,134
Other operation 196,610 186,087 162,134
Maintenance 110,528 103,261 114,210
Depreciation and amortization 137,979 131,932 127,733
Taxes, other than income taxes 54,400 51,931 50,828
Income taxes 96,596 93,997 79,799
---------- ---------- ----------
Total operating expenses 1,370,236 1,366,540 1,347,706
---------- ---------- ----------
Operating income 170,521 182,474 183,169
Other income:
Allowance for equity funds used
during construction 9,142 3,252 2,722
Equity in income of nuclear power
companies 4,816 5,646 6,252
Other income (expense) - net, including
related taxes (293) (566) 1,822
---------- ---------- ----------
Operating and other income 184,186 190,806 193,965
---------- ---------- ----------
Interest:
Interest on long-term debt 38,711 45,837 59,382
Other interest 1,956 5,427 2,071
Allowance for borrowed funds used
during construction - credit (5,854) (1,926) (1,639)
---------- ---------- ----------
Total interest 34,813 49,338 59,814
---------- ---------- ----------
Net income $ 149,373 $ 141,468 $ 134,151
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31,
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Retained earnings at beginning of year $ 346,153 $ 321,699 $ 293,113
Net income 149,373 141,468 134,151
Dividends declared on cumulative
preferred stock (3,440) (4,883) (5,591)
Dividends declared on common stock,
$18.50, $17.25, and $15.50 per share,
respectively (119,323) (111,261) (99,974)
Premium on redemption of preferred stock (870)
---------- ---------- ----------
Retained earnings at end of year $ 372,763 $ 346,153 $ 321,699
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND POWER COMPANY
Balance Sheets
At December 31,
(In Thousands)
------------------------
1994 1993
---- ----
Assets
Utility plant, at original cost $2,524,544 $2,445,702
Less accumulated provisions for depreciation
and amortization 1,001,393 943,750
---------- ----------
1,523,151 1,501,952
Net investment in Seabrook 1 under rate settlement
(Note C-2) 38,283 103,344
Construction work in progress 314,777 165,860
---------- ----------
Net utility plant 1,876,211 1,771,156
---------- ----------
Investments:
Nuclear power companies, at equity (Note C-1) 46,349 46,342
Non-utility property and other investments 22,980 19,927
---------- ----------
Total investments 69,329 66,269
---------- ----------
Current assets:
Cash 377 610
Accounts receivable:
Affiliated companies 197,655 201,674
Others 69,532 58,581
Fuel, materials, and supplies, at average cost 73,361 55,955
Prepaid and other current assets 33,729 26,454
---------- ----------
Total current assets 374,654 343,274
---------- ----------
Accrued Yankee Atomic costs (Note C-1) 122,452 103,501
Deferred charges and other assets (Note A-6) 170,192 157,087
---------- ----------
$2,612,838 $2,441,287
========== ==========
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 372,763 346,153
---------- ----------
Total common equity 876,590 849,980
Cumulative preferred stock, par value $100 per
share (Note H) 60,516 61,028
Long-term debt 695,466 667,448
---------- ----------
Total capitalization 1,632,572 1,578,456
---------- ----------
Current liabilities:
Short-term debt (including $16,575,000 and
$8,325,000 to affiliates) 145,575 50,525
Accounts payable (including $69,089,000 and
$58,056,000 to affiliates) 179,761 144,100
Accrued liabilities:
Taxes 6,133 9,337
Interest 9,914 10,086
Other accrued expenses (Note A-7) 10,866 38,313
Dividends payable 14,512
---------- ----------
Total current liabilities 352,249 266,873
---------- ----------
Deferred federal and state income taxes 364,073 344,077
Unamortized investment tax credits 59,014 62,591
Accrued Yankee Atomic costs (Note C-1) 122,452 103,501
Other reserves and deferred credits 82,478 85,789
Commitments and contingencies (Note D)
---------- ----------
$2,612,838 $2,441,287
========== ==========
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)
------------------------------------
1994 1993 1992
---- ---- ----
Operating activities:
Net income $ 149,373 $ 141,468 $ 134,151
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 142,764 135,746 130,562
Deferred income taxes and
investment tax credits - net 23,051 20,665 6,378
Allowance for funds used during
construction (14,996) (5,178) (4,361)
Early retirement program 2,967
Decrease (increase) in accounts
receivable (6,932) 31,323 120
Decrease (increase) in fuel,
materials, and supplies (17,406) 16,902 (12,079)
Decrease (increase) in prepaid and
other current assets (7,275) (4,908) (15,938)
Increase (decrease) in accounts payable 35,661 (35,913) 26,437
Increase (decrease) in other current
liabilities (30,823) 25,205 (16,374)
Other, net (26,845) (46,559) (4,995)
--------- --------- ---------
Net cash provided by operating
activities $ 246,572 $ 281,718 $ 243,901
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $(229,015) $(156,614) $(115,093)
Other investing activities (3,053) (2,402)
Purchase of 90 percent interest in
Manchester Street Station from
affiliate ( 3,249)
--------- --------- ---------
Net cash used in investing
activities $(232,068) $(159,016) $(118,342)
--------- --------- ---------
Financing Activities:
Dividends paid on common stock $(133,835) $(120,936) $ (75,787)
Dividends paid on preferred stock (3,440) (4,883) (5,591)
Changes in short-term debt 95,050 32,200 18,325
Long-term debt - issues 28,000 224,000 260,000
Long-term debt - retirements (224,000) (337,000)
Preferred stock - retirements (512) (25,000)
Premium on reacquisition of long-term
debt (3,255) (12,294)
Premium on redemption of preferred
stock (870)
--------- --------- ---------
Net cash used in financing
activities $ (14,737) $(122,744) $(152,347)
--------- --------- ---------
Net decrease in cash and cash
equivalents $ (233) $ (42) $ (26,788)
Cash and cash equivalents at
beginning of year 610 652 27,440
--------- --------- ---------
Cash and cash equivalents at end
of year $ 377 $ 610 $ 652
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $ 32,510 $ 42,390 $ 65,210
--------- --------- ---------
Federal and state income taxes paid $ 83,455 $ 78,300 $ 65,484
--------- --------- ---------
Dividends received from investments
at equity $ 4,809 $ 5,103 $ 5,932
--------- --------- ---------
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. System of Accounts:
The accounts of the Company are maintained in accordance with the
Uniform System of Accounts prescribed by regulatory bodies having
jurisdiction.
2. 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 1994, an average of $25 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 7.8 percent, 8.1
percent, and 9.7 percent in 1994, 1993, and 1992, respectively.
3. 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)
------------------------------------
1994 1993 1992
---- ---- ----
Depreciation $ 52,834 $ 53,128 $ 55,858
Nuclear decommissioning costs (Note A-4) 1,951 1,951 1,890
Amortization:
Investment in Seabrook 1 nuclear unit
under rate settlement (Note C-2) 65,061 58,437 52,443
Oil Conservation Adjustment 11,854 12,137 11,263
Property losses 6,279 6,279 6,279
-------- -------- --------
Total depreciation and amortization
expense $137,979 $131,932 $127,733
======== ======== ========
Depreciation is provided annually on a straight-line basis. The
provisions for depreciation (excluding nuclear decommissioning) as a
percentage of weighted average depreciable property were 2.4 percent in 1994,
2.5 percent in 1993, and 2.7 percent in 1992.
The Oil Conservation Adjustment is designed to recover expenditures for
coal conversion facilities at the Company's Salem Harbor Station by 1995.
At December 31, 1994, such unamortized coal conversion costs included in
utility plant were $4,467,000.
4. Nuclear Plant Decommissioning and Nuclear Fuel Disposal:
The Company is recovering its share of projected decommissioning costs
for the Millstone 3 nuclear generating unit (Millstone 3) and the Seabrook
1 nuclear generating unit (Seabrook 1) through depreciation expense. The
Company records decommissioning cost expense on its books consistent with its
rate recovery. ln addition, the Company is paying its portion of projected
decommissioning costs for all of the Yankee nuclear power companies
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
(Yankees) through purchased power expense. Such costs reflect estimates of
total decommissioning costs approved by the Federal Energy Regulatory
Commission (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 its plant. 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. Listed below is information on each
nuclear plant in which the Company has an ownership interest. (See Note C-1
for a discussion of Yankee Atomic nuclear power station decommissioning.)
The Company's share of (in millions of dollars)
-----------------------------------------------
Estimated
Decommissioning
Ownership Cost Fund License
Unit Interest (in 1994 $) Balances** Expiration
- ---- --------- --------------- ---------- ----------
Connecticut Yankee 15% 53 22 2007
Maine Yankee *** 20% 66 22 2008
Vermont Yankee 20% 66 23 2012
Millstone 3 * 12% 53 11 2025
Seabrook 1 * 10% 36 4 2026
* Fund balances are included in "Non-utility property and other
investments" on the balance sheet 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.
In accordance with its recent rate agreement which became effective in
1995, the Company is allowed to defer for later recovery any increases in
decommissioning payments over the level included in rates until its next rate
filing becomes effective.
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
which do not currently exist.
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 the Millstone 3 and Seabrook 1 nuclear units. 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 recovered from customers through the
Company's fuel clause.
5. Cash:
The Company classifies short-term investments with a remaining maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
Outstanding checks are therefore recorded in accounts payable until such time
as the banks present them for payment.
6. Deferred Charges and Other Assets:
The components of deferred charges and other assets are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Regulatory assets:
Deferred SFAS No. 109 costs (see Note B) $ 34,482 $ 41,114
Unamortized losses on reacquired debt 34,862 37,107
Purchased power termination costs 29,012 28,400
Deferred gas pipeline charges (see Note D-4) 37,562 13,187
Unamortized property losses 7,373 12,745
Deferred SFAS No. 106 costs (see Note E-2) 19,149 10,538
Other 2,542 8,928
-------- --------
164,982 152,019
Other deferred charges and other assets 5,210 5,068
-------- --------
$170,192 $157,087
======== ========
Electric utility rates are generally 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. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable.
Approximately $100 million of the regulatory assets at December 31, 1994
listed above are expected to be recovered within 10 years, with the majority
of the remaining balance to be recovered within the following 20 years. The
only items for which the majority of the balance shown above will not be
recovered within the next 10 years are the deferred SFAS No. 109 costs and
the deferred gas pipeline charges.
7. Other Accrued Expenses:
The components of other accrued expenses are as follows:
At December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Accrued wages and benefits $ 6,397 $10,619
Capital lease obligations due within one year 4,324 4,151
Accrued purchased power termination costs 21,900
Other 145 1,643
------- -------
$10,866 $38,313
======= =======
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes
- ---------------------
The Company and other subsidiaries participate with New England Electric
System (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 through 1991.
Total income taxes in the statements of income are as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Income taxes charged to operations $96,596 $93,997 $79,799
Income taxes charged (credited) to
"Other income" (994) 838 2,627
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Current income taxes $72,551 $74,171 $76,048
Deferred income taxes 26,628 23,270 7,706
Investment tax credits--net (3,577) (2,606) (1,328)
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
Investment tax credits are deferred and amortized over the estimated
lives of the property giving rise to the credits. Since the Tax Reform Act
of 1986 generally eliminated investment tax credits, the amounts shown above
principally reflect the amortization of investment tax credits generated in
prior years.
Total income taxes, as shown above, consist of federal and state
components as follows:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Federal income taxes $78,274 $77,593 $67,830
State income taxes 17,328 17,242 14,596
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
With regulatory approval of the FERC, the Company has adopted
comprehensive interperiod tax allocation (normalization) for temporary
book/tax differences.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note B - Income Taxes - (continued)
- ---------------------
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)
---------------------------
1994 1993 1992
---- ---- ----
Computed tax at statutory rate $85,741 $82,706 $73,636
Increases (reductions) in tax resulting
from:
Amortization of investment tax credits (3,045) (2,511) (3,210)
State income taxes, net of federal income
tax benefit 11,263 10,770 9,634
All other differences 1,643 3,870 2,366
------- ------- -------
Total income taxes $95,602 $94,835 $82,426
======= ======= =======
The Financial Accounting Standards Board established Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes"
which became effective in 1993. The application of this new standard did not
have a significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Deferred tax asset:
Plant related $ 96 $ 86
Investment tax credits 25 26
All other 29 39
----- -----
150 151
----- -----
Deferred tax liability:
Plant related (384) (373)
Equity AFDC (47) (48)
All other (83) (74)
----- -----
(514) (495)
----- -----
Net deferred tax liability $(364) $(344)
===== =====
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appeared on
the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily included deferred income taxes of $12 million related to utility
plant and $5 million related to losses on reacquired debt, partially offset
by deferred tax credits related to Seabrook 2 property losses of $5 million
and rate adjustment mechanisms of $6 million.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note C - Nuclear Power Investments
- ----------------------------------
1. Yankee Nuclear Power Companies:
The Company has minority interests in the four Yankees. These ownership
interests are accounted for on the equity method. The Company's share of the
expenses of the Yankee units is accounted for on the "Purchased electric
energy" line on the statements of income. A summary of combined results of
operations, assets and liabilities of the four Yankees is as follows:
(In Thousands)
------------------------------------
1994 1993 1992
---- ---- ----
Operating revenue $ 631,940 $ 700,148 $ 684,775
========== ========== ==========
Net income $ 30,345 $ 30,061 $ 35,298
========== ========== ==========
Company's equity in net income $ 4,816 $ 5,646 $ 6,252
========== ========== ==========
Net plant 537,103 591,650 666,685
Other assets 1,458,186 1,286,923 1,221,905
Liabilities and debt (1,748,960) (1,633,139) (1,644,962)
---------- ---------- ----------
Net assets $ 246,329 $ 245,434 $ 243,628
========== ========== ==========
Company's equity in net assets $ 46,349 $ 46,342 $ 45,799
========== ========== ==========
Company's purchased electric energy $ 106,404 $ 118,362 $ 118,465
========== ========== ==========
At December 31, 1994, $12 million of undistributed earnings of the
nuclear power companies were included in the Company's retained earnings.
The Company has a 30 percent ownership interest in Yankee Atomic, which
owns a 185 megawatt (MW) nuclear generating station in Rowe, Massachusetts.
The station began commercial service in 1960. At December 31, 1994, the
Company's investment in Yankee Atomic was approximately $7 million. In
February 1992, the Yankee Atomic board of directors decided to permanently
cease power operation of, and in time decommission, the facility.
In March 1993, the FERC approved a settlement agreement that allows
Yankee Atomic to recover all but $3 million of its approximately $50 million
remaining investment in the plant over the period extending to July 2000,
when the plant's Nuclear Regulatory Commission (NRC) operating license would
have expired. Yankee Atomic recorded the $3 million before-tax write-down
in 1992. The settlement agreement also allows Yankee Atomic to earn a return
on the unrecovered balance during the recovery period and to recover other
costs, including an increased level of decommissioning costs, over this same
period. Decommissioning cost recovery increased from $6 million per year to
$27 million per year for the period 1993 to 1995. In the fourth quarter of
1994, Yankee announced a new decommissioning cost estimate that, subject to
approval by the FERC, would increase billings to the Company by an additional
$11 million per year through July 2000.
The Company has recorded an estimate of its entire future payment
obligations to Yankee Atomic as a liability on its balance sheet and an
offsetting regulatory asset reflecting its expected future rate recovery of
such costs. This liability and related regulatory asset amounted to
approximately $122 million each at December 31, 1994, and are included on
separate lines on the balance sheet.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note C - Nuclear Power Investments (continued)
- ----------------------------------
The Company has a 20 percent ownership interest in Maine Yankee which
owns an 880 MW nuclear generating station in Wiscasset, Maine. Since January
1995, the station has been shut down for refueling and inspection. On the
basis of preliminary results of testing and analysis performed during this
shutdown, Maine Yankee has detected substantially greater deterioration of
its steam generator tubes than had been previously found and is unable to
predict its effect on the future of the unit.
2. Jointly-Owned Nuclear Generating Units:
The Company is also a 12 percent and 10 percent 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 $400 million. The Company's rate recovery of its investment
in Seabrook 1 was resolved through two separate rate settlement agreements.
A portion of the Company's pre-1988 investment is being recovered in base
rates over a period of seven and one-half years ending in mid-1995. Under
the Company's rate agreement, that was recently approved by the FERC,
approximately $15 million of the $38 million in Seabrook 1 costs due to be
recovered in 1995 pursuant to a 1988 settlement agreement will be deferred
and recovered in 1996. This investment, net of amortization, is shown on a
separate line on the balance sheets. The Company's net investment in
Seabrook 1 since January 1, 1988, which amounts to approximately $43 million
at December 31, 1994, is included in "Net utility plant" on the balance sheet
and is being recovered over 37 years. The Company's share of the related
expenses for Millstone 3 and Seabrook 1 is included in the operating expenses
of the Company's income statements.
Note D - Commitments and Contingencies
- --------------------------------------
1. Oil and Gas Operations:
New England Energy Incorporated (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 approved by the Securities and Exchange Commission under the Public
Utility Holding Company Act of 1935. 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 precipitate declines in 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 such 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.
In 1994, 1993, and 1992, the Company recorded accrued fuel expenses and
accrued revenues of $40 million, $46 million, and $55 million, respectively,
representing losses incurred by NEEI in each year. Under the settlement,
certain NEEI costs incurred subsequent to March 1, 1988 are subject to normal
regulatory review.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
2. Plant Expenditures:
The Company's utility plant expenditures are estimated to be $160
million in 1995. At December 31, 1994, 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
$78 million in utility plant at December 31, 1994. 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, 1994, the Company had guaranteed approximately $32 million.
4. Natural Gas Pipeline Capacity:
In connection with the Company's efforts to reduce sulfur dioxide
emissions and repower generating units, the Company has signed several
contracts for natural gas pipeline capacity and gas supply. These agreements
require minimum fixed payments. The Company's minimum net payments are
currently estimated to be approximately $65 million in 1995 and $70 million
per year during 1996 to 1999.
As part of a rate settlement, the Company is 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 is completed. The Company has deferred payments
of approximately $38 million as of December 31, 1994 (see Note A-6). The
Company has been using a portion of this capacity to sell natural gas.
Proceeds from the sale of natural gas and pipeline capacity of $55 million,
$21 million, and $3 million in 1994, 1993, and 1992, respectively, have been
passed to customers through the Company's fuel clause. These proceeds have
been included on the fuel for generation line in the Company's statements of
income as an offset to the related fuel expense.
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 in its
operations a range of potentially hazardous products and by-products. The
NEES subsidiaries currently have in place an environmental audit program
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
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
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 would be successful. The Company believes that hazardous
waste liabilities for all sites of which it is aware will not be material to
its financial position.
6. 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 only $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 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 calculated in 1993, is to be adjusted at
least every five years to reflect inflationary changes. The Company's
current interest in the Yankees (excluding Yankee Atomic), Millstone 3, and
Seabrook 1 would subject the Company to a $58.0 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 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 $17 million per year.
7. Long-term Contracts for the Purchase of Electricity:
The Company purchases a portion of its electricity requirements pursuant
to long-term contracts with owners of various generating units. These
contracts expire in various years from 1995 to 2029.
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 majority of the payments under these contracts
are to the Yankees (excluding Yankee Atomic--see Note C-1) and Ocean State
Power, entities in which the Company or its affiliates hold ownership
interests.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note D - Commitments and Contingencies (continued)
- --------------------------------------
The fixed portion of payments under these contracts totaled $190 million
in 1994 and $220 million in 1993 and 1992. These contracts have minimum
fixed payment requirements of $215 million in 1995, $195 million in 1996,
$190 million in 1997 and 1998, $185 million in 1999, and approximately $2
billion thereafter.
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 $210 million in 1994 and 1993 and $200 million in 1992.
8. 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 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 recent rate filing.
Note E - Employee Benefits
- --------------------------
1. Pension Plans:
The Company participates with other subsidiaries of NEES in
noncontributory defined-benefit plans covering substantially all employees
of the Company. The plans provide pension benefits based on the employee's
compensation during the five years before 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 required contribution under federal law or greater than the maximum
tax deductible amount.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
Net pension cost for 1994, 1993, and 1992 included the following
components:
Year Ended December 31,
(In Thousands)
---------------------------
1994 1993 1992
---- ---- ----
Service cost--benefits earned during
the period $ 2,202 $ 1,953 $ 1,858
Plus (less):
Interest cost on projected benefit
obligation 6,403 6,070 5,558
Return on plan assets at expected
long-term rate (6,554) (5,850) (5,600)
Amortization 557 47 31
------- ------- -------
Net pension cost $ 2,608 $ 2,220 $ 1,847
======= ======= =======
Assumptions used to determine pension
cost:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future
compensation levels 4.35% 5.35% 6.70%
Expected long-term rate of return on
assets 8.75% 8.75% 9.00%
------- ------- -------
Actual return on plan assets $ 608 $ 8,949 $ 4,887
======= ======= =======
Service cost for 1993 does not reflect costs incurred in connection with
an early retirement program offered by the Company in that year (see Note
E-3).
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:
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
Retirement Plans,
(In Millions)
---------------------------
1994 1993
---- ----
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
-------- --------- -------- ---------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $251 $308 $251 $333
Non-vested 8 9 20 6
---- ---- ---- ----
Total $259 $317 $271 $339
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of projected
benefit liability $303 $355 $310 $383
Unrecognized prior service costs (8) (4) (8) (6)
SFAS No. 87 transition liability not
yet recognized (amortized) - (1) - (1)
Net loss not yet recognized
(amortized) (13) (33) (11) (45)
Additional minimum liability
recognized - - - 8
---- ---- ---- ----
282 317 291 339
---- ---- ---- ----
Pension fund assets at fair value 293 323 302 318
SFAS No. 87 transition asset not
yet recognized (amortized) (13) - (14) -
---- ---- ---- ----
280 323 288 318
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $ 3 $ 21
==== ==== ==== ====
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed effective
January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected
long-term rate of return on assets used to calculate pension cost was not
changed from the level shown in the table above. The plans' funded status
at December 31, 1994 was calculated using these revised rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions and Postemployment
Benefits:
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement
Benefits Other Than Pensions" (PBOPs) went into effect. 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.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
The total cost of PBOPs for 1994 and 1993 included the following
components:
Year Ended December 31,
(In Thousands)
---------------------
1994 1993
---- ----
Service cost--benefits earned during the period $1,628 $1,632
Plus (less):
Interest cost on the accumulated benefit
obligation 3,954 4,275
Return on plan assets at expected long-term
rate (1,111) (725)
Amortization 2,591 2,558
------ ------
Net postretirement benefit cost $7,062 $7,740
====== ======
Actual return on plan assets $ 54 $ 746
====== ======
The following table sets forth benefits earned and the plans' funded
status:
At December 31,
(In Millions)
---------------------
1994 1993
---- ----
Accumulated postretirement benefit obligation:
Retirees $ 31 $ 34
Fully eligible active plan participants 3 1
Other active plan participants 17 22
---- ----
Total benefits earned 51 57
Unrecognized transition obligation (46) (49)
Net gain (loss) not yet recognized 6 (1)
---- ----
11 7
Plan assets at fair value 15 12
---- ----
Prepaid postretirement benefit costs recorded
on books $ 4 $ 5
==== ====
1995 1994 1993
---- ---- ----
Assumptions used to determine
postretirement benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return on
assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note E - Employee Benefits (continued)
- --------------------------
The plans' funded status at December 31, 1994 and 1993 presented above
was calculated using the assumed rates in effect for 1995 and 1994,
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, 1994 by approximately $8 million and the net periodic cost for
the year 1994 by approximately $1 million.
The Company funds the annual tax deductible contributions. Plan assets
are invested in equity and debt securities and cash equivalents.
Prior to 1993, the Company recorded the cost of PBOPs when paid which
amounted to approximately $1.7 million in 1992. The Company has deferred all
increased costs that have resulted from the adoption of SFAS No. 106 in 1993.
Pursuant to a recently approved rate agreement, recovery of PBOP costs on a
current basis and recovery of $19 million of previously deferred amounts over
a seven year period commenced January 1, 1995. Therefore adoption of this
new accounting standard did not have a significant impact on net income.
3. 1993 Early Retirement and Special Severance Programs:
In February 1993, the Company offered a voluntary early retirement
program to non-union employees who were at least 55 years old with 10 years
of service. This program was part of an organizational review with the goal
of streamlining operations and reducing the work force. The early retirement
offer was accepted by 43 employees. A special severance program was also
announced in February 1993 for employees affected by the organizational
review, but who were not eligible for, or did not accept, the early
retirement offer. The Company recorded a one-time charge to 1993 earnings
of approximately $6 million, after tax ($10 million, before tax), to reflect
the cost of the early retirement and special severance programs which
consisted principally of pension benefits. This total includes the Company's
portion of its affiliated service company's cost of these programs.
Note F - Short-term Borrowing Arrangements
- ------------------------------------------
At December 31, 1994, the Company had $146 million of short-term debt
outstanding including $129 million in the form of commercial paper borrowings
and $17 million of borrowings of borrowings from affiliates. At December 31,
1994, the Company had lines of credit and standby bond purchase facilities
with banks totaling $490 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, 1994. Fees are paid on the lines
and facilities in lieu of compensating balances. The weighted average rate
on outstanding short-term borrowings was 6.0 percent at December 31, 1994.
Note G - Intercompany Lending Arrangement
- -----------------------------------------
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
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note G - Intercompany Lending Arrangement (continued)
- -----------------------------------------
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.
Note H - Cumulative Preferred Stock
- -----------------------------------
A summary of cumulative preferred stock at December 31, 1994 and 1993
is as follows (in thousands of dollars except for share data):
Shares
Authorized
and Dividends Call
Outstanding Amount Declared Price
------------- ------------- ------------- ------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
$100 Par value--
6.00% Series 75,020 80,140 $ 7,502 $ 8,014 $ 458 $ 481 (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
8.40% Series 840
8.68% Series 580
------- ------- ------- ------- ------ ------
Total 605,160 610,280 $60,516 $61,028 $3,440 $4,883
======= ======= ======= ======= ====== ======
(a) Noncallable.
The annual dividend requirement for total cumulative preferred stock was
$3,433,000 and $3,463,000 for 1994 and 1993, respectively.
During 1993, all of the Company's 8.68 percent Series and 8.40 percent
Series of cumulative preferred stock were redeemed. Total premiums of
$870,000 in connection with these redemptions were charged to retained
earnings in 1993. There are no mandatory redemption provisions on the
Company's cumulative preferred stock.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note I - Long-term Debt
- -----------------------
A summary of long-term debt is as follows:
At December 31, (In Thousands)
------------------------------
Series Rate % Maturity 1994 1993
- ------ ------ -------- ---- ----
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
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
W (93-6) 6.58 February 10, 2000 5,000 5,000
W (93-1) 7.00 February 3, 2003 25,000 25,000
Y (94-2) 8.33 November 8, 2004 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 107,850 107,850
S variable November 1, 2020 20,750 20,750
T variable November 1, 2020 28,000 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
Unamortized discounts and premiums (2,884) (2,902)
-------- --------
Long-term debt $695,466 $667,448
======== ========
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, and $10 million in 1999 to retire maturing
mortgage bonds. There are no cash payments for maturing mortgage bonds
required in 1995.
The terms of $342 million of variable rate pollution control revenue
bonds collateralized by the Company's mortgage bonds require the Company to
reacquire the bonds under certain limited circumstances. At December 31,
1994, interest rates on the Company's variable rate bonds ranged from 3.30
percent to 5.60 percent.
Note J - Fair Value of Financial Instruments
- --------------------------------------------
At December 31, 1994, the Company's long-term debt had a carrying value
of $695,000,000 and had a fair value of approximately $685,000,000. To
estimate fair value, the carrying amount was used for debt that reprices
frequently at market rates because the carrying amount is a reasonable
estimate of fair 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. The fair value of the Company's short-term debt equals
carrying value. The fair value of the Company's other investments equals
carrying value.
NEW ENGLAND POWER COMPANY
Notes to Financial Statements (continued)
Note K - 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, 1994 was 54 percent of total capitalization including
long-term debt due in one year and, accordingly, none of the Company's
retained earnings at December 31, 1994 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, none of the Company's retained earnings at
December 31, 1994 were restricted as to dividends on common stock.
Note L - Supplementary Income Statement Information
- ---------------------------------------------------
Advertising expenses, expenditures for research and development, and
rents were not material and there were no royalties paid. Taxes, other than
income taxes, charged to operating expenses are set forth by classes as
follows:
Year Ended December 31,
(In Thousands)
-----------------------------
1994 1993 1992
---- ---- ----
Municipal property taxes $46,506 $44,124 $43,124
Federal and state payroll and other taxes 7,894 7,807 7,704
------- ------- -------
$54,400 $51,931 $50,828
======= ======= =======
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 $103,961,000, $94,366,000, and
$80,535,000, including capitalized construction costs of $22,396,000,
$20,335,000, and $22,759,000, for each of the years 1994, 1993, and 1992,
respectively.
NEW ENGLAND POWER COMPANY
Operating Statistics (Unaudited)
Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Sources of Energy (Thousands of KWH)
Net generation - thermal 10,971,319 11,621,038 12,087,775 13,569,122 13,333,413
Net generation - conventional hydro 1,352,600 1,253,925 1,212,155 1,507,656 1,887,521
Generation - pumped storage 525,653 548,358 530,796 498,895 511,175
Net generation - nuclear 1,767,959 1,696,677 1,592,340 1,033,332 1,415,029
Nuclear entitlements 2,535,534 2,196,998 2,214,976 2,713,947 1,945,459
Purchased energy from
non-affiliates (B) 8,674,191 7,800,975 7,287,856 6,323,144 5,128,451
Energy for pumping (723,352) (750,784) (738,364) (685,659) (699,473)
---------- ---------- ---------- ---------- ----------
Total generated and purchased 25,103,904 24,367,187 24,187,534 24,960,437 23,521,575
Losses, company use, etc. (635,695) (548,228) (632,850) (589,001) (557,978)
---------- ---------- ---------- ---------- ----------
Total sources of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597
========== ========== ========== ========== ==========
Sales of Energy (Thousands of KWH)
Resale:
Affiliated companies 22,182,761 21,858,491 21,497,993 21,496,098 21,706,432
Less - generation by affiliated
Company (A) (5,781) (4,506) (83,753) (162,844) (583,413)
---------- ---------- ---------- ---------- ----------
Net sales to affiliated companies 22,176,980 21,853,985 21,414,240 21,333,254 21,123,019
Other utilities (B) 1,731,225 1,528,686 1,705,591 2,613,034 1,421,325
Municipals 551,866 426,525 415,659 411,171 404,352
---------- ---------- ---------- ---------- ----------
Total sales for resale 24,460,071 23,809,196 23,535,490 24,357,459 22,948,696
Ultimate customers 8,138 9,763 19,194 13,977 14,901
---------- ---------- ---------- ---------- ----------
Total sales of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597
========== ========== ========== ========== ==========
NEW ENGLAND POWER COMPANY
Operating Statistics (Unaudited) (continued)
Year Ended December 31,
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating Revenue (In Thousands)
Revenue from electric sales
Resale:
Affiliated companies $1,448,503 $1,459,619 $1,450,831 $1,384,222 $1,281,933
Less - G and T credits (A) (32,346) (26,001) (38,697) (50,961) (66,048)
---------- ---------- ---------- ---------- ----------
Net sales to affiliated companies 1,416,157 1,433,618 1,412,134 1,333,261 1,215,885
Other utilities (B) 56,306 52,695 55,156 76,162 66,971
Municipals 32,055 27,574 26,980 25,755 22,989
---------- ---------- ---------- ---------- ----------
Total revenue from sales for resale 1,504,518 1,513,887 1,494,270 1,435,178 1,305,845
Ultimate customers 606 752 1,399 1,097 1,033
---------- ---------- ---------- ---------- ----------
Total revenue from electric sales 1,505,124 1,514,639 1,495,669 1,436,275 1,306,878
Other operating revenue 35,633 34,375 35,206 36,016 35,196
---------- ---------- ---------- ---------- ----------
Total operating revenue $1,540,757 $1,549,014 $1,530,875 $1,472,291 $1,342,074
========== ========== ========== ========== ==========
Annual Maximum Demand
(Kw - one hour peak) 4,385,000 4,081,000 3,964,000 4,250,000 4,059,000
<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)
-------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $ 942 $ 939 $ 907 $ 861 $ 809
Fuel cost recovery 563 576 589 575 498
Other 36 34 35 36 35
------ ------ ------ ------ ------
Total operating revenue $1,541 $1,549 $1,531 $1,472 $1,342
Net income $ 149 $ 141 $ 134 $ 135 $ 222*
Total assets $2,613 $2,441 $2,387 $2,277 $2,306
Capitalization:
Common equity $ 877 $ 850 $ 825 $ 797 $ 784
Cumulative preferred stock 61 61 86 86 86
Long-term debt 695 667 666 730 781
------ ------ ------ ------ ------
Total capitalization $1,633 $1,578 $1,577 $1,613 $1,651
Preferred dividends declared $ 3 $ 5 $ 6 $ 6 $ 6
Common dividends declared $ 119 $ 111 $ 100 $ 116 $ 105
* Includes the reversal of a portion of a 1988 write-down under a rate
settlement related to the Seabrook 1 nuclear power plant. See Note C-2.
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
- -------------- ------- ------- ------- -------
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
1993
Operating revenue $395,065 $361,131 $417,912 $374,906
Operating income $ 51,579 $ 35,864 $ 56,625 $ 38,406
Net income $ 40,090 $ 26,944 $ 47,072 $ 27,362
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, 1994,
will be available on or about April 1, 1995, without charge, upon written
request to New England Power Company, Shareholder Services Department,
25 Research Drive, Westborough, Massachusetts 01582.